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, 2017

OR

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

For the transition period from ___________ to ___________

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. / /

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

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

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

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

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

INDEX

	Page
Definitions	4
Forward-Looking Statements	5
Part I
1.         Business	7
General	7
Regulation and Rates	9
Electric Utility Operating Statistics	12
Electric Supply	14
Natural Gas Utility Operating Statistics	18
Natural Gas Supply for Natural Gas Customers	20
Energy Efficiency	22
Environment	22
Recent and Future Environmental Law and Regulation	23
Executive Officers of the Registrants	25
1A.      Risk Factors	25
1B.      Unresolved Staff Comments	30
2.         Properties	30
3.         Legal Proceedings	30
4.         Mine Safety Disclosures	30
Part II
5.         Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	31
6.         Selected Financial Data	32
7.         Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
7A.      Quantitative and Qualitative Disclosures about Market Risk	63
8.         Financial Statements and Supplementary Data	66
Report of Management and Statement of Responsibility	67
Report of Independent Registered Public Accounting Firm – Puget Energy	68
Report of Independent Registered Public Accounting Firm – Puget Sound Energy	70
9.         Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	132
9A.      Controls and Procedures	132
9B.      Other Information	133
Part III
10.       Directors, Executive Officers and Corporate Governance	134
11.       Executive Compensation	136
12.       Security Ownership of Certain Beneficial Owners and Management and Related	160
Shareholder Matters
13.       Certain Relationships and Related Transactions, and Director Independence	161
14.       Principal Accountant Fees and Services	162
Part IV
15.       Exhibits and Financial Statement Schedules	163
16.       Form 10-K Summary	163
Exhibit Index	164
Signatures	170

3

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, LLC
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
TCJA	Tax Cuts and Jobs Act
Washington Commission	Washington Utilities and Transportation Commission
WSPP	WSPP, Inc.

4

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 risks described in Item 1A, "Risk Factors", some important risks 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;

• Changes in tax law as a result of the Tax Cuts and Jobs Act legislation and uncertain interpretations related thereto;

• Inability to realize deferred tax assets and use Production Tax Credits (PTCs) due to insufficient future taxable income;

• Accidents or natural disasters, such as hurricanes, windstorms, earthquakes, floods, fires and landslides, 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;

5

• 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;

• Opposition and social activism that may hinder PSE's ability to perform work or construct infrastructure;

• 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.  For further information, see the reports on Form 10-Q and current reports on Form 8-K.

6

PART I

ITEM 1.  BUSINESS

General

Puget Energy is an energy services holding company incorporated in the state of Washington in 1999.  Substantially, all of its operations are conducted through its regulated subsidiary, PSE, a utility company.  Puget Energy also hasa wholly-owned non-regulated subsidiary, named Puget LNG, LLC (Puget LNG). Puget LNG was formed on November 29, 2016 and has the sole purpose of owning, developing and financing the non-regulated activity of a liquefied natural gas (LNG) facility at the Port of Tacoma, Washington.

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, Macquarie Capital Group Limited, 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, 2017 and 2016:

	December 31,			December 31,
	2017	2016	Percent	2017	2016	Percent
Customer Count by Class	Electric		Change	Natural Gas		Change
Residential	1,003,984	992,959	1.1%	767,045	756,330	1.4%
Commercial	127,836	125,737	1.7	55,996	55,671	0.6
Industrial	3,377	3,417	(1.2)	2,332	2,365	(1.4)
Other	6,856	6,591	4.0	226	227	(0.4)
Total1	1,142,053	1,128,704	1.2%	825,599	814,593	1.4%

_______________

¹  At December 31, 2017 and 2016, approximately 398,518 and 392,806 customers purchased both electricity and natural gas from PSE, respectively.

	December 31,					December 31,
Retail Revenue by Class	2017		2016		Percent	2017		2016		Percent
(Dollars in Thousands)	Electric				Change	Natural Gas				Change
Residential	$	1,232,075	$	1,138,871	8.2%	$	686,438	$	578,955	18.6%
Commercial	892,360		872,057		2.3	274,907		235,695		16.6
Industrial	112,817		113,469		(0.6)	21,071		19,643		7.3
Other	32,313		30,982		4.3	21,718		20,322		6.9
Total	$	2,269,565	$	2,155,379	5.3%	$	1,004,134	$	854,615	17.5%

7

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 and affect 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 corresponding higher power costs, during the winter heating season in the first and fourth quarters of the year and its lowest sales and corresponding 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. For additional information, see Business, "Regulation and Rates" included in Item 1 of this report and Note 3, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.

Capital Expenditures

The following tables present PSE's capital expenditures for the five-year period ended December 31, 2017 and gross utility plant by category and percentages as of December 31, 2017:

Utility Plant Additions/Retirements 5-Year Total	2013-2017
(Dollars in Thousands)	Electric			Natural Gas			Common
Additions	$	2,148,599		$	868,919		$	499,934
Retirements	(537,049		)	(125,042		)	(257,473		)
Net Utility Plant	$	1,611,550		$	743,877		$	242,461

Utility Plant Balance	December 31, 2017
(Dollars in Thousands)	Electric				Natural Gas				Common
Distribution	$	3,757,600	36.7	%	$	3,532,397	91.0	%	$	—	—	%
Generation	3,948,102		38.6		5,956		0.2		—		—
Transmission	1,471,337		14.4		—		—		—		—
General Plant & Other	1,055,732		10.3		344,380		8.8		843,145		100.0
Total	$	10,232,771	100.0	%	$	3,882,733	100.0	%	$	843,145	100.0	%

Employees

At December 31, 2017, PSE had approximately 3,140 full-time equivalent employees.  Approximately 1,110 PSE employees are represented by the International Brotherhood of Electrical Workers Union (IBEW) or the United Association of Plumbers and Pipefitters (UA).  The contracts with the IBEW and the UA were both ratified effective December 2017 and will expire March 31, 2020 and September 30, 2021, 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 and PSE operate one reportable business segment, referred to as the regulated utility segment.  For more information on this segment, see Note 17, "Segment Information" 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.

8

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 Part III Item 10, "Directors, Executive Officers and Corporate Governance".

Regulation and Rates

PSE is subject to the regulatory authority of: (i) the FERC with respect to the transmission of electricity, the sale of electricity at wholesale, accounting and certain other matters; and (ii) 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 North American Electric Reliability Corporation (NERC), the electric reliability organization certified by the FERC, whose standards are enforced by the Western Electricity Coordinating Council (WECC) in PSE’s operating territory.

Rate mechanisms include: (i) trackers that typically track specific costs during the previous twelve-month period and (ii) riders that project cost recovery during a forward looking twelve-month period. Both allow recovery of expenditures without the lengthy process of a full GRC.

The following table shows PSE’s rate filings for its trackers and riders and whether or not they are included in decoupling rates:

Rate Filings	Electric	Natural 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

General Rate Case Filing

On January 13, 2017, PSE filed its GRC with the Washington Commission, the settlement agreement was accepted by the Washington Commission on December 5, 2017 and the rates became effective December 19, 2017. For further details regarding the 2017 GRC filing, see Note 3, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.

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 assist in mitigating the impact of weather on operating revenue and net income. Since July 2013, 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. This monthly adjustment mitigates the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues are 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. Total electric and natural gas revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption. Following each calendar year, PSE will recover from, or refund to, customers the difference between allowed decoupling revenue and the corresponding actual revenue during the following May to April time period. For further details regarding decoupling filings, see Note 3, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.

9

Electric RateFilings

Power Cost Adjustment Mechanism

PSE currently has a PCA mechanism that provides for the deferral of power costs that vary from the “power cost baseline” level of power costs. The “power cost baseline” is set in part, based on normalized assumptions about weather and hydrological conditions.  Excess power costs or savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism and will trigger a surcharge or refund when the $30.0 million cumulative deferral trigger is reached.

On August 7, 2015, the Washington Commission issued an order approving changes to the PCA mechanism. The settlement agreement took effect January 1, 2017 and will apply the following graduated scale:

	Company's Share		Customers’ Share
Annual Power Cost Variability	Over	Under	Over	Under
Over or Under Collected by up to $17 million	100%	100%	—%	—%
Over or Under Collected by between $17 million - $40 million	35	50	65	50
Over or Under Collected beyond $40 + million	10	10	90	90

Electric 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 and to true-up for actual compared to forecast conservation expenditures from the prior year as well as actual load being different than the forecasted load set in rates.

Federal Incentive Tracker Tariff

The Federal Incentive Tracker Tariff passes through to customers the benefits associated with the wind-related treasury grants. 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. Rates change annually on January 1.

Power Cost Only Rate Case

A power cost rate case is a limited-scope proceeding to 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 is not required to but historically has used an expedited six-month PCORC decision timeline rather than the statutory 11-month timeline for a GRC.

Residential Exchange Benefit

The residential exchange program passes through the residential exchange program benefits that PSE receives from the Bonneville Power Administration (BPA).  Rates change bi-annually on October 1.

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 for recovery in an adjusting tariff 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-up from the prior year.

Natural Gas Rate Filings

Natural Gas Cost Recovery Mechanism

The purpose of the CRM is to recover capital costs related to projects included in PSE's pipe replacement program plan on file with the Washington Commission with the intended effect of enhancing the safety of the natural gas distribution system. Rates change annually on November 1.

10

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. Rates change annually on November 1.

Natural Gas 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 for recovery in an adjusting tariff rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes assessed. The tracker is adjusted each year in May based on that year's assessed property taxes and adjustments to the rate from the prior year.

Natural Gas Conservation Rider

The natural gas 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 and to true-up for actual versus forecast conservation expenditures from the prior year as well as actual load being different than the forecasted load set in rates.

For additional information on electric and natural gas rates, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 7 of this report.

11

ELECTRIC UTILITY OPERATING STATISTICS

	Year Ended December 31,
	2017			2016			2015
Generation and purchased power, MWh
Company-controlled resources	10,825,778			11,577,608			12,747,014
Contracted resources	8,337,348			7,023,786			5,911,012
Non-firm energy purchased	6,147,778			6,005,797			5,315,266
Total generation and purchased power	25,310,904			24,607,191			23,973,292
Less: losses and Company use	(1,568,599		)	(1,547,619		)	(1,514,272		)
Total energy sales, MWh	23,742,305			23,059,572			22,459,020
Electric energy sales, MWh
Residential	10,931,999			10,245,326			10,164,703
Commercial	9,089,842			8,895,950			8,999,068
Industrial	1,214,818			1,223,214			1,257,958
Other customers	87,230			90,753			94,847
Total energy sales to customers	21,323,889			20,455,243			20,516,576
Sales to other utilities and marketers	2,418,416			2,604,329			1,942,444
Total energy sales, MWh	23,742,305			23,059,572			22,459,020
Transportation, including unbilled	2,001,244			2,085,574			2,012,827
Electric energy sales and transportation, MWh	25,743,549			25,145,146			24,471,847
Electric operating revenue by classes
(Dollars in Thousands)
Residential	$	1,232,075		$	1,138,871		$	1,061,117
Commercial	892,360			872,057			867,786
Industrial	112,817			113,469			114,223
Other customers	19,729			20,045			20,216
Total operating revenue from customers	2,256,981			2,144,442			2,063,342
Transportation, including unbilled	12,584			10,937			10,143
Sales to other utilities and marketers	53,789			50,124			46,666
Decoupling revenue	9,975			29,968			13,630
Other decoupling revenue1	(27,706		)	(21,168		)	(16,634		)
Miscellaneous operating revenue	115,040			24,189			11,321
Total electric operating revenue	$	2,420,663		$	2,238,492		$	2,128,468
Number of customers served (average):
Residential	998,078			984,739			970,830
Commercial	126,829			125,067			123,072
Industrial	3,399			3,425			3,434
Other	6,722			6,472			6,283
Transportation	16			16			16
Total customers	1,135,044			1,119,719			1,103,635

_______________

¹  Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve.

12

ELECTRIC UTILITY OPERATING STATISTICS (Continued)

	Year Ended December 31,
	2017			2016			2015
Average kWh used per customer:
Residential	10,953			10,404			10,470
Commercial	71,670			71,129			73,120
Industrial	357,404			357,143			366,324
Other	12,977			14,022			15,096
Average revenue per customer:
Residential	$	1,234		$	1,157		$	1,093
Commercial	7,036			6,973			7,051
Industrial	33,191			33,130			33,262
Other	2,935			3,097			3,218
Average retail revenue per kWh sold:
Residential	$	0.1127		$	0.1112		$	0.1044
Commercial	0.0982			0.0980			0.0964
Industrial	0.0929			0.0928			0.0908
Other	0.2262			0.2209			0.2131
Average retail revenue per kWh sold	$	0.1058		$	0.1048		$	0.1006
Heating degree days	4,584			3,823			3,800
Percent of normal - NOAA2 30-year average	97.2		%	81.0		%	80.5		%
Load factor3	51.6		%	56.2		%	56.2		%

_______________

²  National Oceanic and Atmospheric Administration (NOAA).

³  Average megawatt (aMW) usage by customers divided by their maximum usage.

13

Electric Supply

At December 31, 2017, 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 4,737 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, 2017 and 2016:

	Peak Power Resources At December 31,						Energy Production At December 31,
	2017			2016			2017			2016
	MW	%		MW	%		MWh	%		MWh	%
Purchased resources:
Columbia River PUD contracts	711	15.0	%	708	14.6	%	3,355,134	13.3	%	3,371,827	13.7	%
Other hydroelectric	72	1.5		79	1.6		281,619	1.1		365,670	1.5
Other producers	284	6.0		387	8.0		3,679,623	14.6		2,999,171	12.1
Wind	56	1.2		56	1.2		119,690	0.5		138,148	0.6
Short-term wholesale energy purchases	N/A	—		N/A	—		7,049,060	27.8		6,154,767	25.0
Total purchased	1,123	23.7	%	1,230	25.4	%	14,485,126	57.3	%	13,029,583	52.9	%
Company-controlled resources:
Hydroelectric	254	5.4	%	254	5.2	%	864,821	3.4	%	933,522	3.8	%
Coal	677	14.3		677	14.0		4,463,705	17.6		4,529,179	18.4
Natural gas/oil	1,908	40.3		1,908	39.4		3,822,462	15.1		4,152,205	16.9
Wind	773	16.3		773	16.0		1,674,790	6.6		1,962,702	8.0
Other1	2	—		2	—		—	—		—	—
Total company-controlled	3,614	76.3	%	3,614	74.6	%	10,825,778	42.7	%	11,577,608	47.1	%
Total resources	4,737	100.0	%	4,844	100.0	%	25,310,904	100.0	%	24,607,191	100.0	%

_______________

¹  It is estimated that the Glacier Battery Storage has delivered approximately 746.5 and 250.0 MWh as of December 31, 2017 and 2016, respectively.

14

Company–Owned Electric Generation Resources

At December 31, 2017, PSE owns the following plants with an aggregate net generating capacity of 3,614 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)2	Coal	307	1975 & 1976
Mint Farm	Natural gas combined cycle	297	2007; acquired 2008
Goldendale	Natural gas combined cycle	315	2004; acquired 2007; upgraded 2016
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 Falls3	Hydroelectric	54	1898 to 1911 & 1957; rebuilt 2013
Crystal Mountain	Internal combustion	3	1969
Glacier Battery Storage	Lithium Iron Phosphate	2	2016
Total net capacity		3,614

_______________

¹  Net Maximum Capacity is the capacity a unit can sustain over a specified period of time when not restricted by ambient conditions or deratings, less the losses associated with auxiliary loads.

2 In July 2016, PSE reached a settlement with the Sierra Club to retire Colstrip Units 1 and 2 no later than July 1, 2022.

3 The FERC license authorizes the full 54.4 MW; however, the project's water right issued by the State Department of Ecology limits flow to 2,500 cubic feet and therefore output to 47.7MW.

15

Columbia River Electric Energy Supply Contracts

During 2017, approximately 13.3% 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 (Mid-Columbia).  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, 2017, PSE's portion of the power output of the PUDs’ projects as set forth below:

			Company’s Annual Share (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 Project1	2028	2052	29.9	%	251
Grant County PUD:
Priest Rapids Development	2052	2052	0.6	%	6
Wanapum Development	2052	2052	0.6	%	7
Total					745

_______________

¹  In March 2017, PSE entered a new PPA with Douglas County PUD for Wells Project output that begins upon expiration of the existing contract on August 31, 2018 and continues through September 30, 2028.

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 had seasonal energy and capacity exchange agreements with the Bonneville Power Administration (BPA) for 44 aMW of capacity which expired on July 1, 2017 with no provision to renew this agreement. PSE will procure more capacity from Mid-Columbia to recover for this loss of capacity, if needed. PSE also has an agreement with Pacific Gas & Electric Company for 300 MW of capacity which currently has no set expiration.

PSE began participating in the Energy Imbalance Market (EIM) operated by the California Independent System Operator on October 1, 2016. PSE has committed 600 MW of existing BPA transmission solely for the EIM market. Participation has resulted in reduced costs for PSE customers of approximately $10.0 million, enhanced system reliability, integration of variable energy resources, and geographic diversity of electricity demand and generation resources. The calculated benefits represent the cost savings of the EIM dispatch compared with a counter-factual dispatch without the EIM. Benefits can take the form of cost savings or profits or their combination. Benefits include greenhouse gas (GHG) revenue, transfer revenues and flexible ramping revenues.

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 2017, PSE had 4,646 MW and 595 MW of total transmission demand contracted with the BPA and other utilities, respectively.  Additionally, PSE contracted with BPA for an additional 53 MW of transmission demand that went into effect from May to November of 2017. 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

16

of PSE’s natural gas-fired generation resources.  During 2017, PSE purchased approximately 69.9% of its natural gas in British Columbia, 21.8% in Alberta and 8.3% 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 2017 IRP was filed on November 14, 2017 and identified the following capacity shortfalls and surpluses:

	2018	2019	2020	2021	2022
Projected MW shortfall/(surplus)	(73)	(34)	(121)	(128)	192

The expected capacity needs reflect the mix of energy efficiency programs deemed cost effective in the 2017 IRP. PSE projects that beginning in 2022 its future energy needs will exceed current resources in its supply portfolio because of the retirement of Colstrip Units 1 and 2, approximately 307 MW of capacity.  Therefore, PSE’s IRP sets forth a multi-part strategy of implementing energy efficiency programs and pursuing additional renewable resources and additional capacity resources such as battery storage and generation plants that operate during peak loads.  If PSE cannot acquire needed energy supply resources at a reasonable cost, it may be required to purchase additional power in the wholesale market. These purchases are 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.

17

NATURAL GAS UTILITY OPERATING STATISTICS

	Year Ended December 31,
	2017			2016			2015
Natural gas operating revenue by classes (dollars in thousands):
Residential	$	686,438		$	578,955		$	597,572
Commercial firm	251,584			213,138			239,849
Industrial firm	20,077			17,753			21,533
Interruptible	24,317			24,447			29,082
Total retail natural gas sales	982,416			834,293			888,036
Transportation services	21,718			20,322			18,666
Decoupling revenue	3,522			52,114			51,981
Other decoupling revenue1	(22,862		)	(28,761		)	(26,038		)
Other	12,965			12,542			14,904
Total natural gas operating revenue	$	997,759		$	890,510		$	947,549
Number of customers served (average):
Residential	761,010			749,586			737,339
Commercial firm	55,372			54,992			54,646
Industrial firm	2,330			2,371			2,378
Interruptible	398			410			429
Transportation	226			227			221
Total customers	819,336			807,586			795,013
Natural gas volumes, therms (thousands):
Residential	621,915			521,771			492,997
Commercial firm	279,656			233,586			230,507
Industrial firm	25,500			22,783			23,777
Interruptible	49,249			49,533			43,931
Total retail natural gas volumes, therms	976,320			827,673			791,212
Transportation volumes	236,578			230,724			220,392
Total volumes	1,212,898			1,058,397			1,011,604

_______________

¹  Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve.

18

NATURAL GAS UTILITY OPERATING STATISTICS (Continued)

	Year Ended December 31,
	2017			2016			2015
Working natural gas volumes in storage at year end, therms (thousands):
Jackson Prairie	86,051			86,374			78,337
Clay Basin	45,854			63,136			54,199
Average therms used per customer:
Residential	817			696			669
Commercial firm	5,050			4,248			4,218
Industrial firm	10,944			9,609			9,999
Interruptible	123,742			120,812			102,403
Transportation	1,046,806			1,016,406			997,249
Average revenue per customer:
Residential	$	902		$	772		$	810
Commercial firm	4,544			3,876			4,389
Industrial firm	8,617			7,488			9,055
Interruptible	61,098			59,626			67,791
Transportation	96,099			89,524			84,460
Average revenue per therm sold:
Residential	$	1.104		$	1.110		$	1.212
Commercial firm	0.900			0.912			1.041
Industrial firm	0.787			0.779			0.906
Interruptible	0.494			0.494			0.662
Average retail revenue per therm sold	$	1.006		$	1.008		$	1.122
Transportation	0.092			0.088			0.085
Heating degree days	4,584			3,823			3,800
Percent of normal - NOAA 30-year average	97.2		%	81.0		%	80.5		%

19

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 (British Columbia and Alberta).  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, LLC (NWP), the sole interstate pipeline delivering directly into PSE’s service territory.  Accordingly, delivery of natural gas supply to PSE’s natural gas system is dependent upon the reliable operations of NWP.

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 natural gas system.  Peaking needs are also met by using PSE-owned natural gas held in PSE’s 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 2017, PSE purchased approximately 54.8% of its natural gas for its natural gas customers in British Columbia, 19.1% in Alberta and 26.1% 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 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. 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 640,600 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 12.9 million Dth of Clay Basin storage capacity and approximately 107,400 Dth per day of firm withdrawal capacity under two long-term contracts with remaining terms of two and three 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

20

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 from Plymouth 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.

Tacoma LNG Facility

Currently under construction at the Port of Tacoma, the Tacoma LNG facility is expected to be operational in 2019. On January 24, 2018, the Puget Sound Clean Air Agency’s determined a Supplemental Environmental Impact Statement is necessary in order to rule on the air quality permit for the facility. As a result of requiring a Supplemental Environmental Impact Statement, the Company's construction schedule may be impacted depending on the Puget Sound Clean Air Agency's timing and decision on the air quality permit. If delayed, the construction schedule and costs may be adversely impacted. The Tacoma LNG facility will provide peak-shaving services to PSE’s natural gas customers, and will provide LNG as fuel to transportation customers, particularly in the marine market. Pursuant to the Washington Commission’s order, PSE will be allocated 43.0% of the capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility and Puget LNG will be allocated the remaining 57.0% of the capital and operating costs. The portion of the Tacoma LNG facility allocated to PSE will be subject to regulation by the Washington Commission.

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 Enbridge 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 542,900 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 447,100 Dth per day of seasonal firm capacity on NWP to provide for delivery of natural gas stored at Jackson Prairie to natural gas customers.  PSE holds approximately 217,900 Dth per day of firm transportation capacity on NWP to supply natural gas to its electric generating facilities.  In addition, PSE holds over 34,200 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 2 to 27 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 135,800 Dth per day under various contracts, with remaining terms of two to six years.  PSE has other firm transportation capacity on Westcoast’s pipeline, which supplies the electric generating facilities, totaling 88,400 Dth per day, with remaining terms of three to six 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 79,000 Dth per day, with remaining terms of three to six 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 41,000 Dth per day, with remaining terms of three to six years. PSE’s firm transportation capacity for its natural gas customers on the GTN pipeline, totaling over 77,000 Dth per day, with remaining terms of six 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 40,600 Dth per day, with remaining terms of three to six 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

21

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 2017 from the Washington Commission for continuation of electric and natural gas decoupling mechanisms, which mitigates gross margin erosion resulting from the Company's energy efficiency efforts.

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.  See below for the primary areas of environmental law that have the potential to most significantly impact PSE’s operations and costs.

Air and Climate Change Protection

PSE owns numerous thermal generation facilities, including natural gas plants and an ownership percentage of Colstrip.  All of 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 or the Bald and Golden Eagle Protection Act.  Designations of protected species under these 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 hazardous or 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 of those

22

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.

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 twelve-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 three 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 met the MATS limits for mercury and acid gases as of April 2017.

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 has considered 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

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 2016 were 10.8 million metric tons of carbon dioxide equivalents.  Approximately 43.0% of PSE’s total GHG emissions (approximately 4.6 million metric tons) are associated with PSE’s ownership and contractual interests in Colstrip. 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 Greenhouse Gas Rules

On August 3, 2015, the EPA announced a final rule regarding 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 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/megawatt hour (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 Carbon Dioxide Capture and Sequestration (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 have limited flexibility to alter the standards set by the EPA.

23

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. On October 10, 2017, the EPA proposed to repeal this rule and will accept comments until April 26, 2018. As such, PSE is monitoring the situation and awaiting the final determination by the EPA.

Washington Clean Air Rule

The Clean Air Rule (CAR) was adopted on September 15, 2016 in Washington State and attempts to reduce greenhouse gas emissions from “covered entities” located within Washington State. Included under the new rule are large manufacturers, petroleum producers and natural gas utilities, including PSE. CAR sets a cap on emissions associated with covered entities, which decreases over time approximately 5.0% every three years. Entities must reduce their carbon emissions, or purchase emission reduction units (ERUs), as defined under the rule, from others.

CAR covers natural gas distributors and subjects them to an emissions reduction pathway based on the indirect emissions of their customers. CAR regulates the emissions of natural gas utilities 1.2 million customers across the state, adding to the cost of natural gas for homes and businesses, which may increase costs to PSE customers.

On September 27, 2016, PSE, along with Avista Corporation, Cascade Natural Gas Corporation and NW Natural, filed an action in the U.S. District Court for the Eastern District of Washington challenging CAR. On September 30, 2016, the four companies filed a similar challenge to CAR in Thurston County Superior Court. On December 15, 2017, the Thurston County Superior Court invalidated the CAR. A final court order is pending and in the meantime, the Washington State Department of Ecology, submitted a brief requesting severability, which would make the rule valid for industries with direct emissions. This would apply to the Company's electric utility thermal generation units but not to its natural gas utility. Appeals could be filed to the Thurston County Court of Appeals after the court's final order, including its ruling on severability.

Regional Haze Rule

On January 10, 2017, the EPA provided revisions to the Regional Haze Rule which were published in the Federal Register. Among other things, these revisions delayed new Regional Haze review from 2018 to 2021; however, the end date will remain 2028. Aspects of these revisions are currently being challenged by various entities nationwide and briefing has not yet been scheduled. In the meantime, the state of Montana has indicated plans to work on and submit a State Implementation Plan for the second planning period.

Coal Combustion Residuals

On April 17, 2015, the EPA published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (CCR's) under the Resource Conservation and Recovery Act, Subtitle D. The EPA issued another rule, effective October 4, 2016, extending certain compliance deadlines under the CCR rule. The CCR rule is self-implementing at a federal level or can be taken over by a state. The 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.

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 Environmental Obligations (ARO).

PCB Handling and Disposal

In April 2010, the EPA issued an Advanced Notice of Proposed Rulemaking 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 Advanced Notice of Proposed Rulemaking 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. It was anticipated that the rule would be published in November 2017. However on January 30, 2017 the Trump Administration published the Executive Order on Reducing Regulation and Controlling Regulatory Costs directive which placed the rulemaking on indefinite hold. At this point, PSE cannot determine what impacts this rulemaking will have on its operations, if any, but will continue to work closely with the Utility Solid Waste Activities Group and the American Gas Association (AGA) to monitor developments.

24

Executive Officers of the Registrants

The executive officers of Puget Energy as of March 1, 2018 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	53	President and Chief Executive Officer since March 2011
D. A. Doyle	59	Senior Vice President and Chief Financial Officer since November 2011
S. R. Secrist	56	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
S. J. King	34	Controller and Principal Accounting Officer since November 2, 2017. Senior Manager (audited utility, technology and telecommunication companies) at PwC July 2016 - November 2017; Manager at PwC July 2013 - July 2016; Senior Associate at PwC July 2010 - July 2013

The executive officers of PSE as of March 1, 2018 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	53	President and Chief Executive Officer since March 2011
D. A. Doyle	59	Senior Vice President and Chief Financial Officer since November 2011
B. K. Gilbertson	54	Senior Vice President, Operations since March 2015; Vice President, Operations March 2013 – February 2015; Vice President, Operations Services February 2011 – February 2013
M. D. Mellies	57	Senior Vice President and Chief Administrative Officer since February 2011
D. E. Mills	60	Senior Vice President, Policy and Energy Supply since February 2018; Senior Vice President, Energy Operations January 2017 - February 2018; Vice President, Energy Operations January 2016 - January 2017; Vice President, Energy Supply Operations January 2012 - January 2015
S. R. Secrist	56	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
S. J. King	34	Controller and Principal Accounting Officer since November 2, 2017. Senior Manager (audited utility, technology and telecommunication companies) at PwC July 2016 - November 2017; Manager at PwC July 2013 - July 2016; Senior Associate at PwC July 2010 - July 2013

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 are not limited to, the items discussed below.

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

25

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 conditions projected to occur during the applicable rate year, the ensuing twelve-month period after 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. The settlement agreement accepted by the Washington Commission on December 5, 2017 and effective December 19, 2017 provided for an updated rate of return of 7.60%.

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 and will trigger a surcharge or refund when the cumulative deferral trigger is reached.  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.

26

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, and wind-powered 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 the technology systems were to fail or be breached and PSE were unable to recover in a timely manner, PSE 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 its results of operations, financial condition and cash flows.  In addition, these physical asset or cyber-based attacks could disrupt its 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, in a timely manner, 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.   

27

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 natural 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 natural 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 natural 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 PSE's service territory establishes its own municipal-owned utility, it acquires PSE's assets and takes over the delivery of energy services that PSE provides.  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'S AND PSE'S FINANCING

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 October 25, 2022. There was $102.6 million outstanding under the facility as of December 31, 2017.  Puget Energy's credit facility includes an expansion feature that could, upon the banks' approval, increase the size of the facility to $1.3 billion. PSE also has

28

a separate credit facility, which provides PSE with access to $800.0 million in short-term borrowing capability, and includes an expansion feature that could, upon the banks' approval, increase the size of the facility to $1.4 billion. The PSE credit facility matures on October 25, 2022. As of December 31, 2017, no amounts were drawn and outstanding under the PSE credit facility. In addition, Puget Energy has issued $1.8 billion in senior secured notes, whereas PSE, as of December 31, 2017, 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 3.0 to 1.0.  

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 audits 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.

In particular, the Tax Cuts and Jobs Act which was enacted on December 22, 2017 introduced significant permanent and temporary changes to the federal tax code. These changes include a tax rate change from 35.0% to 21.0%, the exclusion of utility businesses from claiming bonus depreciation, the limitation of interest deductibility by non-utility businesses, in addition to numerous other changes. The final interpretation and regulatory treatment of the tax reform changes is uncertain.

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 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 2018 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

29

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

Puget Energy's ability to pay dividends may be limited. 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 48.0% at December 31, 2017 and the EBITDA to interest expense was 5.5 to 1.0 for the twelve-months ended December 31, 2017.

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.

Challenges relating to the construction or future operation of the Tacoma LNG facility could adversely affect the Company’s operations.  PSE and Puget Energy’s subsidiary, Puget LNG, currently are constructing the Tacoma LNG facility at the Port of Tacoma, a jointly owned facility intended to provide peak-shaving services to PSE’s natural gas customers, and to provide LNG as fuel primarily to the maritime market.  Puget LNG has entered into one fuel supply agreement with a maritime customer, and is marketing the facility’s expected output to other potential customers.  Scheduled to be completed in 2019, delays in the facility’s construction and operation or in its ability to timely deliver fuel to customers could expose Puget LNG to damages under one or more fuel supply contracts, which could unfavorably impact Puget Energy’s return on investment.

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

For information on litigation or legislative rulemaking proceedings, see Item 1, "Business, Recent and Future Environmental Law and Regulation" and Note 14, "Litigation" to the consolidated financial statements included in Item 8 of this report.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

30

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, PSE and Puget Energy pay dividends on its common stock. During 2017, 2016 and 2015, 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 Form 10-K.

31

ITEM 6. SELECTED FINANCIAL DATA

The following tables show selected financial data.  This information should be read in conjunction with the audited consolidated financial statements and the related notes found in Item 8, "Financial Statements and Supplementary Data" along with the information included in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operation" of this Form 10-K.

Puget Energy
Summary of Operations	Year Ended December 31,
(Dollars in Thousands)	2017		2016		2015		2014		2013
Operating revenue	$	3,460,276	$	3,164,301	$	3,092,700	$	3,113,171	$	3,187,297
Operating income	760,497		785,384		671,925		577,851		755,160
Net income	175,194		312,899		241,179		171,835		285,728
Total assets at year-end	$	13,690,789	$	13,266,380	$	12,814,254	$	12,637,946	$	12,781,672
Long-term debt	5,207,929		5,104,073		5,077,518		4,957,951		4,943,577
Junior subordinated notes	250,000		250,000		250,000		250,000		250,000
Capital lease obligations	1,129		645		378		9,473		17,051

Puget Sound Energy
Summary of Operations	Year Ended December 31,
(Dollars in Thousands)	2017		2016		2015		2014		2013
Operating revenue	$	3,460,276	$	3,164,618	$	3,093,258	$	3,116,123	$	3,187,335
Operating income	748,609		774,993		656,138		568,693		735,574
Net income	320,054		380,581		304,189		236,614		356,129
Total assets at year-end	$	11,731,706	$	11,297,080	$	10,799,513	$	10,552,727	$	10,636,634
Long-term debt	3,499,911		3,497,298		3,494,362		3,484,571		3,482,062
Junior subordinated notes	250,000		250,000		250,000		250,000		250,000
Capital lease obligations	1,129		645		378		9,473		17,051

32

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

Overview

Puget Energy is an energy services holding company and substantially 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. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC (Puget LNG). Puget LNG was formed on November 29, 2016, and has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNG facility, currently under construction. All of Puget Energy's common stock is indirectly owned by Puget Holdings, LLC (Puget Holdings). Puget Holdings is owned by a consortium of long-term infrastructure investors including Macquarie Infrastructure Partners, Macquarie Capital Group Limited, 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.

Factors affecting PSE's performance are 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 average of monthly averages (AMA) equity, also 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 AMA equity is not intended to represent the regulated equity. PSE's ROE may not be comparable to other companies' ROE measures.  Furthermore, this measure is not intended to replace ROE (GAAP net income divided by GAAP average common equity) as an indicator of operating performance.

33

The following table presents PSE’s ROE, its return on AMA equity and its authorized regulated ROE for 2017 and 2016:

	2017			2016
(Dollars in Thousands)	Earnings	Average Common Equity	Return on Equity	Earnings	Average Common Equity	Return on Equity
Return on equity	$320,054	$3,545,686	9.0%	$380,581	$3,426,620	11.1%
Less/Plus: Unrealized gains and losses on derivative instruments, after-tax	20,014	—	*	(54,467)	—	*
Less/Plus: Equity adjustments1	—	169,298	*	—	177,196	*
Plus: Impact of average of monthly average (AMA)	—	78,793	*	—	57,212	*
Return on AMA equity	$340,068	$3,793,777	9.0%	$326,114	$3,661,028	8.9%
Authorized regulated return on equity2			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.

²  The authorized regulated return on equity rate changed to 9.5% effective December 19, 2017, per the approved GRC.

^*  Not meaningful and/or applicable.

The Company’s 2017 return on AMA equity was 9.0%, which is lower than the authorized regulated ROE primarily due to the following:

• Regulated equity (rate base time's equity percent) was $478.0 million lower than AMA equity for the year ended December 31, 2017. The variance was primarily driven by the impact on rate base of the deferred tax liability for utility, plant and equipment. The impact on ROE for this variance was negative 1.2%.

• Rates are based on an assumption of normal weather. The amount of variance due to weather was $13.2 million, which resulted in an impact on ROE of positive 0.3%.

• Depreciation expense was $24.8 million higher than the amount allowed in rates for the year ended December 31, 2017 for an impact on ROE of negative 0.7%.

• Partially offsetting the above was net revenue from below the line activities and interest savings which totaled $28.2 million for an impact on ROE of positive 0.7%.

The Company’s 2016 return on AMA equity was 8.9%, which is lower than the authorized regulated ROE primarily due to the following:

• Regulated equity (rate base time's equity percent) was $360.0 million lower than AMA equity for the year ended December 31, 2016. The variance was primarily driven by the impact on rate base of the deferred tax liability for utility, plant and equipment. The impact on ROE for this variance was negative 1.0%.

• Depreciation expense was $10.5 million higher than the amount allowed in rates for the year ended December 31, 2016.

• Partially offsetting the above was net revenue from below the line activities which totaled $4.3 million.

34

Factors and Trends Affecting PSE’s Performance  

PSE’s ongoing regulatory requirements and operational needs necessitated the investment of substantial capital in 2017 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.  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;

• Weather conditions, including the impact of temperature on customer load; the impact of extreme weather events on budgeted maintenance costs; meteorological conditions such as snow-pack, stream-flow and wind-speed which affect power generation, supply and price;

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

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

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

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

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

• Wholesale commodity prices of electricity and natural gas;

• Increasing capital expenditures with additional depreciation and amortization;

• Tax reform, the effect of lower tax rates, and regulatory treatment of excess deferred tax balances on rate base and customer rates;

• 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. 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 an operating expense or capital investment does not meet the reasonable and prudent standards, the costs (including return on any resulting rate base) related to such operating expense or capital investment may be disallowed, partially or entirely, and not recovered in rates.

During 2013, PSE completed an expedited rate filing (ERF), which was a limited scope rate proceeding, and established a decoupling mechanism for natural 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 actual cash payments for the year.

The decoupling mechanism allows PSE to recover delivery 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 required PSE to file a GRC no later than April 1, 2016, which was later extended to January 17, 2017. The GRC was filed with the Washington Commission on January 13, 2017.

Washington state law also requires PSE to pursue electric conservation that is cost-effective, reliable and feasible. PSE’s mandate to pursue electric conservation initiatives may have a negative impact on the electric business financial performance due to lost margins from lower sales volumes as variable power costs are not part of the decoupling mechanism. Although not specified by Washington state law, the Washington Commission also sets natural gas conservation achievement standards for PSE. The effects of achieving these standards will, however, have only a slight negative impact on natural gas business financial performance due to the natural gas business being almost fully decoupled. 

35

2013 Expedited Rate Filing and Decoupling Decision

In 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 to 7.77% which updated long-term debt costs and a capital structure that included 48.0% common equity with a return on equity (ROE) of 9.8%. 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 will share 50.0% of any earnings in excess of the 7.77% authorized rate of return with customers. In addition, the K-Factor (rate plan) increase allowed decoupling revenue per customer for the recovery of delivery system costs to subsequently increase by 3.0% per year for electric customers and 2.2% per year for natural gas customers on January 1 of each year, until the effective date of new rates in PSE's General Rate Case (GRC). The new rates became effective December 19, 2017, as discussed below. In the decoupling mechanism, increases were subject to a cap of 3.0% of the total revenue for customers.

General Rate Case Filing

On January 13, 2017, PSE filed its GRC with the Washington Commission the settlement agreement was accepted by the Washington Commission on December 5, 2017 and the rates became effective December 19, 2017. For further details regarding the 2017 GRC filing, see Note 3, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.

Decoupling Filings

On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues will continue to be recovered on a per customer basis and electric fixed production energy costs will now be decoupled and recovered on a fixed monthly amount basis. The allowed decoupling revenue will no longer increase annually on January 1 for electric and natural gas customers and these amounts can only be changed in a GRC, Power Cost Only Rate Case (PCORC) or ERF filing. Other changes include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the decoupling mechanism going forward. The rate cap which limits the amount of revenues PSE can collect in its annual filings increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The decoupling mechanism will end on the effective date of PSE's first GRC filed in or after 2021, or in a separate proceeding if appropriate unless the continuation of the mechanism is approved in either of those proceedings. PSE’s decoupling mechanism over and under collections will still be collectible or refundable after this effective date even if the decoupling mechanism is not extended.

The Washington Commission approved the following PSE requests to change rates under its electric and natural gas decoupling mechanisms:

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)1
Electric:
May 1, 2017	2.0%	$41.9
May 1, 2016	1.0	20.8
May 1, 2015	2.6	53.8
Natural Gas:
May 1, 2017	2.4%	$22.4
May 1, 2016	2.8	25.4
May 1, 2015	2.1	22.0

¹  The increase in revenue is net of reductions from excess earnings of $11.9 million for electric and $2.2 million for natural gas effective May1, 2017, and $11.9 million for electric and $5.5 million for natural gas effective May 1, 2016.

36

As noted earlier, at the time of the filings below, the Company was also limited to a 3.0% annual decoupling related cap on increases in total revenue. This limitation has been triggered as follows:

Effective Date Accrued Through	Deferrals not Included in Annual Rate Increases (Dollars in Millions)
Natural Gas:
2016	$47.4
2015	28.7

Existing deferrals may be included in customer rates beginning in May 2018, subject to subsequent application of the earnings test and the cap on decoupling related rate increases for natural gas customers, which was changed from 3.0% to 5.0% as a result of the Washington Commission order in PSE's GRC.  

Electric Rates

Power Cost Adjustment Mechanism

PSE currently has a PCA mechanism that provides for the deferral of power costs that 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 hydrological conditions.  Excess power costs or savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism and will trigger a surcharge or refund when the cumulative deferral trigger is reached.

The graduated scale that was applicable through December 31, 2016 was 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 changes to the PCA mechanism. The settlement agreement took effect January 1, 2017 and will apply the following graduated scale:

	Company's Share				Customers’ Share
Annual Power Cost Variability	Over		Under		Over		Under
Over or Under Collected by up to $17 million	100	%	100	%	—	%	—	%
Over or Under Collected by between $17 million - $40 million	35		50		65		50
Over or Under Collected beyond $40 + million	10		10		90		90

The PCA settlement also resulted in the following changes to the PCA mechanism:

• 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. Inclusion of these costs in the decoupling mechanism was subsequently approved in the GRC. These fixed production costs include: (i) return and depreciation/amortization on fixed production assets and regulatory assets and liabilities; (ii) return, depreciation, transmission expense and revenues on specific transmission assets; and (iii) hydroelectric, 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;

• Agreement, 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.

37

On September 30, 2016, PSE filed an accounting petition with the Washington Commission, which requested deferral of the variances, either positive or negative, between the fixed costs previously recovered in the PCA and the revenue received to cover the allowed fixed costs.  The deferral period requested was January 1, 2017 through December 31, 2017, when rates went into effect from PSE's 2017 GRC.  On November 10, 2016, the Washington Commission issued Order No. 01 approving PSE’s accounting petition. With the final determination in PSE’s GRC, this deferral ceased with the rate effective date of December 19, 2017.

For the year ended December 31, 2017, in its PCA mechanism, PSE under recovered its power costs by $11.5 million of which no amount was apportioned to customers.  This compares to an under recovery of power costs of $1.0 million for the year ended December 31, 2016 of which no amounts were apportioned to customers. Although load increased in 2017 compared to 2016, that increase was offset by a decrease in the total baseline rate and an increase in costs. Additionally, the year over year variance was due to the 2017 mechanism changes where fixed production costs, other costs and adjustments are no longer included.  The mechanism is now comparing variable PCA costs using the variable costs portion of the baseline rate.  The fixed costs became part of the decoupling mechanism, effective December 19, 2017 as a result of the GRC but until then the revenue variance associated with the fixed production costs are being deferred using the fixed cost portion of the baseline rate. The revenue variance associated with the fixed production costs was deferred using the fixed cost portion of the baseline rate until December 19, 2017, when the fixed costs became part of the decoupling mechanism with the resolution of PSE’s GRC.

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, 2017	0.7%	$16.5
May 1, 2016	(0.5)	(11.7)
May 1, 2015	0.2	4.2

Federal Incentive Tracker Tariff

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 from prior year	Total credit to be passed back to eligible customers (Dollars in Millions)
January 1, 2018	0.2%	$(48.2)
January 1, 2017	0.3	(51.7)
January 1, 2016	(0.2)	(57.3)
January 1, 2015	(0.2)	(55.2)

Power Cost Only Rate Case and Update Compliance Filing

The following table sets forth PCORC and update compliance filing 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, 2016	(1.7)%	$(37.3)

38

Residential Exchange Benefit

The residential exchange program passes through the residential exchange program benefits that PSE will be receiving from the Bonneville Power Administration (BPA) between October 1, 2017 and September 30, 2019.  Rates change bi-annually on October 1.

The following table sets forth residential exchange benefit adjustments approved by the Washington Commission and the corresponding expected annual 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)
October 1, 2017	(0.6)%	$(80.8)
October 1, 2015	2.4	(76.4)

Electric 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)
May 1, 2017	(0.4)%	$(0.9)
May 1, 2016	0.3	5.7
May 1, 2015	0.3	6.5

Natural Gas Rates

Natural Gas 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, 2017	0.5%	$4.9
November 1, 2016	0.6	5.6
November 1, 2015	0.5	5.3

39

Purchased Gas Adjustment

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, 2017	(3.3)%	$(30.8)
November 1, 2016	(0.4)	(4.1)
November 1, 2015	(17.4)	(185.9)

Natural Gas 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)
May 1, 2017	(0.1)%	$(1.1)
May 1, 2016	0.4	3.5
June 1, 2015	(0.2)	(2.3)

Natural Gas Conservation Rider

The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding annual 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, 2017	(0.1)%	$(1.0)
May 1, 2016	0.3	2.9
May 1, 2015	0.2	2.3

Other Proceedings

Large Customer Retail Wheeling

On October 7, 2016, PSE filed a tariff to provide open access service to a narrow set of qualifying customers. Subsequent to that tariff filing, parties to the case reached an all-party settlement that converted the tariff to a special contract only allowing retail access for the loads of the Microsoft Corporation currently being served under PSE’s electric Schedule 40. The special contract includes the following conditions: (i) Microsoft exceed Washington State’s current renewable portfolio standards, (ii) the remainder of power sold to it be carbon free, (iii) there be no reduction in its funding of PSE’s conservation programs, (iv) an exit fee be paid that will be a straight pass-through to customers and (v) Microsoft fund enhanced low-income support. A definitive agreement among the parties, the special contract and supportive testimony were filed with the Washington Commission on April 11, 2017 with hearings that occurred on May 3, 2017. The Washington Commission issued an order on July 13, 2017 approving PSE’s special contract with Microsoft. Microsoft cannot begin taking service under the special contract until it has the required metering installed, has contracts for the supply and transmission of its power supply and pays the exit fee. PSE currently anticipates these conditions will be met in early 2019.

40

Voluntary Long-Term Renewable Energy

On September 28, 2016, the Washington Commission approved PSE's tariff revision to create an additional voluntary renewable energy product, effective September 30, 2016. This provides customers with energy choices to help them meet their sustainability goals. Incremental costs of the program will be allocated to the voluntary participants of the program as is the case with PSE’s existing Green Power programs. PSE initially offered this service, Green Direct, to larger customers (aggregated annual loads greater than 10,000,000 kWh) and government customers. Approximately 136.8 MW of new wind generation facilities will be constructed in the region by a developer under contract to PSE to meet the demand for this voluntary renewable energy product project. PSE anticipates that customers will start receiving energy through this program in 2019.

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

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. In October 2017, PSE and Puget Energy each entered into new 5-year credit facilities that replaced the previous facilities and are scheduled to mature in October 2022. For additional information on credit facilities, see Note 7, “Liquidity Facilities and Other Financing Arrangements" included in Item 8 of this report.

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, natural 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 a significant amount of resources to fulfill requirements set by regulatory agencies, many of which have greatly expanded mandates on measures including 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. 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. 

41

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, 2017, 2016 and 2015.

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 natural 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 natural 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.

42

The following chart displays the changes in PSE’s electric margin from 2016 to 2017:

_______________

^*Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve.

2016 compared to 2017

Electric Operating Revenue

Electric operating revenuesincreased$182.2 million primarily due to higher retail sales of $112.5 million, increased transportation and other revenue of $92.5 million, partially offset by decreased decoupling revenue of $20.0 million and other decoupling revenue of $6.5 million.  These items are discussed in detail below:

• Electric retail salesincreased$112.5 million due an increase of $100.0 million from additional retail electricity usage of 4.2% compared to the prior year and an increase in rates of $12.5 million due to the decoupling rate mechanism. The additional usage was due to an increase of residential and commercial use per customer of 6.7% and 2.2%, respectively, an increase in heating degree days of 19.9% compared to 2016, and an increase in retail customers of 1.4%.

43

• Decoupling revenue decreased $20.0 million due to a decrease in decoupling deferrals of $23.5 million driven by actual revenue being closer to PSE's allowed revenue per the decoupling mechanism compared to 2016. The increase in actual revenue was due to an increase in load as discussed above in electric retail sales. This was partially offset by an increase in decoupling revenue of $3.5 million due to fixed production cost deferrals, which were removed from the PCA mechanism and placed into the decoupling mechanism effective January 1, 2017.

• Other decoupling revenue decreased $6.5 million due to an increase in decoupling collections of $9.5 million due to an increase in rates in 2017. In 2016, there was $1.3 million of decoupling deferred revenue that could not be collected within 24 months compared to no reserve in the current year. The decoupling collection and refund of rate of return (ROR) excess earnings are driven by the tariff rates and retail sales.

• Transportation and other revenueincreased$92.5 million primarily due to a change in production tax credit (PTC) deferral revenue of $73.2 million due to a $19.9 million reduction to revenue in 2016 as PTCs were generated compared to no PTC generated in 2017, as well as, a $51.2 million remeasurement of the PTC deferral in 2017 due to tax law change. Additionally, there was an increase in net wholesale natural gas sales of $17.5 million due to increased purchased electricity, as discussed below.

Electric Power Costs

Electric power costs increased $43.2 million primarily due to an increase of $58.4 million of purchased electricity costs, partially offset by a decrease of $9.1 million of electric generation fuel expense and an increase of $6.1 million of residential exchange credits. These items are discussed in detail below:

• Purchased electricity expense increased $58.4 million primarily due to an 11.2% increase in wholesale electricity purchases, partially offset by a 0.2% decrease in prices. The increase in purchases was primarily driven by an increase in load and lower wholesale electricity prices on the open market compared to generating power. Additionally, a decrease of hydro and wind production of 7.4% and 14.7%, increased the need to purchase additional wholesale power.

• Electric generation fuel expense decreased $9.1 million primarily due to a $2.7 million reduction in combustion turbine generation costs as a result of a 7.9% reduction in combustion turbine generation due to favorable wholesale electricity prices and a $6.3 million decrease in coal generation costs primarily at Colstrip units 3 and 4 for variable fuel costs due to less coal delivered and burned in 2017.

• Residential exchange credits increased $6.1 million resulting from higher Residential Exchange Program (REP) credits associated with the BPA REP settlement due to the REP credit tariff increase in 2017 and increased usage. 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 BPA.  Pursuant to agreements (including settlement agreements) between BPA and PSE, 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.

44

The following chart displays the changes in PSE’s electric margin from 2015 to 2016:

_______________

^*  Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve.

2015 compared to 2016

Electric Operating Revenue

Electric operating revenues increased $110.0 million primarily due to higher retail sales of $81.1 million, increased decoupling revenue of $16.3 million and transportation and other revenue of $13.6 million.  These items are discussed in detail below:

• Electric retail sales increased $81.1 million due to increases in rates of $86.4 million primarily from the reduction of the residential exchange credits and an increase in the decoupling rate mechanism. The increase from rates was partially offset by $5.6 million due to a 0.3% reduction in retail electricity usage. The reduction in usage was due to a decrease of residential, commercial and industrial average use per customer of 0.6%, 2.7% and 2.5%, respectively, as a result of energy efficiency. The reduction in use per customer were offset by an increase in retail customers of 1.5% and an increase in heating degree days of 0.6% compared to 2015.

45

• Decoupling revenue increased $16.3 million due to actual revenues were lower than PSE's allowed revenue per the decoupling mechanism compared to 2015. This increase was primarily from residential and commercial decoupled rate schedules, which increased $15.6 million in 2016. The increase was driven from an increase in customers which increases the allowed revenue and a decrease in use per customer, which lowers the actual revenue resulting in higher decoupled revenue.

• Other decoupling revenue decreased $4.5 million due to an increase of $16.8 million of decoupling collections as compared to 2015 from an increase in rates in 2016; partially offset by a decrease in the ROR excess earnings sharing of $13.5 million from a reduction in the ROR excess earnings accrual of $6.5 million compared to 2015 and an increase of $7.0 million in refunds to customers for the 2015 ROR excess earnings set into customer rates in 2016. The decoupling collection and refund of ROR excess earnings are driven by the tariff rates and retail sales.

• Transportation and other revenue increased $13.6 million primarily due to a reduction of amortization of PTC deferral credits of $10.1 million since PTC generation at Hopkins Ridge ended in 2015 and increase in net wholesale natural gas sales of $6.8 million.

Electric Power Costs

Electric power costs increased $40.1 million primarily due to a decrease of $42.6 million of residential exchange credit, an increase of $32.1 million of purchased electricity costs, partially offset by a decrease of $34.6 million of electric generation fuel expense. These items are discussed in detail below:

• Purchased electricity expense increased $32.1 million primarily due to a 16.1% increase in wholesale electricity purchases, partially offset by a 8.3% decrease in wholesale electricity prices. The increase in purchases was primarily driven by an increase in load and lower wholesale electricity prices on the open market compared to generating power. Additionally, an increase of hydro and wind production of 32.2% and 14.4% decreased the need to purchase additional wholesale power due to favorable conditions.

• Electric generation fuel expense decreased $34.6 million primarily due to a $43.0 million reduction in combustion turbine costs as a result of a 28.8% reduction in combustion turbine generation due to favorable wholesale electricity prices and increased wind and hydro generation. This was partially offset by an $8.4 million increase in coal generation costs primarily due to an increase in the weighted-average cost of coal.

• Residential exchange credits decreased $42.6 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 BPA.  Pursuant to agreements (including settlement agreements) between BPA and PSE, 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.

46

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 natural gas costs included in baseline PGA rates are deferred and either refunded or collected from customers, respectively, in future periods.

The following chart displays the changes in PSE’s natural gas margin from 2016 to 2017:

_______________

^*Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve.

2016 compared to 2017

Natural Gas Operating Revenue

Natural gas operating revenue increased $107.3 million primarily due to higher retail sales of $148.1 million and increased other decoupling revenue of $5.9 million; partially offset by a decrease in decoupling revenue of $48.6 million.  These items are discussed in the following details:

• Natural gas retail sales increased $148.1 million due to an increase of $155.1 million in natural gas sales, which is a result of an increase in natural gas load of 18.0% from 2016, partially offset by a decrease in revenue per therm of $6.9 million. The decrease in revenue per therm was primarily due to a rate decrease on customer bills for PGA, which decreased rates 0.4% effective November 1, 2016 and increase in decoupling rates of 2.4% effective May 1, 2017, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 7 of this report for natural gas rate changes. Natural gas load increased primarily due to the increase in average therms used per residential and commercial customers of 17.4% and 18.9%, respectively, compared to 2016 as a result of a 19.9% increase in heating degree days and an increase of 1.5% in natural gas customers, which increased the natural gas heating load compared to prior year.

47

• Decoupling revenue decreased $48.6 million primarily due to an increase in use per customer, driven by an increase in heating degree days as discussed above in natural gas retail sales. This caused actual revenue to increase closer to PSE's allowed revenue, which lowered decoupled revenue in 2017.

• Other decoupling revenue increased $5.9 million due to the following: (i) an increase in decoupling collections of $14.7 million from an increase in the amortization rate in 2017 and an increase in therms used; (ii) in 2017, there was $19.6 million of deferred decoupling revenue that was recognized as it met the alternative revenue program revenue recognition criteria that it is expected to be collected from customers within 24 months, compared to the 24-month reserve of $9.6 million in 2016; and (iii) an increase in net overearnings accruals and cash refunds of $8.6 million.

Natural Gas Energy Costs

Purchased natural gas expense increased $46.1 million due to an increase in natural gas costs included in PGA rates effective November 1, 2016 as compared to those effective November 1, 2015, and an increase in natural gas usage of 18.0%.

The following chart displays the changes in PSE’s natural gas margin from 2015 to 2016:

_______________

^*  Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve.

2015 compared to 2016

Natural gas operating revenue decreased$57.0 million primarily due to lower natural gas retail sales revenue of $53.7 million and a decrease in other decoupling revenue of $2.7 million, see discussion below.

48

• Natural gas retail sales revenue decreased $53.7 million due to a decrease in revenue per therm of $90.6 million, partially offset by an increase of $41.0 million in natural gas sales, due to an increase in natural gas load of 4.6% from 2015. The decrease in revenue per therm was primarily due to a rate decrease on customer bills for PGA, which decreased rates 17.4% effective November 1, 2015 partially offset by an increase in decoupling rates of 2.8% effective May 1, 2016, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 7 of this report for natural gas rate changes. Natural gas load increased primarily due to the increase in average therms used per residential and commercial customers of 4.0% and 0.7%, respectively, compared to 2015. In addition, natural gas customers increased by 1.6% and heating degree days increased by 0.6%, which increased the natural gas heating load compared to prior year.

• Other decoupling revenue decreased $2.7 million due to an increase in decoupling deferral collection of $17.9 million, as a result of an additional $17.3 million being set in rates on May 1, 2016, which was partially offset by a decrease in ROR excess earnings sharing accrual of $12.5 million and an increase in ROR excess earnings refund in 2016 of $2.5 million. The decoupling collection and refund of ROR excess earnings are driven by the tariff rates and customer usage.

Natural Gas Energy Costs

Purchased natural gas expense decreased $89.4 million primarily due to lower natural gas costs included in PGA rates effective November 1, 2015, which was partially offset by an increase in natural gas usage of 4.6%.

49

Other Operating Expenses and Other Income (Deductions)

The following chart displays the details of PSE's other operating expenses and other income (deductions) from period 2016 to 2017:

2016 compared to 2017

Other Operating Expenses

• Net unrealized (gain) loss on derivative instruments expense increased $114.6 million to a net loss of $30.8 million for the year ended December 31, 2017. The primary drivers for the increase consist of a reduction of $20.6 million in gains from contract settlements previously recorded as losses that settled to purchased electricity or electric generation fuel and a $94.0 million loss due to a decrease in natural gas and electricity forward prices of 26.9% and 27.5%, respectively. The $20.6 million reduction from contract settlements was comprised of a $16.5 million from natural gas and a $4.1 million from wholesale electric contracts. The decrease in the weighted average natural gas and wholesale electric forward prices resulted in a $78.4 million loss and a $15.6 million loss, respectively.

• Utility operations and maintenance expense increased $15.8 million primarily driven by increases in the following: $6.7 million for electric and natural gas operations primarily due to increased electric operations third-party service provider costs of $3.2 million and gas distribution system integrity costs of $2.0 million $5.5 million increase in outside services expense for customer service optimization initiatives that began in 2016, and a $4.6 million increase in overall labor expense. These increases were partially offset by $1.6 million reduction of uncollectible account costs compared to 2016.

• Non-utility and other expense increased $14.5 million primarily due to an increase in the long-term incentive plan of $12.3 million in 2017 which resulted from a total return in 2017 of 29.1% which resulted in the total return component to be funded at 200.0%. For more information see Part III, "Executive Compensation" included in Item 11 of this report for the Company's long term incentive plan.

• Depreciation and amortization expense increased $55.8 million primarily due to the following: (i) electric depreciation expense of $12.1 million, primarily due to asset net additions to distribution, transmission, and general plant of $186.4 million, $92.0 million and $83.1 million respectively; (ii) natural gas depreciation expense of $6.1 million increased due primarily to net additions to distribution assets of $192.3 million; (iii) $15.5 million of amortization expense due to

50

computer software net additions of $123.7 million; (iv) amortization of PTC regulatory liability of $2.1 million in 2017; (v) a decrease of Lower Snake River U.S. Treasury interest amortization of $3.2 million; (vi) an increase of ARO accretion expense of $2.8 million due to a change in the Colstrip ARO in 2016; and (vii) conservation amortization increased $13.4 million, $10.3 for electric and $3.2 for natural gas, primarily due to an increase of usage attributed to an increase in heating degree days and customers for both electric and natural gas in 2017 as compared to 2016.

• Taxes other than income taxes increased $32.0 million primarily due to increases in municipal taxes of $11.5 million and state excise taxes of $10.2 million as a result of an increase in revenue and an increase of $9.3 million in property taxes related to increased property values and expected levy rates.

Other Income, Interest Expense and Income Tax Expense

• Income tax expense increased $36.6 million primarily driven by the impact of tax reform on the deferred tax balances and partially offset by a 4.3% decrease in pre-tax income. For additional information, see Note 13, "Income Taxes" to the consolidated financial statements included in Item 8 of this report.

The following chart displays the details of PSE's other operating expenses and other income (deductions) from period 2015 to 2016:

2015 compared to 2016

Other Operating Expenses

• Net unrealized (gain) loss on derivative instruments expense decreased $71.1 million to a net gain of $83.8 million for the year ended December 31, 2016. The primary drivers for the 2016 net gain consist of a $61.7 million gain from contract settlements previously recorded as losses in the 2015 unrealized gain on derivative instruments that settle to purchased electricity and electric generation fuel. The $61.7 million gain from contract settlements was comprised of a $39.7 million gain from natural gas and a $22.0 million gain from wholesale electric contract settlements. Natural gas and wholesale electricity gain increased $22.1 million primarily due to increases in forward market prices of 5.7% and 10.8%, respectively. This compares to a net gain of $12.7 million in 2015, comprised of $83.6 million in settlement gains offset by a $70.9 million loss due to a decrease in natural gas and wholesale electricity prices.

51

• Utility operations and maintenance expense increased $37.8 million primarily driven by (i) an increase of $26.9 million of maintenance expense primarily related to natural gas leak repairs and sewer cross bore inspections, maintenance on gearboxes and generators at the Hopkins Ridge and Wild Horse wind generation facilities, electric distribution maintenance for overhead lines and vegetation management; (ii) an increase of outside services expense of $7.4 million primarily related to customer service initiatives; (iii) an increase of salary expense of $2.9 million primarily related to incentive increases; partially offset by (iv) a decrease of $4.6 million in meter reading expense due to the purchase of previously leased meter reading equipment during 2015.

• Depreciation and amortization expense increased $15.7 million primarily due to $16.5 million of depreciation expense primarily due to net additions of $173.9 million of natural gas distribution assets, $148.5 million of electric distribution assets and $90.6 million of electric transmission assets.

• Taxes other than income taxes increased $8.1 million primarily due to an increase in electric property taxes of $6.0 million based on assessed value and levy rates, electric state excise and municipal taxes of $5.8 million driven by an increase in electric revenue, partially offset by a decrease of $4.8 million in natural gas state excise and municipal taxes from a decrease in natural gas revenue.

Other Income, Interest Expense and Income Tax Expense

• Interest expense decreased $6.3 million primarily due to a reduction of $3.8 million in interest on long-term debt related to debt that was refinanced in May 2015 at an interest rate of 4.30% compared to interest rates of 5.197% and 6.75%; and an increase of $1.7 million related to allowance for funds used during construction (AFUDC) debt due to an increase in average construction work in progress (CWIP).

• Income tax expense increased $49.4 million primarily driven by $44.0 million from higher pre-tax income and an increase of $6.5 million due to Hopkins Ridge no longer generating PTCs. PTCs are generated for the first ten years at a wind facility. As of December 2015, Hopkins Ridge is no longer eligible to generate PTCs. For additional information, see Note 13, "Income Taxes" to the consolidated financial statements included in Item 8 of this report.

52

Puget Energy

Substantially all the operations of Puget Energy are conducted through its regulated subsidiary, PSE.  Puget Energy’s results of operation for the years ended December 31, 2017, 2016 and 2015 were as follows:

2016 compared to 2017

Summary Results of Operations

Puget Energy’s net income decreased by $137.7 million, which is primarily attributable to an income tax expense increase of $79.3 million, as well as PSE's net income decrease of $60.5 million.  The following are significant factors that impacted Puget Energy’s net income which are not included in PSE’s discussion:

• Income Tax Expense increased by $79.3 million primarily due to tax reform passed on December 22, 2017 that lowered the corporate tax rate from 35.0% to 21.0%. As a result, income tax expense was effected by the revaluation of Puget Energy's deferred tax assets at the 21.0% rate.

53

2015 compared to 2016

Summary Results of Operations

Puget Energy’s net income increased by $71.7 million, which is primarily attributable to PSE's net income increase of $76.4 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 $5.1 million primarily due to legal outside services of $2.8 million and qualified pension expense of $1.2 million.

54

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, 2017:

	Payments Due Per Period
(Dollars in Thousands)	Total		2018		2019 - 2020		2021 - 2022		Thereafter
Contractual obligations:
Energy purchase obligations1	$	5,508,991	$	824,417	$	1,352,132	$	1,184,192	$	2,148,250
Long-term debt including interest2	7,967,957		402,854		393,521		393,521		6,778,061
Short-term debt including interest	329,463		329,463		—		—		—
Service contract obligations	724,899		76,919		145,371		149,222		353,387
Non-cancelable operating leases3	171,813		21,371		36,584		15,884		97,974
PSE capital leases3	1,162		527		538		97		—
Pension and other benefits funding and payments	78,187		23,803		10,685		6,305		37,394
Total PSE contractual cash obligations	14,782,472		1,679,354		1,938,831		1,749,221		9,415,066
Long-term debt including interest2	2,321,374		201,763		647,043		1,038,008		434,560
Total Puget Energy contractual cash obligations	$	17,103,846	$	1,881,117	$	2,585,874	$	2,787,229	$	9,849,626

_______________

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, "Long-Term Debt," 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, "Leases" 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, 2017:

	Amount of Available Commitments Expiration Per Period
(Dollars in Thousands)	Total			2018		2019 - 2020		2021 - 2022		Thereafter
Commercial commitments:
PSE revolving credit facility1	$	800,000		$	—	$	—	$	800,000	$	—
Inter-company short-term debt2	30,000			—		—		—		30,000
Total PSE commercial commitments	830,000			—		—		800,000		30,000
Puget Energy revolving credit facility3	697,400			—		—		697,400		—
Less: Inter-company short-term debt elimination2	(30,000		)	—		—		—		(30,000		)
Total Puget Energy commercial commitments	$	1,497,400		$	—	$	—	$	1,497,400	$	—

_______________

¹  As of December 31, 2017, PSE had a credit facility which provides $800.0 million of short-term liquidity needs and includes a backstop to the Company's commercial paper program. The credit facility matures in October 2022. The credit facility also includes a swingline feature allowing same day availability on borrowings up to $75.0 million and an expansion feature that, upon the banks' approval, would increase the total size of the facility to $1.4 billion. As of December 31, 2017, no loans or letters of credit were outstanding under the credit facility and $329.5 million was outstanding under the commercial paper program. The credit agreement is syndicated among numerous lenders. Outside of the credit agreement, PSE has a $3.1 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, 2017, PSE had a revolving credit facility with Puget Energy in the form of a promissory note to borrow up to $30.0 million.

³  As of December 31, 2017, Puget Energy had a revolving senior secured credit facility totaling $800.0 million, which matures in October 2022. The revolving senior secured credit facility is syndicated among numerous lenders. The revolving senior secured credit facility also has an expansion feature that, upon the banks' approval, would increase the size of the facility to $1.3 billion. As of December 31, 2017, there was $102.6 million drawn and outstanding under the Puget Energy credit facility.

55

Off-Balance Sheet Arrangements

As of December 31, 2017, 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, other than the items disclosed in Note 8, "Leases" and in Note 15, "Commitment and Contingencies" to the consolidated financial statements included in Item 2 of this report.

Utility Construction Program

PSE’s construction programs for generating facilities, the electric transmission system, the natural gas and electric distribution systems and the Tacoma LNG facility are designed to meet regulatory requirements and customer growth and to support reliable energy delivery.  Construction expenditures, excluding equity AFUDC, totaled $963.7 million in 2017.  Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:

Capital Expenditure Projections
(Dollars in Thousands)	2018		2019		2020
Total energy delivery, technology and facilities expenditures	$	1,003,000	$	839,000	$	740,000

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	Year Ended December 31,
(Dollars in Millions)	2017			2016			Change
Net income	$	320,054		$	380,581		$	(60,527	)
Non-cash items1	782,890			631,440			151,450
Changes in cash flow resulting from working capital2	105,281			(46,554		)	151,835
Regulatory assets and liabilities	(88,875		)	(152,786		)	63,911
Other non-current assets and liabilities3	(32,547		)	6,235			(38,782		)
Net cash provided by operating activities	$	1,086,803		$	818,916		$	267,887

_______________

¹  Non-cash items include depreciation, amortization, deferred income taxes, net unrealized (gain) loss on derivative instruments, AFUDC-equity, production tax credits and miscellaneous non-cash items.

²   Changes in working capital include receivables, unbilled revenue, materials/supplies, fuel/gas inventory, income taxes, prepayments, purchased gas adjustments, accounts payable and accrued expenses.

³   Other non-current assets and liabilities include funding of pension liability.

Year Ended December 31, 2017 compared to 2016

Cash generated from operations for the year ended December 31, 2017 increased by $267.9 million including a net income decrease of $60.5 million. The following are significant factors that impacted PSE's cash flows from operations:

• Non-cash items increased $151.5 million primarily due to changes in derivative instruments of $114.6 million, depreciation and amortization of $42.4 million, deferred taxes of $36.1 million and conservation amortization of $13.4 million offset by a decrease of $53.3 million in production tax credits. For further discussion, see Other Operating Expenses in Item 7, Management's Discussion and Analysis and Note 13, "Income Taxes" in Item 8.

• Changes in cash flow resulting from working capital increased $151.8 million primarily due to changes in accounts receivable and unbilled revenue of $50.7 million, an increase to the purchased gas adjustment of $34.2 million as discussed previously in the electric and natural gas margin discussion, an increase of $27.5 million in materials and supplies, and an increase of $47.0 million in prepayments.

• Regulatory assets and liabilities cash flow increased $63.9 million primarily due to changes in decoupling and derivatives offset by changes in purchased gas adjustments.

56

• Other non-current assets and liabilities cash flow decreased $38.8 million primarily due to an increase in the long-term incentive plan accrual, an increase in major maintenance and inspections, reduced pension funding and other changes in long-term assets and liabilities.

Puget Energy	Year Ended December 31,
(Dollars in Millions)	2017			2016			Change
Net income	$	175,194		$	312,899		$	(137,705	)
Non-cash items1	837,569			602,535			235,034
Changes in cash flow resulting from working capital2	93,654			(24,936		)	118,590
Regulatory assets and liabilities	(88,875		)	(153,643		)	64,768
Other non-current assets and liabilities3	(45,411		)	(7,565		)	(37,846		)
Net cash provided by operating activities	$	972,131		$	729,290		$	242,841

_______________

¹  Non-cash items include depreciation, amortization, deferred income taxes, net unrealized (gain) loss on derivative instruments, AFUDC-equity, production tax credits and other miscellaneous non-cash items.

²   Changes in working capital include receivables, unbilled revenue, materials/supplies, fuel/gas inventory, income taxes, prepayments, purchased gas adjustments, accounts payable and accrued expenses.

³   Other non-current assets and liabilities include funding of pension liability.

Year Ended December 31, 2017 compared to 2016

Cash generated from operations for the year ended December 31, 2017 increased by $242.8 million compared to the same period in 2016.  The net difference was primarily impacted by the increase from cash flow provided by the operating activities of PSE, as previously discussed. The remaining variance is explained below:

• Non-cash items increased $83.6 million primarily due to changes in deferred taxes of $78.8 million. For further discussion, see Note 13, "Income Taxes" in Item 8.

• Changes in cash flow resulting from working capital decreased $33.2 million primarily due to amounts owed to PSE related to Puget LNG.

57

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.

For information on Puget Energy and PSE dividends, long-term debt and credit facilities, see Note 4, “Dividend Payment Restrictions, Note 6, “Long-term Debt” and Note 7, “Liquidity Facilities and Other Financing Arrangements” to the consolidated financial statements included in Item 8 of this report.

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, 2017, PSE could issue:

• Approximately $2.6 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $4.3 billion of electric bondable property available for issuance, subject to an interest coverage ratio limitation of 2.0 times net earnings available for interest (as defined in the electric utility mortgage), which PSE exceeded at December 31, 2017; and

• Approximately $535.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $891.7 million of natural gas bondable property available for issuance, subject to a combined natural gas and electric interest coverage test of 1.75 times net earnings available for interest and a natural 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, 2017

At December 31, 2017, PSE had approximately $7.2 billion in electric and natural gas rate base to support the interest coverage ratio limitation test for net earnings available for interest.

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.  Management believes the following accounting policies are particularly important to the financial statements and 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 a 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,

58

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 Washington Commission 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. The Company will not record any decoupling revenue that is expected to take longer than 24 months to collect following the end of the annual period in which the revenues would have otherwise been recognized. Once determined to be collectible within 24 months, any previously non-recorded amounts will be recorded.

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, 2017 in the amount of $953.1 million and $1,758.6 million, respectively, and regulatory assets and liabilities at December 31, 2016 of $1.1 billion and $653.3 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 Item 7, "Business – Regulation and Rates".  The increases and decreases in the cost of natural gas supply are reflected in customer bills through the PGA mechanism.  PSE expects to fully recover/refund these regulatory balances 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 qualitative and quantitative test.  Management must first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill. If, after assessing the totality of events or circumstances during a qualitative assessment, management determines the fair value of a reporting unit is less than its carrying amount, then the entity shall perform a quantitative test to determine impairment.  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, 2017.  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: (i) estimation of future cash flows, which is dependent on internal forecasts and other market factors, (ii) estimation of the long-term rate of growth for Puget Energy’s business including other market factors, (iii) estimation of the useful life over which cash flows will occur, (iv) the selection of utility holding companies determined to be comparable to Puget Energy, and (v) the determination of an appropriate weighted-average cost of capital or discount rate.

59

Management estimated the fair value of Puget Energy’s equity to be approximately $5.5 billion at the October 1, 2017 measurement date for the annual test of goodwill impairment.  The carrying value of Puget Energy’s equity was approximately $3.8 billion with the excess of the fair value over the carrying value representing 44.7% or $1.7 billion.

The income approach and the market approach valuations resulted in Puget Energy equity values of $5.2 and $5.8 billion, respectively.  The result of the income approach was very sensitive to long-term cash flow growth rates applicable to periods beyond management’s five-year business plan and financial forecast period and the weighted-average cost of capital assumptions of 3.0% and 5.9%, respectively.

The following table summarizes the results of the income valuation method, using the long-term growth rate and weighted average cost of capital:

Equity Value Sensitivity Table
(Dollars in Billions)
Weighted-Average Cost of Capital Rate	Long-Term Growth Rate
	2.8		%	2.9		%	3.0		%	3.1		%	3.2		%	3.3		%
6.2%	$	3.7		$	4.0		$	4.3		$	4.6		$	4.9		$	5.3
5.9	4.5			4.9			5.2			5.6			6.0			6.5
5.7	5.6			6.0			6.4			6.9			7.4			7.9

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 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.

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.  PSE 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, 2017, the Company did not have any outstanding interest rate swap instruments.

For additional information, see Item 7A, "Quantitative and Qualitative Disclosures about Market Risk" Note 9, "Accounting for Derivative Instruments and Hedging Activities" and Note 10, "Fair Value Measurements" to the consolidated financial statements included in Item 8 of this report.

60

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, "Quantitative and Qualitative Disclosures about Market Risk".

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 $12.1 million, $14.5 million and $22.9 million for the years ended December 31, 2017, 2016 and 2015, respectively.  Of these amounts, approximately 51.6%, 55.5% and 58.5% were included in utility operations and maintenance expense in 2017, 2016 and 2015, respectively, and the remaining amounts were capitalized.  For the years ended December 31, 2017 and 2016, Puget Energy recognized incremental qualified pension income of $13.4 million and $15.5 million, respectively.  In 2018, it is expected that PSE and Puget Energy will recognize pension expense of $11.5 million and incremental qualified pension income of $13.0 million, respectively.

PSE has a Supplemental Executive Retirement Plan (SERP).  PSE recognized pension and other postretirement benefit expenses of $4.8 million, $4.8 million and $5.6 million for the years ended December 31, 2017, 2016 and 2015, respectively.  For the years ended December 31, 2017 and 2016, Puget Energy recognized incremental income of $0.5 million and $0.4 million, respectively.  In 2018, it is expected that PSE and Puget Energy will recognize pension expense of $5.1 million and incremental pension income of $0.5 million, respectively.

PSE also has other limited postretirement benefit plans.  PSE recognized income of $0.5 million, $0.5 million and $0.2 million for the years ended December 31, 2017, 2016 and 2015, respectively.  For the years ended December 31, 2017 and 2016, Puget Energy recognized incremental expense of $0.2 million each year.  In 2018, it is expected that PSE and Puget Energy will recognize income of $0.5 million 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 2017, the Company made cash contributions of $18.0 million to the qualified defined benefit plan.  Management is closely monitoring the funding status of its qualified pension plan.  At December 31, 2017 and 2016, the Company’s qualified pension plan was $3.9 million overfunded and $32.3 million underfunded as measured under GAAP, or 100.6% and 95.0% funded, respectively. As of January 1, 2018, 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 pension plan, SERP and other postretirement plans for the year ending December 31, 2018 are expected to be at least $18.0 million, $5.5 million and $0.3 million, respectively.

The discount rate used in accounting for pension and other benefit obligations decreased from 4.50% in 2016 to 4.00% in 2017. The discount rate used in accounting for pension and other benefit expense decreased from 4.65% in 2016 to 4.50% in 2017. The rate of return on plan assets for qualified pension benefits decreased from 7.75% in 2016 to 7.45% in 2017. The rate of return on plan assets for other benefits in 2017 and 2016 was 6.75%, respectively.

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

61

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	$	(38,831	)	$	(1,940	)	$	(548	)
Decrease in discount rate	50 basis points	43,000			2,069			601

Puget Energy	Change in Assumption	Impact on 2017 Pension Expense Increase /(Decrease)
(Dollars in Thousands)		Pension Benefits			SERP			Other Benefits
Increase in discount rate	50 basis points	$	155		$	(173	)	$	(50	)
Decrease in discount rate	50 basis points	2,333			181			52
Increase in return on plan assets	50 basis points	(3,207		)	*			(34		)
Decrease in return on plan assets	50 basis points	3,207			*			34

Puget Sound Energy	Change in Assumption	Impact on 2017 Pension Expense Increase /(Decrease)
(Dollars in Thousands)		Pension Benefits			SERP			Other Benefits
Increase in discount rate	50 basis points	$	(2,906	)	$	(173	)	$	(51	)
Decrease in discount rate	50 basis points	3,026			181			52
Increase in return on plan assets	50 basis points	(3,212		)	*			(34		)
Decrease in return on plan assets	50 basis points	3,212			*			34

_______________

* Calculation not applicable.

Recently Adopted Accounting Pronouncements

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

62

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 natural gas portfolio risks. The forward physical electric and natural gas contracts are both fixed and variable (at index). 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, 2017				December 31, 2016
(Dollars in Thousands)	Assets		Liabilities		Assets		Liabilities
Electric portfolio:
Current	$	12,553	$	37,991	$	30,596	$	30,997
Long-term	838		11,059		5,864		10,332
Total electric derivatives	13,391		49,050		36,460		41,329
Natural Gas portfolio:
Current	9,694		26,868		23,745		13,172
Long-term	1,320		10,176		2,874		5,929
Total natural gas derivatives	11,014		37,044		26,619		19,101
Total energy derivatives	$	24,405	$	86,094	$	63,079	$	60,430

At December 31, 2017, the Company had total assets of $24.4 million and total liabilities of $86.1 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 $10.6 million.

63

The change in fair value of the Company’s outstanding energy derivative instruments from December 31, 2016 through December 31, 2017 is summarized in the table below:

Puget Energy and Puget Sound Energy Energy Derivative Contracts Asset (Liability)
(Dollars in Thousands)
Fair value of contracts outstanding at December 31, 2016	$	2,649
Contracts realized or otherwise settled during 2017	54,169
Change in fair value of derivatives	(118,507		)
Fair value of contracts outstanding at December 31, 2017	$	(61,689	)

The fair value of the Company’s outstanding derivative instruments at December 31, 2017, 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)	2018			2019-2020			2021-2022			Thereafter		Total
Prices provided by external sources1	$	(46,927	)	$	(17,434	)	$	(349	)	$	—	$	(64,710	)
Prices based on internal models and valuation methods	4,315			18			(1,312		)	—		3,021
Total fair value	$	(42,612	)	$	(17,416	)	$	(1,661	)	$	—	$	(61,689	)

_______________

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 Note 9, "Accounting for Derivative Instruments and Hedging Activities" and Note 10, "Fair Value Measurements" to the consolidated financial statements included in Item 8 of this report.

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 natural gas and electric contracts; and North American Energy Standards Board (NAESB) agreements which standardize physical natural 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. In order to mitigate concentrated credit risk with a subset of counterparties, PSE executed a futures and cleared swaps agreement in November 2016, and began transacting power futures contracts on the Intercontinental Exchange (ICE) in early 2017.

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, 2017, PSE held approximately $458.5 million in standby letters of credit or limited parental guarantees and had 6 counterparties with unlimited parental guarantees, in support of various electric and natural gas transactions. The Company monitors counterparties for significant swings in credit default swap rates, credit rating changes by external rating agencies, ownership changes or financial distress. As of December 31, 2017, approximately 83.6% 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.

64

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, 2017, 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, 2017, 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.

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, 2017				December 31, 2016
(Dollars in Thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Puget Energy	$	5,787,392	$	7,191,513	$	5,599,836	$	6,805,791
Puget Sound Energy	$	4,079,374	$	5,118,528	$	3,993,061	$	4,816,807

For further details regarding Puget Energy and Puget Sound Energy debt instruments, see Note 6, "Long-Term Debt" and Note 10, "Fair Value Measurements" to the consolidated financial statements included in Item 8 of this report.

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, 2017 was a net loss of $5.0 million after tax and accumulated amortization.  This compares to an after-tax loss of $5.4 million in OCI as of December 31, 2016.  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, 2017.

The Company may also enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts.  In January 2017, Puget Energy's outstanding interest rate swaps matured, and as of December 31, 2017, the Company had no outstanding interest rate swap instruments.

65

ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

	Page
REPORTS:
Report of Management and Statement of Responsibility	67
Report of Independent Registered Public Accounting Firm – Puget Energy	68
Report of Independent Registered Public Accounting Firm – Puget Sound Energy	70
INDEX TO FINANCIAL STATEMENTS:
PUGET ENERGY:
Consolidated Statements of Income - Years Ended December 31, 2017, 2016 and 2015	72
Consolidated Statements of Comprehensive Income - Years Ended December 31, 2017, 2016, 2015	73
Consolidated Balance Sheets - December 31, 2017 and 2016	74
Consolidated Statements of Common Shareholder’s Equity - Years Ended December 31, 2017, 2016 and 2015	76
Consolidated Statements of Cash Flows - Years Ended December 31, 2017, 2016 and 2015	77
PUGET SOUND ENERGY:
Consolidated Statements of Income - Years Ended December 31, 2017, 2016 and 2015	78
Consolidated Statements of Comprehensive Income - Years Ended December 31, 2017, 2016, 2015	79
Consolidated Balance Sheets - December 31, 2017 and 2016	80
Consolidated Statements of Common Shareholder’s Equity - Years Ended December 31, 2017, 2016 and 2015	82
Consolidated Statements of Cash Flows - Years Ended December 31, 2017, 2016 and 2015	83

NOTES  to the Consolidated Financial Statements of Puget Energy and Puget Sound Energy:
Note 1.	Summary of Significant Accounting Policies	84
Note 2.	New Accounting Pronouncements	89
Note 3.	Regulation and Rates	90
Note 4.	Dividend Payment Restrictions	94
Note 5.	Utility Plant	95
Note 6.	Long-Term Debt	98
Note 7.	Liquidity Facilities and Other Financing Arrangements	99
Note 8.	Leases	101
Note 9.	Accounting for Derivative Instruments and Hedging Activities	101
Note 10.	Fair Value Measurements	105
Note 11.	Employee Investment Plans	110
Note 12.	Retirement Benefits	111
Note 13.	Income Taxes	117
Note 14.	Litigation	120
Note 15.	Commitments and Contingencies	122
Note 16.	Related Party Transactions	123
Note 17.	Segment Information	124
Note 18.	Accumulated Other Comprehensive Income (Loss)	124

SUPPLEMENTAL QUARTERLY FINANCIAL DATA	127
SCHEDULE:
I.   Condensed Financial Information of Puget Energy	128
II.  Valuation and Qualifying Accounts and Reserves	132
Years Ended December 31, 2017, 2016 and 2015

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.

66

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/ Stephen J. King
Kimberly J. Harris	Daniel A. Doyle	Stephen J. King
President and Chief Executive Officer	Senior Vice President and Chief Financial Officer	Controller and Principal Accounting Officer

67

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder of

Puget Energy, Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the consolidated financial statements, including the related notes and financial statement schedules, of Puget Energy, Inc. (the Company) and its subsidiaries as listed in the accompanying index (collectively referred to as the “consolidated financial statements”).We also have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework(2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidatedfinancial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of theiroperations and their cash flows for each of the three years in the period ended December 31, 2017in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework(2013)issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidatedfinancial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidatedfinancial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. 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.

Definition and Limitations of Internal Control over Financial Reporting

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.

68

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

March 1, 2018

We have served as the Company or its predecessor’s auditor since 1933.

69

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder of

Puget Sound Energy, Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the consolidated financial statements, including the related notes and financial statement schedule, of Puget Sound Energy, Inc. (the Company) and its subsidiary as listed in the accompanying index (collectively referred to as the “consolidated financial statements”).We also have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework(2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidatedfinancial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of theiroperations and their cash flows for each of the three years in the period ended December 31, 2017in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework(2013)issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidatedfinancial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidatedfinancial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. 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.

Definition and Limitations of Internal Control over Financial Reporting

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.

70

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

March 1, 2018

We have served as the Company or its predecessor’s auditor since 1933.

71

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

	Year Ended December 31,
	2017			2016			2015
Operating revenue:
Electric	$	2,420,663		$	2,238,492		$	2,128,468
Natural gas	997,759			890,510			947,549
Other	41,854			35,299			16,683
Total operating revenue	3,460,276			3,164,301			3,092,700
Operating expenses:
Energy costs:
Purchased electricity	590,030			531,596			499,522
Electric generation fuel	206,275			215,331			249,907
Residential exchange	(75,933		)	(69,824		)	(112,473		)
Purchased natural gas	360,009			313,954			403,310
Unrealized (gain) loss on derivative instruments, net	30,790			(83,795		)	(13,233		)
Utility operations and maintenance	584,263			568,492			530,720
Non-utility expense and other	40,487			27,151			10,818
Depreciation and amortization	481,969			439,579			420,807
Conservation amortization	121,216			107,784			110,866
Taxes other than income taxes	360,673			328,649			320,531
Total operating expenses	2,699,779			2,378,917			2,420,775
Operating income (loss)	760,497			785,384			671,925
Other income (deductions):
Other income	27,892			25,539			20,711
Other expense	(14,104		)	(10,923		)	(6,764		)
Non-hedged interest rate swap expense	28			(1,062		)	(3,796		)
Interest charges:
AFUDC	10,826			9,304			7,575
Interest expense	(354,802		)	(355,139		)	(356,696		)
Income (loss) before income taxes	430,337			453,103			332,955
Income tax (benefit) expense	255,143			140,204			91,776
Net income (loss)	$	175,194		$	312,899		$	241,179

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

72

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

	Year Ended December 31,
	2017		2016			2015
Net income (loss)	$	175,194	$	312,899		$	241,179
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $5,078, $(3,471) and $5,087, respectively	9,430		(6,446		)	9,444
Reclassification of net unrealized (gain) loss on energy derivative instruments, net of tax of $0, $0 and $179, respectively	—		—			333
Other comprehensive income (loss)	9,430		(6,446		)	9,777
Comprehensive income (loss)	$	184,624	$	306,453		$	250,956

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

73

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

ASSETS

	December 31,
	2017			2016
Utility plant (at original cost, including construction work in progress of $495,937 and $420,278, respectively):
Electric plant	$	8,135,847		$	7,673,772
Natural gas plant	3,307,545			3,051,586
Common plant	811,815			594,994
Less:  Accumulated depreciation and amortization	(2,428,524		)	(2,161,796		)
Net utility plant	9,826,683			9,158,556
Other property and investments:
Goodwill	1,656,513			1,656,513
Other property and investments	182,355			106,418
Total other property and investments	1,838,868			1,762,931
Current assets:
Cash and cash equivalents	26,616			28,878
Restricted cash	10,145			12,418
Accounts receivable, net of allowance for doubtful accounts of $8,901 and $9,798, respectively	341,110			329,375
Unbilled revenue	222,186			234,053
Purchased gas adjustment receivable	—			2,785
Materials and supplies, at average cost	107,003			106,378
Fuel and natural gas inventory, at average cost	49,908			58,181
Unrealized gain on derivative instruments	22,247			54,341
Prepaid expense and other	21,996			43,046
Power contract acquisition adjustment gain	12,207			33,413
Total current assets	813,418			902,868
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	—			72,038
Power cost adjustment mechanism	4,576			4,531
Regulatory assets related to power contracts	19,454			22,613
Other regulatory assets	948,532			1,034,348
Unrealized gain on derivative instruments	2,158			8,738
Power contract acquisition adjustment gain	162,711			241,648
Other	74,389			58,109
Total other long-term and regulatory assets	1,211,820			1,442,025
Total assets	$	13,690,789		$	13,266,380

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

74

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

CAPITALIZATION AND LIABILITIES

	December 31,
	2017			2016
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	465,355			413,468
Accumulated other comprehensive income (loss), net of tax	(24,282		)	(33,712		)
Total common shareholder’s equity	3,750,030			3,688,713
Long-term debt:
First mortgage bonds and senior notes	3,164,412			3,362,000
Pollution control bonds	161,860			161,860
Junior subordinated notes	250,000			250,000
Long-term debt	1,902,600			1,812,480
Debt discount, issuance costs and other	(220,943		)	(234,679		)
Total long-term debt	5,257,929			5,351,661
Total capitalization	9,007,959			9,040,374
Current liabilities:
Accounts payable	359,586			317,043
Short-term debt	329,463			245,763
Current maturities of long-term debt	200,000			2,412
Purchased gas adjustment payable	16,051			—
Accrued expenses:
Taxes	117,948			111,428
Salaries and wages	53,220			49,749
Interest	73,564			73,610
Unrealized loss on derivative instruments	64,859			44,310
Power contract acquisition adjustment loss	2,762			3,159
Other	80,206			71,996
Total current liabilities	1,297,659			919,470
Other Long-term and regulatory liabilities:
Deferred income taxes	746,868			1,570,931
Unrealized loss on derivative instruments	21,235			16,261
Regulatory liabilities	731,587			654,622
Regulatory liability for deferred income taxes	1,011,626			—
Regulatory liabilities related to power contracts	174,918			275,061
Power contract acquisition adjustment loss	16,693			19,454
Other deferred credits	682,244			770,207
Total other long-term and regulatory liabilities	3,385,171			3,306,536
Commitments and contingencies (Note 15)
Total capitalization and liabilities	$	13,690,789		$	13,266,380

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

75

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, 2014	200	$	—	$	3,308,957	$	271,414		$	(37,043	)	$	3,543,328
Net income (loss)	—	—		—		241,179			—			241,179
Common stock dividend paid	—	—		—		(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
Net income (loss)	—	—		—		312,899			—			312,899
Common stock dividend paid	—	—		—		(148,965		)	—			(148,965		)
Other comprehensive income (loss)	—	—		—		—			(6,446		)	(6,446		)
Balance at December 31, 2016	200	$	—	$	3,308,957	$	413,468		$	(33,712	)	$	3,688,713
Net income (loss)	—	—		—		175,194			—			175,194
Common stock dividend paid	—	—		—		(123,307		)	—			(123,307		)
Other comprehensive income (loss)	—	—		—		—			9,430			9,430
Balance at December 31, 2017	200	$	—	$	3,308,957	$	465,355		$	(24,282	)	$	3,750,030

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

76

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

	Year Ended December 31,
	2017			2016			2015
Operating activities:
Net income (loss)	$	175,194		$	312,899		$	241,179
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	481,969			439,579			420,807
Conservation amortization	121,216			107,784			110,866
Deferred income taxes and tax credits, net	254,524			139,640			91,978
Net unrealized (gain) loss on derivative instruments	30,650			(88,704		)	(17,255		)
Derivative contracts classified as financing activities due to merger	—			—			8,045
AFUDC - equity	(15,027		)	(12,576		)	(9,325		)
Production tax credits	(53,331		)	—			—
Other non-cash	17,568			16,812			16,155
Funding of pension liability	(18,000		)	(24,000		)	(18,000		)
Regulatory assets and liabilities	(88,875		)	(153,643		)	(156,491		)
Other long-term assets and liabilities	(27,411		)	16,435			21,729
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	132			(21,763		)	(66,703		)
Materials and supplies	(625		)	(28,134		)	4,945
Fuel and natural gas inventory	8,266			473			9,332
Prepayments and other	21,050			(25,927		)	4,086
Purchased gas adjustment	18,836			(15,374		)	33,662
Accounts payable	26,396			32,465			(48,037		)
Taxes payable	6,520			(3,426		)	7,072
Other	13,079			36,750			(5,323		)
Net cash provided by (used in) operating activities	972,131			729,290			648,722
Investing activities:
Construction expenditures - excluding equity AFUDC	(1,040,135		)	(706,444		)	(587,225		)
Restricted cash	2,273			(4,469		)	24,914
Other	(195		)	(1,921		)	754
Net cash provided by (used in) investing activities	(1,038,057		)	(712,834		)	(561,557		)
Financing activities:
Change in short-term debt, net	83,700			86,759			74,004
Dividends paid	(123,307		)	(148,965		)	(263,059		)
Proceeds from long-term debt and bonds issued	90,120			12,481			825,000
Redemption of bonds and notes	—			—			(711,000		)
Derivative contracts classified as financing activities due to merger	—			—			(8,045		)
Other	13,151			19,653			902
Net cash provided by (used in) financing activities	63,664			(30,072		)	(82,198		)
Net increase (decrease) in cash and cash equivalents	(2,262		)	(13,616		)	4,967
Cash and cash equivalents at beginning of period	28,878			42,494			37,527
Cash and cash equivalents at end of period	$	26,616		$	28,878		$	42,494
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	326,798		$	329,603		$	339,866
Cash payments (refunds) for income taxes	1,649			—			2
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	92,959		$	76,813		$	51,588
Reclassification of Colstrip from utility plant to a regulatory asset	(49,177		)	176,804			—
Reclassification of hydro treasury grants to a regulatory liability	95,935			—			—

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

77

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

	Year Ended December 31,
	2017			2016			2015
Operating revenue:
Electric	$	2,420,663		$	2,238,492		$	2,128,468
Natural gas	997,759			890,510			947,549
Other	41,854			35,616			17,241
Total operating revenue	3,460,276			3,164,618			3,093,258
Operating expenses:
Energy costs:
Purchased electricity	590,030			531,596			499,522
Electric generation fuel	206,275			215,331			249,907
Residential exchange	(75,933		)	(69,824		)	(112,473		)
Purchased natural gas	360,009			313,954			403,310
Unrealized (gain) loss on derivative instruments, net	30,790			(83,795		)	(12,688		)
Utility operations and maintenance	584,263			568,492			530,720
Non-utility expense and other	52,389			37,859			26,618
Depreciation and amortization	481,955			439,579			420,807
Conservation amortization	121,216			107,784			110,866
Taxes other than income taxes	360,673			328,649			320,531
Total operating expenses	2,711,667			2,389,625			2,437,120
Operating income (loss)	748,609			774,993			656,138
Other income (deductions):
Other income	26,853			25,537			20,711
Other expense	(14,104		)	(10,923		)	(6,764		)
Interest charges:
AFUDC	10,826			9,304			7,575
Interest expense	(240,144		)	(242,983		)	(247,571		)
Income (loss) before income taxes	532,040			555,928			430,089
Income tax (benefit) expense	211,986			175,347			125,900
Net income (loss)	$	320,054		$	380,581		$	304,189

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

78

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

	Year Ended December 31,
	2017		2016		2015
Net income (loss)	$	320,054	$	380,581	$	304,189
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $9,848, $2,004 and $10,987, respectively	18,288		3,722		20,404
Reclassification of net unrealized (gain) loss on energy derivative instruments, net of tax of $0, $0 and $369, respectively	—		—		686
Amortization of treasury interest rate swaps to earnings, net of tax of $171, $171 and $171, respectively	317		317		317
Other comprehensive income (loss)	18,605		4,039		21,407
Comprehensive income (loss)	$	338,659	$	384,620	$	325,596

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

79

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

ASSETS

	December 31,
	2017			2016
Utility plant (at original cost, including construction work in progress of $495,937 and $420,278, respectively):
Electric plant	$	10,232,771		$	9,813,169
Natural gas plant	3,882,733			3,640,271
Common plant	843,145			632,718
Less: Accumulated depreciation and amortization	(5,131,966		)	(4,927,602		)
Net utility plant	9,826,683			9,158,556
Other property and investments:
Other property and investments	76,350			77,960
Total other property and investments	76,350			77,960
Current assets:
Cash and cash equivalents	25,864			28,481
Restricted cash	10,145			12,418
Accounts receivable, net of allowance for doubtful accounts of $8,901 and $9,798, respectively	343,546			344,964
Unbilled revenue	222,186			234,053
Purchased gas adjustment receivable	—			2,785
Materials and supplies, at average cost	107,003			106,378
Fuel and natural gas inventory, at average cost	48,585			56,851
Unrealized gain on derivative instruments	22,247			54,341
Prepaid expenses and other	21,996			43,046
Total current assets	801,572			883,317
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	—			71,517
Power cost adjustment mechanism	4,576			4,531
Other regulatory assets	948,540			1,034,352
Unrealized gain on derivative instruments	2,158			8,738
Other	71,827			58,109
Total other long-term and regulatory assets	1,027,101			1,177,247
Total assets	$	11,731,706		$	11,297,080

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

80

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

CAPITALIZATION AND LIABILITIES

	December 31,
	2017			2016
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			3,275,105
Retained earnings	452,066			359,795
Accumulated other comprehensive income (loss), net of tax	(126,906		)	(145,511		)
Total common shareholder’s equity	3,601,124			3,490,248
Long-term debt:
First mortgage bonds and senior notes	3,164,412			3,362,000
Pollution control bonds	161,860			161,860
Junior subordinated notes	250,000			250,000
Debt discount, issuance costs and other	(26,361		)	(28,974		)
Total long-term debt	3,549,911			3,744,886
Total capitalization	7,151,035			7,235,134
Current liabilities:
Accounts payable	359,585			317,043
Short-term debt	329,463			245,763
Current maturities of long-term debt	200,000			2,412
Purchased gas adjustment payable	16,051			—
Accrued expenses:
Taxes	117,063			111,428
Salaries and wages	53,220			49,749
Interest	47,837			48,087
Unrealized loss on derivative instruments	64,859			44,170
Other	80,206			71,996
Total current liabilities	1,268,284			890,648
Other Long-term and regulatory liabilities:
Deferred income taxes	869,473			1,732,390
Unrealized loss on derivative instruments	21,235			16,261
Regulatory liabilities	730,273			653,296
Regulatory liability for deferred income taxes	1,012,260			—
Other deferred credits	679,146			769,351
Total other long-term and regulatory liabilities	3,312,387			3,171,298
Commitments and contingencies (Note 15)
Total capitalization and liabilities	$	11,731,706		$	11,297,080

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

81

 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, 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 paid	—	—		—		(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
Net income (loss)	—	—		—		380,581			—			380,581
Common stock dividend paid	—	—		—		(257,364		)	—			(257,364		)
Other comprehensive income (loss)	—	—		—		—			4,039			4,039
Balance at December 31, 2016	85,903,791	$	859	$	3,275,105	$	359,795		$	(145,511	)	$	3,490,248
Net income (loss)	—	—		—		320,054			—			320,054
Common stock dividend paid	—	—		—		(227,783		)	—			(227,783		)
Other comprehensive income (loss)	—	—		—		—			18,605			18,605
Balance at December 31, 2017	85,903,791	$	859	$	3,275,105	$	452,066		$	(126,906	)	$	3,601,124

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

82

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

	Year Ended December 31,
	2017			2016				2015
Operating activities:
Net income (loss)	$	320,054		$	380,581			$	304,189
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	481,955			439,579				420,807
Conservation amortization	121,216			107,784				110,866
Deferred income taxes and tax credits, net	210,842			174,776				125,900
Net unrealized (gain) loss on derivative instruments	30,790			(83,795		)		(12,688		)
AFUDC - equity	(15,027		)	(12,576		)		(9,325		)
Production tax credits	(53,331		)	—			—	—
Other non-cash	6,445			5,672				5,512
Funding of pension liability	(18,000		)	(24,000		)		(18,000		)
Regulatory assets and liabilities	(88,875		)	(152,786		)		(156,491		)
Other long-term assets and liabilities	(14,547		)	30,235				36,481
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	13,285			(37,385		)		(66,547		)
Materials and supplies	(625		)	(28,134		)		4,945
Fuel and natural gas inventory	8,266			473				9,332
Prepayments and other	21,050			(25,927		)		4,089
Purchased gas adjustment	18,836			(15,374		)		33,662
Accounts payable	26,396			32,465				(48,031		)
Taxes payable	5,635			(3,426		)		7,072
Other	12,438			30,754				(12,992		)
Net cash provided by (used in) operating activities	1,086,803			818,916				738,781
Investing activities:
Construction expenditures - excluding equity AFUDC	(963,652		)	(681,112		)		(587,225		)
Restricted cash	2,273			(4,469		)		24,914
Other	241			4,156				6,386
Net cash provided by (used in) investing activities	(961,138		)	(681,425		)		(555,925		)
Financing activities:
Change in short-term debt, net	83,700			86,759				74,004
Dividends paid	(227,783		)	(257,364		)		(270,233		)
Loan from (payment to) parent	—			—				(28,933		)
Investment from parent	—			—				28,900
Proceeds from long-term debt and bonds issued	—			—				425,000
Redemption of bonds and notes	—			—				(412,000		)
Other	15,801			19,739				4,796
Net cash provided by (used in) financing activities	(128,282		)	(150,866		)		(178,466		)
Net increase (decrease) in cash and cash equivalents	(2,617		)	(13,375		)		4,390
Cash and cash equivalents at beginning of period	28,481			41,856				37,466
Cash and cash equivalents at end of period	$	25,864		$	28,481			$	41,856
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	224,423		$	227,668			$	242,774
Cash payments (refunds) for income taxes	3,058			—				2
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	92,959		$	76,813			$	51,588
Reclassification of Colstrip from utility plant to a regulatory asset	(49,177		)	176,804				—
Reclassification of hydro treasury grants to a regulatory liability	95,935			—				—

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

83

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.  Puget Energy also has a wholly-owned non-regulated subsidiary, named Puget LNG, LLC (Puget LNG), formed in 2016, which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNG facility, currently under construction. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that occur under PSE and are allocated to Puget LNG are related party transactions by nature. As of December 31, 2017, Puget LNG has incurred $104.3 million in construction work in progress and operating costs related to Puget LNG’s portion of the Tacoma LNG facility.

The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries.  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 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.

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 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.

Other Property and Investments

For PSE, the costs of other property and investments (i.e., non-utility) 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.  Replacements 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

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 annual depreciation provision stated as a percent of a depreciable electric utility plant was 2.8%, for each of 2017, 2016 and 2015; depreciable natural gas utility plant was 3.4%, for each of 2017, 2016 and 2015; and depreciable common utility plant was 8.3%, 9.7% and 8.5% in 2017, 2016 and 2015, respectively.  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

84

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 qualitative and quantitative test.  Management must first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill. If, after assessing the totality of events or circumstances during a qualitative assessment, management determines the fair value of a reporting unit is less than its carrying amount, then the entity shall perform a quantitative test to determine impairment.  This would entail a full valuation of Puget Energy’s assets and liabilities and comparing the valuation to its carrying amounts, with the aggregate difference indicating the amount of impairment.  Goodwill of a reporting unit is required to be tested for impairment on an interim basis if an event occurs or circumstances change that would cause the fair value of a reporting unit to fall below its carrying amount.

Puget Energy conducted its annual impairment test in 2017 using an October 1, 2017 measurement date.  The fair value of Puget Energy’s reporting unit was estimated using a combination of the discounted cash flow and market approach.  The discounted cash flow approach 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, 2017.  There were no known events or circumstances from the date of the assessment through December 31, 2017 that would impact management’s conclusion.

Tacoma LNG Facility

The Tacoma LNG facility is intended to provide peak-shaving services to PSE’s natural gas customers. By storing surplus natural gas, PSE is able to meet the requirements of peak consumption later during different seasons. LNG will also provide fuel to transportation customers, particularly in the marine market. On January 24, 2018, the Puget Sound Clean Air Agency’s determined a Supplemental Environmental Impact Statement is necessary in order to rule on the air quality permit for the facility. As a result of requiring a Supplemental Environmental Impact Statement, the Company's construction schedule may be impacted depending on the Puget Sound Clean Air Agency's timing and decision on the air quality permit. If delayed, the construction schedule and costs may be adversely impacted. Pursuant to the Washington Commission’s order, PSE will be allocated approximately 43.0% of common capital and operating costs, consistent with the regulated portion of Tacoma LNG facility. The remaining 57.0% of common capital and operating costs of the Tacoma LNG facility will be allocated to Puget LNG.

For Puget Energy, $104.0 million in construction work in progress related to Puget LNG’s portion of the Tacoma LNG facility is reported in the “Other property and investments” financial statement line item. For PSE, construction work in progress of $87.2 million related to PSE’s portion of the Tacoma LNG facility is reported in the “Utility plant - Natural gas plant” line item, as PSE is a regulated entity.

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 carrying amounts of cash and cash equivalents are reported at cost and approximate fair value, due to the short-term maturity.

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.  The Company records these items at weighted-average cost.

85

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.  The Company records these items at the lower of cost or net realizable value 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 or losses 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.  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 when amortization periods extend longer than one year.  For further details regarding regulatory assets and liabilities, see Note 3, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.

Puget Energy recorded regulatory assets and liabilities at the time of the merger related to power purchase contracts.

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; the AFUDC debt portion is credited to interest expense, while the AFUDC equity portion is credited to other income.  Cash inflow related to AFUDC does not occur until these charges are reflected in rates. The current AFUDC rate authorized by the Washington Commission for natural gas and electric utility plant additions through December 18, 2017 was 7.77%. Effective December 19, 2017 with the Washington Commission order, the new AFUDC rate authorized is 7.60%.

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).  Revenue from retail sales is billed based on tariff rates approved by the Washington Commission.  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 tariff rate schedule to estimate the unbilled revenues by customer.

PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $257.1 million, $235.3 million and $234.2 million for 2017, 2016 and 2015, 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.

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 and gross margin erosion due to weather and 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. Revenue is recognized under this program when deemed collectible 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. On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. The rate test which limits the amount of revenues PSE can collect in its annual filings increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The

86

Company will not record any decoupling revenue that is expected to take longer than 24 months to collect following the end of the annual period in which the revenues would have otherwise been recognized. Once determined to be collectible within 24 months, any previously non-recognized amounts will be recognized. 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 balance for allowance for doubtful accounts at December 31, 2017 and 2016 was $8.9 million and $9.8 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.  Under the December 5, 2017 Washington Commission order regarding PSE’s GRC, the cumulative annual cost threshold for deferral of storms under the mechanism increased from $8.0 million to $10.0 million effective January 1, 2018.  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, which 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.

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 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 during the first ten years of operation. From a regulatory perspective, the tax savings from these credits were intended to be refunded by PSE to its customers when monetized on the income tax return through its revenue requirement as initially approved by the Washington Commission. As the Company has not generated taxable income and these credits have not been monetized, they have not been refunded to customers. Amounts to be refunded have been recorded as a liability with an offsetting reduction to revenue as it was intended to be refunded through the revenue requirement. A deferred tax asset and reduction to deferred tax expense was also recorded for PTCs not yet monetized. These entries resulted in no net income impact. In connection with the GRC settlement in 2017, the Washington Commission authorized the Company to utilize the tax savings associated with the monetization of the PTCs to fund the following: (i) Colstrip Community Transition Fund, (ii) unrecovered Colstrip plant and (iii) incurred decommissioning and remediation costs for Colstrip. As PTCs will no longer be

87

refunded to customers through the revenue requirement, a non-cash charge to revenue and deferred tax expense will be recorded as the PTCs are monetized. These entries will result in no net income impact. At December 31, 2017 $2.1 million of PTCs are estimated to be monetized through tax filings.

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 natural gas related derivatives 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 its financial reporting.  The contracts that were de-designated related to physical electric supply contracts and natural gas swap contracts used to fix the price of natural gas for electric generation.  For these contracts and for contracts initiated after such date, all mark-to-market adjustments are recognized through earnings.  The amount previously recorded in accumulated other comprehensive income (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, 2017, 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" to the consolidated financial statements included in Item 8 of this report.

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" to the consolidated financial statements included in Item 8 of this report.

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 and presented net of long-term liabilities on the balance sheet.

88

(2)  New Accounting Pronouncements

Revenue Recognition

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

The standard is effective for the Company beginning January 1, 2018 and allows for two methods of adoption: application of the standard to each prior reporting period presented (full retrospective), or application of a cumulative effect on retained earnings recognized at the date of initial application (modified retrospective method). The Company will adopt the standard using the modified retrospective method. In preparation for adoption of the standard, the Company initiated a project team that met bi-weekly to make key accounting assessments related to the standard, which included the implementation of associated internal controls.

As a result of implementation of this standard, the Company has concluded there to be no impact on revenue for contracts with customers open as of January 1, 2018. The Company's revenue is 93.6% comprised of contracts with customers from rate-regulated sales of electricity and natural gas to retail customers where revenue will continue to be recognized over time as delivered. Pursuant to the new standard, the Company's current presentation of revenue on the income statement will not change; however, enhanced disclosure for revenue from contracts with customers and revenue outside the scope of ASC 606 will be disclosed.

Lease Accounting

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)". The FASB issued this ASU and the related amendments to increase transparency and comparability among organizations by recognizing right-of-use (ROU) lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. To meet that objective, the FASB is amending the FASB Accounting Standards Codification and creating Topic 842, Leases. ASU 2016-02requires lessees to recognize the following for all leases (with the exception of short-term leases) at the commencement date: (i) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The income statement recognition is similar to existing lease accounting and is based on lease classification. Under the new guidance, lessor accounting is largely unchanged.

This amendment is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Earlier adoption is permitted for all entities upon issuance. Reporting entities must apply a modified retrospective approach for the adoption of the new standard.  The Company will adopt ASU 2016-02 during the first quarter of fiscal year 2019. The Company expects the adoption of the standard will result in recognition of right-of-use assets and liabilities that have not previously been recorded, which will have a material impact on the consolidated balance sheets. For a current breakout of existing operating and capital leases, see Note 8, "Leases" to the consolidated financial statements included in Item 8 of this report.

Statement of Cash Flows

In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments". The amendments in ASU 2016-15 provide guidance for eight specific cash flow issues that include (i) debt prepayment or debt extinguishment costs, (ii) settlement of zero-coupon debt instruments, (iii) contingent consideration payments made after a business combination, (iv) proceeds from the settlement of insurance claims, (v) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, (vi) distribution received from equity method investees, (vii) beneficial interest in securitization transactions, and (viii) separately identifiable cash flows and application of the predominance principle.

This update is effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted for all entities upon issuance. The amendments in this update should be applied using a retrospective transition method to each period presented. The Company will adopt ASU 2016-15 during the first quarter of fiscal year 2018 and is in the process of evaluating the impact this standard will have on its consolidated statement of cash flows.

In November 2016, the FASB issued ASU 2016-18, "Statement of Cash Flows (Topic 230): Restricted Cash". The amendments in this update require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents,

89

and amounts generally described as restricted cash or restricted cash equivalents. The new standard is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company will adopt ASU 2016-18 during the first quarter of fiscal year 2018 retrospectively to all periods presented by moving the presentation of restricted cash, in the statement of cash flows, to net cash flows of total cash, cash equivalents, and restricted cash. Additionally, the Company will disclose the nature of the Company's restricted cash.

Retirement Benefits

In March 2017, the FASB issued ASU 2017-07, "Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost". The amendments require that an employer report the service cost component in the same line items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The line item used in the income statement to present the other components of net benefit cost must be disclosed. Additionally, the service cost component of net benefit cost is the only eligible cost for capitalization.

This amendment is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. Early adoption is permitted as of the beginning of an annual period for which financial statements (interim or annual) have not been issued or made available for issuance. The Company will adopt ASU 2017-07 during the first quarter of fiscal year 2018 by applying the amendments related to income statement activity retrospectively, and balance sheet activity prospectively. The Company’s non-service components for the year ended December 31, 2017, was a credit of $18.4 million for Puget Energy and $4.7 million for PSE.  The non-service cost components are in an income position and will be presented in the other income section, upon adoption.

Stranded Tax Effects in AOCI

In February 2018, the FASB issued ASU 2018-02, "Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income". The amendments in this update allow reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act (TCJA) and will improve the usefulness of information reported to financial statement users.

This amendment is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. Early adoption is permitted, including adoption in any interim period for reporting periods for which financial statements have not yet been issued. The Company will early adopt ASU 2018-02 during the first quarter of fiscal year 2018 through a retrospective reclassification from accumulated other comprehensive income to retained earnings. The Company is still evaluating the impact of the reclassification to retained earnings.

(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.  

90

The net regulatory assets and liabilities at December 31, 2017 and 2016 included the following:

Puget Sound Energy	Remaining Amortization Period	December 31,
(Dollars in Thousands)		2017					2016
Storm damage costs electric	4 to 6 years			128,508					122,709
Colstrip 1 & 2 Regulatory Asset	N/A			127,627					176,804
Decoupling deferrals and interest		98,769					156,408
Decoupling 24-month revenue reserve		—					(20,847	)
Total decoupling asset	Less than 2 years			98,769					135,561
Chelan PUD contract initiation	13.8 years			98,052					105,140
Environmental remediation	(a)			81,550					74,557
Lower Snake River	19.4 years			70,975					74,862
Baker Dam licensing operating and maintenance costs	N/A			54,817					61,453
Deferred Washington Commission AFUDC	10 years			50,301					51,404
Unamortized loss on reacquired debt	1 to 28 years			39,674					42,196
Property tax tracker	Less than 2 years			36,517					41,949
Energy conservation costs	(a)			35,538					41,027
PGA deferral of unrealized losses on derivative instruments	N/A			26,030					—
White River relicensing and other costs	3 years			19,502					21,627
Generation plant major maintenance, excluding Colstrip	5 to 11 years			17,216					13,178
Mint Farm ownership and operating costs	7.3 years			14,319					16,319
Colstrip major maintenance	1.5 years			8,723					6,589
Snoqualmie licensing operating and maintenance costs	N/A			7,341					8,018
Ferndale	1.8 years			7,295					11,274
Colstrip common property	7.4 years			4,618					5,334
PCA mechanism	N/A			4,576					4,531
Electron unrecovered loss	1 year			3,786					7,178
Deferred income taxes(d)	N/A			—					71,517
PGA receivable	1 year			—					2,785
Various other regulatory assets	(a)			17,382					17,173
Total PSE regulatory assets				953,116					1,113,185
Deferred income taxes(d)	N/A			(1,012,260		)			—
Cost of removal	(b)			(389,579		)			(369,300		)
Treasury grants	20 years			(205,775		)			(133,709		)
Production tax credits	(c)			(93,616		)			(93,616		)
Decoupling ROR excess earnings		(18,400	)				(13,300	)
Decoupling deferrals and interest		(7,896	)				(16,448	)
Total decoupling liability	Less than 2 years			(26,296		)			(29,748		)
PGA payable	1 year			(16,051		)			—
Summit purchase option buy-out	2.8 years			(4,463		)			(6,038		)
PGA deferral of unrealized gains on derivative instruments	N/A			—					(7,517		)
Various other regulatory liabilities	(a)			(10,544		)			(13,368		)
Total PSE regulatory liabilities				(1,758,584		)			(653,296		)
PSE net regulatory assets (liabilities)				$	(805,468	)			$	459,889

_______________

^(a)  Amortization periods vary depending on timing of underlying transactions.

^(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.

^(d)  For additional information, see Note 13,"Income Taxes" to the consolidated financial statements included in Item 8 of this report.

91

Puget Energy	Remaining Amortization Period	December 31,
(Dollars in Thousands)		2017			2016
Total PSE regulatory assets	(a)	$	953,116		$	1,113,185
Puget Energy acquisition adjustments:
Regulatory assets related to power contracts	1 to 20 years	19,454			22,613
Various other regulatory assets	Varies	(8		)	517
Total Puget Energy regulatory assets		972,562			1,136,315
Total PSE regulatory liabilities	(a)	(1,758,584		)	(653,296		)
Puget Energy acquisition adjustments:
Deferred income taxes		634			—
Regulatory liabilities related to power contracts	1 to 35 years	(174,918		)	(275,061		)
Various other regulatory liabilities	Varies	(1,314		)	(1,326		)
Total Puget Energy regulatory liabilities		(1,934,182		)	(929,683		)
Puget Energy net regulatory asset (liabilities)		$	(961,620	)	$	206,632

_______________

^(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 $389.6 million and $369.3 million in 2017 and 2016, respectively, for the cost of removal of utility plant.  These amounts are collected from PSE’s customers through depreciation rates.

General Rate Case Filing

On January 13, 2017, PSE filed its GRC with the Washington Commission, which proposed a weighted cost of capital of 7.74%, or 6.69% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.8%. The requested combined electric tariff changes would result in a net increase of $86.3 million or 4.1%, annually. The requested combined natural gas tariff changes would result in a net decrease of $22.3 million, or 2.4%, annually. Additionally, a depreciation study which calculates annual depreciation accruals related to utility plant was filed as part of the GRC filing. The tariffs were subsequently suspended, which means that the final rates authorized in the proceeding would go into effect on or shortly after the suspension date of December 13, 2017. PSE filed a supplemental filing in the GRC on April 3, 2017, which among other things provided updates to power costs. The requested combined electric tariff changes based on the updated supplemental filing would result in a net increase of $67.9 million, or 3.2%, annually. The requested combined natural gas tariff changes based on the updated supplemental filing would result in a net decrease of $29.3 million, or 3.2%, annually.

PSE’s GRC filing included the required plan for Colstrip Units 1 and 2 closures, see Note 14, "Litigation" to the consolidated financial statements included in Item 8 of this report. The filing also requested that electric energy supply fixed costs be included in PSE’s decoupling mechanism. Additionally, PSE’s filing contained requests for two new mechanisms to address regulatory lag. PSE requested procedures for an ERF that can be used to update PSE’s delivery revenues on an expedited basis following a GRC proceeding. PSE also requested approval to establish an electric cost recovery mechanism (CRM), similar to its existing natural gas CRM, which would allow PSE to obtain accelerated cost recovery on specified electric reliability projects.

On September 15, 2017, ten of the eleven parties to the proceeding, including PSE, filed a multi-party settlement agreement with the Washington Commission. The multi-party settlement resolved some, but not all, contested issues in the case. Hearings were held on August 30, 2017 regarding the contested issues and on September 29, 2017 regarding the multi-party settlement. The settlement agreement was accepted by the Washington Commission on December 5, 2017 and the rates became effective December 19, 2017. The settlement agreement resolved all but four of the contested issues between the settling parties. The settlement agreement provides for a weighted cost of capital of 7.60% or 6.55% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.5%. The settlement also resulted in a combined electric tariff change that resulted in a net increase of $20.2 million, or 0.9%, and a combined natural gas tariff change that resulted in a net decrease of $35.5 million, or 3.8%.

92

The expected closure date for Colstrip Units 1 and 2 is July 1, 2022 and the settlement included a plan to cover the costs for the closure of these Units. As part of the settlement PSE committed to fund a Colstrip Community Transition Fund of $10.0 million of which PSE shareholders will fund $5.0 million and $5.0 million will be funded by the regulatory liability for monetized PTCs, which are PTCs used on the filed tax returns. PSE is recognizing the funding of this commitment at the time the PTC’s are accrued for use in the tax return. The settlement provided that the regulatory liability for monetized PTCs will be used for the following Colstrip costs: (i) Colstrip Community Transition Fund, (ii) recover unrecovered Colstrip plant and (iii) recover incurred decommissioning and remediation costs for Colstrip. In addition, the hydro-related treasury grants were allowed to be used to fund and recover incurred decommissioning and remediation costs for Colstrip 1 and 2 as established in RCW 80.04.350. Depreciation rates were updated which increased PSE's depreciation for Colstrip Units 1 and 2. The increase in depreciation caused the Colstrip regulatory asset to be reduced to $127.6 million as of December 31, 2017. Finally, depreciation rates for Colstrip Units 3 and 4 were also updated, which increased PSE's depreciation to recover plant costs for those units based on a negotiated depreciation life ending on December 31, 2027.

The contested issues were PSE’s proposed electric CRM, the majority of decoupling issues, certain portions of electric rate spread/rate design issues and the entire natural gas rate spread/rate design-related issues. The Washington Commission also ruled on the remaining contested issues on December 5, 2017. The Washington Commission approved, PSE's proposal to modify its earning sharing mechanism to exclude normalizing adjustments that are required for Commission Basis Reporting purposes under Washington Administrative Code 480-90-257 (natural gas) and 480-100-257 (electric). The Washington Commission rejected PSE’s requested electric CRM.

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 assist in mitigating the impact of weather on operating revenue and net income. Since July 2013, 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 most residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues are recovered on a per customer basis regardless of actual consumption levels. PSE's 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 from, or refund to, customers the difference between allowed decoupling revenue and the corresponding actual revenue during the following May to April time period. During the rate plan, which ended in December 2017, the allowed decoupling revenue per customer for the recovery of delivery system costs increased by 3.0% for the electric customers and 2.2% for the natural gas customers on January 1.

On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues will continue to be recovered on a per customer basis and electric fixed production energy costs will now be decoupled and recovered on a fixed monthly amount basis. The allowed decoupling revenue will no longer increase annually on January 1 for electric and natural gas customers and these amounts can only be changed in a GRC, Power Cost Only Rate Case (PCORC) or ERF filing. Other changes include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the decoupling mechanism going forward. The rate test which limits the amount of revenues PSE can collect in its annual filings increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The decoupling mechanism will end on the effective date of PSE’s first rate case or other proceeding filed in or after 2021 unless the continuation of the mechanism is approved in either of those proceedings. PSE’s decoupling mechanism over and under collections will still be collectible or refundable after this effective date even if the decoupling mechanism is not extended.

There is a 3.0% cap for electric and 5.0% cap for natural gas on annual decoupling increases noted above and the size of decoupling deferral assets on the balance sheet, PSE performed an analysis as of December 31, 2017 to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980-605.  If not, for GAAP purposes only, PSE will need to record a reserve against the decoupling revenue and regulatory asset balance.  Once the revenue is forecasted to be collected within 24 months, the reserve can be reversed. The analysis indicated all current deferred revenues for electric and natural gas will be collected within 24 months of the annual period; therefore, there were no adjustments to 2017 decoupling revenues other than to record the previously unrecognized decoupling deferrals of $20.8 million.

93

Storm Damage Deferral Accounting

The Washington Commission issued a GRC order that defined deferrable storm events and provided that costs in excess of the annual cost threshold may be deferred for qualifying storm damage costs that meet the modified IEEE outage criteria for system average interruption duration index. In 2017 and 2016, PSE incurred $30.4 million and $22.0 million, respectively, in storm-related electric transmission and distribution system restoration costs, of which $21.6 million was deferred in 2017 and $12.4 million was deferred in 2016. Under the December 5, 2017 Washington Commission order regarding PSE’s GRC, the following changes to PSE’s storm deferral mechanism were approved: (i) the cumulative annual cost threshold for deferral of storms under the mechanism increased from $8.0 million to $10.0 million effective January 1, 2018; and (ii) qualifying events where the total qualifying cost is less than$0.5 million will not qualify for deferral and these costs will also not count toward the 10.0 million annual cost threshold.

Washington Commission Tax Deferral Filing

The TCJA was signed into law in December of 2017. As a result of this change, PSE reviewed its deferred tax balances under the new corporate tax rate.  As PSE is a regulated utility, the impact of tax rate changes on the deferred tax balance is subject to approval by the Washington Commission.   Accordingly, PSE filed an accounting petition on December 29, 2017 requesting deferred accounting treatment for the impacts of tax reform.   The deferral accounting treatment results in the tax rate change being captured in the deferred income tax balance with an offset to the regulatory liability for deferred income taxes.  The tax rate change for certain deferred tax balances that are not subject to regulatory treatment have been recorded through tax expense.

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.  In accordance with 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 $38.9 million for natural gas and $8.9 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, 2017, the Company’s share of future remediation costs is estimated to be approximately $28.6 million. The Company's deferred electric environmental costs are $17.6 million, $13.8 million and $14.0 million at December 31, 2017, 2016 and 2015, respectively, net of insurance proceeds. The Company's deferred natural gas environmental costs are $63.9 million, $60.7 million, and $52.9 million at December 31, 2017, 2016 and 2015, respectively, net of insurance proceeds. In the GRC which became effective December 19, 2017, the Company had its third party recoveries and remediation costs incurred as of September 30, 2016, net of a portion of insurance, approved for amortization and inclusion in rates.

(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, 2017, approximately $645.1 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 3.0 to 1.0.  The common equity ratio, calculated on a regulatory basis, was 48.0% at December 31, 2017, and the EBITDA to interest expense was 5.5 to 1.0 for the twelve months ended December 31, 2017.

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

Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission.  Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated

94

EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than 2.0 to 1.0.  Puget Energy's EBITDA to interest expense was 3.7 to 1.0 for the twelve months ended December 31, 2017.

At December 31, 2017, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

(5)  Utility Plant

The following table presents electric, natural gas and common utility plant classified by account:

		Puget Energy						Puget Sound Energy
Utility Plant	Estimated Useful Life	At December 31,						At December 31,
(Dollars in Thousands)	(Years)	2017			2016			2017			2016
Distribution plant	20-65	$	5,670,351		$	5,287,542		$	7,289,998		$	6,922,176
Production plant	12-90	3,068,135			3,007,546			3,954,057			3,910,129
Transmission plant	43-75	1,361,495			1,307,687			1,471,337			1,420,334
General plant	5-75	586,226			541,424			628,179			611,237
Intangible plant (including capitalized software)	NA	447,568			347,697			438,185			338,327
Plant acquisition adjustment	NA	242,826			242,826			282,792			282,792
Underground storage	25-60	31,815			30,695			45,288			44,206
Liquefied natural gas storage	25-60	12,628			12,628			14,498			14,498
Plant held for future use	NA	53,428			52,484			53,580			52,636
Recoverable Cushion Gas	NA	8,655			8,655			8,655			8,655
Plant not classified	1-125	275,014			159,345			275,014			159,345
Grant	NA	—			(99,100		)	—			(99,100		)
Capital leases, net of accumulated amortization1	4-6	1,129			645			1,129			645
Less: accumulated provision for depreciation		(2,428,524		)	(2,161,796		)	(5,131,966		)	(4,927,602		)
Subtotal		$	9,330,746		$	8,738,278		$	9,330,746		$	8,738,278
Construction work in progress	NA	495,937			420,278			495,937			420,278
Net utility plant		$	9,826,683		$	9,158,556		$	9,826,683		$	9,158,556

_______________

¹  Accumulated amortization of capital leases at Puget Energy and PSE was $0.7 million in 2017 and $0.6 million in 2016.

Jointly owned generating plant service costs are included in utility plant service cost at the Company's ownership share.  The Company provides financing for its ownership interest in the jointly owned utility plants. The following tables indicate the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, 2017.  These amounts are also included in the Utility Plant table above. The Company's share of fuel costs and operating expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income.

Puget Energy
Jointly Owned Generating Plants (Dollars in Thousands)	Energy Source (Fuel)	Company’s Ownership Share	Plant in Service at Cost		Construction Work in Progress			Accumulated Depreciation
Colstrip Units 1 & 2	Coal	50.0%	$	246,510	$	(23	)	$	(38,170	)
Colstrip Units 3 & 4	Coal	25.0%	307,254		1,726			(71,061		)
Colstrip Units 1 – 4 Common Facilities	Coal	various	83		—			(31		)
Frederickson 1	Natural Gas	49.85%	61,783		—			(3,850		)
Jackson Prairie	Natural Gas Storage	33.34%	31,141		43			(6,325		)

95

Puget Sound Energy
Jointly Owned Generating Plants (Dollars in Thousands)	Energy Source (Fuel)	Company’s Ownership Share	Plant in Service at Cost		Construction Work in Progress			Accumulated Depreciation
Colstrip Units 1 & 2	Coal	50.0%	$	378,574	$	(23	)	$	(170,234	)
Colstrip Units 3 & 4	Coal	25.0%	571,604		1,726			(335,414		)
Colstrip Units 1 – 4 Common Facilities	Coal	various	252		—			(199		)
Frederickson 1	Natural Gas	49.85%	67,851		—			(9,917		)
Jackson Prairie	Natural Gas Storage	33.34%	45,288		43			(20,471		)
Tacoma LNG	LNG	43.0%	2,667		87,207			—

Asset Retirement Obligation

The Company has recorded liabilities for steam generation sites, combustion turbine generation sites, wind generation sites, distribution and transmission poles, natural gas mains, and leased facilities where disposal is governed by ASC 410 “Asset Retirement and Environmental Obligations" (ARO).

On April 17, 2015, the U.S. Environmental Protection Agency (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 ruling requires the Company to perform an extensive study on the effects of coal ash on the environment and public health. The 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.

The CCR rule and two new legal agreements which include a consent decree with the Sierra Club and a settlement agreement with the Sierra Club and the National Wildlife Federation in 2016 make significant changes to the Company’s Colstrip operations and those changes were reviewed by the Company and the plant operator in 2015 and 2016. PSE had previously recognized a legal obligation in 2003 under EPA rules to dispose of coal ash material at Colstrip. Due to the updated Colstrip information, additional disposal costs were added to the ARO.

On September 6, 2016, PSE entered into two new agreements requiring the Company to close the Colstrip 1 and 2 plants on or before July 1, 2022 and to incur additional monitoring costs, water treatment costs, forced evaporation cost, and post closure care costs for all Colstrip Units. As a result, in 2016 the Company adjusted the Colstrip ARO ending liability to increase by $45.7 million for Colstrip 1 and 2 and $37.0 million for Colstrip 3 and 4.

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.

For the twelve months ended December 31, 2017 the Company reviewed the estimated remediation costs at Colstrip and reduced the Colstrip ARO liability by $5.5 million for Colstrip Units 1 and 2 and $12.7 million for Colstrip Units 3 and 4. The Company also recorded the Colstrip relief of liability of $3.8 million. In addition, the Company recorded a new Tacoma LNG facility ARO liability of $2.7 million for PSE and $2.2 million for Puget LNG as of December 31, 2017.

96

 The following table describes the changes to the Company’s ARO for the year ended December 31, 2017:

Puget Energy and Puget Sound Energy	At December 31,
(Dollars in Thousands)	2017			2016
Asset retirement obligation at beginning of the period	$	200,345		$	85,028
New asset retirement obligation recognized in the period1	2,881			—
Liability adjustments	(3,841		)	(411		)
Revisions in estimated cash flows	(13,748		)	113,081
Accretion expense	5,539			2,647
Asset retirement obligation at end of period1	$	191,176		$	200,345

_______________

^{1  New asset retirement obligations include $2.2 million ARO for Puget LNG only held at Puget Energy.} 

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, 2017 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.

97

(6)  Long-Term Debt

The following table presents outstanding long-term debt principal amounts and due dates as of 2017 and 2016:

(Dollars in Thousands)			At December 31,
Series	Type	Due	2017			2016
Puget Sound Energy:
6.740%	Senior Secured Note1	2018	$	200,000		$	200,000
5.500%	Promissory Note2	2020	2,412			2,412
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			425,000
4.700%	Senior Secured Note	2051	45,000			45,000
6.974%	Junior Subordinated Note	2067	250,000			250,000
*	Debt discount, issuance cost and other	*	(26,361		)	(28,974		)
Total PSE long-term debt			3,749,911			3,747,298
Puget Energy:
*	Fair value adjustment of PSE long-term debt	*	(190,895		)	(199,436		)
*	Revolving Credit Agreement	2022	102,600			12,480
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			400,000
*	Debt discount, issuance cost and other	*	(3,687		)	(6,269		)
Total Puget Energy long-term debt			$	5,457,929		$	5,354,073

_______________

* Not Applicable.

¹  6.74% Senior Secured Note in the amount of $200.0 million is classified on the Balance Sheet as a current maturity of long-term debt as of June 15, 2017.

²  5.50% Promissory Note (Puget Western Note Payable) in the amount of $2.4 million was classified on the Balance Sheet as a current maturity of long-term debt from January 1, 2017 to August 13, 2017, at which time the agreement was amended and extended until August 13, 2020. The Promissory Note is currently classified as long-term debt on the Balance sheet as of September 1, 2017.

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, 2017, the latest maturity date of the first mortgage bonds, other than pledged first mortgage bonds, is December 22, 2025.

98

Puget Sound Energy Long-Term Debt

PSE has in effect a shelf registration statement ("the existing shelf") under which it may issue, as of the date of this report, up to $800.0 million aggregate principal amount of senior notes secured by first mortgage bonds. The existing shelf will expire in November 2019.

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, 2017, the earnings available for interest exceeded the required 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)	2018		2019		2020		2021		2022		Thereafter		Total
Maturities of:
PSE	$	200,000	$	—	$	2,412	$	—	$	—	$	3,573,860	$	3,776,272
Puget Energy	—		—		450,000		500,000		552,600		400,000		1,902,600
Total long-term debt	$	200,000	$	—	$	452,412	$	500,000	$	552,600	$	3,973,860	$	5,678,872

(7)  Liquidity Facilities and Other Financing Arrangements

As of December 31, 2017 and 2016, PSE had $329.5 million and $245.8 million in short-term debt outstanding, respectively.  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 facility 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 2017 and 2016 was 3.5% and 3.2%, respectively.  As of December 31, 2017, PSE and Puget Energy had several committed credit facilities that are described below.

Puget Sound Energy

Credit Facility

In October 2017, PSE entered into a new $800.0 million credit facility which consolidates the two previous facilities into a single, smaller facility. All other features including fees, interest rate options, letter of credit, same day swingline borrowings, financial covenant and accordion feature remain substantially the same. The credit facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facility also has an expansion feature which, upon the banks' approval, would increase the total size of the facility to $1.4 billion. The unsecured revolving credit facility matures in October 2022.

The credit agreement is syndicated among numerous lenders and contains usual and customary affirmative and negative covenants that, among other things, places limitations on PSE's ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit agreement also contains 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, 2017, PSE was in compliance with all applicable covenant ratios.

The credit agreement provides PSE with the ability to borrow at different interest rate options. The credit agreement allows 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 facility. 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, 2017, no amounts were drawn and outstanding under PSE's credit facility. No letters of credit were outstanding and $329.5 million was outstanding under the commercial paper program. Outside of the credit agreement, PSE had a $3.1 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

99

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%.  As of December 31, 2017, there was no outstanding balance under the Note.

Puget Energy

Credit Facility

In October 2017, Puget Energy entered into a new $800.0 million credit facility to replace the existing facility. The terms and conditions, including fees, interest rate options, financial covenant, and expansion feature remain substantially the same. The new facility matures in October 2022. As of December 31, 2017, there was $102.6 million drawn and outstanding under the facility. The Puget Energy revolving senior secured credit facility also has an expansion 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 the date of this report, the spread over LIBOR was 1.75% and the commitment fee was 0.275%.

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, 2017, Puget Energy was in compliance with all applicable covenants.

100

(8)  Leases

PSE leases buildings and assets under operating leases. Certain leases contain purchase options, renewal options and escalation provisions.  Payments received for the subleases of properties were immaterial for each of the years ended 2017, 2016 and 2015.

Operating lease expenses net of sublease receipts were:

(Dollars in Thousands)
At December 31,	Operating Lease Expense
Years
2017	$	35,198
2016	31,786
2015	27,843

The following table summarizes the Company’s estimated future minimum lease payments for non-cancelable leases net of sublease receipts, through the terms of its existing contracts:

(Dollars in Thousands)	Future Minimum Lease Payments
At December 31,
Years	Operating		Capital
2018	$	21,371	$	527
2019	19,077		306
2020	17,507		232
2021	9,137		97
2022	6,747		—
Thereafter	97,974		—
Total minimum lease payments	$	171,813	$	1,162

(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. In November 2017, PSE implemented a risk-responsive component to its hedging strategy for the core natural gas portfolio. This strategy utilizes quantitative risk-based measures with defined objectives to balance both portfolio risk and hedge costs.

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. Currently, the Company does not apply cash flow hedge accounting, and therefore records all mark-to-market gains or losses through earnings.

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, 2017, the Company did not have any outstanding interest rate swap instruments.

101

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

Puget Energy and Puget Sound Energy	At Year Ended December 31,
(Dollars in Thousands)	Volumes (millions)		Assets1				Liabilities²
	2017	2016	2017		2016		2017		2016
Interest rate swap derivatives3	$0.0	$450.0	$	—	$	—	$	—	$	141
Electric portfolio derivatives	*	*	13,391		36,460		49,050		41,329
Natural gas derivatives (MMBtus)4	332.1	336.4	11,014		26,619		37,044		19,101
Total derivative contracts			$	24,405	$	63,079	$	86,094	$	60,571
Current			$	22,247	$	54,341	$	64,859	$	44,310
Long-term			2,158		8,738		21,235		16,261
Total derivative contracts			$	24,405	$	63,079	$	86,094	$	60,571

_______________

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

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

³  Interest rate swap contracts are only held at Puget Energy and matured in January 2017.

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.

^*  Electric portfolio derivatives consist of electric generation fuel of 166.8 million One Million British Thermal Units (MMBtus) and purchased electricity of2.9 million megawatt hours (MWhs) at December 31, 2017 and 186.8 million MMBtus and 3.6 million MWhs at December 31, 2016.

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 natural gas and electric contracts; and North American Energy Standards Board (NAESB) agreements, which standardize physical natural 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 the 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. For further details regarding the fair value of derivative instruments, see Note 10, "Fair Value Measurements," to the consolidated financial statements included in Item 8 of this report.

102

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, 2017
(Dollars in Thousands)	Gross Amounts Recognized in the Statement of Financial Position 1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
							Commodity Contracts			Cash Collateral Received/Posted			Net Amount
Assets:
Energy derivative contracts	$	24,405	$	—	$	24,405	$	(17,940	)	$	—		$	6,465
Liabilities:
Energy derivative contracts	86,094		—		86,094		(17,940		)	(353		)	67,801
Puget Energy and Puget Sound Energy
At December 31, 2016
(Dollars in Thousands)	Gross Amounts Recognized in the Statement of Financial Position 1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
							Commodity Contracts			Cash Collateral Received/Posted			Net Amount
Assets:
Energy derivative contracts	$	63,079	$	—	$	63,079	$	(42,858	)	$	—		$	20,221
Liabilities:
Energy derivative contracts	60,430		—		60,430		(42,858		)	—			17,572
Interest rate swaps2	141		—		141		—			—			141

_______________

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 and matured in January 2017.

103

The following tables present the effect and locations of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income:

Puget Energy		Year Ended December 31,
(Dollars in Thousands)	Location	2017			2016			2015
Interest rate contracts:
	Non-hedged interest rate swap (expense) income	$	28		$	(1,062	)	$	(3,796	)
	Interest expense	—			—			560
Gas for Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	(32,492		)	62,318			(9,315		)
Realized	Electric generation fuel	(23,195		)	(39,656		)	(44,648		)
Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net1	1,702			21,477			22,548
Realized	Purchased electricity	(17,873		)	(21,998		)	(39,137		)
Total gain (loss) recognized in income on derivatives		$	(71,830	)	$	21,079		$	(73,788	)

Puget Sound Energy		Year Ended December 31,
(Dollars in Thousands)	Location	2017			2016			2015
Gas for Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	$	(32,492	)	$	62,318		$	(9,315	)
Realized	Electric generation fuel	(23,195		)	(39,656		)	(44,648		)
Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net1	1,702			21,477			22,003
Realized	Purchased electricity	(17,873		)	(21,998		)	(39,137		)
Total gain (loss) recognized in income on derivatives		$	(71,858	)	$	22,141		$	(71,097	)

_______________

¹  Differences between Puget Energy and PSE for the twelve months ended December 31, 2015 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 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, and exposure monitoring and mitigation.

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

It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of December 31, 2017, approximately 99.5% of the Company's energy portfolio exposure, excluding normal purchase normal sale (NPNS) transactions, is with counterparties that are rated investment grade by rating agencies and 0.5% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies.

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

104

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, 2017, 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 period. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. In March 2017, PSE began transacting power futures contracts on the Intercontinental Exchange (ICE) platform. Execution of these contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of December 31, 2017, PSE had cash posted as collateral of $2.6 million related to contracts executed on this platform. Also, as of December 31, 2017, PSE has a $1.0 million letter of credit posted as collateral 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 during the twelve months ended December 31, 2017, nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades.

The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post:

Puget Energy and Puget Sound Energy	At December 31,
(Dollars in Thousands)	2017						2016
Contingent Feature	Fair Value1 Liability		Posted Collateral		Contingent Collateral		Fair Value1 Liability		Posted Collateral		Contingent Collateral
Credit rating2	$	3,187	$	—	$	3,187	$	4,894	$	—	$	4,894
Requested credit for adequate assurance	37,374		—		—		7,427		—		—
Forward value of contract3	353		2,639		—		507		—		—
Total	$	40,914	$	2,639	$	3,187	$	12,828	$	—	$	4,894

_______________

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

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

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

(10)  Fair Value Measurements

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

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

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

105

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 as 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.

The Company considers its electric and natural gas contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. 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. Management's assessment is 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 used to value Level 2 commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter.

Assets and Liabilities with Estimated Fair Value

The carrying values of cash and cash equivalents, restricted cash, and short-term debt as reported on the balance sheet are reasonable estimates of their fair value due to the short-term nature of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value of other investments of $48.5 million and $49.1 million at December 31, 2017 and 2016, respectively, are included in "Other property and investments" on the balance sheet. These values are also reasonable estimates of their fair value and classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar transactions.

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's credit spreads as inputs, interpolating to the maturity date of each issue. The carrying values and estimated fair values were as follows:

Puget Energy		At December 31, 2017				At December 31, 2016
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	238,935	$	250,000	$	210,261
Long-term debt (fixed-rate), net of discount1	2	5,105,329		6,520,515		5,091,593		6,337,287
Long-term debt (variable-rate)	2	102,600		102,600		12,480		12,480
Total		$	5,457,929	$	6,862,050	$	5,354,073	$	6,560,028
Puget Sound Energy		At December 31, 2017				At December 31, 2016
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	238,935	$	250,000	$	210,261
Long-term debt (fixed-rate), net of discount2	2	3,499,911		4,550,130		3,497,298		4,360,783
Total		$	3,749,911	$	4,789,065	$	3,747,298	$	4,571,044

_______________

¹  The carrying value includes debt issuances costs of $27.9 million and $33.0 million for December 31, 2017 and 2016, respectively, which are not included in fair value.

²  The carrying value includes debt issuances costs of $24.6 million and $27.2 million for December 31, 2017 and 2016, respectively, which are not included in fair value.

106

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 and Puget Sound Energy	Fair Value						Fair Value
	At December 31, 2017						At December 31, 2016
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	9,866	$	3,525	$	13,391	$	30,666	$	5,794	$	36,460
Natural gas derivative instruments	6,973		4,041		11,014		23,316		3,303		26,619
Total derivative assets	$	16,839	$	7,566	$	24,405	$	53,982	$	9,097	$	63,079
Liabilities:
Interest rate derivative instruments1	$	—	$	—	$	—	$	141	$	—	$	141
Electric derivative instruments	46,623		2,427		49,050		36,507		4,822		41,329
Natural gas derivative instruments	34,926		2,118		37,044		16,423		2,678		19,101
Total derivative liabilities	$	81,549	$	4,545	$	86,094	$	53,071	$	7,500	$	60,571

_______________

¹  Interest rate derivative instruments are only held at Puget Energy, and matured January 2017.

Puget Energy and Puget Sound Energy	Year Ended December 31,
Level 3 Roll-Forward Net (Liability)	2017									2016									2015
(Dollars in Thousands)	Electric			Gas			Total			Electric			Gas			Total			Electric			Gas			Total
Balance at beginning of period	$	972		$	625		$	1,597		$	(7,345	)	$	(2,383	)	$	(9,728	)	$	(12,062	)	$	(2,040	)	$	(14,102	)
Changes during period
Realized and unrealized energy derivatives:
Included in earnings1	2,781			—			2,781			4,007			—			4,007			(6,432		)	—			(6,432		)
Included in regulatory assets / liabilities	—			6,346			6,346			—			4,312			4,312			—			3,695			3,695
Settlements2	(6,549		)	(6,372		)	(12,921		)	(1,129		)	(2,679		)	(3,808		)	902			(3,885		)	(2,983		)
Transferred into Level 3	523			(553		)	(30		)	(3,021		)	—			(3,021		)	(787		)	—			(787		)
Transferred out Level 3	3,371			1,877			5,248			8,460			1,375			9,835			11,034			(153		)	10,881
Balance at end of period	$	1,098		$	1,923		$	3,021		$	972		$	625		$	1,597		$	(7,345	)	$	(2,383	)	$	(9,728	)

_______________

¹  Income Statement classification: 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 $1.5 million, $2.0 million and $(7.4) million for the years ended December 31, 2017, 2016 and 2015, respectively.

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

107

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

In order to determine which assets and liabilities are classified as Level 3, the Company receives market data from its independent external pricing service defining the tenor of observable market quotes. To the extent any of the Company's commodity contracts extend beyond what is considered observable as defined by its independent pricing service, the contracts are classified as Level 3. The actual tenor of what the independent pricing service defines as observable is subject to change depending on market conditions. Therefore, as the market changes, the same contract may be designated Level 3 one month and Level 2 the next, and vice versa. The changes of fair value classification into or out of Level 3 are recognized each month, and reported in the Level 3 Roll-forward table above. The Company did not have any transfers between Level 2 and Level 1 during the years ended December 31, 2017, 2016 and 2015. 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, 2017:

Puget Energy and Puget Sound Energy	Fair Value				Range
(Dollars in Thousands)	Assets1	Liabilities1	Valuation Technique	Unobservable Input	Low	High	Weighted Average
Electric	$3,525	$2,427	Discounted cash flow	Power Prices (per MWh)	$7.02	$28.94	$18.61
Natural gas	$4,041	$2,118	Discounted cash flow	Natural Gas Prices (per MMBtu)	$1.22	$2.80	$1.54

_______________

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, 2017, 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 $0.9 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.

108

During 2017 and 2016, Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. In 2017 and 2016, due to continued decreases in forward power prices and decreases in forecasted revenue and cost estimates, the following impairments were recorded to the Company's intangible asset contracts, with corresponding reductions to the regulatory liability as follows:

Puget Energy
(Dollars in Thousands)
Valuation Date	Contract Name	Carrying Value		Fair Value		Write Down
September 30, 2017	Wells Hydro	$	10,621	$	9,609	$	1,012
March 31, 2017	Wells Hydro	14,879		13,067		1,812
	Rocky Reach	235,331		159,818		75,513
	Priest Rapids RP	5,665		2,657		3,008
Total 2017 Impairments						$	81,345
September 30, 2016	Priest Rapids RP	$	18,969	$	6,191	$	12,778
March 31, 2016	Wells Hydro	25,193		19,855		5,338
Total 2016 Impairments						$	18,116

109

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 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 2017 and 2016:

Puget Energy
Valuation Date	Contract	Unobservable Input	Low	High	Average
September 30, 2017	Wells Hydro	Power prices (per MWh)	14.06	26.86	22.24
		Power contract costs per quarter (in thousands)	4,126	4,126	4,126
March 31, 2017	Wells Hydro	Power prices (per MWh)	8.76	26.70	20.86
		Power contract costs per quarter (in thousands)	3,965	4,223	4,051
	Rocky Reach	Power prices (per MWh)	8.53	48.21	27.69
		Power contract costs per quarter (in thousands)	5,827	6,780	6,150
	Priest Rapids RP	Power prices (per MWh)	13.70	29.38	23.14
		Power contract costs per year (in thousands)	620	4,022	2,306
September 30, 2016	Priest Rapids RP	Power prices (per MWh)	24.24	58.96	39.31
		Power contract costs per year (in thousands)	618	4,633	2,472
March 31, 2016	Wells Hydro	Power prices (per MWh)	9.46	25.96	21.38
		Power contract costs per quarter (in thousands)	4,100	4,659	4,452

(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 $19.2 million, $17.2 million and $16.1 million for the years 2017, 2016 and 2015, 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 6.0% of plan compensation each paycheck, and will make an additional year-end contribution equal to 1.0% of base pay. 

• For employees grandfathered under the Final Average Earning retirement plan formula, PSE will match 55.0% of an employee’s contribution up to 6.0% of plan compensation each paycheck.

Non-represented and UA-represented employees hired on or after January 1, 2014 along with IBEW-represented employees hired on or after December 12, 2014, will have access to the 401(k) plan. The two contribution sources from PSE are below:

• 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 3.0% of pay contributed and 50.0% match on the next 3.0% of pay contributed. An employee who contributes 6.0% of pay will receive 4.5% of pay in company match. Company matching will be immediately vested.

110

• Company Contribution: New UA-represented employees will receive an annual company contribution of 4.0% of eligible pay placed in the Cash Balance retirement plan. New non-represented and IBEW-represented employees will receive an annual company contribution of 4.0% 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 4.0% contribution either into the 401(k) plan or into an account in the Cash Balance retirement plan. The Company’s 4.0% contribution will vest after three years of service. 

(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 non-represented and UA-represented employees, along with IBEW-represented employees 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 4.0% 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 1.0% 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, 2017 and 2016:

Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2017			2016			2017			2016			2017			2016
Change in benefit obligation:
Benefit obligation at beginning of period	$	652,607		$	643,088		$	51,734		$	51,279		$	11,194		$	13,946
Service cost	20,081			18,913			913			1,085			72			93
Interest cost	28,373			28,689			2,285			2,325			500			533
Actuarial loss (gain)	40,945			1,545			2,722			106			725			(2,262		)
Benefits paid	(40,594		)	(38,730		)	(1,900		)	(3,061		)	(1,137		)	(1,264		)
Medicare part D subsidy received	—			—			—			—			100			148
Administrative expense	(931		)	(898		)	—			—			—			—
Benefit obligation at end of period	$	700,481		$	652,607		$	55,754		$	51,734		$	11,454		$	11,194

Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2017			2016			2017			2016			2017			2016
Change in plan assets:
Fair value of plan assets at beginning of period	$	620,260		$	598,865		$	—		$	—		$	7,200		$	7,203
Actual return on plan assets	107,836			37,022			—			—			784			926
Employer contribution	18,000			24,000			1,900			3,061			291			335
Benefits paid	(40,594		)	(38,730		)	(1,900		)	(3,061		)	(1,137		)	(1,264		)
Administrative expense	(1,142		)	(897		)	—			—			—			—
Fair value of plan assets at end of period	$	704,360		$	620,260		$	—		$	—		$	7,138		$	7,200
Funded status at end of period	$	3,879		$	(32,347	)	$	(55,754	)	$	(51,734	)	$	(4,316	)	$	(3,994	)

111

Puget Energy and Puget Sound Energy	Qualified Pension Benefits					SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2017		2016			2017			2016			2017			2016
Amounts recognized in Statement of Financial Position consist of:
Noncurrent assets	$	3,879	$	—		$	—		$	—		$	—		$	—
Current liabilities	—		—			(5,486		)	(1,911		)	(317		)	(325		)
Noncurrent liabilities	—		(32,347		)	(50,268		)	(49,823		)	(3,999		)	(3,669		)
Net assets (liabilities)	$	3,879	$	(32,347	)	$	(55,754	)	$	(51,734	)	$	(4,316	)	$	(3,994	)

Puget Energy and Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2017		2016		2017		2016		2017		2016
Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets:
Projected benefit obligation	$	700,481	$	652,607	$	55,754	$	51,734	$	11,454	$	11,194
Accumulated benefit obligation	688,908		641,855		52,681		47,639		11,367		11,092
Fair value of plan assets	704,360		620,260		—		—		7,138		7,200

The following tables summarize Puget Energy's and PSE's pension benefit amounts recognized in AOCI for the years ended December 31, 2017 and 2016:

Puget Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2017			2016			2017		2016		2017			2016
Amounts recognized in Accumulated Other Comprehensive Income consist of:
Net loss (gain)	$	37,693		$	56,588		$	10,689	$	9,043	$	(3,386	)	$	(4,190	)
Prior service cost (credit)	(7,843		)	(9,822		)	204		246		—			—
Total	$	29,850		$	46,766		$	10,893	$	9,289	$	(3,386	)	$	(4,190	)

Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2017			2016			2017		2016		2017			2016
Amounts recognized in Accumulated Other Comprehensive Income consist of:
Net loss (gain)	$	185,277		$	217,143		$	13,134	$	11,978	$	(4,901	)	$	(5,994	)
Prior service cost (credit)	(6,232		)	(7,806		)	208		251		—			—
Total	$	179,045		$	209,337		$	13,342	$	12,229	$	(4,901	)	$	(5,994	)

112

The following tables summarize Puget Energy's and PSE's net periodic benefit cost for the years ended December 31, 2017, 2016 and 2015:

Puget Energy	Qualified Pension Benefits									SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2017			2016			2015			2017		2016		2015		2017			2016			2015
Components of net periodic benefit cost:
Service cost	$	20,081		$	18,913		$	21,287		$	913	$	1,085	$	1,108	$	72		$	93		$	112
Interest cost	28,373			28,689			28,088			2,285		2,325		2,281		500			533			621
Expected return on plan assets	(47,784		)	(46,619		)	(45,038		)	—		—		—		(461		)	(446		)	(531		)
Amortization of prior service cost (credit)	(1,980		)	(1,980		)	(1,980		)	42		42		42		—			—			—
Amortization of net loss (gain)	—			—			3,887			1,077		911		1,641		(402		)	(386		)	(130		)
Net periodic benefit cost	$	(1,310	)	$	(997	)	$	6,244		$	4,317	$	4,363	$	5,072	$	(291	)	$	(206	)	$	72

Puget Sound Energy	Qualified Pension Benefits									SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2017			2016			2015			2017		2016		2015		2017			2016			2015
Components of net periodic benefit cost:
Service cost	$	20,081		$	18,913		$	21,287		$	913	$	1,085	$	1,108	$	72		$	93		$	112
Interest cost	28,373			28,689			28,088			2,285		2,325		2,281		500			533			621
Expected return on plan assets	(47,862		)	(46,814		)	(45,462		)	—		—		—		(461		)	(446		)	(531		)
Amortization of prior service cost (credit)	(1,573		)	(1,573		)	(1,573		)	44		44		44		—			—			3
Amortization of net loss (gain)	13,048			15,257			20,555			1,565		1,330		2,120		(641		)	(632		)	(406		)
Net periodic benefit cost	$	12,067		$	14,472		$	22,895		$	4,807	$	4,784	$	5,553	$	(530	)	$	(452	)	$	(201	)

The following tables summarize Puget Energy's and PSE's benefit obligations recognized in other comprehensive income (OCI) for the years ended December 31, 2017 and 2016:

Puget Energy	Qualified Pension Benefits					SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2017			2016		2017			2016			2017		2016
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	$	(18,896	)	$	11,141	$	2,722		$	106		$	403	$	(2,742	)
Amortization of net (loss) gain	—			—		(1,076		)	(910		)	401		385
Amortization of prior service (cost) credit	1,980			1,980		(42		)	(42		)	—		—
Total change in other comprehensive income for year	$	(16,916	)	$	13,121	$	1,604		$	(846	)	$	804	$	(2,357	)

113

Puget Sound Energy	Qualified Pension Benefit						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2017			2016			2017			2016			2017		2016
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	$	(18,817	)	$	11,336		$	2,722		$	106		$	452	$	(2,742	)
Amortization of net (loss) gain	(13,048		)	(15,257		)	(1,565		)	(1,330		)	641		631
Amortization of prior service (cost) credit	1,573			1,573			(44		)	(44		)	—		—
Total change in other comprehensive income for year	$	(30,292	)	$	(2,348	)	$	1,113		$	(1,268	)	$	1,093	$	(2,111	)

The estimated net (loss) gain and prior service cost (credit) for the pension plans that will be amortized from Accumulated Other Comprehensive Income (AOCI) into net periodic benefit cost in 2018 by PSE are $(14.5) million and $1.6 million, respectively.  The estimated net (loss) gain for the SERP that will be amortized from AOCI into net periodic benefit cost in 2018 is $(2.1) million. The estimated prior service cost (credit) for the SERP that will be amortized from AOCI into net periodic benefit cost in 2018 is immaterial.  The estimated net (loss) gain and prior service cost (credit) for the other postretirement plans that will be amortized from AOCI into net periodic benefit cost in 2018 is $0.6 million. For Puget Energy, the overall amounts expected to be amortized from AOCI into net period benefit cost in 2018 is $(1.1) million.

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, 2018 are expected to be at least $18.0 million, $5.5 million and $0.3 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	2017		2016		2015		2017		2016		2015		2017		2016		2015
Discount rate	4.00	%	4.50	%	4.65	%	4.00	%	4.50	%	4.65	%	4.00	%	4.50	%	4.65	%
Rate of compensation increase	4.50		4.50		4.50		4.50		4.50		4.50		4.50		4.50		4.50
Medical trend rate	—		—		—		—		—		—		6.80		8.80		7.20
Benefit Cost Assumptions
Discount rate	4.50	%	4.65	%	4.25	%	4.50	%	4.65	%	4.25	%	4.50	%	4.65	%	4.25	%
Return on plan assets	7.45		7.75		7.75		—		—		—		6.75		6.75		7.00
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	—		—		—		—		—		—		9.50		5.30		7.20

The assumed medical inflation rate used to determine benefit obligations is 6.80% in 2018 grading down to 4.10% in 2019.  A 1.0% change in the assumed medical inflation rate would have the following effects:

	2017					2016
(Dollars in Thousands)	1% Increase		1% Decrease			1% Increase		1% Decrease
Effect on post-retirement benefit obligation	$	23	$	(22	)	$	38	$	(35	)
Effect on service and interest cost components	1		(1		)	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 based on a five-year smoothing of asset gains (losses) measured from the expected return on market-related assets.  This is a calculated value that recognizes changes in fair value in a systematic and rational manner over five years.  The same manner of calculating market-related value is used for all classes of assets, and is applied consistently from year to year.

114

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)	2018		2019		2020		2021		2022		2023-2027
Qualified Pension total benefits	$	42,600	$	43,400	$	44,800	$	45,700	$	46,900	$	246,500
SERP Pension total benefits	5,486		6,001		4,684		1,728		4,577		37,394
Other Benefits total with Medicare Part D subsidy	911		885		852		811		863		3,748
Other Benefits total without Medicare Part D subsidy	1,172		1,155		1,131		1,097		1,070		4,844

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	—		9		15
Non-U.S. equity	10		25		30
Fixed income	15		25		30
Real estate	—		—		10
Absolute return	5		10		15
Cash	—		—		5

115

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: (i) how investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies; (ii) major categories of plan assets; (iii) inputs and valuation techniques used to measure the fair value of plan assets; (iv) effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period; and (v) 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, 2017 and 2016:

	Recurring Fair Value Measures						Recurring Fair Value Measures
	As of December 31, 2017						As of December 31, 2016
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Mutual Funds	$	117,796	$	—	$	117,796	$	181,212	$	—	$	181,212
Common Stock	209,504		—		209,504		154,255		—		154,255
Government Securities	18,316		23,782		42,098		18,754		16,197		34,951
Corporate Bonds	—		34,588		34,588		—		38,543		38,543
Cash and cash equivalents	2,684		9,304		11,988		—		—		—
Subtotal	$	348,300	$	67,674	415,974		$	354,221	$	54,740	408,961
Investments measured at NAV1					237,427						222,819
Net (payable) receivable					50,959						(9,894		)
Total assets					$	704,360					$	621,886

_______________

¹  In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments that were measured at NAV per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV primarily consist of common/collective trust funds and two partnerships held as of December 31, 2017.

Mesirow Institutional Multi-Strategy Fund Partnership, L.P. utilizes a combination of long and short strategies through investments in investment funds. The major strategy allocations of the investment funds include (1) Investments in debt obligations of public and private entities; typically, in financial duress, and (2) Investments in equity positions on a global basis utilizing fundamental analysis.

Grosvenor Institutional Partners Fund, L.P invests substantially all of the fund assets available in the Grosvenor Master Fund, a Cayman Islands exempted company which is sponsored, managed and has the same investment objective as the Partnership fund. In addition to the Master Fund, investments are made primarily in offshore investment funds, investment partnerships, and pooled investment vehicles; collectively referred to as Portfolio Funds, which generally implement "nontraditional" or "alternative" investment strategies.

116

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, 2017						As of December 31, 2016
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Mutual fund1	$	7,089	$	—	$	7,089	$	7,182	$	—	$	7,182
Investments measured at NAV2					49						80
Total assets					$	7,138					$	7,262

_______________

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, 2017.

²  In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments that were measured at NAV per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV consist of a common/collective trust fund as of December 31, 2017.

(13)  Income Taxes

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

Puget Energy	Year Ended December 31,
(Dollars in Thousands)	2017			2016			2015
Charged to operating expenses:
Current:
Federal	$	1,127		$	—		$	—
State	17			20			—
Deferred:
Federal	254,420			140,315			91,968
State	(421		)	(131		)	(192		)
Total income tax expense	$	255,143		$	140,204		$	91,776

Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	2017		2016		2015
Charged to operating expenses:
Current:
Federal	$	1,127	$	—	$	—
State	17		20		—
Deferred:
Federal	210,842		175,327		125,900
State	—		—		—
Total income tax expense	$	211,986	$	175,347	$	125,900

117

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)	2017			2016			2015
Income taxes at the statutory rate	$	148,847		$	158,586		$	116,534
Increase (decrease):
Production tax credit1	—			(12,925		)	(19,470		)
Utility plant differences	—			3,966			5,671
Treasury grant amortization	(9,537		)	(9,788		)	(8,807		)
Tax reform	117,185			—			—
Other - net	(1,352		)	365			(2,152		)
Total income tax expense	$	255,143		$	140,204		$	91,776
Effective tax rate	60.0		%	30.9		%	27.6		%

Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	2017			2016			2015
Income taxes at the statutory rate	$	185,430		$	194,572		$	150,531
Increase (decrease):
Production tax credit1	—			(12,925		)	(19,470		)
Utility plant differences	—			3,966			5,671
Treasury grant amortization	(9,537		)	(9,788		)	(8,807		)
Tax reform	36,328			—			—
Other - net	(235		)	(478		)	(2,025		)
Total income tax expense	$	211,986		$	175,347		$	125,900
Effective tax rate	40.0		%	31.5		%	29.3		%

_______________

¹  PSE's Wild Horse wind plant and Hopkins Ridge wind plant earned their last PTCs in December 2016 and 2015, respectively. No further PTCs are expected.

The Company’s net deferred tax liability at December 31, 2017 and 2016 is composed of amounts related to the following types of temporary differences:

Puget Energy	At December 31,
(Dollars in Thousands)	2017			2016
Utility plant and equipment	$	2,034,328		$	1,880,782
Regulatory asset for income taxes	—			72,038
Fair value of debt instruments	38,777			67,444
Pensions and other compensation	46,338			77,230
Other deferred tax liabilities	86,933			119,050
Subtotal deferred tax liabilities	2,206,376			2,216,544
Net operating loss carryforward	(212,168		)	(352,827		)
Net regulatory liability for income taxes	(1,011,626		)	—
Production tax credit carryforward	(187,617		)	(190,999		)
Regulatory liability on production tax credit	(49,873		)	(101,787		)
Net other deferred tax assets	1,776			—
Subtotal deferred tax assets	(1,459,508		)	(645,613		)
Total net deferred tax liabilities	$	746,868		$	1,570,931

118

Puget Sound Energy	At December 31,
(Dollars in Thousands)	2017			2016
Utility plant and equipment	$	2,034,328		$	1,880,782
Regulatory asset for income taxes	—			71,517
Other, net deferred tax liabilities	86,933			113,938
Subtotal deferred tax liabilities	2,121,261			2,066,237
Net regulatory liability for income taxes	(1,012,260		)	—
Net operating loss carryforward	—			(41,061		)
Production tax credit carryforward	(187,617		)	(190,999		)
Regulatory liability on production tax credit	(49,873		)	(101,787		)
Net other deferred tax assets	(2,038		)	—
Subtotal deferred tax assets	(1,251,788		)	(333,847		)
Total net deferred tax liabilities	$	869,473		$	1,732,390

On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). Substantially all of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes significant changes to the Internal Revenue Code of 1986 (as amended, the Code), including amendments which significantly change the taxation of business entities and includes specific provisions related to regulated public utilities including PSE. The most significant change that impacts the Company included in the TCJA is the reduction in the corporate federal income tax rate from 35.0% percent to 21.0% percent. The specific provisions related to regulated public utilities in the TCJA generally allow for the continued deductibility of interest expense, the elimination of full expensing for tax purposes of certain property acquired after September 27, 2017 and continues normalization requirements for accelerated depreciation benefits. For Puget Energy, TCJA provides for full expensing of property acquired after September 27, 2017 and limits a deduction for interest expense to 30.0% percent of adjusted taxable income (which resembles earnings before interest, taxes, depreciation and amortization or “EBITDA”).

Under generally accepted accounting principles (US GAAP) specifically ASC Topic 740, Income Taxes the tax effects of changes in tax laws must be recognized in the period in which the law is enacted and deferred tax assets and liabilities are to be re-measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. For PSE, the change in deferred taxes is recorded as either an offset to a regulatory asset or liability and is subject to approval by the Washington Commission. For Puget Energy, the change in deferred taxes is recorded as an adjustment to Puget Energy’s income tax expense, which decreased Puget Energy’s net income.

Upon, enactment of the TCJA, the Company re-measured their deferred tax assets and liabilities based upon the TCJA’s 21.0% percent corporate federal income tax rate. The corporate tax rate change for PSE is captured in the deferred tax balance with an offset to the regulatory liability for deferred income taxes. The balance of the regulatory deferred tax account at the beginning of the year, before tax reform, was a $71.5 million asset. As a result of tax reform, the balance is a liability of $1,012.3 million which represents the excess deferred taxes that will eventually be refunded to customers. Since, PSE is in a net regulatory liability position with respect to these income tax matters, PSE netted the regulatory asset for deferred income taxes against the regulatory liability for deferred income taxes. Under the normalization requirements continued by the TCJA, $919.8 million of the net regulatory liability related to certain accelerated tax depreciation benefits is to be amortized over the remaining lives of the related assets. The remainder of the net regulatory liability of $92.5 million is available for PSE and the Washington Commission regulatory process to determine how the amounts will be refunded to customers. PSE requested to delay the impact of tax reform in an accounting petition which was filed with the Washington Commission on December 29, 2017. The income statement impact for the regulatory deferred tax will come in the future when the Washington Commission issues a final order. The timing for that is unknown but will likely occur in 2018.

The impact of the TCJA to income tax expense was $36.3 million of which $3.0 million relates to deferred tax balances that are not subject to regulatory treatment. In addition, $33.3 million relates to the revaluation of the PTC deferred taxes. The liability owed to customers for PTCs, which previously reduced revenue upon generation of the PTCs, was also revalued at the TCJAs 21 percent rate. The change in the liability owed to customers for PTCs due to TCJA increased revenue by $51.2 million, which increased tax expense by $17.9 million, to reverse the initial deferral. The changes in deferred tax and liability owed to customers for PTCs had no impact on net income. Incrementally, Puget Energy increased their tax expense by $80.9 million primarily due to the revaluation of Puget Energy's net deferred tax asset on its net operating loss carryforward.

The staff of the US Securities and Exchange Commission (SEC) has recognized the complexity of reflecting the impacts of the TCJA, and on December 22, 2017 issued guidance in Staff Accounting Bulletin 118 (SAB 118) which clarifies accounting for

119

income taxes under ASC 740 if information is not yet available or complete and provides for up to a one year period in which to complete the required analyses and accounting (the measurement period). SAB 118 describes three scenarios (or “buckets”) associated with a company’s status of accounting for income tax reform: (1) a company is complete with its accounting for certain effects of tax reform, (2) a company is able to determine a reasonable estimate for certain effects of tax reform and records that estimate as a provisional amount, or (3) a company is not able to determine a reasonable estimate and therefore continues to apply ASC 740, based on the provisions of the tax laws that were in effect immediately prior to the TCJA being enacted. The Company has completed the required analysis and accounting for substantially all the effects of the TCJA's enactment and have made a reasonable estimate as to the other effects, and have reflected the measurement and accounting of the effects in the 2017 consolidated financial statements. The items reflected as provisional amounts include tax depreciation and amortization and other book to tax differences. PSE has accounted for these items based on its interpretation of the TCJA. Further interpretive guidance on the TCJA from the IRS, U.S. Treasury Department, or the Joint Committee on Taxation may require adjustments to PSE's accounting. In accordance with SAB 118, adjustments, if any, will be recorded in 2018. The Company did not identify any effects on the TCJA for which they were not able to either complete the required analysis or make a reasonable estimate.

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 2037.  The Company’s net operating loss carryforwards expire from 2029 through 2036. No valuation allowance has been provided for PTC or net operating loss carryforwards.

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, 2017 and 2016, the Company had no material unrecognized tax benefits.  As a result, no interest or penalties were accrued for unrecognized tax benefits during the year.

The Company has open tax years from 2014 through 2017. The Company classifies interest as interest expense and penalties as other expense in the financial statements.

(14)  Litigation

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. On July 12, 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court on September 6, 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE and Talen Energy, agreed to retire the two oldest units (Units 1 and 2) at Colstrip in eastern Montana by no later than July 1, 2022. The Washington Commission allows full recovery in rates of the net book value (NBV) at retirement and related decommissioning costs consistent with prior precedents. As a result, PSE reclassified $176.8 million from a utility plant asset to a regulatory asset, which represents the expected NBV at retirement of Colstrip Units 1 and 2, based on the expected shutdown date of July 1, 2022 as of December 31, 2016.

Depreciation rates were updated in the GRC effective December 19, 2017, where PSE's depreciation increased for Colstrip Units 1 and 2 to recover plant costs to the expected shutdown date. The increase in depreciation caused the Colstrip Units 1 and 2 regulatory asset to be reduced to $127.6 million as of December 31, 2017. The GRC also repurposed PTCs and hydro-related treasury grants to fund and recover decommissioning and remediation costs for Colstrip Units 1 and 2. Colstrip Units 3 and 4, which are newer and more efficient, are not affected by the settlement, and allegations in the lawsuit against Colstrip Units 3 and 4 were dismissed as part of the settlement with the Sierra Club. While PSE has estimated the ARO for Colstrip Units 1 and 2, the full scope of decommissioning activities and costs may vary from the estimates that are available at this time.

120

Greenwood

On March 9, 2016, a natural gas explosion occurred in the Greenwood neighborhood of Seattle, WA, damaging multiple structures. The Washington Commission Staff completed its investigation of the incident and filed a complaint on September 20, 2016, seeking up to $3.2 million in fines from PSE. As of September 30, 2016, PSE accrued $3.2 million for the fine. On March 28, 2017, pipeline safety regulators and PSE reached a settlement in response to the complaint. As part of the agreement, PSE agreed to pay a penalty of $2.8 million, of which $1.3 million was suspended on condition that PSE complete a comprehensive inspection and remediation program. On June 19, 2017, the Washington Commission approved the settlement without conditions and adopted the reduced penalty of $2.8 million, of which $1.3 million was suspended. On June 30, 2017, PSE paid the penalty it had previously accrued. However, litigation is still pending regarding damage and personal injury claims.

Coal Combustion Residuals

On April 17, 2015, the EPA published a final rule, effective October 19, 2015, that regulates CCR's under the Resource Conservation and Recovery Act, Subtitle D. The EPA issued another rule, effective October 4, 2016, extending certain compliance deadlines under the CCR rule. The CCR rule is self-implementing at a federal level or can be taken over by a state. The 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.

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 ARO.

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

In June 2014, the EPA issued a proposed Clean Power Plan (CPP) 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. The EPA published a final rule on October 23, 2015. The rule was being challenged by other states and parties, and the Supreme Court granted a stay of the rule on February 9, 2016 until the litigation is resolved. On March 31, 2017, the EPA Administrator, Scott Pruitt, signed a notice of withdrawal of the proposed CPP federal plan and model trading rules and, on October 10, 2017, the EPA proposed to repeal the CPP rule and is currently accepting comment on the proposal. PSE is still reviewing the impact of these developments.

Washington Clean Air Rule

The CAR was adopted on September 15, 2016 in Washington State and attempts to reduce greenhouse gas emissions from “covered entities” located within Washington State. Included under the new rule are large manufacturers, petroleum producers and natural gas utilities, including PSE. The CAR sets a cap on emissions associated with covered entities, which decreases over time, approximately 5.0% every three years. Entities must reduce their carbon emissions, or purchase emission reduction units (ERUs), as defined under the rule, from others.

The CAR covers natural gas distributors and subjects them to an emissions reduction pathway based on the indirect emissions of their customers. The CAR regulates the emissions of natural gas utilities 1.2 million customers across the state, adding to the cost of natural gas for homes and businesses, which may increase costs to PSE customers.

On September 27, 2016, PSE, along with Avista Corporation, Cascade Natural Gas Corporation and NW Natural, filed a lawsuit in the U.S. District Court for the Eastern District of Washington challenging the CAR. On September 30, 2016, the four companies filed a similar challenge to the CAR in Thurston County Superior Court. On December 15, 2017, the Thurston County Superior Court invalidated the CAR. A final court order is pending and in the meantime, the Washington State Department of Ecology (WDOE), submitted a brief requesting severability, which would make the rule valid for industries with direct emissions. This would apply to The Company's electric utility thermal generation units but not to its natural gas utility. Appeals could be filed to the Thurston County Court of Appeals after the court's final order, including its ruling on severability.

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 $2.4 million and $0.7 million relating to these claims as of December 31, 2017 and 2016, respectively.

121

(15)  Commitments and Contingencies

For the year ended December 31, 2017, approximately 13.3% 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 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)	2017		2016		2015
PUD contract costs	$	73,827	$	77,667	$	72,833

As of December 31, 2017, 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 2018 Costs		2018 Debt Service Costs		Interest included in 2018 Debt Service Costs		Debt Outstanding
Chelan County PUD:
Rock Island Project	2031	25.0	%	156	$	29,135	$	10,105	$	5,354	$	84,269
Rocky Reach Project	2031	25.0		325	28,800		5,796		2,548		39,563
Douglas County PUD:
Wells Project1	2028	29.9		251	11,002		4,695		1,379		49,629
Grant County PUD:
Priest Rapids Development	2052	0.6		6	2,050		1,231		1,231		13,723
Wanapum Development	2052	0.6		7	2,050		1,231		1,231		13,723
Total				745	$	73,037	$	23,058	$	11,743	$	200,907

_______________

¹  In March 2017, PSE entered a new PPA with Douglas County PUD for Wells Project output that begins upon expiration of the existing contract on August 31, 2018 and continues through September 30, 2028.

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

(Dollars in Thousands)	2018		2019		2020		2021		2022		Thereafter		Total
Columbia River projects	$	82,200	$	97,890	$	95,704	$	91,862	$	91,018	$	708,499	$	1,167,173
Other utilities	1,257		888		—		—		—		—		2,145
Non-utility contracts	206,233		233,776		238,016		244,962		244,906		1,128,466		2,296,359
Short-term electric supply contracts	70,786		140		—		—		—		—		70,926
Total	$	360,476	$	332,694	$	333,720	$	336,824	$	335,924	$	1,836,965	$	3,536,603

122

Total purchased power contracts provided the Company with approximately 14.5 million, 13.0 million and 11.2 million MWhs of firm energy at a cost of approximately $456.4 million, $402.5 million and $373.8 million for the years 2017, 2016 and 2015, 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 1 year to 27 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage.  The Company incurred demand charges for 2017 for firm transportation, storage and peaking services for its natural gas customers of $121.4 million. The Company incurred demand charges in 2017 for firm transportation and storage services for the natural gas supply for its combustion turbines in the amount of $41.8 million.

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)	2018		2019		2020		2021		2022		Thereafter		Total
Natural gas supply	$	245,669	$	193,458	$	163,818	$	145,662	$	109,401	$	—	$	858,008
Firm transportation service	154,170		154,204		141,962		126,319		125,335		310,428		1,012,418
Firm storage service	8,328		8,899		7,908		3,108		1,619		857		30,719
Short-term natural gas supply contracts	55,774		13,818		1,651		—		—		—		71,243
Total	$	463,941	$	370,379	$	315,339	$	275,089	$	236,355	$	311,285	$	1,972,388

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)	2018		2019		2020		2021		2022		Thereafter		Total
Energy production service contracts	$	28,674	$	27,939	$	28,639	$	29,415	$	30,142	$	165,689	$	310,498
Automated meter reading system	48,245		44,842		43,951		44,497		45,168		187,698		414,401
Total	$	76,919	$	72,781	$	72,590	$	73,912	$	75,310	$	353,387	$	724,899

Other Commitments and Contingencies

For information regarding PSE's environmental remediation obligations, see Note 3, "Regulation and Rates," to the consolidated financial statements included in item 8 of this report.

(16)  Related Party Transactions

Scott Armstrong serves on the Board of Directors of the Company and, until its acquisition by Kaiser Permanente on February 1, 2017, was the President and Chief Executive Officer of Group Health Cooperative (Group Health). Group Health provided coverage to over 600,000 residents in Washington and Northern Idaho. Certain employees of PSE elected Group Health as their medical provider prior to its acquisition by Kaiser Permanente, and as a result, PSE paid Group Health a total of $3.9 million, $23.3 million and $20.3 million for medical coverage for the year ended December 31, 2017, 2016 and 2015. Kaiser Permanente is not considered a related party to PSE.

Kimberly Harris, the President and Chief Executive Officer and a director of Puget Energy and PSE, is married to Kyle Branum, who as of January 2017 is a partner at Summit Law Group, which provides legal services to PSE.  In 2017 Summit Law Group was paid $0.8 million for legal services provided to PSE and Mr. Branum was among the lawyers at Summit Law Group

123

who provided such legal services.  This work was performed under the supervision of PSE's General Counsel. Through 2016, Mr. Branum was a principal at the law firm Riddell Williams P.S., which provided legal services to PSE. In 2016 and 2015, Riddell Williams was paid $1.0 million and $1.8 million, respectively.

(17)  Segment Information

Puget Energy and PSE operate one reportable 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.

(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, 2017, 2016 and 2015, respectively:

Puget Energy	Net unrealized gain (loss) and prior service cost on pension plans			Net unrealized gain (loss) on energy derivative instruments
Changes in AOCI, net of tax
(Dollars in Thousands)							Total
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	)
Other comprehensive income (loss) before reclassifications	(5,528		)	—			(5,528		)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	(918		)	—			(918		)
Net current-period other comprehensive income (loss)	(6,446		)	—			(6,446		)
Balance at December 31, 2016	$	(33,712	)	$	—		$	(33,712	)
Other comprehensive income (loss) before reclassifications	10,251			—			10,251
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	(821		)	—			(821		)
Net current-period other comprehensive income (loss)	9,430			—			9,430
Balance at December 31, 2017	$	(24,282	)	$	—		$	(24,282	)

124

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, 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	)
Other comprehensive income (loss) before reclassifications	(5,655		)	—			—			(5,655		)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	9,377			—			317			9,694
Net current-period other comprehensive income (loss)	3,722			—			317			4,039
Balance at December 31, 2016	$	(140,155	)	$	—		$	(5,356	)	$	(145,511	)
Other comprehensive income (loss) before reclassifications	10,200			—			—			10,200
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	8,088			—			317			8,405
Net current-period other comprehensive income (loss)	18,288			—			317			18,605
Balance at December 31, 2017	$	(121,867	)	$	—		$	(5,039	)	$	(126,906	)

Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2017, 2016 and 2015, 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)
		2017			2016			2015
Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost	(a)	$	1,938		$	1,938		$	1,938
Amortization of net gain (loss)	(a)	(675		)	(525		)	(5,397		)
	Total before tax	1,263			1,413			(3,459		)
	Tax (expense) or benefit	(442		)	(495		)	1,211
	Net of Tax	821			918			(2,248		)
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts: Electric derivatives	Purchased electricity	—			—			(512		)
	Tax (expense) or benefit	—			—			179
	Net of Tax	—			—			(333		)
Total reclassification for the period	Net of Tax	$	821		$	918		$	(2,581	)

_______________

^(a) These AOCI components are included in the computation of net periodic pension cost, see Note 12, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details.

125

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)
		2017			2016			2015
Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost	(a)	$	1,529		$	1,529		$	1,526
Amortization of net gain (loss)	(a)	(13,972		)	(15,955		)	(22,268		)
	Total before tax	(12,443		)	(14,426		)	(20,742		)
	Tax (expense) or benefit	4,355			5,049			7,260
	Net of tax	(8,088		)	(9,377		)	(13,482		)
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts: Electric derivatives	Purchased electricity	—			—			(1,055		)
	Tax (expense) or benefit	—			—			369
	Net of Tax	—			—			(686		)
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	$	(8,405	)	$	(9,694	)	$	(14,485	)

_______________

^(a) These AOCI components are included in the computation of net periodic pension cost, see Note 12, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details.

126

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	2017 Quarter
(Unaudited; Dollars in Thousands)	First		Second		Third		Fourth
Operating revenue	$	1,077,232	$	719,767	$	660,377	$	1,002,900
Operating income	271,727		130,030		99,044		259,696
Net income (loss)	127,550		35,275		12,836		(467		)

	2016 Quarter
(Unaudited; Dollars in Thousands)	First		Second		Third		Fourth
Operating revenue	$	962,697	$	668,169	$	618,278	$	915,157
Operating income	284,824		175,634		88,072		236,854
Net income (loss)	141,186		64,553		2,335		104,825

Puget Sound Energy	2017 Quarter
(Unaudited; Dollars in Thousands)	First		Second		Third		Fourth
Operating revenue	$	1,077,232	$	719,767	$	660,377	$	1,002,900
Operating income	268,431		126,800		96,369		257,009
Net income (loss)	143,092		50,654		29,100		97,208

	2016 Quarter
(Unaudited; Dollars in Thousands)	First		Second		Third		Fourth
Operating revenue	$	962,697	$	668,169	$	618,594	$	915,158
Operating income	281,425		171,991		84,476		237,101
Net income (loss)	156,505		80,900		18,977		124,199

127

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,
	2017			2016			2015
Non-utility expense and other	$	(1,466	)	$	(5,252	)	$	(1,617	)
Other income (deductions):
Equity in earnings of subsidiary	323,568			385,838			309,603
Non-hedged interest rate swap expense	28			(1,062		)	(3,796		)
Interest income	1,039			2			63
Interest expense	(106,072		)	(104,600		)	(100,114		)
Income taxes	(41,903		)	37,973			37,040
Net income (loss)	175,194			312,899			241,179
Comprehensive income (loss)	$	184,624		$	306,453		$	250,956

See accompanying notes to the condensed financial statements.

128

Puget Energy

Condensed Balance Sheets

(Dollars in Thousands)

	December 31,
	2017		2016
Assets:
Investment in subsidiaries	$	3,721,553	$	3,571,550
Other property and investments:
Goodwill	1,656,513		1,656,513
Current assets:
Cash	751		397
Receivables from affiliates1	78,570		213
Total current assets	79,321		610
Long-term assets:
Deferred income taxes	208,889		309,812
Other	3,196		521
Total long-term assets	212,085		310,333
Total assets	$	5,669,472	$	5,539,006
Capitalization and liabilities:
Common equity	$	3,750,030	$	3,688,713
Long-term debt	1,892,672		1,808,828
Total capitalization	5,642,702		5,497,541
Current liabilities:
Account Payable	1,042		15,801
Interest	25,728		25,523
Unrealized loss on derivative instruments	—		141
Total current liabilities	26,770		41,465
Long-term liabilities:
Total long-term liabilities	—		—
Commitments and contingencies (Note 3)
Total capitalization and liabilities	$	5,669,472	$	5,539,006

_______________

¹  Eliminated in consolidation.

See accompanying notes to the condensed financial statements.

129

Puget Energy

Condensed Statements of Cash Flows

(Dollars in Thousands)

	Year Ended December 31,
	2017			2016			2015
Operating activities:
Net cash provided by (used in) operating activities	139,005			$	145,719		$	171,576
Investing activities:
Investment in subsidiaries	(24,222		)	—			(28,900		)
(Increase) decrease in loan to subsidiary	(78,155		)	—			28,933
Other	(437		)	(6,078		)	(5,632		)
Net cash provided by (used in) investing activities	(102,814		)	(6,078		)	(5,599		)
Financing activities:
Dividends paid	(123,307		)	(148,965		)	(263,059		)
Issuance of bond	—			—			400,000
Issuance/redemption of term-loan and other long-term debt	90,120			12,480			(299,000		)
Issue costs and others	(2,650		)	(3,398		)	(3,341		)
Net cash provided by (used in) by financing activities	(35,837		)	(139,883		)	(165,400		)
Increase (decrease) in cash	354			(242		)	577
Cash at beginning of year	397			639			62
Cash at end of year	$	751		$	397		$	639

See accompanying notes to the condensed financial statements.

130

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 regulated subsidiary, PSE. Puget Energy also hasa wholly-owned non-regulated subsidiary, named Puget LNG, LLC (Puget LNG). Puget LNG was formed on November 29, 2016, and has the sole purpose of owning, developing and financing the non-regulated activity of a LNG facility at the Port of Tacoma, Washington. 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 subsidiaries have been included using the equity method, should be read in conjunction with the consolidated financial statements and notes thereto of Puget Energy included in Item 8, "Financial Statements and Supplementary Data" of this Form 10-K. Puget Energy owns 100% of the common stock of its subsidiaries.

Equity earnings of subsidiary included earnings from PSE of $320.1 million, $380.6 million and $304.2 million for the years ended December 31, 2017, 2016 and 2015, respectively, and business combination accounting adjustments under ASC 805 recorded at Puget Energy for PSE of $3.9 million, $5.2 million and $5.4 million for the years ended December 31, 2017, 2016 and 2015, respectively. Investment in subsidiaries includes Puget Energy business combination accounting adjustments under ASC 805 that are recorded at Puget Energy.

(2) Debt

For information concerning Puget Energy’s long-term debt obligations, see Note 6, "Long-Term Debt" to the consolidated financial statements included in Item 8 of this report.

(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 included in Item 8 of this report.

131

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, 2017
Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable	$	9,798	$	26,266	$	27,163	$	8,901
Year Ended December 31, 2016
Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable	$	9,756	$	24,389	$	24,347	$	9,798
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

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

PugetEnergy

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of Puget Energy’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, Puget Energy has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of December 31, 2017 the end of the period covered by this report.  Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of Puget Energy concluded that these disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There have been no changes in Puget Energy’s internal control over financial reporting during the quarter ended December 31, 2017 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, 2017.

Puget Energy’s effectiveness of internal control over financial reporting as of December 31, 2017 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

132

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, 2017, the end of the period covered by this report.  Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of PSE concluded that these disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There have been no changes in PSE’s internal control over financial reporting during the quarter ended December 31, 2017 that have materially affected, or are reasonably likely to materially affect, PSE’s internal control over financial reporting.

In January 2017, PSE implemented a financial systems modernization project designed to improve the financial processes, tools and methods used throughout our business. The new/updated systems were used in preparing financial information for the year ended December 31, 2017. Management monitored developments related to the financial systems modernization project, including working with the project team to ensure control impacts were identified and documented, in order to assist management in evaluating impacts to internal control. System integration and user acceptance testing were conducted to aid management in its evaluations. Post-implementation reviews of the system implementation and impacted business processes were being conducted to enable management to evaluate the design and effectiveness of internal controls during 2017.

During 2017, PSE implemented internal controls covering the evaluation and assessment of revenue contracts related to the adoption of the new revenue recognition standard as of January 1, 2018. PSE does not anticipate significant changes to internal controls over financial reporting as a result of the adoption of this new standard.

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, 2017.

PSE’s effectiveness of internal control over financial reporting as of December 31, 2017 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

Departure of Directors and Certain Officers; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers

Effective February 28, 2018, the sole shareholders of Puget Sound Energy and PSE (together, the Companies") appointed and elected Christopher Hind to the Boards of Directors of the Companies (the "Boards"). Mr. Hind was appointed to replace David MacMillan, who resigned from the Boards effective January 18, 2018. Initially, Mr. Hind will not be appointed to any committees of the Board.

Mr. Hind is currently the Senior Principal, Private Infrastructure with Canada Pension Plan Investment Board ("CPPIB"), which position he has held since January 2016. Prior to that, Mr. Hind served as a Managing Director, Investment Banking, at CIBC from October 1997 to January 2016. Mr. Hind also currently serves on the board of directors of Transportadora de Gas del Peru S.A., the largest transporter of natural gas and natural gas liquids in Peru.

Mr. Hind was selected by CPPIB and pursuant to the Amended and Restated Bylaws of each of the Companies, will serve as an Owner Director on their respective Boards of Directors. Mr. Hind will not receive any director compensation from the Companies for his service as an Owner Director on the Boards, but will be reimbursed for out-of-pocket expenses.

133

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Board of Directors

As of March 1, 2018, 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 58, has been a director on the boards of PSE since June of 2015 and on the board of Puget Energy since November 2017. Mr. Armstrong was President and CEO of Group Health Cooperative of Seattle, Washington, positions he had held since January 2005, until its acquisition by Kaiser Permanente on February 1, 2017. 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 62, has been a director on the boards of both Puget Energy and PSE since February 2009.  Mr. Chapman is currently the Vice President of Macquarie Infrastructure and Real Assets Inc., a 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 also served on the boards of Cleco Power LLC. 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.

Barbara Gordon, age 59,has been a director on the board of PSE since November 2017.  Ms. Gordon currently serves as a Vice President of the board of directors for Seattle-King County Habitat for Humanity. Ms. Gordon previously served as Executive Vice President and Chief Customer Officer of Bellevue-based Apptio (2016-2017). Prior to that time, Ms. Gordon served as Senior Vice President and Chief Operating Officer of Isilon/EMC (2013-2016) and as Corporate Vice President of Worldwide Customer Service and Support at Microsoft (2003-2013). An independent director not affiliated with any of the Company's investors, Ms. Gordon brings to the Board her expertise in customer-facing technology initiatives and enterprise level management of customer service and support.

Kimberly Harris, age 53, 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, and serves as chair of the American Gas Association.

Christopher Hind, age 48, has been elected a director on the boards of both Puget Energy and PSE effective February 28, 2018. He is currently the Senior Principal, Private Infrastructure with Canada Pension Plan Investment Board ("CPPIB"), which position he has held since January 2016. Prior to that, Mr. Hind served as a Managing Director, Investment Banking, at CIBC from October 1997 to January 2016. Mr. Hind also currently serves on the board of directors of Transportadora de Gas del Peru S.A., the largest transporter of natural gas and natural gas liquids in Peru. Mr. Hind was selected by CPPIB and pursuant to the Amended and Restated Bylaws of each of the Companies, will serve as an Owner Director on their respective Boards of Directors. Mr. Hind will not receive any director compensation from the Companies for his service as an Owner Director on the Boards, but will be reimbursed for out-of-pocket expenses.

Steven W. Hooper, age 64, is a director on the boards of both Puget Energy and PSE, 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 Airbiquity, 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,

134

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.

Karl Kuchel, age 39, has been a director on the boards of both Puget Energy and PSE since January 2017, as a representative of the Company’s Macquarie affiliated investors and FSS Infrastructure Trust, consistent with the Puget Energy and PSE bylaws. Mr. Kuchel is currently the Chief Executive Officer of Macquarie Infrastructure Partners, Inc., which position he has held since June 2016. Prior to that time, Mr. Kuchel served as Chief Operating Officer (from November 2010 through May 2016) of Macquarie Infrastructure Partners, Inc. Mr. Kuchel also currently serves on the boards of directors of various other portfolio companies managed and advised by Macquarie Infrastructure Partners, Inc., and provides the Puget Energy and PSE boards the benefit of his experience managing and overseeing the financial and operational affairs of infrastructure owners.

Christopher Leslie, age 53, 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 also serves as a director on the board of Cleco Power, LLC.  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.

Paul McMillan,age 63, 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 board of 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 69, 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 Business Health Trust.  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.

Etienne Middleton, age 43, has been a director on the boards of both Puget Energy and PSE since March 1, 2016. Mr. Middleton is currently the Senior Principal, Private Infrastructure with CPPIB, which position he has held since 2009. Mr. Middleton 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. Mr. Middleton also serves on the boards of Transelec S.A., a Chilean transmission company, and Grupo Costanera, a Chilean toll-road operator.

Christopher Trumpy, age 63, 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.

135

Audit Committee

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

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.

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 2017, 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 2017 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);

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

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

136

•Philip K. Bussey, Senior Vice President, Chief Customer 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. (FW Cook).  The Committee recommends to the full Board for approval both the salary level for our CEO, based on information provided by FW Cook, 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, based on the compensation philosophy and taking into consideration information provided by FW Cook.

In 2017, 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 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 levels to external market data from similar companies in our industry and targets each element of 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 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 target 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 strategy 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 earned 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 program 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 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-

137

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 fixed and variable cash-based compensation elements to achieve its compensation objectives.

The target 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 2017 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 2017 base salaries, target annual incentives and target long-term incentive awards, the Committee reviewed market data obtained from both industry-specific surveys and proxy statements of public 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 2016 Energy Services Survey, comprised of utility and other companies similar in size and scope of operations to PSE.  The 23 companies in the custom market survey cut used to inform target compensation decisions for 2017 were:

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

As noted, the market survey data were supplemented with proxy statement data for select positions in the Company’s executive compensation peer group, which was comprised of 16 companies, all but three of which overlapped with companies included in the market survey data. The 2016 median revenue of the executive compensation peers was $3.4 billion, which was comparable to PSE’s annual revenues of $3.1 billion at the time the peer group was developed. The peer companies included in the Company’s executive compensation benchmarking peer group to inform 2017 compensation decisions are shown below:

Proxy Peer Group
1.	Alliant Energy	7.	Great Plains Energy	13.	SCANA
2.	Ameren	8.	MDU Resources Group	14.	Vectren
3.	Avista	9.	NiSource	15.	WEC Energy
4.	Black Hills	10.	OGE Energy	16.	Westar Energy
5.	CMS Energy	11.	Pinnacle West Capital
6.	Eversource Energy	12.	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 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

138

differ from those typically found in the market. In addition to the foregoing market data, the Committee generally also received advice from FW Cook in connection with 2017 compensation decisions.

Base Salary

We recognize that it is necessary to provide executives with a fixed amount of 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 2017

The Committee reviewed the base salaries of the Named Executive Officers in early 2017 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, 2017. Base salaries for 2017 generally remained at the 50th percentile of market among the comparator group.   The annual salary for Ms. Harris is unchanged from 2016, given that her current base salary was slightly higher than the market median. The salary increase percentages approved by the Board for the other Named Executive Officers were approximately 3%, similar to salary increases for other non-represented employees, except for Mr. Doyle who did not receive an increase and Mr. Secrist who received an additional adjustment to better align with the market levels.

Name	2016 Base Salary	2017 Base Salary	% Change
Kimberly J. Harris	$900,000	$900,000	—%
Daniel A. Doyle	511,396	511,396	—
Steve R. Secrist	388,327	403,861	4
Marla D. Mellies	308,755	318,019	3
Philip K. Bussey	306,510	312,640	2

2017 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 2017, 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 2017 were the same as those in 2016 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 2017, 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 three targets which must all be satisfied for the safety measure to be treated as met. The three targets for 2017 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 0.52 in 2017.

139

• All employees complete an online defensive driving training. The target completion rate is no less than 95%.

In 2017, 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. The safety measure and eight out of nine SQI measures were met for 2017. For the one SQI measure below the WUTC target, System Average Interruption Duration Index (SAIDI), the Board considered the measure met for incentive purposes based on PSE's performance and recent changes in the measure by the Washington Commission. For 2018 and future years, Company performance on SAIDI will continue to be measured as part of the annual incentive plan, based on performance targets approved by the Board and will function as one of the 10 measures. All 10 customer service and safety measures were met or deemed met.

Funding levels for 2017 at maximum, target, and threshold are shown in the table below:

Annual Incentive Performance Payout Scale and Actual Performance
Performance	2017 EBITDA (In Millions)		SQI & Safety*	Funding Level
Maximum	$	1,733.9	10/10	200	%
Target	1,284.4		10/10	100
Threshold	1,156.0		6/10	30
2017 Actual Performance	$	1,318.3	10/10	113.2	%

_______________

^*  Combined SQI & Safety results of 6/10 or better and minimum EBITDA of $1,156 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 made no adjustments. Individual awards may be adjusted upward or downward based on an evaluation of an executive officer’s performance against individual and team goals that align with the corporate goals described below.

2017 Corporate Goals

In 2017, 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 2017 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 ISP 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.

2017 Annual Incentive Plan Results

Achievement of the corporate goals for 2017 was at 102.6% of target for EBITDA, and deemed fully met for SQI and safety achievement.  PSE EBITDA was $1,318.3 million, and SQI and safety achievement was 10 out of 10, leading to a funding level for 2017 of 113.2% for the annual incentive plan.

For 2017, individual target incentive levels for the annual incentive plan varied by executive officer as a percentage of 2017 base salary as shown in the table below, based on the executive’s level of responsibility within the Company and informed by market data.  Target annual incentive opportunities as a percentage of base salary for Named Executive Officers remained unchanged

140

from 2016 levels, except for Mr. Doyle's target which was increased to 55% of base salary. 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, adjustments were made by the CEO for individual performance of certain Named Executive Officers below CEO in 2016. In recognition of the achievement of individual goals and the Company's financial performance, the Committee similarly recommended an award adjustment for the CEO in 2017. The adjustments for individual performance are noted in the "Bonus" column on the Summary Compensation table and did not materially change the amounts resulting from 2017 achievement of the corporate goals. The Board approved the incentive amounts shown below, which will be paid in March 2018:

Name	Target Incentive (% of Base Salary)	2017 Actual Incentive Paid		2017 Actual Incentive (% of Base Salary)
Kimberly J. Harris	100%	$	1,069,740	119	%
Daniel A. Doyle	55	286,556		56
Steve R. Secrist	45	205,727		51
Marla D. Mellies	45	161,999		51
Philip K. Bussey	45	159,259		51

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 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.

2017-2019 Long-Term Incentive Plan Target Awards and Performance Goals

Consistent with prior years, target LTI Plan awards for the 2017-2019 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 and the corresponding market data. Target LTI Plan award amounts for the 2017-2019 performance cycle were 265% 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 2016-2018 performance cycle, except for Ms. Harris. The Board approved an increase in Ms. Harris’ target award from 220% to 265% to provide a target award that was market competitive. The total number of target LTI Plan units granted to a Named Executive Officer for the 2017-2019 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 $52.37. Details of the number of units granted and expected values at target, threshold and maximum performance levels can be found in the “2017 Grants of Plan-Based Awards” table below. Target Total Return is set annually by the Board prior to the grant date, and was set at 9.8% for the 2017-2019 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.

141

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 2017-2019 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	200.0%
115% of Target	185.5
110% of Target	157.0
105% of Target	128.5
100% of Total Return Target	100.0
95% of Target	88.6
90% of Target	77.1
89.1% of Target	75.0
85% of Target	59.0
80% of Target	39.5
75% of Target	20.0
<75% of Target	—

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	200.0%
115% of Target	185.5
110% of Target	157.0
105% of Target	128.5
Target ROE	100.0
95% of Target	84.0
90% of Target	68.0
85% of Target	52.0
80% of Target	36.0
75% of Target	20.0
<75% of Target	—

142

Performance Scales for the 2016-2018 LTI Plan 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 2016-2018 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	200.0%
115% of Target	185.5
110% of Target	157.0
105% of Target	128.5
100% of Total Return Target	100.0
95% of Target	92.9
90% of Target	85.7
85% of Target	78.6
82.5% of Target	75.0
80% of Target	56.7
75% of Target	20.0
<75% of Target	—

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	200.0%
115% of Target	185.5
110% of Target	157.0
105% of Target	128.5
Target ROE	100.0
95% of Target	84.0
90% of Target	68.0
85% of Target	52.0
80% of Target	36.0
75% of Target	20.0
<75% of Target	—

143

Performance Scales for the 2015-2017 LTI Plan 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	200.0%
115% of Target	185.5
110% of Target	157.0
105% of Target	128.5
100% of Total Return Target	100.0
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	20.0
<75% of Target	—

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	200.0%
115% of Target	185.5
110% of Target	157.0
105% of Target	128.5
Target ROE	100.0
95% of Target	84.0
90% of Target	68.0
85% of Target	52.0
80% of Target	36.0
75% of Target	20.0
<75% of Target	—

144

Long-Term Incentive Plan Performance 2015-2017 Performance Cycle

The 2015-2017 performance cycle has now ended. Amounts payable as a result of award vesting are shown in the following table:

• Performance on Total Return in 2017 was 29.1%, which was significantly higher than target, reflecting an increase in valuation due to market transactions during 2017.

• Performance on the Total Return component for the three-year performance cycle was a compounded annual rate of 14.93%, above target and at the maximum of the funding scale. The Total Return Component funded at 200% of target units.

• Performance on the ROE component of the grant was an average of 102.2% of target for funding at 112.8% of target units.

Name	Target Incentive (% of Base Salary)1	Total Return Component Units Granted/Paid	ROE Component Units Granted/Paid	2015-2017 Actual LTIP Paid2
Kimberly J. Harris	200%	20,211/40,422	20,211/22,798	$	4,274,305
Daniel A. Doyle	95%	5,296/10,592	5,296/5,973.9	1,120,020
Steve R. Secrist	95%	3,871.5/7,743	3,871.5/4,367.1	818,760
Marla D. Mellies	95%	3,197.5/6,395	3,197.5/3,606.8	676,220
Philip K. Bussey	95%	3,174.5/6,349	3,174.5/3,580.8	671,356

______________

¹  Target LTI Plan incentive is a percentage of 2015 base salary when the grants were made in 2015.

²  2015-2017 actual LTI Plan amount payable is equal to the unit price $67.61 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, 2017, 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 (% of Target)	Payout (% of Target)	Total Projected Payout (based on performance as of 12/31/2017)
2016-2018	67% Complete	15.3%	200%	102.2%	118.4%	159.4%
2017-2019	33% Complete	15.2%	200%	102.7%	115.1%	157.6%

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 “2017 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 “2017 Nonqualified Deferred Compensation” table.

145

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, 2017.

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 2017. 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.

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. With the changes in federal tax law enacted in 2018, the Company will become subject to IRS section 162(m) limitations on company deductions for executive pay. Based on current understanding of the new tax law, the Company does not expect to make changes in program designs.

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

146

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 2017, except as noted below.

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, 2017 for filing with the SEC.

Compensation and Leadership

Development Committee of

Puget Energy, Inc.

Puget Sound Energy, Inc.

Christopher Trumpy, Chair

Scott Armstrong (served beginning March 1, 2017)

Christopher Leslie

Etienne Middleton

Mary McWilliams

147

Summary Compensation Table

The following information is provided for the year ended December 31, 2017 (and for prior years where applicable) with respect to the Named Executive Officers during 2017.  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, 2017.  Salary and incentive compensation includes amounts deferred at the executive’s election.

Name and Principal Position	Year	Salary		Bonus1		Stock Awards		Option Awards		Non-Equity Incentive Plan Compensation2		Change in Pension Value and Nonqualified Deferred Compensation Earnings3		All Other Compensation4		Total
Kimberly J. Harris	2017	$	900,000	$	50,940					$	5,293,105	$	1,523,783	$	20,338	$	7,788,166
President and Chief	2016	$	900,000	$	269,595	$	—	$	—	$	2,615,706	$	650,281	$	20,338	$	4,455,920
Executive Officer5	2015	900,000		—		—		—		2,245,875		157,077		25,032		3,327,984
Daniel A. Doyle	2017	$	511,396							$	1,406,575	$	483,109	$	56,801	$	2,457,881
Senior Vice President,	2016	$	508,322	$	18,299	$	—	$	—	$	742,885	$	370,670	$	49,836	$	1,690,012
Chief Financial Officer6	2015	493,488		—		—		—		609,770		360,012		51,487		1,514,757
Steve R. Secrist	2017	$	400,690							$	1,024,487	$	576,802	$	46,033	$	2,048,012
Senior Vice President,	2016	$	383,085	$	50,510	$	—	$	—	$	549,678	$	268,972	$	41,344	$	1,293,589
General Counsel, Chief Ethics & Compliance Officer7	2015	360,721		—		—		—		297,862		95,399		23,861		777,843
Marla D. Mellies	2017	$	316,128							$	838,219	$	478,905	$	34,531	$	1,667,783
Senior Vice President,	2016	$	306,901	$	20,588	$	—	$	—	$	447,014	$	279,975	$	30,414	$	1,084,892
Chief Administrative Officer8	2015	297,651		—		—		—		387,201		143,686		30,941		859,479
Philip K. Bussey	2017	$	311,388							$	830,615	$	465,653	$	26,989	$	1,634,645
Senior Vice President, Chief Customer Officer9	2016	$	304,668	$	12,186	$	—	$	—	$	448,226	$	305,837	$	25,503	$	1,096,420
	2015	296,367		—		—		—		378,286		408,937		23,792		1,107,382

_______________

¹  For 2017, reflects individual performance above target as described in the "Compensation Discussion and Analysis," section titled "2017 Annual Incentive Plan Results" in the amount of: Ms. Harris, $50,940. For 2016, also included additional incentive paid based on review of 2015 results for SQIs in the amount of: Ms. Harris, $85,995; Mr. Doyle, $18,299; Mr. Secrist, $14,862; Ms. Mellies, $13,503; Mr. Bussey, $12,186 and includes adjustments to reflect individual performance above target in the amount of: Ms. Harris, $183,600; Mr. Secrist, $35,648; Ms. Mellies, $7,085.

²  For 2017, reflects annual cash incentive compensation paid under the 2017 Goals and Incentive Plan and cash incentive compensation paid under the LTI Plan for the 2015-2017 performance cycle. Cash incentive amounts were paid in early 2018 or deferred at the executive's election.  The 2017 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 2018.

³  Reflects the aggregate increase in the actuarial present value of the executive’s accumulated benefit under all pension plans during the year.  The amounts are determined using interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements and include amounts which the executive may not currently be entitled to receive because such amounts are not vested.  In 2017, updated interest rates and mortality assumptions have generally increased the actuarial value of the underlying retirement benefits relative to assumptions for 2016.  Information regarding these pension plans is set forth in further detail under “2017 Pension Benefits.”  The change in pension value amounts for 2017 are: Ms. Harris, $1,520,618; Mr. Doyle, $483,109; Mr. Secrist, $576,802, Ms. Mellies, $478,462; and Mr. Bussey, $465,653.  Also included in this column are the portions of Deferred Compensation Plan earnings that are considered above market.  These amounts for 2017 are: Ms. Harris, $3,165; Mr. Doyle, $0; Mr. Secrist, $0; Ms. Mellies, $443; and Mr. Bussey, $0. See the “2017 Nonqualified Deferred Compensation” table for all Deferred Compensation Plan earnings.

⁴  All Other Compensation for 2017 is shown in detail in the table below.

⁵  Ms. Harris was promoted to President and CEO from President on March 1, 2011.

⁶  Mr. Doyle joined PSE and Puget Energy as Senior Vice President and Chief Financial Officer on November 28, 2011.

⁷  Mr. Secrist has worked at PSE since May 1989.

⁸  Ms. Mellies has worked at PSE since October 2005.

⁹  Mr. Bussey rejoined PSE as Senior Vice President and Chief Customer Officer on March 19, 2012 and retired effective January 8, 2018.

148

Detail of All Other Compensation

Name	Perquisites and Other Personal Benefits1		Registrant Contributions to Defined Contribution and Deferred Compensation Plans2		Other3
Kimberly J. Harris	$	—	$	14,650	$	5,688
Daniel A. Doyle	2,500		48,516		5,785
Steve R. Secrist	1,300		40,416		4,317
Marla D. Mellies	1,263		29,981		3,287
Philip K. Bussey	1,440		18,850		6,699

_______________

¹  Reimbursement for financial planning, tax planning, and/or legal planning, with the initial plan up to a maximum of $5,000, and then annual reimbursement up to a maximum of $5,000 for Ms. Harris and $2,500 for the other Named Executive Officers.  

²  Includes Company contributions during 2017 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, $14,650; Mr. Doyle, $18,850; Mr. Secrist $18,850 ; Ms. Mellies, $18,850; and Mr. Bussey, $18,850 Company contributions to the Deferred Compensation Plan are as follows: Ms. Harris, $0; Mr. Doyle, $29,666; Mr. Secrist, $21,566; Ms. Mellies, $11,131; and Mr. Bussey, $0.

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

2017 Grants of Plan-Based Awards

The following table presents information regarding 2017 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 Incentive1	1/1/2017		$	270,000	$	900,000	$	1,800,000
LTI Plan 2017-20192	3/2/2017	45,451	590,120		3,156,902		6,614,375
Daniel A. Doyle
Annual Incentive1	1/1/2017		$	84,380	$	281,268	$	562,536
LTI Plan 2017-20192	3/2/2017	9,277	120,211		643,082		1,347,391
Steve R. Secrist
Annual Incentive1	1/1/2017		$	54,521	$	181,737	$	363,475
LTI Plan 2017-20192	3/2/2017	7,326	94,930		507,838		1,064,028
Marla D. Mellies
Annual Incentive1	1/1/2017		$	42,933	$	143,109	$	286,217
LTI Plan 2017-20192	3/2/2017	5,769	74,755		399,907		837,890
Philip K. Bussey
Annual Incentive1	1/1/2017		$	41,379	$	137,930	$	275,859
LTI Plan 2017-20192	3/2/2017	5,671	73,485		393,114		823,656

_______________

¹  As described in the “Compensation Discussion and Analysis,” the 2017 Goals and Incentive Plan had dual funding triggers in 2017 of $1,156 million EBITDA and SQI performance of 6/10.  Payment would be $0 if either trigger is not met.  The threshold estimate assumes $1,156 million EBITDA and SQI/Safety measure performance at 6/10. The target estimate assumes $1,284.4 million EBITDA and SQI/Safety measure performance at 10/10.  The maximum estimate assumes $1,733.9 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 2017-2019 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.

149

2017 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	18.7	$	469,525	$	—
	SERP	18.7	9,449,499		—
Daniel A. Doyle	Retirement Plan	6.1	183,734		—
	SERP	6.1	1,766,273		—
Steve R. Secrist	Retirement Plan	28.6	547,704		—
	SERP	28.6	2,700,486		—
Marla D. Mellies	Retirement Plan	12.2	340,322		—
	SERP	12.2	1,940,490		—
Philip K. Bussey	Retirement Plan	11.3	375,495		—
	SERP	11.3	2,038,638		—

_______________

¹  The amounts reported in this column for each executive were calculated assuming no future service or pay increases. Present values were calculated assuming no pre-retirement mortality or termination.  The values under the Retirement Plan and the SERP are the actuarial present values as of December 31, 2017 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 4.00%, and the post-retirement mortality assumption is based on the 2018 417(e) unisex mortality table. Annuity benefits are converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 1.75%, 3.76%, and 4.66% (the 24-month average of the underlying rates as of September 2017).  These assumptions are consistent with the ones used for the Retirement Plan and the SERP for financial reporting purposes for 2017.  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, 2016 for the benefits earned as of that date using the assumptions used for financial reporting purposes for 2016.  These assumptions included assumed cash balance interest credits of 4.0%, a discount assumption of 4.50% and post-retirement mortality assumption based on the 2017 417(e) unisex mortality table. Annuity benefits were converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 1.52%, 3.80% and 4.79% (the 24-month average of the underlying rates as of September 2016). Other assumptions used to determine the value as of December 31, 2016 were the same as those used for December 31, 2017.

²  As described in footnote 1 above, the amounts reported for the SERP in this column are actuarial present values, calculated using the actuarial assumptions used for financial reporting purposes.  These assumptions are different from those used to calculate the actual amount of benefit payments under the SERP (see text below for a discussion of the actuarial assumptions used to calculate actual payment amounts).  The following table shows the estimated lump sum amount that would be paid under the SERP to each SERP-eligible Named Executive Officer at age 62 (without discounting to the present), calculated as if such Named Executive Officer had terminated employment on December 31, 2017.  Each SERP-eligible Named Executive Officer was vested in his or her SERP benefits as of December 31, 2017.

Name	Estimated Lump Sum
Kimberly J. Harris	$	13,102,472
Daniel A. Doyle	1,954,612
Steve R. Secrist	3,428,163
Marla D. Mellies	2,292,468
Philip K. Bussey	2,058,726

150

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 2017, the limit was $270,000. For 2018, the limit is $275,000. 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 2017 and 2018, 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, 2017, 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 are vested in their SERP benefits.  

151

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 (i) below minus the sum of (ii) and (iii) below:

i.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.

ii.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.

iii.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 “2017 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.

152

2017 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 2017 and year-end account balances under the Deferred Compensation Plan.

Name	Executive Contributions in 20171		Registrant Contributions in 20172		Aggregate Earnings in 20173		Aggregate Withdrawals/ Distributions		Aggregate Balance at December 31, 20174
Kimberly J. Harris	$	—	$	—	$	12,727	$	—	$	324,915
Daniel A. Doyle	27,866		29,666		84,406		—		940,709
Steve R. Secrist	32,355		21,566		5,222		—		98,893
Marla D. Mellies	10,706		11,131		16,833		—		168,591
Philip K. Bussey	—		—		—		—		—

_______________

¹  The amount in this column reflects elective deferrals by the executive of salary, annual incentive compensation or LTI Plan awards paid in 2017.  Deferred salary amounts are: Ms. Harris, $0; Mr. Doyle, $27,866; Mr. Secrist, $32,355; Ms. Mellies, $10,706; and Mr. Bussey, $0. Deferred incentive compensation amounts are: Ms. Harris, $0; Mr. Doyle, $0; Mr. Secrist, $0; Ms. Mellies, $0; and Mr. Bussey, $0. The amounts are also included in the applicable column of the Summary Compensation Table for 2017.

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 2017.

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 2017.

⁴  Of the amounts in this column, the amounts in the table below have also been reported in the Summary Compensation Table for 2017, 2016 and 2015.

Name	Reported for 2017		Reported for 2016		Reported for 2015
Kimberly J. Harris	$	3,165	$	4,033	$	3,259
Daniel A. Doyle	57,531		273,509		259,782
Steve R. Secrist	53,922		39,223		—
Marla D. Mellies	22,280		15,428		17,869
Philip K. Bussey	—		—		—

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 2017 calendar year returns of these tracking funds were:

Vanguard Total Bond Market Index	3.57	%
Vanguard 500 Index	21.67
Vanguard Money Market Index	0.81
Interest Crediting Fund (pre-2012 deferrals)	4.14

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.

153

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) a change in control; (ii) an involuntary termination without cause or for good reason in connection with a change in control; (iii) retirement; (iv) disability; or (v) 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 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, under certain conditions, as 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.

154

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 2017, 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.

155

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 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.

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, 2017.  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.

156

	Upon Change in Control (and awards not assumed or substituted)		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	8,846,802		8,846,802		—		8,846,802		8,846,802
SERP (additional years of credited service)1	—		—		—		—		—
Benefits (continuation)2	—		29,788		—		29,788		29,788
Supplemental Life Insurance	—		—		—		—		3,000,000
Total Estimated Incremental Value	$	8,846,802	$	14,276,590	$	—	$	8,876,590	$	11,876,590
Daniel A. Doyle	$	—	$	—	$	—	$	—	$	—
Long Term Incentive Plan	2,175,280		2,175,280		—		2,175,280		2,175,280
SERP (additional years of credited service)1	—		—		—		—		—
Benefits (continuation)2	—		—		—		—		—
Supplemental Life Insurance	—		—		—		—		1,073,932
Total Estimated Incremental Value	$	2,175,280	$	2,175,280	$	—	$	2,175,280	$	3,249,212
Steve R. Secrist	$	—	$	—	$	—	$	—	$	—
Long Term Incentive Plan	1,629,983		1,629,983		—		1,629,983		1,629,983
SERP (additional years of credited service)1	—		—		—		—		—
Benefits (continuation)2	—		—		—		—		—
Supplemental Life Insurance	—		—		—		—		767,336
Total Estimated Incremental Value	$	1,629,983	$	1,629,983	$	—	$	1,629,983	$	2,397,319
Marla D. Mellies	$	—	$	—	$	—	$	—	$	—
Cash Severance (salary and/or annual incentive)	—		1,383,383		—		—		—
Long Term Incentive Plan	1,319,202		1,319,202		—		1,319,202		1,319,202
SERP (additional years of credited service)1	—		447,342		—		—		—
Benefits (continuation)2	—		42,756		—		42,756		42,756
Supplemental Life Insurance	—		—		—		—		604,236
Total Estimated Incremental Value	$	1,319,202	$	3,192,683	$	—	$	1,361,958	$	1,966,194
Philip K. Bussey	$	—	$	—	$	—	$	—	$	—
Cash Severance (salary and/or annual incentive)
Long Term Incentive Plan	1,307,720		1,307,720		—		1,307,720		1,307,720
SERP (additional years of credited service)1	—		—		—		—		—
Benefits (continuation)2	—		—		—		—		—
Supplemental Life Insurance	—		—		—		—		594,016
Total Estimated Incremental Value	$	1,307,720	$	1,307,720	$	—	$	1,307,720	$	1,901,736

_______________

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, 2017. 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.

157

Chief Executive Officer Pay Ratio

We are providing the following information about the relationship of the annual total compensation of our employees and the annual total compensation for our Chief Executive Officer in accordance with SEC Item 402(u) of Regulation S-K.

For 2017, our last completed fiscal year:

• The annual total compensation of our CEO, as reported in the 2017 Summary Compensation Table, was $7,788,167.

• The median of the annual total compensation of all our employees (excluding our CEO) was $117,999

As a result, for 2017 the ratio of annual total compensation of our Chief Executive Officer and President, to the median of our annual total compensation of all employees was 66:1.

We identified our median employee by examining the total cash compensation we paid during 2017 to all individuals, excluding our CEO, who were employed by us on December 31, 2017, which totaled approximately 3,160 individuals, all located in the United States (as reported in Item 1. Business), including employees, whether employed on a full-time, part-time or seasonal basis. Total cash compensation consisted of base salary, overtime, paid time off and annual incentives as reflected in our payroll records. We consistently applied this compensation measure and did not make any assumptions, adjustments, or estimates with respect to total cash compensation. We believe that the use of total cash compensation for all employees is a consistently applied compensation measure because it includes all major compensation elements available to employees. Pay for all non-represented employees in the organization is benchmarked periodically to ensure alignment with our compensation philosophy of paying at the market median.

After identifying the median employee based on total cash compensation for 2017, we calculated annual total compensation for such employee for 2017 using the same methodology we use for our named executive officers as set forth in the 2017 Summary Compensation Table in accordance with the requirements of Item 402 (c)(2)(x) of Regulation S-K. Annual total compensation for 2017 for our median employee included annual salary, annual incentives, company contributions towards benefits including retirement. Annual total compensation for 2017 for our CEO consists of the amount reported in the "Total" column of our 2017 Summary Compensation Table.

158

Director Compensation for Fiscal Year 2017

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 2017 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, Karl Kuchel, Christopher Leslie, and Etienne Middleton. 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 2017 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 Earnings1		Total
Scott Armstrong	$	—	$	146,400	$	146,400
Melanie Dressel2	30,700		—		30,700
Barbara Gordon	18,333				18,333
Steve Hooper	—		187,033		187,033
David MacMillan3	155,200		—		155,200
Paul McMillan	139,600		—		139,600
Mary O. McWilliams	134,800		—		134,800
Christopher Trumpy	144,400		—		144,400

_______________

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

²  Melanie Dressel’s service as a member of the Board of Directors ended upon her death as of February 19, 2017.

³  David MacMillan resigned from his position as a member of the Board of Directors, effective as of January 18, 2018.

Nonemployee Director Compensation Program

The 2017 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 2017 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 2017, 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.

159

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.   Steve Hooper and Scott Armstrong are the only independent board members to defer any director fees during 2017.

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, 2017 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, 2017.

Beneficial Ownership Table of Puget Energy and PSE

	Number of Beneficially Owned Shares
Name	Puget Energy	PSE
Puget Equico LLC and affiliates	2001, 2	—
Puget Energy	—	85,903,7913

_______________

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, among others, 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), 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, 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 is 125 West 55th Street, Level 22, New York, NY 10019.

• 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.

160

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 arm's 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.

Scott Armstrong serves on the Board of Directors of the Company and, until its acquisition by Kaiser Permanente on February 1, 2017, was the president and Chief Executive Officer of Group Health Cooperative (Group Health). Group Health provided coverage to over 600,000 residents in Washington and Northern Idaho. Certain employees of PSE elected Group Health as their medical provider prior to its acquisition by Kaiser Permanente. PSE made no payments to Group Health, as all payments were made after its acquisition by Kaiser Permanente for medical coverage for the year ended December 31, 2017.

Kimberly Harris, the President and Chief Executive Officer and a director of Puget Energy and PSE, is married to Kyle Branum, who is a partner at Summit Law Group, which provides legal services to PSE.  In 2017, Summit Law Group was paid $0.8 million for legal services provided to PSE and Mr. Branum was among the lawyers at Summit Law Group who provided such legal services.  This work was performed under the supervision of PSE's General Counsel.

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), Scott Armstrong (member of the Board of PSE and added to the Board of Puget Energy at the November, 2017 Board Meeting), and Barbara Gordon (member of the Board of PSE) are independent under the NYSE corporate governance listing standards and also meet the definition of an “Independent Director” under the Company’s Amended and Restated Bylaws.  Under the Amended and Restated Bylaws of Puget Energy and PSE, an Independent Director is a director who: (i) 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), (ii) shall not be an officer or employee of PSE, (iii) shall be a resident of the state of Washington, and (iv) 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.

161

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.  Mr. Hooper and Mr. Armstrong, Ms. McWilliams and former Board member Melanie Dressel serve (or served) as directors or officers of, or otherwise have/had 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.  Mr. Hooper, 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, "Directors, Executives Officers and Corporate Governance" of Part III of this Form 10-K 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, 2017 and 2016 were as follows:

	2017				2016
(Dollars in Thousands)	Puget Energy		PSE		Puget Energy		PSE
Audit fees1	$	2,777	$	2,546	$	2,597	$	2,397
Audit related fees2	22		22		47		47
Tax fees3	—		—		—		—
Other fees4	337		337		383		383
Total	$	3,136	$	2,905	$	3,027	$	2,827

_______________

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 2017 fees are estimated and include an aggregate amount of $1.7 million billed to Puget Energy and $1.6 million to PSE through December 2017.

²  Consists of work performed in connection with registration statements and other regulatory audits.

³  Consists of tax consulting and tax return reviews.

⁴  Consists of software and research tools.

The Audit Committee of the Company has adopted policies for the pre-approval of all audit and non-audit services provided by the Company’s independent registered public accounting firm.  The policies are designed to ensure that the provision of these services does not impair the firm’s independence.  Under the policies, unless a type of service to be provided by the independent registered public accounting firm has received general pre-approval, it will require specific pre-approval by 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

162

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 2017 and 2016, 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, 2017, 2016 and 2015, consist of the following:

I. Condensed Financial Information of Puget Energy

II. Valuation of Qualifying Accounts and Reserves

3) Exhibits

ITEM 16. FORM 10-K SUMMARY

None.

163

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 (Exhibit originally filed with the Securities and Exchange Commission in paper format and as such, a hyperlink is not available.), Commission File No. 1-4393; Exhibit 4.26 to Puget Sound Energy’s Current Report on Form 8-K, dated March 4, 1999 (Exhibit originally filed with the Securities and Exchange Commission in paper format and as such, a hyperlink is not available.), Commission File No. 1-4393; Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated November 2, 2000 (Exhibit originally filed with the Securities and Exchange Commission in paper format and as such, a hyperlink is not available.), 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 Puget Sound Energy’s Registration Statement on Form S-3, filed March 13, 2009, Registration No. 333-157960).
		Exhibits 4.3 through and including 4.23: 4.3, 4.4, 4.5, 4.6, 4.7, 4.8, 4.9. 4.10, 4.11, 4.12, 4.13, 4.14, 4.15, 4.16, 4.17, 4.18, 4.19, 4.20, 4.21, 4.22, 4.23.
***	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, (Exhibit originally filed with Securities and Exchange 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, not available). 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 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.

164

***		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.
		Commission File No. 1-4393; Exhibit 4.28 to Puget Sound Energy's Current Report on 10-K for fiscal year ended December 31, 2004.
	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).
		Exhibits 4.1 through 4.3: 4.1, 4.2, 4.3.
	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).
		Exhibits 4.26 through 4.30: 4.26, 4.27, 4.28, 4.29, 4.30.
***	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).

165

	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).
***	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).

166

***	10.12	Contract dated June 19, 1974 between Puget Sound Energy, Inc. and P.U.D. No. 1 of Chelan County (incorporated herein by reference to Exhibit 10.12 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
***	10.13	Transmission Agreement dated April 17, 1981 between the Bonneville Power Administration and Puget Sound Energy, Inc. (Colstrip Project) (incorporated herein by reference to Exhibit (10)-55 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
***	10.14	Transmission Agreement dated April 17, 1981 between the Bonneville Power Administration and Montana Intertie Users (Colstrip Project) (incorporated herein by reference to Exhibit (10)-56 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
***	10.15	Ownership and Operation Agreement dated as of May 6, 1981 between Puget Sound Energy, Inc. and other Owners of the Colstrip Project (Colstrip 3 and 4) (incorporated herein by reference to Exhibit (10)-57 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
***	10.16	Colstrip Project Transmission Agreement dated as of May 6, 1981 between Puget Sound Energy, Inc. and Owners of the Colstrip Project (incorporated herein by reference to Exhibit (10)-58 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
***	10.17	Common Facilities Agreement dated as of May 6, 1981 between Puget Sound Energy, Inc. and Owners of Colstrip 1 and 2, and 3 and 4 (incorporated herein by reference to Exhibit (10)-59 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
***	10.18	Amendment dated as of June 1, 1968, to Power Sales Contract between Public Utility District No. 1 of Chelan County, Washington and Puget Sound Energy, Inc. (Rocky Reach Project) (incorporated herein by reference to Exhibit (10)-66 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
***	10.19	Transmission Agreement dated as of December 30, 1987 between the Bonneville Power Administration and Puget Sound Energy, Inc. (Rock Island Project) (incorporated herein by reference to Exhibit (10)-74 to Report on Form 10-K for the fiscal year ended December 31, 1988, Commission File No. 1-4393).
***	10.20	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).

167

	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).
**	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 (incorporated herein by reference to Exhibit 10.38 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2015, Commission File No.1-16305 and 1-4393).
**	10.39	Puget Sound Energy, Inc. Supplemental Death Benefit Plan for Executive Employees, effective October 1, 2000, as amended (incorporated herein by reference to Exhibit 10.45 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305 and 1-4393).
**	10.40	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 (incorporated herein by reference to Exhibit 10.43 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2015, Commission File No. 1-16305 and 1-4393).
	10.44	Amendment No. 1 dated April 15, 2014 to Credit Agreement dated as of February 4, 2013 among Puget Sound Energy, Inc., as Borrower, Wells Fargo Bank, National Association, as Administrative Agent and the Lenders party thereto. (incorporated herein by reference to Exhibit 10.2 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2014, Commission File No. 1-16305 and 1-4393).

168

	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).
	10.46	Credit Agreement dated October 25, 2017 among Puget Energy Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto. (incorporated by reference to Exhibits 10.1 to Puget Energy's Current Report on Form 8-K, filed in October 31, 2017, Commission File No. 1-16305).
	10.47	Credit Agreement dated October 25, 2017 among Puget Sound Energy, Inc., as Borrower, Mizuho Bank, Ltd., as Administrative Agent, and the lenders party thereto. (incorporated by reference to Exhibits 10.2 to Puget Sound Energy's Current Report on Form 8-K, filed October 31, 2017, Commission file No. 1-4393).
*	12.1	Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy, Inc. (2013 through 2017).
*	12.2	Statement setting forth computation of ratios of earnings to fixed charges of Puget Sound Energy, Inc. (2013 through 2017).
*	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, 2017, filed on March 1, 2018, formatted in XBRL: (i) the Consolidated Statement of Income (Unaudited), (ii) the Consolidated Statements of Comprehensive Income (Unaudited), (iii) the Consolidated Balance Sheets (Unaudited), (iii) the Consolidated Statements of Cash Flows (Unaudited), and (iv) the Notes to Consolidated Financial Statements (submitted electronically herewith).

_______________

* Filed herewith.

** Management contract, compensatory plan or arrangement.

*** Exhibit originally filed with the Securities and Exchange Commission in paper format and as such, a hyperlink is not available.

169

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

PUGET ENERGY, INC.		PUGET SOUND ENERGY, INC.
/s/ Kimberly J. Harris		/s/ Kimberly J. Harris
Kimberly J. Harris		Kimberly J. Harris
President and Chief Executive Officer		President and Chief Executive Officer
Date:	March 1, 2018	Date:	March 1, 2018

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of each registrant and in the capacities and on the dates indicated.

Signature	Title	Date
	(Puget Energy and PSE unless otherwise noted)
/s/ Kimberly J. Harris	President and	March 1, 2018
(Kimberly J. Harris)	Chief Executive Officer
/s/ Daniel A. Doyle	Senior Vice President and
(Daniel A. Doyle)	Chief Financial Officer
/s/ Stephen J. King	Controller and Principal Accounting Officer
(Stephen J. King)
/s/ Scott Armstrong	Director
(Scott Armstrong)
/s/ Andrew Chapman	Director
(Andrew Chapman)
/s/ Steven W. Hooper	Director
(Steven W. Hooper)
/s/ Karl Kuchel	Director
(Karl Kuchel)
/s/ Christopher J. Leslie	Director
(Christopher J. Leslie)
/s/ Barbara Gordon	Director of PSE only
(Barbara Gordon)

170

/s/ Paul McMillan	Director
(Paul McMillan)
/s/ Mary O. McWilliams	Director
(Mary O. McWilliams)
/s/ Etienne Middleton	Director
(Etienne Middleton)
/s/ Christopher Trumpy	Director
(Christopher Trumpy)
/s/ Christopher Hind	Director
(Christopher Hind)

171

EX-12.1

																	Exhibit 12.1
PUGET ENERGY
STATEMENT SETTING FORTH COMPUTATIONS OF RATIOS OF
EARNINGS TO FIXED CHARGES
(Dollars in Thousands)
	Years Ended December 31,
	2017				2016				2015				2014				2013
Earnings Available For Fixed Charges:
Pre-tax income:
Income from continuing operations before income taxes	$	430,337			$	453,103			$	332,954			$	228,820			$	408,136
AFUDC - equity	(15,027		)		(12,576		)		(9,325		)		(7,002		)		(15,930		)
AFUDC - debt	(10,826		)		(9,304		)		(7,575		)		(5,611		)		(11,261		)
Total	404,484				431,223				316,054				216,207				380,945
Fixed charges:
Interest expense	343,976				355,139				356,696				367,308				392,264
Other interest	15,027				12,576				9,325				7,002				15,930
Portion of rentals representative of the interest factor (a)	8,062				8,061				8,980				10,732				10,257
Total	367,065				375,776				375,001				385,042				418,451
Earnings available for combined fixed changes	$	771,549			$	806,999			$	691,055			$	601,249			$	799,396
Ratio of Earnings to Fixed Changes	$	2.10		x	$	2.15		x	$	1.84		x	$	1.56		x	$	1.91		x

^(a) Represents interest portion of rents estimated at 33 1/3 percent.

EX-12.2

																	Exhibit 12.2
PUGET SOUND ENERGY
STATEMENT SETTING FORTH COMPUTATIONS OF RATIOS OF
EARNINGS TO FIXED CHARGES
(Dollars in Thousands)
	Years Ended December 31,
	2017				2016				2015				2014				2013
Earnings Available For Fixed Charges:
Pre-tax income:
Income from continuing operations before income taxes	$	532,040			$	555,928			$	430,089			$	325,955			$	517,015
AFUDC - equity	(15,027		)		(12,576		)		(9,325		)		(7,002		)		(15,930		)
AFUDC - debt	(10,826		)		(9,304		)		(7,575		)		(5,611		)		(11,261		)
Total	506,187				534,048				413,189				313,342				489,824
Fixed charges:
Interest expense	229,317				242,983				247,571				264,926				261,377
Other interest	15,027				12,576				9,325				7,002				15,930
Portion of rentals representative of the interest factor (a)	8,062				8,061				8,980				10,732				10,257
Total	252,406				263,620				265,876				282,660				287,564
Earnings available for combined fixed charges	$	758,593			$	797,668			$	679,065			$	596,002			$	777,388
Ratio of Earnings to Fixed Charges	$	3.01		x	$	3.03		x	$	2.55		x	$	2.11		x	$	2.70		x

^(a)Represents interest portion of rents estimated at 33 1/3 percent.

EX-21.1

Exhibit 21.1

Puget Energy, Inc.

SUBSIDIARIES

1. Puget Sound Energy, Inc.

10885 N.E. Fourth Street, Suite 1200

Bellevue, Washington 98004

2. Puget LNG, LLC

10885 N.E. Fourth Street, Suite 1200

Bellevue, Washington 98004

EX-21.2

Exhibit 21.2

Puget Sound Energy, Inc.

SUBSIDIARIES

1. Puget Western, Inc.

19515 North Creek Parkway

Suite 310

Bothell, Washington 98011

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-214490) of Puget Sound Energy, Inc. of our report dated March 1, 2018 relating to the financial statements, financial statement schedules and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Seattle, Washington

March 1, 2018

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Kimberly J. Harris, certify that:

I have reviewed this report on Form 10-K of Puget Energy, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s Board of Directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	March 1, 2018
/s/ Kimberly J. Harris
Kimberly J. Harris
President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Daniel A. Doyle, certify that:

I have reviewed this report on Form 10-K of Puget Energy, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s Board of Directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	March 1, 2018
/s/ Daniel A. Doyle
Daniel A. Doyle
Senior Vice President and
Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Kimberly J. Harris, certify that:

I have reviewed this report on Form 10-K of Puget Sound Energy, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s Board of Directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	March 1, 2018
/s/ Kimberly J. Harris
Kimberly J. Harris
President and Chief Executive Officer

EX-31.4

Exhibit 31.4

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Daniel A. Doyle, certify that:

I have reviewed this report on Form 10-K of Puget Sound Energy, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s Board of Directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	March 1, 2018
/s/ Daniel A. Doyle
Daniel A. Doyle
Senior Vice President and
Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Puget Energy, Inc. and Puget Sound Energy, Inc. (the “Companies”) on Form 10-K for the year ended December 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-K”), I, Kimberly J. Harris, the President and Chief Executive Officer of the Companies, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Companies.

Date:	March 1, 2018
/s/ Kimberly J. Harris
Kimberly J. Harris
President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Puget Energy, Inc. and Puget Sound Energy, Inc. (the “Companies”) on Form 10-K for the year ended December 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-K”), I, Daniel A. Doyle, Senior Vice President and Chief Financial Officer of the Companies, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Companies.

Date:	March 1, 2018
/s/ Daniel A. Doyle
Daniel A. Doyle
Senior Vice President and Chief Financial Officer

XML

Document And Entity Information	12 Months Ended
	Dec. 31, 2017 shares	Jun. 30, 2016 USD ($)
Entity Information [Line Items]
EBITDA to Interest Expense Denominator	1.0
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio at Period End	1.0
Entity Registrant Name	PUGET ENERGY INC /WA
Entity Central Index Key	0001085392
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float | $		$ 0
Entity Common Stock, Shares Outstanding | shares	200
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Subsidiaries [Member]
Entity Information [Line Items]
EBITDA to Interest Expense Denominator	1.0
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio at Period End	1.0
Entity Registrant Name	PUGET SOUND ENERGY INC
Entity Central Index Key	0000081100
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float | $		$ 0
Entity Common Stock, Shares Outstanding | shares	85,903,791
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating revenue:
Electric	$ 2,420,663	$ 2,238,492	$ 2,128,468
Natural gas	997,759	890,510	947,549
Other	41,854	35,299	16,683
Total operating revenue	3,460,276	3,164,301	3,092,700
Energy costs:
Purchased electricity	590,030	531,596	499,522
Electric generation fuel	206,275	215,331	249,907
Residential exchange	(75,933)	(69,824)	(112,473)
Purchased natural gas	360,009	313,954	403,310
Unrealized (gain) loss on derivative instruments, net	30,790	(83,795)	(13,233)
Utility operations and maintenance	584,263	568,492	530,720
Non-utility expense and other	40,487	27,151	10,818
Depreciation and amortization	481,969	439,579	420,807
Conservation amortization	121,216	107,784	110,866
Taxes other than income taxes	360,673	328,649	320,531
Total operating expenses	2,699,779	2,378,917	2,420,775
Operating income (loss)	760,497	785,384	671,925
Other income (deductions):
Other income	27,892	25,539	20,711
Other expense	(14,104)	(10,923)	(6,764)
Non-hedged interest rate swap expense	28	(1,062)	(3,796)
Interest charges:
AFUDC	10,826	9,304	7,575
Interest expense	(354,802)	(355,139)	(356,696)
Income (loss) before income taxes	430,337	453,103	332,955
Income tax (benefit) expense	255,143	140,204	91,776
Net income (loss)	175,194	312,899	241,179
Subsidiaries [Member]
Operating revenue:
Electric	2,420,663	2,238,492	2,128,468
Natural gas	997,759	890,510	947,549
Other	41,854	35,616	17,241
Total operating revenue	3,460,276	3,164,618	3,093,258
Energy costs:
Purchased electricity	590,030	531,596	499,522
Electric generation fuel	206,275	215,331	249,907
Residential exchange	(75,933)	(69,824)	(112,473)
Purchased natural gas	360,009	313,954	403,310
Unrealized (gain) loss on derivative instruments, net	30,790	(83,795)	(12,688)
Utility operations and maintenance	584,263	568,492	530,720
Non-utility expense and other	52,389	37,859	26,618
Depreciation and amortization	481,955	439,579	420,807
Conservation amortization	121,216	107,784	110,866
Taxes other than income taxes	360,673	328,649	320,531
Total operating expenses	2,711,667	2,389,625	2,437,120
Operating income (loss)	748,609	774,993	656,138
Other income (deductions):
Other income	26,853	25,537	20,711
Other expense	(14,104)	(10,923)	(6,764)
Interest charges:
AFUDC	10,826	9,304	7,575
Interest expense	(240,144)	(242,983)	(247,571)
Income (loss) before income taxes	532,040	555,928	430,089
Income tax (benefit) expense	211,986	175,347	125,900
Net income (loss)	$ 320,054	$ 380,581	$ 304,189

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Parent [Line Items]
Net income (loss)	$ 175,194	$ 312,899	$ 241,179
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	9,430	(6,446)	9,444
Reclassification of net unrealized loss on energy derivative instruments settled during the period, net of tax	0	0	333
Other comprehensive income (loss)	9,430	(6,446)	9,777
Comprehensive income (loss)	184,624	306,453	250,956
Subsidiaries [Member]
Parent [Line Items]
Net income (loss)	320,054	380,581	304,189
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	18,288	3,722	20,404
Reclassification of net unrealized loss on energy derivative instruments settled during the period, net of tax	0	0	686
Amortization of treasury interest rate swaps to earnings, net of tax	317	317	317
Other comprehensive income (loss)	18,605	4,039	21,407
Comprehensive income (loss)	$ 338,659	$ 384,620	$ 325,596

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, tax	$ 5,078	$ (3,471)	$ 5,087
Reclassification of net unrealized loss on energy derivative instruments during the period, tax	0	0	179
Subsidiaries [Member]
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, tax	9,848	2,004	10,987
Reclassification of net unrealized loss on energy derivative instruments during the period, tax	0	0	369
Amortization of treasury interest rate swaps to earnings, tax	$ 171	$ 171	$ 171

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Utility Plant [Abstract]
Electric plant	$ 8,135,847	$ 7,673,772
Natural gas plant	3,307,545	3,051,586
Common plant	811,815	594,994
Less: Accumulated depreciation and amortization	(2,428,524)	(2,161,796)
Net utility plant	9,826,683	9,158,556
Other property and investments:
Goodwill	1,656,513	1,656,513
Other property and investments	182,355	106,418
Total other property and investments	1,838,868	1,762,931
Current assets:
Cash and cash equivalents	26,616	28,878
Restricted cash	10,145	12,418
Accounts receivable, net of allowance for doubtful accounts	341,110	329,375
Unbilled revenue	222,186	234,053
Purchased gas adjustment receivable	0	2,785
Materials and supplies, at average cost	107,003	106,378
Fuel and natural gas inventory, at average cost	49,908	58,181
Unrealized gain on derivative instruments	22,247	54,341
Prepaid expense and other	21,996	43,046
Power contract acquisition adjustment gain	12,207	33,413
Total current assets	813,418	902,868
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	0	72,038
Power cost adjustment mechanism	4,576	4,531
Regulatory assets related to power contracts	19,454	22,613
Other regulatory assets	948,532	1,034,348
Unrealized gain on derivative instruments	2,158	8,738
Power contract acquisition adjustment gain	162,711	241,648
Other	74,389	58,109
Total other long-term and regulatory assets	1,211,820	1,442,025
Total assets	13,690,789	13,266,380
Common shareholder’s equity:
Common stock	0	0
Additional paid-in capital	3,308,957	3,308,957
Retained earnings	465,355	413,468
Accumulated other comprehensive income (loss), net of tax	(24,282)	(33,712)
Total common shareholder’s equity	3,750,030	3,688,713
Long-term debt:
First mortgage bonds and senior notes	3,164,412	3,362,000
Pollution control bonds	161,860	161,860
Junior subordinated notes	250,000	250,000
Long-term debt	1,902,600	1,812,480
Debt discount, issuance costs and other	(220,943)	(234,679)
Total long-term debt	5,257,929	5,351,661
Total capitalization	9,007,959	9,040,374
Current liabilities:
Accounts payable	359,586	317,043
Short-term debt	329,463	245,763
Current maturities of long-term debt	200,000	2,412
Purchased gas adjustment payable	16,051	0
Accrued expenses:
Taxes	117,948	111,428
Salaries and wages	53,220	49,749
Interest	73,564	73,610
Unrealized loss on derivative instruments	64,859	44,310
Power Contract Acquisition Adjustment Loss Current	2,762	3,159
Other	80,206	71,996
Total current liabilities	1,297,659	919,470
Other Long-term and regulatory liabilities:
Deferred income taxes	746,868	1,570,931
Unrealized loss on derivative instruments	21,235	16,261
Regulatory liabilities	731,587	654,622
Deferred Tax Liabilities, Regulatory Assets and Liabilities	1,011,626	0
Regulatory Liabilities Related To Power Contracts	174,918	275,061
Power Contract Acquisition Adjustment Loss Non Current	16,693	19,454
Other deferred credits	682,244	770,207
Total other long-term and regulatory liabilities	3,385,171	3,306,536
Commitments and contingencies (Note 15)
Total capitalization and liabilities	13,690,789	13,266,380
Subsidiaries [Member]
Utility Plant [Abstract]
Electric plant	10,232,771	9,813,169
Natural gas plant	3,882,733	3,640,271
Common plant	843,145	632,718
Less: Accumulated depreciation and amortization	(5,131,966)	(4,927,602)
Net utility plant	9,826,683	9,158,556
Other property and investments:
Other property and investments	76,350	77,960
Total other property and investments	76,350	77,960
Current assets:
Cash and cash equivalents	25,864	28,481
Restricted cash	10,145	12,418
Accounts receivable, net of allowance for doubtful accounts	343,546	344,964
Unbilled revenue	222,186	234,053
Purchased gas adjustment receivable	0	2,785
Materials and supplies, at average cost	107,003	106,378
Fuel and natural gas inventory, at average cost	48,585	56,851
Unrealized gain on derivative instruments	22,247	54,341
Prepaid expense and other	21,996	43,046
Total current assets	801,572	883,317
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	0	71,517
Power cost adjustment mechanism	4,576	4,531
Other regulatory assets	948,540	1,034,352
Unrealized gain on derivative instruments	2,158	8,738
Other	71,827	58,109
Total other long-term and regulatory assets	1,027,101	1,177,247
Total assets	11,731,706	11,297,080
Common shareholder’s equity:
Common stock	859	859
Additional paid-in capital	3,275,105	3,275,105
Retained earnings	452,066	359,795
Accumulated other comprehensive income (loss), net of tax	(126,906)	(145,511)
Total common shareholder’s equity	3,601,124	3,490,248
Long-term debt:
First mortgage bonds and senior notes	3,164,412	3,362,000
Pollution control bonds	161,860	161,860
Junior subordinated notes	250,000	250,000
Debt discount, issuance costs and other	(26,361)	(28,974)
Total long-term debt	3,549,911	3,744,886
Total capitalization	7,151,035	7,235,134
Current liabilities:
Accounts payable	359,585	317,043
Short-term debt	329,463	245,763
Current maturities of long-term debt	200,000	2,412
Purchased gas adjustment payable	16,051	0
Accrued expenses:
Taxes	117,063	111,428
Salaries and wages	53,220	49,749
Interest	47,837	48,087
Unrealized loss on derivative instruments	64,859	44,170
Other	80,206	71,996
Total current liabilities	1,268,284	890,648
Other Long-term and regulatory liabilities:
Deferred income taxes	869,473	1,732,390
Unrealized loss on derivative instruments	21,235	16,261
Regulatory liabilities	730,273	653,296
Deferred Tax Liabilities, Regulatory Assets and Liabilities	1,012,260	0
Other deferred credits	679,146	769,351
Total other long-term and regulatory liabilities	3,312,387	3,171,298
Commitments and contingencies (Note 15)
Total capitalization and liabilities	$ 11,731,706	$ 11,297,080

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Assets:
Construction work in progress	$ 495,937	$ 420,278
Current assets:
Allowance for doubtful accounts	$ 8,901	$ 9,798
Common shareholder’s equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	1,000	1,000
Common stock, shares outstanding (in shares)	200	200
Subsidiaries [Member]
Assets:
Construction work in progress	$ 495,937	$ 420,278
Current assets:
Allowance for doubtful accounts	$ 8,901	$ 9,798
Common shareholder’s equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	150,000,000	150,000,000
Common stock, shares outstanding (in shares)	85,903,791	85,903,791

XML

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Subsidiaries [Member]	Subsidiaries [Member] Common Stock	Subsidiaries [Member] Additional Paid-in Capital	Subsidiaries [Member] Retained Earnings	Subsidiaries [Member] Accumulated Other Comprehensive Income (Loss)	Subsidiaries [Member] Financial Support, Capital Contributions [Member]
Balance at Dec. 31, 2014	$ 3,543,328		$ 3,308,957	$ 271,414	$ (37,043)	$ 3,278,729	$ 859	$ 3,246,205	$ 202,622	$ (170,957)
Balance (in shares) at Dec. 31, 2014		200					85,903,791
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	241,179			241,179		304,189			304,189
Common stock dividend paid	(263,059)			(263,059)		(270,233)			(270,233)
Proceeds from Contributed Capital						(28,900)					$ 28,900
Other comprehensive income (loss)	9,777				9,777	21,407				21,407
Balance at Dec. 31, 2015	3,531,225		3,308,957	249,534	(27,266)	3,362,992	$ 859	3,275,105	236,578	(149,550)
Balance (in shares) at Dec. 31, 2015		200.0					85,903,791
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	312,899			312,899		380,581			380,581
Common stock dividend paid	(148,965)			(148,965)		(257,364)			(257,364)
Other comprehensive income (loss)	(6,446)				(6,446)	4,039				4,039
Balance at Dec. 31, 2016	$ 3,688,713		3,308,957	413,468	(33,712)	$ 3,490,248	$ 859	3,275,105	359,795	(145,511)
Balance (in shares) at Dec. 31, 2016	200	200.0				85,903,791	85,903,791
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 175,194			175,194		$ 320,054			320,054
Common stock dividend paid	(123,307)			(123,307)		(227,783)			(227,783)
Other comprehensive income (loss)	9,430				9,430	18,605				18,605
Balance at Dec. 31, 2017	$ 3,750,030		$ 3,308,957	$ 465,355	$ (24,282)	$ 3,601,124	$ 859	$ 3,275,105	$ 452,066	$ (126,906)
Balance (in shares) at Dec. 31, 2017	200	200.0				85,903,791	85,903,791

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating activities:
Net income (loss)	$ 175,194	$ 312,899	$ 241,179
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	481,969	439,579	420,807
Conservation amortization	121,216	107,784	110,866
Deferred income taxes and tax credits, net	254,524	139,640	91,978
Net unrealized (gain) loss on derivative instruments	30,650	(88,704)	(17,255)
Derivative contracts classified as financing activities due to merger	0	0	8,045
AFUDC - equity	(15,027)	(12,576)	(9,325)
Production tax credits	(53,331)	0	0
Other non-cash	17,568	16,812	16,155
Funding of pension liability	(18,000)	(24,000)	(18,000)
Regulatory assets and liabilities	(88,875)	(153,643)	(156,491)
Other long-term assets and liabilities	(27,411)	16,435	21,729
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	132	(21,763)	(66,703)
Materials and supplies	(625)	(28,134)	4,945
Fuel and natural gas inventory	8,266	473	9,332
Prepayments and other	21,050	(25,927)	4,086
Purchased gas adjustment	18,836	(15,374)	33,662
Accounts payable	26,396	32,465	(48,037)
Taxes payable	6,520	(3,426)	7,072
Other	13,079	36,750	(5,323)
Net cash provided by (used in) operating activities	972,131	729,290	648,722
Investing activities:
Construction expenditures - excluding equity AFUDC	(1,040,135)	(706,444)	(587,225)
Restricted cash	2,273	(4,469)	24,914
Other	(195)	(1,921)	754
Net cash provided by (used in) investing activities	(1,038,057)	(712,834)	(561,557)
Financing activities:
Change in short-term debt, net	83,700	86,759	74,004
Dividends paid	(123,307)	(148,965)	(263,059)
Proceeds from long-term debt and bonds issued	90,120	12,481	825,000
Redemption of bonds and notes	0	0	(711,000)
Derivative contracts classified as financing activities due to merger	0	0	(8,045)
Other	13,151	19,653	902
Net cash provided by (used in) financing activities	63,664	(30,072)	(82,198)
Net increase (decrease) in cash and cash equivalents	(2,262)	(13,616)	4,967
Cash and cash equivalents at beginning of period	28,878	42,494	37,527
Cash and cash equivalents at end of period	26,616	28,878	42,494
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	326,798	329,603	339,866
Cash payments (refunds) for income taxes	1,649	0	2
Accounts payable for capital expenditures eliminated from cash flows	92,959	76,813	51,588
Reclassification of Colstrip from utility plant to a regulatory asset	(49,177)	176,804	0
Reclassification of hydro treasury grants to a regulatory liability	95,935	0	0
Subsidiaries [Member]
Operating activities:
Net income (loss)	320,054	380,581	304,189
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	481,955	439,579	420,807
Conservation amortization	121,216	107,784	110,866
Deferred income taxes and tax credits, net	210,842	174,776	125,900
Net unrealized (gain) loss on derivative instruments	30,790	(83,795)	(12,688)
AFUDC - equity	(15,027)	(12,576)	(9,325)
Production tax credits	(53,331)	0	0
Other non-cash	6,445	5,672	5,512
Funding of pension liability	(18,000)	(24,000)	(18,000)
Regulatory assets and liabilities	(88,875)	(152,786)	(156,491)
Other long-term assets and liabilities	(14,547)	30,235	36,481
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	13,285	(37,385)	(66,547)
Materials and supplies	(625)	(28,134)	4,945
Fuel and natural gas inventory	8,266	473	9,332
Prepayments and other	21,050	(25,927)	4,089
Purchased gas adjustment	18,836	(15,374)	33,662
Accounts payable	26,396	32,465	(48,031)
Taxes payable	5,635	(3,426)	7,072
Other	12,438	30,754	(12,992)
Net cash provided by (used in) operating activities	1,086,803	818,916	738,781
Investing activities:
Construction expenditures - excluding equity AFUDC	(963,652)	(681,112)	(587,225)
Restricted cash	2,273	(4,469)	24,914
Other	241	4,156	6,386
Net cash provided by (used in) investing activities	(961,138)	(681,425)	(555,925)
Financing activities:
Change in short-term debt, net	83,700	86,759	74,004
Dividends paid	(227,783)	(257,364)	(270,233)
Loan from (payment to) parent	0	0	(28,933)
Investment from parent	0	0	28,900
Proceeds from long-term debt and bonds issued	0	0	425,000
Redemption of bonds and notes	0	0	(412,000)
Other	15,801	19,739	4,796
Net cash provided by (used in) financing activities	(128,282)	(150,866)	(178,466)
Net increase (decrease) in cash and cash equivalents	(2,617)	(13,375)	4,390
Cash and cash equivalents at beginning of period	28,481	41,856	37,466
Cash and cash equivalents at end of period	25,864	28,481	41,856
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	224,423	227,668	242,774
Cash payments (refunds) for income taxes	3,058	0	2
Accounts payable for capital expenditures eliminated from cash flows	92,959	76,813	51,588
Reclassification of Colstrip from utility plant to a regulatory asset	(49,177)	176,804	0
Reclassification of hydro treasury grants to a regulatory liability	$ 95,935	$ 0	$ 0

XML

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

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.  Puget Energy also has a wholly-owned non-regulated subsidiary, named Puget LNG, LLC (Puget LNG), formed in 2016, which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNG facility, currently under construction. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that occur under PSE and are allocated to Puget LNG are related party transactions by nature. As of December 31, 2017, Puget LNG has incurred $104.3 million in construction work in progress and operating costs related to Puget LNG’s portion of the Tacoma LNG facility.

The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries.  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 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.

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 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.

Other Property and Investments

For PSE, the costs of other property and investments (i.e., non-utility) 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.  Replacements 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

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 annual depreciation provision stated as a percent of a depreciable electric utility plant was 2.8%, for each of 2017, 2016 and 2015; depreciable natural gas utility plant was 3.4%, for each of 2017, 2016 and 2015; and depreciable common utility plant was 8.3%, 9.7% and 8.5% in 2017, 2016 and 2015, respectively.  The cost of removal is collected from PSE’s customers through depreciation expense and any excess is recorded as a regulatory liability.

Goodwill

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

The goodwill recorded by Puget Energy represents the potential long-term return to the Company’s investors.  Goodwill is tested for impairment annually using a qualitative and quantitative test.  Management must first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill. If, after assessing the totality of events or circumstances during a qualitative assessment, management determines the fair value of a reporting unit is less than its carrying amount, then the entity shall perform a quantitative test to determine impairment.  This would entail a full valuation of Puget Energy’s assets and liabilities and comparing the valuation to its carrying amounts, with the aggregate difference indicating the amount of impairment.  Goodwill of a reporting unit is required to be tested for impairment on an interim basis if an event occurs or circumstances change that would cause the fair value of a reporting unit to fall below its carrying amount.

Puget Energy conducted its annual impairment test in 2017 using an October 1, 2017 measurement date.  The fair value of Puget Energy’s reporting unit was estimated using a combination of the discounted cash flow and market approach.  The discounted cash flow approach 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, 2017.  There were no known events or circumstances from the date of the assessment through December 31, 2017 that would impact management’s conclusion.

Tacoma LNG Facility

The Tacoma LNG facility is intended to provide peak-shaving services to PSE’s natural gas customers. By storing surplus natural gas, PSE is able to meet the requirements of peak consumption later during different seasons. LNG will also provide fuel to transportation customers, particularly in the marine market. On January 24, 2018, the Puget Sound Clean Air Agency’s determined a Supplemental Environmental Impact Statement is necessary in order to rule on the air quality permit for the facility. As a result of requiring a Supplemental Environmental Impact Statement, the Company's construction schedule may be impacted depending on the Puget Sound Clean Air Agency's timing and decision on the air quality permit. If delayed, the construction schedule and costs may be adversely impacted. Pursuant to the Washington Commission’s order, PSE will be allocated approximately 43.0% of common capital and operating costs, consistent with the regulated portion of Tacoma LNG facility. The remaining 57.0% of common capital and operating costs of the Tacoma LNG facility will be allocated to Puget LNG.

For Puget Energy, $104.0 million in construction work in progress related to Puget LNG’s portion of the Tacoma LNG facility is reported in the “Other property and investments” financial statement line item. For PSE, construction work in progress of $87.2 million related to PSE’s portion of the Tacoma LNG facility is reported in the “Utility plant - Natural gas plant” line item, as PSE is a regulated entity.

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 carrying amounts of cash and cash equivalents are reported at cost and approximate fair value, due to the short-term maturity.

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.  The Company records 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.  The Company records these items at the lower of cost or net realizable value 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 or losses 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.  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 when amortization periods extend longer than one year.  For further details regarding regulatory assets and liabilities, see Note 3, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.

Puget Energy recorded regulatory assets and liabilities at the time of the merger related to power purchase contracts.

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; the AFUDC debt portion is credited to interest expense, while the AFUDC equity portion is credited to other income.  Cash inflow related to AFUDC does not occur until these charges are reflected in rates. The current AFUDC rate authorized by the Washington Commission for natural gas and electric utility plant additions through December 18, 2017 was 7.77%. Effective December 19, 2017 with the Washington Commission order, the new AFUDC rate authorized is 7.60%.

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).  Revenue from retail sales is billed based on tariff rates approved by the Washington Commission.  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 tariff rate schedule to estimate the unbilled revenues by customer.

PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $257.1 million, $235.3 million and $234.2 million for 2017, 2016 and 2015, 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.

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 and gross margin erosion due to weather and 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. Revenue is recognized under this program when deemed collectible 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. On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. The rate test which limits the amount of revenues PSE can collect in its annual filings increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The Company will not record any decoupling revenue that is expected to take longer than 24 months to collect following the end of the annual period in which the revenues would have otherwise been recognized. Once determined to be collectible within 24 months, any previously non-recognized amounts will be recognized. 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 balance for allowance for doubtful accounts at December 31, 2017 and 2016 was $8.9 million and $9.8 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.  Under the December 5, 2017 Washington Commission order regarding PSE’s GRC, the cumulative annual cost threshold for deferral of storms under the mechanism increased from $8.0 million to $10.0 million effective January 1, 2018.  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, which 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.

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 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 during the first ten years of operation. From a regulatory perspective, the tax savings from these credits were intended to be refunded by PSE to its customers when monetized on the income tax return through its revenue requirement as initially approved by the Washington Commission. As the Company has not generated taxable income and these credits have not been monetized, they have not been refunded to customers. Amounts to be refunded have been recorded as a liability with an offsetting reduction to revenue as it was intended to be refunded through the revenue requirement. A deferred tax asset and reduction to deferred tax expense was also recorded for PTCs not yet monetized. These entries resulted in no net income impact. In connection with the GRC settlement in 2017, the Washington Commission authorized the Company to utilize the tax savings associated with the monetization of the PTCs to fund the following: (i) Colstrip Community Transition Fund, (ii) unrecovered Colstrip plant and (iii) incurred decommissioning and remediation costs for Colstrip. As PTCs will no longer be refunded to customers through the revenue requirement, a non-cash charge to revenue and deferred tax expense will be recorded as the PTCs are monetized. These entries will result in no net income impact. At December 31, 2017 $2.1 million of PTCs are estimated to be monetized through tax filings.

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 natural gas related derivatives 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 its financial reporting.  The contracts that were de-designated related to physical electric supply contracts and natural gas swap contracts used to fix the price of natural gas for electric generation.  For these contracts and for contracts initiated after such date, all mark-to-market adjustments are recognized through earnings.  The amount previously recorded in accumulated other comprehensive income (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, 2017, 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" to the consolidated financial statements included in Item 8 of this report.

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" to the consolidated financial statements included in Item 8 of this report.

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 and presented net of long-term liabilities on the balance sheet.

XML

New Accounting Pronouncements

12 Months Ended

Dec. 31, 2017

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Pronouncements

New Accounting Pronouncements

Revenue Recognition

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

The standard is effective for the Company beginning January 1, 2018 and allows for two methods of adoption: application of the standard to each prior reporting period presented (full retrospective), or application of a cumulative effect on retained earnings recognized at the date of initial application (modified retrospective method). The Company will adopt the standard using the modified retrospective method. In preparation for adoption of the standard, the Company initiated a project team that met bi-weekly to make key accounting assessments related to the standard, which included the implementation of associated internal controls.

As a result of implementation of this standard, the Company has concluded there to be no impact on revenue for contracts with customers open as of January 1, 2018. The Company's revenue is 93.6% comprised of contracts with customers from rate-regulated sales of electricity and natural gas to retail customers where revenue will continue to be recognized over time as delivered. Pursuant to the new standard, the Company's current presentation of revenue on the income statement will not change; however, enhanced disclosure for revenue from contracts with customers and revenue outside the scope of ASC 606 will be disclosed.

Lease Accounting

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)". The FASB issued this ASU and the related amendments to increase transparency and comparability among organizations by recognizing right-of-use (ROU) lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. To meet that objective, the FASB is amending the FASB Accounting Standards Codification and creating Topic 842, Leases. ASU 2016-02requires lessees to recognize the following for all leases (with the exception of short-term leases) at the commencement date: (i) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The income statement recognition is similar to existing lease accounting and is based on lease classification. Under the new guidance, lessor accounting is largely unchanged.

This amendment is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Earlier adoption is permitted for all entities upon issuance. Reporting entities must apply a modified retrospective approach for the adoption of the new standard.  The Company will adopt ASU 2016-02 during the first quarter of fiscal year 2019. The Company expects the adoption of the standard will result in recognition of right-of-use assets and liabilities that have not previously been recorded, which will have a material impact on the consolidated balance sheets. For a current breakout of existing operating and capital leases, see Note 8, "Leases" to the consolidated financial statements included in Item 8 of this report.

Statement of Cash Flows

In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments". The amendments in ASU 2016-15 provide guidance for eight specific cash flow issues that include (i) debt prepayment or debt extinguishment costs, (ii) settlement of zero-coupon debt instruments, (iii) contingent consideration payments made after a business combination, (iv) proceeds from the settlement of insurance claims, (v) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, (vi) distribution received from equity method investees, (vii) beneficial interest in securitization transactions, and (viii) separately identifiable cash flows and application of the predominance principle.

This update is effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted for all entities upon issuance. The amendments in this update should be applied using a retrospective transition method to each period presented. The Company will adopt ASU 2016-15 during the first quarter of fiscal year 2018 and is in the process of evaluating the impact this standard will have on its consolidated statement of cash flows.

In November 2016, the FASB issued ASU 2016-18, "Statement of Cash Flows (Topic 230): Restricted Cash". The amendments in this update require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. The new standard is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company will adopt ASU 2016-18 during the first quarter of fiscal year 2018 retrospectively to all periods presented by moving the presentation of restricted cash, in the statement of cash flows, to net cash flows of total cash, cash equivalents, and restricted cash. Additionally, the Company will disclose the nature of the Company's restricted cash.

Retirement Benefits

In March 2017, the FASB issued ASU 2017-07, "Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost". The amendments require that an employer report the service cost component in the same line items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The line item used in the income statement to present the other components of net benefit cost must be disclosed. Additionally, the service cost component of net benefit cost is the only eligible cost for capitalization.

This amendment is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. Early adoption is permitted as of the beginning of an annual period for which financial statements (interim or annual) have not been issued or made available for issuance. The Company will adopt ASU 2017-07 during the first quarter of fiscal year 2018 by applying the amendments related to income statement activity retrospectively, and balance sheet activity prospectively. The Company’s non-service components for the year ended December 31, 2017, was a credit of $18.4 million for Puget Energy and $4.7 million for PSE.  The non-service cost components are in an income position and will be presented in the other income section, upon adoption.

Stranded Tax Effects in AOCI

In February 2018, the FASB issued ASU 2018-02, "Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income". The amendments in this update allow reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act (TCJA) and will improve the usefulness of information reported to financial statement users.

This amendment is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. Early adoption is permitted, including adoption in any interim period for reporting periods for which financial statements have not yet been issued. The Company will early adopt ASU 2018-02 during the first quarter of fiscal year 2018 through a retrospective reclassification from accumulated other comprehensive income to retained earnings. The Company is still evaluating the impact of the reclassification to retained earnings.

XML

Regulation and Rates

12 Months Ended

Dec. 31, 2017

Regulated Operations [Abstract]

Regulation and Rates

(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.  

The net regulatory assets and liabilities at December 31, 2017 and 2016 included the following:

Puget Sound Energy	Remaining Amortization Period	December 31,
(Dollars in Thousands)		2017					2016
Storm damage costs electric	4 to 6 years			128,508					122,709
Colstrip 1 & 2 Regulatory Asset	N/A			127,627					176,804
Decoupling deferrals and interest		98,769					156,408
Decoupling 24-month revenue reserve		—					(20,847	)
Total decoupling asset	Less than 2 years			98,769					135,561
Chelan PUD contract initiation	13.8 years			98,052					105,140
Environmental remediation	(a)			81,550					74,557
Lower Snake River	19.4 years			70,975					74,862
Baker Dam licensing operating and maintenance costs	N/A			54,817					61,453
Deferred Washington Commission AFUDC	10 years			50,301					51,404
Unamortized loss on reacquired debt	1 to 28 years			39,674					42,196
Property tax tracker	Less than 2 years			36,517					41,949
Energy conservation costs	(a)			35,538					41,027
PGA deferral of unrealized losses on derivative instruments	N/A			26,030					—
White River relicensing and other costs	3 years			19,502					21,627
Generation plant major maintenance, excluding Colstrip	5 to 11 years			17,216					13,178
Mint Farm ownership and operating costs	7.3 years			14,319					16,319
Colstrip major maintenance	1.5 years			8,723					6,589
Snoqualmie licensing operating and maintenance costs	N/A			7,341					8,018
Ferndale	1.8 years			7,295					11,274
Colstrip common property	7.4 years			4,618					5,334
PCA mechanism	N/A			4,576					4,531
Electron unrecovered loss	1 year			3,786					7,178
Deferred income taxes(d)	N/A			—					71,517
PGA receivable	1 year			—					2,785
Various other regulatory assets	(a)			17,382					17,173
Total PSE regulatory assets				953,116					1,113,185
Deferred income taxes(d)	N/A			(1,012,260		)			—
Cost of removal	(b)			(389,579		)			(369,300		)
Treasury grants	20 years			(205,775		)			(133,709		)
Production tax credits	(c)			(93,616		)			(93,616		)
Decoupling ROR excess earnings		(18,400	)				(13,300	)
Decoupling deferrals and interest		(7,896	)				(16,448	)
Total decoupling liability	Less than 2 years			(26,296		)			(29,748		)
PGA payable	1 year			(16,051		)			—
Summit purchase option buy-out	2.8 years			(4,463		)			(6,038		)
PGA deferral of unrealized gains on derivative instruments	N/A			—					(7,517		)
Various other regulatory liabilities	(a)			(10,544		)			(13,368		)
Total PSE regulatory liabilities				(1,758,584		)			(653,296		)
PSE net regulatory assets (liabilities)				$	(805,468	)			$	459,889

_______________

^(a)  Amortization periods vary depending on timing of underlying transactions.

^(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.

^(d)  For additional information, see Note 13,"Income Taxes" to the consolidated financial statements included in Item 8 of this report.

Puget Energy	Remaining Amortization Period	December 31,
(Dollars in Thousands)		2017			2016
Total PSE regulatory assets	(a)	$	953,116		$	1,113,185
Puget Energy acquisition adjustments:
Regulatory assets related to power contracts	1 to 20 years	19,454			22,613
Various other regulatory assets	Varies	(8		)	517
Total Puget Energy regulatory assets		972,562			1,136,315
Total PSE regulatory liabilities	(a)	(1,758,584		)	(653,296		)
Puget Energy acquisition adjustments:
Deferred income taxes		634			—
Regulatory liabilities related to power contracts	1 to 35 years	(174,918		)	(275,061		)
Various other regulatory liabilities	Varies	(1,314		)	(1,326		)
Total Puget Energy regulatory liabilities		(1,934,182		)	(929,683		)
Puget Energy net regulatory asset (liabilities)		$	(961,620	)	$	206,632

_______________

^(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 $389.6 million and $369.3 million in 2017 and 2016, respectively, for the cost of removal of utility plant.  These amounts are collected from PSE’s customers through depreciation rates.

General Rate Case Filing

On January 13, 2017, PSE filed its GRC with the Washington Commission, which proposed a weighted cost of capital of 7.74%, or 6.69% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.8%. The requested combined electric tariff changes would result in a net increase of $86.3 million or 4.1%, annually. The requested combined natural gas tariff changes would result in a net decrease of $22.3 million, or 2.4%, annually. Additionally, a depreciation study which calculates annual depreciation accruals related to utility plant was filed as part of the GRC filing. The tariffs were subsequently suspended, which means that the final rates authorized in the proceeding would go into effect on or shortly after the suspension date of December 13, 2017. PSE filed a supplemental filing in the GRC on April 3, 2017, which among other things provided updates to power costs. The requested combined electric tariff changes based on the updated supplemental filing would result in a net increase of $67.9 million, or 3.2%, annually. The requested combined natural gas tariff changes based on the updated supplemental filing would result in a net decrease of $29.3 million, or 3.2%, annually.

PSE’s GRC filing included the required plan for Colstrip Units 1 and 2 closures, see Note 14, "Litigation" to the consolidated financial statements included in Item 8 of this report. The filing also requested that electric energy supply fixed costs be included in PSE’s decoupling mechanism. Additionally, PSE’s filing contained requests for two new mechanisms to address regulatory lag. PSE requested procedures for an ERF that can be used to update PSE’s delivery revenues on an expedited basis following a GRC proceeding. PSE also requested approval to establish an electric cost recovery mechanism (CRM), similar to its existing natural gas CRM, which would allow PSE to obtain accelerated cost recovery on specified electric reliability projects.

On September 15, 2017, ten of the eleven parties to the proceeding, including PSE, filed a multi-party settlement agreement with the Washington Commission. The multi-party settlement resolved some, but not all, contested issues in the case. Hearings were held on August 30, 2017 regarding the contested issues and on September 29, 2017 regarding the multi-party settlement. The settlement agreement was accepted by the Washington Commission on December 5, 2017 and the rates became effective December 19, 2017. The settlement agreement resolved all but four of the contested issues between the settling parties. The settlement agreement provides for a weighted cost of capital of 7.60% or 6.55% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.5%. The settlement also resulted in a combined electric tariff change that resulted in a net increase of $20.2 million, or 0.9%, and a combined natural gas tariff change that resulted in a net decrease of $35.5 million, or 3.8%.

The expected closure date for Colstrip Units 1 and 2 is July 1, 2022 and the settlement included a plan to cover the costs for the closure of these Units. As part of the settlement PSE committed to fund a Colstrip Community Transition Fund of $10.0 million of which PSE shareholders will fund $5.0 million and $5.0 million will be funded by the regulatory liability for monetized PTCs, which are PTCs used on the filed tax returns. PSE is recognizing the funding of this commitment at the time the PTC’s are accrued for use in the tax return. The settlement provided that the regulatory liability for monetized PTCs will be used for the following Colstrip costs: (i) Colstrip Community Transition Fund, (ii) recover unrecovered Colstrip plant and (iii) recover incurred decommissioning and remediation costs for Colstrip. In addition, the hydro-related treasury grants were allowed to be used to fund and recover incurred decommissioning and remediation costs for Colstrip 1 and 2 as established in RCW 80.04.350. Depreciation rates were updated which increased PSE's depreciation for Colstrip Units 1 and 2. The increase in depreciation caused the Colstrip regulatory asset to be reduced to $127.6 million as of December 31, 2017. Finally, depreciation rates for Colstrip Units 3 and 4 were also updated, which increased PSE's depreciation to recover plant costs for those units based on a negotiated depreciation life ending on December 31, 2027.

The contested issues were PSE’s proposed electric CRM, the majority of decoupling issues, certain portions of electric rate spread/rate design issues and the entire natural gas rate spread/rate design-related issues. The Washington Commission also ruled on the remaining contested issues on December 5, 2017. The Washington Commission approved, PSE's proposal to modify its earning sharing mechanism to exclude normalizing adjustments that are required for Commission Basis Reporting purposes under Washington Administrative Code 480-90-257 (natural gas) and 480-100-257 (electric). The Washington Commission rejected PSE’s requested electric CRM.

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 assist in mitigating the impact of weather on operating revenue and net income. Since July 2013, 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 most residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues are recovered on a per customer basis regardless of actual consumption levels. PSE's 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 from, or refund to, customers the difference between allowed decoupling revenue and the corresponding actual revenue during the following May to April time period. During the rate plan, which ended in December 2017, the allowed decoupling revenue per customer for the recovery of delivery system costs increased by 3.0% for the electric customers and 2.2% for the natural gas customers on January 1.

On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues will continue to be recovered on a per customer basis and electric fixed production energy costs will now be decoupled and recovered on a fixed monthly amount basis. The allowed decoupling revenue will no longer increase annually on January 1 for electric and natural gas customers and these amounts can only be changed in a GRC, Power Cost Only Rate Case (PCORC) or ERF filing. Other changes include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the decoupling mechanism going forward. The rate test which limits the amount of revenues PSE can collect in its annual filings increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The decoupling mechanism will end on the effective date of PSE’s first rate case or other proceeding filed in or after 2021 unless the continuation of the mechanism is approved in either of those proceedings. PSE’s decoupling mechanism over and under collections will still be collectible or refundable after this effective date even if the decoupling mechanism is not extended.

There is a 3.0% cap for electric and 5.0% cap for natural gas on annual decoupling increases noted above and the size of decoupling deferral assets on the balance sheet, PSE performed an analysis as of December 31, 2017 to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980-605.  If not, for GAAP purposes only, PSE will need to record a reserve against the decoupling revenue and regulatory asset balance.  Once the revenue is forecasted to be collected within 24 months, the reserve can be reversed. The analysis indicated all current deferred revenues for electric and natural gas will be collected within 24 months of the annual period; therefore, there were no adjustments to 2017 decoupling revenues other than to record the previously unrecognized decoupling deferrals of $20.8 million.

Storm Damage Deferral Accounting

The Washington Commission issued a GRC order that defined deferrable storm events and provided that costs in excess of the annual cost threshold may be deferred for qualifying storm damage costs that meet the modified IEEE outage criteria for system average interruption duration index. In 2017 and 2016, PSE incurred $30.4 million and $22.0 million, respectively, in storm-related electric transmission and distribution system restoration costs, of which $21.6 million was deferred in 2017 and $12.4 million was deferred in 2016. Under the December 5, 2017 Washington Commission order regarding PSE’s GRC, the following changes to PSE’s storm deferral mechanism were approved: (i) the cumulative annual cost threshold for deferral of storms under the mechanism increased from $8.0 million to $10.0 million effective January 1, 2018; and (ii) qualifying events where the total qualifying cost is less than$0.5 million will not qualify for deferral and these costs will also not count toward the 10.0 million annual cost threshold.

Washington Commission Tax Deferral Filing

The TCJA was signed into law in December of 2017. As a result of this change, PSE reviewed its deferred tax balances under the new corporate tax rate.  As PSE is a regulated utility, the impact of tax rate changes on the deferred tax balance is subject to approval by the Washington Commission.   Accordingly, PSE filed an accounting petition on December 29, 2017 requesting deferred accounting treatment for the impacts of tax reform.   The deferral accounting treatment results in the tax rate change being captured in the deferred income tax balance with an offset to the regulatory liability for deferred income taxes.  The tax rate change for certain deferred tax balances that are not subject to regulatory treatment have been recorded through tax expense.

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.  In accordance with 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 $38.9 million for natural gas and $8.9 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, 2017, the Company’s share of future remediation costs is estimated to be approximately $28.6 million. The Company's deferred electric environmental costs are $17.6 million, $13.8 million and $14.0 million at December 31, 2017, 2016 and 2015, respectively, net of insurance proceeds. The Company's deferred natural gas environmental costs are $63.9 million, $60.7 million, and $52.9 million at December 31, 2017, 2016 and 2015, respectively, net of insurance proceeds. In the GRC which became effective December 19, 2017, the Company had its third party recoveries and remediation costs incurred as of September 30, 2016, net of a portion of insurance, approved for amortization and inclusion in rates.

XML

Dividend Payment Restrictions

12 Months Ended

Dec. 31, 2017

Dividend Payment Restrictions [Abstract]

Dividend Payment Restrictions

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, 2017, approximately $645.1 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 3.0 to 1.0.  The common equity ratio, calculated on a regulatory basis, was 48.0% at December 31, 2017, and the EBITDA to interest expense was 5.5 to 1.0 for the twelve months ended December 31, 2017.

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

Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission.  Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than 2.0 to 1.0.  Puget Energy's EBITDA to interest expense was 3.7 to 1.0 for the twelve months ended December 31, 2017.

At December 31, 2017, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

XML

Utility Plant

12 Months Ended

Dec. 31, 2017

Utility Plant [Abstract]

Utility Plant

Utility Plant

The following table presents electric, natural gas and common utility plant classified by account:

		Puget Energy						Puget Sound Energy
Utility Plant	Estimated Useful Life	At December 31,						At December 31,
(Dollars in Thousands)	(Years)	2017			2016			2017			2016
Distribution plant	20-65	$	5,670,351		$	5,287,542		$	7,289,998		$	6,922,176
Production plant	12-90	3,068,135			3,007,546			3,954,057			3,910,129
Transmission plant	43-75	1,361,495			1,307,687			1,471,337			1,420,334
General plant	5-75	586,226			541,424			628,179			611,237
Intangible plant (including capitalized software)	NA	447,568			347,697			438,185			338,327
Plant acquisition adjustment	NA	242,826			242,826			282,792			282,792
Underground storage	25-60	31,815			30,695			45,288			44,206
Liquefied natural gas storage	25-60	12,628			12,628			14,498			14,498
Plant held for future use	NA	53,428			52,484			53,580			52,636
Recoverable Cushion Gas	NA	8,655			8,655			8,655			8,655
Plant not classified	1-125	275,014			159,345			275,014			159,345
Grant	NA	—			(99,100		)	—			(99,100		)
Capital leases, net of accumulated amortization1	4-6	1,129			645			1,129			645
Less: accumulated provision for depreciation		(2,428,524		)	(2,161,796		)	(5,131,966		)	(4,927,602		)
Subtotal		$	9,330,746		$	8,738,278		$	9,330,746		$	8,738,278
Construction work in progress	NA	495,937			420,278			495,937			420,278
Net utility plant		$	9,826,683		$	9,158,556		$	9,826,683		$	9,158,556

_______________

¹  Accumulated amortization of capital leases at Puget Energy and PSE was $0.7 million in 2017 and $0.6 million in 2016.

Jointly owned generating plant service costs are included in utility plant service cost at the Company's ownership share.  The Company provides financing for its ownership interest in the jointly owned utility plants. The following tables indicate the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, 2017.  These amounts are also included in the Utility Plant table above. The Company's share of fuel costs and operating expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income.

Puget Energy
Jointly Owned Generating Plants (Dollars in Thousands)	Energy Source (Fuel)	Company’s Ownership Share	Plant in Service at Cost		Construction Work in Progress			Accumulated Depreciation
Colstrip Units 1 & 2	Coal	50.0%	$	246,510	$	(23	)	$	(38,170	)
Colstrip Units 3 & 4	Coal	25.0%	307,254		1,726			(71,061		)
Colstrip Units 1 – 4 Common Facilities	Coal	various	83		—			(31		)
Frederickson 1	Natural Gas	49.85%	61,783		—			(3,850		)
Jackson Prairie	Natural Gas Storage	33.34%	31,141		43			(6,325		)

Puget Sound Energy
Jointly Owned Generating Plants (Dollars in Thousands)	Energy Source (Fuel)	Company’s Ownership Share	Plant in Service at Cost		Construction Work in Progress			Accumulated Depreciation
Colstrip Units 1 & 2	Coal	50.0%	$	378,574	$	(23	)	$	(170,234	)
Colstrip Units 3 & 4	Coal	25.0%	571,604		1,726			(335,414		)
Colstrip Units 1 – 4 Common Facilities	Coal	various	252		—			(199		)
Frederickson 1	Natural Gas	49.85%	67,851		—			(9,917		)
Jackson Prairie	Natural Gas Storage	33.34%	45,288		43			(20,471		)
Tacoma LNG	LNG	43.0%	2,667		87,207			—

Asset Retirement Obligation

The Company has recorded liabilities for steam generation sites, combustion turbine generation sites, wind generation sites, distribution and transmission poles, natural gas mains, and leased facilities where disposal is governed by ASC 410 “Asset Retirement and Environmental Obligations" (ARO).

On April 17, 2015, the U.S. Environmental Protection Agency (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 ruling requires the Company to perform an extensive study on the effects of coal ash on the environment and public health. The 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.

The CCR rule and two new legal agreements which include a consent decree with the Sierra Club and a settlement agreement with the Sierra Club and the National Wildlife Federation in 2016 make significant changes to the Company’s Colstrip operations and those changes were reviewed by the Company and the plant operator in 2015 and 2016. PSE had previously recognized a legal obligation in 2003 under EPA rules to dispose of coal ash material at Colstrip. Due to the updated Colstrip information, additional disposal costs were added to the ARO.

On September 6, 2016, PSE entered into two new agreements requiring the Company to close the Colstrip 1 and 2 plants on or before July 1, 2022 and to incur additional monitoring costs, water treatment costs, forced evaporation cost, and post closure care costs for all Colstrip Units. As a result, in 2016 the Company adjusted the Colstrip ARO ending liability to increase by $45.7 million for Colstrip 1 and 2 and $37.0 million for Colstrip 3 and 4.

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.

For the twelve months ended December 31, 2017 the Company reviewed the estimated remediation costs at Colstrip and reduced the Colstrip ARO liability by $5.5 million for Colstrip Units 1 and 2 and $12.7 million for Colstrip Units 3 and 4. The Company also recorded the Colstrip relief of liability of $3.8 million. In addition, the Company recorded a new Tacoma LNG facility ARO liability of $2.7 million for PSE and $2.2 million for Puget LNG as of December 31, 2017.

 The following table describes the changes to the Company’s ARO for the year ended December 31, 2017:

Puget Energy and Puget Sound Energy	At December 31,
(Dollars in Thousands)	2017			2016
Asset retirement obligation at beginning of the period	$	200,345		$	85,028
New asset retirement obligation recognized in the period1	2,881			—
Liability adjustments	(3,841		)	(411		)
Revisions in estimated cash flows	(13,748		)	113,081
Accretion expense	5,539			2,647
Asset retirement obligation at end of period1	$	191,176		$	200,345

_______________

^{1  New asset retirement obligations include $2.2 million ARO for Puget LNG only held at Puget Energy.} 

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, 2017 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.

XML

Long-Term Debt

12 Months Ended

Dec. 31, 2017

Long-term Debt, Unclassified [Abstract]

Long-term Debt

Long-Term Debt

The following table presents outstanding long-term debt principal amounts and due dates as of 2017 and 2016:

(Dollars in Thousands)			At December 31,
Series	Type	Due	2017			2016
Puget Sound Energy:
6.740%	Senior Secured Note1	2018	$	200,000		$	200,000
5.500%	Promissory Note2	2020	2,412			2,412
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			425,000
4.700%	Senior Secured Note	2051	45,000			45,000
6.974%	Junior Subordinated Note	2067	250,000			250,000
*	Debt discount, issuance cost and other	*	(26,361		)	(28,974		)
Total PSE long-term debt			3,749,911			3,747,298
Puget Energy:
*	Fair value adjustment of PSE long-term debt	*	(190,895		)	(199,436		)
*	Revolving Credit Agreement	2022	102,600			12,480
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			400,000
*	Debt discount, issuance cost and other	*	(3,687		)	(6,269		)
Total Puget Energy long-term debt			$	5,457,929		$	5,354,073

_______________

* Not Applicable.

¹  6.74% Senior Secured Note in the amount of $200.0 million is classified on the Balance Sheet as a current maturity of long-term debt as of June 15, 2017.

²  5.50% Promissory Note (Puget Western Note Payable) in the amount of $2.4 million was classified on the Balance Sheet as a current maturity of long-term debt from January 1, 2017 to August 13, 2017, at which time the agreement was amended and extended until August 13, 2020. The Promissory Note is currently classified as long-term debt on the Balance sheet as of September 1, 2017.

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, 2017, 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 ("the existing shelf") under which it may issue, as of the date of this report, up to $800.0 million aggregate principal amount of senior notes secured by first mortgage bonds. The existing shelf will expire in November 2019.

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, 2017, the earnings available for interest exceeded the required 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)	2018		2019		2020		2021		2022		Thereafter		Total
Maturities of:
PSE	$	200,000	$	—	$	2,412	$	—	$	—	$	3,573,860	$	3,776,272
Puget Energy	—		—		450,000		500,000		552,600		400,000		1,902,600
Total long-term debt	$	200,000	$	—	$	452,412	$	500,000	$	552,600	$	3,973,860	$	5,678,872

XML

Liquidity Facilities and Other Financing Arrangements

12 Months Ended

Dec. 31, 2017

Liquidity Facilities and Other Financing Arrangements [Abstract]

Liquidity Facilities and Other Financing Arrangements

 Liquidity Facilities and Other Financing Arrangements

As of December 31, 2017 and 2016, PSE had $329.5 million and $245.8 million in short-term debt outstanding, respectively.  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 facility 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 2017 and 2016 was 3.5% and 3.2%, respectively.  As of December 31, 2017, PSE and Puget Energy had several committed credit facilities that are described below.

Puget Sound Energy

Credit Facility

In October 2017, PSE entered into a new $800.0 million credit facility which consolidates the two previous facilities into a single, smaller facility. All other features including fees, interest rate options, letter of credit, same day swingline borrowings, financial covenant and accordion feature remain substantially the same. The credit facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facility also has an expansion feature which, upon the banks' approval, would increase the total size of the facility to $1.4 billion. The unsecured revolving credit facility matures in October 2022.

The credit agreement is syndicated among numerous lenders and contains usual and customary affirmative and negative covenants that, among other things, places limitations on PSE's ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit agreement also contains 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, 2017, PSE was in compliance with all applicable covenant ratios.

The credit agreement provides PSE with the ability to borrow at different interest rate options. The credit agreement allows 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 facility. 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, 2017, no amounts were drawn and outstanding under PSE's credit facility. No letters of credit were outstanding and $329.5 million was outstanding under the commercial paper program. Outside of the credit agreement, PSE had a $3.1 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%.  As of December 31, 2017, there was no outstanding balance under the Note.

Puget Energy

Credit Facility

In October 2017, Puget Energy entered into a new $800.0 million credit facility to replace the existing facility. The terms and conditions, including fees, interest rate options, financial covenant, and expansion feature remain substantially the same. The new facility matures in October 2022. As of December 31, 2017, there was $102.6 million drawn and outstanding under the facility. The Puget Energy revolving senior secured credit facility also has an expansion 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 the date of this report, the spread over LIBOR was 1.75% and the commitment fee was 0.275%.

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, 2017, Puget Energy was in compliance with all applicable covenants.

XML

Leases

12 Months Ended

Dec. 31, 2017

Leases [Abstract]

Leases

Leases

PSE leases buildings and assets under operating leases. Certain leases contain purchase options, renewal options and escalation provisions.  Payments received for the subleases of properties were immaterial for each of the years ended 2017, 2016 and 2015.

Operating lease expenses net of sublease receipts were:

(Dollars in Thousands)
At December 31,	Operating Lease Expense
Years
2017	$	35,198
2016	31,786
2015	27,843

The following table summarizes the Company’s estimated future minimum lease payments for non-cancelable leases net of sublease receipts, through the terms of its existing contracts:

(Dollars in Thousands)	Future Minimum Lease Payments
At December 31,
Years	Operating		Capital
2018	$	21,371	$	527
2019	19,077		306
2020	17,507		232
2021	9,137		97
2022	6,747		—
Thereafter	97,974		—
Total minimum lease payments	$	171,813	$	1,162

XML

Accounting for Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Accounting for Derivative Instruments and Hedging Activities

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. In November 2017, PSE implemented a risk-responsive component to its hedging strategy for the core natural gas portfolio. This strategy utilizes quantitative risk-based measures with defined objectives to balance both portfolio risk and hedge costs.

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. Currently, the Company does not apply cash flow hedge accounting, and therefore records all mark-to-market gains or losses through earnings.

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, 2017, the Company did not have any outstanding interest rate swap instruments.

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

Puget Energy and Puget Sound Energy	At Year Ended December 31,
(Dollars in Thousands)	Volumes (millions)		Assets1				Liabilities²
	2017	2016	2017		2016		2017		2016
Interest rate swap derivatives3	$0.0	$450.0	$	—	$	—	$	—	$	141
Electric portfolio derivatives	*	*	13,391		36,460		49,050		41,329
Natural gas derivatives (MMBtus)4	332.1	336.4	11,014		26,619		37,044		19,101
Total derivative contracts			$	24,405	$	63,079	$	86,094	$	60,571
Current			$	22,247	$	54,341	$	64,859	$	44,310
Long-term			2,158		8,738		21,235		16,261
Total derivative contracts			$	24,405	$	63,079	$	86,094	$	60,571

_______________

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

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

³  Interest rate swap contracts are only held at Puget Energy and matured in January 2017.

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.

^*  Electric portfolio derivatives consist of electric generation fuel of 166.8 million One Million British Thermal Units (MMBtus) and purchased electricity of2.9 million megawatt hours (MWhs) at December 31, 2017 and 186.8 million MMBtus and 3.6 million MWhs at December 31, 2016.

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 natural gas and electric contracts; and North American Energy Standards Board (NAESB) agreements, which standardize physical natural 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 the 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. For further details regarding the fair value of derivative instruments, see Note 10, "Fair Value Measurements," to the consolidated financial statements included in Item 8 of this report.

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, 2017
(Dollars in Thousands)	Gross Amounts Recognized in the Statement of Financial Position 1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
							Commodity Contracts			Cash Collateral Received/Posted			Net Amount
Assets:
Energy derivative contracts	$	24,405	$	—	$	24,405	$	(17,940	)	$	—		$	6,465
Liabilities:
Energy derivative contracts	86,094		—		86,094		(17,940		)	(353		)	67,801
Puget Energy and Puget Sound Energy
At December 31, 2016
(Dollars in Thousands)	Gross Amounts Recognized in the Statement of Financial Position 1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
							Commodity Contracts			Cash Collateral Received/Posted			Net Amount
Assets:
Energy derivative contracts	$	63,079	$	—	$	63,079	$	(42,858	)	$	—		$	20,221
Liabilities:
Energy derivative contracts	60,430		—		60,430		(42,858		)	—			17,572
Interest rate swaps2	141		—		141		—			—			141

_______________

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 and matured in January 2017.

The following tables present the effect and locations of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income:

Puget Energy		Year Ended December 31,
(Dollars in Thousands)	Location	2017			2016			2015
Interest rate contracts:
	Non-hedged interest rate swap (expense) income	$	28		$	(1,062	)	$	(3,796	)
	Interest expense	—			—			560
Gas for Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	(32,492		)	62,318			(9,315		)
Realized	Electric generation fuel	(23,195		)	(39,656		)	(44,648		)
Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net1	1,702			21,477			22,548
Realized	Purchased electricity	(17,873		)	(21,998		)	(39,137		)
Total gain (loss) recognized in income on derivatives		$	(71,830	)	$	21,079		$	(73,788	)

Puget Sound Energy		Year Ended December 31,
(Dollars in Thousands)	Location	2017			2016			2015
Gas for Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	$	(32,492	)	$	62,318		$	(9,315	)
Realized	Electric generation fuel	(23,195		)	(39,656		)	(44,648		)
Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net1	1,702			21,477			22,003
Realized	Purchased electricity	(17,873		)	(21,998		)	(39,137		)
Total gain (loss) recognized in income on derivatives		$	(71,858	)	$	22,141		$	(71,097	)

_______________

¹  Differences between Puget Energy and PSE for the twelve months ended December 31, 2015 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 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, and exposure monitoring and mitigation.

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

It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of December 31, 2017, approximately 99.5% of the Company's energy portfolio exposure, excluding normal purchase normal sale (NPNS) transactions, is with counterparties that are rated investment grade by rating agencies and 0.5% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies.

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, 2017, 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 period. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. In March 2017, PSE began transacting power futures contracts on the Intercontinental Exchange (ICE) platform. Execution of these contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of December 31, 2017, PSE had cash posted as collateral of $2.6 million related to contracts executed on this platform. Also, as of December 31, 2017, PSE has a $1.0 million letter of credit posted as collateral 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 during the twelve months ended December 31, 2017, nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades.

The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post:

Puget Energy and Puget Sound Energy	At December 31,
(Dollars in Thousands)	2017						2016
Contingent Feature	Fair Value1 Liability		Posted Collateral		Contingent Collateral		Fair Value1 Liability		Posted Collateral		Contingent Collateral
Credit rating2	$	3,187	$	—	$	3,187	$	4,894	$	—	$	4,894
Requested credit for adequate assurance	37,374		—		—		7,427		—		—
Forward value of contract3	353		2,639		—		507		—		—
Total	$	40,914	$	2,639	$	3,187	$	12,828	$	—	$	4,894

_______________

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

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

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

XML

Fair Value Measurements

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

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

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

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

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

Financial assets and liabilities measured at fair value are classified in their entirety in the appropriate fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves, contract terms and prices, credit-risk adjustments, and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs as 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.

The Company considers its electric and natural gas contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. 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. Management's assessment is 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 used to value Level 2 commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter.

Assets and Liabilities with Estimated Fair Value

The carrying values of cash and cash equivalents, restricted cash, and short-term debt as reported on the balance sheet are reasonable estimates of their fair value due to the short-term nature of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value of other investments of $48.5 million and $49.1 million at December 31, 2017 and 2016, respectively, are included in "Other property and investments" on the balance sheet. These values are also reasonable estimates of their fair value and classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar transactions.

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's credit spreads as inputs, interpolating to the maturity date of each issue. The carrying values and estimated fair values were as follows:

Puget Energy		At December 31, 2017				At December 31, 2016
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	238,935	$	250,000	$	210,261
Long-term debt (fixed-rate), net of discount1	2	5,105,329		6,520,515		5,091,593		6,337,287
Long-term debt (variable-rate)	2	102,600		102,600		12,480		12,480
Total		$	5,457,929	$	6,862,050	$	5,354,073	$	6,560,028
Puget Sound Energy		At December 31, 2017				At December 31, 2016
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	238,935	$	250,000	$	210,261
Long-term debt (fixed-rate), net of discount2	2	3,499,911		4,550,130		3,497,298		4,360,783
Total		$	3,749,911	$	4,789,065	$	3,747,298	$	4,571,044

_______________

¹  The carrying value includes debt issuances costs of $27.9 million and $33.0 million for December 31, 2017 and 2016, respectively, which are not included in fair value.

²  The carrying value includes debt issuances costs of $24.6 million and $27.2 million for December 31, 2017 and 2016, respectively, which are not included in fair value.

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 and Puget Sound Energy	Fair Value						Fair Value
	At December 31, 2017						At December 31, 2016
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	9,866	$	3,525	$	13,391	$	30,666	$	5,794	$	36,460
Natural gas derivative instruments	6,973		4,041		11,014		23,316		3,303		26,619
Total derivative assets	$	16,839	$	7,566	$	24,405	$	53,982	$	9,097	$	63,079
Liabilities:
Interest rate derivative instruments1	$	—	$	—	$	—	$	141	$	—	$	141
Electric derivative instruments	46,623		2,427		49,050		36,507		4,822		41,329
Natural gas derivative instruments	34,926		2,118		37,044		16,423		2,678		19,101
Total derivative liabilities	$	81,549	$	4,545	$	86,094	$	53,071	$	7,500	$	60,571

_______________

¹  Interest rate derivative instruments are only held at Puget Energy, and matured January 2017.

Puget Energy and Puget Sound Energy	Year Ended December 31,
Level 3 Roll-Forward Net (Liability)	2017									2016									2015
(Dollars in Thousands)	Electric			Gas			Total			Electric			Gas			Total			Electric			Gas			Total
Balance at beginning of period	$	972		$	625		$	1,597		$	(7,345	)	$	(2,383	)	$	(9,728	)	$	(12,062	)	$	(2,040	)	$	(14,102	)
Changes during period
Realized and unrealized energy derivatives:
Included in earnings1	2,781			—			2,781			4,007			—			4,007			(6,432		)	—			(6,432		)
Included in regulatory assets / liabilities	—			6,346			6,346			—			4,312			4,312			—			3,695			3,695
Settlements2	(6,549		)	(6,372		)	(12,921		)	(1,129		)	(2,679		)	(3,808		)	902			(3,885		)	(2,983		)
Transferred into Level 3	523			(553		)	(30		)	(3,021		)	—			(3,021		)	(787		)	—			(787		)
Transferred out Level 3	3,371			1,877			5,248			8,460			1,375			9,835			11,034			(153		)	10,881
Balance at end of period	$	1,098		$	1,923		$	3,021		$	972		$	625		$	1,597		$	(7,345	)	$	(2,383	)	$	(9,728	)

_______________

¹  Income Statement classification: 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 $1.5 million, $2.0 million and $(7.4) million for the years ended December 31, 2017, 2016 and 2015, respectively.

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

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

In order to determine which assets and liabilities are classified as Level 3, the Company receives market data from its independent external pricing service defining the tenor of observable market quotes. To the extent any of the Company's commodity contracts extend beyond what is considered observable as defined by its independent pricing service, the contracts are classified as Level 3. The actual tenor of what the independent pricing service defines as observable is subject to change depending on market conditions. Therefore, as the market changes, the same contract may be designated Level 3 one month and Level 2 the next, and vice versa. The changes of fair value classification into or out of Level 3 are recognized each month, and reported in the Level 3 Roll-forward table above. The Company did not have any transfers between Level 2 and Level 1 during the years ended December 31, 2017, 2016 and 2015. 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, 2017:

Puget Energy and Puget Sound Energy	Fair Value				Range
(Dollars in Thousands)	Assets1	Liabilities1	Valuation Technique	Unobservable Input	Low	High	Weighted Average
Electric	$3,525	$2,427	Discounted cash flow	Power Prices (per MWh)	$7.02	$28.94	$18.61
Natural gas	$4,041	$2,118	Discounted cash flow	Natural Gas Prices (per MMBtu)	$1.22	$2.80	$1.54

_______________

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, 2017, 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 $0.9 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 2017 and 2016, Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. In 2017 and 2016, due to continued decreases in forward power prices and decreases in forecasted revenue and cost estimates, the following impairments were recorded to the Company's intangible asset contracts, with corresponding reductions to the regulatory liability as follows:

Puget Energy
(Dollars in Thousands)
Valuation Date	Contract Name	Carrying Value		Fair Value		Write Down
September 30, 2017	Wells Hydro	$	10,621	$	9,609	$	1,012
March 31, 2017	Wells Hydro	14,879		13,067		1,812
	Rocky Reach	235,331		159,818		75,513
	Priest Rapids RP	5,665		2,657		3,008
Total 2017 Impairments						$	81,345
September 30, 2016	Priest Rapids RP	$	18,969	$	6,191	$	12,778
March 31, 2016	Wells Hydro	25,193		19,855		5,338
Total 2016 Impairments						$	18,116

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 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 2017 and 2016:

Puget Energy
Valuation Date	Contract	Unobservable Input	Low	High	Average
September 30, 2017	Wells Hydro	Power prices (per MWh)	14.06	26.86	22.24
		Power contract costs per quarter (in thousands)	4,126	4,126	4,126
March 31, 2017	Wells Hydro	Power prices (per MWh)	8.76	26.70	20.86
		Power contract costs per quarter (in thousands)	3,965	4,223	4,051
	Rocky Reach	Power prices (per MWh)	8.53	48.21	27.69
		Power contract costs per quarter (in thousands)	5,827	6,780	6,150
	Priest Rapids RP	Power prices (per MWh)	13.70	29.38	23.14
		Power contract costs per year (in thousands)	620	4,022	2,306
September 30, 2016	Priest Rapids RP	Power prices (per MWh)	24.24	58.96	39.31
		Power contract costs per year (in thousands)	618	4,633	2,472
March 31, 2016	Wells Hydro	Power prices (per MWh)	9.46	25.96	21.38
		Power contract costs per quarter (in thousands)	4,100	4,659	4,452

XML

Employee Investment Plans

12 Months Ended

Dec. 31, 2017

Employee Investment Plans [Abstract]

Employee Investment Plans

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 $19.2 million, $17.2 million and $16.1 million for the years 2017, 2016 and 2015, 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 6.0% of plan compensation each paycheck, and will make an additional year-end contribution equal to 1.0% of base pay. 

• For employees grandfathered under the Final Average Earning retirement plan formula, PSE will match 55.0% of an employee’s contribution up to 6.0% of plan compensation each paycheck.

Non-represented and UA-represented employees hired on or after January 1, 2014 along with IBEW-represented employees hired on or after December 12, 2014, will have access to the 401(k) plan. The two contribution sources from PSE are below:

• 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 3.0% of pay contributed and 50.0% match on the next 3.0% of pay contributed. An employee who contributes 6.0% 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 4.0% of eligible pay placed in the Cash Balance retirement plan. New non-represented and IBEW-represented employees will receive an annual company contribution of 4.0% 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 4.0% contribution either into the 401(k) plan or into an account in the Cash Balance retirement plan. The Company’s 4.0% contribution will vest after three years of service.

XML

Retirement Benefits

12 Months Ended

Dec. 31, 2017

Retirement Benefits [Abstract]

Retirement Benefits

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 non-represented and UA-represented employees, along with IBEW-represented employees 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 4.0% 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 1.0% 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, 2017 and 2016:

Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2017			2016			2017			2016			2017			2016
Change in benefit obligation:
Benefit obligation at beginning of period	$	652,607		$	643,088		$	51,734		$	51,279		$	11,194		$	13,946
Service cost	20,081			18,913			913			1,085			72			93
Interest cost	28,373			28,689			2,285			2,325			500			533
Actuarial loss (gain)	40,945			1,545			2,722			106			725			(2,262		)
Benefits paid	(40,594		)	(38,730		)	(1,900		)	(3,061		)	(1,137		)	(1,264		)
Medicare part D subsidy received	—			—			—			—			100			148
Administrative expense	(931		)	(898		)	—			—			—			—
Benefit obligation at end of period	$	700,481		$	652,607		$	55,754		$	51,734		$	11,454		$	11,194

Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2017			2016			2017			2016			2017			2016
Change in plan assets:
Fair value of plan assets at beginning of period	$	620,260		$	598,865		$	—		$	—		$	7,200		$	7,203
Actual return on plan assets	107,836			37,022			—			—			784			926
Employer contribution	18,000			24,000			1,900			3,061			291			335
Benefits paid	(40,594		)	(38,730		)	(1,900		)	(3,061		)	(1,137		)	(1,264		)
Administrative expense	(1,142		)	(897		)	—			—			—			—
Fair value of plan assets at end of period	$	704,360		$	620,260		$	—		$	—		$	7,138		$	7,200
Funded status at end of period	$	3,879		$	(32,347	)	$	(55,754	)	$	(51,734	)	$	(4,316	)	$	(3,994	)

Puget Energy and Puget Sound Energy	Qualified Pension Benefits					SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2017		2016			2017			2016			2017			2016
Amounts recognized in Statement of Financial Position consist of:
Noncurrent assets	$	3,879	$	—		$	—		$	—		$	—		$	—
Current liabilities	—		—			(5,486		)	(1,911		)	(317		)	(325		)
Noncurrent liabilities	—		(32,347		)	(50,268		)	(49,823		)	(3,999		)	(3,669		)
Net assets (liabilities)	$	3,879	$	(32,347	)	$	(55,754	)	$	(51,734	)	$	(4,316	)	$	(3,994	)

Puget Energy and Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2017		2016		2017		2016		2017		2016
Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets:
Projected benefit obligation	$	700,481	$	652,607	$	55,754	$	51,734	$	11,454	$	11,194
Accumulated benefit obligation	688,908		641,855		52,681		47,639		11,367		11,092
Fair value of plan assets	704,360		620,260		—		—		7,138		7,200

The following tables summarize Puget Energy's and PSE's pension benefit amounts recognized in AOCI for the years ended December 31, 2017 and 2016:

Puget Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2017			2016			2017		2016		2017			2016
Amounts recognized in Accumulated Other Comprehensive Income consist of:
Net loss (gain)	$	37,693		$	56,588		$	10,689	$	9,043	$	(3,386	)	$	(4,190	)
Prior service cost (credit)	(7,843		)	(9,822		)	204		246		—			—
Total	$	29,850		$	46,766		$	10,893	$	9,289	$	(3,386	)	$	(4,190	)

Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2017			2016			2017		2016		2017			2016
Amounts recognized in Accumulated Other Comprehensive Income consist of:
Net loss (gain)	$	185,277		$	217,143		$	13,134	$	11,978	$	(4,901	)	$	(5,994	)
Prior service cost (credit)	(6,232		)	(7,806		)	208		251		—			—
Total	$	179,045		$	209,337		$	13,342	$	12,229	$	(4,901	)	$	(5,994	)

The following tables summarize Puget Energy's and PSE's net periodic benefit cost for the years ended December 31, 2017, 2016 and 2015:

Puget Energy	Qualified Pension Benefits									SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2017			2016			2015			2017		2016		2015		2017			2016			2015
Components of net periodic benefit cost:
Service cost	$	20,081		$	18,913		$	21,287		$	913	$	1,085	$	1,108	$	72		$	93		$	112
Interest cost	28,373			28,689			28,088			2,285		2,325		2,281		500			533			621
Expected return on plan assets	(47,784		)	(46,619		)	(45,038		)	—		—		—		(461		)	(446		)	(531		)
Amortization of prior service cost (credit)	(1,980		)	(1,980		)	(1,980		)	42		42		42		—			—			—
Amortization of net loss (gain)	—			—			3,887			1,077		911		1,641		(402		)	(386		)	(130		)
Net periodic benefit cost	$	(1,310	)	$	(997	)	$	6,244		$	4,317	$	4,363	$	5,072	$	(291	)	$	(206	)	$	72

Puget Sound Energy	Qualified Pension Benefits									SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2017			2016			2015			2017		2016		2015		2017			2016			2015
Components of net periodic benefit cost:
Service cost	$	20,081		$	18,913		$	21,287		$	913	$	1,085	$	1,108	$	72		$	93		$	112
Interest cost	28,373			28,689			28,088			2,285		2,325		2,281		500			533			621
Expected return on plan assets	(47,862		)	(46,814		)	(45,462		)	—		—		—		(461		)	(446		)	(531		)
Amortization of prior service cost (credit)	(1,573		)	(1,573		)	(1,573		)	44		44		44		—			—			3
Amortization of net loss (gain)	13,048			15,257			20,555			1,565		1,330		2,120		(641		)	(632		)	(406		)
Net periodic benefit cost	$	12,067		$	14,472		$	22,895		$	4,807	$	4,784	$	5,553	$	(530	)	$	(452	)	$	(201	)

The following tables summarize Puget Energy's and PSE's benefit obligations recognized in other comprehensive income (OCI) for the years ended December 31, 2017 and 2016:

Puget Energy	Qualified Pension Benefits					SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2017			2016		2017			2016			2017		2016
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	$	(18,896	)	$	11,141	$	2,722		$	106		$	403	$	(2,742	)
Amortization of net (loss) gain	—			—		(1,076		)	(910		)	401		385
Amortization of prior service (cost) credit	1,980			1,980		(42		)	(42		)	—		—
Total change in other comprehensive income for year	$	(16,916	)	$	13,121	$	1,604		$	(846	)	$	804	$	(2,357	)

Puget Sound Energy	Qualified Pension Benefit						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2017			2016			2017			2016			2017		2016
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	$	(18,817	)	$	11,336		$	2,722		$	106		$	452	$	(2,742	)
Amortization of net (loss) gain	(13,048		)	(15,257		)	(1,565		)	(1,330		)	641		631
Amortization of prior service (cost) credit	1,573			1,573			(44		)	(44		)	—		—
Total change in other comprehensive income for year	$	(30,292	)	$	(2,348	)	$	1,113		$	(1,268	)	$	1,093	$	(2,111	)

The estimated net (loss) gain and prior service cost (credit) for the pension plans that will be amortized from Accumulated Other Comprehensive Income (AOCI) into net periodic benefit cost in 2018 by PSE are $(14.5) million and $1.6 million, respectively.  The estimated net (loss) gain for the SERP that will be amortized from AOCI into net periodic benefit cost in 2018 is $(2.1) million. The estimated prior service cost (credit) for the SERP that will be amortized from AOCI into net periodic benefit cost in 2018 is immaterial.  The estimated net (loss) gain and prior service cost (credit) for the other postretirement plans that will be amortized from AOCI into net periodic benefit cost in 2018 is $0.6 million. For Puget Energy, the overall amounts expected to be amortized from AOCI into net period benefit cost in 2018 is $(1.1) million.

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, 2018 are expected to be at least $18.0 million, $5.5 million and $0.3 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	2017		2016		2015		2017		2016		2015		2017		2016		2015
Discount rate	4.00	%	4.50	%	4.65	%	4.00	%	4.50	%	4.65	%	4.00	%	4.50	%	4.65	%
Rate of compensation increase	4.50		4.50		4.50		4.50		4.50		4.50		4.50		4.50		4.50
Medical trend rate	—		—		—		—		—		—		6.80		8.80		7.20
Benefit Cost Assumptions
Discount rate	4.50	%	4.65	%	4.25	%	4.50	%	4.65	%	4.25	%	4.50	%	4.65	%	4.25	%
Return on plan assets	7.45		7.75		7.75		—		—		—		6.75		6.75		7.00
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	—		—		—		—		—		—		9.50		5.30		7.20

The assumed medical inflation rate used to determine benefit obligations is 6.80% in 2018 grading down to 4.10% in 2019.  A 1.0% change in the assumed medical inflation rate would have the following effects:

	2017					2016
(Dollars in Thousands)	1% Increase		1% Decrease			1% Increase		1% Decrease
Effect on post-retirement benefit obligation	$	23	$	(22	)	$	38	$	(35	)
Effect on service and interest cost components	1		(1		)	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 based on a five-year smoothing of asset gains (losses) measured from the expected return on market-related assets.  This is a calculated value that recognizes changes in fair value in a systematic and rational manner over five years.  The same manner of calculating market-related value is used for all classes of assets, and is applied consistently from year to year.

Puget Energy’s pension and other postretirement benefits income or costs depend on several factors and assumptions, including plan design, timing and amount of cash contributions to the plan, earnings on plan assets, discount rate, expected long-term rate of return, 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)	2018		2019		2020		2021		2022		2023-2027
Qualified Pension total benefits	$	42,600	$	43,400	$	44,800	$	45,700	$	46,900	$	246,500
SERP Pension total benefits	5,486		6,001		4,684		1,728		4,577		37,394
Other Benefits total with Medicare Part D subsidy	911		885		852		811		863		3,748
Other Benefits total without Medicare Part D subsidy	1,172		1,155		1,131		1,097		1,070		4,844

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	—		9		15
Non-U.S. equity	10		25		30
Fixed income	15		25		30
Real estate	—		—		10
Absolute return	5		10		15
Cash	—		—		5

Plan Fair Value Measurements

ASC 715, “Compensation – Retirement Benefits” (ASC 715) directs companies to provide additional disclosures about plan assets of a defined benefit pension or other postretirement plan.  The objectives of the disclosures are to disclose the following: (i) how investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies; (ii) major categories of plan assets; (iii) inputs and valuation techniques used to measure the fair value of plan assets; (iv) effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period; and (v) 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, 2017 and 2016:

	Recurring Fair Value Measures						Recurring Fair Value Measures
	As of December 31, 2017						As of December 31, 2016
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Mutual Funds	$	117,796	$	—	$	117,796	$	181,212	$	—	$	181,212
Common Stock	209,504		—		209,504		154,255		—		154,255
Government Securities	18,316		23,782		42,098		18,754		16,197		34,951
Corporate Bonds	—		34,588		34,588		—		38,543		38,543
Cash and cash equivalents	2,684		9,304		11,988		—		—		—
Subtotal	$	348,300	$	67,674	415,974		$	354,221	$	54,740	408,961
Investments measured at NAV1					237,427						222,819
Net (payable) receivable					50,959						(9,894		)
Total assets					$	704,360					$	621,886

_______________

¹  In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments that were measured at NAV per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV primarily consist of common/collective trust funds and two partnerships held as of December 31, 2017.

Mesirow Institutional Multi-Strategy Fund Partnership, L.P. utilizes a combination of long and short strategies through investments in investment funds. The major strategy allocations of the investment funds include (1) Investments in debt obligations of public and private entities; typically, in financial duress, and (2) Investments in equity positions on a global basis utilizing fundamental analysis.

Grosvenor Institutional Partners Fund, L.P invests substantially all of the fund assets available in the Grosvenor Master Fund, a Cayman Islands exempted company which is sponsored, managed and has the same investment objective as the Partnership fund. In addition to the Master Fund, investments are made primarily in offshore investment funds, investment partnerships, and pooled investment vehicles; collectively referred to as Portfolio Funds, which generally implement "nontraditional" or "alternative" investment strategies.

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, 2017						As of December 31, 2016
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Mutual fund1	$	7,089	$	—	$	7,089	$	7,182	$	—	$	7,182
Investments measured at NAV2					49						80
Total assets					$	7,138					$	7,262

_______________

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, 2017.

²  In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments that were measured at NAV per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV consist of a common/collective trust fund as of December 31, 2017.

XML

Income Taxes

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

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

Puget Energy	Year Ended December 31,
(Dollars in Thousands)	2017			2016			2015
Charged to operating expenses:
Current:
Federal	$	1,127		$	—		$	—
State	17			20			—
Deferred:
Federal	254,420			140,315			91,968
State	(421		)	(131		)	(192		)
Total income tax expense	$	255,143		$	140,204		$	91,776

Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	2017		2016		2015
Charged to operating expenses:
Current:
Federal	$	1,127	$	—	$	—
State	17		20		—
Deferred:
Federal	210,842		175,327		125,900
State	—		—		—
Total income tax expense	$	211,986	$	175,347	$	125,900

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)	2017			2016			2015
Income taxes at the statutory rate	$	148,847		$	158,586		$	116,534
Increase (decrease):
Production tax credit1	—			(12,925		)	(19,470		)
Utility plant differences	—			3,966			5,671
Treasury grant amortization	(9,537		)	(9,788		)	(8,807		)
Tax reform	117,185			—			—
Other - net	(1,352		)	365			(2,152		)
Total income tax expense	$	255,143		$	140,204		$	91,776
Effective tax rate	60.0		%	30.9		%	27.6		%

Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	2017			2016			2015
Income taxes at the statutory rate	$	185,430		$	194,572		$	150,531
Increase (decrease):
Production tax credit1	—			(12,925		)	(19,470		)
Utility plant differences	—			3,966			5,671
Treasury grant amortization	(9,537		)	(9,788		)	(8,807		)
Tax reform	36,328			—			—
Other - net	(235		)	(478		)	(2,025		)
Total income tax expense	$	211,986		$	175,347		$	125,900
Effective tax rate	40.0		%	31.5		%	29.3		%

_______________

¹  PSE's Wild Horse wind plant and Hopkins Ridge wind plant earned their last PTCs in December 2016 and 2015, respectively. No further PTCs are expected.

The Company’s net deferred tax liability at December 31, 2017 and 2016 is composed of amounts related to the following types of temporary differences:

Puget Energy	At December 31,
(Dollars in Thousands)	2017			2016
Utility plant and equipment	$	2,034,328		$	1,880,782
Regulatory asset for income taxes	—			72,038
Fair value of debt instruments	38,777			67,444
Pensions and other compensation	46,338			77,230
Other deferred tax liabilities	86,933			119,050
Subtotal deferred tax liabilities	2,206,376			2,216,544
Net operating loss carryforward	(212,168		)	(352,827		)
Net regulatory liability for income taxes	(1,011,626		)	—
Production tax credit carryforward	(187,617		)	(190,999		)
Regulatory liability on production tax credit	(49,873		)	(101,787		)
Net other deferred tax assets	1,776			—
Subtotal deferred tax assets	(1,459,508		)	(645,613		)
Total net deferred tax liabilities	$	746,868		$	1,570,931

Puget Sound Energy	At December 31,
(Dollars in Thousands)	2017			2016
Utility plant and equipment	$	2,034,328		$	1,880,782
Regulatory asset for income taxes	—			71,517
Other, net deferred tax liabilities	86,933			113,938
Subtotal deferred tax liabilities	2,121,261			2,066,237
Net regulatory liability for income taxes	(1,012,260		)	—
Net operating loss carryforward	—			(41,061		)
Production tax credit carryforward	(187,617		)	(190,999		)
Regulatory liability on production tax credit	(49,873		)	(101,787		)
Net other deferred tax assets	(2,038		)	—
Subtotal deferred tax assets	(1,251,788		)	(333,847		)
Total net deferred tax liabilities	$	869,473		$	1,732,390

On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). Substantially all of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes significant changes to the Internal Revenue Code of 1986 (as amended, the Code), including amendments which significantly change the taxation of business entities and includes specific provisions related to regulated public utilities including PSE. The most significant change that impacts the Company included in the TCJA is the reduction in the corporate federal income tax rate from 35.0% percent to 21.0% percent. The specific provisions related to regulated public utilities in the TCJA generally allow for the continued deductibility of interest expense, the elimination of full expensing for tax purposes of certain property acquired after September 27, 2017 and continues normalization requirements for accelerated depreciation benefits. For Puget Energy, TCJA provides for full expensing of property acquired after September 27, 2017 and limits a deduction for interest expense to 30.0% percent of adjusted taxable income (which resembles earnings before interest, taxes, depreciation and amortization or “EBITDA”).

Under generally accepted accounting principles (US GAAP) specifically ASC Topic 740, Income Taxes the tax effects of changes in tax laws must be recognized in the period in which the law is enacted and deferred tax assets and liabilities are to be re-measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. For PSE, the change in deferred taxes is recorded as either an offset to a regulatory asset or liability and is subject to approval by the Washington Commission. For Puget Energy, the change in deferred taxes is recorded as an adjustment to Puget Energy’s income tax expense, which decreased Puget Energy’s net income.

Upon, enactment of the TCJA, the Company re-measured their deferred tax assets and liabilities based upon the TCJA’s 21.0% percent corporate federal income tax rate. The corporate tax rate change for PSE is captured in the deferred tax balance with an offset to the regulatory liability for deferred income taxes. The balance of the regulatory deferred tax account at the beginning of the year, before tax reform, was a $71.5 million asset. As a result of tax reform, the balance is a liability of $1,012.3 million which represents the excess deferred taxes that will eventually be refunded to customers. Since, PSE is in a net regulatory liability position with respect to these income tax matters, PSE netted the regulatory asset for deferred income taxes against the regulatory liability for deferred income taxes. Under the normalization requirements continued by the TCJA, $919.8 million of the net regulatory liability related to certain accelerated tax depreciation benefits is to be amortized over the remaining lives of the related assets. The remainder of the net regulatory liability of $92.5 million is available for PSE and the Washington Commission regulatory process to determine how the amounts will be refunded to customers. PSE requested to delay the impact of tax reform in an accounting petition which was filed with the Washington Commission on December 29, 2017. The income statement impact for the regulatory deferred tax will come in the future when the Washington Commission issues a final order. The timing for that is unknown but will likely occur in 2018.

The impact of the TCJA to income tax expense was $36.3 million of which $3.0 million relates to deferred tax balances that are not subject to regulatory treatment. In addition, $33.3 million relates to the revaluation of the PTC deferred taxes. The liability owed to customers for PTCs, which previously reduced revenue upon generation of the PTCs, was also revalued at the TCJAs 21 percent rate. The change in the liability owed to customers for PTCs due to TCJA increased revenue by $51.2 million, which increased tax expense by $17.9 million, to reverse the initial deferral. The changes in deferred tax and liability owed to customers for PTCs had no impact on net income. Incrementally, Puget Energy increased their tax expense by $80.9 million primarily due to the revaluation of Puget Energy's net deferred tax asset on its net operating loss carryforward.

The staff of the US Securities and Exchange Commission (SEC) has recognized the complexity of reflecting the impacts of the TCJA, and on December 22, 2017 issued guidance in Staff Accounting Bulletin 118 (SAB 118) which clarifies accounting for income taxes under ASC 740 if information is not yet available or complete and provides for up to a one year period in which to complete the required analyses and accounting (the measurement period). SAB 118 describes three scenarios (or “buckets”) associated with a company’s status of accounting for income tax reform: (1) a company is complete with its accounting for certain effects of tax reform, (2) a company is able to determine a reasonable estimate for certain effects of tax reform and records that estimate as a provisional amount, or (3) a company is not able to determine a reasonable estimate and therefore continues to apply ASC 740, based on the provisions of the tax laws that were in effect immediately prior to the TCJA being enacted. The Company has completed the required analysis and accounting for substantially all the effects of the TCJA's enactment and have made a reasonable estimate as to the other effects, and have reflected the measurement and accounting of the effects in the 2017 consolidated financial statements. The items reflected as provisional amounts include tax depreciation and amortization and other book to tax differences. PSE has accounted for these items based on its interpretation of the TCJA. Further interpretive guidance on the TCJA from the IRS, U.S. Treasury Department, or the Joint Committee on Taxation may require adjustments to PSE's accounting. In accordance with SAB 118, adjustments, if any, will be recorded in 2018. The Company did not identify any effects on the TCJA for which they were not able to either complete the required analysis or make a reasonable estimate.

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 2037.  The Company’s net operating loss carryforwards expire from 2029 through 2036. No valuation allowance has been provided for PTC or net operating loss carryforwards.

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, 2017 and 2016, the Company had no material unrecognized tax benefits.  As a result, no interest or penalties were accrued for unrecognized tax benefits during the year.

The Company has open tax years from 2014 through 2017. The Company classifies interest as interest expense and penalties as other expense in the financial statements.

XML

Litigation

12 Months Ended

Dec. 31, 2017

Litigation Disclosure [Abstract]

Litigation

 Litigation

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. On July 12, 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court on September 6, 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE and Talen Energy, agreed to retire the two oldest units (Units 1 and 2) at Colstrip in eastern Montana by no later than July 1, 2022. The Washington Commission allows full recovery in rates of the net book value (NBV) at retirement and related decommissioning costs consistent with prior precedents. As a result, PSE reclassified $176.8 million from a utility plant asset to a regulatory asset, which represents the expected NBV at retirement of Colstrip Units 1 and 2, based on the expected shutdown date of July 1, 2022 as of December 31, 2016.

Depreciation rates were updated in the GRC effective December 19, 2017, where PSE's depreciation increased for Colstrip Units 1 and 2 to recover plant costs to the expected shutdown date. The increase in depreciation caused the Colstrip Units 1 and 2 regulatory asset to be reduced to $127.6 million as of December 31, 2017. The GRC also repurposed PTCs and hydro-related treasury grants to fund and recover decommissioning and remediation costs for Colstrip Units 1 and 2. Colstrip Units 3 and 4, which are newer and more efficient, are not affected by the settlement, and allegations in the lawsuit against Colstrip Units 3 and 4 were dismissed as part of the settlement with the Sierra Club. While PSE has estimated the ARO for Colstrip Units 1 and 2, the full scope of decommissioning activities and costs may vary from the estimates that are available at this time.

Greenwood

On March 9, 2016, a natural gas explosion occurred in the Greenwood neighborhood of Seattle, WA, damaging multiple structures. The Washington Commission Staff completed its investigation of the incident and filed a complaint on September 20, 2016, seeking up to $3.2 million in fines from PSE. As of September 30, 2016, PSE accrued $3.2 million for the fine. On March 28, 2017, pipeline safety regulators and PSE reached a settlement in response to the complaint. As part of the agreement, PSE agreed to pay a penalty of $2.8 million, of which $1.3 million was suspended on condition that PSE complete a comprehensive inspection and remediation program. On June 19, 2017, the Washington Commission approved the settlement without conditions and adopted the reduced penalty of $2.8 million, of which $1.3 million was suspended. On June 30, 2017, PSE paid the penalty it had previously accrued. However, litigation is still pending regarding damage and personal injury claims.

Coal Combustion Residuals

On April 17, 2015, the EPA published a final rule, effective October 19, 2015, that regulates CCR's under the Resource Conservation and Recovery Act, Subtitle D. The EPA issued another rule, effective October 4, 2016, extending certain compliance deadlines under the CCR rule. The CCR rule is self-implementing at a federal level or can be taken over by a state. The 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.

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 ARO.

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

In June 2014, the EPA issued a proposed Clean Power Plan (CPP) 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. The EPA published a final rule on October 23, 2015. The rule was being challenged by other states and parties, and the Supreme Court granted a stay of the rule on February 9, 2016 until the litigation is resolved. On March 31, 2017, the EPA Administrator, Scott Pruitt, signed a notice of withdrawal of the proposed CPP federal plan and model trading rules and, on October 10, 2017, the EPA proposed to repeal the CPP rule and is currently accepting comment on the proposal. PSE is still reviewing the impact of these developments.

Washington Clean Air Rule

The CAR was adopted on September 15, 2016 in Washington State and attempts to reduce greenhouse gas emissions from “covered entities” located within Washington State. Included under the new rule are large manufacturers, petroleum producers and natural gas utilities, including PSE. The CAR sets a cap on emissions associated with covered entities, which decreases over time, approximately 5.0% every three years. Entities must reduce their carbon emissions, or purchase emission reduction units (ERUs), as defined under the rule, from others.

The CAR covers natural gas distributors and subjects them to an emissions reduction pathway based on the indirect emissions of their customers. The CAR regulates the emissions of natural gas utilities 1.2 million customers across the state, adding to the cost of natural gas for homes and businesses, which may increase costs to PSE customers.

On September 27, 2016, PSE, along with Avista Corporation, Cascade Natural Gas Corporation and NW Natural, filed a lawsuit in the U.S. District Court for the Eastern District of Washington challenging the CAR. On September 30, 2016, the four companies filed a similar challenge to the CAR in Thurston County Superior Court. On December 15, 2017, the Thurston County Superior Court invalidated the CAR. A final court order is pending and in the meantime, the Washington State Department of Ecology (WDOE), submitted a brief requesting severability, which would make the rule valid for industries with direct emissions. This would apply to The Company's electric utility thermal generation units but not to its natural gas utility. Appeals could be filed to the Thurston County Court of Appeals after the court's final order, including its ruling on severability.

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 $2.4 million and $0.7 million relating to these claims as of December 31, 2017 and 2016, respectively.

XML

Commitments and Contingencies

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

For the year ended December 31, 2017, approximately 13.3% 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 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)	2017		2016		2015
PUD contract costs	$	73,827	$	77,667	$	72,833

As of December 31, 2017, 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 2018 Costs		2018 Debt Service Costs		Interest included in 2018 Debt Service Costs		Debt Outstanding
Chelan County PUD:
Rock Island Project	2031	25.0	%	156	$	29,135	$	10,105	$	5,354	$	84,269
Rocky Reach Project	2031	25.0		325	28,800		5,796		2,548		39,563
Douglas County PUD:
Wells Project1	2028	29.9		251	11,002		4,695		1,379		49,629
Grant County PUD:
Priest Rapids Development	2052	0.6		6	2,050		1,231		1,231		13,723
Wanapum Development	2052	0.6		7	2,050		1,231		1,231		13,723
Total				745	$	73,037	$	23,058	$	11,743	$	200,907

_______________

¹  In March 2017, PSE entered a new PPA with Douglas County PUD for Wells Project output that begins upon expiration of the existing contract on August 31, 2018 and continues through September 30, 2028.

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

(Dollars in Thousands)	2018		2019		2020		2021		2022		Thereafter		Total
Columbia River projects	$	82,200	$	97,890	$	95,704	$	91,862	$	91,018	$	708,499	$	1,167,173
Other utilities	1,257		888		—		—		—		—		2,145
Non-utility contracts	206,233		233,776		238,016		244,962		244,906		1,128,466		2,296,359
Short-term electric supply contracts	70,786		140		—		—		—		—		70,926
Total	$	360,476	$	332,694	$	333,720	$	336,824	$	335,924	$	1,836,965	$	3,536,603

Total purchased power contracts provided the Company with approximately 14.5 million, 13.0 million and 11.2 million MWhs of firm energy at a cost of approximately $456.4 million, $402.5 million and $373.8 million for the years 2017, 2016 and 2015, 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 1 year to 27 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage.  The Company incurred demand charges for 2017 for firm transportation, storage and peaking services for its natural gas customers of $121.4 million. The Company incurred demand charges in 2017 for firm transportation and storage services for the natural gas supply for its combustion turbines in the amount of $41.8 million.

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)	2018		2019		2020		2021		2022		Thereafter		Total
Natural gas supply	$	245,669	$	193,458	$	163,818	$	145,662	$	109,401	$	—	$	858,008
Firm transportation service	154,170		154,204		141,962		126,319		125,335		310,428		1,012,418
Firm storage service	8,328		8,899		7,908		3,108		1,619		857		30,719
Short-term natural gas supply contracts	55,774		13,818		1,651		—		—		—		71,243
Total	$	463,941	$	370,379	$	315,339	$	275,089	$	236,355	$	311,285	$	1,972,388

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)	2018		2019		2020		2021		2022		Thereafter		Total
Energy production service contracts	$	28,674	$	27,939	$	28,639	$	29,415	$	30,142	$	165,689	$	310,498
Automated meter reading system	48,245		44,842		43,951		44,497		45,168		187,698		414,401
Total	$	76,919	$	72,781	$	72,590	$	73,912	$	75,310	$	353,387	$	724,899

Other Commitments and Contingencies

For information regarding PSE's environmental remediation obligations, see Note 3, "Regulation and Rates," to the consolidated financial statements included in item 8 of this report.

XML

Related Party Transactions

12 Months Ended

Dec. 31, 2017

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

Scott Armstrong serves on the Board of Directors of the Company and, until its acquisition by Kaiser Permanente on February 1, 2017, was the President and Chief Executive Officer of Group Health Cooperative (Group Health). Group Health provided coverage to over 600,000 residents in Washington and Northern Idaho. Certain employees of PSE elected Group Health as their medical provider prior to its acquisition by Kaiser Permanente, and as a result, PSE paid Group Health a total of $3.9 million, $23.3 million and $20.3 million for medical coverage for the year ended December 31, 2017, 2016 and 2015. Kaiser Permanente is not considered a related party to PSE.

Kimberly Harris, the President and Chief Executive Officer and a director of Puget Energy and PSE, is married to Kyle Branum, who as of January 2017 is a partner at Summit Law Group, which provides legal services to PSE.  In 2017 Summit Law Group was paid $0.8 million for legal services provided to PSE and Mr. Branum was among the lawyers at Summit Law Group who provided such legal services.  This work was performed under the supervision of PSE's General Counsel. Through 2016, Mr. Branum was a principal at the law firm Riddell Williams P.S., which provided legal services to PSE. In 2016 and 2015, Riddell Williams was paid $1.0 million and $1.8 million, respectively.

XML

Segment Information

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Segment Information

Segment Information

Puget Energy and PSE operate one reportable 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.

XML

Accumulated Other Comprehensive Income (Loss)

12 Months Ended

Dec. 31, 2017

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

Accumulated Other Comprehensive Income (Loss)

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, 2017, 2016 and 2015, respectively:

Puget Energy	Net unrealized gain (loss) and prior service cost on pension plans			Net unrealized gain (loss) on energy derivative instruments
Changes in AOCI, net of tax
(Dollars in Thousands)							Total
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	)
Other comprehensive income (loss) before reclassifications	(5,528		)	—			(5,528		)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	(918		)	—			(918		)
Net current-period other comprehensive income (loss)	(6,446		)	—			(6,446		)
Balance at December 31, 2016	$	(33,712	)	$	—		$	(33,712	)
Other comprehensive income (loss) before reclassifications	10,251			—			10,251
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	(821		)	—			(821		)
Net current-period other comprehensive income (loss)	9,430			—			9,430
Balance at December 31, 2017	$	(24,282	)	$	—		$	(24,282	)

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, 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	)
Other comprehensive income (loss) before reclassifications	(5,655		)	—			—			(5,655		)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	9,377			—			317			9,694
Net current-period other comprehensive income (loss)	3,722			—			317			4,039
Balance at December 31, 2016	$	(140,155	)	$	—		$	(5,356	)	$	(145,511	)
Other comprehensive income (loss) before reclassifications	10,200			—			—			10,200
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	8,088			—			317			8,405
Net current-period other comprehensive income (loss)	18,288			—			317			18,605
Balance at December 31, 2017	$	(121,867	)	$	—		$	(5,039	)	$	(126,906	)

Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2017, 2016 and 2015, 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)
		2017			2016			2015
Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost	(a)	$	1,938		$	1,938		$	1,938
Amortization of net gain (loss)	(a)	(675		)	(525		)	(5,397		)
	Total before tax	1,263			1,413			(3,459		)
	Tax (expense) or benefit	(442		)	(495		)	1,211
	Net of Tax	821			918			(2,248		)
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts: Electric derivatives	Purchased electricity	—			—			(512		)
	Tax (expense) or benefit	—			—			179
	Net of Tax	—			—			(333		)
Total reclassification for the period	Net of Tax	$	821		$	918		$	(2,581	)

_______________

^(a) These AOCI components are included in the computation of net periodic pension cost, see Note 12, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details.

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)
		2017			2016			2015
Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost	(a)	$	1,529		$	1,529		$	1,526
Amortization of net gain (loss)	(a)	(13,972		)	(15,955		)	(22,268		)
	Total before tax	(12,443		)	(14,426		)	(20,742		)
	Tax (expense) or benefit	4,355			5,049			7,260
	Net of tax	(8,088		)	(9,377		)	(13,482		)
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts: Electric derivatives	Purchased electricity	—			—			(1,055		)
	Tax (expense) or benefit	—			—			369
	Net of Tax	—			—			(686		)
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	$	(8,405	)	$	(9,694	)	$	(14,485	)

_______________

^(a) These AOCI components are included in the computation of net periodic pension cost, see Note 12, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details.

XML

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY

12 Months Ended

Dec. 31, 2017

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Schedule I: Condensed Financial Information of Puget Energy

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,
	2017			2016			2015
Non-utility expense and other	$	(1,466	)	$	(5,252	)	$	(1,617	)
Other income (deductions):
Equity in earnings of subsidiary	323,568			385,838			309,603
Non-hedged interest rate swap expense	28			(1,062		)	(3,796		)
Interest income	1,039			2			63
Interest expense	(106,072		)	(104,600		)	(100,114		)
Income taxes	(41,903		)	37,973			37,040
Net income (loss)	175,194			312,899			241,179
Comprehensive income (loss)	$	184,624		$	306,453		$	250,956

See accompanying notes to the condensed financial statements.

Puget Energy

Condensed Balance Sheets

(Dollars in Thousands)

	December 31,
	2017		2016
Assets:
Investment in subsidiaries	$	3,721,553	$	3,571,550
Other property and investments:
Goodwill	1,656,513		1,656,513
Current assets:
Cash	751		397
Receivables from affiliates1	78,570		213
Total current assets	79,321		610
Long-term assets:
Deferred income taxes	208,889		309,812
Other	3,196		521
Total long-term assets	212,085		310,333
Total assets	$	5,669,472	$	5,539,006
Capitalization and liabilities:
Common equity	$	3,750,030	$	3,688,713
Long-term debt	1,892,672		1,808,828
Total capitalization	5,642,702		5,497,541
Current liabilities:
Account Payable	1,042		15,801
Interest	25,728		25,523
Unrealized loss on derivative instruments	—		141
Total current liabilities	26,770		41,465
Long-term liabilities:
Total long-term liabilities	—		—
Commitments and contingencies (Note 3)
Total capitalization and liabilities	$	5,669,472	$	5,539,006

_______________

¹  Eliminated in consolidation.

See accompanying notes to the condensed financial statements.

Puget Energy

Condensed Statements of Cash Flows

(Dollars in Thousands)

	Year Ended December 31,
	2017			2016			2015
Operating activities:
Net cash provided by (used in) operating activities	139,005			$	145,719		$	171,576
Investing activities:
Investment in subsidiaries	(24,222		)	—			(28,900		)
(Increase) decrease in loan to subsidiary	(78,155		)	—			28,933
Other	(437		)	(6,078		)	(5,632		)
Net cash provided by (used in) investing activities	(102,814		)	(6,078		)	(5,599		)
Financing activities:
Dividends paid	(123,307		)	(148,965		)	(263,059		)
Issuance of bond	—			—			400,000
Issuance/redemption of term-loan and other long-term debt	90,120			12,480			(299,000		)
Issue costs and others	(2,650		)	(3,398		)	(3,341		)
Net cash provided by (used in) by financing activities	(35,837		)	(139,883		)	(165,400		)
Increase (decrease) in cash	354			(242		)	577
Cash at beginning of year	397			639			62
Cash at end of year	$	751		$	397		$	639

See accompanying notes to the condensed financial statements.

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 regulated subsidiary, PSE. Puget Energy also hasa wholly-owned non-regulated subsidiary, named Puget LNG, LLC (Puget LNG). Puget LNG was formed on November 29, 2016, and has the sole purpose of owning, developing and financing the non-regulated activity of a LNG facility at the Port of Tacoma, Washington. 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 subsidiaries have been included using the equity method, should be read in conjunction with the consolidated financial statements and notes thereto of Puget Energy included in Item 8, "Financial Statements and Supplementary Data" of this Form 10-K. Puget Energy owns 100% of the common stock of its subsidiaries.

Equity earnings of subsidiary included earnings from PSE of $320.1 million, $380.6 million and $304.2 million for the years ended December 31, 2017, 2016 and 2015, respectively, and business combination accounting adjustments under ASC 805 recorded at Puget Energy for PSE of $3.9 million, $5.2 million and $5.4 million for the years ended December 31, 2017, 2016 and 2015, respectively. Investment in subsidiaries includes Puget Energy business combination accounting adjustments under ASC 805 that are recorded at Puget Energy.

(2) Debt

For information concerning Puget Energy’s long-term debt obligations, see Note 6, "Long-Term Debt" to the consolidated financial statements included in Item 8 of this report.

(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 included in Item 8 of this report.

XML

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

12 Months Ended

Dec. 31, 2017

Valuation and Qualifying Accounts [Abstract]

Schedule II: Valuation and Qualifying Accounts and Reserves

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, 2017
Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable	$	9,798	$	26,266	$	27,163	$	8,901
Year Ended December 31, 2016
Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable	$	9,756	$	24,389	$	24,347	$	9,798
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

XML

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Basis of Presentation

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.  Puget Energy also has a wholly-owned non-regulated subsidiary, named Puget LNG, LLC (Puget LNG), formed in 2016, which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNG facility, currently under construction. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that occur under PSE and are allocated to Puget LNG are related party transactions by nature. As of December 31, 2017, Puget LNG has incurred $104.3 million in construction work in progress and operating costs related to Puget LNG’s portion of the Tacoma LNG facility.

The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries.  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 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.

Utility Plant

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 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.

Other Property and Investments

For PSE, the costs of other property and investments (i.e., non-utility) 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.  Replacements 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

Depreciation and Amortization

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 annual depreciation provision stated as a percent of a depreciable electric utility plant was 2.8%, for each of 2017, 2016 and 2015; depreciable natural gas utility plant was 3.4%, for each of 2017, 2016 and 2015; and depreciable common utility plant was 8.3%, 9.7% and 8.5% in 2017, 2016 and 2015, respectively.  The cost of removal is collected from PSE’s customers through depreciation expense and any excess is recorded as a regulatory liability.

Goodwill

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 qualitative and quantitative test.  Management must first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill. If, after assessing the totality of events or circumstances during a qualitative assessment, management determines the fair value of a reporting unit is less than its carrying amount, then the entity shall perform a quantitative test to determine impairment.  This would entail a full valuation of Puget Energy’s assets and liabilities and comparing the valuation to its carrying amounts, with the aggregate difference indicating the amount of impairment.  Goodwill of a reporting unit is required to be tested for impairment on an interim basis if an event occurs or circumstances change that would cause the fair value of a reporting unit to fall below its carrying amount.

Puget Energy conducted its annual impairment test in 2017 using an October 1, 2017 measurement date.  The fair value of Puget Energy’s reporting unit was estimated using a combination of the discounted cash flow and market approach.  The discounted cash flow approach 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, 2017.  There were no known events or circumstances from the date of the assessment through December 31, 2017 that would impact management’s conclusion.

Cash and Cash Equivalents

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 carrying amounts of cash and cash equivalents are reported at cost and approximate fair value, due to the short-term maturity.

Materials and Supplies

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.  The Company records these items at weighted-average cost.

Fuel and Gas Inventory

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.  The Company records these items at the lower of cost or net realizable value method.

Regulatory Assets and Liabilities

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 or losses 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.  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 when amortization periods extend longer than one year.  For further details regarding regulatory assets and liabilities, see Note 3, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.

Allowance for Funds Used During Construction

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; the AFUDC debt portion is credited to interest expense, while the AFUDC equity portion is credited to other income.  Cash inflow related to AFUDC does not occur until these charges are reflected in rates. The current AFUDC rate authorized by the Washington Commission for natural gas and electric utility plant additions through December 18, 2017 was 7.77%. Effective December 19, 2017 with the Washington Commission order, the new AFUDC rate authorized is 7.60%.

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

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).  Revenue from retail sales is billed based on tariff rates approved by the Washington Commission.  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 tariff rate schedule to estimate the unbilled revenues by customer.

PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $257.1 million, $235.3 million and $234.2 million for 2017, 2016 and 2015, 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.

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 and gross margin erosion due to weather and 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. Revenue is recognized under this program when deemed collectible 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. On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. The rate test which limits the amount of revenues PSE can collect in its annual filings increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The Company will not record any decoupling revenue that is expected to take longer than 24 months to collect following the end of the annual period in which the revenues would have otherwise been recognized. Once determined to be collectible within 24 months, any previously non-recognized amounts will be recognized. 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

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 balance for allowance for doubtful accounts at December 31, 2017 and 2016 was $8.9 million and $9.8 million, respectively.

Self Insurance

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.  Under the December 5, 2017 Washington Commission order regarding PSE’s GRC, the cumulative annual cost threshold for deferral of storms under the mechanism increased from $8.0 million to $10.0 million effective January 1, 2018.  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

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, which is the ultimate tax payer.

Natural Gas Off System Sales and Capacity Release

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.

Non-Core 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 electric operating revenue and are included in the PCA mechanism.

Production Tax Credit

Production Tax Credit

Production Tax Credits (PTCs) represent federal income tax incentives available to taxpayers that generate energy from qualifying renewable sources during the first ten years of operation. From a regulatory perspective, the tax savings from these credits were intended to be refunded by PSE to its customers when monetized on the income tax return through its revenue requirement as initially approved by the Washington Commission. As the Company has not generated taxable income and these credits have not been monetized, they have not been refunded to customers. Amounts to be refunded have been recorded as a liability with an offsetting reduction to revenue as it was intended to be refunded through the revenue requirement. A deferred tax asset and reduction to deferred tax expense was also recorded for PTCs not yet monetized. These entries resulted in no net income impact. In connection with the GRC settlement in 2017, the Washington Commission authorized the Company to utilize the tax savings associated with the monetization of the PTCs to fund the following: (i) Colstrip Community Transition Fund, (ii) unrecovered Colstrip plant and (iii) incurred decommissioning and remediation costs for Colstrip. As PTCs will no longer be refunded to customers through the revenue requirement, a non-cash charge to revenue and deferred tax expense will be recorded as the PTCs are monetized. These entries will result in no net income impact. At December 31, 2017 $2.1 million of PTCs are estimated to be monetized through tax filings.

Accounting for Derivatives

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 natural gas related derivatives 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 its financial reporting.  The contracts that were de-designated related to physical electric supply contracts and natural gas swap contracts used to fix the price of natural gas for electric generation.  For these contracts and for contracts initiated after such date, all mark-to-market adjustments are recognized through earnings.  The amount previously recorded in accumulated other comprehensive income (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, 2017, 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" to the consolidated financial statements included in Item 8 of this report.

Fair Value Measurements of Derivatives

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" to the consolidated financial statements included in Item 8 of this report.

Debt Related Costs

Debt Related Costs

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

XML

Regulation and Rates (Tables)

12 Months Ended

Dec. 31, 2017

Regulation and Rates [Line Items]

Schedule of Net Regulatory Assets and Liabilities

The net regulatory assets and liabilities at December 31, 2017 and 2016 included the following:

Puget Sound Energy	Remaining Amortization Period	December 31,
(Dollars in Thousands)		2017					2016
Storm damage costs electric	4 to 6 years			128,508					122,709
Colstrip 1 & 2 Regulatory Asset	N/A			127,627					176,804
Decoupling deferrals and interest		98,769					156,408
Decoupling 24-month revenue reserve		—					(20,847	)
Total decoupling asset	Less than 2 years			98,769					135,561
Chelan PUD contract initiation	13.8 years			98,052					105,140
Environmental remediation	(a)			81,550					74,557
Lower Snake River	19.4 years			70,975					74,862
Baker Dam licensing operating and maintenance costs	N/A			54,817					61,453
Deferred Washington Commission AFUDC	10 years			50,301					51,404
Unamortized loss on reacquired debt	1 to 28 years			39,674					42,196
Property tax tracker	Less than 2 years			36,517					41,949
Energy conservation costs	(a)			35,538					41,027
PGA deferral of unrealized losses on derivative instruments	N/A			26,030					—
White River relicensing and other costs	3 years			19,502					21,627
Generation plant major maintenance, excluding Colstrip	5 to 11 years			17,216					13,178
Mint Farm ownership and operating costs	7.3 years			14,319					16,319
Colstrip major maintenance	1.5 years			8,723					6,589
Snoqualmie licensing operating and maintenance costs	N/A			7,341					8,018
Ferndale	1.8 years			7,295					11,274
Colstrip common property	7.4 years			4,618					5,334
PCA mechanism	N/A			4,576					4,531
Electron unrecovered loss	1 year			3,786					7,178
Deferred income taxes(d)	N/A			—					71,517
PGA receivable	1 year			—					2,785
Various other regulatory assets	(a)			17,382					17,173
Total PSE regulatory assets				953,116					1,113,185
Deferred income taxes(d)	N/A			(1,012,260		)			—
Cost of removal	(b)			(389,579		)			(369,300		)
Treasury grants	20 years			(205,775		)			(133,709		)
Production tax credits	(c)			(93,616		)			(93,616		)
Decoupling ROR excess earnings		(18,400	)				(13,300	)
Decoupling deferrals and interest		(7,896	)				(16,448	)
Total decoupling liability	Less than 2 years			(26,296		)			(29,748		)
PGA payable	1 year			(16,051		)			—
Summit purchase option buy-out	2.8 years			(4,463		)			(6,038		)
PGA deferral of unrealized gains on derivative instruments	N/A			—					(7,517		)
Various other regulatory liabilities	(a)			(10,544		)			(13,368		)
Total PSE regulatory liabilities				(1,758,584		)			(653,296		)
PSE net regulatory assets (liabilities)				$	(805,468	)			$	459,889

_______________

^(a)  Amortization periods vary depending on timing of underlying transactions.

^(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.

^(d)  For additional information, see Note 13,"Income Taxes" to the consolidated financial statements included in Item 8 of this report.

Puget Energy	Remaining Amortization Period	December 31,
(Dollars in Thousands)		2017			2016
Total PSE regulatory assets	(a)	$	953,116		$	1,113,185
Puget Energy acquisition adjustments:
Regulatory assets related to power contracts	1 to 20 years	19,454			22,613
Various other regulatory assets	Varies	(8		)	517
Total Puget Energy regulatory assets		972,562			1,136,315
Total PSE regulatory liabilities	(a)	(1,758,584		)	(653,296		)
Puget Energy acquisition adjustments:
Deferred income taxes		634			—
Regulatory liabilities related to power contracts	1 to 35 years	(174,918		)	(275,061		)
Various other regulatory liabilities	Varies	(1,314		)	(1,326		)
Total Puget Energy regulatory liabilities		(1,934,182		)	(929,683		)
Puget Energy net regulatory asset (liabilities)		$	(961,620	)	$	206,632

_______________

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

XML

Utility Plant (Tables)

12 Months Ended

Dec. 31, 2017

Utility Plant [Abstract]

Schedule of Utility Plant

		Puget Energy						Puget Sound Energy
Utility Plant	Estimated Useful Life	At December 31,						At December 31,
(Dollars in Thousands)	(Years)	2017			2016			2017			2016
Distribution plant	20-65	$	5,670,351		$	5,287,542		$	7,289,998		$	6,922,176
Production plant	12-90	3,068,135			3,007,546			3,954,057			3,910,129
Transmission plant	43-75	1,361,495			1,307,687			1,471,337			1,420,334
General plant	5-75	586,226			541,424			628,179			611,237
Intangible plant (including capitalized software)	NA	447,568			347,697			438,185			338,327
Plant acquisition adjustment	NA	242,826			242,826			282,792			282,792
Underground storage	25-60	31,815			30,695			45,288			44,206
Liquefied natural gas storage	25-60	12,628			12,628			14,498			14,498
Plant held for future use	NA	53,428			52,484			53,580			52,636
Recoverable Cushion Gas	NA	8,655			8,655			8,655			8,655
Plant not classified	1-125	275,014			159,345			275,014			159,345
Grant	NA	—			(99,100		)	—			(99,100		)
Capital leases, net of accumulated amortization1	4-6	1,129			645			1,129			645
Less: accumulated provision for depreciation		(2,428,524		)	(2,161,796		)	(5,131,966		)	(4,927,602		)
Subtotal		$	9,330,746		$	8,738,278		$	9,330,746		$	8,738,278
Construction work in progress	NA	495,937			420,278			495,937			420,278
Net utility plant		$	9,826,683		$	9,158,556		$	9,826,683		$	9,158,556

_______________

¹  Accumulated amortization of capital leases at Puget Energy and PSE was $0.7 million in 2017 and $0.6 million in 2016.

Schedule of Jointly Owned Utility Plants

These amounts are also included in the Utility Plant table above. The Company's share of fuel costs and operating expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income.

Puget Energy
Jointly Owned Generating Plants (Dollars in Thousands)	Energy Source (Fuel)	Company’s Ownership Share	Plant in Service at Cost		Construction Work in Progress			Accumulated Depreciation
Colstrip Units 1 & 2	Coal	50.0%	$	246,510	$	(23	)	$	(38,170	)
Colstrip Units 3 & 4	Coal	25.0%	307,254		1,726			(71,061		)
Colstrip Units 1 – 4 Common Facilities	Coal	various	83		—			(31		)
Frederickson 1	Natural Gas	49.85%	61,783		—			(3,850		)
Jackson Prairie	Natural Gas Storage	33.34%	31,141		43			(6,325		)

Puget Sound Energy
Jointly Owned Generating Plants (Dollars in Thousands)	Energy Source (Fuel)	Company’s Ownership Share	Plant in Service at Cost		Construction Work in Progress			Accumulated Depreciation
Colstrip Units 1 & 2	Coal	50.0%	$	378,574	$	(23	)	$	(170,234	)
Colstrip Units 3 & 4	Coal	25.0%	571,604		1,726			(335,414		)
Colstrip Units 1 – 4 Common Facilities	Coal	various	252		—			(199		)
Frederickson 1	Natural Gas	49.85%	67,851		—			(9,917		)
Jackson Prairie	Natural Gas Storage	33.34%	45,288		43			(20,471		)
Tacoma LNG	LNG	43.0%	2,667		87,207			—

Schedule of Asset Retirement Obligations

The following table describes the changes to the Company’s ARO for the year ended December 31, 2017:

Puget Energy and Puget Sound Energy	At December 31,
(Dollars in Thousands)	2017			2016
Asset retirement obligation at beginning of the period	$	200,345		$	85,028
New asset retirement obligation recognized in the period1	2,881			—
Liability adjustments	(3,841		)	(411		)
Revisions in estimated cash flows	(13,748		)	113,081
Accretion expense	5,539			2,647
Asset retirement obligation at end of period1	$	191,176		$	200,345

_______________

^{1  New asset retirement obligations include $2.2 million ARO for Puget LNG only held at Puget Energy.} 

XML

Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2017

Debt Instrument [Line Items]

Schedule of Long-Term Debt Instruments

Long-Term Debt

The following table presents outstanding long-term debt principal amounts and due dates as of 2017 and 2016:

(Dollars in Thousands)			At December 31,
Series	Type	Due	2017			2016
Puget Sound Energy:
6.740%	Senior Secured Note1	2018	$	200,000		$	200,000
5.500%	Promissory Note2	2020	2,412			2,412
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			425,000
4.700%	Senior Secured Note	2051	45,000			45,000
6.974%	Junior Subordinated Note	2067	250,000			250,000
*	Debt discount, issuance cost and other	*	(26,361		)	(28,974		)
Total PSE long-term debt			3,749,911			3,747,298
Puget Energy:
*	Fair value adjustment of PSE long-term debt	*	(190,895		)	(199,436		)
*	Revolving Credit Agreement	2022	102,600			12,480
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			400,000
*	Debt discount, issuance cost and other	*	(3,687		)	(6,269		)
Total Puget Energy long-term debt			$	5,457,929		$	5,354,073

_______________

* Not Applicable.

¹  6.74% Senior Secured Note in the amount of $200.0 million is classified on the Balance Sheet as a current maturity of long-term debt as of June 15, 2017.

²  5.50% Promissory Note (Puget Western Note Payable) in the amount of $2.4 million was classified on the Balance Sheet as a current maturity of long-term debt from January 1, 2017 to August 13, 2017, at which time the agreement was amended and extended until August 13, 2020. The Promissory Note is currently classified as long-term debt on the Balance sheet as of September 1, 2017.

Schedule of Maturities of Long-Term Debt

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

(Dollars in Thousands)	2018		2019		2020		2021		2022		Thereafter		Total
Maturities of:
PSE	$	200,000	$	—	$	2,412	$	—	$	—	$	3,573,860	$	3,776,272
Puget Energy	—		—		450,000		500,000		552,600		400,000		1,902,600
Total long-term debt	$	200,000	$	—	$	452,412	$	500,000	$	552,600	$	3,973,860	$	5,678,872

XML

Leases (Tables)

12 Months Ended

Dec. 31, 2017

Leases [Abstract]

Schedule of Operating Lease Expense

Operating lease expenses net of sublease receipts were:

(Dollars in Thousands)
At December 31,	Operating Lease Expense
Years
2017	$	35,198
2016	31,786
2015	27,843

Schedule of Future Minimum Lease Payments for Non-cancellable Leases

:

(Dollars in Thousands)	Future Minimum Lease Payments
At December 31,
Years	Operating		Capital
2018	$	21,371	$	527
2019	19,077		306
2020	17,507		232
2021	9,137		97
2022	6,747		—
Thereafter	97,974		—
Total minimum lease payments	$	171,813	$	1,162

XML

Accounting for Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2017

Derivative [Line Items]

Schedule of Credit Risk Related Contingent Features [Table Text Block]

The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post:

Puget Energy and Puget Sound Energy	At December 31,
(Dollars in Thousands)	2017						2016
Contingent Feature	Fair Value1 Liability		Posted Collateral		Contingent Collateral		Fair Value1 Liability		Posted Collateral		Contingent Collateral
Credit rating2	$	3,187	$	—	$	3,187	$	4,894	$	—	$	4,894
Requested credit for adequate assurance	37,374		—		—		7,427		—		—
Forward value of contract3	353		2,639		—		507		—		—
Total	$	40,914	$	2,639	$	3,187	$	12,828	$	—	$	4,894

_______________

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

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

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

Offsetting Assets and Liabilities [Table Text Block]

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, 2017
(Dollars in Thousands)	Gross Amounts Recognized in the Statement of Financial Position 1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
							Commodity Contracts			Cash Collateral Received/Posted			Net Amount
Assets:
Energy derivative contracts	$	24,405	$	—	$	24,405	$	(17,940	)	$	—		$	6,465
Liabilities:
Energy derivative contracts	86,094		—		86,094		(17,940		)	(353		)	67,801
Puget Energy and Puget Sound Energy
At December 31, 2016
(Dollars in Thousands)	Gross Amounts Recognized in the Statement of Financial Position 1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
							Commodity Contracts			Cash Collateral Received/Posted			Net Amount
Assets:
Energy derivative contracts	$	63,079	$	—	$	63,079	$	(42,858	)	$	—		$	20,221
Liabilities:
Energy derivative contracts	60,430		—		60,430		(42,858		)	—			17,572
Interest rate swaps2	141		—		141		—			—			141

_______________

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 and matured in January 2017

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

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

Puget Energy and Puget Sound Energy	At Year Ended December 31,
(Dollars in Thousands)	Volumes (millions)		Assets1				Liabilities²
	2017	2016	2017		2016		2017		2016
Interest rate swap derivatives3	$0.0	$450.0	$	—	$	—	$	—	$	141
Electric portfolio derivatives	*	*	13,391		36,460		49,050		41,329
Natural gas derivatives (MMBtus)4	332.1	336.4	11,014		26,619		37,044		19,101
Total derivative contracts			$	24,405	$	63,079	$	86,094	$	60,571
Current			$	22,247	$	54,341	$	64,859	$	44,310
Long-term			2,158		8,738		21,235		16,261
Total derivative contracts			$	24,405	$	63,079	$	86,094	$	60,571

_______________

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

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

³  Interest rate swap contracts are only held at Puget Energy and matured in January 2017.

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.

^*  Electric portfolio derivatives consist of electric generation fuel of 166.8 million One Million British Thermal Units (MMBtus) and purchased electricity of2.9 million megawatt hours (MWhs) at December 31, 2017 and 186.8 million MMBtus and 3.6 million MWhs at December 31, 2016.

Parent Company [Member]

Derivative [Line Items]

Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance [Table Text Block]

The following tables present the effect and locations of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income:

Puget Energy		Year Ended December 31,
(Dollars in Thousands)	Location	2017			2016			2015
Interest rate contracts:
	Non-hedged interest rate swap (expense) income	$	28		$	(1,062	)	$	(3,796	)
	Interest expense	—			—			560
Gas for Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	(32,492		)	62,318			(9,315		)
Realized	Electric generation fuel	(23,195		)	(39,656		)	(44,648		)
Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net1	1,702			21,477			22,548
Realized	Purchased electricity	(17,873		)	(21,998		)	(39,137		)
Total gain (loss) recognized in income on derivatives		$	(71,830	)	$	21,079		$	(73,788	)

Subsidiaries [Member]

Derivative [Line Items]

Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance [Table Text Block]

Puget Sound Energy		Year Ended December 31,
(Dollars in Thousands)	Location	2017			2016			2015
Gas for Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	$	(32,492	)	$	62,318		$	(9,315	)
Realized	Electric generation fuel	(23,195		)	(39,656		)	(44,648		)
Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net1	1,702			21,477			22,003
Realized	Purchased electricity	(17,873		)	(21,998		)	(39,137		)
Total gain (loss) recognized in income on derivatives		$	(71,858	)	$	22,141		$	(71,097	)

_______________

¹  Differences between Puget Energy and PSE for the twelve months ended December 31, 2015 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.

XML

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2017

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value Inputs, Liabilities, Quantitative Information

Puget Energy		At December 31, 2017				At December 31, 2016
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	238,935	$	250,000	$	210,261
Long-term debt (fixed-rate), net of discount1	2	5,105,329		6,520,515		5,091,593		6,337,287
Long-term debt (variable-rate)	2	102,600		102,600		12,480		12,480
Total		$	5,457,929	$	6,862,050	$	5,354,073	$	6,560,028
Puget Sound Energy		At December 31, 2017				At December 31, 2016
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	238,935	$	250,000	$	210,261
Long-term debt (fixed-rate), net of discount2	2	3,499,911		4,550,130		3,497,298		4,360,783
Total		$	3,749,911	$	4,789,065	$	3,747,298	$	4,571,044

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

Puget Energy and Puget Sound Energy	Year Ended December 31,
Level 3 Roll-Forward Net (Liability)	2017									2016									2015
(Dollars in Thousands)	Electric			Gas			Total			Electric			Gas			Total			Electric			Gas			Total
Balance at beginning of period	$	972		$	625		$	1,597		$	(7,345	)	$	(2,383	)	$	(9,728	)	$	(12,062	)	$	(2,040	)	$	(14,102	)
Changes during period
Realized and unrealized energy derivatives:
Included in earnings1	2,781			—			2,781			4,007			—			4,007			(6,432		)	—			(6,432		)
Included in regulatory assets / liabilities	—			6,346			6,346			—			4,312			4,312			—			3,695			3,695
Settlements2	(6,549		)	(6,372		)	(12,921		)	(1,129		)	(2,679		)	(3,808		)	902			(3,885		)	(2,983		)
Transferred into Level 3	523			(553		)	(30		)	(3,021		)	—			(3,021		)	(787		)	—			(787		)
Transferred out Level 3	3,371			1,877			5,248			8,460			1,375			9,835			11,034			(153		)	10,881
Balance at end of period	$	1,098		$	1,923		$	3,021		$	972		$	625		$	1,597		$	(7,345	)	$	(2,383	)	$	(9,728	)

_______________

¹  Income Statement classification: 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 $1.5 million, $2.0 million and $(7.4) million for the years ended December 31, 2017, 2016 and 2015, respectively.

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

Fair Value Inputs, Assets and Liabilities, Quantitative Information [Table Text Block]

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 2017 and 2016, Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets.

Below are the forward price ranges for the Company's commodity contracts, as of December 31, 2017:

Puget Energy and Puget Sound Energy	Fair Value				Range
(Dollars in Thousands)	Assets1	Liabilities1	Valuation Technique	Unobservable Input	Low	High	Weighted Average
Electric	$3,525	$2,427	Discounted cash flow	Power Prices (per MWh)	$7.02	$28.94	$18.61
Natural gas	$4,041	$2,118	Discounted cash flow	Natural Gas Prices (per MMBtu)	$1.22	$2.80	$1.54

_______________

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, 2017, 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 $0.9 million.

Below are significant unobservable inputs used in estimating the impaired long term power purchase contracts' fair value in 2017 and 2016:

Puget Energy
Valuation Date	Contract	Unobservable Input	Low	High	Average
September 30, 2017	Wells Hydro	Power prices (per MWh)	14.06	26.86	22.24
		Power contract costs per quarter (in thousands)	4,126	4,126	4,126
March 31, 2017	Wells Hydro	Power prices (per MWh)	8.76	26.70	20.86
		Power contract costs per quarter (in thousands)	3,965	4,223	4,051
	Rocky Reach	Power prices (per MWh)	8.53	48.21	27.69
		Power contract costs per quarter (in thousands)	5,827	6,780	6,150
	Priest Rapids RP	Power prices (per MWh)	13.70	29.38	23.14
		Power contract costs per year (in thousands)	620	4,022	2,306
September 30, 2016	Priest Rapids RP	Power prices (per MWh)	24.24	58.96	39.31
		Power contract costs per year (in thousands)	618	4,633	2,472
March 31, 2016	Wells Hydro	Power prices (per MWh)	9.46	25.96	21.38
		Power contract costs per quarter (in thousands)	4,100	4,659	4,452

Schedule of Impaired Intangible Assets [Table Text Block]

n 2017 and 2016, due to continued decreases in forward power prices and decreases in forecasted revenue and cost estimates, the following impairments were recorded to the Company's intangible asset contracts, with corresponding reductions to the regulatory liability as follows:

Puget Energy
(Dollars in Thousands)
Valuation Date	Contract Name	Carrying Value		Fair Value		Write Down
September 30, 2017	Wells Hydro	$	10,621	$	9,609	$	1,012
March 31, 2017	Wells Hydro	14,879		13,067		1,812
	Rocky Reach	235,331		159,818		75,513
	Priest Rapids RP	5,665		2,657		3,008
Total 2017 Impairments						$	81,345
September 30, 2016	Priest Rapids RP	$	18,969	$	6,191	$	12,778
March 31, 2016	Wells Hydro	25,193		19,855		5,338
Total 2016 Impairments						$	18,116

Fair Value, Measurements, Recurring

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Schedule of Fair Value, Assets and Liabilities Measured on 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 and Puget Sound Energy	Fair Value						Fair Value
	At December 31, 2017						At December 31, 2016
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	9,866	$	3,525	$	13,391	$	30,666	$	5,794	$	36,460
Natural gas derivative instruments	6,973		4,041		11,014		23,316		3,303		26,619
Total derivative assets	$	16,839	$	7,566	$	24,405	$	53,982	$	9,097	$	63,079
Liabilities:
Interest rate derivative instruments1	$	—	$	—	$	—	$	141	$	—	$	141
Electric derivative instruments	46,623		2,427		49,050		36,507		4,822		41,329
Natural gas derivative instruments	34,926		2,118		37,044		16,423		2,678		19,101
Total derivative liabilities	$	81,549	$	4,545	$	86,094	$	53,071	$	7,500	$	60,571

XML

Retirement Benefits (Tables)

12 Months Ended

Dec. 31, 2017

Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]

Schedule of Changes in Projected Benefit Obligations

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, 2017 and 2016:

Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2017			2016			2017			2016			2017			2016
Change in benefit obligation:
Benefit obligation at beginning of period	$	652,607		$	643,088		$	51,734		$	51,279		$	11,194		$	13,946
Service cost	20,081			18,913			913			1,085			72			93
Interest cost	28,373			28,689			2,285			2,325			500			533
Actuarial loss (gain)	40,945			1,545			2,722			106			725			(2,262		)
Benefits paid	(40,594		)	(38,730		)	(1,900		)	(3,061		)	(1,137		)	(1,264		)
Medicare part D subsidy received	—			—			—			—			100			148
Administrative expense	(931		)	(898		)	—			—			—			—
Benefit obligation at end of period	$	700,481		$	652,607		$	55,754		$	51,734		$	11,454		$	11,194

Schedule of Changes in Fair Value of Plan Assets

Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2017			2016			2017			2016			2017			2016
Change in plan assets:
Fair value of plan assets at beginning of period	$	620,260		$	598,865		$	—		$	—		$	7,200		$	7,203
Actual return on plan assets	107,836			37,022			—			—			784			926
Employer contribution	18,000			24,000			1,900			3,061			291			335
Benefits paid	(40,594		)	(38,730		)	(1,900		)	(3,061		)	(1,137		)	(1,264		)
Administrative expense	(1,142		)	(897		)	—			—			—			—
Fair value of plan assets at end of period	$	704,360		$	620,260		$	—		$	—		$	7,138		$	7,200
Funded status at end of period	$	3,879		$	(32,347	)	$	(55,754	)	$	(51,734	)	$	(4,316	)	$	(3,994	)

Schedule of Amounts Recognized in Balance Sheet and Accumulated Other Comprehensive Income

Puget Energy and Puget Sound Energy	Qualified Pension Benefits					SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2017		2016			2017			2016			2017			2016
Amounts recognized in Statement of Financial Position consist of:
Noncurrent assets	$	3,879	$	—		$	—		$	—		$	—		$	—
Current liabilities	—		—			(5,486		)	(1,911		)	(317		)	(325		)
Noncurrent liabilities	—		(32,347		)	(50,268		)	(49,823		)	(3,999		)	(3,669		)
Net assets (liabilities)	$	3,879	$	(32,347	)	$	(55,754	)	$	(51,734	)	$	(4,316	)	$	(3,994	)

Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets [Table Text Block]

Puget Energy and Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2017		2016		2017		2016		2017		2016
Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets:
Projected benefit obligation	$	700,481	$	652,607	$	55,754	$	51,734	$	11,454	$	11,194
Accumulated benefit obligation	688,908		641,855		52,681		47,639		11,367		11,092
Fair value of plan assets	704,360		620,260		—		—		7,138		7,200

Schedule of Net Benefit Costs

The following tables summarize Puget Energy's and PSE's net periodic benefit cost for the years ended December 31, 2017, 2016 and 2015:

Puget Energy	Qualified Pension Benefits									SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2017			2016			2015			2017		2016		2015		2017			2016			2015
Components of net periodic benefit cost:
Service cost	$	20,081		$	18,913		$	21,287		$	913	$	1,085	$	1,108	$	72		$	93		$	112
Interest cost	28,373			28,689			28,088			2,285		2,325		2,281		500			533			621
Expected return on plan assets	(47,784		)	(46,619		)	(45,038		)	—		—		—		(461		)	(446		)	(531		)
Amortization of prior service cost (credit)	(1,980		)	(1,980		)	(1,980		)	42		42		42		—			—			—
Amortization of net loss (gain)	—			—			3,887			1,077		911		1,641		(402		)	(386		)	(130		)
Net periodic benefit cost	$	(1,310	)	$	(997	)	$	6,244		$	4,317	$	4,363	$	5,072	$	(291	)	$	(206	)	$	72

Schedule of Amounts Recognized in Other Comprehensive Income (Loss)

The following tables summarize Puget Energy's and PSE's benefit obligations recognized in other comprehensive income (OCI) for the years ended December 31, 2017 and 2016:

Puget Energy	Qualified Pension Benefits					SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2017			2016		2017			2016			2017		2016
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	$	(18,896	)	$	11,141	$	2,722		$	106		$	403	$	(2,742	)
Amortization of net (loss) gain	—			—		(1,076		)	(910		)	401		385
Amortization of prior service (cost) credit	1,980			1,980		(42		)	(42		)	—		—
Total change in other comprehensive income for year	$	(16,916	)	$	13,121	$	1,604		$	(846	)	$	804	$	(2,357	)

Schedule of Assumptions Used

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	2017		2016		2015		2017		2016		2015		2017		2016		2015
Discount rate	4.00	%	4.50	%	4.65	%	4.00	%	4.50	%	4.65	%	4.00	%	4.50	%	4.65	%
Rate of compensation increase	4.50		4.50		4.50		4.50		4.50		4.50		4.50		4.50		4.50
Medical trend rate	—		—		—		—		—		—		6.80		8.80		7.20
Benefit Cost Assumptions
Discount rate	4.50	%	4.65	%	4.25	%	4.50	%	4.65	%	4.25	%	4.50	%	4.65	%	4.25	%
Return on plan assets	7.45		7.75		7.75		—		—		—		6.75		6.75		7.00
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	—		—		—		—		—		—		9.50		5.30		7.20

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates

The assumed medical inflation rate used to determine benefit obligations is 6.80% in 2018 grading down to 4.10% in 2019.  A 1.0% change in the assumed medical inflation rate would have the following effects:

	2017					2016
(Dollars in Thousands)	1% Increase		1% Decrease			1% Increase		1% Decrease
Effect on post-retirement benefit obligation	$	23	$	(22	)	$	38	$	(35	)
Effect on service and interest cost components	1		(1		)	2		(2		)

Schedule of Expected Benefit Payments

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)	2018		2019		2020		2021		2022		2023-2027
Qualified Pension total benefits	$	42,600	$	43,400	$	44,800	$	45,700	$	46,900	$	246,500
SERP Pension total benefits	5,486		6,001		4,684		1,728		4,577		37,394
Other Benefits total with Medicare Part D subsidy	911		885		852		811		863		3,748
Other Benefits total without Medicare Part D subsidy	1,172		1,155		1,131		1,097		1,070		4,844

Schedule of Allocation of Plan Assets

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	—		9		15
Non-U.S. equity	10		25		30
Fixed income	15		25		30
Real estate	—		—		10
Absolute return	5		10		15
Cash	—		—		5

The following table sets forth by level, within the fair value hierarchy, the qualified pension plan as of December 31, 2017 and 2016:

	Recurring Fair Value Measures						Recurring Fair Value Measures
	As of December 31, 2017						As of December 31, 2016
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Mutual Funds	$	117,796	$	—	$	117,796	$	181,212	$	—	$	181,212
Common Stock	209,504		—		209,504		154,255		—		154,255
Government Securities	18,316		23,782		42,098		18,754		16,197		34,951
Corporate Bonds	—		34,588		34,588		—		38,543		38,543
Cash and cash equivalents	2,684		9,304		11,988		—		—		—
Subtotal	$	348,300	$	67,674	415,974		$	354,221	$	54,740	408,961
Investments measured at NAV1					237,427						222,819
Net (payable) receivable					50,959						(9,894		)
Total assets					$	704,360					$	621,886

_______________

¹  In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments that were measured at NAV per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV primarily consist of common/collective trust funds and two partnerships held as of December 31, 2017.

Mesirow Institutional Multi-Strategy Fund Partnership, L.P. utilizes a combination of long and short strategies through investments in investment funds. The major strategy allocations of the investment funds include (1) Investments in debt obligations of public and private entities; typically, in financial duress, and (2) Investments in equity positions on a global basis utilizing fundamental analysis.

Grosvenor Institutional Partners Fund, L.P invests substantially all of the fund assets available in the Grosvenor Master Fund, a Cayman Islands exempted company which is sponsored, managed and has the same investment objective as the Partnership fund. In addition to the Master Fund, investments are made primarily in offshore investment funds, investment partnerships, and pooled investment vehicles; collectively referred to as Portfolio Funds, which generally implement "nontraditional" or "alternative" investment strategies.

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, 2017						As of December 31, 2016
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Mutual fund1	$	7,089	$	—	$	7,089	$	7,182	$	—	$	7,182
Investments measured at NAV2					49						80
Total assets					$	7,138					$	7,262

_______________

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, 2017.

²  In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments that were measured at NAV per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV consist of a common/collective trust fund as of December 31, 2017.

Parent Company [Member]

Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]

Schedule of Amounts Recognized in Balance Sheet and Accumulated Other Comprehensive Income

The following tables summarize Puget Energy's and PSE's pension benefit amounts recognized in AOCI for the years ended December 31, 2017 and 2016:

Puget Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2017			2016			2017		2016		2017			2016
Amounts recognized in Accumulated Other Comprehensive Income consist of:
Net loss (gain)	$	37,693		$	56,588		$	10,689	$	9,043	$	(3,386	)	$	(4,190	)
Prior service cost (credit)	(7,843		)	(9,822		)	204		246		—			—
Total	$	29,850		$	46,766		$	10,893	$	9,289	$	(3,386	)	$	(4,190	)

Subsidiaries [Member]

Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]

Schedule of Amounts Recognized in Balance Sheet and Accumulated Other Comprehensive Income

Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2017			2016			2017		2016		2017			2016
Amounts recognized in Accumulated Other Comprehensive Income consist of:
Net loss (gain)	$	185,277		$	217,143		$	13,134	$	11,978	$	(4,901	)	$	(5,994	)
Prior service cost (credit)	(6,232		)	(7,806		)	208		251		—			—
Total	$	179,045		$	209,337		$	13,342	$	12,229	$	(4,901	)	$	(5,994	)

Schedule of Net Benefit Costs

Puget Sound Energy	Qualified Pension Benefits									SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2017			2016			2015			2017		2016		2015		2017			2016			2015
Components of net periodic benefit cost:
Service cost	$	20,081		$	18,913		$	21,287		$	913	$	1,085	$	1,108	$	72		$	93		$	112
Interest cost	28,373			28,689			28,088			2,285		2,325		2,281		500			533			621
Expected return on plan assets	(47,862		)	(46,814		)	(45,462		)	—		—		—		(461		)	(446		)	(531		)
Amortization of prior service cost (credit)	(1,573		)	(1,573		)	(1,573		)	44		44		44		—			—			3
Amortization of net loss (gain)	13,048			15,257			20,555			1,565		1,330		2,120		(641		)	(632		)	(406		)
Net periodic benefit cost	$	12,067		$	14,472		$	22,895		$	4,807	$	4,784	$	5,553	$	(530	)	$	(452	)	$	(201	)

Schedule of Amounts Recognized in Other Comprehensive Income (Loss)

Puget Sound Energy	Qualified Pension Benefit						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2017			2016			2017			2016			2017		2016
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	$	(18,817	)	$	11,336		$	2,722		$	106		$	452	$	(2,742	)
Amortization of net (loss) gain	(13,048		)	(15,257		)	(1,565		)	(1,330		)	641		631
Amortization of prior service (cost) credit	1,573			1,573			(44		)	(44		)	—		—
Total change in other comprehensive income for year	$	(30,292	)	$	(2,348	)	$	1,113		$	(1,268	)	$	1,093	$	(2,111	)

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2017

Income Tax Disclosures [Line Items]

Schedule of Components of Income Tax Expense (Benefit)

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

Puget Energy	Year Ended December 31,
(Dollars in Thousands)	2017			2016			2015
Charged to operating expenses:
Current:
Federal	$	1,127		$	—		$	—
State	17			20			—
Deferred:
Federal	254,420			140,315			91,968
State	(421		)	(131		)	(192		)
Total income tax expense	$	255,143		$	140,204		$	91,776

Schedule of Effective Income Tax Rate Reconciliation

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)	2017			2016			2015
Income taxes at the statutory rate	$	148,847		$	158,586		$	116,534
Increase (decrease):
Production tax credit1	—			(12,925		)	(19,470		)
Utility plant differences	—			3,966			5,671
Treasury grant amortization	(9,537		)	(9,788		)	(8,807		)
Tax reform	117,185			—			—
Other - net	(1,352		)	365			(2,152		)
Total income tax expense	$	255,143		$	140,204		$	91,776
Effective tax rate	60.0		%	30.9		%	27.6		%

Schedule of Deferred Tax Assets and Liabilities

The Company’s net deferred tax liability at December 31, 2017 and 2016 is composed of amounts related to the following types of temporary differences:

Puget Energy	At December 31,
(Dollars in Thousands)	2017			2016
Utility plant and equipment	$	2,034,328		$	1,880,782
Regulatory asset for income taxes	—			72,038
Fair value of debt instruments	38,777			67,444
Pensions and other compensation	46,338			77,230
Other deferred tax liabilities	86,933			119,050
Subtotal deferred tax liabilities	2,206,376			2,216,544
Net operating loss carryforward	(212,168		)	(352,827		)
Net regulatory liability for income taxes	(1,011,626		)	—
Production tax credit carryforward	(187,617		)	(190,999		)
Regulatory liability on production tax credit	(49,873		)	(101,787		)
Net other deferred tax assets	1,776			—
Subtotal deferred tax assets	(1,459,508		)	(645,613		)
Total net deferred tax liabilities	$	746,868		$	1,570,931

Subsidiaries [Member]

Income Tax Disclosures [Line Items]

Schedule of Components of Income Tax Expense (Benefit)

Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	2017		2016		2015
Charged to operating expenses:
Current:
Federal	$	1,127	$	—	$	—
State	17		20		—
Deferred:
Federal	210,842		175,327		125,900
State	—		—		—
Total income tax expense	$	211,986	$	175,347	$	125,900

Schedule of Effective Income Tax Rate Reconciliation

Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	2017			2016			2015
Income taxes at the statutory rate	$	185,430		$	194,572		$	150,531
Increase (decrease):
Production tax credit1	—			(12,925		)	(19,470		)
Utility plant differences	—			3,966			5,671
Treasury grant amortization	(9,537		)	(9,788		)	(8,807		)
Tax reform	36,328			—			—
Other - net	(235		)	(478		)	(2,025		)
Total income tax expense	$	211,986		$	175,347		$	125,900
Effective tax rate	40.0		%	31.5		%	29.3		%

Schedule of Deferred Tax Assets and Liabilities

Puget Sound Energy	At December 31,
(Dollars in Thousands)	2017			2016
Utility plant and equipment	$	2,034,328		$	1,880,782
Regulatory asset for income taxes	—			71,517
Other, net deferred tax liabilities	86,933			113,938
Subtotal deferred tax liabilities	2,121,261			2,066,237
Net regulatory liability for income taxes	(1,012,260		)	—
Net operating loss carryforward	—			(41,061		)
Production tax credit carryforward	(187,617		)	(190,999		)
Regulatory liability on production tax credit	(49,873		)	(101,787		)
Net other deferred tax assets	(2,038		)	—
Subtotal deferred tax assets	(1,251,788		)	(333,847		)
Total net deferred tax liabilities	$	869,473		$	1,732,390

XML

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2017

Other Commitments [Line Items]

Schedule of Long-term Contracts for Purchase of Electric Power

The Company's expenses under these PUD contracts were as follows for the years ended December 31:

(Dollars in Thousands)	2017		2016		2015
PUD contract costs	$	73,827	$	77,667	$	72,833

As of December 31, 2017, 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 2018 Costs		2018 Debt Service Costs		Interest included in 2018 Debt Service Costs		Debt Outstanding
Chelan County PUD:
Rock Island Project	2031	25.0	%	156	$	29,135	$	10,105	$	5,354	$	84,269
Rocky Reach Project	2031	25.0		325	28,800		5,796		2,548		39,563
Douglas County PUD:
Wells Project1	2028	29.9		251	11,002		4,695		1,379		49,629
Grant County PUD:
Priest Rapids Development	2052	0.6		6	2,050		1,231		1,231		13,723
Wanapum Development	2052	0.6		7	2,050		1,231		1,231		13,723
Total				745	$	73,037	$	23,058	$	11,743	$	200,907

_______________

¹  In March 2017, PSE entered a new PPA with Douglas County PUD for Wells Project output that begins upon expiration of the existing contract on August 31, 2018 and continues through September 30, 2028.

The Company's expenses under these PUD contracts were as follows for the years ended December 31:

(Dollars in Thousands)	2017		2016		2015
PUD contract costs	$	73,827	$	77,667	$	72,833

Schedule of Long-term Purchase Commitments

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)	2018		2019		2020		2021		2022		Thereafter		Total
Natural gas supply	$	245,669	$	193,458	$	163,818	$	145,662	$	109,401	$	—	$	858,008
Firm transportation service	154,170		154,204		141,962		126,319		125,335		310,428		1,012,418
Firm storage service	8,328		8,899		7,908		3,108		1,619		857		30,719
Short-term natural gas supply contracts	55,774		13,818		1,651		—		—		—		71,243
Total	$	463,941	$	370,379	$	315,339	$	275,089	$	236,355	$	311,285	$	1,972,388

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)	2018		2019		2020		2021		2022		Thereafter		Total
Energy production service contracts	$	28,674	$	27,939	$	28,639	$	29,415	$	30,142	$	165,689	$	310,498
Automated meter reading system	48,245		44,842		43,951		44,497		45,168		187,698		414,401
Total	$	76,919	$	72,781	$	72,590	$	73,912	$	75,310	$	353,387	$	724,899

These contracts have varying terms and may include escalation and termination provisions.

(Dollars in Thousands)	2018		2019		2020		2021		2022		Thereafter		Total
Columbia River projects	$	82,200	$	97,890	$	95,704	$	91,862	$	91,018	$	708,499	$	1,167,173
Other utilities	1,257		888		—		—		—		—		2,145
Non-utility contracts	206,233		233,776		238,016		244,962		244,906		1,128,466		2,296,359
Short-term electric supply contracts	70,786		140		—		—		—		—		70,926
Total	$	360,476	$	332,694	$	333,720	$	336,824	$	335,924	$	1,836,965	$	3,536,603

XML

Accumulated Other Comprehensive Income (Loss) (Tables)

12 Months Ended

Dec. 31, 2017

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

The following tables present the changes in the Company’s (loss) AOCI by component for the years ended December 31, 2017, 2016 and 2015, respectively:

Puget Energy	Net unrealized gain (loss) and prior service cost on pension plans			Net unrealized gain (loss) on energy derivative instruments
Changes in AOCI, net of tax
(Dollars in Thousands)							Total
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	)
Other comprehensive income (loss) before reclassifications	(5,528		)	—			(5,528		)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	(918		)	—			(918		)
Net current-period other comprehensive income (loss)	(6,446		)	—			(6,446		)
Balance at December 31, 2016	$	(33,712	)	$	—		$	(33,712	)
Other comprehensive income (loss) before reclassifications	10,251			—			10,251
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	(821		)	—			(821		)
Net current-period other comprehensive income (loss)	9,430			—			9,430
Balance at December 31, 2017	$	(24,282	)	$	—		$	(24,282	)

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, 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	)
Other comprehensive income (loss) before reclassifications	(5,655		)	—			—			(5,655		)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	9,377			—			317			9,694
Net current-period other comprehensive income (loss)	3,722			—			317			4,039
Balance at December 31, 2016	$	(140,155	)	$	—		$	(5,356	)	$	(145,511	)
Other comprehensive income (loss) before reclassifications	10,200			—			—			10,200
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	8,088			—			317			8,405
Net current-period other comprehensive income (loss)	18,288			—			317			18,605
Balance at December 31, 2017	$	(121,867	)	$	—		$	(5,039	)	$	(126,906	)

Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]

Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2017, 2016 and 2015, 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)
		2017			2016			2015
Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost	(a)	$	1,938		$	1,938		$	1,938
Amortization of net gain (loss)	(a)	(675		)	(525		)	(5,397		)
	Total before tax	1,263			1,413			(3,459		)
	Tax (expense) or benefit	(442		)	(495		)	1,211
	Net of Tax	821			918			(2,248		)
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts: Electric derivatives	Purchased electricity	—			—			(512		)
	Tax (expense) or benefit	—			—			179
	Net of Tax	—			—			(333		)
Total reclassification for the period	Net of Tax	$	821		$	918		$	(2,581	)

_______________

^(a) These AOCI components are included in the computation of net periodic pension cost, see Note 12, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details.

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)
		2017			2016			2015
Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost	(a)	$	1,529		$	1,529		$	1,526
Amortization of net gain (loss)	(a)	(13,972		)	(15,955		)	(22,268		)
	Total before tax	(12,443		)	(14,426		)	(20,742		)
	Tax (expense) or benefit	4,355			5,049			7,260
	Net of tax	(8,088		)	(9,377		)	(13,482		)
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts: Electric derivatives	Purchased electricity	—			—			(1,055		)
	Tax (expense) or benefit	—			—			369
	Net of Tax	—			—			(686		)
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	$	(8,405	)	$	(9,694	)	$	(14,485	)

_______________

^(a) These AOCI components are included in the computation of net periodic pension cost, see Note 12, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details.

XML

Summary of Significant Accounting Policies (Details) $ in Thousands		6 Months Ended	12 Months Ended
	Dec. 19, 2017	Dec. 31, 2013	Dec. 31, 2017 USD ($) mi² unit	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Jan. 01, 2018 USD ($)	Jan. 01, 2017 USD ($)	Jan. 01, 2015	Dec. 31, 2014 USD ($)	Feb. 06, 2009 USD ($)
Accounting Policies
Goodwill			$ 1,656,513	$ 1,656,513						$ 1,700,000
Number of reportable segments | unit			1
Cash and Cash Equivalents
Cash and Cash Equivalents, at Carrying Value			$ 26,616	28,878	$ 42,494				$ 37,527
Revenue Recognition
Excise taxes collected			257,100	235,300	$ 234,200
Allowance for Doubtful Accounts
Allowance for doubtful accounts			$ 8,901	$ 9,798
Electric Transmission
Accounting Policies
Annual depreciation provision			2.80%
Gas Transmission Equipment
Accounting Policies
Annual depreciation provision			3.40%
Common Plant
Accounting Policies
Annual depreciation provision			8.30%	9.70%	8.50%
Maximum
Accounting Policies
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)	5.00%							3.00%
Subsidiaries [Member]
Accounting Policies
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities	7.60%	7.77%
Area of service territory (sqmi) | mi²			6,000
Cash and Cash Equivalents
Cash and Cash Equivalents, at Carrying Value			$ 25,864	$ 28,481	$ 41,856				$ 37,466
Allowance for Doubtful Accounts
Allowance for doubtful accounts			$ 8,901	$ 9,798
Self Insurance [Abstract]
Public Utilities, Rate Case, Deferred Storm Costs Threshold						$ 10,000	$ 8,000
Puget LNG [Member]
Statements of Cash Flows
Jointly Owned Non-Utility Plant Share			57.00%
Construction in Progress, Gross			$ 104,000
Construction in Progress and O&M Expenses			$ 104,300
Tacoma LNG [Member]
Statements of Cash Flows
Jointly Owned Non-Utility Plant Share			43.00%
Construction in Progress, Gross			$ 87,200

XML

Summary of Significant Accounting Policies - AFUDC (Details)	12 Months Ended
	Dec. 31, 2017
Regulatory Assets [Line Items]
Public Utilities, Property, Plant and Equipment, Non-project Electric Utility Plant, Estimated Useful Life Average	30 years

XML

New Accounting Pronouncements Revenue Recognition (Details) - Pension Plan [Member] $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Defined Benefit Plan, Other Cost (Credit)	$ 18.4
Subsidiaries [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Defined Benefit Plan, Other Cost (Credit)	$ 4.7

XML

Regulation and Rates Net regulatory assets and liabilities (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
Deferred income tax charge
Regulatory Assets [Line Items]
Regulatory Liabilities		$ 634	$ 0
Various other regulatory liabilities
Regulatory Assets [Line Items]
Regulatory Liabilities		(1,314)	(1,326)
Regulatory liabilities related to power contracts
Regulatory Assets [Line Items]
Regulatory Liabilities		(174,918)	(275,061)
Liabilities, Total
Regulatory Assets [Line Items]
Regulatory Liabilities		(1,934,182)	(929,683)
Net Regulatory Assets
Regulatory Assets [Line Items]
Net Regulatory Assets		(961,620)
Net Regulatory Assets
Regulatory Assets [Line Items]
Net Regulatory Assets			206,632
Various other regulatory assets
Regulatory Assets [Line Items]
Regulatory Assets		(8)	517
Requlatory Assets Related to Power Contracts
Regulatory Assets [Line Items]
Regulatory Assets		19,454	22,613
Assets, Total
Regulatory Assets [Line Items]
Regulatory Assets		972,562	1,136,315
Subsidiaries [Member] | Deferred income tax charge
Regulatory Assets [Line Items]
Regulatory Liabilities	[1]	(1,012,260)	0
Subsidiaries [Member] | Cost of removal
Regulatory Assets [Line Items]
Regulatory Liabilities	[2]	$ (389,579)	(369,300)
Subsidiaries [Member] | Treasury grants
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		20 years
Regulatory Liabilities		$ (205,775)	(133,709)
Subsidiaries [Member] | Production tax credits [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities	[3]	(93,616)	(93,616)
Subsidiaries [Member] | Decoupling rate of return sharing [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities		(18,400)	(13,300)
Subsidiaries [Member] | Deferral and interest decoupling revenue [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities		$ (7,896)	(16,448)
Subsidiaries [Member] | PGA payable
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		1 year
Regulatory Liabilities		$ (16,051)	0
Subsidiaries [Member] | Deferred decoupling revenue, net [Member]
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		2 years
Regulatory Liabilities		$ (26,296)	(29,748)
Subsidiaries [Member] | Summit purchase option buy-out
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		2 years 10 months
Regulatory Liabilities		$ (4,463)	(6,038)
Subsidiaries [Member] | Purchased Gas Adjustment Deferral of Unrealized Gains on Derivatives [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities		0	(7,517)
Subsidiaries [Member] | Various other regulatory liabilities
Regulatory Assets [Line Items]
Regulatory Liabilities	[4]	(10,544)	(13,368)
Subsidiaries [Member] | Liabilities, Total
Regulatory Assets [Line Items]
Regulatory Liabilities	[4]	(1,758,584)	(653,296)
Subsidiaries [Member] | Net Regulatory Assets
Regulatory Assets [Line Items]
Net Regulatory Assets		(805,468)
Subsidiaries [Member] | Net Regulatory Assets
Regulatory Assets [Line Items]
Net Regulatory Assets			459,889
Subsidiaries [Member] | Storm Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets		128,508	122,709
Subsidiaries [Member] | Colstrip Regulatory Asset [Domain]
Regulatory Assets [Line Items]
Regulatory Assets		127,627	176,804
Subsidiaries [Member] | Deferred decoupling revenue, gross [Member]
Regulatory Assets [Line Items]
Regulatory Assets		98,769	156,408
Subsidiaries [Member] | Other decoupling 24 month reserve [Member]
Regulatory Assets [Line Items]
Regulatory Assets		0	(20,847)
Subsidiaries [Member] | Deferred decoupling revenue, net [Member]
Regulatory Assets [Line Items]
Regulatory Assets		$ 98,769	135,561
Net Regulatory Assets, Remaining Amortization Period		2 years
Subsidiaries [Member] | Chelan PUD contract initiation
Regulatory Assets [Line Items]
Regulatory Assets		$ 98,052	105,140
Net Regulatory Assets, Remaining Amortization Period		13 years 10 months
Subsidiaries [Member] | Environmental remediation
Regulatory Assets [Line Items]
Regulatory Assets	[4]	$ 81,550	74,557
Subsidiaries [Member] | Lower Snake River
Regulatory Assets [Line Items]
Regulatory Assets		$ 70,975	74,862
Net Regulatory Assets, Remaining Amortization Period		19 years 5 months
Subsidiaries [Member] | Baker Dam Licensing Operating Maintenance Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets		$ 54,817	61,453
Subsidiaries [Member] | Deferred Washington Commission AFUDC
Regulatory Assets [Line Items]
Regulatory Assets		$ 50,301	51,404
Net Regulatory Assets, Remaining Amortization Period		10 years
Subsidiaries [Member] | Unamortized loss on reacquired debt
Regulatory Assets [Line Items]
Regulatory Assets		$ 39,674	42,196
Subsidiaries [Member] | Property tax tracker
Regulatory Assets [Line Items]
Regulatory Assets		$ 36,517	41,949
Net Regulatory Assets, Remaining Amortization Period		2 years
Subsidiaries [Member] | Energy Conservation Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	[4]	$ 35,538	41,027
Subsidiaries [Member] | PGA deferral of unrealized losses on derivative instruments
Regulatory Assets [Line Items]
Regulatory Assets		26,030	0
Subsidiaries [Member] | White River relicensing and other costs
Regulatory Assets [Line Items]
Regulatory Assets		$ 19,502	21,627
Net Regulatory Assets, Remaining Amortization Period		3 years
Subsidiaries [Member] | Generation plant major maintenance [Member]
Regulatory Assets [Line Items]
Regulatory Assets		$ 17,216	13,178
Subsidiaries [Member] | Mint Farm ownership and operating costs
Regulatory Assets [Line Items]
Regulatory Assets		$ 14,319	16,319
Net Regulatory Assets, Remaining Amortization Period		7 years 4 months
Subsidiaries [Member] | Colstrip major maintenance [Member]
Regulatory Assets [Line Items]
Regulatory Assets		$ 8,723	6,589
Net Regulatory Assets, Remaining Amortization Period		1 year 6 months
Subsidiaries [Member] | Snoqualmie Licensing Operating Maintenance Costs
Regulatory Assets [Line Items]
Regulatory Assets		$ 7,341	8,018
Subsidiaries [Member] | Ferndale
Regulatory Assets [Line Items]
Regulatory Assets		$ 7,295	11,274
Net Regulatory Assets, Remaining Amortization Period		1 year 10 months
Subsidiaries [Member] | Colstrip common property
Regulatory Assets [Line Items]
Regulatory Assets		$ 4,618	5,334
Net Regulatory Assets, Remaining Amortization Period		7 years 5 months
Subsidiaries [Member] | PCA Mechanism [Member]
Regulatory Assets [Line Items]
Regulatory Assets		$ 4,576	4,531
Subsidiaries [Member] | Electron Unrecovered Loss
Regulatory Assets [Line Items]
Regulatory Assets		$ 3,786	7,178
Net Regulatory Assets, Remaining Amortization Period		1 year
Subsidiaries [Member] | Deferred income tax charge
Regulatory Assets [Line Items]
Regulatory Assets	[1]	$ 0	71,517
Subsidiaries [Member] | PGA receivable [Domain]
Regulatory Assets [Line Items]
Regulatory Assets		$ 0	2,785
Net Regulatory Assets, Remaining Amortization Period		1 year
Subsidiaries [Member] | Various other regulatory assets
Regulatory Assets [Line Items]
Regulatory Assets	[4]	$ 17,382	17,173
Subsidiaries [Member] | Assets, Total
Regulatory Assets [Line Items]
Regulatory Assets	[4]	953,116	1,113,185
Colstrip Regulatory Asset [Domain]
Regulatory Assets [Line Items]
Regulatory Assets		$ 127,600	$ 176,800

[1] (d) For additional information, see Note 13,"Income Taxes" to the consolidated financial statements included in Item 8 of this report.

[2] The balance is dependent upon the cost of removal of underlying assets and the life of utility plant.

[3] Amortization will begin once PTCs are utilized by PSE on its tax return.

[4] Amortization periods vary depending on timing of underlying transactions.

XML

Regulation and Rates Rate Adjustments (Details) - USD ($) $ in Millions					6 Months Ended	12 Months Ended
	Dec. 19, 2017	Apr. 03, 2017	Jan. 13, 2017	Jan. 01, 2017	Dec. 31, 2013	Dec. 31, 2017
Decoupling Mechanism [Member]
Regulation and Rates [Line Items]
Deferred Revenue, Revenue Recognized						$ 20.8
Subsidiaries [Member]
Regulation and Rates [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities	7.60%				7.77%
Subsidiaries [Member] | Decoupling Mechanism [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage				2.20%
Subsidiaries [Member] | Decoupling Mechanism [Member] | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage				3.00%
Subsidiaries [Member] | General Rate Case [Member]
Regulation and Rates [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities			7.74%
Regulated Utility, After-tax Allowed Rate of Return on Net Regulatory Assets and Liabilities	6.55%		6.69%
Public Utilities, Requested Equity Capital Structure, Percentage			48.50%
Public Utilities, Requested Return on Equity, Percentage			9.80%
Subsidiaries [Member] | General Rate Case [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage	(3.80%)
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage		(3.20%)
Public Utilities, Approved Rate Increase (Decrease), Amount	$ (35.5)
Public Utilities, Requested Rate Increase (Decrease), Amount			$ (22.3)
Public Utilities, Requested Rate Increase (Decrease), Percentage			(2.40%)
Subsidiaries [Member] | General Rate Case [Member] | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage	0.90%
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage		3.20%
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 20.2
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 86.3
Public Utilities, Requested Rate Increase (Decrease), Percentage			4.10%
Maximum | Decoupling Mechanism [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage	5.00%
Maximum | Subsidiaries [Member] | Decoupling Mechanism [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage	3.00%			3.00%
Colstrip Units 1 & 2
Regulation and Rates [Line Items]
Decommissioning Fund Investments	$ 10.0
Colstrip Units 1 & 2 | Shareholders Fund Amount [Domain]
Regulation and Rates [Line Items]
Decommissioning Fund Investments	5.0
Colstrip Units 1 & 2 | Regulatory Liability Monetized PTC Fund Amount [Domain]
Regulation and Rates [Line Items]
Decommissioning Fund Investments	$ 5.0

XML

Regulation and Rates (Details)						6 Months Ended	12 Months Ended
	Dec. 19, 2017 USD ($)	Sep. 15, 2017	Apr. 03, 2017 USD ($)	Jan. 13, 2017	Jan. 01, 2017 USD ($)	Dec. 31, 2013	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Jan. 01, 2018 USD ($)	Jan. 01, 2015
Regulation and Rates [Line Items]
Accrual for Environmental Loss Contingencies							$ 28,600,000
Electric [Member]
Regulation and Rates [Line Items]
Environmental Remediation Expense							8,900,000
Environmental Expense and Liabilities							17,600,000	$ 13,800,000	$ 14,000,000
Natural Gas [Member]
Regulation and Rates [Line Items]
Environmental Remediation Expense							38,900,000
Environmental Expense and Liabilities							63,900,000	60,700,000	$ 52,900,000
Subsidiaries [Member]
Regulation and Rates [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities	7.60%					7.77%
Regulatory Liabilities Reclassified from Accumulated Depreciation							389,600,000	369,300,000
Public Utilities, Rate Case, Deferred Storm Costs Threshold					$ 8,000,000					$ 10,000,000
Public Utilities, Rate Case, Deferred Storm Qualifying Costs										$ 500,000
Storm Damage Costs Incurred During Period							30,400,000	22,000,000
Storm Damage Costs Deferred During Period							$ 21,600,000	$ 12,400,000.0
Decoupling Mechanism [Member] | Subsidiaries [Member] | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage					3.00%
Decoupling Mechanism [Member] | Subsidiaries [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage					2.20%
General Rate Case [Member] | Subsidiaries [Member]
Regulation and Rates [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities				7.74%
Regulated Utility, After-tax Allowed Rate of Return on Net Regulatory Assets and Liabilities	6.55%			6.69%
Public Utilities, Approved Equity Capital Structure, Percentage	48.50%
Public Utilities, Approved Return on Equity, Percentage	9.50%
Number of new mechanisms				2
Number of parties that agreed to settle		10
Number of parties total		11
Number of contested issues not settled		4
Public Utilities, Requested Equity Capital Structure, Percentage				48.50%
Public Utilities, Requested Return on Equity, Percentage				9.80%
General Rate Case [Member] | Subsidiaries [Member] | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage				4.10%
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount			$ 67,900,000
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage			3.20%
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 20,200,000
Public Utilities, Approved Rate Increase (Decrease), Percentage	0.90%
General Rate Case [Member] | Subsidiaries [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage				(2.40%)
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount			$ (29,300,000)
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage			(3.20%)
Public Utilities, Approved Rate Increase (Decrease), Amount	$ (35,500,000)
Public Utilities, Approved Rate Increase (Decrease), Percentage	(3.80%)
Maximum
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)	5.00%										3.00%
Maximum | Decoupling Mechanism [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage	5.00%
Maximum | Decoupling Mechanism [Member] | Subsidiaries [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage	3.00%				3.00%
Regulatory liabilities related to power contracts | Parent Company [Member]
Regulation and Rates [Line Items]
Net Regulatory Assets, Remaining Amortization Period, Min							1 year
Net Regulatory Assets, Remaining Amortization Period, Max							35 years
Treasury grants | Subsidiaries [Member]
Regulation and Rates [Line Items]
Net Regulatory Assets, Remaining Amortization Period							20 years
Generation plant major maintenance [Member] | Subsidiaries [Member]
Regulation and Rates [Line Items]
Net Regulatory Assets, Remaining Amortization Period, Min							5 years
Net Regulatory Assets, Remaining Amortization Period, Max							11 years
Chelan PUD contract initiation | Subsidiaries [Member]
Regulation and Rates [Line Items]
Net Regulatory Assets, Remaining Amortization Period							13 years 10 months
Ferndale | Subsidiaries [Member]
Regulation and Rates [Line Items]
Net Regulatory Assets, Remaining Amortization Period							1 year 10 months
Deferred decoupling revenue, net [Member] | Subsidiaries [Member]
Regulation and Rates [Line Items]
Net Regulatory Assets, Remaining Amortization Period							2 years
Requlatory Assets Related to Power Contracts | Parent Company [Member]
Regulation and Rates [Line Items]
Net Regulatory Assets, Remaining Amortization Period, Min							1 year
Net Regulatory Assets, Remaining Amortization Period, Max							20 years
Lower Snake River | Subsidiaries [Member]
Regulation and Rates [Line Items]
Net Regulatory Assets, Remaining Amortization Period							19 years 5 months
Storm Costs [Member] | Subsidiaries [Member]
Regulation and Rates [Line Items]
Net Regulatory Assets, Remaining Amortization Period, Min							4 years
Net Regulatory Assets, Remaining Amortization Period, Max							6 years
Unamortized loss on reacquired debt | Subsidiaries [Member]
Regulation and Rates [Line Items]
Net Regulatory Assets, Remaining Amortization Period, Min							1 year
Net Regulatory Assets, Remaining Amortization Period, Max							28 years

XML

Dividend Payment Restrictions (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)
Parent [Line Items]
Retained Earnings, Unappropriated	$ 645.1
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio, Threshold For Dividend Payment	2.0
EBITDA Interest Expense Ratio	3.7
EBITDA to Interest Expense Denominator	1.0
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio at Period End	1.0
Subsidiaries [Member]
Parent [Line Items]
Dividends, Common Equity Ratio, Threshold For Dividend Payment	44.00%
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio, Threshold For Dividend Payment	3.0
Dividends, Common Equity Ratio at Period End	48.00%
EBITDA Interest Expense Ratio	5.5
EBITDA to Interest Expense Denominator	1.0
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio at Period End	1.0

XML

Utility Plant (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
Public Utility, Property, Plant and Equipment
Accumulated amortization of capital leases		$ 700	$ 600
Utility Plant
Distribution plant		5,670,351	5,287,542
Production plant		3,068,135	3,007,546
Transmission plant		1,361,495	1,307,687
General plant		586,226	541,424
Intangible plant (including capitalized software)		447,568	347,697
Plant acquisition adjustment		242,826	242,826
Underground storage		31,815	30,695
Liquefied natural gas storage		12,628	12,628
Plant held for future use		53,428	52,484
Recoverable cushion gas		8,655	8,655
Public Utilities, Property, Plant and Equipment, Other Property, Plant and Equipment		275,014	159,345
Public Utilities, Property, Plant and Equipment Grant		0	(99,100)
Capital leases, net of accumulated amortization	[1]	1,129	645
Less: Accumulated depreciation and amortization		(2,428,524)	(2,161,796)
Subtotal		9,330,746	8,738,278
Construction work in progress		495,937	420,278
Net utility plant		$ 9,826,683	9,158,556
Minimum
Public Utility, Property, Plant and Equipment
Distribution plant, Estimated Useful Life		20 years
Production plant, Estimated Useful Life		12 years
Transmission plant, Estimated Useful Life		43 years
General plant, Estimated Useful Life		5 years
Underground storage, Estimated Useful Life		25 years
Liquefied natural gas storage, Estimated Useful Life		25 years
Public Utilities, Property, Plant and Equipment, Plant Not Classified, Estimated Useful Life		1 year
Capital leases, net of accumulated amortization, Estimated Useful Life	[1]	4 years
Maximum
Public Utility, Property, Plant and Equipment
Distribution plant, Estimated Useful Life		65 years
Production plant, Estimated Useful Life		90 years
Transmission plant, Estimated Useful Life		75 years
General plant, Estimated Useful Life		75 years
Underground storage, Estimated Useful Life		60 years
Liquefied natural gas storage, Estimated Useful Life		60 years
Public Utilities, Property, Plant and Equipment, Plant Not Classified, Estimated Useful Life		125 years
Capital leases, net of accumulated amortization, Estimated Useful Life	[1]	6 years
Subsidiaries [Member]
Utility Plant
Distribution plant		$ 7,289,998	6,922,176
Production plant		3,954,057	3,910,129
Transmission plant		1,471,337	1,420,334
General plant		628,179	611,237
Intangible plant (including capitalized software)		438,185	338,327
Plant acquisition adjustment		282,792	282,792
Underground storage		45,288	44,206
Liquefied natural gas storage		14,498	14,498
Plant held for future use		53,580	52,636
Recoverable cushion gas		8,655	8,655
Public Utilities, Property, Plant and Equipment, Other Property, Plant and Equipment		275,014	159,345
Public Utilities, Property, Plant and Equipment Grant		0	(99,100)
Capital leases, net of accumulated amortization	[1]	1,129	645
Less: Accumulated depreciation and amortization		(5,131,966)	(4,927,602)
Subtotal		9,330,746	8,738,278
Construction work in progress		495,937	420,278
Net utility plant		$ 9,826,683	$ 9,158,556

[1] Accumulated amortization of capital leases at Puget Energy and PSE was $0.7 million in 2017 and $0.6 million in 2016.

XML

Utility Plant - Jointly Owned Utility Plant (Details) $ in Thousands	Dec. 31, 2017 USD ($)
Colstrip Units 1 & 2
Jointly Owned Utility Plant Interests
Plant in Service at Cost	$ 246,510
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	(23)
Accumulated Depreciation	(38,170)
Colstrip Units 3 & 4
Jointly Owned Utility Plant Interests
Plant in Service at Cost	307,254
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	1,726
Accumulated Depreciation	(71,061)
Colstrip Units 1 – 4 Common Facilities
Jointly Owned Utility Plant Interests
Plant in Service at Cost	83
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0
Accumulated Depreciation	(31)
Frederickson 1
Jointly Owned Utility Plant Interests
Plant in Service at Cost	61,783
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0
Accumulated Depreciation	(3,850)
Jackson Prairie [Member]
Jointly Owned Utility Plant Interests
Plant in Service at Cost	31,141
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	43
Accumulated Depreciation	$ (6,325)
Subsidiaries [Member] | Colstrip Units 1 & 2
Jointly Owned Utility Plant Interests
Company’s Ownership Share	50.00%
Plant in Service at Cost	$ 378,574
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	(23)
Accumulated Depreciation	$ (170,234)
Subsidiaries [Member] | Colstrip Units 3 & 4
Jointly Owned Utility Plant Interests
Company’s Ownership Share	25.00%
Plant in Service at Cost	$ 571,604
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	1,726
Accumulated Depreciation	(335,414)
Subsidiaries [Member] | Colstrip Units 1 – 4 Common Facilities
Jointly Owned Utility Plant Interests
Plant in Service at Cost	252
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0
Accumulated Depreciation	$ (199)
Subsidiaries [Member] | Frederickson 1
Jointly Owned Utility Plant Interests
Company’s Ownership Share	49.85%
Plant in Service at Cost	$ 67,851
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0
Accumulated Depreciation	$ (9,917)
Subsidiaries [Member] | Jackson Prairie [Member]
Jointly Owned Utility Plant Interests
Company’s Ownership Share	33.34%
Plant in Service at Cost	$ 45,288
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	43
Accumulated Depreciation	$ (20,471)
Subsidiaries [Member] | Tacoma LNG [Member]
Jointly Owned Utility Plant Interests
Company’s Ownership Share	43.00%
Plant in Service at Cost	$ 2,667
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	87,207
Accumulated Depreciation	$ 0

XML

Utility Plant - Asset Retirement Obligation (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Sep. 06, 2016
number of agreements			2
Subsidiaries [Member]
Decommissioning Liability, Noncurrent	$ 3,800
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at beginning of period	200,345	$ 85,028
Costs Incurred, Asset Retirement Obligation Incurred	2,881	0
Asset Retirement Obligation, Liabilities Incurred	(3,841)	(411)
Asset Retirement Obligation, Revision of Estimate	(13,748)	113,081
Asset Retirement Obligation, Accretion Expense	5,539	2,647
Asset retirement obligation at end of period	191,176	200,345
Colstrip Units 1 and 2 [Member] | Subsidiaries [Member]
Decommissioning Liability, Noncurrent	5,500	45,700
Colstrip Units 3 and 4 [Member] | Subsidiaries [Member]
Decommissioning Liability, Noncurrent	12,700	$ 37,000
Tacoma LNG [Member] | Subsidiaries [Member]
Decommissioning Liability, Noncurrent	2,700
Tacoma LNG [Member] | Puget LNG [Member]
Decommissioning Liability, Noncurrent	$ 2,200

XML

Long-Term Debt (Schedule of Long-Term Debt Instruments) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 01, 2017	Jun. 15, 2017
Debt Instrument [Line Items]
Current borrowing capacity of line of credit		$ 800,000
Proceeds from long-term debt and bonds issued		90,120	$ 12,481	$ 825,000
Total PSE long-term debt		5,678,872
Long Term Debt, Reconciliation, Fair Value Adjustment		(190,895)	(199,436)
Long-term Line of Credit, Noncurrent		102,600	12,480
Unamortized discount on senior notes		(3,687)	(6,269)
Net PSE long-term debt		$ 5,457,929	5,354,073
Senior Secured Note | 6.500% Senior Secured Note Due 2020
Debt Instrument [Line Items]
Stated interest rate percent		6.50%
Total PSE long-term debt		$ 450,000	450,000
Senior Secured Note | 6.000% Senior Secured Note Due 2021
Debt Instrument [Line Items]
Stated interest rate percent		6.00%
Total PSE long-term debt		$ 500,000	500,000
Senior Secured Note | 5.625% Senior Secured Note Due 2022
Debt Instrument [Line Items]
Stated interest rate percent		5.625%
Total PSE long-term debt		$ 450,000	450,000
Senior Secured Note | 3.650% Senior Secured Note Due 2025 [Member]
Debt Instrument [Line Items]
Stated interest rate percent		3.65%
Total PSE long-term debt		$ 400,000	400,000
Subsidiaries [Member]
Debt Instrument [Line Items]
Proceeds from long-term debt and bonds issued		0	0	$ 425,000
Total PSE long-term debt		3,776,272
Unamortized discount on senior notes		(26,361)	(28,974)
Net PSE long-term debt		$ 3,749,911	3,747,298
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 5.500% Secured Promissory Note Due 2017
Debt Instrument [Line Items]
Stated interest rate percent		5.50%			5.50%
Total PSE long-term debt	[1]	$ 2,412	2,412		$ 2,400
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 7.150% Series Due 2025
Debt Instrument [Line Items]
Stated interest rate percent		7.15%
Total PSE long-term debt		$ 15,000	15,000
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 7.200% Series Due 2025
Debt Instrument [Line Items]
Stated interest rate percent		7.20%
Total PSE long-term debt		$ 2,000	2,000
Subsidiaries [Member] | Pollution Control Bonds | 3.900% Series Due 2031
Debt Instrument [Line Items]
Stated interest rate percent		3.90%
Total PSE long-term debt		$ 138,460	138,460
Subsidiaries [Member] | Pollution Control Bonds | 4.000% Series Due 2031
Debt Instrument [Line Items]
Stated interest rate percent		4.00%
Total PSE long-term debt		$ 23,400	23,400
Subsidiaries [Member] | Junior Subordinated Notes | 6.974% Series Due 2067
Debt Instrument [Line Items]
Stated interest rate percent		6.974%
Total PSE long-term debt		$ 250,000	250,000
Subsidiaries [Member] | Senior Secured Note | 6.740% Series Due 2018
Debt Instrument [Line Items]
Stated interest rate percent		6.74%				6.74%
Total PSE long-term debt	[2]	$ 200,000	200,000			$ 200,000
Subsidiaries [Member] | Senior Secured Note | 7.020% Series Due 2027
Debt Instrument [Line Items]
Stated interest rate percent		7.02%
Total PSE long-term debt		$ 300,000	300,000
Subsidiaries [Member] | Senior Secured Note | 7.000% Series Due 2029
Debt Instrument [Line Items]
Stated interest rate percent		7.00%
Total PSE long-term debt		$ 100,000	100,000
Subsidiaries [Member] | Senior Secured Note | 5.483% Series Due 2035
Debt Instrument [Line Items]
Stated interest rate percent		5.483%
Total PSE long-term debt		$ 250,000	250,000
Subsidiaries [Member] | Senior Secured Note | 6.724% Series Due 2036
Debt Instrument [Line Items]
Stated interest rate percent		6.724%
Total PSE long-term debt		$ 250,000	250,000
Subsidiaries [Member] | Senior Secured Note | 6.274% Series Due 2037
Debt Instrument [Line Items]
Stated interest rate percent		6.274%
Total PSE long-term debt		$ 300,000	300,000
Subsidiaries [Member] | Senior Secured Note | 5.757% Series Due 2039
Debt Instrument [Line Items]
Stated interest rate percent		5.757%
Total PSE long-term debt		$ 350,000	350,000
Subsidiaries [Member] | Senior Secured Note | 5.795% Series Due 2040
Debt Instrument [Line Items]
Stated interest rate percent		5.795%
Total PSE long-term debt		$ 325,000	325,000
Subsidiaries [Member] | Senior Secured Note | 5.764% Series Due 2040
Debt Instrument [Line Items]
Stated interest rate percent		5.764%
Total PSE long-term debt		$ 250,000	250,000
Subsidiaries [Member] | Senior Secured Note | 4.434% Series Due 2041
Debt Instrument [Line Items]
Stated interest rate percent		4.434%
Total PSE long-term debt		$ 250,000	250,000
Subsidiaries [Member] | Senior Secured Note | 5.638% Series Due 2041
Debt Instrument [Line Items]
Stated interest rate percent		5.638%
Total PSE long-term debt		$ 300,000	300,000
Subsidiaries [Member] | Senior Secured Note | 4.300% Series Due 2045
Debt Instrument [Line Items]
Stated interest rate percent		4.30%
Total PSE long-term debt		$ 425,000	425,000
Subsidiaries [Member] | Senior Secured Note | 4.700% Series Due 2051
Debt Instrument [Line Items]
Stated interest rate percent		4.70%
Total PSE long-term debt		$ 45,000	$ 45,000

[1] 2 5.50% Promissory Note (Puget Western Note Payable) in the amount of $2.4 million was classified on the Balance Sheet as a current maturity of long-term debt from January 1, 2017 to August 13, 2017, at which time the agreement was amended and extended until August 13, 2020. The Promissory Note is currently classified as long-term debt on the Balance sheet as of September 1, 2017.

[2] Accumulated amortization of capital leases at Puget Energy and PSE was $0.7 million in 2017 and $0.6 million in 2016.

XML

Long-Term Debt (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term debt	$ 5,678,872
Current borrowing capacity of line of credit	800,000
Senior Secured Note | 3.650% Senior Secured Note Due 2025 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 400,000	$ 400,000
Stated interest rate percent	3.65%
Subsidiaries [Member]
Debt Instrument [Line Items]
Long-term debt	$ 3,776,272
Subsidiaries [Member] | Senior Secured Note | 4.300% Series Due 2045
Debt Instrument [Line Items]
Long-term debt	$ 425,000	$ 425,000
Stated interest rate percent	4.30%

XML

Long-Term Debt (Schedule of Maturities of Long-Term Debt) (Details) $ in Thousands	Dec. 31, 2017 USD ($)
Maturities of Long-term Debt [Abstract]
2016	$ 200,000
2017	0
2018	452,412
2019	500,000
2020	552,600
Thereafter	3,973,860
Total long-term debt	5,678,872
Subsidiaries [Member]
Maturities of Long-term Debt [Abstract]
2016	200,000
2017	0
2018	2,412
2019	0
2020	0
Thereafter	3,573,860
Total long-term debt	3,776,272
Parent Company [Member]
Maturities of Long-term Debt [Abstract]
2016	0
2017	0
2018	450,000
2019	500,000
2020	552,600
Thereafter	400,000
Total long-term debt	$ 1,902,600

XML

Liquidity Facilities and Other Financing Arrangements (Details) - USD ($)		12 Months Ended
	Feb. 10, 2012	Dec. 31, 2017	Oct. 10, 2017	Dec. 31, 2016	Dec. 31, 2015
Short-term Debt [Line Items]
Short-term debt		$ 329,463,000		$ 245,763,000
Line of Credit Facility, Maximum Borrowing Capacity		1,300,000,000
Current borrowing capacity of line of credit		800,000,000
Long-term Line of Credit, Noncurrent		102,600,000		12,480,000
Senior secured credit facility
Short-term Debt [Line Items]
Short-term debt		0			$ 0
Subsidiaries [Member]
Short-term Debt [Line Items]
Short-term debt		$ 329,463,000		$ 245,763,000	$ 245,800,000
Weighted-average interest rate on short-term debt (percent)		3.50%		3.20%
Maximum capitalization percentage		65.00%
Derivative, Basis Spread on Variable Rate		1.25%
Line of Credit, Unused Capacity, Commitment Fee Percentage		0.175%
Subsidiaries [Member] | Energy Hedging Activities [Member]
Short-term Debt [Line Items]
Outstanding amount for line of credit		$ 1,000,000
Subsidiaries [Member] | Letter of Credit | Working Capital Needs
Short-term Debt [Line Items]
Outstanding amount for line of credit		329,500,000
Current borrowing capacity of line of credit		3,100,000.0
Subsidiaries [Member] | Senior secured credit facility | Promissory Note with Puget Energy
Short-term Debt [Line Items]
Current borrowing capacity of line of credit		$ 30,000,000
Basis spread on variable rate (percent)		0.25%
Debt instrument variable rate basis		one-month LIBOR
Subsidiaries [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Current Same-Day Borrowing Capacity		$ 75,000,000
Line of Credit Facility, Maximum Borrowing Capacity		$ 1,400,000,000
Subsidiaries [Member] | Working Capital Needs
Short-term Debt [Line Items]
Current borrowing capacity of line of credit			$ 800,000,000
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Current borrowing capacity of line of credit			800,000,000
Line of Credit Facility, Fair Value of Amount Outstanding			$ 102,600,000
Basis spread on variable rate (percent)		1.75%
Line of Credit Facility, Commitment Fee Percentage	0.275%

XML

Leases (Schedule of Operating Lease Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Subsidiaries [Member]
Operating Leases, Rent Expense, Net [Abstract]
Operating lease expense net of sublease receipts	$ 35,198	$ 31,786	$ 27,843

XML

Leases (Schedule of Future Minimum Lease Payments for Non-cancellable Leases) (Details) - Subsidiaries [Member] $ in Thousands	Dec. 31, 2017 USD ($)
Operating
2014	$ 21,371
2015	19,077
2016	17,507
2017	9,137
2018	6,747
Thereafter	97,974
Total minimum lease payments	171,813
Capital
2014	527
2015	306
2016	232
2017	97
2018	0
Thereafter	0
Total minimum lease payments	$ 1,162

XML

Accounting for Derivative Instruments and Hedging Activities (Narrative) (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Electric Portfolio
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value		$ 2,639	$ 0
Credit Rating | Natural Gas Portfolio
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value		$ 1,000
External Credit Rating, Investment Grade [Member] | Electric Portfolio
Derivative [Line Items]
Percentage of derivatives with credit risk exposure		99.50%
External Credit Rating, Non Investment Grade [Member] | Electric Portfolio
Derivative [Line Items]
Percentage of derivatives with credit risk exposure		0.50%
Credit Rating
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value		$ 2,600
Credit Rating | Electric Portfolio
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	[1]	$ 0	$ 0

[1] 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.

XML

Accounting for Derivative Instruments and Hedging Activities (Schedule of Derivative Assets and Liabilities) (Details) $ in Thousands, MWh in Millions, MMBTU in Millions		Dec. 31, 2017 USD ($) MWh MMBTU	Dec. 31, 2016 USD ($) MWh MMBTU
Derivative [Line Items]
Assets, Current		$ 22,247	$ 54,341
Assets, Long-term		2,158	8,738
Liabilities, Current		64,859	44,310
Liabilities, Long-term		21,235	16,261
Parent Company [Member]
Derivative [Line Items]
Liabilities, Current		0	141
Subsidiaries [Member]
Derivative [Line Items]
Assets, Current		22,247	54,341
Assets, Long-term		2,158	8,738
Liabilities, Current		64,859	44,170
Liabilities, Long-term		21,235	16,261
Energy derivative contracts
Derivative [Line Items]
Gross Amounts Recognized in the Statement of Financial Position 1		24,405	63,079
Total derivative assets		24,405	63,079
Total derivative liabilities		86,094	60,430
Interest Rate Contract
Derivative [Line Items]
Total derivative liabilities			141
Not Designated as Hedging Instrument
Derivative [Line Items]
Total derivative assets	[1]	24,405	63,079
Total derivative liabilities	[2]	86,094	60,571
Not Designated as Hedging Instrument | Parent Company [Member]
Derivative [Line Items]
Assets, Current	[1]	22,247	54,341
Assets, Long-term	[1]	2,158	8,738
Liabilities, Current	[2]	64,859	44,310
Liabilities, Long-term	[2]	21,235	16,261
Not Designated as Hedging Instrument | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	[3]	0	450,000
Total derivative assets	[1],[3]	0	0
Total derivative liabilities	[2],[3]	$ 0	$ 141
Not Designated as Hedging Instrument | Electric Generation Fuel
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU		166.8	186.8
Not Designated as Hedging Instrument | Purchased Electricity
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MWh		2.9	3.6
Not Designated as Hedging Instrument | Electric Portfolio
Derivative [Line Items]
Total derivative assets	[1]	$ 13,391	$ 36,460
Total derivative liabilities	[2]	49,050	41,329
Not Designated as Hedging Instrument | Natural Gas Portfolio
Derivative [Line Items]
Total derivative assets	[1],[4]	11,014	26,619
Total derivative liabilities	[2],[4]	$ 37,044	$ 19,101
Not Designated as Hedging Instrument | Gas Derivatives
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	[4]	332.1	336.4

[1] Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments.

[2] Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments.

[3] Interest rate swap contracts are only held at Puget Energy and matured in January 2017.

[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.

XML

Accounting for Derivative Instruments and Hedging Activities (Schedule of Amounts Recognized in Statement of Income) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		$ 30,790	$ (83,795)	$ (13,233)
Subsidiaries [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		30,790	(83,795)	(12,688)
Not Designated as Hedging Instrument
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		71,830	(21,079)	73,788
Not Designated as Hedging Instrument | Other Income (Deductions) | Interest Expense
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		(28)	1,062	3,796
Not Designated as Hedging Instrument | Interest Rate Contract | Interest Expense
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		0	0	(560)
Not Designated as Hedging Instrument | Energy Related Derivative [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		32,492	(62,318)	9,315
Not Designated as Hedging Instrument | Energy derivative contracts | Electric Generation Fuel
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		23,195	39,656	44,648
Not Designated as Hedging Instrument | Energy derivative contracts | Purchased Electricity
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		17,873	21,998	39,137
Not Designated as Hedging Instrument | Electric [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	[1]	(1,702)	(21,477)	(22,548)
Not Designated as Hedging Instrument | Subsidiaries [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		71,858	(22,141)	71,097
Not Designated as Hedging Instrument | Subsidiaries [Member] | Energy Related Derivative [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		32,492	(62,318)	9,315
Not Designated as Hedging Instrument | Subsidiaries [Member] | Energy derivative contracts | Electric Generation Fuel
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		23,195	39,656	44,648
Not Designated as Hedging Instrument | Subsidiaries [Member] | Energy derivative contracts | Purchased Electricity
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		17,873	21,998	39,137
Not Designated as Hedging Instrument | Subsidiaries [Member] | Electric [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	[1]	$ (1,702)	$ (21,477)	$ (22,003)

[1] Differences between Puget Energy and PSE for the twelve months ended December 31, 2015 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.

XML

Accounting for Derivative Instruments and Hedging Activities (Schedule of Amounts Recognized in Other Comprehensive Income) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Parent Company [Member] | Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax	$ 0	$ 0	$ (512)

XML

Accounting for Derivative Instruments and Hedging Activities (Schedule of Effects of Non-hedging Derivative Instruments on Income) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		$ (30,790)	$ 83,795	$ 13,233
Derivative contracts classified as financing activities due to merger		0	0	(8,045)
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		(71,830)	21,079	(73,788)
Not Designated as Hedging Instrument | Energy Related Derivative [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		(32,492)	62,318	(9,315)
Not Designated as Hedging Instrument | Interest Rate Contract | Interest Expense
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		0	0	560
Not Designated as Hedging Instrument | Commodity contracts: | Electric Generation Fuel
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		(23,195)	(39,656)	(44,648)
Not Designated as Hedging Instrument | Commodity contracts: | Purchased Electricity
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		(17,873)	(21,998)	(39,137)
Not Designated as Hedging Instrument | Electric [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives	[1]	1,702	21,477	22,548
Subsidiaries [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		(30,790)	83,795	12,688
Subsidiaries [Member] | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		(71,858)	22,141	(71,097)
Subsidiaries [Member] | Not Designated as Hedging Instrument | Energy Related Derivative [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		(32,492)	62,318	(9,315)
Subsidiaries [Member] | Not Designated as Hedging Instrument | Commodity contracts: | Electric Generation Fuel
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		(23,195)	(39,656)	(44,648)
Subsidiaries [Member] | Not Designated as Hedging Instrument | Commodity contracts: | Purchased Electricity
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		(17,873)	(21,998)	(39,137)
Subsidiaries [Member] | Not Designated as Hedging Instrument | Electric [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives	[1]	$ 1,702	$ 21,477	$ 22,003

[1] Differences between Puget Energy and PSE for the twelve months ended December 31, 2015 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.

XML

Accounting for Derivative Instruments and Hedging Activities (Schedule of Contractual Contingent Liability Positions) (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Electric Portfolio
Derivative [Line Items]
Fair Value Liability	[1]	$ 40,914	$ 12,828
Collateral Already Posted, Aggregate Fair Value		2,639	0
Contingent Collateral		3,187	4,894
Credit Rating | Natural Gas Portfolio
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value		1,000
Forward Value of Contract [Member] | Electric Portfolio
Derivative [Line Items]
Fair Value Liability	[1],[2]	353	507
Collateral Already Posted, Aggregate Fair Value	[2]	2,639	0
Contingent Collateral	[2]	0	0
Requested Credit for Adequate Assurance | Electric Portfolio
Derivative [Line Items]
Fair Value Liability	[1]	37,374	7,427
Collateral Already Posted, Aggregate Fair Value		0	0
Contingent Collateral		0	0
Credit Rating
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value		2,600
Credit Rating | Electric Portfolio
Derivative [Line Items]
Fair Value Liability	[1],[3]	3,187	4,894
Collateral Already Posted, Aggregate Fair Value	[3]	0	0
Contingent Collateral	[3]	$ 3,187	$ 4,894

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

[3] 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.

XML

Accounting for Derivative Instruments and Hedging Activities (Offsetting) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Energy derivative contracts
Assets:
Gross Amounts Recognized in the Statement of Financial Position 1	$ 24,405	$ 63,079
Gross Amounts Offset in the Statement of Financial Position	0	0
Net of Amounts Presented in the Statement of Financial Position	24,405	63,079
Commodity Contracts	17,940	42,858
Cash Collateral Received/Posted	0	0
Net Amount	6,465	20,221
Liabilities:
Gross Amounts Recognized in the Statement of Financial Position 1	86,094	60,430
Gross Amounts Offset in the Statement of Financial Position	0	0
Net of Amounts Presented in the Statement of Financial Position	86,094	60,430
Commodity Contracts	17,940	42,858
Cash Collateral Received/Posted	353	0
Net Amount	$ 67,801	17,572
Interest rate swaps
Liabilities:
Gross Amounts Recognized in the Statement of Financial Position 1		141
Gross Amounts Offset in the Statement of Financial Position		0
Net of Amounts Presented in the Statement of Financial Position		141
Commodity Contracts		0
Cash Collateral Received/Posted		0
Net Amount		$ 141

XML

Fair Value Measurements - Assets and Liabilities Measured on Recurring Basis (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Interest Rate Contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities			$ 141
Fair Value, Measurements, Recurring | Parent Company [Member] | Level 2 | Interest Rate Contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		$ 0	141
Fair Value, Measurements, Recurring | Parent Company [Member] | Level 3 | Electric Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	[1]	3,525
Derivative Liabilities	[1]	2,427
Fair Value, Measurements, Recurring | Parent Company [Member] | Level 3 | Natural Gas Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	[1]	4,041
Derivative Liabilities	[1]	2,118
Fair Value, Measurements, Recurring | Parent Company [Member] | Level 3 | Interest Rate Contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		0	0
Fair Value, Measurements, Recurring | Parent Company [Member] | Total | Interest Rate Contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		0	141
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		16,839	53,982
Derivative Liabilities		81,549	53,071
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Level 2 | Electric Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		9,866	30,666
Derivative Liabilities		46,623	36,507
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Level 2 | Natural Gas Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		6,973	23,316
Derivative Liabilities		34,926	16,423
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		7,566	9,097
Derivative Liabilities		4,545	7,500
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Level 3 | Electric Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets			5,794
Derivative Liabilities			4,822
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Level 3 | Natural Gas Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets			3,303
Derivative Liabilities			2,678
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Total
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		24,405	63,079
Derivative Liabilities		86,094	60,571
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Total | Electric Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		13,391	36,460
Derivative Liabilities		49,050	41,329
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Total | Natural Gas Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		11,014	26,619
Derivative Liabilities		37,044	19,101
Carrying Amount | Parent Company [Member] | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Notes receivable and other		$ 48,500	$ 49,100

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

XML

Fair Value Measurements - Debt at Carrying and Fair Value (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Subsidiaries [Member] | Carrying Amount | Income Approach Valuation Technique
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure		$ 3,749,911	$ 3,747,298
Subsidiaries [Member] | Carrying Amount | Income Approach Valuation Technique | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unamortized Debt Issuance Expense		24,600	27,200
Junior subordinated notes		250,000	250,000
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[1]	3,499,911	3,497,298
Subsidiaries [Member] | Total | Income Approach Valuation Technique
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure		4,789,065	4,571,044
Subsidiaries [Member] | Total | Income Approach Valuation Technique | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Junior subordinated notes		238,935	210,261
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[1]	4,550,130	4,360,783
Parent Company [Member] | Carrying Amount | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Notes Receivable, Fair Value Disclosure		48,500	49,100
Parent Company [Member] | Carrying Amount | Income Approach Valuation Technique
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure		5,457,929	5,354,073
Parent Company [Member] | Carrying Amount | Income Approach Valuation Technique | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unamortized Debt Issuance Expense		27,900	33,000
Junior subordinated notes		250,000	250,000
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[2]	5,105,329	5,091,593
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure		102,600	12,480
Parent Company [Member] | Total | Income Approach Valuation Technique
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure		6,862,050	6,560,028
Parent Company [Member] | Total | Income Approach Valuation Technique | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Junior subordinated notes		238,935	210,261
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[2]	6,520,515	6,337,287
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure		$ 102,600	$ 12,480

[1] 2 The carrying value includes debt issuances costs of $24.6 million and $27.2 million for December 31, 2017 and 2016, respectively, which are not included in fair value.

[2] 1 The carrying value includes debt issuances costs of $27.9 million and $33.0 million for December 31, 2017 and 2016, respectively, which are not included in fair value.

XML

Fair Value Measurements - Unobservable Input Reconciliation (Details)		3 Months Ended		9 Months Ended	12 Months Ended
		Mar. 31, 2017 USD ($) $ / MWh	Mar. 31, 2016 USD ($) $ / MWh	Sep. 30, 2017 USD ($) $ / MWh	Dec. 31, 2017 USD ($) $ / MWh	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		$ 1,597,000	$ (9,728,000)	$ 1,597,000	$ 1,597,000	$ (9,728,000)	$ (14,102,000)
Included in earnings	[1]				2,781,000	4,007,000	(6,432,000)
Included in regulatory assets / liabilities					6,346,000	4,312,000	3,695,000
Settlements	[2]				(12,921,000)	(3,808,000)	(2,983,000)
Transferred into Level 3					(30,000)	(3,021,000)	(787,000)
Transferred out of Level 3					5,248,000	9,835,000	10,881,000
Balance at end of period					3,021,000	1,597,000	(9,728,000)
Electric Portfolio
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		972,000	(7,345,000)	972,000	972,000	(7,345,000)	(12,062,000)
Included in earnings	[1]				2,781,000	4,007,000	(6,432,000)
Included in regulatory assets / liabilities					0	0	0
Settlements	[2]				(6,549,000)	(1,129,000)	902,000
Transferred into Level 3					523,000	(3,021,000)	(787,000)
Transferred out of Level 3					3,371,000	8,460,000	11,034,000
Balance at end of period					1,098,000	972,000	(7,345,000)
Unrealized gain (loss) on derivative instruments, net					1,500,000	2,000,000	(7,400,000)
Natural Gas Portfolio
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		$ 625,000	$ (2,383,000)	$ 625,000	625,000	(2,383,000)	(2,040,000)
Included in earnings	[1]				0	0	0
Included in regulatory assets / liabilities					6,346,000	4,312,000	3,695,000
Settlements	[2]				(6,372,000)	(2,679,000)	(3,885,000)
Transferred into Level 3					(553,000)	0	0
Transferred out of Level 3					1,877,000	1,375,000	(153,000)
Balance at end of period					$ 1,923,000	$ 625,000	$ (2,383,000)
Income Approach Valuation Technique | Minimum | Electric Portfolio
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh					7.02
Income Approach Valuation Technique | Minimum | Wells Project1
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh		8.76	9.46	14.06
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair Value Inputs, Power Contract Costs		$ 3,965	$ 4,100	$ 4,126
Income Approach Valuation Technique | Maximum | Electric Portfolio
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh					28.94
Income Approach Valuation Technique | Maximum | Wells Project1
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh		26.70	25.96	26.86
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair Value Inputs, Power Contract Costs		$ 4,223	$ 4,659	$ 4,126
Income Approach Valuation Technique | Weighted Average | Electric Portfolio
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh					18.61
Income Approach Valuation Technique | Weighted Average | Wells Project1
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh		20.86	21.38	22.24
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair Value Inputs, Power Contract Costs		$ 4,051	$ 4,452	$ 4,126

[1] Income Statement classification: 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 $1.5 million, $2.0 million and $(7.4) million for the years ended December 31, 2017, 2016 and 2015, respectively.

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

XML

Fair Value Measurements - Valuation Techniques (Details)		3 Months Ended			9 Months Ended		12 Months Ended
		Sep. 30, 2017 USD ($)	Mar. 31, 2017 USD ($) $ / MWh	Mar. 31, 2016 USD ($) $ / MWh	Sep. 30, 2017 USD ($) $ / MWh	Sep. 30, 2016 USD ($) $ / MWh	Dec. 31, 2017 USD ($) $ / MMBTU $ / MWh	Dec. 31, 2016 USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of Intangible Assets (Excluding Goodwill)				$ 5,338,000		$ 12,778,000	$ 81,345,000	$ 18,116,000
Fair Value measurement, sensitivity analysis, hypothetical increase or decrease of market prices, result on fair value, percent							10.00%
Fair Value Measurements, Sensitivity Analysis, Hypothetical Increase or Decrease of Market Prices, Result on Fair Value							$ (900,000)
Energy derivative contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net of Amounts Presented in the Statement of Financial Position							24,405,000	63,079,000
Net of Amounts Presented in the Statement of Financial Position							$ 86,094,000	$ 60,430,000
Natural Gas Portfolio | Income Approach Valuation Technique | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU							1.22
Natural Gas Portfolio | Income Approach Valuation Technique | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU							2.80
Natural Gas Portfolio | Income Approach Valuation Technique | Weighted Average
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU							1.54
Natural Gas Portfolio | Parent Company [Member] | Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net of Amounts Presented in the Statement of Financial Position	[1]						$ 4,041,000
Net of Amounts Presented in the Statement of Financial Position	[1]						$ 2,118,000
Electric Portfolio | Income Approach Valuation Technique | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh							7.02
Electric Portfolio | Income Approach Valuation Technique | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh							28.94
Electric Portfolio | Income Approach Valuation Technique | Weighted Average
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh							18.61
Electric Portfolio | Parent Company [Member] | Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net of Amounts Presented in the Statement of Financial Position	[1]						$ 3,525,000
Net of Amounts Presented in the Statement of Financial Position	[1]						$ 2,427,000
Wells Project1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Finite-Lived Intangible Assets, Net		$ 10,621,000	$ 14,879,000	$ 25,193,000	$ 10,621,000
Impairment of Intangible Assets (Excluding Goodwill)		1,012,000	$ 1,812,000
Wells Project1 | Income Approach Valuation Technique | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh			8.76	9.46	14.06
Fair Value Inputs, Power Contract Costs			$ 3,965	$ 4,100	$ 4,126
Wells Project1 | Income Approach Valuation Technique | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh			26.70	25.96	26.86
Fair Value Inputs, Power Contract Costs			$ 4,223	$ 4,659	$ 4,126
Wells Project1 | Income Approach Valuation Technique | Weighted Average
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh			20.86	21.38	22.24
Fair Value Inputs, Power Contract Costs			$ 4,051	$ 4,452	$ 4,126
Rocky Reach Project
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Finite-Lived Intangible Assets, Net			235,331,000
Impairment of Intangible Assets (Excluding Goodwill)			$ 75,513,000
Rocky Reach Project | Income Approach Valuation Technique | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh			8.53
Fair Value Inputs, Power Contract Costs			$ 5,827
Rocky Reach Project | Income Approach Valuation Technique | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh			48.21
Fair Value Inputs, Power Contract Costs			$ 6,780
Rocky Reach Project | Income Approach Valuation Technique | Weighted Average
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh			27.69
Fair Value Inputs, Power Contract Costs			$ 6,150
Priest Rapids Development
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Finite-Lived Intangible Assets, Net			5,665,000			$ 18,969,000
Impairment of Intangible Assets (Excluding Goodwill)			$ 3,008,000
Priest Rapids Development | Income Approach Valuation Technique | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh			13.70			24.24
Fair Value Inputs, Power Contract Costs			$ 620			$ 618
Priest Rapids Development | Income Approach Valuation Technique | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh			29.38			58.96
Fair Value Inputs, Power Contract Costs			$ 4,022			$ 4,633
Priest Rapids Development | Income Approach Valuation Technique | Weighted Average
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh			23.14			39.31
Fair Value Inputs, Power Contract Costs			$ 2,306			$ 2,472
Carrying Amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure				$ 19,855,000		$ 6,191,000
Carrying Amount | Wells Project1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure		$ 9,609,000	13,067,000		$ 9,609,000
Carrying Amount | Rocky Reach Project
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure			159,818,000
Carrying Amount | Priest Rapids Development
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure			$ 2,657,000

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

XML

Employee Investment Plans (Details) - Subsidiaries [Member] $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Defined Contribution Plan
Employer matching contribution, percent	1.00%	4.00%
Employer discretionary contribution amount		$ 19.2	$ 17.2	$ 16.1
Defined Contribution Plan, Vesting Years	3	3
6 percent
Defined Contribution Plan
Employer matching contribution, percent		4.50%
Maximum annual contribution per employee, percent		6.00%
Cash Balance Formula
Defined Contribution Plan
Employer matching contribution, percent		100.00%
Maximum annual contribution per employee, percent		6.00%
Employer additional contribution of base pay, percentage		1.00%
Cash Balance Formula | First 3 Percent
Defined Contribution Plan
Employer matching contribution, percent		100.00%
Maximum annual contribution per employee, percent		3.00%
Cash Balance Formula | Second 3 Percent
Defined Contribution Plan
Employer matching contribution, percent		50.00%
Maximum annual contribution per employee, percent		3.00%
Final Average Earnings Formula
Defined Contribution Plan
Employer matching contribution, percent		55.00%
Maximum annual contribution per employee, percent		6.00%

XML

Retirement Benefits - Change in Net Benefit Obligation and Fair Value (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Benefits
Change in benefit obligation:
Benefit obligation at beginning of period	$ 11,194	$ 13,946
Service cost	72	93
Interest cost	500	533
Actuarial loss (gain)	725	(2,262)
Benefits paid	(1,137)	(1,264)
Medicare part D subsidy received	100	148
Defined Benefit Plan, Expected Administration Expenses	0	0
Benefit obligation at end of period	11,454	11,194	$ 13,946
Change in plan assets:
Fair value of plan assets at beginning of period	7,200	7,203
Actual return on plan assets	784	926
Employer contribution	291	335
Benefits paid	(1,137)	(1,264)
Defined Benefit Plan, Plan Assets, Administration Expense	0	0
Fair value of plan assets at end of period	7,138	7,200	7,203
Funded status at end of period	(4,316)	(3,994)
Subsidiaries [Member] | Other Benefits
Change in benefit obligation:
Service cost	72	93	112
Interest cost	500	533	621
Estimate of Fair Value Measurement [Member] | Fair Value, Measurements, Recurring | Qualified Pension Benefits
Change in plan assets:
Fair value of plan assets at beginning of period	621,886
Fair value of plan assets at end of period	704,360	621,886
Estimate of Fair Value Measurement [Member] | Fair Value, Measurements, Recurring | Other Benefits
Change in plan assets:
Fair value of plan assets at beginning of period	7,262
Fair value of plan assets at end of period	7,138	7,262
Estimate of Fair Value Measurement [Member] | Net Receivables [Member] | Fair Value, Measurements, Recurring | Qualified Pension Benefits
Change in plan assets:
Fair value of plan assets at beginning of period	(9,894)
Fair value of plan assets at end of period	50,959	(9,894)
Nonqualified Plan | Qualified Pension Benefits
Change in benefit obligation:
Benefit obligation at beginning of period	51,734	51,279
Service cost	913	1,085
Interest cost	2,285	2,325
Actuarial loss (gain)	2,722	106
Benefits paid	(1,900)	(3,061)
Medicare part D subsidy received	0	0
Defined Benefit Plan, Expected Administration Expenses	0	0
Benefit obligation at end of period	55,754	51,734	51,279
Change in plan assets:
Fair value of plan assets at beginning of period	0	0
Actual return on plan assets	0	0
Employer contribution	1,900	3,061
Benefits paid	(1,900)	(3,061)
Defined Benefit Plan, Plan Assets, Administration Expense	0	0
Fair value of plan assets at end of period	0	0	0
Funded status at end of period	(55,754)	(51,734)
Nonqualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Change in benefit obligation:
Service cost	913	1,085	1,108
Interest cost	2,285	2,325	2,281
Qualified Plan | Qualified Pension Benefits
Change in benefit obligation:
Benefit obligation at beginning of period	652,607	643,088
Service cost	20,081	18,913
Interest cost	28,373	28,689
Actuarial loss (gain)	40,945	1,545
Benefits paid	(40,594)	(38,730)
Medicare part D subsidy received	0	0
Defined Benefit Plan, Expected Administration Expenses	(931)	(898)
Benefit obligation at end of period	700,481	652,607	643,088
Change in plan assets:
Fair value of plan assets at beginning of period	620,260	598,865
Actual return on plan assets	107,836	37,022
Employer contribution	18,000	24,000
Benefits paid	(40,594)	(38,730)
Defined Benefit Plan, Plan Assets, Administration Expense	(1,142)	(897)
Fair value of plan assets at end of period	704,360	620,260	598,865
Funded status at end of period	3,879	(32,347)
Qualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Change in benefit obligation:
Service cost	20,081	18,913	21,287
Interest cost	$ 28,373	$ 28,689	$ 28,088

XML

Retirement Benefits - Amounts Recognized (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation		$ 11,454	$ 11,194	$ 13,946
Defined Benefit Plan, Accumulated Benefit Obligation		11,367	11,092
Defined Benefit Plan, Fair Value of Plan Assets		7,138	7,200	7,203
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract]
Noncurrent assets		0	0
Current liabilities		(317)	(325)
Noncurrent liabilities		(3,999)	(3,669)
Net assets (liabilities)		(4,316)	(3,994)
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)		403	(2,742)
Amortization of net (loss) gain		401	385
Amortization of prior service (cost) credit		0	0
Total change in other comprehensive income for year		804	(2,357)
Parent Company [Member] | Other Benefits
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)		(3,386)	(4,190)
Prior service cost (credit)		0	0
Total		(3,386)	(4,190)
Subsidiaries [Member] | Other Benefits
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)		(4,901)	(5,994)
Prior service cost (credit)		0	0
Total		(4,901)	(5,994)
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)		452	(2,742)
Amortization of net (loss) gain		641	631
Amortization of prior service (cost) credit		0	0
Total change in other comprehensive income for year		1,093	(2,111)
Nonqualified Plan | Qualified Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation		55,754	51,734	51,279
Defined Benefit Plan, Accumulated Benefit Obligation		52,681	47,639
Defined Benefit Plan, Fair Value of Plan Assets		0	0	0
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract]
Noncurrent assets		0	0
Current liabilities		(5,486)	(1,911)
Noncurrent liabilities		(50,268)	(49,823)
Net assets (liabilities)		(55,754)	(51,734)
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)		2,722	106
Amortization of net (loss) gain		(1,076)	(910)
Amortization of prior service (cost) credit		(42)	(42)
Total change in other comprehensive income for year		1,604	(846)
Nonqualified Plan | Parent Company [Member] | Qualified Pension Benefits
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)		10,689	9,043
Prior service cost (credit)		204	246
Total		10,893	9,289
Nonqualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)		13,134	11,978
Prior service cost (credit)		208	251
Total		13,342	12,229
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)		2,722	106
Amortization of net (loss) gain		(1,565)	(1,330)
Amortization of prior service (cost) credit		(44)	(44)
Total change in other comprehensive income for year		1,113	(1,268)
Qualified Plan | Qualified Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation		700,481	652,607	643,088
Defined Benefit Plan, Accumulated Benefit Obligation		688,908	641,855
Defined Benefit Plan, Fair Value of Plan Assets		704,360	620,260	$ 598,865
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract]
Noncurrent assets		3,879	0
Current liabilities		0	0
Noncurrent liabilities		0	(32,347)
Net assets (liabilities)		3,879	(32,347)
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)		(18,896)	11,141
Amortization of net (loss) gain		0	0
Amortization of prior service (cost) credit		1,980	1,980
Total change in other comprehensive income for year		(16,916)	13,121
Qualified Plan | Parent Company [Member] | Qualified Pension Benefits
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)		37,693	56,588
Prior service cost (credit)		(7,843)	(9,822)
Total		29,850	46,766
Qualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)		185,277	217,143
Prior service cost (credit)		(6,232)	(7,806)
Total		179,045	209,337
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)		(18,817)	11,336
Amortization of net (loss) gain		(13,048)	(15,257)
Amortization of prior service (cost) credit		1,573	1,573
Total change in other comprehensive income for year		$ (30,292)	$ (2,348)
Scenario, Plan [Member] | Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Plans, Net Gain (Loss), Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	$ (1,100)
Scenario, Plan [Member] | Subsidiaries [Member] | Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Plans, Net Gain (Loss), Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	600
Scenario, Plan [Member] | Nonqualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Plans, Net Gain (Loss), Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	(2,100)
Scenario, Plan [Member] | Qualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Plans, Net Gain (Loss), Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	$ (14,500)

XML

Retirement Benefits - Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Benefits
Components of net periodic benefit cost:
Service cost	$ 72	$ 93
Interest cost	500	533
Parent Company [Member] | Other Benefits
Components of net periodic benefit cost:
Service cost	72	93	$ 112
Interest cost	500	533	621
Expected return on plan assets	(461)	(446)	(531)
Amortization of prior service cost (credit)	0	0	0
Amortization of net loss (gain)	(402)	(386)	(130)
Net periodic benefit cost	(291)	(206)	72
Subsidiaries [Member] | Other Benefits
Components of net periodic benefit cost:
Service cost	72	93	112
Interest cost	500	533	621
Expected return on plan assets	(461)	(446)	(531)
Amortization of prior service cost (credit)	0	0	3
Amortization of net loss (gain)	(641)	(632)	(406)
Net periodic benefit cost	(530)	(452)	(201)
Nonqualified Plan | Qualified Pension Benefits
Components of net periodic benefit cost:
Service cost	913	1,085
Interest cost	2,285	2,325
Nonqualified Plan | Parent Company [Member] | Qualified Pension Benefits
Components of net periodic benefit cost:
Service cost	913	1,085	1,108
Interest cost	2,285	2,325	2,281
Expected return on plan assets	0	0	0
Amortization of prior service cost (credit)	42	42	42
Amortization of net loss (gain)	1,077	911	1,641
Net periodic benefit cost	4,317	4,363	5,072
Nonqualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Components of net periodic benefit cost:
Service cost	913	1,085	1,108
Interest cost	2,285	2,325	2,281
Expected return on plan assets	0	0	0
Amortization of prior service cost (credit)	44	44	44
Amortization of net loss (gain)	1,565	1,330	2,120
Net periodic benefit cost	4,807	4,784	5,553
Qualified Plan | Qualified Pension Benefits
Components of net periodic benefit cost:
Service cost	20,081	18,913
Interest cost	28,373	28,689
Qualified Plan | Parent Company [Member] | Qualified Pension Benefits
Components of net periodic benefit cost:
Service cost	20,081	18,913	21,287
Interest cost	28,373	28,689	28,088
Expected return on plan assets	(47,784)	(46,619)	(45,038)
Amortization of prior service cost (credit)	(1,980)	(1,980)	(1,980)
Amortization of net loss (gain)	0	0	3,887
Net periodic benefit cost	(1,310)	(997)	6,244
Qualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Components of net periodic benefit cost:
Service cost	20,081	18,913	21,287
Interest cost	28,373	28,689	28,088
Expected return on plan assets	(47,862)	(46,814)	(45,462)
Amortization of prior service cost (credit)	(1,573)	(1,573)	(1,573)
Amortization of net loss (gain)	13,048	15,257	20,555
Net periodic benefit cost	$ 12,067	$ 14,472	$ 22,895

XML

Retirement Benefits - Assumptions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2018
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates
1% Increase, Effect on post-retirement benefit obligation		$ 23	$ 38
1% Decrease, Effect on post-retirement benefit obligation		(22)	(35)
1% Increase, Effect on service and interest cost components		1	2
1% Decrease, Effect on service and interest cost components		$ (1)	$ (2)
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Current and Prior Fiscal Year		1.00%
Other Benefits
Benefit Obligation Assumptions
Discount rate		4.00%	4.50%	4.65%
Rate of compensation increase		4.50%	4.50%	4.50%
Medical trend rate		6.80%	8.80%	7.20%
Benefit Cost Assumptions
Discount rate		4.50%	4.65%	4.25%
Return on plan assets		6.75%	6.75%	7.00%
Rate of compensation increase		4.50%	4.50%	4.50%
Medical trend rate		9.50%	5.30%	7.20%
Nonqualified Plan | Qualified Pension Benefits
Benefit Obligation Assumptions
Discount rate		4.00%	4.50%	4.65%
Rate of compensation increase		4.50%	4.50%	4.50%
Medical trend rate		0.00%	0.00%	0.00%
Benefit Cost Assumptions
Discount rate		4.50%	4.65%	4.25%
Return on plan assets		0.00%	0.00%	0.00%
Rate of compensation increase		4.50%	4.50%	4.50%
Medical trend rate		0.00%	0.00%	0.00%
Qualified Plan | Qualified Pension Benefits
Benefit Obligation Assumptions
Discount rate		4.00%	4.50%	4.65%
Rate of compensation increase		4.50%	4.50%	4.50%
Medical trend rate		0.00%	0.00%	0.00%
Benefit Cost Assumptions
Discount rate		4.50%	4.65%	4.25%
Return on plan assets		7.45%	7.75%	7.75%
Rate of compensation increase		4.50%	4.50%	4.50%
Medical trend rate		0.00%	0.00%	0.00%
Scenario, Plan [Member]
Assumed Health Care Cost Trend Rates
Medical inflation rate assumed for next fiscal year					6.80%
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates
defined benefit plan health care cost trend rate assumed for next two years	4.10%

XML

Retirement Benefits - Future Benefit Payments (Details) $ in Thousands	Dec. 31, 2017 USD ($)
Other Benefits
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
2016	$ 911
2017	885
2018	852
2019	811
2020	863
2021-2025	3,748
2016, without Medicare Part D subsidy	1,172
2017, without Medicare Part D subsidy	1,155
2018, without Medicare Part D subsidy	1,131
2019, without Medicare Part D subsidy	1,097
2020, without Medicare Part D subsidy	1,070
2021-2025, without Medicare Part D subsidy	4,844
Qualified Plan | Qualified Pension Benefits
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
2016	42,600
2017	43,400
2018	44,800
2019	45,700
2020	46,900
2021-2025	246,500
Nonqualified Plan | Qualified Pension Benefits
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
2016	5,486
2017	6,001
2018	4,684
2019	1,728
2020	4,577
2021-2025	$ 37,394

XML

Retirement Benefits - Plan Asset Allocation (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
Domestic Small Cap Equity Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation		9.00%
Foreign Equity Funds [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation		25.00%
Domestic Large Cap Equity Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation		31.00%
Fixed income
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation		25.00%
Real estate
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation		0.00%
Absolute return
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation		10.00%
Cash and cash equivalents
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation		0.00%
Fair Value, Measurements, Recurring | Pension Plan [Member] | Total
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 704,360	$ 621,886
Fair Value, Measurements, Recurring | Equities: | Pension Plan [Member] | Level 1
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		348,300	354,221
Fair Value, Measurements, Recurring | Equities: | Pension Plan [Member] | Level 2
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		67,674	54,740
Fair Value, Measurements, Recurring | Equities: | Pension Plan [Member] | Total
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		415,974	408,961
Fair Value, Measurements, Recurring | Fair Value Measurement [Domain] | Pension Plan [Member] | Total
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		237,427	222,819
Fair Value, Measurements, Recurring | Mutual Funds | Pension Plan [Member] | Level 1
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[1]	117,796	181,212
Fair Value, Measurements, Recurring | Mutual Funds | Pension Plan [Member] | Level 2
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[1]	0	0
Fair Value, Measurements, Recurring | Mutual Funds | Pension Plan [Member] | Total
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[1]	117,796	181,212
Fair Value, Measurements, Recurring | Common Stock | Pension Plan [Member] | Level 1
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		209,504	154,255
Fair Value, Measurements, Recurring | Common Stock | Pension Plan [Member] | Level 2
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Fair Value, Measurements, Recurring | Common Stock | Pension Plan [Member] | Total
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		209,504	154,255
Fair Value, Measurements, Recurring | US Treasury and Government [Member] | Pension Plan [Member] | Level 1
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		18,316	18,754
Fair Value, Measurements, Recurring | US Treasury and Government [Member] | Pension Plan [Member] | Level 2
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		23,782	16,197
Fair Value, Measurements, Recurring | US Treasury and Government [Member] | Pension Plan [Member] | Total
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		42,098	34,951
Fair Value, Measurements, Recurring | Corporate Bond Securities [Member] | Pension Plan [Member] | Level 1
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Fair Value, Measurements, Recurring | Corporate Bond Securities [Member] | Pension Plan [Member] | Level 2
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		34,588	38,543
Fair Value, Measurements, Recurring | Corporate Bond Securities [Member] | Pension Plan [Member] | Total
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		34,588	38,543
Fair Value, Measurements, Recurring | Cash and cash equivalents | Pension Plan [Member] | Level 1
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		2,684	0
Fair Value, Measurements, Recurring | Cash and cash equivalents | Pension Plan [Member] | Level 2
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		9,304	0
Fair Value, Measurements, Recurring | Cash and cash equivalents | Pension Plan [Member] | Total
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 11,988	$ 0
Minimum | Domestic Small Cap Equity Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)		0
Minimum | Foreign Equity Funds [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)		0.1
Minimum | Domestic Large Cap Equity Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)		0.25
Minimum | Fixed income
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)		0.15
Minimum | Real estate
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)		0
Minimum | Absolute return
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)		0.05
Minimum | Cash and cash equivalents
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)		0
Maximum | Domestic Small Cap Equity Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)		0.15
Maximum | Foreign Equity Funds [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)		0.3
Maximum | Domestic Large Cap Equity Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)		0.4
Maximum | Fixed income
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)		0.3
Maximum | Real estate
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)		0.1
Maximum | Absolute return
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)		0.15
Maximum | Cash and cash equivalents
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)		0.05

[1] In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments that were measured at NAV per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV primarily consist of common/collective trust funds and two partnerships held as of December 31, 2017.Mesirow Institutional Multi-Strategy Fund Partnership, L.P. utilizes a combination of long and short strategies through investments in investment funds. The major strategy allocations of the investment funds include (1) Investments in debt obligations of public and private entities; typically, in financial duress, and (2) Investments in equity positions on a global basis utilizing fundamental analysis.Grosvenor Institutional Partners Fund, L.P invests substantially all of the fund assets available in the Grosvenor Master Fund, a Cayman Islands exempted company which is sponsored, managed and has the same investment objective as the Partnership fund. In addition to the Master Fund, investments are made primarily in offshore investment funds, investment partnerships, and pooled investment vehicles; collectively referred to as Portfolio Funds, which generally implement "nontraditional" or "alternative" investment strategies.

XML

Retirement Benefits - Textuals (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017
Subsidiaries [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent	1.00%		4.00%
Scenario, Plan [Member] | Other Benefits
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year, Net Gain (Loss)		$ (1.1)
Scenario, Plan [Member] | Subsidiaries [Member] | Other Benefits
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year, Net Gain (Loss)		0.6
Estimated Future Employer Contributions in Current Fiscal Year		0.3
Scenario, Plan [Member] | Qualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year, Net Gain (Loss)		(14.5)
Pension and Other Postretirement Benefit Plans, Net Prior Service Cost or Credit, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year		1.6
Estimated Future Employer Contributions in Current Fiscal Year		18.0
Scenario, Plan [Member] | Nonqualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year, Net Gain (Loss)		(2.1)
Estimated Future Employer Contributions in Current Fiscal Year		$ 5.5

XML

Retirement Benefits Accumulated Benefit Obligation (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation		$ 11,454	$ 11,194	$ 13,946
Defined Benefit Plan, Accumulated Benefit Obligation		11,367	11,092
Defined Benefit Plan, Fair Value of Plan Assets		7,138	7,200	$ 7,203
Fair Value, Measurements, Recurring | Level 1 | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets
Fair Value, Measurements, Recurring | Level 1 | Mutual Funds | Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[1]	117,796	181,212
Fair Value, Measurements, Recurring | Level 1 | Mutual Funds | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[2]	7,089	7,182
Fair Value, Measurements, Recurring | Level 1 | Cash and cash equivalents | Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		2,684	0
Fair Value, Measurements, Recurring | Estimate of Fair Value Measurement [Member] | Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		704,360	621,886
Fair Value, Measurements, Recurring | Estimate of Fair Value Measurement [Member] | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		7,138	7,262
Fair Value, Measurements, Recurring | Estimate of Fair Value Measurement [Member] | Mutual Funds | Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[1]	117,796	181,212
Fair Value, Measurements, Recurring | Estimate of Fair Value Measurement [Member] | Mutual Funds | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[2]	7,089	7,182
Fair Value, Measurements, Recurring | Estimate of Fair Value Measurement [Member] | Cash and cash equivalents | Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		11,988	0
Fair Value, Measurements, Recurring | Estimate of Fair Value Measurement [Member] | Fair Value Measurement [Domain] | Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		237,427	222,819
Fair Value, Measurements, Recurring | Estimate of Fair Value Measurement [Member] | Fair Value Measurement [Domain] | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[3]	49	80
Fair Value, Measurements, Recurring | Level 2 | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets
Fair Value, Measurements, Recurring | Level 2 | Mutual Funds | Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[1]	0	0
Fair Value, Measurements, Recurring | Level 2 | Mutual Funds | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[2]	0	0
Fair Value, Measurements, Recurring | Level 2 | Cash and cash equivalents | Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 9,304	$ 0

[1] In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments that were measured at NAV per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV primarily consist of common/collective trust funds and two partnerships held as of December 31, 2017.Mesirow Institutional Multi-Strategy Fund Partnership, L.P. utilizes a combination of long and short strategies through investments in investment funds. The major strategy allocations of the investment funds include (1) Investments in debt obligations of public and private entities; typically, in financial duress, and (2) Investments in equity positions on a global basis utilizing fundamental analysis.Grosvenor Institutional Partners Fund, L.P invests substantially all of the fund assets available in the Grosvenor Master Fund, a Cayman Islands exempted company which is sponsored, managed and has the same investment objective as the Partnership fund. In addition to the Master Fund, investments are made primarily in offshore investment funds, investment partnerships, and pooled investment vehicles; collectively referred to as Portfolio Funds, which generally implement "nontraditional" or "alternative" investment strategies.

[2] 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, 2017.

[3] In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments that were measured at NAV per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV consist of a common/collective trust fund as of December 31, 2017.

XML

Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosures [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	35.00%
Other Deductions or Allowable Credits	$ 0.300
Current Federal Tax Expense (Benefit)	1,127,000	$ 0	$ 0
Current State and Local Tax Expense (Benefit)	17,000	20,000	0
Federal	254,420,000	140,315,000	91,968,000
State	(421,000)	(131,000)	(192,000)
Total income tax expense	255,143,000	140,204,000	91,776,000
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Revenue Change	51,200,000
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, effect on income tax expense	17,900,000
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Effect on Income Taxes due to revaluation	80,900,000
Subsidiaries [Member]
Income Tax Disclosures [Line Items]
Current Federal Tax Expense (Benefit)	1,127,000	0	0
Current State and Local Tax Expense (Benefit)	17,000	20,000	0
Federal	210,842,000	175,327,000	125,900,000
State	0	0	0
Total income tax expense	211,986,000	$ 175,347,000	$ 125,900,000
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, unregulated portion	3,000,000
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, PTC revaluation	$ 33,300,000

XML

Income Taxes - Income Tax Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosures [Line Items]
Current Federal Tax Expense (Benefit)	$ 1,127	$ 0	$ 0
Current State and Local Tax Expense (Benefit)	17	20	0
Federal	254,420	140,315	91,968
State	$ (421)	(131)	(192)
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	35.00%
Income Tax Reconciliation [Abstract]
Income taxes at the statutory rate	$ 148,847	158,586	116,534
Production tax credit1	0	(12,925)	(19,470)
Utility plant differences	0	3,966	5,671
Income Tax Reconciliation, Treasury Grant	(9,537)	(9,788)	(8,807)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	117,185	0	0
Other - net	(1,352)	365	(2,152)
Total income tax expense	$ 255,143	$ 140,204	$ 91,776
Effective tax rate	60.00%	30.90%	27.60%
Regulatory asset for income taxes	$ 0	$ 72,038
Deferred Tax Assets, Regulatory Assets and Liabilities, Accelerated Tax Depreciation	919,800
Deferred Tax Assets, Regulatory Assets and Liabilities, Undetermined refund	92,500
Subsidiaries [Member]
Income Tax Disclosures [Line Items]
Current Federal Tax Expense (Benefit)	1,127	0	$ 0
Current State and Local Tax Expense (Benefit)	17	20	0
Federal	210,842	175,327	125,900
State	0	0	0
Income Tax Reconciliation [Abstract]
Income taxes at the statutory rate	185,430	194,572	150,531
Production tax credit1	0	(12,925)	(19,470)
Utility plant differences	0	3,966	5,671
Income Tax Reconciliation, Treasury Grant	(9,537)	(9,788)	(8,807)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	36,328	0	0
Other - net	(235)	(478)	(2,025)
Total income tax expense	$ 211,986	$ 175,347	$ 125,900
Effective tax rate	40.00%	31.50%	29.30%
Regulatory asset for income taxes	$ 0	$ 71,517
Deferred Tax Assets, Regulatory Assets and Liabilities	$ (1,012,300)

XML

Income Taxes - Deferred Income Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Deferred Tax Liabilities, Gross
Utility plant and equipment	$ 2,034,328	$ 1,880,782
Regulatory asset for income taxes	0	72,038
Fair value of debt instruments	38,777	67,444
Deferred Tax Liabilities, Pension and Other Compensation	46,338	77,230
Other deferred tax liabilities	86,933	119,050
Subtotal deferred tax liabilities	2,206,376	2,216,544
Deferred Tax Assets, Net Regulatory Liability for Income Taxes	(1,011,626)	0
Deferred Tax Assets, Gross
Net operating loss carryforward	(212,168)	(352,827)
Production tax credit carryforward	(187,617)	(190,999)
Regulatory liability on production tax credit	(49,873)	(101,787)
Deferred Tax Assets, Other	1,776	0
Subtotal deferred tax assets	(1,459,508)	(645,613)
Total net deferred tax liabilities	746,868	1,570,931
Subsidiaries [Member]
Deferred Tax Liabilities, Gross
Utility plant and equipment	2,034,328	1,880,782
Regulatory asset for income taxes	0	71,517
Other deferred tax liabilities	86,933	113,938
Subtotal deferred tax liabilities	2,121,261	2,066,237
Deferred Tax Assets, Net Regulatory Liability for Income Taxes	(1,012,260)	0
Deferred Tax Assets, Gross
Net operating loss carryforward	0	(41,061)
Production tax credit carryforward	(187,617)	(190,999)
Regulatory liability on production tax credit	(49,873)	(101,787)
Deferred Tax Assets, Other	(2,038)	0
Subtotal deferred tax assets	(1,251,788)	(333,847)
Total net deferred tax liabilities	$ 869,473	$ 1,732,390

XML

Income Taxes - Balance Sheet Location (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosures [Line Items]
Non-current deferred taxes	$ 746,868	$ 1,570,931
Total net deferred tax liabilities	746,868	1,570,931
Subsidiaries [Member]
Income Tax Disclosures [Line Items]
Non-current deferred taxes	869,473	1,732,390
Total net deferred tax liabilities	$ 869,473	$ 1,732,390

XML

Litigation (Details) $ in Millions			12 Months Ended
	Jun. 19, 2017 USD ($)	Mar. 28, 2017 USD ($)	Dec. 31, 2017 USD ($) unit	Dec. 31, 2016 USD ($)	Sep. 30, 2016 USD ($)	Sep. 20, 2016 USD ($)
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss						$ 3.2
Loss Contingency, Accrual, Current					$ 3.2
Litigation Settlement, Amount Awarded to Other Party	$ 2.8	$ 2.8
Loss Contingency, Estimate of Possible Loss	$ 1.3	$ 1.3
CAR Emissions Cap % Reduction for Covered Entities			5.00%
Number of Natural Gas Customers			1,200,000.0
Pending Litigation
Loss Contingencies [Line Items]
Litigation claims accrual			$ 2.4	$ 0.7
Colstrip Unit One and Two
Loss Contingencies [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
Colstrip Unit Three and Four
Loss Contingencies [Line Items]
Equity Method Investment, Ownership Percentage			25.00%
Colstrip Unit One and Two
Loss Contingencies [Line Items]
Number of Units | unit			2
Colstrip Regulatory Asset [Domain]
Loss Contingencies [Line Items]
Regulatory Assets			$ 127.6	$ 176.8

XML

Commitments and Contingencies (Details) $ in Thousands, MWh in Millions	12 Months Ended
	Dec. 31, 2017 USD ($) MWh Contracts $ / kWh MW	Dec. 31, 2016 USD ($) MWh	Dec. 31, 2015 USD ($) MWh
Long-term Purchase Commitment [Line Items]
Long-term Line of Credit, Noncurrent	$ 102,600	$ 12,480
Average cost of Company's energy output (US$ per kWh) | $ / kWh	0.022
Number of Public Utility Districts with long term purchase agreements | Contracts	3
Contract expenses	$ 73,827	$ 77,667	$ 72,833
Percent of Output	13.30%
Megawatt Capacity | MW	745
Estimated 2018 Costs	$ 73,037
2018 Debt Service Costs	23,058
Interest included in 2018 Debt Service Costs	11,743
Debt Outstanding	200,907
Payment Obligations for Power Purchases
2014	360,476
2015	332,694
2016	333,720
2017	336,824
2018	335,924
Thereafter	1,836,965
Total	$ 3,536,603
Total energy obtained during period under purchased power contracts (MWh) | MWh	14.5	13.0	11.2
Cost incurred during period to provide energy under purchased power contracts	$ 456,400	$ 402,500	$ 373,800
Daily take obligation under long-term service contract (percent)	100.00%
Daily delivery obligation under long-term service contract (percent)	100.00%
Natural Gas [Member]
Payment Obligations for Power Purchases
2014	$ 245,669
2015	193,458
2016	163,818
2017	145,662
2018	109,401
Thereafter	0
Total	858,008
Columbia River projects
Payment Obligations for Power Purchases
2014	82,200
2015	97,890
2016	95,704
2017	91,862
2018	91,018
Thereafter	708,499
Total	1,167,173
Other utilities
Payment Obligations for Power Purchases
2014	1,257
2015	888
2016	0
2017	0
2018	0
Thereafter	0
Total	2,145
Non-utility contracts
Payment Obligations for Power Purchases
2014	206,233
2015	233,776
2016	238,016
2017	244,962
2018	244,906
Thereafter	1,128,466
Total	2,296,359
Firm transportation service
Payment Obligations for Power Purchases
2014	154,170
2015	154,204
2016	141,962
2017	126,319
2018	125,335
Thereafter	310,428
Total	1,012,418
Firm Storage and Peaking Service [Member]
Payment Obligations for Power Purchases
2014	8,328
2015	8,899
2016	7,908
2017	3,108
2018	1,619
Thereafter	857
Total	30,719
Long-term Purchase Commitment, Demand Charges	121,400
Firm natural gas supply
Payment Obligations for Power Purchases
2014	463,941
2015	370,379
2016	315,339
2017	275,089
2018	236,355
Thereafter	311,285
Total	1,972,388
Combustion turbines
Payment Obligations for Power Purchases
Long-term Purchase Commitment, Demand Charges	41,800
Energy production service contracts
Payment Obligations for Power Purchases
2014	28,674
2015	27,939
2016	28,639
2017	29,415
2018	30,142
Thereafter	165,689
Total	310,498
Automated meter reading system
Payment Obligations for Power Purchases
2014	48,245
2015	44,842
2016	43,951
2017	44,497
2018	45,168
Thereafter	187,698
Total	414,401
Service contract obligations
Payment Obligations for Power Purchases
2014	76,919
2015	72,781
2016	72,590
2017	73,912
2018	75,310
Thereafter	353,387
Total	724,899
Short-Term Energy Supply Contracts [Member]
Payment Obligations for Power Purchases
2014	55,774
2015	13,818
2016	1,651
2017	0
2018	0
Thereafter	0
Total	71,243
Short-Term Energy Supply Contracts [Member]
Payment Obligations for Power Purchases
2014	70,786
2015	140
2016	0
2017	0
2018	0
Thereafter	0
Total	$ 70,926
Minimum | Combustion turbines
Payment Obligations for Power Purchases
Remaining terms under contract	1 year
Maximum | Combustion turbines
Payment Obligations for Power Purchases
Remaining terms under contract	27
Rock Island Project
Long-term Purchase Commitment [Line Items]
Percent of Output	25.00%
Megawatt Capacity | MW	156
Estimated 2018 Costs	$ 29,135
2018 Debt Service Costs	10,105
Interest included in 2018 Debt Service Costs	5,354
Debt Outstanding	$ 84,269
Rocky Reach Project
Long-term Purchase Commitment [Line Items]
Percent of Output	25.00%
Megawatt Capacity | MW	325
Estimated 2018 Costs	$ 28,800
2018 Debt Service Costs	5,796
Interest included in 2018 Debt Service Costs	2,548
Debt Outstanding	$ 39,563
Wells Project1
Long-term Purchase Commitment [Line Items]
Percent of Output	29.90%
Megawatt Capacity | MW	251
Estimated 2018 Costs	$ 11,002
2018 Debt Service Costs	4,695
Interest included in 2018 Debt Service Costs	1,379
Debt Outstanding	$ 49,629
Priest Rapids Development
Long-term Purchase Commitment [Line Items]
Percent of Output	0.60%
Megawatt Capacity | MW	6
Estimated 2018 Costs	$ 2,050
2018 Debt Service Costs	1,231
Interest included in 2018 Debt Service Costs	1,231
Debt Outstanding	$ 13,723
Wanapum Development
Long-term Purchase Commitment [Line Items]
Percent of Output	0.60%
Megawatt Capacity | MW	7
Estimated 2018 Costs	$ 2,050
2018 Debt Service Costs	1,231
Interest included in 2018 Debt Service Costs	1,231
Debt Outstanding	$ 13,723

XML

Related Party Transactions (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Related Party Transaction [Line Items]
Number of Residents receiving Group Health Coverage in WA and N. ID	600,000,000
Related Party Transaction, Due from (to) Related Party		$ 1.0
Affiliated Entity [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction	$ 0.8	1.0	$ 1.8
Subsidiaries [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction		$ 23.3	$ 20.3

XML

Segment Information (Details)	12 Months Ended
	Dec. 31, 2017 mi² segment
Segment Reporting Information [Line Items]
Number of operating segments | segment	1
Subsidiaries [Member]
Segment Reporting Information [Line Items]
Area of service territory (sqmi) | mi²	6,000

XML

Accumulated Other Comprehensive Income (Loss) Changes in AOCI, net of tax (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	$ (33,712)
Accumulated other comprehensive income (loss), net of tax	(24,282)	$ (33,712)
Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(145,511)
Accumulated other comprehensive income (loss), net of tax	(126,906)	(145,511)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(33,712)	(27,266)	$ (36,710)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	10,251	(5,528)	7,196
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(821)	(918)	2,248
Other Comprehensive Income (Loss), Net of Tax	9,430	(6,446)	9,444
Accumulated other comprehensive income (loss), net of tax	(24,282)	(33,712)	(27,266)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(140,155)	(143,877)	(164,281)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	10,200	(5,655)	6,922
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	8,088	9,377	13,482
Other Comprehensive Income (Loss), Net of Tax	18,288	3,722	20,404
Accumulated other comprehensive income (loss), net of tax	(121,867)	(140,155)	(143,877)
Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(33,712)	(27,266)	(37,043)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	10,251	(5,528)	7,196
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(821)	(918)	2,581
Other Comprehensive Income (Loss), Net of Tax	9,430	(6,446)	9,777
Accumulated other comprehensive income (loss), net of tax	(24,282)	(33,712)	(27,266)
Comprehensive Income [Member] | Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(145,511)	(149,550)	(170,957)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	10,200	(5,655)	6,922
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	8,405	9,694	14,485
Other Comprehensive Income (Loss), Net of Tax	18,605	4,039	21,407
Accumulated other comprehensive income (loss), net of tax	(126,906)	(145,511)	(149,550)
Energy Related Derivative [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	0	0	(333)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0	0	333
Other Comprehensive Income (Loss), Net of Tax	0	0	333
Accumulated other comprehensive income (loss), net of tax	0	0	0
Energy Related Derivative [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member] | Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	0	0	(686)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0	0	686
Other Comprehensive Income (Loss), Net of Tax	0	0	686
Accumulated other comprehensive income (loss), net of tax	0	0	0
Interest Rate Swap [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member] | Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(5,356)	(5,673)	(5,990)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	317	317	317
Other Comprehensive Income (Loss), Net of Tax	317	317	317
Accumulated other comprehensive income (loss), net of tax	$ (5,039)	$ (5,356)	$ (5,673)

XML

Accumulated Other Comprehensive Income (Loss) Reclassifications Out of Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification of net unrealized loss on energy derivative instruments during the period, tax		$ 0	$ 0	$ (179)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		0	0	(333)
Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification of net unrealized loss on energy derivative instruments during the period, tax		0	0	(369)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		0	0	(686)
Reclassification out of Accumulated Other Comprehensive Income | Parent Company [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Comprehensive income (loss)		821	918	(2,581)
Reclassification out of Accumulated Other Comprehensive Income | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Comprehensive income (loss)		(8,405)	(9,694)	(14,485)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | Parent Company [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Amortization of prior service cost	[1]	1,938	1,938	1,938
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax	[1]	(675)	(525)	(5,397)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax		1,263	1,413	(3,459)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax		(442)	(495)	1,211
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, after Tax		821	918	(2,248)
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Noncontrolling Interest [Member] | Energy Related Derivative [Member] | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax		0	0	(1,055)
Reclassification of net unrealized loss on energy derivative instruments during the period, tax		0	0	369
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		0	0	(686)
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Noncontrolling Interest [Member] | Interest Rate Swap [Member] | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax		(488)	(488)	(488)
Reclassification of net unrealized loss on energy derivative instruments during the period, tax		171	171	171
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		(317)	(317)	(317)
Accumulated Defined Benefit Plans Adjustment Attributable to Noncontrolling Interest [Member] | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Amortization of prior service cost	[2]	1,529	1,529	1,526
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax	[2]	(13,972)	(15,955)	(22,268)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax		(12,443)	(14,426)	(20,742)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax		4,355	5,049	7,260
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, after Tax		(8,088)	(9,377)	(13,482)
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Energy Related Derivative [Member] | Parent Company [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax		0	0	(512)
Reclassification of net unrealized loss on energy derivative instruments during the period, tax		0	0	179
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		$ 0	$ 0	$ (333)

[1] These AOCI components are included in the computation of net periodic pension cost, see Note 12, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details.

[2] These AOCI components are included in the computation of net periodic pension cost, see Note 12, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details.

XML

SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information [Line Items]
Operating revenues									$ 3,460,276	$ 3,164,301	$ 3,092,700
Operating income									760,497	785,384	671,925
Net income (loss)									175,194	312,899	241,179
Parent Company [Member]
Quarterly Financial Information [Line Items]
Operating revenues	$ 1,002,900	$ 660,377	$ 719,767	$ 1,077,232	$ 915,157	$ 618,278	$ 668,169	$ 962,697
Operating income	259,696	99,044	130,030	271,727	236,854	88,072	175,634	284,824
Net income (loss)	(467)	12,836	35,275	127,550	104,825	2,335	64,553	141,186	175,194	312,899	241,179
Subsidiaries [Member]
Quarterly Financial Information [Line Items]
Operating revenues	1,002,900	660,377	719,767	1,077,232	915,158	618,594	668,169	962,697	3,460,276	3,164,618	3,093,258
Operating income	257,009	96,369	126,800	268,431	237,101	84,476	171,991	281,425	748,609	774,993	656,138
Net income (loss)	$ 97,208	$ 29,100	$ 50,654	$ 143,092	$ 124,199	$ 18,977	$ 80,900	$ 156,505	$ 320,054	$ 380,581	$ 304,189

XML

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY - Condensed Statements of Income (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Financial Statements, Captions [Line Items]
Non-utility expense and other									$ (40,487)	$ (27,151)	$ (10,818)
Non-hedged interest rate swap expense									28	(1,062)	(3,796)
Interest expense									(354,802)	(355,139)	(356,696)
Income taxes									(255,143)	(140,204)	(91,776)
Net income (loss)									175,194	312,899	241,179
Comprehensive income (loss)									184,624	306,453	250,956
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Non-utility expense and other									(1,466)	(5,252)	(1,617)
Equity In Net Income (Loss) Of Subsidiaries									323,568	385,838	309,603
Non-hedged interest rate swap expense									28	(1,062)	(3,796)
Interest income									1,039	2	63
Interest expense									(106,072)	(104,600)	(100,114)
Income taxes									(41,903)	37,973	37,040
Net income (loss)	$ (467)	$ 12,836	$ 35,275	$ 127,550	$ 104,825	$ 2,335	$ 64,553	$ 141,186	175,194	312,899	241,179
Comprehensive income (loss)									$ 184,624	$ 306,453	$ 250,956

XML

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY - Condensed Balance Sheets (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Feb. 06, 2009
Other property and investments:
Goodwill		$ 1,656,513	$ 1,656,513				$ 1,700,000
Current assets:
Cash and Cash Equivalents, at Carrying Value		26,616	28,878	$ 42,494	$ 37,527
Total current assets		813,418	902,868
Long-term assets:
Other		74,389	58,109
Total assets		13,690,789	13,266,380
Capitalization and liabilities:
Common equity		3,750,030	3,688,713	3,531,225	$ 3,543,328
Long-term debt		1,902,600	1,812,480
Total capitalization		9,007,959	9,040,374
Current liabilities:
Accounts payable		359,586	317,043
Interest		73,564	73,610
Deferred income taxes		746,868	1,570,931
Unrealized loss on derivative instruments		64,859	44,310
Total current liabilities		1,297,659	919,470
Long-term liabilities:
Unrealized loss on derivative instruments		21,235	16,261
Total capitalization and liabilities		13,690,789	13,266,380
Parent Company [Member]
Assets:
Investments in subsidiaries		3,721,553	3,571,550
Other property and investments:
Goodwill		1,656,513	1,656,513
Current assets:
Cash and Cash Equivalents, at Carrying Value		751	397	$ 639		$ 62
Receivables from affiliates	[1]	78,570	213
Total current assets		79,321	610
Long-term assets:
Deferred income taxes		208,889	309,812
Other		3,196	521
Total long-term assets		212,085	310,333
Total assets		5,669,472	5,539,006
Capitalization and liabilities:
Common equity		3,750,030	3,688,713
Long-term debt		1,892,672	1,808,828
Total capitalization		5,642,702	5,497,541
Current liabilities:
Accounts payable		1,042	15,801
Interest		25,728	25,523
Unrealized loss on derivative instruments		0	141
Total current liabilities		26,770	41,465
Long-term liabilities:
Total long-term liabilities		0	0
Total capitalization and liabilities		$ 5,669,472	$ 5,539,006

[1] Eliminated in consolidation.

XML

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY - Condensed Statements of Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Net cash provided by (used in) operating activities	$ 972,131	$ 729,290	$ 648,722
Investing activities:
Other	(195)	(1,921)	754
Net cash provided by (used in) investing activities	(1,038,057)	(712,834)	(561,557)
Financing activities:
Dividends paid	(123,307)	(148,965)	(263,059)
Proceeds from long-term debt and bonds issued	90,120	12,481	825,000
Issuance/redemption of term-loan and other long-term debt	0	0	(711,000)
Net cash provided by (used in) financing activities	63,664	(30,072)	(82,198)
Net increase (decrease) in cash and cash equivalents	(2,262)	(13,616)	4,967
Cash and cash equivalents at beginning of period	28,878	42,494	37,527
Cash and cash equivalents at end of period	26,616	28,878	42,494
Parent Company [Member]
Investing activities:
Adjustments to Additional Paid in Capital, Other	(24,222)	0	(28,900)
(Increase) decrease in loan to subsidiary	(78,155)	0	28,933
Other	(437)	(6,078)	(5,632)
Net cash provided by (used in) investing activities	(102,814)	(6,078)	(5,599)
Financing activities:
Dividends paid	(123,307)	(148,965)	(263,059)
Proceeds from long-term debt and bonds issued	0	0	400,000
Issuance/redemption of term-loan and other long-term debt	90,120	12,480	(299,000)
Issue costs and others	(2,650)	(3,398)	(3,341)
Net cash provided by (used in) financing activities	(35,837)	(139,883)	(165,400)
Net increase (decrease) in cash and cash equivalents	354	(242)	577
Cash and cash equivalents at beginning of period	397	639
Cash and cash equivalents at end of period	$ 751	$ 397	$ 639

XML

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY Notes (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Net income									$ 175,194	$ 312,899	$ 241,179
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									184,624	306,453	250,956
Net Cash Provided by (Used in) Operating Activities									972,131	729,290	648,722
Net Cash Provided by (Used in) Investing Activities									(1,038,057)	(712,834)	(561,557)
Parent Company [Member]
Net income	$ (467)	$ 12,836	$ 35,275	$ 127,550	$ 104,825	$ 2,335	$ 64,553	$ 141,186	175,194	312,899	241,179
Goodwill, Purchase Accounting Adjustments									3,900	5,200	5,400
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									184,624	306,453	250,956
Net Cash Provided by (Used in) Investing Activities									(102,814)	(6,078)	(5,599)
Subsidiaries [Member]
Net income	$ 97,208	$ 29,100	$ 50,654	$ 143,092	$ 124,199	$ 18,977	$ 80,900	$ 156,505	320,054	380,581	304,189
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									338,659	384,620	325,596
Net Cash Provided by (Used in) Operating Activities									1,086,803	818,916	738,781
Net Cash Provided by (Used in) Investing Activities									$ (961,138)	$ (681,425)	$ (555,925)

XML

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Details) - Allowance for doubtful accounts receivable - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance At Beginning of Period	$ 9,798	$ 9,756	$ 7,472
Additions Charged to Costs and Expenses	26,266	24,389	20,732
Deductions	27,163	24,347	18,448
Balance At End Of Period	$ 8,901	$ 9,798	$ 9,756