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

Puget Energy, Inc.

Yes

/ /

/X/

Puget Sound Energy, Inc.

Yes

/ /

/X/

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

Puget Energy, Inc.

Yes

/ /

/X/

Puget Sound Energy, Inc.

Yes

/ /

/X/

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

Puget Energy, Inc.

Yes

/X/

/ /

Puget Sound Energy, Inc.

Yes

/X/

/ /

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

Puget Energy, Inc.

Yes

/X/

/ /

Puget Sound Energy, Inc.

Yes

/X/

/ /

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

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

Puget Energy, Inc.

Large accelerated filer

/ /

Accelerated filer

/ /

Non-accelerated filer

/X/

Smaller reporting company

/ /

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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.

Puget Energy, Inc.

Yes

/X/

/ /

Puget Sound Energy, Inc.

Yes

/X/

/ /

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

Puget Energy, Inc.

Yes

/ /

/X/

Puget Sound Energy, Inc.

Yes

/ /

/X/

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

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

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

INDEX



		Page
Definitions		4
Forward-Looking Statements		5
Part I
1. ~~Business~~	7
1. ~~General~~Business		7
General		7
Regulation and Rates		9
Electric Utility Operating Statistics		1213
Electric Supply		1415
Natural Gas Utility Operating Statistics		1819
Natural Gas Supply for Natural Gas Customers		2021
Energy Efficiency		2223
Environment		2223
Recent and Future Environmental Law and Regulation		2324
Human Capital Resources		26
Executive Officers of the Registrants		2528
1A. Risk Factors		2529
1B. Unresolved Staff Comments		3036
2. Properties		3036
3. Legal Proceedings		3036
4. Mine Safety Disclosures		3036

Part II
5. Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities		3136
6. ~~Selected~~Selecte d Financial Data		3237
7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		3338
7A. Quantitative and Qualitative Disclosures about Market Risk		6367
8. Financial Statements and Supplementary Data		6670
Report of Management and Statement of Responsibility		6771
Report of Independent Registered Public Accounting Firm – Puget Energy		6872
Report of Independent Registered Public Accounting Firm – Puget Sound Energy		7074
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		~~132~~142
9A. Controls and Procedures		~~132~~142
9B. Other Information		~~133~~143

Part III
10. Directors, Executive Officers and Corporate Governance		~~134~~144
11. Executive Compensation		~~136~~147
12. Security Ownership of Certain Beneficial Owners and Management and Related		~~160~~167
Shareholder Matters
13. Certain Relationships and Related Transactions, and Director Independence		~~161~~168
14. Principal Accountant Fees and Services		~~162~~169

Part IV
15. Exhibits and Financial Statement Schedules		~~163~~170
16. Form 10-K Summary		~~163~~170
Exhibit Index		~~164~~171
Signatures		~~170~~177

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		U.S. 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~~kW		~~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.

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 the 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~~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~~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~~significant or sustained civil disturbances or disruptions, 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;
•		The impact of widespread health developments, including the recent global coronavirus (COVID–19) pandemic, and responses to such developments (such as voluntary and mandatory quarantines, including government stay at home orders, as well as shut downs and other restrictions on travel, commercial, social and other activities) could materially and adversely affect, among other things, electric and natural gas demand, customers’ ability to pay, supply chains, availability of skilled work-force, contract counterparties, liquidity and financial markets;
•		Commodity price risks associated with procuring natural gas and power in wholesale markets from creditworthy counterparties;
•		Wholesale market disruption, which may result in a deterioration of market liquidity, increase the risk of counterparty default, affect the regulatory and legislative process in unpredictable ways, negatively affect wholesale energy prices and/or impede PSE's ability to manage its energy portfolio risks and procure energy supply, affect the availability and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers;
•		Financial difficulties of other energy companies and related events, which may affect the regulatory and legislative process in unpredictable ways, adversely affect the availability of and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers;
•		The effect of wholesale market structures (including, but not limited to, regional market designs or transmission organizations) or other related federal initiatives;
•		PSE electric or natural gas distribution system failure, blackouts or large curtailments of transmission systems (whether PSE's or others'), or failure of the interstate natural gas pipeline delivering to PSE's system, all of which can affect PSE's ability to deliver power or natural gas to its customers and generating facilities;
•		Electric plant generation and transmission system outages, which can have an adverse impact on PSE's expenses with respect to repair costs, added costs to replace energy or higher costs associated with dispatching a more expensive generation resource;


•			The ability to restart generation following a regional transmission disruption;
•			The ability of a natural gas or electric plant to operate as intended;
•			Changes in climate or weather conditions in the Pacific Northwest, which could have effects on customer usage and PSE's revenue and expenses;


•
•	Regional or national weather, which could impact PSE's ability to procure adequate supplies of natural gas, fuel or purchased power to serve its customers and the cost of procuring such supplies;
•		Variable hydrological conditions, which can impact streamflow and PSE's ability to generate electricity from hydroelectric facilities;
•		Variable wind conditions, which can impact PSE's ability to generate electricity from the wind 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,~~strikes; work ~~stoppages,~~stoppages; absences due to pandemics, accidents, natural disasters or other significant, unforeseeable events; 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.

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,~~Puget Sound Energy, Inc. (PSE), a utility company. Puget Energy also hasa wholly-owned, non-regulated subsidiary, ~~named~~ Puget LNG, LLC (Puget LNG)~~. Puget LNG~~, which was formed ~~on November 29,~~in 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). 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, ~~(CPPIB),~~ the British Columbia Investment Management Corporation ~~and~~(BCI), the Alberta Investment Management ~~Corporation. All~~Corporation (AIMCo), Ontario Municipal Employee Retirement System (OMERS) and PGGM Vermogensbeheer B.V. The sale of previous owners', Macquarie Infrastructure Partners and Macquarie Capital Group Limited, shares to OMERS, PGGM Vermogensbeheer B.V., AIMCo and BCI was approved by various federal and state agencies, including that of the Washington Utilities and Transportation Commission (Washington Commission), and closed on April 17th, 2019. Puget ~~Energy’s common stock is indirectly owned by Puget Holdings.~~Energy and PSE are collectively referred to herein as “the Company.”

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.~~PSE, and be the clean energy provider of choice for its customers.

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~~2020, and ~~2016:~~2019:


	December 31,			December 31,
	2017	2016	Percent	2017	2016	Percent		December 31,			December 31,
Customer Count by Class	Electric		Change	Natural Gas		Change	Customer Count by Class	2020	2019	Percent	2020	2019	Percent
(in thousands)							(in thousands)	Electric		Change	Natural Gas		Change
Residential	1,003,984	992,959	1.1%	767,045	756,330	1.4%	Residential	1,048	1,033	1.5%	797	788	1.2%
Commercial	127,836	125,737	1.7	55,996	55,671	0.6	Commercial	131	130	0.8	57	57	0.1
Industrial	3,377	3,417	(1.2)	2,332	2,365	(1.4)	Industrial	3	3	(1.1)	2	2	(0.6)
Other	6,856	6,591	4.0	226	227	(0.4)	Other	8	8	3.8	—	—	(3.1)
Total¹	1,142,053	1,128,704	1.2%	825,599	814,593	1.4%	Total1	1,190	1,174	1.4%	856	847	1.1%

_______________


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

1At December 31, 2020, and 2019, approximately 414,210 and 409,820 customers purchased both electricity and natural gas from PSE, respectively.


	December 31,					December 31,						December 31,					December 31,
Retail Revenue by Class	2017		2016		Percent	2017		2016		Percent	Retail Revenue by Class	2020		2019		Percent	2020		2019		Percent
(Dollars in Thousands)	Electric				Change	Natural Gas				Change	(Dollars in Thousands)	Electric				Change	Natural Gas				Change
Residential	$	1,232,075	$	1,138,871	8.2%	$	686,438	$	578,955	18.6%	Residential	$	1,186,013	$	1,139,356	4.1%	$	662,502	$	613,617	8.0%
Commercial	892,360		872,057		2.3	274,907		235,695		16.6	Commercial	791,898		854,910		(7.4)	253,526		236,059		7.4
Industrial	112,817		113,469		(0.6)	21,071		19,643		7.3	Industrial	101,567		105,020		(3.3)	19,064		16,322		16.8
Other	32,313		30,982		4.3	21,718		20,322		6.9	Other	37,864		37,920		(0.1)	17,296		20,283		(14.7)
Total	$	2,269,565	$	2,155,379	5.3%	$	1,004,134	$	854,615	17.5%	Total	$	2,117,342	$	2,137,206	(0.9)%	$	952,388	$	886,281	7.5%

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 3,4, "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~~2020, and gross utility plant by category and percentages as of December 31, ~~2017:~~2020:


Utility Plant Additions/Retirements 5-Year Total	2016 - 2020
(Dollars in Thousands)	Electric		Natural Gas		Common
Additions	$	1,904,303	$	1,196,439	$	778,884
Retirements	(910,519)		(119,056)		(205,323)
Net Utility Plant	$	993,784	$	1,077,383	$	573,561

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, 2020
(Dollars in Thousands)	Electric			Natural Gas			Common
Distribution	$	4,375,442	41.1%	$	4,293,359	94.9%	$	—	—%
Generation	4,046,923		38.0	2,883		0.1	—		—
Transmission	1,601,731		15.0	—		—	—		—
General Plant & Other	629,712		5.9	227,429		5.0	1,071,258		100.0
Total (excluding CWIP)	$	10,653,808	100.0%	$	4,523,671	100.0%	$	1,071,258	100.0%

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~~355 110th Ave NE, 4^th ~~Street, Suite 1200,~~ Bellevue, Washington 98004 and the telephone number is (425) 454-6363.

Available Information

be accessed free of charge at the Company’s website, www.pugetenergy.com. The Securities and Exchange Commission (SEC) maintains an internet site that contains reports, proxy and information ~~required by Item 101(e) of Regulation S-K is incorporated herein by reference to~~statements, and other information regarding issuers that file electronically with the ~~material under “Additional Information” in Part III Item 10, "Directors, Executive Officers~~SEC and ~~Corporate Governance".~~information may also be obtained via the SEC Internet website at www.sec.gov.

Regulation and Rates

PSE is subject to the regulatory authority ~~of:~~of the following: (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~~forward-looking twelve-month period. Both allow recovery of expenditures ~~without~~outside the ~~lengthy~~ process of a full ~~GRC.~~general rate case (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~~Purchased gas adjustment rider		N/A			No

Power Cost Only Rate Case

A power cost only rate case (PCORC) 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.

On December 9, 2020, PSE filed its 2020 PCORC. The filing proposed an increase of $78.5 million (or an average of approximately 3.7%) in the Company's overall power supply costs with an anticipated effective date in June 2021. On February 2, 2021, PSE supplemented the PCORC to update its power costs, leading to a requested increase from $78.5 million to $88.0 million (or an average of approximately 4.1%).

General Rate Case Filing

~~On January 13, 2017,~~ PSE filed ~~its~~a GRC with the Washington Commission on June 20, 2019, requesting an overall increase in electric and natural gas rates of 6.9% and 7.9%, respectively. PSE requested a return on equity of 9.8% with an overall rate of return of 7.62%. In addition to the ~~settlement agreement was accepted by~~traditional areas of focus (revenue requirements, cost allocation, rate design and cost of capital), the Company completed an attrition study and included a portion of the attrition revenue requirement in the overall request in order to address the expected regulatory lag in the rate year. Additionally, as the non-plant related excess deferred taxes that resulted from the Tax Cuts and Jobs Act (TCJA) remained outstanding from PSE’s Expedited Rate Filing (ERF) as discussed below, PSE requested in its GRC to pass back the amounts over four years. On September 17, 2019, PSE filed supplemental testimony, which provided certain updates to the original filing, but did not impact the requested overall electric and natural gas rate increases, return on equity or overall rate of return as originally filed. On January 15, 2020, PSE filed rebuttal testimony which

included a reduction to the requested return on equity to 9.5%, which decreased the rate of return to 7.48%. The requested rate increase for both electric and natural gas remained at 6.9% and 7.9%, respectively. For both electric and natural gas PSE did not originally request its full attrition adjustment; therefore, the decrease in return on equity led to a reduction in the electric rate increase of only $1.5 million and did not have an impact on the natural gas rate increase.

On July 8, 2020, the Washington Commission issued its order on ~~December 5, 2017~~PSE’s GRC. The ruling provided for a weighted cost of capital of 7.39% or 6.80% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.4%. The order also resulted in a combined net increase to electric of $29.5 million, or 1.6%, and to natural gas of $36.5 million, or 4.0%. However, the Washington Commission extended the amortization of certain regulatory assets, PSE’s electric decoupling deferral, and PSE’s purchased gas adjustment (PGA) deferral to mitigate the impact of the rate increase in response to the economic instability created by the COVID-19 pandemic, which reduced the electric revenue increase to approximately $0.9 million, or 0.05% and the ~~rates~~natural gas increase to $1.3 million, or 0.15%. The Washington Commission also determined that the Company’s proposed attrition adjustment of $23.9 million for electric and $16.2 million for natural gas was not in the public interest at this time. The order also effectively ends the deferral of PSE’s advanced metering infrastructure (AMI) investment while allowing the deferral on the return on AMI investments through December 31, 2019. Additional AMI investments will be evaluated in future proceedings for deferrals of return until the AMI project is complete. On July 17, 2020, PSE filed a motion for clarification with the Washington Commission seeking clarification on several items. On July 31, 2020, the Washington Commission issued an order granting PSE’s motion for clarification. The ruling adjusted certain items from the final order issued on July 8, 2020, which led to a combined net increase to electric of $59.6 million, or 2.9%, an increase of $30.1 million above the $29.5 million granted in the final order. The order also led to a combined net increase to natural gas of $42.9 million, or 5.6%, an increase of $6.4 million above the $36.5 million granted in the final order. The Washington Commission maintained adjustments which mitigated the impacts of the rate increases in response to the economic instability created by the COVID-19 pandemic, which reduced the electric revenue increase to approximately $27.7 million, or 1.3% and the natural gas increase to $0.2 million, or 0.02%.

On August 6, 2020, PSE filed a petition for judicial review with the Superior Court of the State of Washington for King County (Superior Court) challenging the portion of the final order that requires PSE to pass back to customers the reversal of plant-related excess deferred income taxes in a manner that may deviate from the IRS normalization and consistency rules. On August 7, 2020, PSE filed a motion to stay with the Superior Court related to the portions of the final order under judicial review. On September 14, 2020, the Superior Court denied PSE's motion to stay. PSE reviewed the original Washington Commission order including the ramifications of certain tax issues and requested a Private Letter Ruling (PLR) with the IRS regarding this matter. PSE will continue to utilize the average rate assumption method (ARAM) in the turnaround of certain accelerated tax depreciation benefits on PSE assets. On September 23, 2020, PSE filed a compliance filing with the Washington Commission. The natural gas tariffs became effective ~~December 19, 2017.~~ October 1, 2020 and the electric tariffs on October 15, 2020. On October 7, 2020, PSE, the Washington Commission and interveners agreed to dismiss the petition for judicial review. The agreement is based on a commitment from the Washington Commission that if the IRS ruling finds that the Washington Commission’s methodology for reversing plant-related excess deferred income taxes is impermissible, the Washington Commission will open a proceeding to review and enact the changes required by the IRS ruling. There is approximately $25.6 million in annual revenue requirement related to the 2019 GRC which PSE has requested it be allowed to track in order to allow the Washington Commission to decide if it is appropriate for PSE to recover, pending the outcome of the IRS ruling.

For further details regarding the ~~2017~~2019 GRC filing and credit ratings, see Note 4, "Regulations and Rates" to the consolidated financial statements included in Item 8 of this report and "Financing Program" in Item 7 of this report, respectively.

Expedited Rate Filing

On November 7, 2018, PSE filed an ERF with the Washington Commission. On January 22, 2019, all parties in the proceeding reached an agreement on settlement terms. The settlement agreement was filed on January 30, 2019. On February 21, 2019, the Washington Commission approved the settlement with one condition, that PSE passed back the deferred balance associated with the tax over-collection of $34.6 million for the period January 1, 2018, through April 30, 2018, over a one-year period which ended May 1, 2020.

For further details regarding the 2018 ERF filing, see Note ~~3, "Regulation~~4, "Regulations and Rates" to the consolidated financial statements included in Item 8 of this report.

Washington Commission Tax Deferral Filing

The TCJA was signed into law in December 2017. As a result of this change, PSE re-measured its deferred tax balances under the new corporate tax rate. PSE filed an accounting petition on December 29, 2017, requesting deferred accounting treatment for the impacts of tax reform. The deferred 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. Additionally, on March 30,

2018, PSE filed for a rate change for electric and natural gas customers associated with TCJA to reflect the decrease in the federal corporate income tax rate from 35% to 21%. PSE began passing back protected deferred tax balances created by tax reform as determined in the ERF settlement agreement through PSE’s Schedule 141X tariff. The pass back of deferred tax balances was continued with the GRC final order which also created PSE’s Schedule 141Z tariff, in addition to Schedule 141X, to pass-back additional deferred tax balances. Further details of the outcomes associated with PSE’s tax deferral filing are discussed in the ERF and GRC disclosures. .

For further details regarding the Washington Commission Tax Deferral Filing, see Note 4, "Regulations 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 and beginning December 19, 2017, fixed production costs from most 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 delivery revenues are recovered on a per customer basis and electric fixed production energy costs are recovered on the basis of a fixed monthly amount regardless of actual consumption levels. The energy supply costs, which are part of the power cost adjustment (PCA) and ~~purchased gas adjustment (PGA)~~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.~~consumption except for fixed production costs, which are held at the level of cost from the most recent rate proceeding and are not impacted by customer growth. 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 3,4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.

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” islevels are set, in part, based on normalized assumptions about weather and ~~hydrological~~hydroelectric 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~~Effective January 1, 2017, ~~and will apply~~ the following graduated ~~scale:~~

scale is used in the PCA mechanism:


	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

Power Cost Adjustment Clause Filing

The Power Cost Adjustment Clause filing reflects the transition fee as required by Section 12 of the Microsoft Special Contract.

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~~compared to the forecasted load set in rates.

~~Federal Incentive Tracker Tariff~~

~~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~~is adjusted each year in May based on that year's assessed property taxes and true-up from the prior year.

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. Additionally, this tracker is impacted by the TCJA previously discussed. Accordingly, PSE filed for a one-time rate change to be effective May 1, 2018, to recognize the decrease in the federal corporate income tax rate from 35% to 21%.

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 biennially on October 1.

Natural Gas Rate Filings

Natural Gas Cost Recovery Mechanism

The purpose of the ~~CRM~~cost recovery mechanism (CRM) is to recover capital costs related to projects included in PSE's ~~pipe~~pipeline 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.

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 typically change annually on November 1.1, although out-of-cycle rate changes are allowed at other times of the year if needed.

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~~true-up 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~~compared to forecast conservation expenditures from the prior year, as well as actual ~~load being different than~~compared to 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.

ELECTRIC UTILITY OPERATING STATISTICS


	Year Ended December 31,										Year Ended December 31,
	2017			2016			2015				2020		2019		2018
Generation and purchased power, MWh										Generation and purchased power, MWh
Company-controlled resources	10,825,778			11,577,608			12,747,014			Company-controlled resources	11,700,918		13,420,043		11,168,286
Contracted resources	8,337,348			7,023,786			5,911,012			Contracted resources	8,237,394		6,752,261		7,654,872
Non-firm energy purchased	6,147,778			6,005,797			5,315,266			Non-firm energy purchased	4,916,761		5,707,102		6,490,602
Total generation and purchased power	25,310,904			24,607,191			23,973,292			Total generation and purchased power	24,855,073		25,879,406		25,313,760
Less: losses and Company use	(1,568,599		)	(1,547,619		)	(1,514,272		)	Less: losses and Company use	(1,611,563)		(1,298,854)		(1,513,451)
Total energy sales, MWh	23,742,305			23,059,572			22,459,020			Total energy sales, MWh	23,243,510		24,580,552		23,800,309
Electric energy sales, MWh										Electric energy sales, MWh
Residential	10,931,999			10,245,326			10,164,703			Residential	10,976,068		10,756,628		10,497,389
Commercial	9,089,842			8,895,950			8,999,068			Commercial	7,942,292		8,837,457		8,932,681
Industrial	1,214,818			1,223,214			1,257,958			Industrial	1,095,916		1,161,149		1,189,828
Other customers	87,230			90,753			94,847			Other customers	81,261		85,302		84,382
Total energy sales to customers	21,323,889			20,455,243			20,516,576			Total energy sales to customers	20,095,537		20,840,536		20,704,280
Sales to other utilities and marketers	2,418,416			2,604,329			1,942,444			Sales to other utilities and marketers	3,147,973		3,740,016		3,096,029
Total energy sales, MWh	23,742,305			23,059,572			22,459,020			Total energy sales, MWh	23,243,510		24,580,552		23,800,309
Transportation, including unbilled	2,001,244			2,085,574			2,012,827			Transportation, including unbilled	2,220,372		2,322,021		2,028,727
Electric energy sales and transportation, MWh	25,743,549			25,145,146			24,471,847			Electric energy sales and transportation, MWh	25,463,882		26,902,573		25,829,036
Electric operating revenue by classes										Electric operating revenue by classes
(Dollars in Thousands)										(Dollars in Thousands)
Residential	$	1,232,075		$	1,138,871		$	1,061,117		Residential	$	1,186,013	$	1,139,356	$	1,147,260
Commercial	892,360			872,057			867,786			Commercial	791,898		854,910		885,457
Industrial	112,817			113,469			114,223			Industrial	101,567		105,020		110,607
Other customers	19,729			20,045			20,216			Other customers	18,182		18,408		18,718
Total operating revenue from customers	2,256,981			2,144,442			2,063,342			Total operating revenue from customers	2,097,660		2,117,694		2,162,042
Transportation, including unbilled	12,584			10,937			10,143			Transportation, including unbilled	19,682		19,512		13,878
Sales to other utilities and marketers	53,789			50,124			46,666			Sales to other utilities and marketers	68,198		109,105		89,324
Decoupling revenue	9,975			29,968			13,630			Decoupling revenue	49,632		15,673		13,530
Other decoupling revenue¹	(27,706		)	(21,168		)	(16,634		)	Other decoupling revenue1	(27,053)		(6,866)		(5,475)
Miscellaneous operating revenue	115,040			24,189			11,321			Miscellaneous operating revenue	111,297		241,923		182,620
Total electric operating revenue	$	2,420,663		$	2,238,492		$	2,128,468		Total electric operating revenue	$	2,319,416	$	2,497,041	$	2,455,919
Number of customers served (average):										Number of customers served (average):
Residential	998,078			984,739			970,830			Residential	1,039,596		1,025,024		1,010,574
Commercial	126,829			125,067			123,072			Commercial	130,924		129,944		128,845
Industrial	3,399			3,425			3,434			Industrial	3,289		3,328		3,362
Other	6,722			6,472			6,283			Other	7,668		7,323		6,992
Transportation	16			16			16			Transportation	100		80		16
Total customers	1,135,044			1,119,719			1,103,635			Total customers	1,181,577		1,165,699		1,149,789

_______________


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

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

ELECTRIC UTILITY OPERATING STATISTICS (Continued)


	Year Ended December 31,										Year Ended December 31,
	2017			2016			2015				2020			2019			2018
Average kWh used per customer:										Average kWh used per customer:
Residential	10,953			10,404			10,470			Residential	10,558			10,494			10,388
Commercial	71,670			71,129			73,120			Commercial	60,663			68,010			69,329
Industrial	357,404			357,143			366,324			Industrial	333,206			348,903			353,905
Other	12,977			14,022			15,096			Other	10,597			11,649			12,068
Average revenue per customer:										Average revenue per customer:
Residential	$	1,234		$	1,157		$	1,093		Residential	$	1,141		$	1,112		$	1,135
Commercial	7,036			6,973			7,051			Commercial	6,049			6,579			6,872
Industrial	33,191			33,130			33,262			Industrial	30,881			31,556			32,899
Other	2,935			3,097			3,218			Other	2,371			2,514			2,677
Average retail revenue per kWh sold:										Average retail revenue per kWh sold:
Residential	$	0.1127		$	0.1112		$	0.1044		Residential	$	0.1081		$	0.1059		$	0.1093
Commercial	0.0982			0.0980			0.0964			Commercial	0.0997			0.0967			0.0991
Industrial	0.0929			0.0928			0.0908			Industrial	0.0927			0.0904			0.0930
Other	0.2262			0.2209			0.2131			Other	0.2237			0.2158			0.2218
Average retail revenue per kWh sold	$	0.1058		$	0.1048		$	0.1006		Average retail revenue per kWh sold	0.1044			0.1016			0.1044
Heating degree days	4,584			3,823			3,800			Heating degree days	$	4,122		$	4,208		$	4,065
Percent of normal - NOAA²30-year average	97.2		%	81.0		%	80.5		%	Percent of normal - NOAA2 30-year average	87.8		%	89.6		%	86.2		%
Load factor³	51.6		%	56.2		%	56.2		%	Load factor3	62.1		%	61.6		%	64.2		%

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~~the federal incentive tracker tariff revenue requirement 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 from prior year	Total credit to be passed back to eligible customers (Dollars in Millions)
January 1, 2021	0.3%	$(29.5)
January 1, 2020	(0.04)	(37.8)
January 1, 2019	0.1	(38.7)
May 1, 2018	0.4	(40.1)
January 1, 2018	0.2	(48.2)

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)

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 12, 2019	0.01%	$(81.8)
October 1, 2017	(0.6)	(80.8)

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, 2020	1.2%	$10.6
November 1, 2019	0.8	7.0
November 1, 2018	0.5	5.0

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

Purchased Gas Adjustment

On April 25, 2019, the Washington Commission approved PSE’s request for an out-of-cycle change to PGA rates with the rate change taking effect May 1, 2019. The out-of-cycle PGA filing was needed to begin amortizing a large PGA commodity deferral balance that had grown due to higher than projected commodity costs during the 2018/19 winter. These higher than projected commodity costs were primarily due to an October 9, 2018, rupture and subsequent explosion on Westcoast Pipeline which is one of the major pipelines feeding PSE’s distribution system. The pipeline was repaired in October 2018, however supply capacity on the pipeline was limited over the 2018/19 winter leading to higher prices. February weather was also much colder than normal which also increased the demand for natural gas. The out-of-cycle PGA rates were effective from May 1, 2019 through April 30, 2020 and on May 1, 2020 the out-of-cycle PGA rates were set to zero. At the end of the recovery period, an unamortized balance of $4.9 million remained which PSE requested to be amortized in its annual PGA filing for rates effective November 1, 2020.

On October 24, 2019, the Washington Commission approved PSE’s request for November 2019 PGA rates, with the rate change taking effect on November 1, 2019. As part of that filing, PSE requested PGA rates increase annual revenue by $17.8 million, while the new tracker rates increased by annual revenue of $100.6 million; this was in addition to continuing the

collection on the remaining balance of $54.0 million from the out-of-cycle PGA. The tracker rates include deferral balances for the three separate amounts: (i) $114.4 million of under collected commodity balances deferred in February and March; (ii) a $10.8 million balance of over-collected commodity costs for the 2018 PGA, and (iii) a $4.1 million remaining balance from the $54.7 million credit to customers, caused by the 2017 over-collection, established in the 2018 tracker. The high commodity deferral balances for winter months through March 2019 were the result of three noteworthy events last winter experienced by PSE: the Enbridge pipeline rupture, unusually low temperatures in February and March, and a compressor failure in February at the Jackson Prairie storage facility. Additionally, to reduce customer impact, as part of the approved PGA filing, PSE will be collecting $114.4 million commodity deferrals and related interest over a two year period, instead of the historic one year period, from November 2019 through October 2021.

On July 8, 2020, the Washington Commission issued the final order in Dockets UE-190529 and UG-190530, which instructed PSE to extend the collection of amortization balances for the portion of PGA amortization balances originally filed through annual November 1, 2019 PGA filing under Supplemental Schedule 106B. The extension requires PSE to move amortization balances for PGA Schedule 106B as of August 31, 2020 to be collected from customers for a three-year period, instead of originally approved two-year period.

On October 29, 2020, the Washington Commission approved PSE’s request for November 2020 PGA rates in Docket UG-200832, effective November 1, 2020. As part of that filing, PSE requested PGA rates increase annual revenue by $32.6 million, while the new tracker rates increased annual revenue by $37.4 million; this was in addition to continuing the collection on the remaining balance of $69.4 million under Supplemental Schedule 106B.

The following table presents the PGA mechanism balances and activity at December 31, 2020 and December 31, 2019:


Puget Energy and Puget Sound Energy
(Dollars in Thousands)	At December 31,		At December 31,
PGA receivable balance and activity	2020		2019
PGA receivable beginning balance	$	132,766	$	9,921
Actual natural gas costs	314,792		406,162
Allowed PGA recovery	(363,886)		(289,876)
Interest	3,983		6,559
PGA receivable ending balance	$	87,655	$	132,766

The following table sets forth the PGA rate 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	Increase (Decrease) in Revenue (Dollars in Millions)
November 1, 2020	7.7%	$70.0
October 1, 2020	(3.9)	(35.5)
November 1, 20192	13.4	118.3
May 1, 20191	6.3	54.0
November 1, 2018	(10.9)	(98.4)

_______________

1.The rate for out of the cycle May 2019 PGA (Supplemental A) filing was set to zero effective May 1, 2020, The actual residual amount resulting was included in annual PGA filling effective November 1, 2020.

2.The 2019 GRC final order lengthened the recovery period from two to three years.

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, 2020	(0.3)%	$(2.8)
May 1, 2019	(0.2)	(1.6)
May 1, 2018	(0.2)	(2.2)

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, 2020	0.4%	$3.5
May 1, 2019	0.1	1.1
May 1, 2017	(0.1)	(1.0)

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~~Microsoft Special Contract

~~On October 7, 2016,~~Following discussions between PSE, ~~filed~~the Microsoft Corporation, and others, and after completing a ~~tariff to provide open access service to a narrow set of qualifying customers. Subsequent to that tariff filing, parties to~~negotiated regulatory process, the ~~case reached~~Washington Commission issued an ~~all-party settlement that converted the tariff to~~order in July 2017 approving a special contract ~~only allowing~~between PSE and Microsoft relating to retail access for ~~the~~Microsoft loads ~~of the Microsoft Corporation~~ currently being served under PSE’s electric Schedule 40. The special contract includes the following conditions: (i) Microsoft must exceed Washington State’s current renewable portfolio standards, (ii) the remainder of power sold to itMicrosoft must be carbon free, (iii) there will be no reduction in ~~its~~Microsoft's funding of PSE’s conservation programs, (iv) ~~an exit~~Microsoft paid a transition fee ~~be paid~~ that ~~will be~~was a straight pass-through to customers and (v) Microsoft will 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~~began taking service under the special contract ~~until it has~~on April 1, 2019, after meeting the ~~required metering installed, has contracts for~~eligibility requirements under the ~~supply and transmission of its power supply and pays the exit fee. PSE currently anticipates these conditions will be met in early 2019.~~special contract.

Voluntary Long-Term Renewable Energy

OnEffective September ~~28,~~ 2016, the Washington Commission approved PSE's tariff revision to create an additional voluntary renewable energy ~~product, effective September 30, 2016.~~product. This provides customers with ~~energy choices~~electric generation resource options 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)~~10,000 MWh) and government customers. ~~Approximately 136.8 MW of~~The initial resource option offered under this rate schedule is a new wind generation ~~facilities~~facility with the capacity of approximately 136.8 MW which went into operation on November 7, 2020. The project is fully subscribed and the twenty-one customers under Phase 1 of the program began taking service in November 2020.

In July 2018, the Washington Commission approved a second phase of the Green Direct product. The phase two project is the 150 MW solar facility to be located in Klickitat County, WA. It is expected to achieve commercial operation in 2021 and serve twenty customers. The phase 2 offering will be ~~constructed in~~a blend of the ~~region by a developer under contract to PSE to meet~~phase 1 wind and the ~~demand for this voluntary renewable energy product project. PSE anticipates that~~solar facility. Phase 1 customers will ~~start receiving~~receive wind through 2020 and then are expected to receive the blended energy ~~through~~later in 2021.

Crisis Affected Customer Assistance Program

On April 6, 2020, PSE filed with the Washington Commission revisions to its currently effective Tariff WN U-60. The purpose of this filing is to incorporate into PSE’s low-income tariff a new temporary bill assistance program, Crisis Affected Customer Assistance Program (CACAP), to mitigate the economic impact of the COVID-19 pandemic on PSE’s customers. CACAP would allow PSE customers facing financial hardship due to COVID-19 to receive up to $1,000 in ~~2019.~~bill assistance. The program puts to immediate use $11.0 million in unspent low income funds from prior years, and supplements other forms of financial assistance. The program does not require an increase to rates and is fully compatible with other low income programs. Based on the COVID-19 pandemic and resulting state of emergency, the Washington Commission allowed the tariff revisions to become effective on April 13, 2020. PSE made an additional filing on July 21, 2020 to increase the amount of electric funds available for distribution by $4.5 million under the CACAP program. The program ended on September 30, 2020.

For additional information, see ~~Business,~~Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 18 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~~refinance existing or issue new long-term debt, obtain access to new or renew existing credit facilities and could increase the cost of ~~such~~issuing long-term debt and maintaining credit 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 acquisitions, 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"~~"Financing Program" included in Item 87 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 also faces increasing competition for sales to its retail ~~customers. Alternative~~customers through alternative methods of electric energy generation, including solar and other self-generation ~~methods, compete with PSE for sales to existing electric retail customers.~~methods. In addition, PSE’s natural gas customers may elect to use heating oil, propane or other fuels instead of using and purchasing natural gas from PSE.

Results of Operations

Puget Sound Energy

The following discussion should be read in conjunction with the audited consolidated financial statements and the related notes included elsewhere in this document. The following discussion provides the significant items that impacted PSE’s results of operations for the years ended December 31, ~~2017, 2016~~2020, and ~~2015.~~December 31, 2019.

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~~��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 in order 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.

The following chart displays the changes in PSE’s electric margin ~~from 2016~~for the years ended December 31, 2019, to ~~2017:~~December 31, 2020:

_______________

~~_______________~~

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

~~2016~~2019 compared to ~~2017~~2020

Electric Operating Revenue

Electric operating revenues ~~increased $182.2~~ decreased $177.6 million primarily due to ~~higher retail sales of $112.5 million, increased~~decreased transportation and other revenue of ~~$92.5~~$130.5 million, ~~partially offset by decreased decoupling revenue~~sales to other utilities and marketers of ~~$20.0~~$40.9 million, ~~and~~ other decoupling revenue of ~~$6.5 million. These items are discussed in detail below:~~

~~Electric~~$20.2 million and by lower retail sales ~~increased $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%.

~~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 wasmillion; 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 revenue~~ increased $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.

~~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~~$34.0 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 decreased $20.0 million due to a ~~0.3% reduction in~~decrease of $70.2 million from reduced retail electricity ~~usage.~~usage of 3.6%; partially offset by an increase in rates of $50.2 million compared to the prior year. The reduction in usage was due to a decrease of ~~residential,~~ commercial and industrial ~~average use per~~ customer usage of ~~0.6%, 2.7%~~10.1% and ~~2.5%~~5.6%, respectively, asprimarily driven by business shut downs resulting from COVID-19 and a ~~result~~decrease in heating degree days of ~~energy efficiency. The reduction in use per customer were~~2.0% compared to 2019; partially offset by an increase in ~~retail customers~~residential sales of ~~1.5%~~2.0%. See Management's Discussion and ~~an increase~~Analysis, "Regulation and Rates" included in ~~heating degree days~~Item 7 of ~~0.6% compared~~this report for rate changes.

•Sales to ~~2015.~~

~~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~~other utilities 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~~ marketersdecreased $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~~$40.9 million primarily due to a ~~reduction~~combination of lower sales volumes and lower market prices. Volumes were 15.8% below 2019 volumes due to lower market heat rates in 2020, higher temperatures and lower demand from impacts of COVID-19. Prices were 25.7% below 2019 prices due to higher than

normal power prices in the first quarter of 2019 when wholesale prices reached an 18-year high driven by record-breaking natural gas prices.

•Decoupling revenue increased $34.0 million, the combination of a $20.2 million increase in delivery deferral revenues and a $13.7 million increase in PCA fixed cost deferral revenues. The increase in delivery decoupling revenues was driven by decreased actual usage, as noted above in the retail revenue section, and an increase of 5.6% in allowed delivery revenues. The year-over-year decrease of 3.1% in allowed fixed production cost (FPC) revenues was outpaced by the decrease in actual usage, resulting in an increase in FPC decoupling revenue recognized during 2020 compared to 2019.

•Other decoupling revenue decreased $20.2 million, primarily due to the following: i) an $8.8 million increase in the 24-month revenue reserve resulting from $0.8 million of decoupling revenue that was deferred in 2018 and recognized as revenue in the first quarter of 2019, as well as the deferral of $8.0 million of decoupling revenue which will not be collected within 24 months from the end of 2020; ii) a $7.9 million decrease year-over-year related to an increase in current year amortization of ~~PTC deferral credits~~previous years' decoupling deferrals resulting from higher amortization rates, partially offset by decreased usage; and iii) $3.5 million decrease related to earnings in excess of ~~$10.1~~allowed rate of return (ROR). In 2019, earnings in excess of allowed ROR of $3.5 million ~~since PTC generation at Hopkins Ridge ended~~was returned to customers. There were no such returns to customers in ~~2015~~2020.

•Transportation and ~~increase~~other revenue decreased $130.5 million primarily due to a decrease in net wholesale ~~natural~~non-core gas sales of ~~$6.8 million.~~

$95.6 million and a decrease in production tax credit (PTC)s deferral revenue of $28.9 million for the re-purpose of the PTCs. The decrease in net wholesale non-core gas sales was due to an approximately 55% decrease in the average price of the non-core gas sold year ended December 31, 2020 compared to the same period in the prior year and a 7% decrease in sales volume. This was offset by a $36.3 million decrease in the total cost of the non-core gas sold, primarily due to an approximately 20% decrease in the average price of non-core gas purchases and to the aforementioned decrease in non-core gas sales volume. Additionally, there was a $3.7 million decrease in natural gas hedging costs. Natural gas prices decreased compared to 2019 due to a combination of high natural gas production, mild weather and surplus storage in the first part of the year, plus a decrease in demand due to the effects of COVID-19. By comparison, natural gas prices were high in early 2019 due to the continuing effects of the late 2018 Enbridge pipeline rupture that decreased pipeline capacity in the region, compressor issues at a gas storage facility that limited gas deliverability, and higher than expected load due to cold weather.

Electric Power Costs

Electric power costs ~~increased $40.1~~ decreased $143.7 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~~$83.8 million of electric generation fuel ~~expense.~~costs and $58.8 million of purchased electricity costs. These items are discussed in detail below:

•Purchased electricity expense ~~increased $32.1~~decreased $58.8 million primarily due to a ~~16.1%~~13.7% decrease in wholesale prices due to natural gas prices that trended down in 2020 compared to 2019 natural gas prices due to the effect of the Enbridge pipeline rupture in late 2018; partially offset by a 5.6% increase in wholesale electricity purchases ~~partially offset by~~due to the retirement of Colstrip Units 1 and 2 and 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.

combustion turbine (CT) generation, discussed below.

•Electric generation fuel expense decreased ~~$34.6~~$83.8 million primarily due to a ~~$43.0~~$46.7 million ~~reduction~~decrease in ~~combustion turbine costs as~~Colstrip related to the retirement of Units 1 and 2 and a ~~result of a 28.8% reduction~~$30.0 million decrease 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~~CT generation costs primarily driven by the cost of natural gas and increase in wholesale purchases. As stated above in transportation and other revenue, natural gas prices trended down in 2020 compared to 2019 natural gas prices which were higher due to ~~an increase~~the effect of the Enbridge pipeline rupture in ~~the weighted-average cost~~late 2018.

For additional information on prior years, please see discussion in Item 7, "Non-GAAP Financial Measures - Electric Margin" of ~~coal.~~

Form 10-K for period ended December 31, 2019.

~~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.

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 to customers 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~~over- and ~~under~~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~~for the years ended December 31, 2019, to ~~2017:~~December 31, 2020:

_______________

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

~~2016~~2019 compared to ~~2017~~2020

Natural Gas Operating Revenue

Natural gas operating revenueincreased ~~$107.3~~$105.5 million primarily due to higher retail sales of ~~$148.1~~$69.1 million, ~~and~~ increased other decoupling revenue of ~~$5.9 million;~~$23.3 million, increased decoupling revenue of $16.6 million and partially offset by ~~a decrease in decoupling~~decreased transportation and other revenue of ~~$48.6~~$3.5 million. These items are discussed in the following details:

•Natural gas retail sales increased ~~$148.1~~$69.1 million due to an increase in rates of ~~$155.1~~$103.5 million ~~in natural gas sales, which is a result of~~primarily from an increase in ~~natural gas load of 18.0% from 2016,~~rates for PGA partially offset by a decrease in ~~revenue per therm~~natural gas load of ~~$6.9 million. The decrease in revenue per therm was~~4.3%, or $34.4 million of natural gas sales. Natural gas load decreased primarily due to a ~~rate~~2.1%, 9.7%, and 4.2% decrease ~~on customer bills for PGA, which decreased rates 0.4% effective November 1, 2016~~in average therms used by residential customers, commercial firm and ~~increase~~industrial firm customers, respectively partially driven by a decrease in ~~decoupling rates~~heating degree days of ~~2.4% effective May 1, 2017, see~~2.0%. Commercial and industrial firm customers decrease was primarily driven by business shut downs resulting from COVID-19. See Management's Discussion and Analysis, "Regulation and Rates" and "Overview" included in Item 72 of this report for natural gas rate ~~changes. Natural gas load~~changes and COVID-19 updates.

•Decoupling revenue increased ~~primarily due~~$16.6 million. This is attributable 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%~~9.3% in allowed natural gas ~~customers, which increased~~revenues and decreased usage, as noted above in the retail revenue section. This resulted in allowed natural gas ~~heating load compared~~revenues being greater than actual natural gas revenues in the current year, whereas in the prior year allowed revenues were closer to ~~prior year.~~actual revenues.

•Other decoupling revenue increased $23.3 million due to a $25.4 million decrease in current year amortization of prior year undercollection, which was driven by decreased usage and a decrease in rates of 5.3% and 0.5% effective May 2019 and May 2020, respectively. This is partially offset by a $2.2 million decrease related to earnings in excess of allowed ROR. In 2019, earnings in excess of allowed ROR of $2.2 million was returned to customers. There were no such returns to customers in 2020.

~~Decoupling~~•Transportation and other revenue decreased ~~$48.6~~$3.5 million primarily due to ~~an increase~~a $2.9 million decrease in ~~use per customer, driven by an increase~~entitlement constraint revenues for interruptible customers that have agreements in ~~heating degree days as discussed above in~~place to curtail their 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~~usage when the natural gas distribution system is constrained 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 revenuedemand 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.~~

2019.

Natural Gas Energy Costs

Purchased natural gas expense increased ~~$46.1~~$71.9 million due to an increase in ~~natural~~the PGA rates in November 2019 and the addition of two supplemental gas commodity costs amortization rates in 2019 which were added in order to recover the large amount of gas costs ~~included~~that PSE incurred in ~~PGA rates effective November 1, 2016 as compared to those effective November 1, 2015,~~late 2018 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.~~

~~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 primarilyearly 2019 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~~Enbridge pipeline explosion 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%.~~4.3% as stated in the natural gas retail sales section above.

For additional information on prior years, please see discussion in Item 7, "Non-GAAP Financial Measures - Natural Gas Margin" of Form 10-K for period ended December 31, 2019.

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~~for the years ended December 31, 2019, to ~~2017:~~December 31, 2020:

~~2016~~

2019 compared to ~~2017~~2020

Other Operating Expenses

•Net unrealized (gain) loss on derivative instruments ~~expense~~ increased ~~$114.6~~$23.2 million to a net loss of ~~$30.8~~$26.8 million for the year ended December 31, ~~2017.~~2020. One of the drivers is related to the change in the weighted average forward prices for electric and natural gas. Specifically, electric prices decreased 22.1% resulting in a $75.4 million loss for electric. Natural gas prices decreased 4.1% resulting in a $17.0 million loss for natural gas. The ~~primary drivers for~~other driver is related to the ~~increase consist~~net settlements of ~~a reduction of $20.6 million in gains from contract settlements~~electric and natural gas trades previously recorded as $63.6 million and $5.6 million in losses, respectively, that settled toand are recorded in purchased electricity or electric generation fuel which results in a gain for unrealized gains and ~~a $94.0~~losses on derivative instruments. For further details, see Note 10, "Accounting for Derivative Instruments and Hedging" to the consolidated financial statements included in Item 8 of this report.

•Non-utility and other expense decreased $2.0 million ~~loss~~primarily due to a decrease in ~~natural gas~~long term incentive plan costs of $16.0 million; partially offset by a one-time $7.0 million biogas payment and ~~electricity forward prices~~an increase in supplemental executive retirement plan (SERP) costs of ~~26.9%~~$7.2 million.

•Depreciation 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~~amortization expense ~~increased $15.8~~decreased $5.7 million primarily driven by ~~increases~~an electric amortization decrease of $31.8 million, or 35.3%, from 2019 due to a $28.9 million change in the ~~following: $6.7 million for electric and natural gas operations primarily~~PTCs amortization 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 werelower taxable income year over year. The decrease was partially offset by ~~$1.6~~(i) an increase in electric distribution depreciation of $8.6 million, ~~reduction~~or 6.2%, from 2019 due to $179.2 million in net additions of ~~uncollectible account costs compared~~electric distribution assets; (ii) natural gas distribution depreciation increased by $8.3 million, or 7.4%, from 2019 due to ~~2016.~~

~~Non-utility~~$231.9 million in net additions in natural gas distribution assets; (iii) natural gas amortization increased by $3.6 million or 41.9% from 2019 due to the final accounting for the AMI deferrals provided by the results of the 2019 GRC and ~~other~~ ~~expense~~net additions of $24.3 million; and (iv) conservation amortization increased ~~$14.5~~by $3.0 million ~~primarily~~ due to an increase in ~~the long-term incentive plan~~rates effective May 1, 2020.

•Taxes other than income taxes decreased $5.3 million primarily due to a decrease in Montana property taxes 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~~$4.1 million primarily due to the ~~following: (i) electric depreciation expense~~retirement of ~~$12.1~~Colstrip 1 & 2 in Montana and $2.4 million ~~primarily~~of property tax tracker 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

load.

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

•Other income/expense increased $15.0 million primarily due to $6.3 million of SmartBurn plant investment at Colstrip Units 3 & 4 which recovery was disallowed in the 2019 GRC, write-offs of $4.8 million of asset costs, and an increase in strategic initiative costs of $3.1 million.

•Interest expense increased $3.1 million due to $9.7 million of interest expense on the $450.0 million senior note issued in 2019, increased PTCs interest expense of $4.9 million in 2020, partially offset by a decrease of $7.9 million of other interest expense attributed to lower commercial paper borrowing in 2020.

•Income tax expense ~~increased $36.6~~ decreased $12.9 million primarily driven by ~~the impact~~a decrease of ~~tax reform on the deferred tax balances~~9.5% of income before income taxes and ~~partially offset by~~ a ~~4.3%~~26.3% decrease in ~~pre-tax income.~~the effective tax rate to 8.7% in 2020 from 11.8% in 2019. For ~~additional information,~~further details, see Note ~~13,~~14, "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~~For additional information on prior years, please see discussion in Item 7, "Other Operating Expenses

~~Net unrealized (gain) loss on derivative instruments~~ ~~expense decreased $71.1 million to a net gain~~ and Other Income (Deductions)" of ~~$83.8 million~~Form 10-K for ~~the year~~period 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.2019.

~~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.

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~~2019, and ~~2015~~December 31, 2020, were as follows:

~~2016~~2019 compared to ~~2017~~2020

Summary Results of Operations

Puget Energy’s net income decreased by ~~$137.7~~$27.9 million, which is primarily attributable to ~~an income tax expense increase of $79.3 million, as well as~~a decrease in PSE's net income ~~decrease~~ of ~~$60.5~~$18.6 million and an increase in interest expense of $13.8 million. The ~~following are significant factors that impacted Puget Energy’s net income which are not included~~increase in ~~PSE’s discussion:~~

~~Income Tax Expense~~ ~~increased by $79.3 million~~interest expense was primarily due to ~~tax reform passed~~a $13.5 million loss from the redemption of senior secured notes in June 2020, a $200 million net additional issuance of $650 million issued in May 2020 and $450 million redeemed in June 2020. For the discussion of redemption, see Note 7, "Long-Term Debt" to the consolidated financial statements in Item 8 of this report.

For additional information 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.~~

~~2015 compared to 2016~~

prior years, please see discussion in Item 7, "Puget Energy Summary Results of ~~Operations~~

~~Puget Energy’s net income increased by $71.7 million, which is primarily attributable to PSE's net income increase~~Operation" of ~~$76.4 million. The following are significant factors that impacted Puget Energy’s net income which are not included in PSE’s discussion:~~Form 10-K for period ended December 31, 2019.

~~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.~~

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:~~2020:


	Payments Due Per Period
(Dollars in Thousands)	Total		2021		2022-2023		2024-2025		Thereafter
Contractual obligations:
Energy purchase obligations1	$	6,610,450	$	1,046,399	$	1,630,182	$	1,274,587	$	2,659,282
Long-term debt including interest2	5,735,238		229,109		453,394		453,394		4,599,341
Short-term debt including interest	373,800		373,800		—		—		—
Service contract obligations	545,199		75,199		155,512		159,832		154,656
Non-cancelable operating leases3	253,074		23,170		45,130		39,862		144,912
PSE finance leases3	885		508		377		—		—
Pension and other benefits funding and payments	69,859		25,760		7,578		16,373		20,148
Total PSE contractual cash obligations	13,588,505		1,773,945		2,292,173		1,944,048		7,578,339
Long-term debt including interest2	2,531,168		610,535		770,723		473,260		676,650
Total Puget Energy contractual cash obligations	$	16,119,673	$	2,384,480	$	3,062,896	$	2,417,308	$	8,254,989

____________________

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 7, "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 9, "Leases" to the consolidated financial statements included in Item 8 of this report.

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:~~2020:


	Amount of Available Commitments Expiration Per Period													Amount of Available Commitments Expiration Per Period
(Dollars in Thousands)	Total			2018		2019 - 2020		2021 - 2022		Thereafter			(Dollars in Thousands)	Total	2021	2022-2023	2024-2025	Thereafter
Commercial commitments:													Commercial commitments:
PSE revolving credit facility¹	$	800,000		$	—	$	—	$	800,000	$	—		PSE revolving credit facility1	$800,000	$—	$800,000	$—	$—
Inter-company short-term debt²	30,000			—		—		—		30,000			Inter-company short-term debt2	30,000	—	—	—	30,000
Total PSE commercial commitments	830,000			—		—		800,000		30,000			Total PSE commercial commitments	830,000	—	800,000	—	30,000
Puget Energy revolving credit facility³	697,400			—		—		697,400		—			Puget Energy revolving credit facility3	785,300	—	785,300	—	—
Less: Inter-company short-term debt elimination²	(30,000		)	—		—		—		(30,000		)	Less: Inter-company short-term debt elimination2	(30,000)	—	—	—	(30,000)
Total Puget Energy commercial commitments	$	1,497,400		$	—	$	—	$	1,497,400	$	—		Total Puget Energy commercial commitments	$1,585,300	$—	$1,585,300	$—	$—

_______________

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.~~

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.

1.As of December 31, 2020, 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 2023. 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, 2020, no loans or letters of credit were outstanding under the credit facility and $373.8 million was outstanding under the commercial paper program. The credit agreement is syndicated among numerous lenders. Outside of the credit agreement, PSE has a $2.7 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, 2020, 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, 2020, Puget Energy had a revolving senior secured credit facility totaling $800.0 million, which matures in October 2023. 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, 2020, there was $14.7 million drawn and outstanding under the Puget Energy credit facility.

Off-Balance Sheet Arrangements

As of December 31, ~~2017,~~2020, 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.~~condition.

Utility Construction Program

~~PSE’s~~The Company’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~~support customer growth and to ~~support reliable~~improve energy ~~delivery.~~ system reliability. Due to business disruptions caused by the COVID-19 pandemic, the Company closely monitored and adjusted capital expenditures, resulting in a decrease of $83.1 million compared to forecasted amounts for 2020.Construction expenditures, excluding equity ~~AFUDC,~~allowance for funds used during construction (AFUDC), totaled ~~$963.7~~$908.1 million in ~~2017.~~2020. Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:


Capital Expenditure Projections
(Dollars in Millions)	2021	2022	2023
Total energy delivery, technology and facilities expenditures	$967.6	$985.0	$1,146.8

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~~may be funded from a combination of sources, which may include cash from operations, short-term debt, long-term debt and/or equity. PSE’s ~~utility construction program~~planned capital expenditures ~~periodically can and do~~may result in a level of spending that will exceed its cash flow ~~generated~~ from operations. As a result, execution of PSE’s ~~utility construction program~~strategy is dependent in part on continued access to capital markets.

Capital Resources

Cash from Operations


Puget Sound Energy	Year Ended December 31,									Puget Sound Energy	Year Ended December 31,
(Dollars in Millions)	2017			2016			Change
(Dollars in Thousands)										(Dollars in Thousands)	2020		2019		Change
Net income	$	320,054		$	380,581		$	(60,527	)	Net income	$	274,280	$	292,924	$	(18,644)
Non-cash items¹	782,890			631,440			151,450			Non-cash items1	724,650		677,261		47,389
Changes in cash flow resulting from working capital²	105,281			(46,554		)	151,835			Changes in cash flow resulting from working capital2	(57,578)		(107,355)		49,777
Regulatory assets and liabilities	(88,875		)	(152,786		)	63,911			Regulatory assets and liabilities	(152,417)		(79,173)		(73,244)
Purchased gas adjustment										Purchased gas adjustment	45,111		(132,766)		177,877
Other non-current assets and liabilities³	(32,547		)	6,235			(38,782		)	Other non-current assets and liabilities3	(9,236)		(26,967)		17,731
Net cash provided by operating activities	$	1,086,803		$	818,916		$	267,887		Net cash provided by operating activities	$	824,810	$	623,924	$	200,886

_______________


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.~~

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~~2020, compared to ~~2016~~2019

Cash generated from operations for the year ended December 31, ~~2017~~2020, increased by ~~$267.9~~$200.9 million, including a net income decrease of ~~$60.5~~$18.6 million. The following are significant factors that impacted PSE's cash flows from operations:

~~Non-cash~~•Cash flow adjustments resulting from non-cash items increased ~~$151.5~~$47.4 million primarily due to ~~changes~~a $28.9 million change in PTC utilization, a $23.2 million change from a net unrealized loss on derivative instruments of ~~$114.6~~$3.6 million to a net unrealized loss on derivative instruments of $26.8 million, a loss of $6.3 million due to writing off Smart Burn project at Colstrip, a decrease of amortization of TCJA related income tax expense over-collection of $6.0 million and increased conservation amortization of $3.0 million, partially offset by decreases in depreciation and amortization of ~~$42.4~~$8.7 million, equity AFUDC of $7.4 million and 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.~~$5.2 million. For further discussion, see ~~Other~~"Other Operating ~~Expenses~~Expenses" in Item 7, Management's Discussion and Analysis and Note ~~13,~~14, "Income Taxes" in Item 8.

•Cash flows resulting from changes in working capital increased $49.8 million primarily due to decreased cash outflow in accounts payable by $132.9 million, which was mainly due to 2019 includes payments of significant power and natural gas costs accrued at December 31, 2018 that were paid in 2019. The decrease of cash outflow in accounts payable was partially offset by cash outflow increases in accounts receivable of $41.5 million, SERP liability of $32.2 million, as well as short-term purchased gas adjustment receivables of $9.9 million.

•Cash flows resulting from regulatory assets and liabilities decreased $73.2 million primarily due to increases in decoupling deferrals of $67.0 million and major maintenance at Colstrip 3 & 4 of $5.0 million.

•Cash flow resulting from purchased gas adjustment (long-term) increased $177.9 million. Affected by three events experienced by PSE in 2019 winter: (1) the Enbridge pipeline rupture, (2) unusually low temperatures in February and March, and (3) a compressor failure in February at the Jackson Prairie storage facility, actual natural gas cost went above natural gas baseline rates in the PGA mechanism, caused the total purchased gas adjustment receivable to increase from $9.9 million to $132.8 million in 2019, which led to $122.9 million cash outflow. In contrast, both price of natural gas and actual gas consumption decreased during 2020. Combined with higher PGA rates taking effect on November 1, 2019, total purchase gas adjustment receivable decreased from $132.8 million to $87.7 million in 2020, resulting in a $45.1 million cash inflow. A change from $122.9 million cash outflow to $45.1 million cash inflow led to an increase of cash flow of $168.0 million, which includes an increase in PGA long-term of $177.9 million and a decrease in PGA short-term of $9.9 million. For further details, see "Natural Gas Margin" in Item 7, Management's Discussion and Analysis.

•Cash flow resulting from changes in other non-current assets and liabilities increased $17.7 million primarily due to $13.7 million payroll taxes deferral, partially offset with other changes in long-term assets and liabilities.


Puget Energy	Year Ended December 31,
(Dollars in Thousands)	2020		2019		Change
Net income	$	(91,563)	$	(82,216)	$	(9,347)
Non-cash items1	2,841		(2,381)		5,222
Changes in cash flow resulting from working capital2	3,415		(4,800)		8,215
Regulatory assets and liabilities	—		(60)		60
Other non-current assets and liabilities3	(11,935)		(7,131)		(4,804)
Net cash provided by operating activities	$	(97,242)	$	(96,588)	$	(654)

______________

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

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

Year Ended December 31, 2020, compared to 2019

Cash generated from operations for the year ended December 31, 2020, in addition to the changes discussed at PSE above, decreased by $0.7 million compared to the same period in 2019, which includes a net income decrease of $9.3 million. The remaining change was primarily impacted by the factors explained below:

•Non-cash items increased $5.2 million primarily caused by the cash outflow of $13.5 million due to extinguishment of debt reflected in financing activities, partially offset by a decrease in cash outflow of $8.6 million due to changes in deferred taxes.

•Changes in cash flow resulting from working capital increased ~~$151.8~~$8.2 million primarily due to a $5.3 million increase related to changes in ~~accounts~~eliminations of PSE's intercompany account receivable and ~~unbilled revenue of $50.7~~account payable balances with Puget LNG and Puget Energy, a $3.6 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~~tax payable, partially offset with decreases in ~~materials and supplies, and an increase of $47.0 million in prepayments.~~

other accrued expenses.

~~Regulatory~~•Other non-current assets and liabilities ~~cash flow increased $63.9~~ decreased $4.8 million primarily due to ~~changes in decoupling and derivatives offset by changes in purchased gas adjustments.~~

~~Other non-current assets and liabilities~~ ~~cash flow decreased $38.8 million primarily due to an increase in~~change of the ~~long-term incentive plan accrual, an increase in major maintenance and inspections, reduced~~valuation of 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~~liability 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:prior year.

~~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.~~

Financing Program

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

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

As a result of the COVID-19 pandemic and its impact on the economy and capital markets, the Company continues to carefully monitor cash receipts from customers and any impacts on the Company’s liquidity which may affect its ability to fund safe, reliable, and dependable service for our customers. Our initiative to suspend disconnections of customers for non-payment and the receipt of the Washington Commission approval to waive late fees will impact future cash receipts.

As a result of the 2019 GRC outcome and the continuing negative impacts of tax reform on the Company's cash flows, Puget Energy and PSE's credit rating metrics were negatively impacted. In response to the 2019 GRC order, Moody's released an issuer comment stating the GRC outcome was credit negative but took no formal credit rating action. S&P placed Puget Energy and PSE on CreditWatch with negative implications due the rate case outcome and Fitch affirmed Puget Energy and PSE ratings but changed its outlook from stable to negative. Subsequently, S&P removed Puget Energy and PSE from CreditWatch negative. All three credit agencies indicated that continued stress on credit metrics and/or lack of sufficient regulatory rate relief over the relative near term could result in additional negative ratings implications, including a credit rating downgrade. A consistent credit rating downgrade by the three credit agencies would lower Puget Energy from investment grade to non-investment grade, however, PSE would remain at investment grade, assuming a one notch credit adjustment. Additionally, a credit rating downgrade would increase the cost of borrowing for Puget Energy and PSE in future long-term

financings and impact the terms under their existing credit facilities. Any increase in the cost of borrowing would negatively impact Puget Energy and PSE's future results of operations and could negatively impact their future liquidity, access to debt capital resources and financial condition. A downgrade to Puget Energy and PSE's credit ratings would not impact debt covenants under our existing credit facilities nor would it impact other contracts, as neither include credit rating triggering event clauses. A credit rating decrease for PSE could result in increased cash collateral required for commodity contracts, which would adversely affect PSE's liquidity. Management continually monitors the credit rating environment for both Puget Energy and PSE, but cannot predict with certainty the actions credit agencies may take, if any, in response to weaker near term credit metrics, regulatory and rate recovery uncertainties, and management's efforts to contain the growth of capital and operating expenditures. Containing the growth of capital and operating expenditures will be limited, over the near to medium term, due to continuing strategic and risk mitigation imperatives and the necessity of providing safe, reliable and resilient service levels to customers, particularly in the context of the COVID-19 pandemic.

Commercial paper markets were significantly impacted for a period of time due to COVID-19, which limited commercial paper borrowings so therefore the Company drew short term funding from its credit facility. The Company created a minimum cash reserve of $100 million on April 1, 2020, which was intended to be utilized to cover cash disbursements in the event of illiquid markets. As a result of significantly improved commercial paper markets and steady cash collection over the second quarter of 2020, the Company reduced its cash reserve requirement to $20 - $25 million. Evolving factors that we cannot accurately predict, including the duration and scope of the COVID-19 pandemic, and any relevant governmental, business and customers’ actions that have been and continue to be taken in response to the COVID-19 pandemic, could negatively impact the Company’s liquidity.

For information on Puget Energy and PSE dividends, long-term debt and credit facilities, see Note 4,5, “Dividend Payment Restrictions, Note 6,7, “Long-term Debt” and Note 7,8, “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,~~2020, PSE could issue:

•Approximately ~~$2.6~~$2.1 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately ~~$4.3~~$3.5 billion of electric bondable property available for issuance, subject to an interest coverage ratio limitation of 2.0 times net earnings available for interest (as defined in the electric utility mortgage), which PSE exceeded at December 31, ~~2017;~~2020; and

•Approximately ~~$535.0~~$838.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately ~~$891.7 million~~$1.4 billion 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~~

2020

At December 31, ~~2017,~~2020, PSE had approximately ~~$7.2~~$8.0 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~~

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)~~ASC 980, “Regulated Operations” (ASC 980), the decoupling mechanism is an alternative revenue program that allows billings to be adjusted for the effects of weather abnormalities, conservation efforts or other various external factors. PSE adjusts these billings in the future in response to these effects to collect additional revenues provided under the decoupling mechanism. Once billing of additional revenues under the decoupling mechanism is permitted,

the additional revenue can be recognized when the following criteria specified by ASC 980 are met: (i) the program is established by an order from the 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.

For further discussion regarding revenue recognition, see Note 3, "Revenue", to the consolidated financial statements included in Item 8 of this report.

Regulatory Accounting

As a regulated entity of the Washington Commission and the FERC, PSE prepares its financial statements in accordance with the provisions of ASC 980. The application of ASC 980 results in differences in the timing and recognition of certain revenue and expenses in comparison with businesses in other industries. The rates that are charged by PSE to its customers are based on cost base regulation reviewed and approved by the Washington Commission and the FERC. Under the authority of these commissions, PSE has recorded certain regulatory assets and liabilities at December 31, ~~2017~~2020, in the amount of ~~$953.1~~$918.1 million and ~~$1,758.6~~$1,685.2 million, respectively, and regulatory assets and liabilities at December 31, ~~2016~~2019, of ~~$1.1 billion~~$847.5 million and ~~$653.3~~$1,676.6 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 Management's Discussion and Analysis, "Regulation and Rates" included in Item 7 ~~"Business – Regulation and Rates".~~of this report. 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.

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.

For additional information, see Item 7A, "Quantitative and Qualitative Disclosures about Market Risk" Note 9,10, "Accounting for Derivative Instruments and Hedging Activities" and Note 10,11, "Fair Value Measurements" to the consolidated financial statements included in Item 8 of this report.

Fair Value

ASC 820 ~~“Fair Value Measurements and Disclosures” (ASC 820),~~ defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). However, as permitted under ASC 820, the Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of its assets and liabilities measured and reported at fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company primarily applies the market approach for recurring fair value measurements as it believes that this approach is used by market participants for these types of assets and liabilities. Accordingly, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. For further discussion on market risk, see Item 7A, "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~~$17.1 million and ~~$22.9~~$12.6 million for the years ended December 31, ~~2017, 2016~~2020, and ~~2015,~~2019, respectively. Of these amounts, approximately ~~51.6%, 55.5%~~50.6% and ~~58.5%~~49.0% were included in utility operations and maintenance expense in ~~2017, 2016~~2020 and ~~2015,~~2019, respectively, and the remaining amounts were capitalized. For the years ended December 31, ~~2017~~2020, and ~~2016,~~2019, Puget Energy recognized incremental qualified pension income of ~~$13.4~~$11.3 million and ~~$15.5~~$12.1 million, respectively. In ~~2018,~~2021, it is expected that PSE and Puget Energy will recognize pension expense of ~~$11.5~~$20.6 million and incremental qualified pension income of ~~$13.0~~$10.3 million, respectively.

PSE has a Supplemental Executive Retirement Plan (SERP). PSE recognized pension and other postretirement benefit expenses of ~~$4.8 million, $4.8~~$5.0 million and ~~$5.6~~$5.4 million for the years ended December 31, ~~2017, 2016~~2020, and ~~2015,~~2019, respectively. For the years ended December 31, ~~2017~~2020, and ~~2016,~~2019, Puget Energy recognized incremental income of ~~$0.5~~$0.3 million and $0.4 million, respectively. In ~~2018,~~2021, it is expected that PSE and Puget Energy will recognize pension expense of ~~$5.1~~$4.5 million and incremental pension income of ~~$0.5~~$0.2 million, respectively.

PSE also has other limited postretirement benefit plans. PSE recognized income of ~~$0.5 million, $0.5~~$0.1 million and ~~$0.2~~$0.5 million for the years ended December 31, ~~2017, 2016~~2020, and ~~2015,~~2019, respectively. For the years ended December 31, ~~2017~~2020, and ~~2016,~~2019, Puget Energy recognized incremental expense of $0.1 million and $0.2 million, ~~each year.~~respectively. In ~~2018,~~2021, it is expected that PSE and Puget Energy will recognize ~~income~~expense of ~~$0.5~~$0.1 million and incremental expense of ~~$0.2~~$0.1 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,~~2020, the Company made cash contributions of $18.0 million to the qualified defined ~~benefit~~pension plan. Management is closely monitoring the funding status of its qualified pension plan. At December 31, ~~2017~~2020, and ~~2016,~~2019, the Company’s qualified pension plan was ~~$3.9~~$14.7 million ~~overfunded~~underfunded and ~~$32.3~~$21.3 million underfunded as measured under GAAP, or ~~100.6%~~98.3% and ~~95.0%~~97.3% funded, respectively. As of January 1, ~~2018,~~2021, 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~~2021, are expected to be at least $18.0 million, ~~$5.5~~$6.8 million and $0.3 million, respectively.

The discount rate used in accounting for pension and other benefit obligations decreased from ~~4.50%~~3.35% in ~~2016~~2019 to ~~4.00%~~2.70% in ~~2017.~~2020. The discount rate used in accounting for pension and other benefit expense decreased from ~~4.65%~~4.40% in ~~2016~~2019 to ~~4.50%~~3.35% in ~~2017.~~2020. The rate of return on plan assets for qualified pension benefits decreased from ~~7.75%~~7.50% in ~~2016~~2019 to ~~7.45%~~7.15% in ~~2017.~~2020. The rate of return on plan assets for other benefits was 7.00% in ~~2017~~both 2019 and ~~2016 was 6.75%, respectively.~~2020.

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


Puget Energy and Puget Sound Energy	Change in Assumption	Impact on Projected Benefit Obligation Increase /(Decrease)
(Dollars in Thousands)		Pension Benefits		SERP		Other Benefits
Increase in discount rate	50 basis points	$	(50,098)	$	(1,398)	$	(559)
Decrease in discount rate	50 basis points	55,751		1,493		611


Puget Energy and Puget Sound Energy	Change in Assumption	Impact on Projected Benefit Obligation Increase /(Decrease)
Puget Energy											Puget Energy	Change in Assumption	Impact on 2020 Pension Expense Increase /(Decrease)
(Dollars in Thousands)		Pension Benefits			SERP			Other Benefits			(Dollars in Thousands)		Pension Benefits		SERP		Other Benefits
Increase in discount rate	50 basis points	$	(38,831	)	$	(1,940	)	$	(548	)	Increase in discount rate	50 basis points	$	(3,331)	$	(128)	$	8
Decrease in discount rate	50 basis points	43,000			2,069			601			Decrease in discount rate	50 basis points	3,651		138		(11)
Increase in return on plan assets											Increase in return on plan assets	50 basis points	$	(3,491)	*		$	(28)
Decrease in return on plan assets											Decrease in return on plan assets	50 basis points	3,491		*		27

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)									Puget Sound Energy	Change in Assumption	Impact on 2020 Pension Expense Increase /(Decrease)
(Dollars in Thousands)		Pension Benefits			SERP			Other Benefits			(Dollars in Thousands)		Pension Benefits		SERP		Other Benefits
Increase in discount rate	50 basis points	$	(2,906	)	$	(173	)	$	(51	)	Increase in discount rate	50 basis points	$	(3,331)	$	(128)	$	7
Decrease in discount rate	50 basis points	3,026			181			52			Decrease in discount rate	50 basis points	3,651		138		(11)
Increase in return on plan assets	50 basis points	(3,212		)	*			(34		)	Increase in return on plan assets	50 basis points	$	(3,492)	*		$	(28)
Decrease in return on plan assets	50 basis points	3,212			*			34			Decrease in return on plan assets	50 basis points	3,492		*		27

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:

1.Our Board has adopted clear corporate governance guidelines.

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

3.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.

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

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

6.The Company has adopted a ~~Corporate Ethics and Compliance~~ Code of Conduct 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.

7.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~~Mary E. Kipp

/s/ Daniel A. Doyle

/s/ Stephen J. King

~~Kimberly J. Harris~~Mary E. Kipp

Daniel A. Doyle

Stephen J. King

President and Chief Executive Officer

Senior Vice President

and Chief Financial Officer

Controller and Principal

Accounting Officer

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder of

Puget Energy, Inc.

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 (the “Company”) 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,~~2020, 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~~2020 and ~~2016~~, 2019, and the results of ~~their~~its operations and ~~their~~its cash flows for each of the three years in the period ended December 31, ~~2017~~2020 in 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,~~2020, based on criteria established in Internal Control - Integrated Framework(2013)issued by the COSO.

Change in Accounting Principle

As discussed in Note 9 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.

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.~~Reporting appearing under Item 9A. 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")~~(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.

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.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Accounting for the Effects of Regulatory Matters

As described in Notes 1 and 4 to the consolidated financial statements, the Company recorded $929.8 million of regulatory assets and $1,781.5 million of regulatory liabilities as of December 31, 2020. Management accounts for the Company’s regulated operations in accordance with the Financial Accounting Standards Board’s (FASB) accounting guidance for regulated operations, which requires deferral of certain costs or losses that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. The FASB’s accounting guidance for regulated operations similarly requires deferral of revenues or gains that are expected to be returned to customers in the future. This accounting 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. As disclosed by management, the regulatory assets and liabilities are expected to be fully recovered through the Company’s rates. If future recovery of costs ceases to be probable, management would be required to write off the regulatory assets and liabilities. In addition, if management determines that it no longer meets the criteria for continued application of the FASB’s accounting guidance for regulated operations, management could be required to write off its regulatory assets and liabilities related to those operations not meeting the FASB’s requirements.

The principal considerations for our determination that performing procedures relating to the Company’s accounting for the effects of regulatory matters is a critical audit matter is the high degree of effort in performing audit procedures and evaluating audit evidence obtained related to the continued application of regulatory accounting and accounting for regulatory assets and liabilities.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s assessment of the continued application of regulatory accounting and management’s review and application of regulatory proceedings. These procedures also included, among others, (i) evaluating the reasonableness of management’s judgments regarding the continued application of regulatory accounting and the probability of recovery of the capital investments and regulatory assets and settlement of regulatory liabilities; (ii) testing existing regulatory assets and liabilities and; (iii) assessing the appropriateness of the disclosures in the consolidated financial statements. Evaluating the continued application of regulatory accounting and the accounting for new and existing regulatory assets and liabilities involved examining the Company’s correspondence with regulators, pending regulatory proceedings, and the provisions and formulas outlined in rate orders to assess the impact on the amounts recognized.

/s/ PricewaterhouseCoopers LLP

Seattle, Washington

~~March 1, 2018~~February 25, 2021

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

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 (the “Company”) 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,~~2020, based on criteria established in Internal Control - Integrated Framework(2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Change in Accounting Principle

As discussed in Note 9 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.

Basis for Opinions

Definition and Limitations of Internal Control over Financial Reporting

Critical Audit Matters

Accounting for the Effects of Regulatory Matters

As described in Notes 1 and 4 to the consolidated financial statements, the Company recorded $918.1 million of regulatory assets and $1,685.2 million of regulatory liabilities as of December 31, 2020. Management accounts for the Company’s regulated operations in accordance with the Financial Accounting Standards Board’s (FASB) accounting guidance for regulated operations, which requires deferral of certain costs or losses that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. The FASB’s accounting guidance for regulated operations similarly requires deferral of revenues or gains that are expected to be returned to customers in the future. This accounting 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. As disclosed by management, the regulatory assets and liabilities are expected to be fully recovered through the Company’s rates. If future recovery of costs ceases to be probable, management would be required to write off the regulatory assets and liabilities. In addition, if management determines that it no longer meets the criteria for continued application of the FASB’s accounting guidance for regulated operations, management could be required to write off its regulatory assets and liabilities related to those operations not meeting the FASB’s requirements.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s assessment of the continued application of regulatory accounting and management’s review and application of regulatory proceedings. These procedures also included, among others, (i) evaluating the reasonableness of management’s judgments regarding the continued application of regulatory accounting and the probability of recovery of the capital investments and regulatory assets and settlement of regulatory liabilities; (ii) existing regulatory assets and liabilities and; (iii) assessing the appropriateness of the disclosures in the consolidated financial statements. Evaluating the continued application of regulatory accounting and the accounting for new and existing regulatory assets and liabilities involved examining the Company’s correspondence with regulators, pending regulatory proceedings, and the provisions and formulas outlined in rate orders to assess the impact on the amounts recognized.

/s/ PricewaterhouseCoopers LLP

Seattle, Washington

~~March 1, 2018~~February 25, 2021

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

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)


	Year Ended December 31,
	2020		2019		2018
Operating revenue:
Electric	$	2,319,416	$	2,497,041	$	2,455,919
Natural gas	980,913		875,371		850,748
Other	26,121		28,718		39,829
Total operating revenue	3,326,450		3,401,130		3,346,496
Operating expenses:
Energy costs:
Purchased electricity	593,719		652,560		638,775
Electric generation fuel	199,107		282,864		204,174
Residential exchange	(80,294)		(79,187)		(77,454)
Purchased natural gas	362,872		290,976		296,699
Unrealized (gain) loss on derivative instruments, net	26,807		3,574		(41,662)
Utility operations and maintenance	597,048		596,676		602,638
Non-utility expense and other	43,425		47,907		54,519
Depreciation and amortization	647,755		656,323		666,432
Conservation amortization	99,585		96,571		111,714
Taxes other than income taxes	328,602		333,858		336,603
Total operating expenses	2,818,626		2,882,122		2,792,438
Operating income (loss)	507,824		519,008		554,058
Other income (deductions):
Other income	58,759		59,905		52,957
Other expense	(23,207)		(9,053)		(11,201)
Interest charges:
AFUDC	14,827		14,559		13,695
Interest expense	(373,822)		(356,638)		(343,795)
Income (loss) before income taxes	184,381		227,781		265,714
Income tax (benefit) expense	1,664		17,073		30,092
Net income (loss)	$	182,717	$	210,708	$	235,622

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.

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)


	Year Ended December 31,
	2020		2019		2018
Net income (loss)	$	182,717	$	210,708	$	235,622
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $(609) and $(1,846) and $(12,677), respectively	(2,288)		(6,947)		(47,690)

Reclassification of stranded taxes to retained earnings due to tax reform	0		0		(5,230)
Other comprehensive income (loss)	(2,288)		(6,947)		(52,920)
Comprehensive income (loss)	$	180,429	$	203,761	$	182,702

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.~~

~~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.

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

~~CAPITALIZATION AND LIABILITIES~~ASSETS


	December 31,
	2020		2019
Utility plant (at original cost, including construction work in progress of $712,204 and $591,199, respectively):
Electric plant	$	9,200,231	$	8,811,889
Natural gas plant	4,227,532		3,916,040
Common plant	1,116,524		1,096,649
Less: Accumulated depreciation and amortization	(3,671,094)		(3,236,240)
Net utility plant	10,873,193		10,588,338
Other property and investments:
Goodwill	1,656,513		1,656,513
Other property and investments	324,184		286,975
Total other property and investments	1,980,697		1,943,488
Current assets:
Cash and cash equivalents	52,307		45,259
Restricted cash	29,544		20,887
Accounts receivable, net of allowance for doubtful accounts of $20,080 and $8,294, respectively	352,132		316,352
Unbilled revenue	221,871		224,657

Materials and supplies, at average cost	118,333		115,684
Fuel and natural gas inventory, at average cost	48,795		52,083
Unrealized gain on derivative instruments	33,015		23,626
Prepaid expenses and other	45,746		27,504
Power contract acquisition adjustment gain	14,874		9,067
Total current assets	916,617		835,119
Other long-term and regulatory assets:
Power cost adjustment mechanism	82,801		41,745
Purchased gas adjustment receivable	87,655		132,766
Regulatory assets related to power contracts	11,728		14,146
Other regulatory assets	747,651		673,021
Unrealized gain on derivative instruments	8,805		7,682
Power contract acquisition adjustment gain	80,900		147,530
Operating lease right-of-use asset	172,167		183,048
Other	80,751		92,980
Total other long-term and regulatory assets	1,272,458		1,292,918
Total assets	$	15,042,965	$	14,659,863

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.

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

CAPITALIZATION AND LIABILITIES


	December 31,
	2020		2019
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding	$	0	$	0
Additional paid-in capital	3,313,532		3,308,957
Retained earnings	912,787		775,491
Accumulated other comprehensive income (loss), net of tax	(86,437)		(84,149)
Total common shareholder’s equity	4,139,882		4,000,299
Long-term debt:
First mortgage bonds and senior notes	4,212,000		4,212,000
Pollution control bonds	161,860		161,860

Long-term debt	1,724,700		1,758,100
Debt discount, issuance costs and other	(206,120)		(211,635)
Total long-term debt	5,892,440		5,920,325
Total capitalization	10,032,322		9,920,624
Current liabilities:
Accounts payable	342,404		325,913
Short-term debt	373,800		176,000
Current maturities of long-term debt	526,412		452,412

Accrued expenses:
Taxes	110,752		99,979
Salaries and wages	42,530		50,091
Interest	73,647		74,855
Unrealized loss on derivative instruments	31,441		13,428
Power contract acquisition adjustment loss	2,039		2,418
Operating lease liabilities	19,204		15,862
Other	73,385		107,809
Total current liabilities	1,595,614		1,318,767
Other Long-term and regulatory liabilities:
Deferred income taxes	810,729		824,720
Unrealized loss on derivative instruments	29,833		12,693
Regulatory liabilities	732,498		730,879
Regulatory liability for deferred income taxes	953,274		946,179
Regulatory liabilities related to power contracts	95,774		156,597
Power contract acquisition adjustment loss	9,689		11,728
Operating lease liabilities	160,980		174,327
Other deferred credits	622,252		563,349
Total long-term and regulatory liabilities	3,415,029		3,420,472
Commitments and contingencies (Note 16)	0		0
Total capitalization and liabilities	$	15,042,965	$	14,659,863

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

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(Dollars in Thousands)



	Common Stock			Additional				Accumulated Other
	Shares	Amount		Paid-in Capital		Retained Earnings		Comprehensive Income (Loss)		Total Equity
Balance at December 31, 2017	200	$	0	$	3,308,957	$	465,355	$	(24,282)	$	3,750,030
Net income (loss)	—	—		—		235,622		—		235,622
Common stock dividend paid	—	—		—		(77,204)		—		(77,204)
Other comprehensive income (loss)	—	—		—		—		(52,920)		(52,920)
Cumulative effect of accounting change	—	—		—		5,230				5,230
Balance at December 31, 2018	200	$	—	$	3,308,957	$	629,003	$	(77,202)	$	3,860,758
Net income (loss)	—	—		—		210,708		—		210,708
Common stock dividend paid	—	—		—		(64,220)		—		(64,220)
Other comprehensive income (loss)	—	—		—		—		(6,947)		(6,947)

Balance at December 31, 2019	200	$	—	$	3,308,957	$	775,491	$	(84,149)	$	4,000,299
Net income (loss)	—	—		—		182,717		—		182,717
Common stock dividend paid	—	—		—		(45,421)		—		(45,421)
Capital contribution	—	—		4,575		—		—		4,575
Other comprehensive income (loss)	—	—		—		—		(2,288)		(2,288)

Balance at December 31, 2020	200	$	—	$	3,313,532	$	912,787	$	(86,437)	$	4,139,882

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.

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)


											Year Ended December 31,
	Year Ended December 31,										2020		2019		2018
	2017			2016			2015
Operating activities:
Net income (loss)	$	175,194		$	312,899		$	241,179
Operating Activities:										Operating Activities:
Net Income (Loss)										Net Income (Loss)	$	182,717	$	210,708	$	235,622
Adjustments to reconcile net income (loss) to net cash provided by operating activities:										Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	481,969			439,579			420,807			Depreciation and amortization	647,755		656,323		666,432
Conservation amortization	121,216			107,784			110,866			Conservation amortization	99,585		96,571		111,714
Deferred income taxes and tax credits, net	254,524			139,640			91,978			Deferred income taxes and tax credits, net	(6,287)		7,475		19,457
Net unrealized (gain) loss on derivative instruments	30,650			(88,704		)	(17,255		)	Net unrealized (gain) loss on derivative instruments	26,807		3,574		(41,662)
Derivative contracts classified as financing activities due to merger	—			—			8,045
(Gain) or loss on extinguishment of debt										(Gain) or loss on extinguishment of debt	13,546		0		0
AFUDC - equity	(15,027		)	(12,576		)	(9,325		)	AFUDC - equity	(23,223)		(15,802)		(17,191)
Production tax credits	(53,331		)	—			—
Production tax credit										Production tax credit	(39,761)		(68,622)		(83,976)
Other non-cash	17,568			16,812			16,155			Other non-cash	9,069		(4,639)		15,339
Funding of pension liability	(18,000		)	(24,000		)	(18,000		)	Funding of pension liability	(18,000)		(18,000)		(18,000)
Regulatory assets and liabilities	(88,875		)	(153,643		)	(156,491		)	Regulatory assets and liabilities	(152,417)		(79,233)		(71,348)
Other long-term assets and liabilities	(27,411		)	16,435			21,729
Purchased gas adjustment										Purchased gas adjustment	45,111		(132,766)		0
Other long term assets and liabilities										Other long term assets and liabilities	(3,171)		(16,098)		2,695
Change in certain current assets and liabilities:										Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	132			(21,763		)	(66,703		)	Accounts receivable and unbilled revenue	(32,994)		3,058		17,659
Materials and supplies	(625		)	(28,134		)	4,945			Materials and supplies	(2,649)		(6,018)		(9,177)
Fuel and natural gas inventory	8,266			473			9,332			Fuel and natural gas inventory	3,287		1,268		(3,443)
Purchased gas adjustment										Purchased gas adjustment	0		9,921		(25,972)
Prepayments and other	21,050			(25,927		)	4,086			Prepayments and other	(18,242)		(1,103)		(3,679)
Purchased gas adjustment	18,836			(15,374		)	33,662
Accounts payable	26,396			32,465			(48,037		)	Accounts payable	16,516		(116,311)		117,270
Taxes payable	6,520			(3,426		)	7,072			Taxes payable	10,773		(18,133)		164
Other	13,079			36,750			(5,323		)	Other	(30,854)		15,163		(7,723)
Net cash provided by (used in) operating activities	972,131			729,290			648,722			Net cash provided by (used in) operating activities	727,568		527,336		904,181
Investing activities:										Investing activities:
Construction expenditures - excluding equity AFUDC	(1,040,135		)	(706,444		)	(587,225		)	Construction expenditures - excluding equity AFUDC	(908,136)		(959,387)		(1,072,670)
Restricted cash	2,273			(4,469		)	24,914
Other	(195		)	(1,921		)	754			Other	5,340		6,908		2,097
Net cash provided by (used in) investing activities	(1,038,057		)	(712,834		)	(561,557		)	Net cash provided by (used in) investing activities	(902,796)		(952,479)		(1,070,573)
Financing activities:
Financing Activities:										Financing Activities:
Change in short-term debt, net	83,700			86,759			74,004			Change in short-term debt, net	197,800		(203,297)		49,834
Dividends paid	(123,307		)	(148,965		)	(263,059		)	Dividends paid	(45,421)		(64,220)		(77,204)

Investment from parent										Investment from parent	4,575		0		0
Proceeds from long-term debt and bonds issued	90,120			12,481			825,000			Proceeds from long-term debt and bonds issued	644,690		689,351		804,050
Redemption of bonds and notes	—			—			(711,000		)	Redemption of bonds and notes	(450,000)		0		(600,000)
Derivative contracts classified as financing activities due to merger	—			—			(8,045		)
Repayment of term loan and revolving credit										Repayment of term loan and revolving credit	(159,400)		0		0
Other	13,151			19,653			902			Other	(1,311)		13,893		8,513
Net cash provided by (used in) financing activities	63,664			(30,072		)	(82,198		)	Net cash provided by (used in) financing activities	190,933		435,727		185,193
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
Net increase (decrease) in cash, cash equivalents, and restricted cash										Net increase (decrease) in cash, cash equivalents, and restricted cash	15,705		10,584		18,801
Cash, cash equivalents, and restricted cash at beginning of period										Cash, cash equivalents, and restricted cash at beginning of period	66,146		55,562		36,761
Cash, cash equivalents, and restricted cash at end of period										Cash, cash equivalents, and restricted cash at end of period	$	81,851	$	66,146	$	55,562
Supplemental cash flow information:										Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	326,798		$	329,603		$	339,866		Cash payments for interest (net of capitalized interest)	$	336,441	$	328,703	$	322,476
Cash payments (refunds) for income taxes	1,649			—			2			Cash payments (refunds) for income taxes	4,974		10,616		8,303

Non-cash financing and investing activities:										Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	92,959		$	76,813		$	51,588
Accounts payable for capital expenditures eliminated from cash flow										Accounts payable for capital expenditures eliminated from cash flow	$	58,304	$	58,329	$	97,673
Reclassification of Colstrip from utility plant to a regulatory asset	(49,177		)	176,804			—			Reclassification of Colstrip from utility plant to a regulatory asset	0		4,163		(3,086)
Reclassification of hydro treasury grants to a regulatory liability	95,935			—			—

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)


	Year Ended December 31,										Year Ended December 31,
	2017			2016			2015				2020		2019		2018
Operating revenue:										Operating revenue:
Electric	$	2,420,663		$	2,238,492		$	2,128,468		Electric	$	2,319,416	$	2,497,041	$	2,455,919
Natural gas	997,759			890,510			947,549			Natural gas	980,913		875,371		850,748
Other	41,854			35,616			17,241			Other	26,121		28,718		39,829
Total operating revenue	3,460,276			3,164,618			3,093,258			Total operating revenue	3,326,450		3,401,130		3,346,496
Operating expenses:										Operating expenses:
Energy costs:										Energy costs:
Purchased electricity	590,030			531,596			499,522			Purchased electricity	593,719		652,560		638,775
Electric generation fuel	206,275			215,331			249,907			Electric generation fuel	199,107		282,864		204,174
Residential exchange	(75,933		)	(69,824		)	(112,473		)	Residential exchange	(80,294)		(79,187)		(77,454)
Purchased natural gas	360,009			313,954			403,310			Purchased natural gas	362,872		290,976		296,699
Unrealized (gain) loss on derivative instruments, net	30,790			(83,795		)	(12,688		)	Unrealized (gain) loss on derivative instruments, net	26,807		3,574		(41,662)
Utility operations and maintenance	584,263			568,492			530,720			Utility operations and maintenance	597,048		596,676		602,638
Non-utility expense and other	52,389			37,859			26,618			Non-utility expense and other	42,266		44,403		51,549
Depreciation and amortization	481,955			439,579			420,807			Depreciation and amortization	647,546		656,220		666,324
Conservation amortization	121,216			107,784			110,866			Conservation amortization	99,585		96,571		111,714
Taxes other than income taxes	360,673			328,649			320,531			Taxes other than income taxes	328,602		333,858		336,603
Total operating expenses	2,711,667			2,389,625			2,437,120			Total operating expenses	2,817,258		2,878,515		2,789,360
Operating income (loss)	748,609			774,993			656,138			Operating income (loss)	509,192		522,615		557,136
Other income (deductions):										Other income (deductions):
Other income	26,853			25,537			20,711			Other income	46,923		47,766		39,847
Other expense	(14,104		)	(10,923		)	(6,764		)	Other expense	(23,207)		(9,053)		(11,201)

Interest charges:										Interest charges:
AFUDC	10,826			9,304			7,575			AFUDC	14,827		14,559		13,695
Interest expense	(240,144		)	(242,983		)	(247,571		)	Interest expense	(247,213)		(243,815)		(231,615)
Income (loss) before income taxes	532,040			555,928			430,089			Income (loss) before income taxes	300,522		332,072		367,862
Income tax (benefit) expense	211,986			175,347			125,900			Income tax (benefit) expense	26,242		39,148		50,700
Net income (loss)	$	320,054		$	380,581		$	304,189		Net income (loss)	$	274,280	$	292,924	$	317,162

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)


	Year Ended December 31,
	2020		2019		2018
Net income (loss)	$	274,280	$	292,924	$	317,162
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $1,897, $539 and $(9,844), respectively	7,136		2,022		(37,030)
Amortization of treasury interest rate swaps to earnings, net of tax of $102, $102 and $102, respectively	385		385		385
Reclassification of stranded taxes to retained earnings due to tax reform	0		0		(27,333)
Other comprehensive income (loss)	7,521		2,407		(63,978)
Comprehensive income (loss)	$	281,801	$	295,331	$	253,184

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.~~

~~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.

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

~~CAPITALIZATION AND LIABILITIES~~ASSETS


	December 31,
	2020		2019
Utility plant (at original cost, including construction work in progress of $712,204 and $591,199, respectively):
Electric plant	$	11,035,402	$	10,671,328
Natural gas plant	4,786,419		4,478,048
Common plant	1,139,120		1,121,568
Less: Accumulated depreciation and amortization	(6,087,748)		(5,682,606)
Net utility plant	10,873,193		10,588,338
Other property and investments:
Other property and investments	83,855		81,112
Total other property and investments	83,855		81,112
Current assets:
Cash and cash equivalents	51,177		44,004
Restricted cash	29,544		20,887
Accounts receivable, net of allowance for doubtful accounts of $20,080 and $8,294, respectively	355,850		319,229
Unbilled revenue	221,871		224,657

Materials and supplies, at average cost	118,333		115,684
Fuel and natural gas inventory, at average cost	47,531		50,818
Unrealized gain on derivative instruments	33,015		23,626
Prepaid expenses and other	45,746		27,504
Total current assets	903,067		826,409
Other long-term and regulatory assets:
Power cost adjustment mechanism	82,801		41,745
Purchased gas adjustment receivable	87,655		132,766
Other regulatory assets	747,651		673,021
Unrealized gain on derivative instruments	8,805		7,682
Operating lease right-of-use asset	172,167		183,048
Other	79,231		90,924
Total other long-term and regulatory assets	1,178,310		1,129,186
Total assets	$	13,038,425	$	12,625,045

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.

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

CAPITALIZATION AND LIABILITIES


	Year Ended December 31,
	2020		2019
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	3,485,105		3,485,105
Retained earnings	876,401		751,193
Accumulated other comprehensive income (loss), net of tax	(180,956)		(188,477)
Total common shareholder’s equity	4,181,409		4,048,680
Long-term debt:
First mortgage bonds and senior notes	4,212,000		4,212,000
Pollution control bonds	161,860		161,860

Debt discount, issuance costs and other	(35,816)		(37,718)
Total long-term debt	4,338,044		4,336,142
Total capitalization	8,519,453		8,384,822
Current liabilities:
Accounts payable	342,504		325,980
Short-term debt	373,800		176,000
Current maturities of long-term debt	2,412		2,412

Accrued expenses:
Taxes	107,254		99,977
Salaries and wages	42,530		50,091
Interest	48,189		48,917
Unrealized loss on derivative instruments	31,441		13,428
Operating lease liabilities	19,204		15,862
Other	73,385		107,809
Total current liabilities	1,040,719		840,476
Other long-term and regulatory liabilities:
Deferred income taxes	987,382		977,163
Unrealized loss on derivative instruments	29,833		12,693
Regulatory liabilities	731,234		729,614
Regulatory liability for deferred income taxes	953,987		946,936
Operating lease liabilities	160,980		174,327
Other deferred credits	614,837		559,014
Total long-term and regulatory liabilities	3,478,253		3,399,747
Commitments and contingencies (Note 16)	0		0
Total capitalization and liabilities	$	13,038,425	$	12,625,045

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(Dollars in Thousands)



	Common Stock			Additional				Accumulated Other
	Shares	Amount		Paid-in Capital		Retained Earnings		Comprehensive Income (Loss)		Total Equity
Balance at December 31, 2017	85,903,791	$	859	$	3,275,105	$	452,066	$	(126,906)	$	3,601,124
Net income (loss)	—	—		—		317,162		—		317,162
Common stock dividend paid	—	—		—		(173,716)		—		(173,716)

Other comprehensive income (loss)	—	—		—		—		(63,978)		(63,978)
Cumulative effect of accounting change	—	—		—		27,332		—		27,332
Balance at December 31, 2018	85,903,791	$	859	$	3,275,105	$	622,844	$	(190,884)	$	3,707,924
Net income (loss)	—	—		—		292,924		—		292,924
Common stock dividend paid	—	—		—		(164,575)		—		(164,575)
Capital contribution	—	—		210,000		—		—		210,000
Other comprehensive income (loss)	—	—		—		—		2,407		2,407

Balance at December 31, 2019	85,903,791	$	859	$	3,485,105	$	751,193	$	(188,477)	$	4,048,680
Net income (loss)	—	—		—		274,280		—		274,280
Common stock dividend paid	—	—		—		(149,072)		—		(149,072)

Other comprehensive income (loss)	—	—		—		—		7,521		7,521

Balance at December 31, 2020	85,903,791	$	859	$	3,485,105	$	876,401	$	(180,956)	$	4,181,409

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.

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)


	Year Ended December 31,
	2020		2019		2018
Operating Activities:
Net Income (Loss)	$	274,280	$	292,924	$	317,162
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	647,546		656,220		666,324
Conservation amortization	99,585		96,571		111,714
Deferred income taxes and tax credits, net	15,271		20,474		30,995
Net unrealized (gain) loss on derivative instruments	26,807		3,574		(41,662)

AFUDC - equity	(23,223)		(15,802)		(17,191)
Production tax credit	(39,761)		(68,622)		(83,976)
Other non-cash	(1,575)		(15,154)		4,428
Funding of pension liability	(18,000)		(18,000)		(18,000)
Regulatory assets and liabilities	(152,417)		(79,173)		(71,348)
Purchased gas adjustment	45,111		(132,766)		0
Other long term assets and liabilities	8,764		(8,967)		16,917
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	(33,835)		7,650		12,626
Materials and supplies	(2,649)		(6,018)		(9,177)
Fuel and natural gas inventory	3,287		1,210		(3,443)
Purchased gas adjustment	0		9,921		(25,972)
Prepayments and other	(18,242)		(1,103)		(3,679)
Accounts payable	16,549		(116,370)		117,397
Taxes payable	7,277		(18,016)		930
Other	(29,965)		15,371		(8,141)
Net cash provided by (used in) operating activities	824,810		623,924		995,904
Investing Activities:
Construction expenditures - excluding equity AFUDC	(876,437)		(919,271)		(1,010,506)
Other	5,340		6,908		2,097
Net cash provided by (used in) investing activities	(871,097)		(912,363)		(1,008,409)
Financing Activities
Change in short-term debt, net	197,800		(203,297)		49,834
Dividends paid	(149,072)		(164,575)		(173,716)

Investment from parent	0		210,000		0
Proceeds from long-term debt and bonds issued	0		443,151		594,750
Redemption of bonds and notes	0		0		(450,000)
Other	13,389		14,558		9,121
Net cash provided by (used in) financing activities	62,117		299,837		29,989
Net increase (decrease) in cash, cash equivalents, and restricted cash	15,830		11,398		17,484
Cash, cash equivalents, and restricted cash at beginning of period	64,891		53,493		36,009
Cash, cash equivalents, and restricted cash at end of period	$	80,721	$	64,891	$	53,493
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	228,420	$	219,665	$	221,155
Cash payments (refunds) for income taxes	11,521		19,269		18,124


Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flow	$	58,304	$	58,329	$	97,673
Reclassification of Colstrip from utility plant to a regulatory asset	0		4,163		(3,086)

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.

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 approximately 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~~liquefied natural gas (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~~are incurred by PSE and ~~are~~ allocated to Puget LNG are related party transactions by nature.

In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As ~~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~~a result of the ~~Tacoma LNG facility.~~merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date.

The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its 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.”~~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, “Business Combinations” (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%~~3.5%, ~~for each of 2017, 2016~~3.4%, and ~~2015;~~3.3% in 2020, 2019, and 2018, respectively; depreciable natural gas utility plant was ~~3.4%~~2.9%, ~~for each of 2017, 2016~~2.8%, and ~~2015;~~2.8% in 2020, 2019, and 2018, respectively; and depreciable common utility plant was ~~8.3%~~7.3%, ~~9.7%~~7.3% and ~~8.5%~~7.1% in ~~2017, 2016~~2020, 2019, and ~~2015,~~2018, respectively. The cost of removal is collected from PSE’s customers through depreciation expense and any excess is recorded as a regulatory liability.

~~Goodwill~~

and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. These events or circumstances could include a significant change in the Company’s business or regulatory outlook, legal factors, a sale or disposition of a significant portion of a reporting unit or significant changes in the financial markets which could influence the Company’s access to capital and interest rates. Application of the goodwill impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, assignment of goodwill to reporting units and the determination of the fair value of the reporting units. Management has determined Puget Energy has only ~~one~~ ~~reporting unit.~~

Puget Energy conducted its annual impairment test in 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

In August 2015, PSE filed a proposal with the Washington Commission to develop an LNG facility at the Port of Tacoma. Currently under construction at the Port of Tacoma, the facility is expected to be operational in 2021. The Tacoma LNG facility is ~~intended~~designed 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.~~consumption. LNG will also provide fuel to transportation customers, particularly in the marine market. On January 24, 2018, ~~the~~ Puget Sound Clean Air ~~Agency’s~~Agency (PSCAA) determined a Supplemental Environmental Impact Statement is(SEIS) was necessary in order to rule on the air quality permit for the facility. As a result of requiring a ~~Supplemental Environmental Impact Statement,~~SEIS, the Company's construction schedule ~~may be impacted depending on~~was impacted. PSE received the ~~Puget Sound Clean Air Agency's timing and~~SEIS which concluded the LNG facility would result in a net decrease in GHG emissions providing, in part, that the natural gas for the facility was sourced from British Columbia or Alberta. On December 10, 2019, the PSCAA approved the Notice of Construction permit, a decision ~~on the air quality permit. If delayed, the construction schedule and costs may be adversely impacted. Pursuant~~which has been appealed to the Washington ~~Commission’s~~Pollution Control Hearings Board by each of the Puyallup Tribe of Indians and nonprofit law firm Earthjustice.

Pursuant to an order by the Washington Commission, PSE will be allocated approximately 43.0% of common capital and operating costs, consistent with the regulated portion of the 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~~ Per this allocation of costs, $231.6 million inand $199.9 million of construction work in progress related to Puget ~~LNG’s~~LNG's portion of the Tacoma LNG facility is reported in the ~~“Other~~Puget Energy "Other property and ~~investments”~~investments" financial statement line ~~item. For PSE,~~item as of December 31, 2020, and December 31, 2019, respectively. Additionally, $0.6 million, $1.2 million, and $2.0 million of operating costs are reported in the Puget Energy "Non-utility expense and other" financial statement line item in 2020, 2019, and 2018, respectively. Additionally, $207.7 million and $162.8 million of construction work in progress ~~of $87.2 million~~ related to PSE’s portion of the Tacoma LNG facility is reported in the PSE “Utility plant - Natural gas plant” financial statement line item as of December 31, 2020, and December 31, 2019, respectively, 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.

Restricted Cash

Restricted cash amounts primarily represent cash posted as collateral for derivative contracts as well as funds required to be set aside for contractual obligations related to transmission and generation facilities.

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)~~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 3,4, "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~~effective December 19, 2017, ~~with~~was 7.60%. Effective October 1, 2020 for natural gas and October 15, 2020 for electric the ~~Washington Commission order, the new~~authorized AFUDC rate ~~authorized~~ is ~~7.60%~~7.39%.

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. 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~~$240.8 million, ~~$235.3~~$236.5 million and ~~$234.2~~$239.3 million for ~~2017, 2016~~2020, 2019, and ~~2015,~~2018, 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~~general rate case (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~~Credit Losses

~~Allowance~~On January 1, 2020, the Company adopted Accounting Standards Update (ASU) 2016-13 Financial Instruments – Credit Losses (ASC 326) which replaces the incurred loss methodology with an expected loss methodology that is referred to as the current expected credit loss (CECL) methodology. The measurement of expected credit losses under the CECL methodology is applicable to financial assets measured at amortized cost, including trade receivables, loan receivables, and held-to-maturity debt securities. It also applies to off-balance sheet credit exposures not accounted for ~~doubtful accounts~~as insurance (loan commitments, standby letters of credit, financial guarantees, and other similar instruments) and net investments in leases recognized by a lessor in accordance with Topic 842 on leases. The only financial assets within the scope of ASU 2016-13 for the Company are ~~provided~~trade receivables.

The Company adopted ASU 2016-13 using the modified retrospective method. Results for reporting periods beginning after January 1, 2020 are presented under ASC 326 while prior period amounts continue to be reported in accordance with previously applicable GAAP. The Company did not record an adjustment to retained earnings as of January 1, 2020, for the cumulative effect of adopting ASU 2016-13, as the impact was immaterial.

Management measures expected credit losses on trade receivables on a collective basis by receivable type, which include electric retail receivables, gas retail receivables, and ~~natural gas customer accounts based upon a~~electric wholesale receivables. The estimate of expected credit losses considers historical ~~experience rate of write-offs of energy~~credit loss information that is adjusted for current conditions and reasonable and supportable forecasts.

The following table presents the activity in the allowance for credit losses for accounts receivable ~~along with information on future economic outlook.~~ for the year ended December 31, 2020:


Puget Energy and Puget Sound Energy
(Dollars in Thousands)	December 31, 2020
Allowance for credit losses:
Beginning balance	$	8,294
Provision for credit loss expense	23,292
Receivables charged-off	(11,506)

Total ending allowance balance	$	20,080

The allowance increased during the period due to both an increase in the provision combined with a reduction in receivables charged-off during the period. During 2020, the Ratepayer Assistance and Preservation of Essential Services proclamation issued by the governor in April 2020 included a moratorium on disconnecting customers, which resulted in a cessation of account ~~is adjusted monthly~~receivable write-offs for ~~this~~non-payment. Additionally, the provision increased based on collection experience ~~rate. The allowance account is maintained until either receipt of payment or~~during 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.period.

Self-Insurance

PSE is self-insured for storm damage and certain environmental contamination associated with current operations 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.~~index and qualifying costs exceed $0.5 million per qualified storm.

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.~~taxpayer.

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,~~Before the 2017 GRC, the tax savings from these credits were intended to be refunded by PSE to its customers when monetized, used on the income tax return, through its revenue requirement as initially approved by the Washington Commission. As the Company ~~has~~had not generated taxable income ~~and these~~with which to monetize the credits, ~~have not been monetized,~~ they ~~have~~had not been refunded to customers. Amounts to be refunded have been recorded as a regulatory 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~~were also recorded for ~~PTCs not yet monetized.~~the regulatory liability. 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~~increase to revenue and deferred tax expense will be recorded as the PTCs are monetized. These entries will result in no net income impact. AtFor the tax year ending December 31, ~~2017 $2.1~~2020 and 2019, $39.8 million and $67.5 million of PTCs ~~are~~were estimated to be monetized through tax ~~filings.~~filings, respectively.

Accounting for 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. 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 9,10, "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 10,11, "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.

Leases

~~(2) New Accounting Pronouncements~~PSE determines if an arrangement is, or contains, a lease at inception of the contract. If the arrangement is, or contains a lease, PSE assesses whether the lease is operating or financing for income statement and balance sheet classification. Operating leases are included in operating lease right-of-use (ROU) assets, operating lease current liabilities, and operating lease liabilities in our consolidated balance sheets. Finance leases are included in utility plant, other current liabilities, and other deferred credits in our consolidated balance sheets.

~~Revenue Recognition~~

~~In May 2014,~~ROU assets represent the ~~FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers (Topic 606)". Accounting Standards Update (ASU) 2014-09~~right to use an underlying asset for the lease term, and consist of the ~~related amendments outline a single comprehensive model for use in accounting for revenue arising from contracts with customers~~amount of the initial measurement of the lease liability, any lease payments made to the lessor at or before the commencement date, minus any lease incentives received, 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 fromany initial direct costs incurred ~~to fulfill a contract.~~

~~The standard is effective for~~by 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.

lessee. 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 2016-02~~requires 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~~represent our obligation to make lease payments arising from the lease and are measured at present value of the lease payments not yet paid, discounted using the discount rate for the lease, determined based on PSE's incremental borrowing rate, at commencement. As most of PSE's leases do not provide an implicit interest rate, PSE uses the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. For fleet, IT and wind farm leases, this rate is applied using a portfolio approach. The lease ~~measured~~terms may include options to extend or terminate the lease when it is reasonably certain that PSE will exercise that option. On the statement of income, operating leases are generally accounted for under a straight-line expense model, while finance leases, which were previously referred to as capital leases, are generally accounted for under a financing model. Consistent with the previous lease guidance, however, the standard allows rate-regulated utilities to recognize expense consistent with the timing of recovery in rates.

PSE has lease agreements with lease and non-lease components. Non-lease components comprise common area maintenance and utilities, and are accounted for separately from lease components.

Variable Interest Entities

On April 12, 2017, PSE entered into a PPA with Skookumchuck Wind Energy Project, LLC (Skookumchuck) in which Skookumchuck would develop a wind generation facility and, once completed, sell bundled energy and associated attributes, namely RECs to PSE over a term of 20 years. Skookumchuck commenced commercial operation in November 2020. PSE has no equity investment in Skookumchuck but is Skookumchuck’s only customer. Based on ~~a discounted basis; and (ii) a right-of-use asset, which~~the terms of the contract, PSE will receive all of the output of the facility, subject to curtailment rights. PSE has concluded that it is ~~an asset that represents~~not the ~~lessee’s right to use, or~~primary beneficiary of this VIE since it does not control the commercial and operating activities of the facility. Additionally, PSE does not have the obligation to absorb losses or receive benefits. Therefore, PSE will not consolidate the VIE. Purchased energy of $4.2 million was recognized in purchased electricity on the Company's consolidated statements of income and included in accounts payable on the Company's consolidated balance sheet for the year ended December 31, 2020.

(2) New Accounting Pronouncements

Recently Adopted Accounting Guidance

Credit Losses

In 2016, the FASB issued ASU 2016-13, "Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments". The amendments in the update change how entities account for credit losses on receivables and certain other assets. The guidance requires use of a ~~specified asset~~current expected loss model, which may result in earlier recognition of credit losses than under previous accounting standards. ASU 2016-13 is effective for interim and annual periods beginning on or after December 15, 2019. The measurement of expected credit losses under the ~~lease term.~~ CECL methodology is applicable to financial assets measured at amortized cost, including trade receivables. It also applies to off-balance sheet credit exposures not accounted for as insurance and net investments in leases recognized by a lessor in accordance with Topic 842.

The ~~income statement recognition is similar~~Company adopted ASC 326 using the modified retrospective method for all financial assets measured at amortized cost. Results for reporting periods beginning after January 1, 2020, are presented under ASC 326 while prior period amounts continue to ~~existing lease accounting~~be reported in accordance with previously applicable GAAP. Upon implementation as of January 1, 2020, the impact was immaterial and isthe Company did not record a transition adjustment to retained earnings.

Fair Value Measurement

In August 2018, the FASB issued ASU 2018-13, "Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement". The amendments in this update modify the disclosure requirements on fair value measurements in Topic 820, Fair Value Measurement, based on ~~lease classification. Under~~ the ~~new guidance, lessor~~concepts in the Concepts Statement, including the consideration of costs and benefits. The amendments are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. The Company adopted this update as of January 1, 2020, and it impacted Note 11, "Fair Value Measurements". As the amendment contemplates changes in disclosures only, it has no material impact on the Company's results of operations, cash flows, or consolidated balance sheets.

Goodwill

In January 2017, the FASB issued ASU 2017-04, "Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for

Goodwill Impairment." The amendment is an accounting standards update to simplify the accounting for goodwill impairment.

This accounting standard updates changes in the procedural steps in determining goodwill impairment by eliminating Step 2 from the goodwill impairment test. A goodwill impairment is ~~largely unchanged.~~measured by the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill.

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~~adopted this update in ~~recognition of right-of-use assets~~2020, and ~~liabilities that have~~it did 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.~~goodwill valuation.

~~Statement of Cash Flows~~Reference Rate Reform

In ~~August 2016,~~March 2020, the FASB issued ASU ~~2016-15,~~ 2020-04, "~~Statement of Cash Flows~~Reference Rate Reform (Topic ~~230)~~848): ~~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 applicationFacilitation of the ~~predominance principle.~~

~~This update is effective for~~Effects of Reference Rate Reform on Financial Reporting” (Issued March 2020): ASU 2020-04 provides temporary optional expedients and exceptions to the current guidance on contract modifications to ease the financial ~~statements issued for fiscal years beginning after December 15, 2017,~~reporting burdens related to the expected market transition from London Interbank Offered Rate (LIBOR) 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~~other interbank offered rates to ~~each period presented.~~alternative reference rates. The Company ~~will adopt ASU 2016-15 during the first quarter~~has term loans, credit agreements, and promissory notes that reference LIBOR. As 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,31, 2020, the Company ~~will disclose the nature~~has not utilized any of the ~~Company's restricted cash.~~expedients discussed within this ASU, however, it continues to assess other agreements to determine if LIBOR is included and if the expedients would be utilized through the allowed period of December 2022.

Retirement Benefits

In ~~March 2017,~~August 2018, the FASB issued ASU ~~2017-07,~~2018-14, "~~Compensation -~~ Compensation—Retirement ~~Benefits (Topic 715)~~Benefits—Defined Benefit Plans—General (Subtopic 715-20): ~~Improving~~Disclosure Framework—Changes to the ~~Presentation~~Disclosure Requirements for Defined Benefit Plans". This update modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans through added, removed, and clarified requirements of ~~Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost~~". relevant disclosures.

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)this update 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~~ending after December 15, ~~2017, including interim periods within those years.~~2020, for public business entities and for fiscal years ending after December 15, 2021, for all other entities. 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.~~all entities. 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 componentsadopted this standard for the year ended December 31, ~~2017, was~~2020. Refer to Note 13, "Retirement Benefits" to the consolidated financial statements.

(3) Revenue

The following table presents disaggregated revenue from contracts with customers, and other revenue by major source:


Puget Energy and Puget Sound Energy
(Dollars in Thousands)	Year Ended December 31,
Revenue from Contracts with Customers:	2020		2019		2018
Electric retail	$	2,106,122	$	2,132,522	$	2,138,008
Natural gas retail	938,061		870,457		849,898
Other	178,208		308,111		234,187
Total revenue from contracts with customers	3,222,391		3,311,090		3,222,093
Alternative revenue programs	35,006		(18,634)		(22,852)
Other non-customer revenue	69,053		108,674		147,255
Total operating revenue	$	3,326,450	$	3,401,130	$	3,346,496

Revenue at PSE is recognized when performance obligations under the terms of a ~~credit~~contract or tariff with our customers are satisfied. Performance obligations are satisfied generally through performance of ~~$18.4 million~~PSE's obligation over time or with transfer of control of electric power, natural gas, and other revenue from contracts with customers. Revenue is measured as the amount of consideration expected to be received in exchange for ~~Puget Energy~~transferring goods and ~~$4.7 million~~services.

Electric and Natural Gas Retail Revenue

Electric and natural gas retail revenue consists of tariff-based sales of electricity and natural gas to PSE's customers. For tariff contracts, PSE has elected the portfolio approach practical expedient model to apply the revenue from contracts with customers to groups of contracts. The Company determined that the portfolio approach will not differ from considering each contract or performance obligation separately. Electric and natural gas tariff contracts include the performance obligation of standing ready to perform electric and natural gas services. The electricity and natural gas the customer chooses to consume is considered an option and is recognized over time using the output method when the customer simultaneously consumes the electricity or natural gas. PSE has elected the right to invoice practical expedient for ~~PSE.~~unbilled retail revenue. The ~~non-service cost components~~obligation of standing ready to perform electric service and the consumption of electricity and natural gas at market value implies a right to consideration for performance completed to date. The Company believes that tariff prices approved by the Washington Commission represent stand-alone selling prices for the performance obligations under ASC 606. PSE collects Washington State excise taxes (which are ina component of general retail customer rates) and municipal taxes and presents the taxes on a gross basis, as PSE is the taxpayer for those excise and municipal taxes.

Other Revenue from Contracts with Customers

Other revenue from contracts with customers is primarily comprised of electric transmission, natural gas transportation, biogas, and wholesale revenue sold on an ~~income position~~intra-month basis.

Electric Transmission and ~~will be presented in~~Natural Gas Transportation

Transmission and transportation tariff contracts include the ~~other income section, upon adoption.~~performance obligation to transmit and transport electricity or natural gas. Transfer of control and recognition of revenue occurs over time as the customer simultaneously receives the transmission and transportation services. Measurement of satisfaction of this performance obligation is determined using the output method. Similar to retail revenue, the Company utilizes the right to invoice practical expedient as PSE’s right to consideration is tied directly to the value of power and natural gas transmitted and transported each month. The price is based on the tariff rates that were approved by the Washington Commission or the FERC and, therefore, corresponds directly to the value to the customer for performance completed to date.

~~Stranded Tax Effects in AOCI~~

~~In February 2018,~~Biogas

Biogas is a renewable natural gas fuel that PSE purchases and sells along with 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~~renewable green attributes derived from the ~~Tax Cuts~~renewable natural gas. Biogas contracts include the performance obligations of biogas and ~~Jobs Act (TCJA)~~renewable credit delivery upon PSE receiving produced biogas from its supplier. Transfer of control and ~~will improve~~recognition of revenue occurs at a point in time as biogas is considered a storable commodity and may not be consumed as it is delivered.

Wholesale

Wholesale revenue at PSE includes sales of electric power and non-core natural gas to other utilities or marketers. Wholesale revenue contracts include the ~~usefulness~~performance obligation of ~~information reported~~physical electric power or natural gas. There are typically no added fixed or variable amounts on top of the established rate for power or natural gas and contracts always have a stated, fixed quantity of power or natural gas delivered. Transfer of control and recognition of revenue occurs at a point in time when the customer takes physical possession of electric power or natural gas. Non-core gas consists of natural gas supply in excess of natural gas used for generation, sold to ~~financial statement users.~~third parties to mitigate the costs of firm transportation and storage capacity for its core natural gas customers. PSE reports non-core gas sold net of costs as PSE does not take control of the natural gas but is merely an agent within the market that connects a seller to a purchaser.

~~This amendment~~

Other Revenue

In accordance with ASC 606, PSE separately presents revenue not collected from contracts with customers that falls under other accounting guidance.

Transaction Price Allocated to Remaining Performance Obligations

In December 2020, PLNG entered into a contract with one customer where PLNG is ~~effective for fiscal years~~selling LNG over a 10-year delivery period beginning ~~after December 15, 2018, including interim periods within those years. Early adoption~~no later than 2024. The contract requires the customer to purchase a minimum annual quantity even if the customer does not take delivery. The price of the LNG includes a fixed charge, a fuel charge that includes both a market index and fixed margin component and other variable consideration. The fixed transaction price is ~~permitted, including adoption in any interim period for reporting periods for~~allocated to the remaining performance obligations which ~~financial statements have not yet been issued.~~ is determined by the fixed charge components multiplied by the outstanding minimum annual quantity. Based on management’s best estimate of commencement, the Company expects to recognize this revenue over the following time periods:


(Dollars in Thousands)	2024		2025	2026	2027	2028	Thereafter	Total
Remaining Performance Obligations	$	15,359	19,710	19,454	19,454	19,454	102,135	$	195,566

The Company ~~will early adopt ASU 2018-02 during~~has elected the ~~first quarter~~optional exemption in ASC 606, under which the Company does not disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. The primary sources of ~~fiscal year 2018 through~~variability are (a) fluctuating market index prices of natural gas used to determine aspects of variable pricing and (b) variation in volumes that may be delivered to the customer. Both sources of variability are expected to be resolved at or shortly before delivery of each unit of LNG or natural gas. As each unit of LNG or natural gas represents a ~~retrospective reclassification from accumulated other comprehensive income to retained earnings. The Company is still evaluating the impact of the reclassification to retained earnings.~~separate performance obligation, future volumes are wholly unsatisfied.

~~(3)~~(4) 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~~2020, and ~~2016~~2019, included the following:


Puget Sound Energy	Remaining Amortization Period		December 31,											Puget Sound Energy		Remaining Amortization Period				December 31,
(Dollars in Thousands)		2017						2016					(Dollars in Thousands)						2020					2019
Storm damage costs electric		4 to 6 years				128,508						122,709			Storm damage costs electric			5 years				$	108,491				$	121,894
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
Environmental remediation														Environmental remediation			(a)				102,647					68,486
Decoupling deferrals and interest (b)														Decoupling deferrals and interest (b)		Less than 2 years				88,504					43,509
PGA receivable														PGA receivable		2 years				87,655					132,766
PCA mechanism														PCA mechanism		N/A				82,801					41,745
Chelan PUD contract initiation	13.8 years				98,052						105,140			Chelan PUD contract initiation		10.8 years				76,787					83,875
Environmental remediation	(a)				81,550						74,557
Deferred Washington Commission AFUDC														Deferred Washington Commission AFUDC		30 years				59,763					57,553
Lower Snake River	19.4 years				70,975						74,862			Lower Snake River		16.4 years				58,442					62,899
Baker Dam licensing operating and maintenance costs	N/A				54,817						61,453			Baker Dam licensing operating and maintenance costs		(c)				54,354					56,427
Deferred Washington Commission AFUDC	10 years				50,301						51,404
Get to zero depreciation expense deferral														Get to zero depreciation expense deferral		N/A				53,236					22,148
Unamortized loss on reacquired debt	1 to 28 years				39,674						42,196			Unamortized loss on reacquired debt		1 to 47 years				37,991					40,177
Property tax tracker	Less than 2 years				36,517						41,949			Property tax tracker		Less than 2 years				24,860					22,442
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
Advanced metering infrastructure														Advanced metering infrastructure		(a)				22,652					14,845
Generation plant major maintenance, excluding Colstrip	5 to 11 years				17,216						13,178			Generation plant major maintenance, excluding Colstrip		3 to 10 years				10,494					12,744
Mint Farm ownership and operating costs	7.3 years				14,319						16,319			Mint Farm ownership and operating costs		4.3 years				8,318					10,318
Energy conservation costs														Energy conservation costs		(a)				8,009					25,272
Snoqualmie licensing operating and maintenance costs														Snoqualmie licensing operating and maintenance costs		(c)				7,435					7,442
Water heater rental property loss														Water heater rental property loss		N/A				6,973					0
Colstrip major maintenance	1.5 years				8,723						6,589			Colstrip major maintenance		(d)				4,335					2,929
Snoqualmie licensing operating and maintenance costs	N/A				7,341						8,018
Ferndale	1.8 years				7,295						11,274
Washington Commission electric vehicle														Washington Commission electric vehicle		N/A				3,641					1,430
Colstrip common property	7.4 years				4,618						5,334			Colstrip common property		3.4 years				2,472					3,188
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
White River relicensing and other costs														White River relicensing and other costs		0.0 years				0					6,399
Various other regulatory assets	(a)				17,382						17,173			Various other regulatory assets		(a)				8,247					9,044
Total PSE regulatory assets					953,116						1,113,185			Total PSE regulatory assets						$	918,107				$	847,532
Deferred income taxes^(d)	N/A				(1,012,260		)				—
Deferred income taxes (f)														Deferred income taxes (f)		N/A				(953,987)					(946,936)
Cost of removal	(b)				(389,579		)				(369,300		)	Cost of removal		(e)				(508,707)					(469,922)
Repurposed production tax credits														Repurposed production tax credits		N/A				(79,581)					(24,823)
Production tax credits														Production tax credits		(f)				(47,094)					(85,323)
Treasury grants	20 years				(205,775		)				(133,709		)	Treasury grants		3 years				(43,164)					(101,981)
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		)
Decoupling liability														Decoupling liability		Less than 2 years				(16,448)					(8,500)
Green direct														Green direct		N/A				(14,313)					(2,421)
Gain on Sale Shuffleton														Gain on Sale Shuffleton		N/A				(11,131)					(12,483)
Microsoft special contract regulatory liability														Microsoft special contract regulatory liability		N/A				0					(12,661)
Various other regulatory liabilities	(a)				(10,544		)				(13,368		)	Various other regulatory liabilities		(a)				(10,796)					(11,500)
Total PSE regulatory liabilities					(1,758,584		)				(653,296		)	Total PSE regulatory liabilities						(1,685,221)					(1,676,550)
PSE net regulatory assets (liabilities)					$	(805,468	)				$	459,889		PSE net regulatory assets (liabilities)						$	(767,114)				$	(829,018)

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.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Board of Directors

As of ~~March 1, 2018, eleven~~February 25, 2021, twelve directors constitute Puget Energy’s Board of Directors and ~~twelve~~thirteen directors currently constitute PSE’s Board of Directors, as set forth below. The directors are selected in accordance with the Amended and Restated Bylaws of each of Puget Energy and PSE, pursuant to which, the investor-owners of Puget Holdings (the indirect parent company of both Puget Energy and PSE) are entitled to select individuals to serve on the boards of Puget Energy and PSE.

Scott Armstrong, age ~~58,~~61, 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 is currently the Chief Executive Officer of Concure Oncology, a position he has held since March 2020.Prior to that Mr. Armstrong was President and CEO of Group Health Cooperative of Seattle, Washington, a health insurance and medical care provider, 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~~Kenton Bradbury, age ~~62,~~51, has been a director on the boards of both Puget Energy and PSE since ~~February 2009. Mr. Chapman~~April 17, 2019. He is currently the ~~Vice President~~Managing Director of ~~Macquarie~~OMERS Infrastructure ~~and Real Assets~~Management Inc., a ~~division of the Macquarie Group, which~~ position he has held since ~~2006.~~2015. Prior to ~~joining~~that, Mr. Bradbury served as a director of Infracapital, the ~~Macquarie Group, Mr. Chapman was~~infrastructure investment arm of M&G Investments, and served as Senior Vice President ~~– Strategy &~~of Infrastructure and Regulation at E.ON in Germany. Mr. Bradbury will not receive any director compensation from the Companies for ~~American Water from 2005 to 2006 and Regional Managing~~his service as an Owner Director ~~from 2003 to 2004. Mr. Chapman also served~~on the Boards, but will be reimbursed for out-of-pocket expenses.

Richard Dinneny, age 58, has been a director 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~~both Puget Energy and PSE ~~bylaws,~~since April 17, 2019. Mr. Dinneny is currently the Senior Portfolio Manager, Infrastructure and ~~brings~~Renewable Resources for British Columbia Investment Management Corporation (BCI) where he has responsibility for all aspects of investing in infrastructure transactions. Mr. Dinneny is a director of Vier Gas Services GmbH & Co. KG, Essen, the owner of Open Grid Europe, German’s leading natural gas transport company and Czech Grid Holdings. Mr. Dinneny was selected by BCI 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. Dinneny will not receive any director compensation from the Companies for his service ~~many years of experience in~~as an Owner Director on the ~~operational and financial management challenges specific to regulated utilities.~~Boards, but will be reimbursed for out-of-pocket expenses.

Barbara Gordon, a~~ge 59,~~age 62, has been a director on the board of PSE since November 2017. Ms. Gordon ~~currently serves~~previously served as a Vice President of the board of directors for Seattle-King County Habitat for ~~Humanity.~~Humanity, a non-profit organization (2016-2018). Prior to that time, Ms. Gordon ~~previously~~ served as Executive Vice President and Chief Customer Officer of Bellevue-based Apptio, a developer of technology business management software (2016-2017)~~. Prior to that time, Ms. Gordon served as~~, Senior Vice President and Chief Operating Officer of Isilon/EMC, a digital storage systems company (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~~Christopher Hind, age ~~53, is~~51, has been 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")~~(CPPIB), an investment management organization, which position he has held since January 2016. Prior to that, Mr. Hind served as a Managing Director, Investment Banking, at CIBC, a financial institution, 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~~Pattern Energy Group LP that develops, owns and ~~natural gas liquids~~operates utility scale wind and solar power facilities that is headquartered in ~~Peru.~~San Francisco, CA. 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~~

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Grant Hodgkins, age ~~64, is~~45, has been a director on the boards of both Puget Energy and PSE ~~which positions~~since December 31, 2020. Mr. Hodgkins is currently the Portfolio Manager, Infrastructure and Renewable Resources Group, for British Columbia Investment Management Corporation (BCI) where he has ~~held~~responsibility for all aspects of investing in infrastructure transactions. Mr. Hodgkins is a director of Corix Infrastructure Inc., a water and wastewater utility and contract energy company based in Vancouver, B.C. Mr. Hodgkins was selected by BCI 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. Hodgkins 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 67, has been a director on the boards of both Puget Energy and PSE 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), an outdoor equipment company, and Airbiquity, Inc., an automotive telematics company, as well as on the boards of various Ignition Partners portfolio companies. An independent director not affiliated with any of the Company’s investors, Mr. Hooper’s leadership skills,

experience with the challenges facing regulated businesses, and involvement with regional educational and civic organizations are some of the reasons that led to his appointment to the Puget Energy and PSE boards.

~~Karl Kuchel~~Tom King, age ~~39,~~59, has been a director on the boards of both Puget Energy and PSE since ~~January 2017,~~April 17, 2019. Mr. King is currently the Operating Executive with AEA investors, a middle market private equity firm, which position he has held since 2017. Mr. King served as Chairman and President of National Grid U.S. from 2007-2015. Prior to that, he was president of PG&E Corporation and Chairman and CEO of Pacific Gas and Electric from 2003-2007. Mr. King serves on the board of Entregado Group and Allied Power Group. Mr. King serves on the boards of Puget Energy and PSE as a representative of CPPIB’s ownership interests, pursuant to the ~~Company’s Macquarie affiliated investors and FSS Infrastructure Trust, consistent with~~terms of 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~~Mary Kipp, age 53, has been a director on the boards of both Puget Energy and PSE since ~~February 2009, as a representative~~January 3, 2020. Ms. Kipp has also been elected President and Chief Executive officer since January 3, 2020, and was President 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,~~from August 2019 to December 2019. Prior to that time Ms. Kipp served as President, ~~of Macquarie Infrastructure and Real Assets Inc., and since 2006~~ Chief Executive Officer and Director of ~~Macquarie Infrastructure Partners Inc. Mr. Leslie also serves~~El Paso Electric Company (El Paso) from May 2017 to August 2019. Prior to that she served as aChief Executive Officer and director ~~on the board~~ of ~~Cleco Power, LLC. In addition~~El Paso from December 2015 to ~~his management~~May 2017, and ~~banking skills, Mr. Leslie provides the Puget Energy and PSE boards the benefit~~President of ~~his experience with electric utilities, gas distribution systems and other aspects of the infrastructure sector.~~El Paso from 2014 to 2015.

Paul McMillan,age ~~63,~~66, 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~~provides consulting and project development services to energy and infrastructure clients, he has held the position 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,~~72, 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, a health care organization, 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,~~Her civic commitments have included Seattle Rotary, Seattle Symphony, YWCA and the Greater Seattle Chamber of Commerce. Ms. ~~McWilliams serves as a Board member of the Virginia Mason Health System and Business Health Trust. Ms. McWilliams’s~~McWilliams’ significant experience managing consumer-focused organizations with challenging regulatory and compliance regimes, her civic involvement in the community, 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~~Martijn Verwoest, age ~~43,~~44, has been a director on the boards of both Puget Energy and PSE since ~~March 1, 2016.~~April 17, 2019. Mr. ~~Middleton~~Verwoest is currently the ~~Senior Principal, Private~~Head of Energy & Utilities at Stichting Pensioenfonds Zorg en Welzijn (PGGM), and is a member of their Infrastructure ~~with CPPIB, which position~~Investment Committee since 2007. From 2001 to 2007, he ~~has held since 2009.~~worked in PGGM’s public equity department. Mr. ~~Middleton serves~~Verwoest will not receive any director compensation from the Companies for his service as an Owner Director 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.Boards, but will be reimbursed for out-of-pocket expenses.

~~Christopher Trumpy~~

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Steven Zucchet, age ~~63,~~55, has been a director on the boards of both Puget Energy and PSE since ~~January 12, 2010.~~April 17, 2019. Mr. ~~Trumpy~~Zucchet is currently the Managing Director at Ontario Municipal Employees Retirement System Infrastructure Management (OMERS). Since joining OMERS in 2003, Mr. Zucchet has led numerous transactions and had asset management responsibilities at a ~~consultant at Circle Square Solutions, which position he has held since 2013.~~number of utility and generation companies in Canada and the United States. He ~~served~~is currently on the board of Oncor and Bruce Power Inc. Mr. Zucchet will not receive any director compensation from the Companies for his service as an Owner Director on 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.Boards, but will be reimbursed for out-of-pocket expenses.

Executive Officers

The information required by this item with respect to Puget Energy and PSE is incorporated herein by reference to the material under “Executive Officers of the Registrants” in Part I of this report.

Audit Committee

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

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

There have been no material changes to the procedures by which shareholders may recommend nominees to the Boards of Directors of Puget Energy and PSE. 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~~Conduct

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,~~EST-11, 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.

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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,~~2020, 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~~2020, the Company’s Named Executive Officers and titles were:

~~Kimberly J. Harris,~~•Mary E. Kipp, President, effective August 30, 2019, and President and Chief Executive Officer (CEO);, effective January 3, 2020;

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

•Kimberly J. Harris, former Chief Executive Officer (CEO) who retired effective January 2, 2020;

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

•~~Marla D. Mellies,~~Booga K. Gilbertson, Senior Vice President and Chief ~~Administrative~~Operations Officer; ~~and~~

•~~Philip K. Bussey,~~Margaret F. Hopkins, Senior Vice President Shared Services and Chief ~~Customer~~Information Officer; and

•David E. Mills, former Senior Vice President and Chief Strategy Officer who retired effective November 9, 2020

This section also includes a discussion and analysis of the overall objectives of our compensation program and each element of compensation the Company ~~provides.~~provides to its Named Executive Officers.

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)~~Meridian Compensation Partners, LLC (Meridian). The Committee recommends to the ~~full~~ Board for approval both the salary level for our CEO, based on information provided by ~~FW Cook,~~Meridian and other relevant factors described below, 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.~~Meridian and other relevant factors.

In ~~2017,~~2020, the ~~Committee~~Company 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~~Company believes that total pay opportunity should be competitive with companies of similar size, revenue, industry and scope of ~~operations so that new executives will want to join the Company and current executives will be retained.~~operations. As described below in the discussion of Compensation Program Elements ~~(Review~~(Role of ~~Pay Element Competitiveness)~~Market Data), the Committee, with the support of Meridian, annually compares executive compensation levels to external market data from similar companies in our industry and generally targets each element of target total direct compensation ~~(the sum of base~~(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.During 2019, the Committee worked with

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Meridian to develop a compensation package for Ms. Kipp who became CEO in January 2020.The ~~Committee~~Company also recognizes the importance of providing retirement income. ~~Executives choose to work for~~As such, 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~~our retirement programs ~~provided by our comparator group~~ and provides benefits that are ~~commensurate~~competitive with ~~this group.~~

our peers.

•Place a significant portion of each executive’s target ~~total~~incentive 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~~Company maintains 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. For example, 78% of Ms. Kipp’s target 2020 compensation was considered “at risk” compensation. By establishing goals, monitoring results, and rewarding achievement of goals, the Company ~~focuses~~seeks to focus executives on actions that will improve ~~the~~ Company performance and enhance investor value, while also retaining key talent. The Committee annually evaluates and establishes the performance ~~factors~~goals 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 Philosophy

The target total compensation package is designed to provide executives with appropriate incentives that are competitive with the comparator group described below and motivate 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.

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. If Company performance exceeds target, actual compensation is expected to be above this targeted level.

Individual pay adjustments are reviewed annually relative to the 50th percentile of market pay, while also considering other factors such as the executive’s recent performance, experience level, company performance, retention and internal pay equity. Notwithstanding 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 differ from those typically found in the market.

Role of Market Data

The Company uses market data compiled by Meridian to inform its pay decisions on base salary, target annual incentives and target long-term incentive awards. Market data is obtained from both industry-specific surveys and proxy statements of public companies selected for inclusion in the Company’s custom executive compensation peer group. The market survey data were sourced from a select cut from the Willis Towers Watson 2019 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 2020 are shown below:


Custom Survey Peer Group
1.	Allete	10.	Evergy	19.	Portland General Electric
2.	Alliant Energy	11.	Eversource Energy	20.	Southwest Gas
3.	Ameren	12.	Hawaiian Electric Industries, Inc.	21.	Spire, Inc.
4.	Atmos Energy	13.	NiSource	22.	UGI
5.	Avangrid	14.	Oncur	23.	WEC Energy Group
6.	Avista	15.	OGE Energy
7	Black Hills	16.	ONE Gas
8	Cleco	17.	Pinnacle West Capital
9.	CMS Energy	18.	PNM Resources

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The market survey data were supplemented with proxy statement data for select positions in the Company’s executive compensation peer group, which was comprised of 15 companies, all but one of which overlapped with companies included in the market survey data. The 2019 median revenue of the executive compensation peers was $3.6 billion, which was comparable to PSE’s annual revenues of $3.4 billion at the time the peer group was developed. The proxy peer group was reviewed by Meridian to assess the continued relevancy of the companies.Based on Meridian’s evaluation, as well as discussion with the Committee, six companies were removed due to either non-regulated business operations or because of being acquired.Five new revenue-size appropriate regulated utilities were added to the group.


Proxy Peer Group
1.	Alliant Energy	7.	Eversource Energy	13.	Portland General Electric
2.	Ameren	8.	Idacorp	14.	Spire, Inc.
3.	Atmos Energy	9.	NiSource	15.	WEC Energy
4.	Avista	10.	ONE Gas
5.	CMS Energy	11.	Pinnacle West Capital
6.	Evergy	12.	PNM Resources

Compensation Program Elements

The Company’s executive compensation program encompasses a mix of base salary, annual and long-term incentive compensation, retirement programs, health and welfare benefits and a limited number of perquisites. ~~The Company also provides certain post-~~

~~termination and change in control benefits to executives who were employed by the Company prior to March 2009.~~ Since the Company is not publicly listed and does not grant equity awards to its executives, it relies on a mix of 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

~~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 regularly paid compensation that ~~is delivered each month and~~ provides a balance to other pay elements that are at risk. ~~As mentioned above, base~~Base salaries are reviewed annually by the Committee based on its median philosophy, internal pay equity considerations and considerations specific to an individual ~~executive considerations~~ such as an executive’s expertise, level of performance, ~~achievement,~~ experience in the role and contribution relative to others in the organization.

Base Salary Adjustments for ~~2017~~2020

The Committee reviewed the base salaries of the Named Executive Officers in early ~~2017~~2020 and recommended base salary adjustments to the Board. The Board approved the Committee’s ~~recommendation to increase executive salaries as~~salary recommendations shown in the table below. The adjustments were effective March 1, ~~2017.~~2020. Base salaries for ~~2017~~2020 generally remained at the 50th percentile of market among the comparator group. The annual salary for Ms. ~~Harris is unchanged from 2016, given that~~Kipp was adjusted to reflect her ~~current base salary was slightly higher than~~promotion to President and CEO and aligns with the market median. The salary increase percentages approved by the Board for ~~the other Named Executive Officers~~Mr. Doyle, Mr. Secrist and Mr. Mills were ~~approximately 3%,~~ similar to salary increases for other non-represented employees, ~~except~~and the salary increases for ~~Mr. Doyle who~~Ms. Gilbertson and Ms. Hopkins were adjusted to reflect their expanded roles in 2020.Ms. Harris did not receive an increase ~~and Mr. Secrist who received an additional adjustment to better align with the market levels.~~in 2020 salary.


Name	2019 Base Salary	2020 Base Salary	% Change
Mary E. Kipp	$860,000	$900,000	5%
Daniel A. Doyle	531,420	547,363	3
Steve R. Secrist	462,800	483,626	4.5
Booga K. Gilbertson	391,000	428,145	9.5
Margaret F. Hopkins	327,540	350,000	6.9
David E. Mills	392,700	404,481	3

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~~2020 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~~incent our employees to achieve both (i) desired annual ~~operating~~financial results, measured by EBITDA, ~~while also meeting the Company’s~~and (ii) pre-established goals based on a service quality commitment to customers, a reliability measure (based on non-storm outage duration—System Average Interruption Disruption Index-- or “SAIDI”) and an

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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,~~2020, the Company’s service quality commitment was measured by performance against ~~nine~~eight 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~~2020 were the same as those in ~~2016~~2019 and were as follows:

•Customer Satisfaction (3 SQIs) - Customer satisfaction with the ~~telephone access~~customer care center, ~~and~~ natural gas field services and number of Washington Commission complaints.

•Customer Service ~~(2 SQIs)~~ (1 SQI)- Calls answered “live” ~~and on-time appointments.~~within 60 seconds by the customer care center.

~~Safety and Reliability~~•Operations Services (4 SQIs)- Gas emergency response, electric emergency response, non-storm outage frequency, and ~~non-storm outage duration.~~

on-time appointments.

In ~~2017,~~2019, the Company ~~retained~~began measuring SAIDI according to a scale based on improvement compared to a five-year average, with the measure for 2020 being 155 minutes.

The employee safety performance measure inreflects the ~~annual incentive plan funding to promote its~~Company’s 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 employee safety targets for ~~2017~~2020 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 (~~D~~ays~~ A~~way from Work, days of~~ R~~estricted Work, or Job~~ T~~ransfer) not to exceed a rate of 0.52 in 2017.~~

•All employees complete ~~an online defensive driving training.~~ a safety conversation with their supervisor or manager.The target completion rate is no less than 95%.

•All employees complete an online mental health training course.The target completion rate is no less than 95%.

Annual incentive funding is decreased if a SQI is not achieved. The employee safety measure and SAIDI function similarly to the eight SQIs in determining the funding of the annual incentive plan. That is, if the safety measure or SAIDI is not achieved, annual incentive funding will be decreased by 10%, in the same way as a missed SQI.

In ~~2017,~~2020, 100% funding for the annual incentive plan required (i) achievement of 10 out of 10 customer service and safety measures (all ~~nine~~eight SQIs, SAIDI and achievement of the safety measure) and (ii) target EBITDA performance. ~~The safety measure and eight out of nine SQI~~All customer service measures were met for ~~2017. For~~2020, but the ~~one SQI~~SAIDI measure ~~below the WUTC~~was not met, and EBITDA finished at 90.1% of target, ~~System Average Interruption Duration Index (SAIDI)~~so funding was less than 100%, 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.~~described further below.

~~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~~2020 Corporate Goals

In ~~2017,~~2020, the Company continued using the Integrated Strategic Plan (ISP) to summarize for employees, including the Named Executive Officers, the direction and overall goals of the Company. The plan has five objectives which capture our ~~2017~~2020 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~~safety objective is our foundation: If ~~Nobody Gets Hurt Today,~~nobody gets hurt today, we will feel safe and secure and be able to perform at our best.

•People - When we’re ~~Safe,~~safe, we can achieve our ~~People Objective~~people objective of being a ~~Great Place~~great place to ~~Work,~~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~~achieve our ~~Process~~process and ~~Tools Objective~~tools objective where results start with achieving ~~Operational Excellence,~~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~~customer objective of delivering greater value and being our ~~Customer’s Energy Partner~~customer’s energy partner of ~~Choice~~choice in a competitive marketplace.

150

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

~~2017~~2020 Annual Incentive Plan Results

~~Achievement~~For 2020, achievement of the corporate goals ~~for 2017~~under the annual incentive plan was at ~~102.6%~~90.1% of target for ~~EBITDA, and deemed fully met for SQI and safety achievement.~~EBITDA. PSE EBITDA was ~~$1,318.3~~$1,291.1 million, and SQI, SAIDI and safety achievement was 109 out of 10, leading to a funding level for ~~2017~~2020 of ~~113.2%~~45.6% for the annual incentive ~~plan.~~plan for the named executive officers.

Funding levels for 2020 at maximum, target, and threshold are shown in the table below:


Annual Incentive Performance Payout Scale and Actual Performance
Performance Measure (Dollars in Millions)	2020 EBITDA			SQI, SAIDI& Safety*	Funding Level
Maximum		$	1,933.2	10/10	200%
Target		1,432.0		10/10	100
Threshold		1,288.8		6/10	30
2020 Actual Performance		$	1,291.1	9/10	45.6%

_______________

* Combined SQI, SAIDI & Safety results of 6/10 or better and minimum EBITDA of $1,288.8 million are required for any annual incentive pay out funding

SQI, SAIDI and Safety results below 10/10 reduce funding (e.g., 9/10=90%, 8/10=80%, 7/10=70%)

For ~~2017,~~2020, individual target incentive levels for the annual incentive plan varied by executive officer as a percentage of ~~2017~~2020 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 the Named Executive Officers ~~remained~~were unchanged

from ~~2016~~2019 levels, except for ~~Mr. Doyle's~~Ms. Kipp whose target ~~which~~annual incentive opportunity was increased to ~~55%~~100% of base ~~salary.~~salary as part of her promotion to President and CEO. Ms. Harris, who retired in January 2020 was not eligible for a 2020 annual incentive award. No bonus is earned unless at least threshold EBITDA and SQI, SAIDI and safety goals are achieved. The achievement of threshold performance results in a 30% of target bonus payout. The maximum incentive payable for exceptional performance in this plan is ~~twice the~~two times each Named Executive Officer's 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.~~2020. 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~~2020 achievement of the corporate goals. The Board approved the incentive amounts shown below, which will be paid in March ~~2018:~~2021:


Name	Target Incentive (% of Base Salary)	2020 Actual Incentive Paid		2020 Actual Incentive (% of Base Salary)
Mary E. Kipp	100%	$	492,480	54.7%
Daniel A. Doyle	65	194,686		36
Steve R. Secrist	65	157,681		33
Booga K. Gilbertson	65	145,938		34
Margaret F. Hopkins	62.5*	104,810		30
David E. Mills	65**	77,139		19

*Ms. Hopkins 2020 Annual Incentive Target is pro-rated for 2 months as VP and 10 months as SVP.

**Mr. Mills 2020 Annual Incentive Target was 65%, but based on plan rules as a retiree, his award was pro-rated for time worked in 2020.

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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 bealign the interests of executives with those of our investors, provide competitive ~~with market practices,~~pay opportunities, support a customer-focused utility, reward long-term performance and promote retention. ~~Long-term~~Starting with the 2020-2022 grant cycle, long term incentive plan (LTI Plan) ~~awards~~grants are denominated ~~in units~~ and ~~are settled~~paid in cash, if at least threshold performance measures are met. ~~Performance~~Prior to 2020, LTI Plan awards were denominated in units and settled in cash if at least threshold performance measures are met.

For the 2020-2022 grant cycle, an EBITDA threshold goal was added to the Return on Equity (ROE) metric. Under this goal, EBITDA during the three-year performance cycle must meet or exceed 90% of target EBITDA for a payment to occur.Assuming the EBITDA threshold is met, the 2020-2022 grant cycle is funded based on ~~two financial goals, total return (Total Return) and~~the three-year average ROE ~~each measured over a three-year performance cycle. Total return~~metric. ROE reflects the ~~change in the value~~income earned on our equity investment.The 2020-2022 LTI payment ultimately paid may range from 0% to 200% 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.~~target, depending on performance.

The Committee recommends for Board approval a targeted LTI grant value for each executive, which is expressed as a percentage of base salary.The targeted LTI grant value is determined by evaluating LTI 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 Company generally does not consider previously granted awards or the level of accrued value from prior or other programs when making new LTI Plan grants.

The 2018-2020 and 2019-2021 LTI plan cycles were denominated in units, determined by dividing the target LTI grant value ~~is then converted into a target number of units, allocated equally among the two financial goals, based on~~by the unit value on the grant date.The initial per-unit value iswas measured at the Puget Holdings level and issubsequent unit values are calculated annually by an independent auditing ~~firm. The~~firm or based on market transactions.For 2018-2020 and 2019-2021 LTIP grants, 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.The 2018-2020 grant cycle was based on performance against two financial goals—total return (Total Return) and ROE—each weighted equally and 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.The 2019-2021 grant cycle is based on achievement of the ROE metric only.

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~~2020-2022 Long-Term Incentive Plan Target Awards ~~and Performance Goals~~

Consistent with prior years, target LTI Plan awards for the ~~2017-2019~~2020-2022 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~~Ms. Kipp’starget LTI Plan ~~award amounts for the 2017-2019 performance cycle were~~grant was set at 265% of base salary ~~for Ms. Harris~~as part of her promotion to President and ~~95% for Mr. Doyle, Mr. Secrist, Ms. Mellies and Mr. Bussey, which~~CEO.These percentages were unchanged from amounts established for the ~~2016-2018~~2019-2021 performance cycle, ~~except for~~with the exception of 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~~Kipp.Target LTI Plan ~~units granted to a Named Executive Officer~~award amounts for the ~~2017-2019~~2020-2022 performance cycle ~~is equal to~~are shown in the ~~applicable percentage of salary (converted to dollars) divided by the per unit value at the beginning of the performance cycle, which~~following table.Ms. Harris was ~~$52.37.~~ not eligible for a 2020-2022 LTI Plan grant.


Name						Target Long Term Incentive (% of Base Salary)
Mary E. Kipp						265%
Daniel A. Doyle						95
Steve R. Secrist						95
Booga K. Gilbertson						95
Margaret F. Hopkins						95
David E. Mills						95

Details of the ~~number of units granted~~target grants and expected values at target, threshold and maximum performance levels can be found in the ~~“2017~~“2020 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.

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:

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~~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~~		—

~~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~~		—



~~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~~		—

~~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~~		—



~~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~~		—

Long-Term Incentive Plan Performance ~~2015-2017~~2018-2020 Performance Cycle Results and Payouts

The ~~2015-2017~~2018-2020 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%~~10.4%, 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%~~105.9% of target. The ROE component funded at 133.6% of target ~~for funding at 112.8%~~units.

Name

Target Incentive

(% of Base Salary)1

Total Return Component

Units Granted/Paid

ROE Component

Units Granted/Paid

2018-2020

Actual LTIP Paid2

Mary E. Kipp

165%

8,667.24/17,334.5

8,667.24/11,579.4

2,354,749

Daniel A. Doyle

4,084.5/8,169

4,084.5/5,456.9

1,109,693

Steve R. Secrist

3,488.5/6,977

3,488.5/4,660.6

947,769

Booga K. Gilbertson

2,665.5/5,331

2,665.5/3,561.1

724,173

Margaret F. Hopkins

1,312/2,624

1,312/1,752.8

356,449

______________

1 Target LTI Plan incentive is a percentage of 2018 base salary when the grants were made in 2018 with a unit price of $60.59, except that Ms. Kipp’s target is a percentage of 2019 base salary equal to 75% of target ~~units.~~LTI % of 220% with a per unit price of $81.86.

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~~2 2018-2020 actual LTI Plan amount payable is equal to the unit price of $81.44 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:~~ROE component units.

3 In connection with Ms. Kipp’s commencement of employment in 2019, Ms. Kipp was eligible to participate in the 2018-2020 performance cycle at a target amount that reflected her reduced participation during that performance cycle but was intended to incentivize her performance following commencement of employment.

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%

In connection with Ms. Harris’ retirement, she was eligible to receive pro-rated portion of her LTI grants for the 2018-2020 and 2019-2021 performance cycles in accordance with the LTI Plan in the amounts of $3,871,077 and $1,105,636, respectively, paid in March 2020. In connection with Mr. Mills’s retirement, he was eligible to receive a pro-rated portion of his LTI grant for the 2018-2020 and 2019-2021 performance cycles at retirement in the amounts of $663,826 and $236,281, respectively, paid in March 2021.

Retirement Plans ~~- SERP~~–– Executive Retirement Plans and Retirement Plan

The Company maintains ~~the SERP~~executive retirement plans 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,~~executive retirement plans, these executives would receive lower percentages of replacement income during retirement than other employees. All the Named Executive Officers participate in executive retirement plans during 2020—Mr. Doyle, Mr. Secrist, Ms. Gilbertson and Ms. Hopkins participate in the ~~SERP.~~SERP and Ms. Kipp participates in the Officer Restoration Benefit, as part of the Deferred Compensation Plan for Key Employees. Ms. Harris and Mr. Mills participated in the SERP until their departures in 2020. Additional information regarding the SERP, Officer Restoration Benefit and the Retirement Plan is shown in the ~~“2017~~“2020 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~~“2020 Nonqualified Deferred Compensation” table.

153

Post-Termination Benefits

~~Effective March 30, 2009, the Company entered into~~Prior to Ms. Harris’ retirement, she was a party to an 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 provideAgreement that provided 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~~No other 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~~officers have ~~an employment~~similar agreements. The agreement with ~~the Company.~~Ms. Harris terminated upon her retirement on January 2, 2020.

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~~has determined not to extent such arrangements to current ~~arrangements generally provide benefits that are similar to those of the comparator group for longer tenured executives, but is not extending them to~~and 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.~~2020.

Other Compensation

~~In addition to base salary and annual and long-term incentive award opportunities, the~~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~~in order to attract qualified candidates from other areas of the country. In connection with Ms. Kipp’s commencement of employment, she was eligible to receive a bonus of $1,500,000 in the event the previously announced acquisition of El Paso Electric by the Infrastructure Investments Fund, an investment vehicle advised by J.P. Morgan Incentive Management Inc. was completed in 2020. This acquisition was completed and Ms. Kipp was paid $1,500,000 during 2020.

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 and 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.~~2020. 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 Tax and 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~~As a result of changes in federal tax law ~~enacted~~effective in 2018, the Company ~~will become~~is now subject to IRS section 162(m) ~~limitations on company deductions for~~. Section 162(m) limits the tax deductibility of compensation paid to certain executive ~~pay. Based on current understanding of~~officers, including the Named Executive Officers, to $1 million per year. Notwithstanding the new tax law, the Company does not expect to make changes in its executive compensation program ~~designs.~~designs and retains the discretion to pay compensation that may not qualify for a tax deduction.

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

154

to have a material

adverse effect on the Company and also provide appropriate incentive opportunities for executives to achieve Company goals that support the interests of our investors and customers.

Compensation and Leadership Development Committee Report

The Board delegates responsibility to the Compensation and Leadership Development Committee to establish and oversee the Company’s executive compensation program. Each member of the Committee served during all of ~~2017, except as noted below.~~2020.

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~~2020, for filing with the SEC.

Compensation and Leadership

Development Committee of

Puget Energy, Inc.

Puget Sound Energy, Inc.

~~Christopher Trumpy, Chair~~Steven Zucchet, chair,

Scott Armstrong ~~(served beginning March 1, 2017)~~

~~Christopher Leslie~~

~~Etienne Middleton~~Barbara Gordon

Mary McWilliams

Christopher Trumpy

Martijn Verwoest

155

Summary Compensation Table

The following information is provided for the year ended December 31, ~~2017~~2020, (and for prior years where applicable) with respect to the Named Executive Officers during ~~2017.~~2020. The positions listed below are at Puget Energy and PSE, except that Ms. ~~Mellies~~Gilbertson and ~~Mr. Bussey~~Ms. Hopkins are executives of PSE only. Positions listed are those held by the Named Executive Officers as of December 31, ~~2017.~~2020. 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


Name and Principal Position	Year	Salary		Bonus1		Stock Awards		Option Awards		Non-Equity Incentive Plan Compensation2		Change in Pension Value and Nonqualified Deferred Compensation3		All Other Compensation4		Total
Mary E. Kipp,	2020	$	891,667	$	—	$	—	$	—	$	2,847,229	$	—	$	1,557,670	$	5,296,566
President and Chief Executive Officer	2019	252,540		—		—		—		1,876,398		—		813,893		2,942,831
Daniel A. Doyle	2020	544,041		—		—		—		1,304,379		824,333		60,602		2,733,355
Senior Vice President	2019	521,399		—		—		—		1,608,655		964,614		63,555		3,158,223
Chief Financial Officer	2018	519,039		—		—		—		1,718,288		489,180		60,657		2,787,164
Kimberly J. Harris	2020	50,725		—		—		—		—		119,996		4,998,260		5,158,981
Former Chief Executive	2019	989,799		—		—		—		7,382,111		3,373,594		28,864		11,774,368
Officer	2018	939,823		45,220		—		—		6,593,310		445,343		20,888		8,044,584
Steve R. Secrist	2020	479,287		—		—		—		1,105,450		658,689		51,325		2,294,751
Senior Vice President	2019	459,165		—		—		—		1,291,097		786,634		53,517		2,590,413
General Counsel, Chief Ethics & Compliance Officer	2018	436,600		—		—		—		1,335,367		273,059		46,850		2,091,876
Booga K. Gilbertson
Senior Vice President, Chief Operations Officer	2020	420,406		—		—		—		870,111		794,245		43,169		2,127,931
Margaret F. Hopkins
Senior Vice President Shared Services and CIO	2020	345,328		—		—		—		461,260		499,683		39,064		1,345,334
David E. Mills
Former Senior Vice President, Chief Strategy Officer	2020	361,900		—		—		—		77,139		217,775		946,102		1,602,916

_______________

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.

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.

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.~~

1.Reflects individual performance above target as described in the "Compensation Discussion and Analysis," section titled"2020 Annual Incentive Plan Results".

2.For 2020, reflects annual cash incentive compensation paid under the 2020 Goals and Incentive Plan and cash incentive compensation paid under the LTI Plan for the 2018-2020 performance cycle. Cash incentive amounts were paid in early 2021 or deferred at the executive's election. The 2020 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 2021.

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 that the executive may not currently be entitled to receive because such amounts are not vested. In 2020, updated interest rates relative to those used for 2019 have generally resulted in comparable increases in value as in prior years. Information regarding these pension plans is set forth in further detail under “2020 Pension Benefits.” The change in pension value amounts for 2020 are: Ms. Kipp, $0; Mr. Doyle, $824,333; Ms. Harris, $119,692; Mr. Secrist, $658,689; Ms. Gilbertson, $790,449; Ms. Hopkins, $499,683; and Mr. Mills, $217,723. Also included in this column are the portions of Deferred Compensation Plan earnings that are considered above market. These amounts for 2020 are: Ms. Kipp, $0, Mr. Doyle, $0; Ms. Harris, $304; Mr. Secrist, $0; Ms. Gilbertson, $3,796; Ms. Hopkins, $0; and Mr. Mills, $52. See the “2020 Nonqualified Deferred Compensation” table for all Deferred Compensation Plan earnings.

4.All Other Compensation for 2020 is shown in detail in the table below.

5.Ms. Harris was promoted to President and CEO from President on March 1, 2011, became CEO effective August 31, 2019, and retired on January 2, 2020.

6.Ms. Kipp joined PSE and Puget Energy as President on August 31, 2019, and became President and CEO on January 3, 2020, with the retirement of Ms. Harris.

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

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

9.Ms. Gilbertson has worked at PSE since 1991.

10.Ms. Hopkins has worked at PSE since 2009.

11.Mr. Mills joined PSE in 2002 and retired as Senior Vice President, Chief Strategy Officer on November 9, 2020.

156

Detail of All Other Compensation


Name	Perquisites and Other Personal Benefits¹		Registrant Contributions to Defined Contribution and Deferred Compensation Plans²		Other³		Name	Perquisites and Other Personal Benefits1			Registrant Contributions to Defined Contribution and Deferred Compensation Plans2			Other3
Mary E. Kipp							Mary E. Kipp		$	1,440		$	49,867		$	1,506,363
Daniel A. Doyle							Daniel A. Doyle		2,500			50,779			7,323
Kimberly J. Harris	$	—	$	14,650	$	5,688	Kimberly J. Harris		5,000			5,843			4,977,417
Daniel A. Doyle	2,500		48,516		5,785
Steve R. Secrist	1,300		40,416		4,317		Steve R. Secrist		980			44,914			5,431
Marla D. Mellies	1,263		29,981		3,287
Philip K. Bussey	1,440		18,850		6,699
Booga K. Gilbertson							Booga K. Gilbertson		712			37,291			5,166
Margaret F. Hopkins							Margaret F. Hopkins		3,500			28,301			7,263
David E. Mills							David E. Mills		2,500			33,672			909,930

_______________


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.

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.~~

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. Kipp and Ms. Harris, and $2,500 for the other Named Executive Officers.

~~2017~~2.Includes Company contributions during 2020 to PSE’s Investment Plan (a tax qualified 401(k) plan) and the Deferred Compensation Plan. Company 401(k) contributions are as follows: Ms. Kipp, $20,347; Mr. Doyle, $19,900; Ms. Harris $5,843,Mr. Secrist $19,990; Ms. Gilbertson $19,565, Ms. Hopkins $16,200 and Mr. Mills, $19,900. Company contributions to the Deferred Compensation Plan are as follows: Ms. Kipp, $29,520; Mr. Doyle, $30,879; Ms. Harris, $0; Mr. Secrist, $25,014; Ms. Gilbertson, $17,725; Ms. Hopkins, $12,101; and Mr. Mills, $13,772.

3.Reflects the value of imputed income for life insurance and Company paid premiums on supplemental disability insurance for all Named Executive Officers. For Ms. Kipp also includes a signing bonus of $1,500,000 as described in the Compensation Discussion and Analysis, “Other Compensation". For Ms. Harris and Mr. Mills also includes pro-rated payment of LTI grants at retirement, per the LTI Plan terms: Ms. Harris 2018-2020 $3,871,077 and 2019-2021 $1,105,636; Mr. Mills 2018-2020 $663,826 and 2019-2021 $236,281.

157

2020 Grants of Plan-Based Awards

The following table presents information regarding ~~2017~~2020 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									Estimated Future Payouts under Non-Equity Incentive Plan Awards
Name	Grant Date	Number Of Units Granted	Threshold		Target		Maximum		Name	Grant Date	Grant Target Value		Threshold		Target		Maximum
Kimberly J. Harris
Mary E. Kipp									Mary E. Kipp
Annual Incentive¹	1/1/2017		$	270,000	$	900,000	$	1,800,000	Annual Incentive1	1/1/2020			$	270,000	$	900,000	$	1,800,000
LTI Plan 2017-2019²	3/2/2017	45,451	590,120		3,156,902		6,614,375
LTIP Plan 2020-20222									LTIP Plan 2020-20222	2/21/2020	$	2,385,000	1,192,500		2,385,000		4,770,000
Daniel A. Doyle									Daniel A. Doyle
Annual Incentive¹	1/1/2017		$	84,380	$	281,268	$	562,536	Annual Incentive1	1/1/2020			$	106,736	$	355,786	$	711,572
LTI Plan 2017-2019²	3/2/2017	9,277	120,211		643,082		1,347,391
LTIP Plan 2020-20222									LTIP Plan 2020-20222	2/21/2020	519,995		259,997		519,995		1,039,990
Steve R. Secrist									Steve R. Secrist
Annual Incentive¹	1/1/2017		$	54,521	$	181,737	$	363,475	Annual Incentive1	1/1/2020			$	94,307	$	314,357	$	628,714
LTI Plan 2017-2019²	3/2/2017	7,326	94,930		507,838		1,064,028
Marla D. Mellies
LTIP Plan 2020-20222									LTIP Plan 2020-20222	2/21/2020	459,445		$229,722		459,445		918,889
Booga K. Gilbertson									Booga K. Gilbertson
Annual Incentive									Annual Incentive	1/1/2020			$	83,488	$	278,294	$	556,589
LTI Plan 2020-2022									LTI Plan 2020-2022	2/21/2020	406,738		203,369		406,738		813,476
Margaret F. Hopkins									Margaret F. Hopkins
Annual Incentive									Annual Incentive	1/1/2020			$	68,250	$	227,500	$	455,000
LTI Plan 2020-2022									LTI Plan 2020-2022	2/21/2020	332,500		166,250		332,500		665,000
David E. Mills									David E. Mills
Annual Incentive¹	1/1/2017		$	42,933	$	143,109	$	286,217	Annual Incentive1	1/1/2020			$	78,874	$	262,913	$	525,825
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
LTIP Plan 2020-20222									LTIP Plan 2020-20222	2/21/2020	384,257		192,128		384,257		768,514

_______________

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.

1.As described in the “Compensation Discussion and Analysis,” the 2020 Goals and Incentive Plan had dual funding triggers in 2020 of $1,288.0 million EBITDA and SQI performance of 6/10. Payment would be $0 if either trigger is not met. The threshold estimate assumes $1,288.0 million EBITDA and SQI/Safety measure performance at 6/10. The target estimate assumes $1,432 million EBITDA and SQI/Safety measure performance at 10/10. The maximum estimate assumes $1,933.2 million EBITDA or higher and SQI/Safety measure performance at 10/10.

2.As described in the “Compensation Discussion and Analysis,” LTI Plan grants for the 2020-2022 performance cycle were allocated 100% to a ROE component subject to achievement of an EBITDA threshold goal. Payments are calculated based on the average three-year performance of ROE. As described in the “Compensation Discussion and Analysis,” LTI Plan grants for the 2020-2022 performance cycle were allocated 100% to a ROE component subject to achievement of an EBITDA threshold goal. Payments are calculated based on the average three-year performance of ROE.

~~2017~~

158

2020 Pension Benefits

The Company and its affiliates maintain two pension plans: the Retirement Plan and the ~~SERP.~~SERP, in addition to an Officer Restoration Benefit as part of the Deferred Compensation Plan. 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.~~plans, except Ms. Kipp, who participates just in the Officer Restoration Benefit (which is reported separately below.)


Name	Plan Name	Number of Years Credited Service	Present Value of Accumulated Benefit ^1,2		Payments During Last Fiscal Year		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	$	—
Mary E. Kipp3							Mary E. Kipp3	Retirement Contribution	1.3		$	—		$	—
	SERP	18.7	9,449,499		—			Restoration Benefit	1.3		—		—
Daniel A. Doyle	Retirement Plan	6.1	183,734		—		Daniel A. Doyle	Retirement Plan	9.1		334,856		—
	SERP	6.1	1,766,273		—			SERP	9.1		3,893,278		—
Kimberly J. Harris							Kimberly J. Harris	Retirement Plan	20.7		708,629		—
								SERP	20.7		—		13,144,354
Steve R. Secrist	Retirement Plan	28.6	547,704		—		Steve R. Secrist	Retirement Plan	31.6		791,915		—
	SERP	28.6	2,700,486		—			SERP	31.6		4,174,657		—
Marla D. Mellies	Retirement Plan	12.2	340,322		—
Booga K. Gilbertson							Booga K. Gilbertson	Retirement Plan	34.8		808,786		—
	SERP	12.2	1,940,490		—			SERP	34.8		3,084,187			—
Philip K. Bussey	Retirement Plan	11.3	375,495		—
Margaret F. Hopkins							Margaret F. Hopkins	Retirement Plan	11.3		345,361			—
	SERP	11.3	2,038,638		—			SERP	11.3		2,018,741			—
David E. Mills							David E. Mills	Retirement Plan	18.5		667,656			—
								SERP	18.5		—			3,504,856

_______________

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, 2020, 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 2.70%, and the post-retirement mortality assumption is based on the 2021 417(e) unisex mortality table. Annuity benefits are converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 2.22%, 3.38%, and 3.92% (the 24-month average of the underlying rates as of September 2019), except that payments assumed to occur during 2020 use segment rates in effect for 2020 (this includes Ms. Harris' and Mr. Doyle's SERP present values). These assumptions are consistent with the ones used for the Retirement Plan and the SERP for financial reporting purposes for 2020. 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, 2019, for the benefits earned as of that date using the assumptions used for financial reporting purposes for 2019. These assumptions included assumed cash balance interest credits of 4.0%, a discount assumption of 3.35% and post-retirement mortality assumption based on the 2020 417(e) unisex mortality table. Annuity benefits were converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 2.79%, 3.92%, and 4.38% (the 24-month average of the underlying rates as of September 2018). Other assumptions used to determine the value as of December 31, 2019, were the same as those used for December 31, 2020.

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, 2020. Each SERP-eligible Named Executive Officer was vested in his or her SERP benefits as of December 31, 2020.

159

Name

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.Estimated Lump Sum

Daniel A. Doyle			$	3,893,278
Steve R. Secrist			4,532,067
Booga K. Gilbertson			3,453,942
Margaret F. Hopkins	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.	2,379,204

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
_______________________

3. Ms. Kipp does not have a SERP benefit as that plan was closed prior to her joining PSE. Ms. Kipp does not have a Retirement Plan benefit, as upon hire, she elected to have her 4% company retirement contribution made to her 401(k) account, which based on service through 12/31/2020 had a value of $19,954. Ms. Kipp also participates in an Officer Restoration Benefit Plan as described below, with vesting after three years of service. The value of Ms. Kipp’s Officer Restoration Benefit which based on service through 12/31/2020 had a value of $31,903.

4.As a result of retirement on January 2, 2020, Ms. Harris received a SERP lump sum in the amount of $13,144,354, calculated per the plan and paid according to Ms. Harris’ payment election. Additionally, as a result of retirement on November 9, 2020, Mr. Mills received a SERP lump sum in the amount of $3,504,856, calculated per the plan and paid according to Mr. Mills’ payment election.

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,~~2020, the limit was ~~$270,000.~~$285,000. For ~~2018,~~2021, the limit is ~~$275,000.~~$290,000. 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~~2020 and ~~2018,~~2021, 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,~~2020, all the Named Executive Officers, except Ms. Kipp, 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

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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. The Company closed the SERP plan to new participants as of August 1, 2019, but existing officer participants continue to accrue benefits in the plan. All the Named Executive Officers hired prior to 2019 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.

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~~“2020 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

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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.

Officer Restoration Benefit

The Officer Restoration Benefit provides a benefit to participating Officers that supplements the retirement income provided to the executives. Executives participating in the SERP are not eligible. Ms. Kipp participates in the benefit and those Company contributions under PSE’s applicable tax-qualified plan that would otherwise have been earned, if not for IRS limitations, are credited by the Company to an account within the Deferred Compensation Plan.

~~2017~~

2020 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~~2020 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		Name	Executive Contributions in 20201			Registrant Contributions in 20202			Aggregate Earnings in 20203			Aggregate Withdrawals/ Distributions			Aggregate Balance at December 31, 20204
Mary E. Kipp											Mary E. Kipp		$	213,089		$	29,520		$	32,069		$	—		$	340,048
Daniel A. Doyle											Daniel A. Doyle		28,479			30,879			135,753						1,413,071
Kimberly J. Harris	$	—	$	—	$	12,727	$	—	$	324,915	Kimberly J. Harris		—			—			704			352,631			—
Daniel A. Doyle	27,866		29,666		84,406		—		940,709
Steve R. Secrist	32,355		21,566		5,222		—		98,893		Steve R. Secrist		36,651			25,014			22,743			—			324,885
Marla D. Mellies	10,706		11,131		16,833		—		168,591
Philip K. Bussey	—		—		—		—		—
Booga K. Gilbertson											Booga K. Gilbertson		54,372			17,725			76,572			—			905,830
Margaret F. Hopkins											Margaret F. Hopkins		144,760			12,101			73,673						700,115
David E. Mills											David E. Mills		13,547			13,772			15,624			225,133			—

_______________

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.~~

1.The amount in this column reflects elective deferrals by the executive of salary, annual incentive compensation or LTI Plan awards paid in 2020. Deferred salary amounts are: Ms. Kipp, $213,089; Mr. Doyle, $28,479; Ms. Harris, $0; Mr. Secrist, $36,651; Ms. Gilbertson, $54,372; Ms. Hopkins, $36,018; and Mr. Mills, $13,547. Deferred incentive compensation and LTI Plan award amounts are $0 for all Named Executives, except for Ms. Hopkins who deferred $24,238 in incentive compensation and $84,505 in LTIPlan awards. The amounts are also included in the applicable column of the Summary Compensation Table for 2020.

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 —
—
—
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 2020.

3.The amount in this column for each executive reflects the change in value of investment tracking funds. Amounts of zero indicate no change in value or a decrease in value. 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 2020.

4.Of the amounts in this column, the amounts in the table below have also been reported in the Summary Compensation Table for 2020, 2019, and 2018.


Name	Reported for 2020			Reported for 2019			Reported for 2018
Mary E. Kipp		$	242,609		$	64,500		$	—
Daniel A. Doyle		59,358			66,403			61,671
Kimberly J. Harris		304			2,516			2,154
Steve R. Secrist		61,665			67,034			55,044
Booga K. Gilbertson		75,893			—			—
Margaret F. Hopkins		156,861			—			—
David E. Mills		27,371			—			—

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

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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~~2020 calendar year returns of these tracking funds were:



Vanguard Total Bond Market Index	~~3.57~~	%7.74%
Vanguard 500 Index	~~21.67~~	18.37
Vanguard Money Market Index	~~0.81~~	0.45
Interest Crediting Fund (pre-2012 deferrals)	~~4.14~~	3.15

The Named Executive Officers may change how deferrals are allocated to the tracking funds at any time. Changes generally become effective as of the first trading day of the following calendar quarter.

The Named Executive Officers generally may choose how and when to receive payments under the Deferred Compensation Plan. There are three types of in-service withdrawals. First, an executive may choose an interim payment of deferred amounts by designating a plan year for payment at the time of his or her deferral election. The interim payment is made in a lump sum within 60 days after the last day of the designated plan year, which must be at least two years following the plan year of the deferral. Second, an in-service withdrawal may also be made to an executive upon a qualifying hardship event and demonstrated need. Third, only with respect to amounts deferred and vested prior to 2005, the executive may elect an in-service withdrawal for any reason by paying a 10% penalty. Payments upon termination of employment depend on whether the executive is then eligible for retirement. If the executive's termination occurs prior to his or her retirement date (generally the earlier of attaining age 62 or age 55 with five years of credited service), the executive will receive a lump sum payment of his or her account balance. If the executive’s termination occurs after his or her retirement date, the executive may choose to receive payments in a lump sum or via one of several installment options (fixed amount, specified amount, annual or monthly installments, of up to 20 years).

Potential Payments Upon Termination or Change in Control

The Estimated Potential Incremental Payments Upon Termination or Change in Control table below reflects the estimated amount of incremental compensation payable to each of the Named Executive Officers in the event of (i) 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,

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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)~~Executive). The Employment ~~Agreements provide for an employment period~~Agreement terminated with Ms. Harris’ retirement as 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.January 2, 2020.

~~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.

~~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~~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.~~2020. 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. Ms. Harris and Mr. Mills were not active as of December 31, 2020 and are not included in the table. The pro-rated LTI Plan amounts payable to them in connection with their retirements pursuant to the terms of the LTI Plan are disclosed in the “Details of All Other Compensation” section of the Summary Compensation Table, which amount for Ms. Harris was $4,976,713 and for Mr. Mills, was $900,107.


	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
Mary E. Kipp	$	—	$	—	$	—	$	—	$	—
Long Term Incentive Plan	3,580,064		3,580,064		3,580,064		3,580,064		3,580,064
Supplemental Life Insurance	—		—		—		—		3,000,000
Total Estimated Incremental Value	$	3,580,064	$	3,580,064	$	3,580,064	$	3,580,064	$	6,580,064
Daniel A. Doyle	$	—	$	—	$	—	$	—	$	—
Long Term Incentive Plan	1,438,079		1,438,079		—		1,438,079		1,438,079
Supplemental Life Insurance	—		—		—		—		1,258,935
Total Estimated Incremental Value	$	1,438,079	$	1,438,079	$	—	$	1,438,079	$	2,697,014
Steve R. Secrist	$	—	$	—	$	—	$	—	$	—
Long Term Incentive Plan	1,233,713		1,233,713		—		1,233,713		1,233,713
Supplemental Life Insurance	—		—		—		—		1,112,340
Total Estimated Incremental Value	$	1,233,713	$	1,233,713	$	—	$	1,233,713	$	2,346,053
Booga K. Gilbertson	$	—	$	—	$	—	$	—	$	—
Long Term Incentive Plan	965,540		965,540		—		965,540		965,540
Supplemental Life Insurance	—		—		—		—		984,734
Total Estimated Incremental Value	$	965,540	$	965,540	$	—	$	965,540	$	1,950,274
Margaret F. Hopkins	$	—	$	—	$	—	$	—	$	—
Long Term Incentive Plan	462,990		462,990		—		462,990		462,990
Supplemental Life Insurance	—		—		—		—		805,000
Total Estimated Incremental Value	$	462,990	$	462,990	$	—	$	462,990	$	1,267,990

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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.

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,~~2020, our last completed fiscal year:

•The annual total compensation of our CEO, actively employed as of December 31, 2020, and reported in the ~~2017~~2020 Summary Compensation Table, was ~~$7,788,167.~~$5,296,566.

•The median of the annual total compensation of all our employees (excluding our CEO) was ~~$117,999~~$140,300.

As a result, for ~~2017~~2020 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:~~38:1.

We identified our median employee by examining the total cash compensation we paid during ~~2017~~2020 to all individuals, excluding our CEO, who were employed by us on December 31, ~~2017,~~2020, which totaled approximately ~~3,160~~3,174 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,~~2020, we calculated annual total compensation for such employee for ~~2017~~2020 using the same methodology we use for our named executive officers as set forth in the ~~2017~~2020 Summary Compensation Table in accordance with the requirements of Item 402 (c)(2)(x) of Regulation S-K. Annual total compensation for ~~2017~~2020 for our median employee included annual salary, annual incentives, and company contributions towards benefits including retirement. Annual total compensation for ~~2017~~2020 for our CEO consists of the amount reported in the "Total" column of our ~~2017~~2020 Summary Compensation Table.

Director Compensation for Fiscal Year ~~2017~~2020

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~~2020 for service as directors. We refer to these directors as ~~nonemployee~~non-employee 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,~~Kenton Bradbury, Richard Dinneny, Chris Hind, Grant Hodgkins, Martijn Verwoest, and ~~Etienne Middleton. Kimberly Harris is employed by the Company and also serves as a director.~~Steven Zucchet.

As described in further detail below, the Company’s ~~nonemployee~~non-employee director compensation program in ~~2017~~2020 consisted of quarterly retainer cash fees of ~~$27,500.~~$42,500. 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		Name	Fees Earned		Nonqualified Deferred Compensation Earnings1		Total
Scott Armstrong	$	—	$	146,400	$	146,400	Scott Armstrong	$	186,600	$	—	$	186,600
Melanie Dressel²	30,700		—		30,700
Barbara Gordon	18,333				18,333		Barbara Gordon	154,440		17,160		171,600
Steve Hooper	—		187,033		187,033		Steve Hooper	—		57,250		57,250
David MacMillan³	155,200		—		155,200
Thomas King							Thomas King	175,600		—		175,600
Paul McMillan	139,600		—		139,600		Paul McMillan	186,600		—		186,600
Mary O. McWilliams	134,800		—		134,800		Mary O. McWilliams	171,600		—		171,600
Christopher Trumpy	144,400		—		144,400		Christopher Trumpy	176,400		—		176,400

_______________


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.~~

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

~~Nonemployee~~

165

Non-employee Director Compensation Program

The ~~2017 nonemployee~~2020 non-employee director compensation program is based on the principles that the level of ~~nonemployee~~non-employee director compensation should be based on Board and committee responsibilities and should be competitive with comparable companies.

The ~~2017~~2020 compensation program for ~~nonemployee~~non-employee directors was as follows:

1.A base cash quarterly retainer fee of ~~$27,500;~~$42,500;

~~$1,600 for attendance at each in-person Board and committee meeting; and~~

$2.A $1,600 per meeting fee ($800 for ~~each telephonic meeting lasting 60 minutes~~telephonic) will be paid when the number of Board or ~~less, and $1,600 for each telephonic meeting lasting more than 60 minutes.~~Committee meetings exceed six per year (not applicable to Asset Management Committee calls).

In ~~2017, nonemployee~~2020, non-employee directors were paid the following additional cash quarterly retainer fees:

1.Independent Board Chairman, $13,750;

2.Chair of the Compensation and Leadership Development Committee, ~~$2,000;~~$3,750;

3.Chair of the Governance ~~and Public Affairs Committees, $1,500;~~Committee, $3,750;

4.Chair of the Business Planning Committee, $3,750

5.Chair of the Audit Committee, ~~$2,500;~~$3,750; and

6.Each member of the Audit Committee other than the chair, $1,000.

~~Nonemployee~~Non-employee directors were reimbursed for actual travel and out-of-pocket expenses incurred in connection with their services.

~~Nonemployee~~ Non-employee directors are eligible to participate in the Company’s matching gift program on the same terms as all Puget Energy employees. Under this program, the Company matches up to a total of $500 a year in contributions by a director to non-profit organizations that have Internal Revenue Service (IRS) 501(c)(3) tax exempt status and are located in and served the people of PSE’s service territory in Washington State.

Deferral of Compensation

~~Nonemployee~~Non-employee 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~~non-employee directors. Non-employee 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~~Non-employee directors are permitted to make changes in measurement fund allocations quarterly. Steve Hooper and ~~Scott Armstrong~~Barbara Gordon are the only independent board ~~members~~member to defer any director fees during ~~2017.~~2020.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS

Security Ownership of Directors, Executive Officers and Certain Beneficial Owners

The following tables show the number of shares of common stock beneficially owned as of December 31, ~~2017~~2020, 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.~~2020.

Beneficial Ownership Table of Puget Energy and PSE

Number of Beneficially

Owned Shares

Name

Puget Energy

~~PSE~~Puget Sound Energy

Puget Equico LLC and affiliates

200^{1, 2}

—

Puget Energy

—

~~85,903,791~~³

85,903,7913

_______________

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:

1Information 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), 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 (BCI), PIP2PX (Pad) Ltd. (PIP2PX) and PIP2GV (Pad) Ltd. (PIP2GV and together with OMERS and PGGM, PMGH, CPPIB, BCI 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. As of February 24, 2021:

•The address of the principal office of Puget Holdings, Puget Intermediate and Puget Equico is the PSE Building, ~~10885~~355 110th Ave NE, ~~4th Street,~~ Bellevue, WA 98004.

•The address of the principal office of ~~MIP~~OMERS is ~~125~~900-100 Adelaide Street West, ~~55th Street, Level 22, New York, NY 10019.~~Toronto, Ontario, Canada, M5H E02

•The address of the principal office of PGGM Vermogensbeheer B.V. is Noordweg Noord 150, 3704 JG Zeist, Netherlands

•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~~BCI is ~~Suite 300-2950 Jutland Road,~~750 Pandora Ave, Victoria, British Columbia, Canada ~~V8T 5K2.~~V8W 0E4.

•The address of the principal office of PIP2PX and PIP2GV is ~~1100, 10830 Jasper Avenue,~~10250, 101 Street NW, Edmonton, Alberta, Canada T5J ~~2B3.~~

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.

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.

3P4.

2Pursuant 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.

3Pursuant 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.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Transactions with Related Persons

Our Boards of Directors have adopted a written policy for the review and approval or ratification of related person transactions. Under the policy, our directors and executive officers are expected to disclose to our Chief Compliance Officer the material facts of any transaction that could be considered a related person transaction promptly upon gaining knowledge of the transaction. A related person transaction is generally defined as any transaction required to be disclosed under Item 404(a) of Regulation S-K, the SEC’s related person transaction disclosure rule.

Any transaction reported to the Chief Compliance Officer will be reviewed according to the following procedures:

1.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.

2.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.

3.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:

1.The extent of the related person’s interest in the transaction;

2.Whether the terms are comparable to those generally available in arm's length transactions; and

3.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.

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

168

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, and 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, in isolation, 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~~2020, and ~~2016~~2019 were as follows:


	2017				2016					2020				2019
(Dollars in Thousands)	Puget Energy		PSE		Puget Energy		PSE		(Dollars in Thousands)	Puget Energy		PSE		Puget Energy		PSE
Audit fees¹	$	2,777	$	2,546	$	2,597	$	2,397	Audit fees1	$	2,598	$	2,346	$	2,630	$	2,378
Audit related fees²	22		22		47		47		Audit related fees2	152		—		114		114
Tax fees³	—		—		—		—		Tax fees3	—		—		—		—
Other fees⁴	337		337		383		383		Other fees4	52		52		52		52
Total	$	3,136	$	2,905	$	3,027	$	2,827	Total	$	2,802	$	2,398	$	2,796	$	2,544

_______________


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.~~

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 2020 fees are estimated and include an aggregate amount of $1.7 million billed to Puget Energy and $1.6 million to PSE through December 2020.

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

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,

169

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~~2020 and ~~2016,~~2019, 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:~~

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~~2020, 2019, and ~~2015,~~2018, 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.

170

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~~	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~~	4.2		First, Second, Third, Fourth, and ~~Fourth~~Fifth 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).~~1-4393 and Exhibit 4.1 to Puget Sound Energy's Current Report on Form 8-K, dated May 23, 2018, 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.



***				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.

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					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~~	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~~	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~~	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~~	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~~	4.14		Third Supplemental Indenture to the Unsecured Debt Indenture, dated March 19, 2018, 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 March 26, 2018, Commission File No. 1-4393).
		4.15		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~~	4.16		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).

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	~~4.16~~	4.17		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~~	4.18		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~~	4.19		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~~	4.20		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~~	4.21		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~~	4.22		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).
	4.23		F i fth Supplemental Indenture dated May 19, 2020 relating to Puget Energy's 4.1% Senior Secured Notes due 2030 (Incorporated herein by reference to E xhibit 4.1 to Puget Energy's Current Report on Form 8-K Filed May 19, 2020 , Commission File No. 1-16 305).
***	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).

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***			10.11			Operation and Maintenance Agreement dated as of July 30, 1971 between The Montana Power Company and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 10.11 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).



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

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			~~10.29~~	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~~10.30		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~~Energy's Current Report on Form 8-K, dated April 3, 2009, Commission ~~File~~file Nos. 1-16305 and 1-4393).
**			~~10.34~~10.31		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~~Energy's and Puget Sound ~~Energy’s~~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~~10.32		Puget Sound Energy, Inc. Amended and Restated Supplemental Executive Retirement Plan effective January 1, ~~2013~~2013. (incorporated herein by reference ~~to Exhibit~~ 10.35 to Puget ~~Energy’s~~Energy's and Puget Sound ~~Energy’s~~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~~10.33		Puget Sound Energy, Inc. Amended and Restated Deferred Compensation Plan for Key Employees effective January 1, ~~2009~~2009. (incorporated herein by reference to Exhibit 10.40 to Puget ~~Energy’s~~Energy's and Puget Sound ~~Energy’s~~Energy's Report on Form 10-K for the fiscal year ended December 31, ~~2008,~~20018, Commission File No. ~~1-16305 and 1-4393)~~1-6305).
**			~~10.37~~10.34		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~~Energy's and Puget Sound ~~Energy’s~~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~~10.35		Summary of Director Compensation (incorporated herein by reference to Exhibit 10.38 to Puget ~~Energy’s~~Energy's and Puget Sound ~~Energy’s~~Energy's Report on Form 10-K for the fiscal year ended December 31, 2015, Commission File ~~No.1-16305~~No. 1-16305 and ~~1-4393).~~1-4393.)
**			~~10.39~~10.36		Puget Sound Energy, Inc. Supplemental Death Benefit Plan for Executive Employees, effective ~~October 1,~~October1, 2000, as amended (incorporated herein by reference to Exhibit 10.45 to Puget ~~Energy’s~~Energy's and Puget Sound ~~Energy’s~~Energy's Report on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. ~~1-16305 and 1-4393)~~1-16305).
**			~~10.40~~10.37		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~~Energy's and Puget Sound ~~Energy’s~~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~~10.38		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~~Energy's and Puget Sound ~~Energy’s~~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~~10.39		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~~Energy's and Puget Sound ~~Energy’s~~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~~10.40		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~~Energy's and Puget Sound ~~Energy’s~~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).10.41



	~~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~~Exhibit 10.1 to Puget Energy's Current Report on Form 8-K, filed in October 31, 2017, Commission File No. 1-16305).
			~~10.47~~10.42		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).~~10.43
*	~~12.2~~	~~Statement setting forth computation of ratios of earnings to fixed charges of~~Purchase Agreement, dated June 4, 2018, between Puget Sound Energy, Inc. ~~(2013 through 2017)~~and J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and Mizuho Securities USA LLC and each of the other underwriters named in Schedule A thereto (incorporated by reference herein to Exhibit 1.1 to Current Report on Form 8-K filed on June 5, 2018, Commission File No. 1-4393).
*			~~21.1~~	10.44		Term Loan Agreement, dated October 1, 2018, among Puget Energy, Toronto Dominion (Texas) LLC, as Administrative Agent, and the lenders party thereto (incorporated by reference herein to Exhibit 10.1 to Current Report on Form 8-K filed on October 3, 2018, Commission file No. 1-16305 and 1-4393).
*			21.1		Subsidiaries of Puget Energy, Inc.
*			21.2		Subsidiaries of Puget Sound Energy, Inc.
*			23.1		Consent of PricewaterhouseCoopers LLP

175


*	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.~~Mary E. Kipp .
*	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.~~Mary E. Kipp
*	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.~~Mary E. Kipp.
*	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,~~2020, filed on ~~March 1, 2018,~~February 25, 2021, 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).
*	101.INS	Inline XBRL Instance
*	101.SCH	Inline XBRL Taxonomy Extension Schema
*	101.CAL	Inline XBRL Taxonomy Extension Calculation
*	101.DEF	Inline XBRL Taxonomy Extension Definition
*	101.LAB	Inline XBRL Taxonomy Extension Label
*	101.PRE	Inline XBRL Taxonomy Extension Presentation
*	104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

_______________


*	~~Filed herewith.~~


**	~~Management contract, compensatory plan or arrangement.~~

*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.

176

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/ Mary E. Kipp

Mary E. Kipp

President and Chief Executive Officer

Date:

February 25, 2021

Date:

February 25, 2021

~~PUGET ENERGY, INC.~~

~~PUGET SOUND ENERGY, INC.~~

~~/s/ Kimberly J. Harris~~

~~Kimberly J. Harris~~

~~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~~person son 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~~Mary E. Kipp		President and	~~March 1, 2018~~February 25, 2021
(~~Kimberly J. Harris)~~Mary E. Kipp)		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~~Kenton Bradbury		Director
(~~Andrew Chapman)~~Kenton Bradbury)

/s/ Steven W. Hooper		Director
(Steven W. Hooper)

/s/ ~~Karl Kuchel~~Tom King		Director
(~~Karl Kuchel)~~Tom King)

/s/ ~~Christopher J. Leslie~~Richard Dinneny		Director
(~~Christopher J. Leslie)~~Richard Dinneny)

~~/s/ Barbara Gordon~~	~~Director of PSE only~~
~~(Barbara Gordon)~~



/s/ Barbara Gordon			Director of PSE Only
(Barbara Gordon)

/s/ Christopher Hind			Director
(Christopher Hind )

177


/s/ Paul McMillan	Director
(Paul McMillan)

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

/s/ ~~Etienne Middleton~~Grant Hodgkins	Director
(~~Etienne Middleton)~~Grant Hodgkins)

/s/ ~~Christopher Trumpy~~Martijn Verwoest	Director
(~~Christopher Trumpy)~~Martijn Verwoest)

/s/ ~~Christopher Hind~~Steven Zucchet	Director	~~Director~~
(~~Christopher Hind)~~Steven Zucchet)

~~171~~178


			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 Project	2028	2052	24.2		228
Grant County PUD:
Priest Rapids Development	2052	2052	0.6		6
Wanapum Development	2052	2052	0.6		7
Total					722



			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


	Year Ended December 31,
	2020	2019	2018
Natural gas volumes for power in storage at year end, therms (thousands):
Jackson Prairie	5,603	4,628	4,097
Plymouth	2,345	2,136	2,268


											Year Ended December 31,
	Year Ended December 31,										2020		2019		2018
	2017			2016			2015
Natural gas operating revenue by classes (dollars in thousands):
Natural gas operating revenue by classes (Dollars in Thousands):										Natural gas operating revenue by classes (Dollars in Thousands):
Residential	$	686,438		$	578,955		$	597,572		Residential	$	662,502	$	613,617	$	598,923
Commercial firm	251,584			213,138			239,849			Commercial firm	232,306		218,302		219,390
Industrial firm	20,077			17,753			21,533			Industrial firm	17,662		15,698		17,247
Interruptible	24,317			24,447			29,082			Interruptible	22,622		18,381		21,113
Total retail natural gas sales	982,416			834,293			888,036			Total retail natural gas sales	935,092		865,998		856,673
Transportation services	21,718			20,322			18,666			Transportation services	17,296		20,283		19,984
Decoupling revenue	3,522			52,114			51,981			Decoupling revenue	18,906		2,296		6,115
Other decoupling revenue¹	(22,862		)	(28,761		)	(26,038		)	Other decoupling revenue1	(6,478)		(29,737)		(37,022)
Other	12,965			12,542			14,904			Other	16,097		16,531		4,998
Total natural gas operating revenue	$	997,759		$	890,510		$	947,549		Total natural gas operating revenue	$	980,913	$	875,371	$	850,748
Number of customers served (average):										Number of customers served (average):
Residential	761,010			749,586			737,339			Residential	791,612		782,413		772,130
Commercial firm	55,372			54,992			54,646			Commercial firm	56,303		56,113		55,716
Industrial firm	2,330			2,371			2,378			Industrial firm	2,293		2,304		2,308
Interruptible	398			410			429			Interruptible	288		367		393
Transportation	226			227			221			Transportation	224		230		234
Total customers	819,336			807,586			795,013			Total customers	850,720		841,427		830,781
Natural gas volumes, therms (thousands):										Natural gas volumes, therms (thousands):
Residential	621,915			521,771			492,997			Residential	592,811		605,313		571,265
Commercial firm	279,656			233,586			230,507			Commercial firm	250,611		277,639		264,775
Industrial firm	25,500			22,783			23,777			Industrial firm	21,946		22,915		23,890
Interruptible	49,249			49,533			43,931			Interruptible	45,240		45,176		47,275
Total retail natural gas volumes, therms	976,320			827,673			791,212			Total retail natural gas volumes, therms	910,608		951,043		907,205
Transportation volumes	236,578			230,724			220,392			Transportation volumes	212,330		227,657		230,735
Total volumes	1,212,898			1,058,397			1,011,604			Total volumes	1,122,938		1,178,700		1,137,940


	Year Ended December 31,
	2020			2019			2018
Working natural gas volumes in storage at year end, therms (thousands):
Jackson Prairie	78,016			82,892			76,348
Clay Basin	80,736			77,532			74,420

Average therms used per customer:
Residential	749			774			740
Commercial firm	4,451			4,948			4,752
Industrial firm	9,571			9,946			10,351
Interruptible	157,083			123,095			120,293
Transportation	947,902			989,813			986,045
Average revenue per customer:
Residential	$	837		$	784		$	776
Commercial firm	4,126			3,890			3,938
Industrial firm	7,703			6,813			7,473
Interruptible	78,549			50,084			53,724
Transportation	77,214			88,187			85,400
Average revenue per therm sold:
Residential	$	1.118		$	1.014		$	1.048
Commercial firm	0.927			0.786			0.829
Industrial firm	0.805			0.685			0.722
Interruptible	0.500			0.407			0.447
Average retail revenue per therm sold	$	1.027		$	0.911		$	0.944
Transportation	0.081			0.089			0.087
Heating degree days	4,122			4,208			4,065
Percent of normal - NOAA 30-year average	87.8		%	89.6		%	86.2		%



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



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



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~~355 110th Ave NE 4^th ~~Street, Suite 1200~~ Bellevue, Washington ~~98004-5591~~98004 (425) 454-6363	91-1969407



1-4393	PUGET SOUND ENERGY, INC. A Washington Corporation ~~10885~~355 110th Ave NE 4^th ~~Street, Suite 1200~~ Bellevue, Washington ~~98004-5591~~98004 (425) 454-6363	91-0374630



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	%


²	~~National Oceanic and Atmospheric Administration (NOAA).~~


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


	Peak Power Resources At December 31,						Energy Production At December 31,
`													`	Peak Power Resources At December 31,				Energy Production At December 31,
	2017			2016			2017			2016				2020		2019		2020		2019
	MW	%		MW	%		MWh	%		MWh	%			MW	%	MW	%	MWh	%	MWh	%
Purchased resources:													Purchased resources:
Columbia River PUD contracts	711	15.0	%	708	14.6	%	3,355,134	13.3	%	3,371,827	13.7	%
Columbia River PUD contracts1													Columbia River PUD contracts1	685	14.9%	687	14.5%	3,796,841	15.3%	2,642,177	10.2%
Other hydroelectric	72	1.5		79	1.6		281,619	1.1		365,670	1.5		Other hydroelectric	111	2.4	72	1.5	583,514	2.3	272,653	1.0
Other producers	284	6.0		387	8.0		3,679,623	14.6		2,999,171	12.1		Other producers	285	6.2	285	6.0	2,704,663	10.9	3,276,502	12.7
Wind	56	1.2		56	1.2		119,690	0.5		138,148	0.6		Wind	193	4.2	56	1.2	300,886	1.2	123,368	0.5
Short-term wholesale energy purchases	N/A	—		N/A	—		7,049,060	27.8		6,154,767	25.0		Short-term wholesale energy purchases	N/A	—	N/A	N/A	5,768,251	23.2	6,144,663	23.7
Total purchased	1,123	23.7	%	1,230	25.4	%	14,485,126	57.3	%	13,029,583	52.9	%	Total purchased	1,274	27.7%	1,100	23.2%	13,154,155	52.9%	12,459,363	48.1%
Company-controlled resources:													Company-controlled resources:
Hydroelectric	254	5.4	%	254	5.2	%	864,821	3.4	%	933,522	3.8	%	Hydroelectric	250	5.5%	250	5.3%	980,194	3.9%	712,727	2.8%
Coal	677	14.3		677	14.0		4,463,705	17.6		4,529,179	18.4
Coal3													Coal3	370	8.0	677	14.4	2,102,338	8.5	4,347,639	16.8
Natural gas/oil	1,908	40.3		1,908	39.4		3,822,462	15.1		4,152,205	16.9		Natural gas/oil	1,931	42.0	1,931	40.8	6,402,647	25.8	6,692,188	25.9
Wind	773	16.3		773	16.0		1,674,790	6.6		1,962,702	8.0		Wind	773	16.8	773	16.3	2,215,739	8.9	1,667,489	6.4
Other¹	2	—		2	—		—	—		—	—
Other2													Other2	2	—	2	—	—	—	—	—
Total company-controlled	3,614	76.3	%	3,614	74.6	%	10,825,778	42.7	%	11,577,608	47.1	%	Total company-controlled	3,326	72.3%	3,633	76.8%	11,700,918	47.1%	13,420,043	51.9%
Total resources	4,737	100.0	%	4,844	100.0	%	25,310,904	100.0	%	24,607,191	100.0	%	Total resources	4,600	100.0%	4,733	100.0%	24,855,073	100.0%	25,879,406	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.~~


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.~~


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.~~


Puget Energy
Summary of Operations	Year Ended December 31,
(Dollars in Thousands)	2020		2019		2018		2017		2016
Operating revenue	$	3,326,450	$	3,401,130	$	3,346,496	$	3,460,276	$	3,164,301
Operating income	507,824		519,008		554,058		739,106		765,474
Net income	182,717		210,708		235,622		175,194		312,899

Total assets at year-end	$	15,042,965	$	14,659,863	$	14,098,861	$	13,690,789	$	13,266,380
Long-term debt	5,892,440		5,920,325		5,672,491		5,207,929		5,104,073
Junior subordinated notes	—		—		—		250,000		250,000
Finance lease obligations	795		1,480		1,315		1,129		645
Operating lease obligations	180,184		190,189		—		—		—


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.~~


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.



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



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



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


Puget Energy and Puget Sound Energy	December 31, 2020				December 31, 2019
(Dollars in Thousands)	Assets		Liabilities		Assets		Liabilities
Electric portfolio:
Current	$	16,862	$	23,697	$	15,399	$	9,273
Long-term	5,682		23,225		4,534		8,231
Total Electric Portfolio	$	22,544	$	46,922	$	19,933	$	17,504
Natural gas portfolio:
Current	$	16,153	$	7,744	$	8,227	$	4,155
Long-term	3,123		6,608		3,148		4,462
Total Natural Gas Portfolio	19,276		14,352		11,375		8,617
Total derivatives	$	41,820	$	61,274	$	31,308	$	26,121



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


Puget Energy and Puget Sound Energy
Energy Derivative Contracts Gain (Loss)
(Dollars in Thousands)	December 31, 2020
Fair value of contracts outstanding at December 31, 2019	$	5,186
Contracts realized or otherwise settled during 2020	4,573
Change in fair value of derivatives	(29,213)
Fair value of contracts outstanding at December 31, 2020	$	(19,454)



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	)


Puget Energy and Puget Sound Energy Source of Fair Value															Puget Energy and Puget Sound Energy Source of Fair Value	Fair Value of Contracts by Settlement Year
	Fair Value of Contracts by Settlement Year
(Dollars in Thousands)	2018			2019-2020			2021-2022			Thereafter		Total			(Dollars in Thousands)	2021		2022-2023		2024-2025		Thereafter		Total
Prices provided by external sources¹	$	(46,927	)	$	(17,434	)	$	(349	)	$	—	$	(64,710	)	Prices provided by external sources1	$	4,855	$	1,978	$	(1,433)	$	—	$	5,400
Prices based on internal models and valuation methods	4,315			18			(1,312		)	—		3,021			Prices based on internal models and valuation methods	(3,281)		(7,856)		(9,569)		(4,148)		(24,854)
Total fair value	$	(42,612	)	$	(17,416	)	$	(1,661	)	$	—	$	(61,689	)	Total fair value	$	1,574	$	(5,878)	$	(11,002)	$	(4,148)	$	(19,454)


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


Long-Term Debt Instruments	December 31, 2020				December 31, 2019
(Dollars in Thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Puget Energy	$	5,892,440	$	7,980,646	$	5,920,325	$	7,412,416
Puget Sound Energy	4,338,044		6,086,358		4,336,142		5,571,818



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