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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


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

For the fiscal year ended December 31, ~~2021~~2022


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


			For the transition period from ___________ to ___________


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


1-16305			PUGET ENERGY, INC A Washington Corporation 355 110th Ave NE Bellevue, Washington 98004 (425) 454-6363			91-1969407


1-4393			PUGET SOUND ENERGY, INC. A Washington Corporation 355 110th Ave NE Bellevue, Washington 98004 (425) 454-6363			91-0374630

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

Title of Each Class

Trading Symbol

Name of Each Exchange on Which Registered

N/A

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

Title of Each Class

Trading Symbol

Name of Each Exchange on Which Registered

N/A

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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Puget Energy, Inc.

Yes

/X/

/ /

Puget Sound Energy, Inc.

Yes

/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/

/ /

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.

Puget Energy, Inc.

Yes

/ /

/X/

Puget Sound Energy, Inc.

Yes

/ /

/X/

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).

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
General			7
Regulation and Rates			98
Electric Utility Operating Statistics			13
Electric Supply			15
Natural Gas Utility Operating Statistics			19
Natural Gas Supply for Natural Gas Customers			21
Energy Efficiency			2322
Environment			23
Recent and Future Environmental Law and Regulation			24
Human Capital Resources			27
Executive Officers of the Registrants			2928
1A. Risk Factors			29
1B. Unresolved Staff Comments			3 736
2. Properties			3736
3. Legal Proceedings			3736
4. Mine Safety Disclosures			3736

Part II
5. Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities			3736
6. [Reserved]			37
7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			3837
7A. Quantitative and Qualitative Disclosures about Market Risk			6668
8. Financial Statements and Supplementary Data			6972
Report of Management and Statement of Responsibility			7073
Report of Independent Registered Public Accounting Firm – Puget Energy			7174
Report of Independent Registered Public Accounting Firm – Puget Sound Energy			7376
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			~~138~~140
9A. Controls and Procedures			~~138~~1 41
9B. Other Information			~~139~~1 42
9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections			~~139~~142

Part III
10. Directors, Executive Officers and Corporate Governance			~~140~~14 2
11. Executive Compensation			114 435
12. Security Ownership of Certain Beneficial Owners and Management and Related			~~163~~164
Shareholder Matters
13. Certain Relationships and Related Transactions, and Director Independence			~~164~~165
14. Principal Accountant Fees and Services			~~165~~166

Part IV
15. Exhibits and Financial Statement Schedules			~~166~~167
16. Form 10-K Summary			~~166~~167
Exhibit Index			~~167~~168
Signatures			1 73174

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
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
PLR			Private Letter Ruling
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~~SOFR			~~Tax Cuts and Jobs Act~~Secured Overnight Financing Rate
VIE			Variable Interest Entity
Washington Commission			Washington Utilities and Transportation Commission
WSPP			WSPP, Inc.

FORWARD-LOOKING STATEMENTS

Puget Energy and Puget Sound Energy, Inc. (PSE) include the following cautionary statements in this Form 10-K to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by or on behalf of Puget Energy or PSE. This report includes forward-looking statements, which are statements of expectations, beliefs, plans, objectives and assumptions of future events or performance. Words or phrases such as “anticipates,” “believes,” “continues,” “could,” “estimates,” “expects,” “future,” “intends,” “may,” “might,” “plans,” “potential,” “predicts,” “projects,” “should,” “will likely result,” “will continue” or similar expressions are intended to identify certain of these forward-looking statements 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, 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) or distribution of natural gas, natural resources, and fish and wildlife (including the Endangered Species Act) as well as the risk of litigation arising from such matters, whether involving public or private claimants or regulatory investigative or enforcement measures;
•			Changes in tax law, related regulations or differing interpretation, or enforcement of applicable law by the Internal Revenue Service (IRS) or other taxing jurisdiction; and PSE's ability to recover costs in a timely manner arising from such changes;
•			Inability to realize deferred tax assets and use production tax credits (PTCs) due to insufficient future taxable income;
•			Accidents or natural disasters, such as hurricanes, windstorms, earthquakes, floods, fires, extreme weather conditions, landslides, and other acts of God, terrorism, asset-based or cyber-based attacks, 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 global Coronavirus Disease 2019 (COVID-19) pandemic, and responses to such developments (such as voluntary and mandatory quarantines, government stay at home orders, restrictions on travel, commercial, social and other activities, and the impact of vaccination mandates on employee and vendor staffing levels) 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;
•			PSE's resource adequacy needs to meet the Clean Energy Transformation Act (CETA) and the Climate Commitment Act (CCA) requirements, through a combination of owned or contracted resources, may significantly increase purchased power and gas costs if pricing pressures and supply constraints on resource acquisitions increase;
•			Changes in climate, weather conditions, or sustained extreme weather events 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, such as inflation, which may impact customer consumption or affect PSE's accounts receivable;
•			The loss of significant customers, changes in the business of significant customers or the condemnation of PSE's facilities as a result of municipalization or other government action or negotiated settlement, which may result in changes in demand for PSE's services;
•			The failure of information systems or the failure to secure information system data, which may impact the operations and cost of PSE's customer service, generation, distribution and transmission;
•			Opposition and social activism that may hinder PSE's ability to perform work or construct infrastructure;
•			Capital market conditions, including changes in the availability of capital and interest rate fluctuations;
•			Employee workforce factors including strikes; work stoppages; retirements; 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;
•			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;
•			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; and
•			Recent laws proposed or passed by various municipalities in PSE's service territory, including Seattle, which seek to reduce or eliminate the use of natural gas in various contexts, such as for space, cooking, and water heating in new commercial and multifamily buildings, which in turn may impact operations due to costs and delays from incremental permitting and other requirements that are outside PSE's control.

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, Puget Sound Energy, Inc. (PSE), a utility company. Puget Energy also has a wholly-owned, non-regulated subsidiary, Puget LNG, LLC (Puget LNG), which was formed 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. Puget Holdings is owned by a consortium of long-term infrastructure investors including the ~~Canada Pension Plan Investment Board (CPPIB), the~~ British Columbia Investment Management Corporation (BCIMC), the Alberta Investment Management Corporation (AIMCo), Ontario Municipal Employee Retirement System (OMERS) ~~and~~, PGGM Vermogensbeheer B.V. ~~In July 2021, CPPIB entered into an agreement to sell its shares to~~, Macquarie Washington Clean Energy Investment, L.P., and Ontario Teachers’ Pension Plan Board. ~~The sale was approved by the Washington Commission and closed on February 22, 2022.~~ Puget 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, 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~~table presents the number of PSE customers ~~and revenue by customer class~~ for electric and natural gas as of December 31, ~~2021~~2022 and ~~2020:~~2021:


		December 31,			December 31,				December 31,			December 31,
Customer Count by Class	Customer Count by Class	2021	2020	Percent	2021	2020	Percent	Customer Count by Class	2022	2021	Percent	2022	2021	Percent
(in thousands)	(in thousands)	Electric		Change	Natural Gas		Change	(in thousands)	Electric		Change	Natural Gas		Change
Residential	Residential	1,059	1,048	1.0%	806	797	1.1%	Residential	1,072	1,059	1.2%	813	806	0.9%
Commercial	Commercial	133	131	1.5%	57	57	—%	Commercial	134	133	0.8%	57	57	—%
Industrial	Industrial	3	3	—%	2	2	—%	Industrial	3	3	—%	2	2	—%
Other	Other	8	8	—%	—	—	—%	Other	8	8	—%	—	—	—%
Total1	Total1	1,203	1,190	1.1%	865	856	1.1%	Total1	1,217	1,203	1.2%	872	865	0.8%

_______________

1 At December 31, 2022, and 2021, approximately 423,382 and ~~2020, approximately~~ 419,437 ~~and 414,210~~ customers purchased both electricity and natural gas from PSE, respectively.

December 31,

December 31,

Retail Revenue by Class 2021 2020

Percent

2021 2020

Percent
(Dollars in Thousands) Electric

Change

Natural Gas

Change
Residential $ 1,318,320 $ 1,186,013 11.2% $ 722,002 $ 662,502 9.0%
Commercial 902,928 791,898 14.0 292,217 253,526 15.3
Industrial 108,267 101,567 6.6 21,726 19,064 14.0
Other 38,054 37,864 0.5 20,104 17,296 16.2
Total $ 2,367,569 $ 2,117,342 11.8% $ 1,056,049 $ 952,388 10.9%

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 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, ~~2021,~~2022, and gross utility plant by category and percentages as of December 31, ~~2021:~~2022:


Utility Plant Additions/Retirements 5-Year Total	Utility Plant Additions/Retirements 5-Year Total	2017 - 2021						Utility Plant Additions/Retirements 5-Year Total	2018 - 2022
(Dollars in Thousands)	(Dollars in Thousands)	Electric		Natural Gas		Common		(Dollars in Thousands)	Electric		Natural Gas		Common
Additions	Additions	$	1,916,410	$	1,330,170	$	801,686	Additions	$	1,876,770	$	1,237,089	$	696,279
Retirements	Retirements	(904,011)		(108,928)		(283,330)		Retirements	(883,625)		(99,768)		(357,513)
Net utility plant	Net utility plant	$	1,012,399	$	1,221,242	$	518,356	Net utility plant	$	993,145	$	1,137,321	$	338,766


Utility Plant Balance	Utility Plant Balance	December 31, 2021									Utility Plant Balance	December 31, 2022
(Dollars in Thousands)	(Dollars in Thousands)	Electric			Natural Gas			Common			(Dollars in Thousands)	Electric			Natural Gas			Common
Distribution	Distribution	$	4,549,499	41.3%	$	4,547,862	95.8%	$	—	—%	Distribution	$	4,760,017	41.9%	$	4,719,214	91.3%	$	—	—%
Generation	Generation	4,097,138		37.2	3,239		0.1	—		—	Generation	4,060,463		35.8	3,239		0.1	—		—
Transmission	Transmission	1,663,559		15.1	—		—	—		—	Transmission	1,683,737		14.8	—		—	—		—
General plant & other	General plant & other	718,315		6.4	194,236		4.1	1,124,144		100.0	General plant & other	851,760		7.5	444,746		8.6	1,087,927		100.0
Total (excluding CWIP)	Total (excluding CWIP)	$	11,028,511	100.0%	$	4,745,337	100.0%	$	1,124,144	100.0%	Total (excluding CWIP)	$	11,355,977	100.0%	$	5,167,199	100.0%	$	1,087,927	100.0%

Corporate Location

PSE’s and Puget Energy's principal executive offices are located at 355 110th Ave NE, Bellevue, Washington 98004 and the telephone number is (425) 454-6363.

Available 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. The Securities and Exchange Commission (SEC) maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC and 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 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 twelve-month period. Both allow recovery of expenditures outside the process of a full 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
Expedited rate filing rider	Yes	Yes
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
Purchased gas adjustment rider	N/A	No

General Rate Case Filing

PSE filed a GRC which includes a ~~three year~~three-year multiyear rate plan with the Washington Commission on January 31, 2022, requesting an overall increase in electric and natural gas rates of 13.6% and 13.0% respectively in 2023; 2.5% and 2.3%, respectively in 2024; and 1.2% and 1.8%, respectively, in 2025. PSE requested a return on equity of 9.9% in all three rate years. PSE requested an overall rate of return of 7.39% in 2023; 7.44% in 2024; and 7.49% in 2025. The filing requests recovery of forecasted plant additions through 2022 as required by ~~RCW~~Revised Code of Washington (RCW) 80.28.425 as well as forecasted plant additions through 2025, the final year of the multiyear rate plan. ~~The next phase~~In August 2022, three separate partial multiparty settlement agreements were reached. For further details regarding the partial settlement agreements, see Management's Discussion and Analysis, "Regulation of PSE Rates and Recovery of PSE Costs" included in Item 7 of this report. On January 6, 2023, the ~~filing will be to establish a procedural calendar for~~Washington Commission approved PSE’s natural gas rates with an overall increase of $70.8 million or 6.40% in 2023 and $19.5 million or 1.65% in 2024, with the ~~adjudication~~effective date of January 7, 2023. Furthermore, on January 10, 2023, the ~~case.~~Washington Commission approved PSE’s electric rates with an overall increase of $247.0 million or 10.75% in 2023 and $33.1 million or 1.33% in 2024, with an effective date of January 11, 2023.

PSE filed 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. On July 8, 2020, the Washington Commission issued its order on PSE’s 2019 GRC. The ruling provided for a weighted cost of capital of 7.39% or 6.8% 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)~~PGA deferral to mitigate the impact of the rate increase in response to the economic uncertainty created by the COVID-19 pandemic. This reduced the electric revenue

increase to approximately $0.9 million, or 0.05%, and the natural gas increase to $1.3 million, or ~~0.15%,~~0.2% and became effective October 15, 2020 and October 1, 2020, respectively.

~~On August 6, 2020,~~In July 2021, PSE ~~filed~~received a petition for judicial review with the Superior Court of the State of Washington for King County 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 deviatePrivate Letter Ruling (PLR) from the ~~Internal Revenue Service (IRS) normalization and consistency rules.~~

~~On July 30, 2021,~~IRS which concluded that in the ~~IRS issued a private letter ruling (PLR) to PSE which concludes that~~2019 GRC the Washington Commission’s methodology for reversing plant-related excess deferred income taxes iswas an impermissible methodology under the IRS normalization and consistency rules. OnThe PLR required adjustments to PSE's rates to bring PSE back into compliance with IRS rules. In September ~~28,~~ 2021, the Washington Commission ~~issued an order amending~~amended its order ~~previously issued on July 8, 2020 to correct for items which were determined to be impermissible under IRS normalization and consistency rules as detailed~~ in accordance with the PLR. To reflect the impact of the PLR, PSE has recorded a regulatory asset and additional revenues of $24.5 million in its operating results through December 31, 2021, of which $5.6 million was collected from customers. Therefore, theThe annualized overall rate impact ~~for this element is~~was an increase of $15.8 million, or 0.7%, for electric and $3.1 million, or 0.3%, for natural gas for a total of $18.9 million with rates effective October 1, 2021. This led to ~~an overall~~a combined annualized net increase to electric rates of $77.1 million, or 3.7%, an increase of $17.5 million above the $59.6 million granted in the revised final order. The order also led to ~~an overall~~a combined annualized net increase to natural gas rates of $45.3 million, or 5.9%, an increase of $2.4 million above the $42.9 million granted in the revised final order. The Washington Commission maintained adjustments that 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 $48.3 million, or 2.3%, and the natural gas increase to $4.9 million, or 0.6%.

~~For additional information, see Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.~~

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~~ 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%).

~~On March 2, 2021, the parties to the PCORC reached an unopposed multiparty~~2022 GRC settlement, in principle. The settlement resulted in an estimated revenue increase of $65.3 million or 3.1%. A term of the settlement requires PSE to include in its next GRC (or another proceeding in 2022) the issue of whether the PCORC should continue, and further prohibits PSE from filing another PCORC before this issue is litigated. On June 1, 2021,which the Washington Commission ~~issued its~~accepted with conditions, PSE agreed not to file a PCORC during 2023 and 2024, the two-year rate plan agreed to in the GRC settlement. Per the 2022 GRC Final Order ~~approving and adopting the settlement and authorizing and requiring a power cost update through a compliance filing.~~

~~On June 17, 2021, PSE filed a compliance filing with the Washington Commission with a revenue increase~~in Docket No. UE-220066, PCORC rates were set to zero as of ~~$70.9 million or 3.3% due to the update on power costs with rates effective July 1, 2021.~~January 11, 2023.

Revenue Decoupling ~~Filings~~Adjustment Mechanism

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. 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 fixed production costs from most residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues are recovered on a per customer basis regardless of actual consumption levels. PSE's energy supply costs, which are part of the power cost adjustment (PCA) and PGA mechanisms, are not included in the decoupling mechanism. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption 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 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.

Electric RateFilings

Colstrip Adjustment Rider

This schedule implements surcharges and/or credits to collect or pass back the costs incurred or benefits realized associated with Colstrip Power Plant Units 1 & 2 and 3 & 4 as authorized in Washington Commission Docket No. UE-220066. Beginning in 2026, only decommissioning and remediation related costs will be included in this Schedule in compliance with the CETA.

Energy Charge Credit Recovery Adjustment

This schedule implements a surcharge to recover certain costs incurred under the electric Schedule 139 Voluntary Long Term Renewable Energy Purchase Rider as authorized in Washington Commission Docket No. UE-220066. The surcharge in this schedule will be updated with each filing that revises the Schedule 139 Energy Charge Credit.

Rates Not Subject to Refund Rate Adjustment

The purpose of this schedule is to recover costs approved during a multiyear rate plan period that are not subject to refund and that are above the level of base rates set in the multiyear rate plan as authorized in Washington Commission Docket No. UE-220066.

Rates Subject to Refund Rate Adjustment

The purpose of this schedule is to charge customers the provisionally approved rates subject to refund approved in a multiyear rate plan, for property granted provisional approval for recovery as authorized in Washington Commission Docket No. UE-220066. PSE will file with the Washington Commission an annual review filing by March 31st each year.

Transportation Electrification Plan Adjustment Rider

This schedule implements surcharges to collect costs incurred associated with the implementation of the Company’s Transportation Electrification Plan, and specifically the products and services offered under Schedules 551, 552, 553, 554, 555, 556, 557, 558, 559 and 583.

Conservation Service 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 compared to the forecasted load set in rates.

Federal Incentive Tracker

The Federal Incentive Tracker 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.

Low Income Program

The Low Income Tracker Tariff recovers changes in costs for the low income bill payment assistance program (as approved in Washington Commission Docket No. UE-011570). The annual filing requests these changes through the existing low income program funding mechanism previously approved by the Washington Commission. The mechanism allows PSE to periodically adjust its electric and natural gas rates to reflect changes in actual sales and costs. Rates change annually on October 1. Included in the electric rate effective October 1, 2022, is the recovery of $25.6 million from the COVID-19 bill assistance program established in Docket No. U-200281 and deferred under the accounting petition approved in Docket No. UE-200780.

~~Electric Rate~~

Power Cost Adjustment Clause

PSE updated its Schedule 95 rates in the Power Cost Adjustment Clause tariff to reflect the transition fee as required by Section 12 of the Special Contract, a non-prescribed commercial/industrial rate contract. Additionally, Schedule 95 rates also include portions of fixed power cost adjustments per the allowed decoupling rate re-allocation resulting from a Special Contract customer becoming a transportation customer as well as small variable power cost adjustments.

~~Filings~~

Power Cost Adjustment Mechanism

PSE currently has a PCA mechanism that provides for the deferral of power costs that vary from the “power cost baseline” level of power costs. The “power cost baseline” levels are set, in part, based on normalized assumptions about weather and 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 cumulative deferral trigger is reached.

Effective January 1, 2017, the following graduated 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~~

~~PSE updated its Schedule 95 rates in the Power Cost Adjustment Clause tariff to reflect the transition fee as required by Section 12 of the Microsoft Special Contract.~~Additionally, Schedule 95 rates also include portions of fixed power cost adjustments per the allowed decoupling rate re-allocation resulting from Microsoft becoming a transportation customer as well as small variable power cost adjustments.

~~Conservation Rider~~

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 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 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 amortizationResidential 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.

~~Low Income Program Tracker Tariff~~

The Low Income Tracker Tariff recovers changes in costs for the low income bill payment assistance program (as approved in Washington Commission Docket Nos. UE-011570 and UG-011571). The annual filing requests these changes through the existing low income program funding mechanism previously approved by the Washington Commission. The mechanism allows PSE to periodically adjust its electric and natural gas rates to reflect changes in actual sales and costs. Rates change annually on October 1.

~~Residential~~Farm Energy 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

Distribution Pipeline Provisional Recovery Adjustment

This schedule implements surcharges in order to defer the revenues associated with the provisional recovery of $30 million for the four miles of distribution pipe to support proper allocation of the investments in a later filing as authorized in Washington Commission Docket No. UG-220067.

Rates Not Subject to Refund Rate Adjustment

Rates Subject to Refund Rate Adjustment

Natural gas rate filings

Conservation Service 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 compared to forecast conservation expenditures from the prior year, as well as actual compared to the forecasted load set in rates.

Cost Recovery Mechanism for Pipeline Replacement

The purpose of the cost recovery mechanism (CRM) is to recover costs related to projects included in PSE's 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. In its 2022 GRC, PSE requested and the Washington Commission approved the recovery of its natural gas CRM investments in the multiyear rate plan. Effective January 7, 2023 PSE will no longer use the CRM annual filing to recover these pipeline replacement program investments.

Property Tax Tracker

The purpose of the property tax tracker mechanism is to pass through the cost of all property taxes incurred by the Company. The mechanism 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 true-up from the prior year.

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, although out-of-cycle rate changes are allowed at other times of the year if needed.

~~Property Tax Tracker Mechanism~~

~~Conservation Rider~~

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

ELECTRIC UTILITY OPERATING STATISTICS


		Year Ended December 31,							Year Ended December 31,
		2021		2020		2019			2022		2021		2020
Generation and purchased power, MWh	Generation and purchased power, MWh							Generation and purchased power, MWh
Company-controlled resources	Company-controlled resources	12,949,384		11,700,918		13,420,043		Company-controlled resources	11,198,936		12,949,384		11,700,918
Contracted resources	Contracted resources	8,624,183		8,237,394		6,752,261		Contracted resources	10,422,069		8,624,183		8,237,394
Non-firm energy purchased	Non-firm energy purchased	4,491,714		4,916,761		5,707,102		Non-firm energy purchased	4,922,194		4,491,714		4,916,761
Total generation and purchased power	Total generation and purchased power	26,065,281		24,855,073		25,879,406		Total generation and purchased power	26,543,199		26,065,281		24,855,073
Less: losses and Company use	Less: losses and Company use	(1,481,152)		(1,611,563)		(1,298,854)		Less: losses and Company use	(1,318,609)		(1,481,152)		(1,611,563)
Total energy sales, MWh	Total energy sales, MWh	24,584,129		23,243,510		24,580,552		Total energy sales, MWh	25,224,590		24,584,129		23,243,510
Electric energy sales, MWh	Electric energy sales, MWh							Electric energy sales, MWh
Residential	Residential	11,479,045		10,976,068		10,756,628		Residential	11,753,057		11,479,045		10,976,068
Commercial	Commercial	8,402,057		7,942,292		8,837,457		Commercial	8,677,178		8,402,057		7,942,292
Industrial	Industrial	1,082,718		1,095,916		1,161,149		Industrial	1,113,909		1,082,718		1,095,916
Other customers	Other customers	79,998		81,261		85,302		Other customers	76,407		79,998		81,261
Total energy sales to customers	Total energy sales to customers	21,043,818		20,095,537		20,840,536		Total energy sales to customers	21,620,551		21,043,818		20,095,537
Sales to other utilities and marketers	Sales to other utilities and marketers	3,540,311		3,147,973		3,740,016		Sales to other utilities and marketers	3,604,039		3,540,311		3,147,973
Total energy sales, MWh	Total energy sales, MWh	24,584,129		23,243,510		24,580,552		Total energy sales, MWh	25,224,590		24,584,129		23,243,510
Transportation, including unbilled	Transportation, including unbilled	2,246,244		2,220,372		2,322,021		Transportation, including unbilled	2,300,711		2,246,244		2,220,372
Electric energy sales and transportation, MWh	Electric energy sales and transportation, MWh	26,830,373		25,463,882		26,902,573		Electric energy sales and transportation, MWh	27,525,301		26,830,373		25,463,882
Electric operating revenue by classes	Electric operating revenue by classes							Electric operating revenue by classes
(Dollars in Thousands)	(Dollars in Thousands)							(Dollars in Thousands)
Residential	Residential	$	1,318,320	$	1,186,013	$	1,139,356	Residential	$	1,381,858	$	1,318,320	$	1,186,013
Commercial	Commercial	902,928		791,898		854,910		Commercial	981,170		902,928		791,898
Industrial	Industrial	108,267		101,567		105,020		Industrial	116,712		108,267		101,567
Other customers	Other customers	18,067		18,182		18,408		Other customers	18,734		18,067		18,182
Total operating revenue from customers	Total operating revenue from customers	2,347,582		2,097,660		2,117,694		Total operating revenue from customers	2,498,474		2,347,582		2,097,660
Transportation, including unbilled	Transportation, including unbilled	19,987		19,682		19,512		Transportation, including unbilled	22,353		19,987		19,682
Sales to other utilities and marketers	Sales to other utilities and marketers	154,533		68,198		109,105		Sales to other utilities and marketers	329,589		154,533		68,198
Decoupling revenue	Decoupling revenue	(12,452)		49,632		15,673		Decoupling revenue	(37,423)		(12,452)		49,632
Other decoupling revenue1	Other decoupling revenue1	(17,506)		(27,053)		(6,866)		Other decoupling revenue1	(12,067)		(17,506)		(27,053)
Miscellaneous operating revenue	Miscellaneous operating revenue	179,479		111,297		241,923		Miscellaneous operating revenue	160,531		179,479		111,297
Total electric operating revenue	Total electric operating revenue	$	2,671,623	$	2,319,416	$	2,497,041	Total electric operating revenue	$	2,961,457	$	2,671,623	$	2,319,416
Number of customers served (average):	Number of customers served (average):							Number of customers served (average):
Residential	Residential	1,053,027		1,039,596		1,025,024		Residential	1,065,508		1,053,027		1,039,596
Commercial	Commercial	132,581		130,924		129,944		Commercial	133,521		132,581		130,924
Industrial	Industrial	3,267		3,289		3,328		Industrial	3,222		3,267		3,289
Other	Other	7,886		7,668		7,323		Other	8,047		7,886		7,668
Transportation	Transportation	98		100		80		Transportation	104		98		100
Total customers	Total customers	1,196,859		1,181,577		1,165,699		Total customers	1,210,402		1,196,859		1,181,577

_______________

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,
		2021			2020			2019				2022			2021			2020
Average kWh used per customer:	Average kWh used per customer:										Average kWh used per customer:
Residential	Residential	10,901			10,558			10,494			Residential	11,030			10,901			10,558
Commercial	Commercial	63,373			60,663			68,010			Commercial	64,987			63,373			60,663
Industrial	Industrial	331,410			333,206			348,903			Industrial	345,720			331,410			333,206
Other	Other	10,144			10,597			11,649			Other	9,495			10,144			10,597
Average revenue per customer:	Average revenue per customer:										Average revenue per customer:
Residential	Residential	$	1,252		$	1,141		$	1,112		Residential	$	1,297		$	1,252		$	1,141
Commercial	Commercial	6,810			6,049			6,579			Commercial	7,348			6,810			6,049
Industrial	Industrial	33,140			30,881			31,556			Industrial	36,223			33,140			30,881
Other	Other	2,291			2,371			2,514			Other	2,328			2,291			2,371
Average retail revenue per kWh sold:	Average retail revenue per kWh sold:										Average retail revenue per kWh sold:
Residential	Residential	$	0.1148		$	0.1081		$	0.1059		Residential	$	0.1176		$	0.1148		$	0.1081
Commercial	Commercial	0.1075			0.0997			0.0967			Commercial	0.1131			0.1075			0.0997
Industrial	Industrial	0.1000			0.0927			0.0904			Industrial	0.1048			0.1000			0.0927
Other	Other	0.2258			0.2237			0.2158			Other	0.2452			0.2258			0.2237
Average retail revenue per kWh sold	Average retail revenue per kWh sold	$	0.1116		$	0.1044		$	0.1016		Average retail revenue per kWh sold	$	0.1156		$	0.1116		$	0.1044
Heating degree days	Heating degree days	4,471			4,122			4,208			Heating degree days	4,715			4,471			4,122
Percent of normal - NOAA1 30-year average	Percent of normal - NOAA1 30-year average	99.2		%	87.8		%	89.6		%	Percent of normal - NOAA1 30-year average	105.2		%	99.2		%	87.8		%
Load factor2	Load factor2	59.7		%	62.1		%	61.6		%	Load factor2	58.7		%	59.7		%	62.1		%

_______________

1.National Oceanic and Atmospheric Administration (NOAA).

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

Electric Supply

At December 31, ~~2021,~~2022, PSE’s electric power resources, which include company-owned or controlled resources as well as those under long-term contract, had a total capacity of approximately ~~4,809~~6,565 megawatts (MW). In order to meet an extreme winter peak load, PSE may supplement its electric power resources with winter-peaking call options and other instruments. When it is more economical for PSE to purchase power than to operate its own generation facilities, PSE will purchase spot market energy when sufficient transmission capacity is available.

The following table shows PSE’s electric energy supply resources and energy production for the years ended December 31, ~~2021,~~2022, and ~~2020:~~2021:


		Peak Power Resources At December 31,				Energy Production At December 31,					Peak Power Resources At December 31,				Energy Production At December 31,
		2021		2020		2021		2020			2022		2021		2022		2021
		MW	%	MW	%	MWh	%	MWh	%		MW	%	MW	%	MWh	%	MWh	%
Purchased resources:	Purchased resources:									Purchased resources:
Columbia River PUD contracts1	Columbia River PUD contracts1	681	14.2%	685	14.3%	3,458,996	13.3%	3,796,841	15.3%	Columbia River PUD contracts1	856	13.0%	681	14.2%	4,351,894	16.4%	3,458,996	13.3%
Other hydroelectric	Other hydroelectric	111	2.3	111	2.3	529,239	2.0	583,514	2.3	Other hydroelectric	99	1.5	111	2.3	497,229	1.9	529,239	2.0
Other producers	Other producers	485	10.1	485	10.1	2,990,615	11.4	2,704,663	10.9	Other producers	1,352	20.6	468	9.7	4,224,027	15.9	2,863,684	10.9
Wind		193	4.0	193	4.0	934,634	3.6	300,886	1.2
Wind/solar										Wind/solar	902	13.7	193	4.0	1,419,839	5.3	934,634	3.6
Biomass										Biomass	17	0.3	17	0.4	83,814	0.3	126,931	0.5
Short-term wholesale energy purchases	Short-term wholesale energy purchases	N/A	—	N/A	—	5,202,413	20.0	5,768,251	23.2	Short-term wholesale energy purchases	N/A	—	N/A	—	4,767,460	18.0	5,202,413	20.0
Total purchased	Total purchased	1,470	30.6%	1,474	30.7%	13,115,897	50.3%	13,154,155	52.9%	Total purchased	3,226	49.0%	1,470	30.6%	15,344,263	57.8%	13,115,897	50.3%
Company-controlled resources:	Company-controlled resources:									Company-controlled resources:
Hydroelectric	Hydroelectric	263	5.5%	250	5.3%	957,818	3.7%	980,194	3.9%	Hydroelectric	263	4.0%	263	5.5%	758,615	2.9%	957,818	3.7%
Coal	Coal	370	7.7	370	7.7	2,576,702	9.9	2,102,338	8.5	Coal	370	5.6	370	7.7	2,726,665	10.3	2,576,702	9.9
Natural gas/oil	Natural gas/oil	1,931	40.1	1,931	40.2	7,341,077	28.1	6,402,647	25.8	Natural gas/oil	1,931	29.5	1,931	40.1	6,028,682	22.7	7,341,077	28.1
Wind		773	16.1	773	16.1	2,073,787	8.0	2,215,739	8.9
Wind/solar										Wind/solar	773	11.8	773	16.1	1,684,974	6.3	2,073,787	8.0
Other2	Other2	2	—	2	—	—	—	—	—	Other2	2	—	2	—	—	—	—	—
Total company-controlled	Total company-controlled	3,339	69.4%	3,326	69.3%	12,949,384	49.7%	11,700,918	47.1%	Total company-controlled	3,339	51.0%	3,339	69.4%	11,198,936	42.2%	12,949,384	49.7%
Total resources	Total resources	4,809	100.0%	4,800	100.0%	26,065,281	100.0%	24,855,073	100.0%	Total resources	6,565	100.0%	4,809	100.0%	26,543,199	100.0%	26,065,281	100.0%

_______________

1.Net of 4140 MW and 3741 MW capacity delivered to Canada pursuant to the provisions of a treaty between Canada and the United States and Canadian Entitlement Allocation agreements as of December 31, ~~2021,~~2022, and ~~2020,~~2021, respectively.

2.It is estimated that the Glacier Battery Storage has delivered approximately ~~1,603.6~~1,646.9 and ~~1,468.2~~1,603.6 MWh as of December 31, ~~2021,~~2022, and ~~2020,~~2021, respectively.

Company–Owned Electric Generation Resources

At December 31, ~~2021,~~2022, PSE owns the following plants with an aggregate net generating capacity of 3,339 MW:

Plant Name

Plant Type

Net Maximum

Capacity (MW)1

Year Installed

Colstrip Units 3 & 4 (25% interest)

Coal

370

1984 & 1986

Mint Farm

Natural gas combined cycle

320

2007; acquired 2008; upgraded 2017

Goldendale

Natural gas combined cycle

315

2004, acquired 2007, upgraded 2016

Frederickson Unit 1 (49.85% interest)

Natural gas combined cycle

136

2002; added duct firing 2005

Lower Snake River

Wind

343

2012

Wild Horse

Wind

273

2006 & 2009

Hopkins Ridge

Wind

157

2005 & 2008

Fredonia Units 1 & 2

Dual-fuel combustion turbines

207

1984

Frederickson Units 1 & 2

Dual-fuel combustion turbines

149

1981

Whitehorn Units 2 & 3

Dual-fuel combustion turbines

149

1981

Fredonia Units 3 & 4

Dual-fuel combustion turbines

107

2001

Ferndale

Natural gas co-generation

253

1994; acquired 2012

Encogen

Natural gas co-generation

165

1993; acquired 1999

Sumas

Natural gas co-generation

127

1993; acquired 2008

Upper Baker River

Hydroelectric

104

1959; unit 2 upgraded 1997, uprated 2021

Lower Baker River

Hydroelectric

105

1925: reconstructed 1960; upgraded 2001 and 2013

Snoqualmie Falls2

Hydroelectric

1898 to 1911 & 1957; rebuilt 2013

Crystal Mountain

Internal combustion

1969

Glacier Battery Storage

Lithium Iron Phosphate

2016

Total Net Capacity

3,339

_______________

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

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

Columbia River Electric Energy Supply Contracts

During ~~2021,~~2022, approximately ~~13.3%~~16.4% of PSE’s energy supply was obtained through long-term contracts with three Washington Public Utility Districts (PUDs) that own and operate hydroelectric projects on the Columbia River (Mid-Columbia). PSE’s payments are not contingent upon the projects being operable.

For the year ended, December 31, ~~2021,~~2022, PSE's portion of the power output of the PUDs’ projects are set forth below:
Company’s Annual Share (Approximate)
Project Contract Expiration Year License Expiration Year Percent of Output MW Capacity
Chelan County PUD:
Rock Island Project 2031 2029 25.0 % 156
Rocky Reach Project 2031 2052 25.0 325
Douglas County PUD:
Wells Project 2028 2052 24.2 203
Grant County PUD:
Priest Rapids Development 2052 2052 0.6 6
Wanapum Development 2052 2052 0.6 7
Total 697


			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	30.0	%	187
Rocky Reach Project	2031	2052	30.0		390
Douglas County PUD:
Wells Project	2028	2052	26.4		222
Grant County PUD:
Priest Rapids Development	2052	2052	4.8		45
Wanapum Development	2052	2052	4.8		52
Total					896

Other Electric Supply, Exchange and Transmission Contracts and Agreements

PSE purchases electric energy under long-term firm purchased power contracts with other utilities and marketers in the Western region. PSE is generally not obligated to make payments under these contracts unless power is delivered. PSE also has an agreement with Pacific Gas & Electric Company (PG&E) for 300 MW of seasonal capacity exchange which, ~~currently has no set expiration.~~on November 14, 2022, PSE submitted a notice of termination with an effective date of December 31, 2027. During and since emerging from its 2001-2004 and 2019-2020 bankruptcy proceedings, PG&E delivered on the energy exchange contract and has continued to meet the exchange contract through its current bankruptcy proceedings.

PSE began participating in the Energy Imbalance Market (EIM) operated by the California Independent System Operator on October 1, 2016. PSE has committed up to 450 MW of existing BPA transmission for the EIM market. Participation has resulted in reduced costs for PSE customers of approximately ~~$20.7~~$31.1 million in year ended December 31, ~~2021,~~2022, enhanced system reliability, integration of variable energy resources, and geographic diversity of electricity demand and generation resources. The calculated benefits represent the annual cost savings of the EIM dispatch compared with a counter-factual dispatch without the EIM. Benefits can take the form of cost savings or revenues or their combination. Benefits include greenhouse gases (GHG) revenue, transfer revenues and flexible ramping revenues.

PSE has entered into multiple various-term transmission contracts with other utilities to integrate electric generation and contracted resources into PSE’s system. These transmission contracts require PSE to pay for transmission service based on the contracted MW level of demand, regardless of actual use. Other transmission agreements provide actual capacity ownership or capacity ownership rights. PSE’s annual charges under these agreements are also based on contracted MW volumes. Capacity on these agreements that is not committed to serve PSE’s load is available for sale to third parties. PSE also purchases short-term transmission services from a variety of providers, including the BPA.

In ~~2021,~~2022, PSE had ~~4,897~~5,007 MW and 595 MW of total transmission demand contracted with the BPA and other utilities, respectively. PSE’s remaining transmission capacity needs are met via PSE owned transmission assets.

Natural Gas Supply for Electric Customers

PSE purchases natural gas supplies for its power portfolio to meet electrical demand through gas-fired generation. Supplies range from long-term to daily agreements, as turbine fueling varies depending on market heat rates. Purchases are made from a diverse group of major and independent natural gas producers and marketers in the United States and Canada. PSE also enters into financial hedges to manage the cost of natural gas. PSE utilizes natural gas storage capacity and transportation that is dedicated to and paid for by the power portfolio to facilitate increased natural gas supply reliability and intra-day dispatch of PSE’s natural gas-fired generation resources.

The following table presents the volumes of natural gas for power ~~year ended~~ inventory ~~values:~~value as of December 31, 2022 and 2021:

Year Ended December 31,
2021 2020 2019
Natural gas volumes for power in storage at year end, therms (thousands):
Jackson Prairie 5,237 5,603 4,628
Plymouth 1,552 2,345 2,136


	At December 31,
	2022	2021
Natural gas volumes for power in storage at year end, therms (thousands):
Jackson Prairie	5,450	5,237
Plymouth LNG (in LNG form)	1,223	1,552

Integrated Resource Plans, Resource Acquisition and Development

~~PSE is required by~~The 2021 Integrated Resource Plan marked a major departure from past Integrated Resource Plans (IRP) due in large part to the passage of CETA. The new electric progress report rules, Washington ~~Commission regulations to file an electric~~Administrative Code 480-100-625 Integrated Resource Plan Development and ~~natural gas integrated resource plan (IRP)~~Timing, outlines the requirements for this report. The two-year progress report must be filed at least every two ~~years. Requests for proposals for generation resources are required to~~years after the utility files it’s IRP. The final 2023 Electric Progress Report will be filed ~~with~~March 31, 2023. For the ~~Washington Commission prior to being issued. The final 2021 IRP and~~draft 2023 Progress Report, the ~~2021 Request for Proposals for All Resources (All-source RFP) were both filed on April 1, 2021.From the 2021 All-source RFP, Table 2,~~ cumulative capacity need by year, the capacity shortfalls and surpluses are:

2022 2023 2024 2025
Projected MW shortfall/(surplus) (230) (350) (306) (257)


	2023	2024	2025	2026	2027
Projected MW shortfall/(surplus)	(200)	174	465	1,336	1,848

~~PSE projects its future energy needs will not exceed~~

PSE’s current ~~resources in its supply~~transmission portfolio ~~until 2026 because~~includes approximately 1,500 MW of ~~the addition of new resources~~firm transmission rights that deliver energy from the ~~2018 RFP.~~Mid‐Columbia trading hub to the PSE load center. Due to growing regional concerns pertaining to capacity within the short-term market, PSE will phase out its reliance on firm short-term market purchases by over 200 MW per year starting in 2024 until PSE reaches zero reliance by 2029. With the expected elimination of Colstrip units 3 & 4 from PSE’s energy supply portfolio starting in 2026, which removes approximately 370 MW of capacity, and the expiration of PSE’s 380 MW coal-transition contract with TransAlta when the Centralia coal plant is retired at the end of 2025, the projected capacity shortfall ~~will be 369~~of 174 MW in 2024 increases to 1,336 MW and ~~increases to 527~~1,848 MW by 2026 and 2027, ~~a large increase from the surplus capacity in 2025.~~respectively. The expected capacity needs reflect the mix of energy efficiency programs deemed cost effective in the ~~2021 IRP.~~2023 Progress Report. As part of the Washington ~~Clean Energy Transformation Act (CETA),~~CETA, PSE must achieve sales with renewable or non-emitting resources of at least 80% by 2030 and 100% by 2045.~~PSE’s current transmission portfolio includes approximately 1,500 MW of firm transmission rights~~

On February 10, 2023 the FERC approved a voluntary regional resource adequacy program that ~~deliver energy from the Mid‐Columbia trading hub~~PSE plans to ~~the PSE load center. The 2021 IRP included a market risk assessment that evaluated the ongoing availability of the short‐term power contracts associated~~participate in along with ~~the transmission rights.The table above assumes all 1,500 MW of firm transmission is available to procure at market for meeting PSE’s peak need.The assessment~~other utilities in the ~~IRP proposed a decrease~~Western United States and Canada. The program is intended to ~~500 MW~~help the region anticipate its future power supply needs as natural gas-fired and coal power plants retire and are replaced by ~~the year 2027.This would change the resource shortfall to 185 MW in 2023~~variable renewable energy resources such as wind and ~~increasing to a 574 MW shortfall by 2025.~~solar.

NATURAL GAS UTILITY OPERATING STATISTICS


		Year Ended December 31,							Year Ended December 31,
		2021		2020		2019			2022		2021		2020
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	Residential	$	722,002	$	662,502	$	613,617	Residential	$	808,376	$	722,002	$	662,502
Commercial firm	Commercial firm	270,708		232,306		218,302		Commercial firm	324,743		270,708		232,306
Industrial firm	Industrial firm	19,664		17,662		15,698		Industrial firm	22,965		19,664		17,662
Interruptible	Interruptible	23,571		22,622		18,381		Interruptible	29,582		23,571		22,622
Total retail natural gas sales	Total retail natural gas sales	1,035,945		935,092		865,998		Total retail natural gas sales	1,185,666		1,035,945		935,092
Transportation services	Transportation services	20,104		17,296		20,283		Transportation services	20,381		20,104		17,296
Decoupling revenue	Decoupling revenue	10,254		18,906		2,296		Decoupling revenue	(4,008)		10,254		18,906
Other decoupling revenue1	Other decoupling revenue1	(11,807)		(6,478)		(29,737)		Other decoupling revenue1	(15,561)		(11,807)		(6,478)
Other	Other	12,922		16,097		16,531		Other	23,158		12,922		16,097
Total natural gas operating revenue	Total natural gas operating revenue	$	1,067,418	$	980,913	$	875,371	Total natural gas operating revenue	$	1,209,636	$	1,067,418	$	980,913
Number of customers served (average):	Number of customers served (average):							Number of customers served (average):
Residential	Residential	801,186		791,612		782,413		Residential	809,965		801,186		791,612
Commercial firm	Commercial firm	56,477		56,303		56,113		Commercial firm	56,824		56,477		56,303
Industrial firm	Industrial firm	2,277		2,293		2,304		Industrial firm	2,260		2,277		2,293
Interruptible	Interruptible	278		288		367		Interruptible	272		278		288
Transportation	Transportation	220		224		230		Transportation	211		220		224
Total customers	Total customers	860,438		850,720		841,427		Total customers	869,532		860,438		850,720
Natural gas volumes, therms (thousands):	Natural gas volumes, therms (thousands):							Natural gas volumes, therms (thousands):
Residential	Residential	611,028		592,811		605,313		Residential	632,145		611,028		592,811
Commercial firm	Commercial firm	270,022		250,611		277,639		Commercial firm	294,879		270,022		250,611
Industrial firm	Industrial firm	22,794		21,946		22,915		Industrial firm	23,467		22,794		21,946
Interruptible	Interruptible	46,115		45,240		45,176		Interruptible	49,322		46,115		45,240
Total retail natural gas volumes, therms	Total retail natural gas volumes, therms	949,959		910,608		951,043		Total retail natural gas volumes, therms	999,813		949,959		910,608
Transportation volumes	Transportation volumes	219,805		212,330		227,657		Transportation volumes	219,059		219,805		212,330
Total volumes	Total volumes	1,169,764		1,122,938		1,178,700		Total volumes	1,218,872		1,169,764		1,122,938

_______________

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

NATURAL GAS UTILITY OPERATING STATISTICS (Continued)

Year Ended December 31,
2021 2020 2019
Working natural gas volumes in storage at year end, therms (thousands):
Jackson Prairie 82,080 78,016 82,892
Clay Basin 74,540 80,736 77,532
Average therms used per customer:
Residential 763 749 774
Commercial firm 4,781 4,451 4,948
Industrial firm 10,011 9,571 9,946
Interruptible 165,881 157,083 123,095
Transportation 999,114 947,902 989,813
Average revenue per customer:
Residential $ 901 $ 837 $ 784
Commercial firm 4,793 4,126 3,890
Industrial firm 8,636 7,703 6,813
Interruptible 84,788 78,549 50,084
Transportation 91,382 77,214 88,187
Average revenue per therm sold:
Residential $ 1.182 $ 1.118 $ 1.014
Commercial firm 1.003 0.927 0.786
Industrial firm 0.863 0.805 0.685
Interruptible 0.511 0.500 0.407
Average retail revenue per therm sold $ 1.091 $ 1.027 $ 0.911
Transportation 0.091 0.081 0.089
Heating degree days 4,471 4,122 4,208
Percent of normal - NOAA 30-year average 99.2 % 87.8 % 89.6 %


	Year Ended December 31,
	2022			2021			2020
Working natural gas volumes in storage at year end, therms (thousands):
Jackson Prairie	79,463			82,080			78,016
Clay Basin	80,242			74,540			80,736
Tacoma LNG (in LNG form)	228			—			—
Gig Harbor LNG (in LNG form)	5			6			9
Average therms used per customer:
Residential	780			763			749
Commercial firm	5,189			4,781			4,451
Industrial firm	10,384			10,011			9,571
Interruptible	181,331			165,881			157,083
Transportation	1,038,194			999,114			947,902
Average revenue per customer:
Residential	$	998		$	901		$	837
Commercial firm	5,715			4,793			4,126
Industrial firm	10,162			8,636			7,703
Interruptible	108,757			84,788			78,549
Transportation	96,592			91,382			77,214
Average revenue per therm sold:
Residential	$	1.279		$	1.182		$	1.118
Commercial firm	1.101			1.003			0.927
Industrial firm	0.979			0.863			0.805
Interruptible	0.600			0.511			0.500
Average retail revenue per therm sold	$	1.186		$	1.091		$	1.027
Transportation	0.093			0.091			0.081
Heating degree days	4,715			4,471			4,122
Percent of normal - NOAA 30-year average	105.2		%	99.2		%	87.8		%

NATURAL GAS FOR NATURAL GAS CUSTOMERS AND ELECTRIC CUSTOMERS

Natural Gas Supply for Natural Gas Customers

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

For base load, peak management and supply reliability purposes, PSE supplements its firm natural gas supply portfolio by purchasing natural gas in periods of lower demand, injecting it into underground storage facilities and withdrawing it during periods of high demand or reduced supply. Underground storage facilities at Jackson Prairie in western Washington and at Clay Basin in Utah are used for this purpose. Clay Basin withdrawals are used to supplement purchases from the U.S. Rocky Mountain supply region, while Jackson Prairie provides incremental peak-day resources utilizing firm storage redelivery transportation capacity. Jackson Prairie is also used for daily balancing of load requirements on PSE’s natural gas system. Peaking needs are also met by using PSE-owned natural gas held in PSE’s Tacoma LNG peaking facility and the Gig Harbor satellite LNG peaking facility, both located within its distribution ~~system in Gig Harbor, Washington;~~system; as well as interrupting service to customers on interruptible service rates, if necessary.

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

PSE’s firm natural gas supply portfolio has ~~adequate~~ flexibility in its transportation arrangements to enable it to achieve savings when there are regional price differentials between natural gas supply basins. The geographic mix of suppliers and daily, monthly and annual take requirements permit some degree of flexibility in managing natural gas supplies during periods of lower demand to minimize costs. Natural gas is marketed outside of PSE’s service territory (off-system sales) to optimize resources when on-system customer demand requirements permit and market economics are favorable; the resulting economics of these transactions are reflected in PSE’s natural gas customer tariff rates through the PGA mechanism.

Natural Gas Storage Capacity

PSE holds storage capacity in the Jackson Prairie and Clay Basin underground natural gas storage facilities adjacent to NWP’s pipeline to serve PSE’s natural gas customers. The Jackson Prairie facility is operated and one-third owned by PSE, and is used primarily for intermediate peaking purposes due to its ability to deliver a large volume of natural gas in a short time period. Combined with capacity contracted from NWP’s one-third stake in Jackson Prairie, PSE holds firm withdrawal capacity of 453,800 Dekatherm (Dth) per day, and over 9.8 million Dth of storage capacity at the Jackson Prairie facility. Of this total, PSE designates 397,100 Dth per day of the firm withdrawal capacity and over 9.2 million Dth of storage capacity to serve natural gas customers. The location of the Jackson Prairie facility in PSE’s market area increases supply reliability and provides significant pipeline demand cost savings by reducing the amount of annual pipeline capacity required to meet peak-day natural gas requirements.

Of the remaining Jackson Prairie storage capacity, 56,700 Dth per day of firm withdrawal capacity and 640,600 Dth of storage capacity is currently designated to PSE's power portfolio, increasing natural gas supply reliability and facilitating intra-day dispatch of PSE's natural gas-fired generation resources.

The Clay Basin storage facility is a supply area storage facility that provides operational flexibility and price protection. PSE holds 12.9 million Dth of Clay Basin storage capacity and approximately 107,400 Dth per day of firm withdrawal capacity under two long-term contracts with remaining terms of ~~one year~~five years and has rights to extend such agreements.

LNG and Propane-Air Resources

LNG and propane-air resources provide firm natural gas supply on short notice for short periods of time. Due to their typically high cost and slow cycle times, these resources are normally utilized as a last resort supply source in extreme peak-demand periods, typically during the coldest hours or days.

PSE holds a contract for LNG storage services of 241,700 Dth of PSE-owned natural gas at Plymouth, with a maximum daily deliverability of 70,500 Dth for use of the PSE generation fleet. PSE uses the Plymouth contract as an alternate supply source for natural gas required to serve PSE’s generation fleet during peak periods on a daily or intra-day basis. In addition, PSE holds 15,000 Dth/day of firm pipeline capacity from Plymouth for the generation fleet. The balance of the LNG capacity is delivered using firm NWP pipeline transportation service previously acquired to serve PSE’s generation fleet.

PSE owns and operates an LNG peaking facility in Gig Harbor, Washington, with total storage capacity of 10,600 Dth, which is capable of delivering 2,500 Dth of natural gas per day.

Tacoma LNG Facility

~~The~~On February 1, 2022, the Tacoma LNG facility at the Port of Tacoma completed commissioning ~~on February 1, 2022~~ and ~~is expected to commence~~commenced commercial operations in the first quarter of 2022. In December 2019, the Puget Sound Clean Air Agency (PSCAA) issued the air quality permit for the facility, and the Pollution Hearings Control Board of Washington State upheld the approval following extended litigation. When in-service, theoperations. The Tacoma LNG facility ~~will provide~~provides peak-shaving services to PSE’s natural gas customers, and ~~provide~~provides LNG as fuel to transportation customers via Puget Energy's non-regulated subsidiary Puget LNG, particularly in the marine market at a lower cost due to the facility's scale. Pursuant to an order by the Washington Commission, PSE ~~will be~~is allocated 43.0% of the capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility, and Puget LNG ~~will be~~is allocated the remaining 57.0% of the capital and operating costs. The portion of the Tacoma LNG facility allocated to PSE ~~will be~~is subject to regulation by the Washington Commission. In December 2022, the Washington Commission approved and authorized PSE to seek recovery of costs related to the Tacoma LNG Facility concurrent with its 2023 PGA filing.

Natural Gas Transportation Capacity

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

PSE holds approximately 542,900 Dth per day of capacity for its natural gas customers on NWP that provides firm year-round delivery to PSE’s service territory. In addition, PSE holds approximately 447,100 Dth per day of seasonal firm capacity on NWP to provide for delivery of natural gas stored at Jackson Prairie to natural gas customers. PSE holds approximately 202,900 Dth per day of firm transportation capacity on NWP to supply natural gas to its electric generating facilities. In addition, PSE holds over 34,200 Dth per day of seasonal firm capacity on NWP to provide for delivery of natural gas stored in Jackson Prairie for its electric generating facilities. PSE’s firm transportation capacity contracts with NWP have remaining terms ranging from one to 2322 years. However, PSE has either the unilateral right to extend the contracts under the contracts’ current terms or the right of first refusal to extend such contracts under current FERC rules.

PSE’s firm transportation capacity for its natural gas customers on Westcoast’s pipeline is 135,800 Dth per day under various contracts, with remaining terms of two to ~~four~~three years. PSE has other firm transportation capacity on Westcoast’s pipeline, which supplies the electric generating facilities, totaling 88,400 Dth per day, with remaining terms of ~~two to four~~three years and an option for PSE to renew its rights under the Westcoast contract. PSE has firm transportation capacity for its natural gas customers on NOVA and Foothills pipelines, each totaling approximately 79,000 Dth per day, with remaining terms of ~~two to four~~three years and an option for PSE to renew its rights on the capacity on NOVA and Foothills pipelines. PSE has other firm transportation capacity on NOVA and Foothills pipelines, which supplies the electric generating facilities, each totaling approximately 41,000 Dth per day, with remaining term of ~~two~~six years. PSE’s firm transportation capacity for its natural gas customers on the GTN pipeline, totaling over 77,000 Dth per day, with remaining term of ~~two years~~one year and PSE has a first right-of-refusal to extend such contracts under current FERC rules. PSE has other firm transportation capacity on GTN pipeline, which supplies the electric generating facilities, totaling 40,600 Dth per day, with remaining terms of ~~two years.~~one year. PSE holds 259,000 Dth per day of firm capacity on CNGC to connect generating facilities to the pipeline grid with remaining terms of one year.

Capacity Release

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

Energy Efficiency

PSE is required under Washington state law to pursue all available electric conservation that is cost-effective, reliable and feasible. PSE offers programs designed to help new and existing residential, commercial and industrial customers use energy efficiently. PSE uses a variety of mechanisms including cost-effective financial incentives, information and technical services to enable customers to make energy efficient choices with respect to building design, equipment and building systems, appliance purchases and operating practices. PSE recovers the actual costs of its electric and natural gas energy efficiency

programs through rider mechanisms. However, the rider mechanisms do not provide assistance with gross margin erosion associated with reduced energy sales. To address this issue, PSE received approval in 2017 from the Washington Commission for continuation of electric and natural gas decoupling mechanisms, which mitigates gross margin erosion resulting from the Company's energy efficiency efforts. The decoupling mechanisms, as approved in 2022 GRC Final Order in Dockets No. UE-220066 and UG-220067 commenced January 7, 2023 for natural gas and January 11, 2023 for electric and will remain in place permanently until such time that PSE proposes and the Washington Commission approves to have them discontinued or modified.

Environment

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

Air and Climate Change Protection

PSE owns numerous thermal generation facilities, including natural gas plants and an ownership percentage of Colstrip. All of ~~these facilities~~the natural gas plants and Colstrip are governed by the Clean Air Act (CAA), and all have CAA Title V operating permits, which must be renewed every five years. This renewal process could result in additional costs to the plants. PSE continues to monitor the permit renewal process to determine the corresponding potential impact to the plants. These facilities also emit ~~GHG,~~GHGs, and thus are also subject to any current or future GHG or climate change legislation or ~~regulation.~~regulation including the Washington State Climate Commitment Act (CCA) and Washington State Clean Energy Transformation Act (CETA). The Colstrip plant represents PSE’s most significant source of GHG emissions.

Species Protection

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

Remediation

PSE and its predecessors are responsible for environmental remediation at various sites. These include properties currently and formerly owned by PSE (or its predecessors), as well as third-party owned properties where hazardous substances were allegedly generated, transported or released. The primary cleanup laws to which PSE is subject include the Comprehensive Environmental Response, Compensation and Liability Act (federal) and, in Washington, the Model Toxics Control Act (state). PSE is also subject to applicable remediation laws in the state of Montana for its ownership interest in Colstrip. Under all of these laws, PSE may be subject to agency orders to carry out site remediation. These laws ~~may hold liable~~impose joint and several liability on any current or past owner or operator of a contaminated site, transporters, as well as any entity that generated and disposed of (or arranged for the disposal of) hazardous or other regulated substances at a contaminated site.

Hazardous and Solid Waste and ~~PCB~~Polychlorinated Biphenyl (PCB) Handling and Disposal

Related to certain operations, including power generation and transmission and distribution maintenance, PSE must handle and dispose of certain hazardous and solid ~~wastes.~~wastes, including PCB waste from pre-1979 electrical equipment. These actions are regulated by the Solid Waste Disposal Act (as amended by the Resource Conservation and Recovery Act), the Toxic Substances Control Act (federal) and hazardous or dangerous waste regulations (state) that impose complex requirements on handling and disposing of regulated substances.

Water Protection

PSE facilities that discharge wastewater or storm water or store bulk petroleum products, ~~to regulated waters~~and PSE construction projects above a certain threshold are governed by the Clean Water Act (federal and state), which includes the Oil Pollution Act amendments. This includes most generation facilities (and all of those with water discharges and some with bulk fuel storage), and many other facilities and construction projects depending on drainage, facility or construction activities, and chemical, petroleum and material storage.

Mercury Emissions

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

Siting New Facilities

In siting new generation, transmission, distribution or other related facilities in Washington, PSE is subject to the State Environmental Policy Act, and may be subject to the federal National Environmental Policy Act if there is a federal nexus, in addition to other possible state laws and local siting, critical area and zoning ordinances. Such facilities may also be subject to federal environmental regulations. These requirements may potentially require mitigation of environmental impacts as well as other measures that can add significant cost to new facilities.

Recent and Future Environmental Law and Regulation

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

Climate Change and Greenhouse Gas Emissions

PSE implements both short-term measures and long-term strategies designed to manage GHG emissions in a scientifically sound and responsible fashion. The Company has worked closely with federal, state and local governments on deep decarbonization and the reduction and mitigation of GHG ~~emissions.~~emissions, including passage of CETA and CCA. As a result, the Company ~~intends and expects~~announced a goal to be ~~net zero methane emissions by the end of 2022,~~ coal free by 2025, net zero carbon emissions for electric and ~~its~~natural gas operations (methane leaks from pipeline system) as well as electric ~~system will be carbon neutral~~supply by 2030. Further, the Company has an aspirational goal to be ~~beyond~~ net zero by 2045 for ~~electric supply,~~natural gas sales and ~~operations. The Company is also~~to go beyond reducing PSE's GHG footprint by helping Washington State address GHG emissions from the transportation sector by investing in electric vehicles and developing liquefied natural gas for maritime and commercial transportation. PSE also remains mindful of our customers' expectation of reliable, affordable service. The Company considers the cost of the decarbonization efforts to date, as well as future efforts, in its IRP process, and will continue to engage in climate and GHG policy development.

PSE's Greenhouse Gas Emission Reporting

PSE is required to submit, on an annual basis, a report of its GHG emissions to the state of Washington Department of Ecology including a report of emissions from all individual power plants emitting over 10,000 tons per year of GHGs and from certain natural gas distribution facilities and operations. Emissions exceeding 25,000 tons per year of GHGs from these sources must also be reported to the U.S. Environmental Protection Agency (EPA). Capital investments to monitor GHGs from the power plants and in the distribution system are not required at this time. Since 2002, PSE has voluntarily undertaken an annual inventory of its GHG emissions associated with PSE’s total electric retail load served from a supply portfolio of owned and purchased resources.

The most recent data indicate that PSE’s total GHG emissions (direct and indirect) from its electric supply portfolio in ~~2020~~2021 were ~~8.3~~9.1 million metric tons of carbon dioxide equivalents. Approximately ~~25.3%~~27.5% of PSE’s total GHG emissions (approximately ~~2.1~~2.5 million metric tons) are associated with PSE’s ownership and contractual interests in Colstrip. Compared to ~~2019,~~2020, total emissions ~~decreased appreciably,~~increased by ~~26.2%~~9.0%. This trend is due primarily to ~~the retirement of~~an increase in output from Colstrip Units 13 and ~~3, totaling 307 MW of coal capacity, effective December 31, 2019.~~4 and an increase in output from the natural gas thermal fleet. PSE’s overall emissions strategy ~~demonstrates~~continues to demonstrate a concerted effort to manage customers’ needs with an appropriate balance of new renewable generation, existing generation owned and/or operated by PSE and significant energy efficiency efforts.

Executive Orders Addressing Environmental Issues

President Joseph Biden issued several executive orders in January 2021 that are likely to affect PSE’s environmental obligations. The ~~new~~ executive orders revoked several existing executive orders and established new federal environmental mandates, including rejoining the Paris Agreement on climate change, which requires commitments to reduce GHG emissions, among other things.

Inflation Reduction Act

24On August 16, 2022, the Inflation Reduction Act (IRA) was signed into public law. The IRA is intended to lower gasoline and electricity prices, increase energy security, and help consumers to afford emission-cutting technologies. In addition, the IRA will provide tax credits for clean electricity sources and renewable technologies, such as solar and wind. As of December 31, 2022, the IRA had no material financial impact on the Company, however the Company continues to assess the potential impacts of the legislation.

Federal Greenhouse Gas Rules: New and Existing Power Plants

The EPA sets rules that apply to both new and existing power plants regarding GHGs. In 2015, the EPA set a final rule regarding New Source Performance Standards (NSPS) for the control of carbon dioxide (CO2) from new power plants that burn fossil fuels under section 111(b) of the ~~Clean Air Act.~~CAA. New natural gas power plants can emit no more than 1,000 lbs. of CO2/megawatt hour (MWh) which is achievable with the latest combined cycle technology. New coal power plants can emit no more than 1,400 lbs. of CO2/MWh. Carbon Dioxide Capture and Sequestration (CCS) was reaffirmed by the EPA in this rule as the “best system of emission reductions” (BSER). In 2018, due to the high cost and limited geographic availability of CCS, EPA issued a proposed rule that the BSER for newly constructed coal-fired units is the most efficient demonstrated steam cycle in combination with the best operating practices, but did not take action on a final rule nor has EPA proposed to amend the NSPS. In January 2021, EPA issued a framework for determining when standards are appropriate for GHG emissions from stationary source categories under ~~Clean Air Act~~CAA section 111(b)(1)(A).

In August 2015, the EPA issued a final rule under Section 111(d) of the ~~Clean Air Act,~~CAA, referred to as the Clean Power Plan (CPP), to regulate GHG emissions from existing power plants. The proposed rule includes state-specific goals and guidelines for states to develop plans for meeting these goals.

In June 2019, the EPA repealed the CPP rule and finalized the Affordable Clean Energy (ACE) rule, pursuant to Section 111(d) of the Clean Air Act as a CPP rule replacement. The ACE rule established emission guidelines for states to develop plans to address ~~greenhouse gas~~GHG emissions from existing coal-fired plants. On January 19, 2021 the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued an opinion vacating the ACE rule and remanding the rule back to the Agency for further consideration consistent with its opinion, after finding that the Agency had misinterpreted the ~~Clean Air Act~~CAA when adopting the ACE rule. In February 2021, the EPA issued a memorandum notifying states that it will not ~~requires~~require the submittal of plans to the EPA under Section 111(d) because the court vacated the ACE rule without reinstating the CPP.

The ~~ACE rule will be reviewed by the U.S.~~ Supreme Court granted review of the D.C. Circuit's decision related to EPA's authority to require generation shifting under the CPP in October 2021 (West Virginia v. EPA) ~~and oral argument is scheduled for February, 28, 2022.~~. PSE joined a coalition of utilities defending the vacatur of the ACE rule along with EPA, as well as, a coalition of states that includes Washington State. PSE cannot predict either the outcome of this case or its impact on the ACE rule or the CPP rule.

~~Washington Clean Air Rule~~

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

In September 2016, PSE, along with Avista Corporation, Cascade Natural Gas Corporation and NW Natural, filed a lawsuit in the U.S. District Court for the Eastern District of Washington challenging the CAR. In September 2016, the four companies filed a similar challenge to the CAR in Thurston County Superior Court. In March 2018, the Thurston County Superior Court invalidated the CAR. The Washington Department of Ecology appealed the Superior Court decision in May 2018. As a result of the appeal, direct review to the Washington State Supreme Court was granted and oral Oral argument was held on March 16, 2019. In January 2020, the Washington Supreme Court affirmed that CAR is not valid for “indirect emitters,” meaning it does not apply to the sale of natural gas for use by customers. The court ruled, however, that the rule can be severedFebruary 28, 2022, and is valid for direct emitters including electric utilities with permitted air emission sources, but remanded the case back to the superior court to determine which parts of the rule survive. The remand is pending in the superior court. In light of the Supreme Court issued its decision on June 30, 2022, finding that EPA lacked clear congressional authorization to require generation shifting under Section 111(d), but remaining silent as to the ~~federal court litigation was dismissed~~appropriate scope of state compliance flexibilities. In response to this decision, on ~~March 11, 2020. Notably,~~October 3, 2022, the ~~Climate Commitment Act prohibits~~D.C. Circuit recalled its partial mandate vacating the ~~Department~~ACE Rule and granted a motion by EPA to hold pending challenges to the ACE Rule in abeyance while EPA develops a replacement rule. PSE cannot predict EPA’s timeline for issuing this replacement rule; however, in December 2022, EPA published proposed changes to the Section 111(d) implementing regulations, which will impact EPA’s future promulgation of ~~Ecology from adopting or enforcing a program that regulates greenhouse gas~~emissions guidelines, including the forthcoming 111(d) rule governing GHG emissions from existing electricity generating units. EPA has indicated that it intends to issue a ~~stationary source except as provided in the Act, which could effectively preempt the Clean Air Rule.~~final rule by April 2023.

Washington Climate Commitment Act

In 2021, the Washington Legislature adopted the ~~Climate Commitment Act,~~CCA, which establishes a GHG emissions cap-and-invest program that ~~will take effect~~caps GHG emissions beginning on January 1, ~~2023.~~2023 and makes further reductions to the cap annually through 2050. The Washington Department of Ecology ~~is currently developing~~(WDOE) published final regulations to implement the program ~~but in~~to implement the program on September 29, 2022, which became effective on October 30, 2022. In general, the program will require covered entities to obtain emission allowances or offset credits for covered ~~emissions.~~emissions and the WDOE provides the annual allowance budget based on the cap. Allowances can be obtained through quarterly auctions, or bought and sold on a secondary market.

The ~~Climate Commitment Act will regulate~~CCA regulates PSE both as an electric utility and as a natural gas distribution utility. PSE ~~will be~~is required to obtain emission allowances or offset credits for GHG emissions associated with electricity generated in or imported into the state ~~if the~~to serve Washington State load, and all electricity generated by Washington State PSE facilities with total annual emissions ~~associated with this generation exceed~~exceeding 25,000 metric tons of carbon dioxide equivalent per year. As an electric utility subject to Washington’s ~~Clean Energy Transformation Act,~~CETA, which is discussed below, PSE will receive emission allowances at no cost through 2050 for direct emissions associated with electricity used to serve Washington State load to mitigate impacts to ratepayers. PSE will also be required to obtain emission allowances for GHG emissions associated with natural gas supplied to customers and any natural gas system associated facilities with emissions that exceed 25,000 metric tons of carbon dioxide equivalent per year. PSE will receive some emission allowances at no ~~cost through 2050~~cost; the amount will be based on a percentage of baseline emissions (determined from 2015 - 2019 natural gas system related emissions) that will decline to mitigate rate impacts to ~~ratepayers. The Department~~certain natural gas customers. Offset credit use is limited and the WDOE will reduce the cap proportionally for any offsets used. In the first compliance period, 2023-2026, participating entities can cover up to 5% of ~~Ecology is working~~their emissions with offset credits, and can cover an additional 3% with credits from projects on ~~implementing regulations which are expected~~federally recognized Tribal lands. In the second compliance period, 2027-2030, the general limit drops to ~~be finalized later this year.~~

4%, with an additional 2% from projects on Tribal lands.

Washington Clean Energy Transformation Act

In May 2019, Washington State passed the ~~Clean Energy Transformation Act that~~CETA, which supports Washington's clean energy economy and transitioning to a clean, affordable, and reliable energy future. The ~~Clean Energy Transition Act~~CETA requires all electric utilities to eliminate coal-fired generation from their allocation of electricity by December 31, 2025; to be carbon-neutral by January 1, 2030 through a combination of non-emitting electric generation, renewable generation, and/or alternative compliance options; and makes it the state policy that, by 2045, 100% of electric generation and retail electricity sales will come from renewable or non-emitting resources. Clean energy implementation plans are required every four years from each investor-owned utility (IOU) ~~and~~. The plan must propose interim targets for meeting the 2045 standard between 2030 and 2045 and describe an actionable plan that the IOU intends to pursue to meet the standard. The Washington Commission may approve, reject or recommend alterations to an IOU’s plan.

In order to meet these requirements, the Act clarifies the Washington Commission’s authority to consider and implement performance and incentive-based regulation, multi-year rate plans, and other flexible regulatory mechanisms where appropriate. The Act mandates that the Washington Commission accelerate depreciation schedules for coal-fired resources, including transmission lines, to December 31, 2025, or to allow IOUs to recover costs in rates for earlier closure of those facilities. IOUs will be allowed to earn a rate of return on certain Power Purchase Agreements (PPAs) and 36 months deferred accounting treatment for clean energy projects (including PPAs) identified in the utility’s clean energy implementation plan.

IOUs are considered to be in compliance when the cost of meeting the standard or an interim target within the four-year period between plans equals a 2% increase in the weather-adjusted sales revenue to customers from the previous year. If relying on the cost cap exemption, IOUs must demonstrate that they have maximized investments in renewable resources and non-emitting generation prior to using alternative compliance measures.

~~The law requires additional rulemaking by several Washington agencies for its measures to be enacted and PSE is unable to predict outcomes at this time.~~ The Company intends to seek recovery of any costs associated with ~~the clean energy legislation~~CETA through the regulatory process.

Regional Haze Rule

In January 2017, the EPA provided revisions to the Regional Haze Rule which were published in the Federal Register. Among other things, these revisions delayed new Regional Haze review from 2018 to 2021; however, the end date will remain 2028. In January 2018, the EPA announced that it would revisit certain aspects of these revisions and PSE is unable to predict the outcome. Challenges to the 2017 Regional Haze Revision Rule are being held in abeyance in the U.S. Court of Appeals for the D.C. Circuit, pending resolution of EPA’s reconsideration of the rule.

Coal Combustion Residuals

In April 2015, the EPA published a final rule, effective October 2015, which regulates Coal Combustion Residuals (CCR) under the Resource Conservation and Recovery Act, Subtitle D. The CCR rule currently is self-implementing at a federal level, or can be implemented and enforced by a state. The rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash containment structures by establishing technical design, operation and maintenance, closure and post closure care requirements for CCR landfills and surface impoundments, and corrective action requirements for any related leakage.

In addition to the EPA's CCR rule, the operator of Colstrip and the state of Montana in 2012 entered into an Administrative Order of Consent (AOC) that also addresses clean up and closure of CCR units at Colstrip. The CCR rule and the AOC require significant changes to the Company's Colstrip operations and those changes were reviewed by the Company and the plant operator in the second quarter of 2015. PSE had previously recognized a legal obligation under the EPA rules to dispose of ash material at Colstrip in 2003. Due to the CCR rule, additional disposal costs were added to the Asset Retirement and Environmental Obligations (ARO). In 2018, the D.C. Circuit Court of Appeals overturned certain provisions of the CCR rule in 2018 and remanded some of its provisions back to the EPA. As a result of that decision and certain other developments, EPA has continued to work on developing new rules regarding CCR, including establishing a presumptive date of April 11, 2021, for facilities to stop placing coal ash into unlined surface impoundments. In addition, the EPA has proposed a federal permitting program for coal ash disposal units along with the Water Infrastructure Improvement for the Nation Act (WIIN Act). The WIIN Act allows states to develop a state program for the regulation of CCR in lieu of the federal CCR rule, and also authorizes EPA to develop a federal permitting program. Currently, Montana has not applied for a state permit program, and EPA has not yet finalized a federal permitting program.

~~PCB Handling and Disposal~~

In April 2010, the EPA issued an Advanced Notice of Proposed Rulemaking soliciting information on a broad range of questions concerning inventory, management, use, and disposal of polychlorinated biphenyl (PCB)-containing equipment.

The rule was scheduled to be published in July 2015, but due to the number of comments received by the EPA, the rule has undergone multiple extensions and revisions. It was anticipated that the rule would be published in November 2017, but was placed on indefinite hold by the administration of President Donald Trump via executive order). The executive order was rescinded and it is expected that the new administration will revisit the ANPRM and PSE will continue to work closely with the Utility Solid Waste Activities Group and the American Gas Association to monitor developments. At this point, PSE cannot determine what impacts this rulemaking will have on its operations, if any.

Human Capital Resources

PSE is committed to maintaining a work environment free of violence or harassment or discrimination of any kind, including harassment based on race, color, gender, sex, sexual orientation, age, religion, creed, national origin, marital status, veteran status or disability. Violence and threatening behavior are not tolerated by the Company, and employees are expected to treat one another with mutual respect and dignity. PSE complies with all federal, state, and local employment laws and prohibit unlawful discrimination in the recruiting, hiring, compensating, promoting, transferring, training, downgrading, terminating, laying off, or recalling of any person based upon race, religion, creed, color, national origin, age, sex, sexual orientation, gender identity, marital status, veteran or military status, the presence of a disability, or any other characteristic protected by law.

Additional information regarding the Company’s human capital measures and objectives is contained in the Environmental, Social and Governance (ESG) report that can be found on the Company’s website, www.pse.com. The information on the Company’s website is not, and will not be deemed to be a part of this annual report on Form 10-K or incorporated into the Company’s other filings with the SEC.

Employee Overview

At December 31, ~~2021,~~2022, PSE had ~~3,185~~approximately 3,250 full-time equivalent employees. Approximately 970 PSE employees are represented by the International Brotherhood of Electrical Workers Union (IBEW) or the United Association of Plumbers and Pipefitters (UA). The UA contract was ratified effective December 2021, and will expire September 30, 2025. The IBEW contract was ratified effective April 1, 2020, and will expire March 31, 2026.

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

Safety

Our safety objective is our foundation: Nobody gets hurt today so that we will feel safe and secure and able to perform at our best. When we’re safe, we can achieve our people objective of being a great place to work, with engaged employees who live our values, embrace an ownership culture and are motivated to drive results for our company and our customers.

Our workplace safety program puts significant emphasis on education and ~~training.~~training, delivering information by multiple means, including articles and videos. Topics cover not only safety around the equipment and conditions employees work in but also day-to-day issues such as ergonomics, mental health, and overall wellness. This ensures compliance with all federal Occupational Safety and Health Administration and Washington State Division of Occupational Safety and Health rules to ensure PSE provides and remains a safe and healthy working environment for all employees. PSE vehicles, equipment, and construction practices meet all applicable regulations and codes for worker and public safety. An executive-level steering committee oversees employee safety performance and programs. Policies are outlined in a comprehensive manual, ~~the “Yellow Book,”~~ which is maintained by PSE’s Safety and Health Department. As a way of recognizing the importance of safety, the annual employee incentive is tied to performance on goals for ~~safety training, education and performance.~~safety.

Employee Benefits

To attract employees that meet the needs of the Company’s skilled workforce, the Company offers employee benefits that are a component of the Company’s total compensation package. Employee benefits include medical, health and dental insurance, long-term disability insurance, accidental death insurance, and our 401(k) plan. Non-represented and UA-represented employees hired on or after January 1, 2014 along with IBEW-represented employees hired on or after December 12, 2014, have access to the 401(k) plan. The two contribution sources from PSE are below:

•401(k) Company Matching: non-represented, UA-represented and IBEW-represented employees PSE will match 100% on the first 3.0% of pay contributed and 50.0% on the next 3.0% of pay contributed, such that an employee who contributes 6.0% of pay will receive 4.5% of pay in company match. Company matching will be immediately vested.

•Company Contribution: UA-represented employees will receive an annual company contribution of 4.0% of eligible pay placed in the Cash Balance retirement plan. Non-represented and IBEW-represented employees will receive an annual company contribution of 4.0% of eligible pay, placed either in the Investment Plan 401(k) plan or in PSE’s Cash Balance retirement plan. Non-represented and IBEW-represented employees will make a one-time election within 30 days of hire and direct that PSE put the 4.0% contribution either into the 401(k) plan or into an account in the Cash Balance retirement plan. The Company's 4.0% contribution will vest after three years of service.

For additional details see Item 8 (for employees hired prior to January 1, 2014) and Item 11 of this report.

Employee Development

The Company offers development opportunities to employees. Some of the programs are:

•Employee wellness program: PSE maintains a wellness program that offers a wide range of resources and tools at little or no cost to employees and their families, including company sponsored wellness events and ongoing health and wellness communications. The PSE program also includes resources and tools that focus on mental health and wellbeing.

•Employee engagement: PSE has been conducting the Great Place to Work® survey since 2001 in an ongoing effort to create a culture that supports company values and enables PSE to do its best work on behalf of its customers and communities. The Company also conducts periodic pulse surveys to engage employees on relevant topics and provide them with opportunities to inform decisions.

•Professional development and tuition reimbursement: PSE provides its employees with tools and development resources to enhance their skills and careers at the Company. Employees are encouraged to discuss their professional development and identify interests during one-to-one discussions and annual performance reviews with their supervisors. Employees are provided with learning opportunities that support our diversity, equity and inclusion strategies and create a more inclusive culture. Leadership development is critical to PSE’s success and we provide training and support to help leaders more effectively navigate and work in different ways including virtually or in a hybrid workplace. PSE has multiple training programs and modules designed to educate employees on an assortment of health and safety practices and certifications, corporate ethics and compliance, business management, employee relations, environmental awareness, community engagement, and regulatory compliance, and emergency preparation and response. PSE also offers employees a tuition reimbursement program for relevant education opportunities.

•Diversity, Equity and Inclusion (DEI): PSE is committed to being our customers’ clean energy partner of choice and views DEI as an essential aspect of the Company's aspirations. As a result, PSE's employees are critical to creating an inclusive culture and the Company is committed to creating opportunities for engagement and learning from one another. PSE has nine active employee resource groups (ERGs) that are designed for inspiring engagement. ERGs are a benefit for its members and the Company as they create environments for integrating diverse perspectives, provide additional insight into how to solve problems, innovate, and meet customer needs. ERGs also help to build connections with local communities and business partners resulting in strengthened relationships. PSE joined a regional coalition of employers through the Washington Employers of Racial Equity (WERE) pledging our support for the Commitment to Progress. PSE also participates with other member companies of the Edison Electric Institute (EEI) to help shape DEI objectives. PSE currently is in the first phase, assess, of the 10-year process. The assess phase includes the following: (i) embedding the DEI assessment into functional work; (ii) gathering and analyzing data related to our community, customers, people and suppliers; (iii) gathering input from stakeholders; (iv) evaluating WERE and EEI commitments and DEI related efforts and (v) creating a task force to energize PSE ERGs to enhance employee engagement.

Executive Officers of the Registrants

The executive officers of Puget Energy as of February ~~24, 2022,~~23, 2023, are listed below along with their business experience during the past five years. Officers of Puget Energy are elected for one-year terms.

Name

Age

Offices

M. E. Kipp

5455

President since August 2019; Chief Executive Officer since January 2020. President and Chief Executive Officer at El Paso Electric from May 2017 to August 2019; Chief Executive Officer at El Paso Electric from December 2015 to May 2017; President at El Paso Electric from September 2014 to December 2015

K. Hasan

5152

Executive Vice President and Chief Financial Officer since August 2022; Senior Vice President and Chief Financial Officer ~~since~~from June ~~24, 2021;~~2021 to August 2022; Executive Vice President and Chief Financial Officer of CLECO Corporation from 2018 to June 2021; Chief Risk Officer and Vice President at AES Corporation from 2014 to 2018

~~S. R. Secrist~~L. Luebbe

6055

Senior Vice President, Chief Sustainability Officer and General Counsel since December 1, 2022; Vice President Sustainability and Deputy General Counsel from March 2022 to November 2022; Assistant General Counsel and ~~Chief Ethics and Compliance Officer since January 2014~~Director Environmental Services from 2005 to March 2022

S. ~~J. King~~W. Smith

3837

Controller and Principal Accounting Officer since ~~November 2, 2017. Senior~~December 19, 2022; Manager, Revenue Requirements from September 2019 to December 2022; Manager, Energy and Derivatives Accounting from July 2018 to August 2019; Manager, Source to Pay Accounting at ~~PricewaterhouseCoopers LLP (PwC), a public accounting firm,~~Nike, Inc. from August 2017 to July ~~2016 - November 2017; Manager at PwC July 2013 - July 2016~~2018

The executive officers of PSE as of February ~~24, 2022,~~23, 2023, are listed below along with their business experience during the past five years. Officers of PSE are elected for one-year terms.

Name

Age

Offices

M. E. Kipp

5455

K. Hasan

5152

Executive Vice President and Chief Financial Officer since August 2022; Senior Vice President and Chief Financial Officer ~~since~~from June ~~2021;~~2021 to August 2022; Executive Vice President and Chief Financial Officer of CLECO Corporation from 2018 to June 2021; Chief Risk Officer and Vice President at AES Corporation from 2014 to 2018

M. F. Hopkins

5657

Senior Vice President Shared Services and Chief Information Officer since March 2020; Vice President and Chief Information Officer from August 2013 to March 2020

~~S. R. Secrist~~L. Luebbe

6055

Senior Vice President, ~~General Counsel and~~ Chief ~~Ethics and Compliance Officer since January 2014~~

~~A. J. Rodriguez~~

~~Senior Vice President Regulatory & Strategy since January 2021. Interim Chief Executive~~Sustainability Officer and General Counsel ~~at El Paso Electric~~since December 1, 2022; Vice President Sustainability and Deputy General Counsel from ~~August 2019~~March 2022 to ~~September 2020;~~November 2022; Assistant General Counsel and Director Environmental Services from 2005 to March 2022

A.W. Smith

Executive Vice President and Chief Operating Officer since July 2022. Senior Vice President, ~~- General Counsel~~Electric Operations at ~~El Paso~~Pacific Gas and Electric Company from ~~September 2017~~May 2021 to July ~~2020;~~2022. Senior Vice President, ~~- General Counsel~~Grid Development at ~~El Paso~~American Electric Power Service Company from ~~May 2017 to September 2017; Principal Attorney at El Paso Electric from July 2016 to May 2017~~2015-2021

A.W. Wappler

5758

Senior Vice President and Chief Customer Officer since November 2021. Vice President Customer Operations and Communications from 2016 to November 2021

S. ~~J. King~~W. Smith

3837

Controller and Principal Accounting Officer since ~~November 2, 2017. Senior~~December 19, 2022; Manager, Revenue Requirements from September 2019 to December 2022; Manager, Energy and Derivatives Accounting from July 2018 to August 2019; Manager, Source to Pay Accounting at ~~PwC~~Nike, Inc. from August 2017 to July ~~2016 - November 2017~~2018

ITEM 1A. RISK FACTORS

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

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

PSE's regulated utility business is subject to various federal and state regulations. PSE's regulatory risks include, but are not limited to, the items discussed below.

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

PSE is also subject to the regulatory authority of the Washington Commission with respect to accounting, operations, the issuance of securities and certain other matters, and the regulatory authority of the FERC with respect to the transmission of electric energy, the sale of electric energy at the wholesale level, accounting and certain other matters. In addition, proceedings with the Washington Commission typically involve multiple stakeholder parties, including consumer advocacy groups and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or decreasing rates. Policies and regulatory actions by these regulators could have a material impact on PSE’s financial position, results of operations and liquidity.

PSE’s recovery of costs is subject to regulatory review and its operating income may be adversely affected if its costs are disallowed. The Washington Commission determines the rates PSE may charge to its electric retail customers based, in part, on historic costs during a particular test year, adjusted for certain normalizing adjustments. Power costs on the other hand, are normalized for market, weather and hydrological conditions projected to occur during the applicable rate year, the ensuing twelve-month period after rates become effective. The Washington Commission determines the rates PSE may charge to its

natural gas customers based on historic costs during a particular test year. Natural gas costs are adjusted through the PGA mechanism, as discussed previously. If in a specific year PSE’s costs are higher than the amounts used by the Washington Commission to determine the rates, revenue may not be sufficient to permit PSE to earn its allowed return or to cover its costs. In addition, the Washington Commission has the authority to determine what level of expense and investment is reasonable and prudent in providing electric and natural gas service. If the Washington Commission decides that part of PSE’s costs do not meet the standard, those costs may be disallowed partially or entirely and not recovered in rates. For the aforementioned reasons, the rates authorized by the Washington Commission may not be sufficient to earn the allowed return or recover the costs incurred by PSE in a given period.

PSE is currently subject to a Washington Commission order that requires PSE to share its excess earnings above the authorized rate of return with customers. The Washington Commission previously approved an electric and natural gas decoupling mechanism for the recovery of its delivery-system and fixed production costs, along with a rate plan and earnings sharing mechanism that requires PSE and its customers to share in any earnings in excess of the authorized rate of ~~return of 7.39%.~~return. The earnings test is done for each service (electric/natural gas) separately, so PSE would be obligated to share the earnings for one service exceeding the authorized rate of return, even if the other service did not exceed the authorized rate of return.

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

RISKS RELATING TO PSE’s OPERATION

PSE’s cash flow and earnings could be adversely affected by potential high prices and volatile markets for purchased power, recurrence of low availability of hydroelectric resources, outages of its generating facilities or a failure to deliver on the part of its suppliers. The utility business involves many operating risks. If PSE’s operating expenses, including the cost of purchased power and natural gas, significantly exceed the levels recovered from retail customers, its cash flow and earnings would be negatively affected. Factors which could cause PSE's purchased power and natural gas costs to be higher than anticipated include, but are not limited to, high prices in western wholesale markets during periods when PSE has insufficient energy resources to meet its energy supply needs and/or purchases in wholesale markets of high volumes of energy at prices above the amount recovered in retail rates due to:

•Below normal levels of generation by PSE-owned hydroelectric resources due to low streamflow conditions or precipitation;

•Extended outages of any of PSE-owned generating facilities or the transmission lines that deliver energy to load centers, or the effects of large-scale natural disasters on a substantial portion of distribution infrastructure; and

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

PSE’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs. PSE owns and operates coal, natural gas-fired, hydroelectric, and wind-powered generating facilities. Operation of electric generating facilities involves risks that can adversely affect energy output and efficiency levels or increase expenditures, including:

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

•Volatility in prices for fuel and fuel transportation;

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

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

•Labor disputes;

•Operator error or safety related stoppages;

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

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

Cyber-attacks, including cyber-terrorism, foreign-state support cyber threats or other information technology security breaches, or information technology failures may disrupt business operations, increase costs, lead to the disclosure of confidential information and damage PSE's reputation.Security breaches of PSE's information technology infrastructure, including cyber-attacks and cyber-terrorism, or other failures of PSE's information technology infrastructure could lead to disruptions of PSE's production and distribution operations, and otherwise adversely impact PSE's ability to safely and effectively operate electric and natural gas systems and serve customers. In addition, an attack on or failure of information technology systems could result in the unauthorized release of customer, employee or Company data that is crucial to PSE's operational security or could adversely affect PSE's ability to deliver and collect on customer bills. Such security breaches of PSE's information technology infrastructure could adversely affect our operations and business reputation, diminish customer confidence, subject PSE to financial liability or increased regulation, expose PSE to fines or material legal claims and liability and adversely affect our financial results. PSE has implemented preventive, detective and remediation measures to manage these risks, and maintains cyber risk insurance to mitigate the effects of these events. Nevertheless, these may not effectively protect all of PSE's systems all of the time. To the extent that the occurrence of any of these cyber-events is not fully covered by insurance, it could adversely affect PSE’s financial condition and results of operations.

Natural disasters like wildfires and catastrophic events, including terrorist acts, may adversely affect PSE's business. Events such as fires, earthquakes, explosions, floods, tornadoes, extreme weather events, vandalism, terrorist acts, and other similar occurrences, could damage PSE's operational assets, including utility facilities, information technology infrastructure, distributed generation assets and pipeline assets. Such events could likewise damage the operational assets of PSE's suppliers or customers. These events could disrupt PSE's ability to meet customer requirements, significantly increase PSE's response costs, and significantly decrease PSE's revenues. Unanticipated events or a combination of events, failure in resources needed to respond to events, or a slow or inadequate response to events may have an adverse impact on PSE's operations, financial condition, and results of operations. The availability of insurance covering catastrophic events like wildfires, sabotage and terrorism may be limited or may result in higher deductibles, higher premiums, and more restrictive policy terms.

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

Costs of compliance with environmental, climate change and endangered species laws are significant and the costs or reduced revenue related to compliance with new and emerging laws and regulations and the occurrence of associated liabilities could adversely affect PSE’s results of operations. PSE’s operations are subject to extensive federal, state and local laws and regulations relating to environmental issues, including air emissions and climate change, endangered species protection, remediation of contamination, avian protection, waste handling and disposal, decommissioning, water protection and siting new facilities. In addition, recent laws proposed or passed by the State of Washington and various municipalities in PSE's service territory, including Seattle, seek to reduce or eliminate the use of natural gas in various contexts, such as for space and water heating in new commercial and multifamily buildings. As a result of these legal requirements, PSE must spend significant sums of money to comply with these measures including resource planning, remediation, monitoring, analysis, adoption of mitigation measures, use of pollution control equipment, and emissions-related abatement and fees. New environmental laws and regulations affecting PSE’s operations or restricting the use of products sold by PSE may be adopted, and new interpretations of existing laws and regulations could be adopted or become applicable to PSE or its facilities. Compliance with these or other future regulations could require significant expenditures by PSE or reduce revenue and thus adversely affect PSE financially. In addition, PSE may not be able to recover all of its costs for such expenditures through electric and natural gas rates in a timely manner.

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

adopted both renewable portfolio standards and GHG legislation, including CETA and CCA, and PSE anticipates full compliance with these requirements.

In 2021, the Washington Legislature adopted the CCA, which establishes a GHG emissions cap-and-invest program that caps GHG emissions beginning on January 1, 2023 and makes further reductions to the cap annually through 2050. The WDOE published final regulations to implement the program on September 29, 2022, which became effective on October 30, 2022. WDOE also indicated that they will have subsequent rulemakings that will build off initial rulemaking as program implementation gets underway and progress with Washington State carbon goals are evaluated. In general, the program will require covered entities to obtain emission allowances or offset credits for covered emissions and the WDOE provides the annual allowance budget based on the cap. Allowances can be obtained through quarterly auctions, or bought and sold on a secondary market. The CCA regulates PSE both as an electric utility and as a natural gas distribution utility. PSE is required to obtain emission allowances or offset credits for GHG emissions associated with electricity generated in or imported into the state to serve Washington State load, and all electricity generated by Washington State PSE facilities with total annual emissions exceeding 25,000 metric tons of carbon dioxide equivalent per year. As an electric utility subject to Washington’s CETA, PSE will receive emission allowances at no cost through 2050 for direct emissions associated with electricity used to serve Washington State load to mitigate impacts to ratepayers. PSE will also be required to obtain emission allowances for GHG emissions associated with natural gas supplied to customers and any natural gas system associated facilities with emissions that exceed 25,000 metric tons of carbon dioxide equivalent per year. Based on the rules passed in 2022, there is potential for PSE’s compliance with the CCA to result in increased costs to customers or amounts that PSE may not be able to recover through electric and natural gas rates. Potential risks associated with CCA compliance could include: the evolving nature of the CCA rulemaking as indicated by WDOE, market uncertainty based on rule interpretation during implementation, unresolved recovery methodology for CCA’s impact on energy costs, company costs, customer rate impacts, and cash, liquidity and credit volatility.

PSE's inability to adequately develop or acquire the necessary infrastructure to comply with new and emerging laws and regulations could have a material adverse impact on our business and results of operations. Potential changes in regulatory standards, impacts of new and existing laws and regulations, including environmental laws and regulations and those seeking to combat climate change, and the need to obtain various regulatory approvals create uncertainty surrounding our energy resource portfolio. The current abundance of low, stably priced natural gas, together with environmental, regulatory, and other concerns surrounding coal-fired generation resources, fossil fuel infrastructure bans, and energy resource portfolio requirements, including those related to renewables development and energy efficiency measures, create strategic challenges as to the appropriate generation portfolio and fuel diversification mix.

In expressing concerns about the environmental and climate-related impacts from continued extraction, transportation, delivery and combustion of fossil fuels including natural gas, environmental advocacy groups and other third parties have in recent years undertaken greater efforts to oppose the permitting and construction of natural gas infrastructure projects. These efforts may increase in scope and frequency depending on a number of variables, including the future course of local, state and federal environmental regulation and the increasing financial resources devoted to these opposition activities. PSE cannot predict the effect that any such opposition may have on our ability to develop and construct natural gas infrastructure projects in the future.

PSE's operating results fluctuate on a seasonal and quarterly basis and can be impacted by various impacts of climate change. PSE's business is seasonal and weather patterns can have a material impact on its revenue, expenses and operating results. Demand for electricity is greater in the winter months associated with heating. Accordingly, PSE's operations have historically generated less revenue and income when weather conditions are milder in winter. In the event that the Company experiences unusually mild winters, its results of operations and financial condition could be adversely affected. PSE's hydroelectric resources are also dependent on snow conditions in the Pacific Northwest.

PSE may be adversely affected by extreme events in which PSE is not able to promptly respond, repair and restart the electric and natural gas infrastructure system. PSE must maintain an emergency planning and training program to allow PSE to quickly respond to extreme events. Without emergency planning, PSE is subject to availability of outside contractors during an extreme event which may impact the quality of service provided to PSE’s customers and also require significant expenditures by PSE. In addition, a slow or ineffective response to extreme events may have an adverse effect on earnings as customers may be without electricity and natural gas for an extended period of time.

PSE depends on its work force and third party vendors to perform certain important services and may be negatively affected by its inability to attract and retain professional and technical employees or the unavailability of vendors. PSE is subject to workforce factors, including but not limited to loss or retirement of key personnel and availability of qualified personnel. PSE’s ability to implement a workforce succession plan is dependent upon PSE’s ability to employ and retain

skilled professional and technical workers. Without a skilled workforce, PSE’s ability to provide quality service to PSE’s

customers and to meet regulatory requirements could affect PSE’s earnings. Also, the costs associated with attracting and retaining qualified employees could reduce earnings and cash flows.

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

Potential municipalization may adversely affect PSE's financial condition. PSE may be adversely affected if we experience a loss in the number of our customers due to municipalization or other related government action. When a town, city, county, or portion of a county in PSE's service territory establishes its own municipal-owned utility or public utility district, it acquires PSE's assets and takes over the delivery of energy services that PSE provides. Although PSE is compensated in connection with the government entity's acquisition of its assets, any such loss of customers and related revenue could negatively affect PSE's future financial condition.

Technological developments may have an adverse impact on PSE's financial condition. Advances in power generation, energy efficiency and other alternative energy technologies, such as solar generation, could lead to more wide-spread use of these technologies, thereby reducing customer demand for the energy supplied by PSE which could negatively impact PSE's revenue and financial condition.

PSE ~~faces~~may face risks related to the COVID-19 pandemic and other outbreaks that could have a material adverse impact on our business and results of operations. Business disruptions arising from ~~stay at home mandates due to the~~pandemics, such as COVID-19, ~~pandemic have~~may adversely ~~affected~~affect economic activity within Washington State and the United States of America. ~~We cannot predict the degree that the continued spread of COVID-19 and efforts~~Efforts to contain ~~the virus~~and mitigate such pandemics and/or outbreaks (including, but not limited to, voluntary and mandatory quarantines, vaccination requirements, restrictions on travel, limiting gatherings of people, and reduced operations and extended closures of many businesses and institutions) could materially impact our results of operations, financial condition and ongoing operations. The impacts include but are not limited to:

•impacting customer demand for electricity and natural gas by our customers, particularly from commercial and industrial customers;

•reducing the availability and productivity of our employees;

•reducing the availability and productivity of key contractors and vendors;

•causing us to experience an increase in costs as a result of our emergency measures, delayed payments from our customers and uncollectible accounts;

•causing delays and disruptions in the availability of and timely delivery of materials and components used in our operations;

•causing a deterioration in our financial metrics or the business environment that impacts our credit ratings;

•causing significant disruption in the financial markets which could have a negative impact on our ability to access capital in the future and cost of capital;

•resulting in our inability to meet the requirements of the covenants in our existing credit facilities, including covenants regarding the ratio of total debt to total capitalization; and

•disrupting our ability to meet customer requirements and potentially significantly increase response costs.

PSE could be adversely affected by disruptions in the global economy and rising geopolitical tensions caused by the ongoing military conflict between Russia and Ukraine.The global economy has been negatively impacted by the military conflict between Russia and Ukraine. Governments including the U.S., United Kingdom, and European Union imposed import and export controls on certain products and economic sanctions on certain industries and parties in Russia. Further escalation of geopolitical tensions related to the military conflict, including increased trade barriers or restrictions on global trade, could result in, among other things, cyberattacks, supply chain disruptions, and increased costs, including energy costs, which may adversely affect our business and supply chain.

RISKS RELATING TO PUGET ENERGY'S AND PSE'S FINANCING

The Company's business is dependent on its ability to successfully access capital. The Company relies on access to internally generated funds, bank borrowings through multi-year committed credit facilities and short-term money markets as sources of liquidity and longer-term debt markets to fund PSE's utility construction program and other capital expenditure requirements of PSE. If Puget Energy or PSE are unable to access capital on reasonable terms, their ability to pursue improvements or acquisitions, including generating capacity, which may be necessary for future growth, could be adversely affected. Capital and credit market disruptions, a downgrade of Puget Energy's or PSE's credit rating or the unavailability of or the imposition of restrictions on borrowings under their credit facilities in the event of a deterioration of financial condition of Puget Energy or PSE may increase Puget Energy's and PSE’s cost of borrowing or adversely affect the ability to access one or more financial markets.

The amount of the Company's debt could adversely affect its liquidity and results of operations. Puget Energy and PSE have short-term and long-term debt, and may incur additional debt (including secured debt) in the future. Puget Energy has access to a multi-year $800.0 million revolving credit facility, secured by substantially all of its assets, which has a maturity date of ~~October 25, 2023.~~May 14, 2027. There was ~~$33.3~~$118.6 million outstanding under the facility as of December 31, ~~2021.~~2022. Puget Energy's credit facility includes an expansion feature that could, subject to the commitment of one or more lenders, increase the size of the facility to $1.3 billion. PSE also has a separate credit facility, which provides PSE with access to a multi-year $800.0 million revolving credit facility, and includes an expansion feature that could, subject to the commitment of one or more lenders, increase the size of the facility to $1.4 billion. The PSE credit facility matures on ~~October 25, 2023.~~May 14, 2027. As of December 31, ~~2021,~~2022, no amounts were drawn and outstanding under the PSE credit facility. In addition, Puget Energy has issued $2.0 billion in senior secured notes, whereas PSE, as of December 31, ~~2021,~~2022, had approximately $4.8 billion outstanding under first mortgage bonds, pollution control bonds and senior notes. The Company's debt level could have important effects on the business, including but not limited to:

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

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

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

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

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

PSE may not declare or make any dividend distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or if its credit ratings are below investment grade, PSE’s ratio of earnings before interest, tax, depreciation and amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3.0 to 1.0.

Changes in the method for determining LIBOR and the potential replacement of LIBOR may affect our credit facilities and the interest rates on such borrowings. LIBOR, the London interbank offered rate, is the basic rate of interest used in lending between banks on the London interbank market and is widely used as a reference for setting the interest rate on loans globally. Puget Energy and PSE’s credit facilities allow Puget Energy or PSE, respectively to borrow at the bank's prime rate or to make floating rate advances at LIBOR plus a spread that is based upon Puget Energy’s or PSE's credit rating, respectively.

In July 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR announced that it intends to phase out LIBOR by the end of 2021. In November 2020, LIBOR’s administrator indicated that US dollar LIBOR will likely

continue to be published until June 30, 2023, which would allow time for certain legacy contracts to mature before US dollar LIBOR is no longer available.

If the method for calculation of LIBOR changes, if LIBOR is no longer available or if

lenders have increased costs due to changes in LIBOR, Puget Energy or PSE may suffer from potential increases in interest rates on any borrowings. ~~Further, in the event~~In May 2022, Puget Energy and PSE entered into new revolving credit facilities that eliminated LIBOR as the benchmark for floating rate loans and replaced it with the Secured Overnight Financing Rate (SOFR) as the new benchmark rate for floating rate loans plus a spread that is based upon Puget Energy’s or ~~PSE extends or enters into any substantial amendments to its~~PSE’s credit ~~facility, it is possible that the lenders under such credit facility will require that an alternative index to LIBOR be incorporated into such credit facility.~~ratings, respectively.

Poor performance of pension and postretirement benefit plan investments and other factors impacting plan costs could unfavorably impact PSE’s cash flow and liquidity. PSE provides a defined benefit pension plan and postretirement benefits to certain PSE employees and former employees. Costs of providing these benefits are based, in part, on the value of the plan’s assets and the current interest rate environment and therefore, adverse market performance or low interest rates could result in lower rates of return for the investments that fund PSE’s pension and postretirement benefits plans and could increase PSE’s funding requirements related to the pension plans. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase PSE's funding requirements related to the pension plans. Any contributions to PSE’s plans in ~~2022~~2023 and beyond as well as the timing of the recovery of such contributions in GRCs could impact PSE’s cash flow and liquidity.

RISKS RELATING TO PUGET ENERGY'S CORPORATE STRUCTURE

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

The payment of dividends by PSE to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE’s electric and natural gas mortgage indentures. In addition, beginning February 2009, pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio calculated on a regulatory basis is 44.0% or below, except to the extent a lower equity ratio is ordered by the Washington Commission. Also, pursuant to the merger order, PSE's ability to declare or make any distribution is limited by its' corporate credit/issuer rating and EBITDA to interest ratio, as previously discussed above. The common equity ratio, calculated on a regulatory basis, was ~~47.5%~~48.1% at December 31, ~~2021,~~2022, and the EBITDA to interest expense was ~~5.5~~5.0 to 1.0 for the twelve-months ended December 31, ~~2021.~~2022.

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

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

GENERAL RISK FACTORS

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

taxing authorities. Disputes over interpretations of tax laws may be settled with the taxing authority in examination, upon appeal or through litigation.

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

The Company's costs and expenses could increase as a result of inflationary pressures.

Such inflationary pressures could result in increased labor, commodities, materials and supplies, outside services and capital costs, among others, that may not be offset by an increase in revenues, which would adversely affect the Company’s results of operations. While regulatory mechanisms exist to mitigate the impacts of inflation on commodity prices, the Company cannot assure that rising inflation will not have an adverse effect on the Company's results of operations.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

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

ITEM 3. LEGAL PROCEEDINGS

~~On August 26,~~Effective in November 2020, the SEC ~~issued~~ Final Rule Release No. 33-10825, "Modernization of Regulation S-K Items 101, 103, and ~~105." This rule, which became effective on November 9, 2020,~~105" updated the disclosure threshold for environmental proceedings. Prior to this rule, environmental proceedings to which the government is a party were required to be disclosed if the proceeding was expected to result in sanctions of $100,000 or more. The ~~above referenced~~ rule increases the quantitative threshold to $300,000, but also permits ~~the registrant~~registrants to elect a higher threshold, limited to the lesser of $1 million or 1% of consolidated current assets, if the registrant determines that such threshold is more reasonably designed to result in the disclosure of material environmental proceedings. ~~The registrant must disclose this alternative threshold in each annual and quarterly report.~~

Given the size of the Company's operations, ~~we have~~PSE elected ~~to adopt~~ a threshold of $1 million. For information on litigation or legislative rulemaking proceedings, see Note 15, "Litigation" to the consolidated financial statements included in Item 8 of this report.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

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

All of the outstanding shares of Puget Energy’s common stock, the only class of common equity of Puget Energy, are held by its direct parent Puget Equico LLC (Puget Equico), which is an indirect wholly-owned subsidiary of Puget Holdings, and are not publicly traded. The outstanding shares of PSE’s common stock, the only class of common equity of PSE, are held by Puget Energy and are not publicly traded.

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

From time to time, when deemed advisable and permitted, PSE and Puget Energy pay dividends on its common stock. During 2022, 2021, ~~2020,~~ and ~~2019,~~2020, PSE paid dividends to its parent, Puget Energy, and Puget Energy paid dividends to its parent, Puget Equico, in the amounts shown in Puget Energy's and PSE's Consolidated Statements of Common Shareholder's Equity, included in Item 8, "Financial Statements and Supplementary Data" of this ~~Form 10-K.~~report.

ITEM 6. [Reserved]

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

The following discussion and analysis is intended to promote understanding of the results of operations and financial condition, is provided as a supplement to, and should be read in conjunction with the financial statements and related notes thereto included elsewhere in this report on Form 10-K. This section generally discusses the results of operations and changes in financial condition for ~~2021~~2022 compared to ~~2020.~~2021. For discussion related to the results of operations and changes in financial condition for ~~2020~~2021 compared to ~~2019~~2020 refer to Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations in our fiscal year ~~2020~~2021 Form 10-K, which was filed with the United States Securities and Exchange commission (SEC). The discussion contains forward-looking statements that involve risks and uncertainties, such as Puget Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE) objectives, expectations and intentions. Words or phrases such as “anticipates,” “believes,” “continues,” “could,” “estimates,” “expects,” “future,” “intends,” “may,” “might,” “plans,” “potential,” “predicts,” “projects,” “should,” “will likely result,” “will continue” and similar expressions are intended to identify certain of these forward-looking statements. However, these words are not the exclusive means of identifying such statements. In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward-looking statements. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. Puget Energy’s and PSE’s actual results could differ materially from results that may be anticipated by such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed in the section entitled “Forward-Looking Statements” and “Risk Factors” included elsewhere in this report. Except as required by law, neither Puget Energy nor PSE undertakes any obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. Readers are urged to carefully review and consider the various disclosures made in this report and in Puget Energy’s and PSE’s other reports filed with the ~~U.S. Securities and Exchange Commission (SEC)~~SEC that attempt to advise interested parties of the risks and factors that may affect Puget Energy’s and PSE’s business, prospects and results of ~~operations, including the COVID-19 pandemic.~~operations.

Overview

Puget Energy is an energy services holding company and substantially all of its operations are conducted through its wholly-owned subsidiary PSE, a regulated electric and natural gas utility company. PSE is the largest electric and natural gas utility in the state of Washington, primarily engaged in the business of electric transmission, distribution and generation and natural gas distribution. Puget Energy's business strategy is to generate stable cash flows by offering reliable electric and natural gas service in a cost-effective manner through PSE. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC (Puget LNG), which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma liquefied natural gas (LNG) ~~facility which is under construction.~~facility. 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 the ~~Canada Pension Plan Investment Board (CPPIB), the~~ British Columbia Investment Management Corporation (BCIMC), the Alberta Investment Management Corporation (AIMCo), Ontario Municipal Employee Retirement System (OMERS) ~~and~~, PGGM Vermogensbeheer B.V. ~~In July 2021, CPPIB entered into an agreement to sell its shares to~~, Macquarie Washington Clean Energy Investment, L.P., and Ontario Teachers’ Pension Plan Board. ~~The sale was approved by the Washington Commission and closed on February 22, 2022.~~ Puget Energy and PSE are collectively referred to herein as “the Company.”

PSE generates revenue and cash flow primarily from the sale of electric and natural gas services to residential and commercial customers within a service territory covering approximately 6,000 square miles, principally in the Puget Sound

region of the state of Washington. PSE continually balances its load requirements, generation resources, purchase power agreements, and market purchases to meet customer demand. The Company's external financing requirements principally reflect the cash needs of its construction program, its schedule of maturing debt and certain operational needs. PSE requires access to bank and capital markets to meet its financing needs.

~~COVID-19 Update~~

The outbreak of the Coronavirus Disease 2019 (COVID-19) has resulted in a global pandemic. The Company continues to monitor the impact of the pandemic and take steps to mitigate known risks. The Company provides a critical and essential service to its customers and the health and safety of its employees and customers is its first priority. The Company is continuously monitoring its supply chain and is working closely with essential vendors to understand the impact of COVID-19 to its business and does not currently expect service disruptions to customers.

Due to various stages of continued stay at home orders, work from home mandates, and business disruptions caused by COVID-19, customer usage patterns were impacted, thus affecting the Company's electric and natural gas load. Overall, during the year ended December 31, 2021, electric and natural gas loads increased 1.3% and decreased 2.1%, respectively; residential electric and natural gas loads increased 5.2% and decreased 2.8%, respectively; and commercial electric and natural gas loads decreased 3.3% and 7.0%, respectively. Industrial customers, who represent 3.8% of the Company's total retail revenue and are generally transmission and transportation services which are not volumetric in nature, are not expected to be materially impacted. Revenue reductions are partially offset by the effects of decoupling. Decoupling revenue during the year ended December 31, 2021 was $12.5 million that was over collected for electric and $10.3 million of revenue that was recognized for natural gas, as compared to $49.6 million and $18.9 million revenue that was recognized in the same period of 2020 for electric and natural gas, respectively.

Due to business disruptions caused by the COVID-19 pandemic, the Company has incurred increased costs and partially offsetting cost savings through the year ended December 31, 2021. On September 3, 2020, the Company filed an accounting petition with the Washington Utilities and Transportation Commission (Washington Commission), requesting authorization to defer the costs and foregone revenue net of offsets associated with the COVID-19 public health emergency. On November 6, 2020, PSE filed a revised petition which was approved on December 10, 2020 by the Washington Commission granting PSE's accounting petition in part by allowing the deferral of COVID-19 incremental costs and foregone revenue net of offsets. As of December 31, 2021, PSE deferred $23.3 million specific to COVID-19 net of offsets.

On March 27, 2020, the U.S. Government enacted the CARES Act, which provided approximately $2 trillion of economic relief and stimulus to support the national economy during the COVID-19 pandemic. This package included support for individuals, large corporations, small business, and health care entities, among other affected groups. Among other provisions, the CARES Act includes modifications to corporate income tax provisions, including temporary suspension of certain payment requirements for the employer portion of social security taxes. As a result of these modifications, the Company deferred payroll taxes totaling $6.8 million as of December 31, 2021.

The Company anticipates that electric and natural gas loads may be less impacted going forward. Continued work at home initiatives, however, remain in effect for many businesses, and may impact electric and natural gas loads, particularly among residential and commercial customers. Factors that may affect these assumptions include the duration, severity, and potential resurgence of the virus, government proclamations related to managing public health, and fiscal stimulus policies to support economic recovery.

On September 30, 2021, the Company announced that in order to comply with state and federal vaccine mandates all employees and contingent workers are required to be fully vaccinated against COVID-19. On December 10, 2021, the Company announced a pause in the vaccination requirement due to a federal court temporarily halting the Executive Order that required federal contractors to receive their final vaccine dose by January 4, 2022. The government vaccination mandate may impact the Company's and vendor staffing levels, which could affect storm response and the timeliness of our response to customers' inquiries.

Factors affecting PSE's performance are set forth in this “Overview” section, as well as in other sections of the Management's Discussion and Analysis.

Non-GAAP Financial Measures

The following discussion includes financial information prepared in accordance with U.S. Generally Accepted Accounting Principles (GAAP), as well as return on equity (ROE) excluding unrealized gains and losses on derivative instruments (net income plus unrealized losses and/or minus unrealized gains on derivative instruments divided by average common equity) that is considered a “non-GAAP financial ~~measure.”~~measure”. Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that includes adjustments that result in a presentation that is not defined by GAAP. The Company believes that its return on average of monthly averages (AMA) equity, also a non-GAAP measure, is a suitable metric for comparing ROE across years and is a relevant metric for assessing and evaluating ROE performance against the Company's authorized regulated ROE. The AMA equity is not intended to represent the regulated equity. PSE's ROE may not be comparable to other companies' ROE measures. Furthermore, this measure is not intended to replace ROE (GAAP net income divided by GAAP average common equity) as an indicator of operating performance.

The following table presents PSE’s ROE, its return on AMA equity and its authorized regulated ROE for ~~2021~~2022 and ~~2020:~~2021:


		2021			2020				2022			2021
(Dollars in Thousands)	(Dollars in Thousands)	Earnings	Average Common Equity	Return on Equity	Earnings	Average Common Equity	Return on Equity	(Dollars in Thousands)	Earnings	Average Common Equity	Return on Equity	Earnings	Average Common Equity	Return on Equity
Return on equity	Return on equity	$336,063	$4,268,420	7.9%	$274,280	$4,115,045	6.7%	Return on equity	$490,952	$4,613,257	10.6%	$336,063	$4,268,420	7.9%
Less/Plus: Unrealized gains and losses on derivative instruments, after-tax	Less/Plus: Unrealized gains and losses on derivative instruments, after-tax	(10,890)	—	*	21,178	—	*	Less/Plus: Unrealized gains and losses on derivative instruments, after-tax	(206,330)	—	*	(10,890)	—	*
Plus: Equity adjustments1	Plus: Equity adjustments1	—	104,731	*	—	185,638	*	Plus: Equity adjustments1	—	(108,984)	*	—	104,731	*
Plus: Impact of average of monthly average (AMA)	Plus: Impact of average of monthly average (AMA)	—	97,767	*	—	(3,533)	*	Plus: Impact of average of monthly average (AMA)	—	127,482	*	—	97,767	*
Return on AMA equity	Return on AMA equity	$325,173	$4,470,918	7.3%	$295,458	$4,297,150	6.9%	Return on AMA equity	$284,622	$4,631,755	6.1%	$325,173	$4,470,918	7.3%
Authorized regulated return on equity2	Authorized regulated return on equity2			9.4%			9.4%	Authorized regulated return on equity2			9.4%			9.4%

_______________

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 per the approved 2019 GRC is 9.4% for natural gas and electric effective October 1, 2020 and October 15, 2020, respectively.

*Not meaningful and/or applicable.

The Company’s 2022 return on AMA equity was 6.1%, which is lower than the authorized regulated ROE primarily due to the following:

•Regulated equity (rate base multiplied by equity percent) was $589.3 million lower than AMA equity for the year ended December 31, 2022. The impact on ROE for this variance was negative 1.2%. The variance was primarily driven by investment in items that do not earn a return or earn a return that is less than the authorized ROE. Such items include investment in construction work in progress and growth in rate base since the last general rate case (GRC).

•Depreciation expense was $18.0 million higher than the amount allowed in rates on an after-tax basis for the year ended December 31, 2022, for an impact on ROE of negative 0.4%.

•Operations and maintenance expense, including production operations and maintenance, was $61.5 million higher than the amount allowed in rates on an after-tax basis for the year ended December 31, 2022, for an impact on ROE of negative 1.3%.

The Company’s 2021 return on AMA equity was 7.3%, which is lower than the authorized regulated ROE primarily due to the following:

•Regulated equity (rate base multiplied by equity percent) was $630.3 million lower than AMA equity for the year ended December 31, 2021. The impact on ROE for this variance was negative 1.3%. The variance was primarily driven by investment in items that do not earn a return or earn a return that is less than the authorized ROE. Such items include investment in construction work in progress and growth in rate base since the last ~~general rate case (GRC).~~GRC.

•Depreciation expense was $26.8 million higher than the amount allowed in rates on a pre-tax basis for the year ended December 31, 2021, for an impact on ROE of negative 0.6%.

~~The Company’s 2020 return on AMA equity was 6.9%, which is lower than the authorized regulated ROE primarily due to the following:~~

•Regulated equity (rate base multiplied by equity percent) was $504.9 million lower than AMA equity for the year ended December 31, 2020. The impact on ROE for this variance was negative 1.1%. The variance was primarily driven by investment in items that do not earn a return or earn a return that is less than the authorized ROE. Such items include investment in construction work in progress and growth in rate base since the last GRC.

•~~Depreciation expense was $90.9 million higher than the amount allowed in rates on a pre-tax basis for the year ended December 31, 2020, for an impact on ROE of negative 2.1%.~~

Factors and Trends Affecting PSE’s Performance

PSE’s ongoing regulatory requirements and operational needs necessitated the investment of substantial capital in ~~2021~~2022 and will continue to do so in future years. Because PSE intends to seek recovery of such investments through the regulatory process, its financial results depend heavily upon favorable outcomes from that process. The principal business, economic and other factors that affect PSE’s operations and financial performance include:

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

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

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

•The effects of climate change, including changes in the environment that may affect energy costs or consumption, increase the Company’s costs, or adversely affect its operations;

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

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

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

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

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

•Wholesale commodity prices of electricity and natural gas;

•Increasing capital expenditures with additional depreciation and amortization;

•Failure to complete capital projects on schedule and within budget or the abandonment of capital projects, either of which could result in the Company’s inability to recover project costs;

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

•General economic conditions, such as inflation, in PSE's service territory and its effects on customer growth and use-per-customer;

•Federal, state, and local taxes;

•Employee workforce factors, including potential strikes, work stoppages, transitions in senior management, and loss or retirement of key personnel and availability of qualified personnel;

•The effectiveness of PSE’s risk management policies and procedures;

•Cyber security attacks, data security breaches, or other malicious acts that cause damage to the Company’s generation and transmission facilities or information technology systems, or result in the release of confidential customer, employee, or Company information;

•Acts of war or terrorism locally or abroad, or the impact of civil unrest to infrastructure or preventing access to ~~infrastructure;~~infrastructure and its impact on the supply chain and prices of goods and services; and

•Risks due to pandemics, including supply shortages, rising costs, disruption to vendor or customer relationships, the potential for reputational harm, the impact of government, business and company closure of facilities, customer or contract defaults, concerns of safety to employees and customers, potential costs due to quarantining of employees and work-from-home policies, and the Company's and vendor staffing levels resulting from vaccination mandates.

4139

Regulation of PSE Rates and Recovery of PSE Costs

PSE's regulatory requirements and operational needs require the investment of substantial capital in ~~2021~~2022 and future years. As PSE intends to seek recovery of these investments through the regulatory process, its financial results depend heavily upon outcomes from that process. The rates that PSE is allowed to charge for its services influence its financial condition, results of operations and liquidity. PSE is highly regulated and the rates that it charges its retail customers are approved by the Washington Commission. The Washington Commission has traditionally required these rates be determined based, to a large extent, on historic test year costs plus weather normalized assumptions about hydroelectric conditions and power costs in the relevant rate year. Incremental customer growth and sales typically have not provided sufficient revenue to cover general cost increases over time due to the combined effects of regulatory lag and attrition. Absent a resolution for the impact of lag and attrition, the Company will need to seek rate relief through a rate case ~~on a regular and frequent basis in~~with the ~~foreseeable future. In addition, the~~Washington Commission. The Washington Commission determines whether the Company's expenses and capital investments are reasonable and prudent for the provision of cost-effective, reliable and safe electric and natural gas service. If the Washington Commission determines that a capital investment is not reasonable or prudent, the costs (including return on any resulting rate base) related to such capital investment may be disallowed, partially or entirely, and not recovered in rates.

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

On May 3, 2021, the Washington Governor signed legislation passed by the state legislature that would require investor-owned utilities to file a multiyear rate plan for two, three, or four years as part of a GRC filed with the Washington Commission on or after January 1, 2022. For the initial rate year, the legislation requires the Washington Commission to ascertain and determine the fair value for rate-making purposes of the property in service as of the date that rates go into effect. Utilities would be bound to the first and second year of a multiyear rate plan and can file for a new rate plan in years three or four. If a company earns greater than a half percent above its authorized rate of return on a regulated basis, revenues above the level must be deferred for funds to customers or another determination by the Washington Commission in a subsequent adjudicative proceeding. The Washington Commission must also set performance measurements to ~~be assessed in the~~assess a natural gas or electric company operating under a multiyear rate plan.

General Rate Case Filing

2022 GRC

In August 2022, three separate partial multiparty settlement agreements were reached. On August 5, 2022, parties filed an unopposed partial multiparty settlement agreement relating to the Voluntary Long Term Renewable Energy Purchase rider, known as Green Direct, resolving the method for calculating the energy credit Green Direct customers receive, among other matters. On August 26, 2022, six of the ~~filing~~sixteen parties, including PSE, filed a partial multiparty settlement agreement with the Washington Commission determining that the regulated portion of the Tacoma LNG Facility will be ~~to establish~~included in rates, as a ~~procedural calendar~~tracker, beginning November 2023. Also, on August 26, 2022, twelve of the sixteen parties, including PSE, filed a partial multiparty settlement agreement with the Washington Commission for the ~~adjudication~~remaining items in the GRC. The GRC settlement agreement set a two year rate plan instead of a three year plan as originally filed, provided a capital structure of 49.0% equity and 51.0% debt, and a return on equity of 9.4% with an overall rate of return of 7.16%.

On December 22, 2022, the Washington Commission issued an order on PSE’s 2022 GRC which approved, with conditions, three settlement agreements which cover a two-year period beginning January 1, 2023. The ruling provided for a weighted cost of capital of 7.16%, or 6.62% after-tax, and a capital structure of 49.0% in common equity in 2023 and 49.5% in common equity in 2024, with a return on equity of 9.4%. The order also provided for an update to power costs in 2023 and 2024 and authorizes PSE to seek recovery of the ~~case.~~costs related to the Tacoma LNG Facility concurrent with its 2023 PGA filing. PSE is also allowed to file two additional trackers that will request to recover all rate base, depreciation, and operations and maintenance (O&M) expenses related to investments under the Company’s Clean Energy Implementation Plan (CEIP) and Transportation Electrification Plan.

On December 27, 2022 PSE submitted compliance filings, including an update to power costs, and revised tariff sheets to comply with the order. On January 6, 2023, the Washington Commission rejected the compliance filing, in part; and required a revised compliance filing specific to electric rates to remove an additional $135.8 million related to PSE’s recovery of projected costs related to the modeling of the Climate Commitment Act’s impacts on PSE’s use of natural gas and coal-fired resources that had been included as part of PSE's update to power costs in the compliance filing. Per the order, PSE is allowed to either defer the $135.8 million in projected power costs and may submit a request for recovery of those costs either in its 90-day compliance filing for 2024 forecasted power costs or file a petition for Washington Commission review of these costs in a separate proceeding.

Natural gas rates became effective on January 7, 2023, resulting in a $70.8 million increase in natural gas base revenue in 2023 and a $19.5 million increase in 2024, representing increases of 6.4% and 1.65%, respectively. On January 10, 2023, the Washington Commission accepted the revised compliance filing with electric rates going into effect on January 11, 2023. The revisions reflected a final base electric revenue increase of $247.0 million in 2023 and $33.1 million in 2024, which represents an increase of 10.75% and 1.33%, respectively.

2019 GRC

PSE filed 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. On July 8, 2020, the Washington Commission issued its order on PSE’s 2019 GRC. The ruling provided for a weighted cost of capital of 7.39% or 6.8% 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 purchases gas adjustment (PGA) deferral to mitigate the impact of the rate increase in response to the economic uncertainty created by the COVID-19 pandemic. This reduced the electric revenue increase to approximately $0.9 million, or ~~0.05%~~0.1% and the natural gas increase to $1.3 million, or ~~0.15%~~0.2% and became effective October 15, 2020 and October 1, 2020, respectively.

On August 6, 2020, PSE filed a petition for judicial review with the Superior Court of the State of Washington for King County 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 Internal Revenue Service (IRS) normalization and consistency rules.

~~On July 30, 2021,~~PSE requested a Private Letter Ruling (PLR) from the IRS ~~issued~~regarding this matter. On October 7, 2020, PSE, the Washington Commission and interveners agreed to dismiss the petition for judicial review. The agreement was based on a ~~PLR to PSE which concludes~~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 would open a proceeding to review and enact the changes required by the IRS ruling. There was approximately $25.6 million in annual revenue requirement related to the 2019 GRC, which PSE requested it be allowed to track and recover.

In July 2021, PSE received a Private Letter Ruling (PLR) from the IRS which concluded that in the 2019 GRC the Washington Commission’s methodology for reversing plant-related excess deferred income taxes was an impermissible methodology under the IRS normalization and consistency rules. OnThe PLR required adjustments to PSE's rates to bring PSE back into compliance with IRS rules. In September ~~28,~~ 2021, the Washington Commission ~~issued an order amending~~amended its order ~~previously issued on July 8, 2020 to correct for items which were determined to be impermissible under IRS normalization and consistency rules as detailed~~ in accordance with the PLR. To reflect the impact of the PLR, PSE has recorded a regulatory asset and additional revenues of $24.5 million in its operating results through December 31, 2021, of which $5.6 million was collected from customers. Therefore, theThe annualized overall rate impact ~~for this element is~~was an increase of $15.8 million, or 0.7%, for electric and $3.1 million, or 0.3%,

for natural gas for a total of $18.9 million with rates effective October 1, 2021. This led to an overall annualized net increase to electric rates of $77.1 million, or 3.7%, an increase of $17.5 million above the $59.6 million granted in the revised final order. The order also led to an overall annualized net increase to natural gas rates of $45.3 million, or 5.9%, an increase of $2.4 million above the $42.9 million granted in the revised final order. The Washington Commission maintained adjustments that 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 $48.3 million, or 2.3%, and the natural gas increase to $4.9 million, or 0.6%.

For additional information, see Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.

Power Cost Only Rate Case

On December 9, 2020, PSE filed its 2020 power cost only rate case (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%).

Commission issued its Final Order approving and adopting the settlement and authorizing and requiring a power cost update through a compliance filing. On June 17, 2021, PSE filed a compliance filing with the Washington Commission with a revenue increase of $70.9 million or 3.3% due to the update on power costs with rates effective July 1, 2021.

The 2022 GRC Order in Docket No. UE-220066, set PCORC rates to zero effective January 11, 2023 and PSE agreed not to file a PCORC during 2023 and 2024, the two-year rate plan agreed to in the GRC settlement.

Revenue Decoupling ~~Filings~~Adjustment Mechanism

On December 23, 2020, the Washington Commission approved PSE’s filing to update Schedule 142 decoupling amortization rates, with an effective date of January 1, 2021, by zeroing out rates still effective past October 15, 2020 on tariff sheet Schedule 142-H, which was replaced by rates on tariff sheet Schedule 142-I effective October 15, 2020. PSE included a true up of the over-collection amounts for the period of October 15, 2020 through December 31, 2020 in PSE’s annual May 2021 decoupling filing.

On June 1, 2021, the Washington Commission approved a multi-party settlement agreement in PSE's PCORC that was originally filed on December 9, 2020. As part of this settlement agreement, the electric annual fixed power cost allowed revenue was updated to reflect changes in the approved revenue requirement. The changes took effect on July 1, 2021.

On September 28, 2021, the Washington Commission approved 2019 GRC filing updated to PLR changes. As part of this filing, the annual electric and gas delivery cost allowed revenue was updated to reflect changes in the approved revenue requirement. The changes took effect on October 1, 2021.

On January 6, 2023, the Washington Commission approved the natural gas 2022 GRC filing. As part of this filing the annual gas delivery allowed revenue was updated to reflect changes in the approved revenue requirement. Additionally, the Commission approved the removal of the earnings test from the decoupling mechanism in accordance with RCW 80.28.425(6). The changes took effect on January 7, 2023.

On January 10, 2023, the Washington Commission approved the electric 2022 GRC filing. As part of this filing the annual electric delivery and fixed power cost allowed revenue was updated to reflect changes in the approved revenue requirement. Additionally, the Commission approved the removal of the earnings test from the decoupling mechanism in accordance with RCW 80.28.425(6). The changes took effect on January 11, 2023.

On December 31, ~~2021,~~2022, PSE performed an analysis to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980. If not, for GAAP purposes only, PSE would need to record a reserve against the decoupling revenue and regulatory asset balance. Once the reserve is probable of collection within 24 months from the end of the annual period, the reserve can be recognized as decoupling revenue. The analysis indicated that ~~$3.0 million of~~ electric ~~deferred revenue will not be collected within 24 months of the annual period; therefore, a reserve adjustment was booked to 2021 electric decoupling revenue. Natural~~and natural gas deferred revenue will be collected within 24 months of the annual period; therefore, no reserve adjustment was booked to ~~2021~~2022 electric or natural gas decoupling revenue.

4342

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


Effective Date	Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)1	Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)1
Electric:	Electric:			Electric:
May 1, 20211		1.0%	$21.4
May 1, 20222				May 1, 20222	(1.0)%	$(23.5)
May 1, 20213				May 1, 20213	1.0	21.4
January 1, 2021	January 1, 2021	(1.0)	(20.6)	January 1, 2021	(1.0)	(20.6)
October 15, 20202		(0.5)	(10.2)
October 15, 20204				October 15, 20204	(0.5)	(10.2)
May 1, 2020	May 1, 2020	0.2	2.0	May 1, 2020	0.2	2.0
May 1, 2019		0.9	20.6
Natural Gas:	Natural Gas:			Natural Gas:
May 1, 2022				May 1, 2022	(0.7)%	$(7.4)
May 1, 2021	May 1, 2021	1.5%	$15.0	May 1, 2021	1.5	15.0
May 1, 2020	May 1, 2020	(0.5)	(4.8)	May 1, 2020	(0.5)	(4.8)
May 1, 2019		(5.3)	(45.9)

___________________

1.For electric and natural gas rates effective May 1, 2022, May 1, 2021 and May 1, 2020, there were no excess earnings that impacted the approved revenue change.

2.For the electric rates effective May 1, 2022, there was $8.0 million of excess deferred revenues for delivery and fixed power costs which could not be set in rates until May 1, 2023 due to the 3% rate cap.

3.For the electric rates effective May 1, 2021, there was $24.1 million of excess deferred revenues for delivery and fixed power costs which could not be set in rates until May 1, 2022 due to the 3% rate cap; there was no excess earnings that impacted both electric and natural gas revenue change. For electric and natural gas rates effective May 1, 2020 and May 1, 2019, there were no excess earnings that impacted the approved revenue change.cap.

2.4.The 2019 GRC final order lengthened the recovery period from the original one-year recovery to a two-year recovery toof April 2022. The remaining decoupling amortization balances for delivery and fixed power costs of $1.7 million were included in electric decoupling mechanism tariff rates, effective May 1, 2022.

Electric Rates

Colstrip Adjustment Rider

Effective Date

Average

Percentage

Increase (Decrease)

in Rates

Increase (Decrease)

in Revenue

(Dollars in Millions)

January 11, 2023

2.2%

$50.3

Energy Charge Credit Recovery Adjustment

Effective Date

Average

Percentage

Increase (Decrease)

in Rates

Increase (Decrease)

in Revenue

(Dollars in Millions)

January 11, 2023

1.5%

$35.3

Rates Not Subject to Refund Rate Adjustment

Effective Date

Average

Percentage

Increase (Decrease)

in Rates

Increase (Decrease)

in Revenue

(Dollars in Millions)

January 11, 2023

7.9%

$182.5

Rates Subject to Refund Rate Adjustment

The purpose of this schedule is to charge customers the provisionally approved rates subject to refund approved in a multiyear rate plan, for property granted provisional approval for recovery as authorized in Washington Commission Docket No. UE-220066. PSE will file an annual review March 31st of each year, which will be reviewed by the Washington Commission.

Effective Date

Average

Percentage

Increase (Decrease)

in Rates

Increase (Decrease)

in Revenue

(Dollars in Millions)

January 11, 2023

4.0%

$91.7

Transportation Electrification Plan Adjustment Rider

Effective Date

Average

Percentage

Increase (Decrease)

in Rates

Increase (Decrease)

in Revenue

(Dollars in Millions)

March 1, 2023

0.2%

$6.0

Conservation Service Rider

The following table sets forth conservation rider 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)
May 1, 2022	1.0%	$21.6
May 1, 2021	(0.6)	(12.3)
May 1, 2020	0.9	17.8

Federal Incentive Tracker

The following table sets forth 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, 20231	1.3%	$1.0
January 1, 2022	0.1	(28.2)
January 1, 2021	0.3	(29.5)
January 1, 2020	(0.04)	(37.8)

____________________

1.The 2022 rate period represented the final year of the ten year period used to pass back the Treasury Grants included in Schedule 95A (Federal Incentive Tracker). The overall rate now represents a surcharge as amounts from the 2022 filing are expected to be over-distributed.

Low Income Program

The following table sets forth the low income program funding 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)
October 1, 2022	1.1%	$25.8
October 1, 2021	0.3	5.8

Power Cost Adjustment Clause

PSE exceeded the $20.0 million cumulative deferral balance in its PCA mechanism in 2020. The surcharging of deferrals can be triggered by the Company when the balance in the deferral account is a credit of $20.0 million or more. During 2020, actual power costs were higher than baseline power costs, thereby creating an under-recovery of $76.1 million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $32.1 million of the under-recovered amount, and customers were responsible for the remaining $44.0 million, or $46.0 million including interest. PSE filed to recover the deferred balance in Docket No. UE-210300, and the Washington Commission allowed the recovery effective December 1, 2021.

Additionally, PSE exceeded the $20.0 million cumulative deferral balance in its PCA mechanism in 2021. During 2021, actual power costs were higher than baseline power costs; thereby, creating an under-recovery of $68.0 million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $31.3 million of the under-recovered amount, and customers were responsible for the remaining $36.7 million, or $38.4 million including interest. On October 27, 2022, the Washington Commission approved PSE's 2021 PCA report that proposes to recover the deferred balance for 2021 PCA period by keeping the current rates and allowing recovery from January 1, 2023 through November 30, 2023.

The following table sets forth power cost adjustment clause filing 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)
December 1, 20201	2.1%	$43.9
October 15, 2020	(0.2)	(3.3)
July 3, 20202	1.2	23.9

______________

1.The Schedule 95 PCA mechanism rates from the prior year that recover the 2019 imbalance (effective December 1, 2020) have been extending through December 31, 2022 to recover the imbalance attributable to 2020. As of October 27, 2022 in UE-220308 Final Order, the Washington Commission approved to extend PCA imbalance rates to recover the PCA imbalance attributable to 2021 from January 1, 2023 to November 30, 2023.

2. The rates for the Electric Special Contract were zeroed out effective July 3, 2020 following the July 2019 through June 2020 period. The actual residual amount resulting at July 31, 2020 were included in the electric Schedule 129 Low Income Program rates that became effective October 1, 2020.

Power Cost Adjustment Mechanism

PSE currently has a power cost adjustment (PCA) mechanism that provides for the deferral of power costs that vary from the “power cost baseline” level of power costs. The “power cost baseline” levels are set, in part, based on normalized assumptions about weather and 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 cumulative deferral trigger is reached.

Effective January 1, 2017, the following graduated 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

For the year ended December 31, ~~2021,~~2022, in its PCA mechanism, PSE under recovered its allowable costs by ~~$68.0~~$110.1 million of which ~~$36.7~~$74.6 million was apportioned to customers and ~~$1.7~~$1.5 million of interest was accrued on the deferred customer balance. This compares to an under recovery of allowable costs of ~~$76.1~~$68.0 million for the year ended December 31, ~~2020,~~2021, of which ~~$44.0~~$36.7 million was apportioned to customers and accrued ~~$2.0~~$1.7 million interest on the total deferred customer balance. ~~The under recovery in 2020 was included in the Power Cost Adjustment Clause filing, mentioned below.~~

~~Power Cost Adjustment Clause Filing~~

actual power costs were higher than baseline power costs, thereby creating an under-recovery of $76.1 million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $32.1 million of the under-recovered amount, and customers were responsible for the remaining $44.0 million, or $46.0 million including interest. PSE filed to recover the deferred balance in Docket UE-210300, effective December 1, 2021, and the Washington Commission approved PSE’s request on September 30, 2021.

~~The following table sets forth power cost adjustment clause filing 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)
December 1, 20201
2.1% $43.9
October 15, 2020 (0.2) (3.3)
July 3, 20202
1.2 23.9
July 1, 2019 (1.2) (24.9)
May 1, 2019 0.1 3.3

~~______________~~

1.The Schedule 95 PCA mechanism rates from the prior year that recover the 2019 imbalance (effective 12-1-2020 have been extending through December 31, 2022 to recover the imbalance attributable to 2020.

2.The rates for the Electric Special Contract were zeroed out effective July 3, 2020 following the July 2019 through June 2020 period. The actual residual amount resulting at July 31, 2020 were included in the electric Schedule 129 Low Income Program rates that become effective October 1, 2020.

~~Conservation Rider~~

~~The following table sets forth conservation rider 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)
May 1, 2021 (0.6)% $(12.3)
May 1, 2020 0.9 17.8
May 1, 2019 (0.9) (17.5)

Property Tax Tracker ~~Mechanism~~

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


Effective Date	Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)	Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
May 1, 2022				May 1, 2022	(0.3)%	$(5.8)
May 1, 2021	May 1, 2021	(0.1)%	$(1.7)	May 1, 2021	(0.1)	(1.7)
May 1, 2020	May 1, 2020	0.07	1.4	May 1, 2020	0.07	1.4
May 1, 2019		(0.2)	(5.1)

4546

~~Federal Incentive Tracker Tariff~~Residential and Farm Exchange Benefit

The following table sets forth ~~the federal incentive tracker tariff revenue requirement~~residential and farm exchange benefit adjustments approved by the Washington Commission and the corresponding expected annual impact on ~~PSE’s~~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, 2022 0.1% $(28.2)
January 1, 2021 0.3 (29.5)
January 1, 2020 (0.04) (37.8)
January 1, 2019

0.1

(38.7)

Effective Date

Average

Percentage

Increase (Decrease)

in Rates

Total credit to be passed back to eligible customers

(Dollars in Millions)

November 1, 2021

0.4%

$(75.7)

Natural Gas Rates

Distribution Pipeline Provisional Recovery Adjustment

This schedule implements surcharges in order to defer the revenues associated with the provisional recovery of $30.0 million for the four miles of distribution pipe to support proper allocation of the investments in a later filing as authorized in Washington Commission Docket No. UG-220067.

Effective Date

Average

Percentage

Increase (Decrease)

in Rates

Increase (Decrease)

in Revenue

(Dollars in Millions)

January 7, 2023

0.3%

$3.0

Rates Not Subject to Refund Rate Adjustment

Effective Date

Average

Percentage

Increase (Decrease)

in Rates

Increase (Decrease)

in Revenue

(Dollars in Millions)

January 7, 2023

(0.1)%

$(1.6)

Rates Subject to Refund Rate Adjustment

Effective Date

Average

Percentage

Increase (Decrease)

in Rates

Increase (Decrease)

in Revenue

(Dollars in Millions)

January 7, 2023

4.1%

$45.5

Conservation Service 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, 2022	0.3%	$3.2
May 1, 2021	(0.2)	(1.5)
May 1, 2020	0.4	3.5

Cost Recovery Mechanism for Pipeline Replacement

The following table sets forth cost recovery mechanism (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)
January 7, 20231	(2.0)%	$(22.6)
November 1, 2022	0.4	4.6
November 1, 2021	0.5	4.9
November 1, 2020	1.2	10.6

____________________

1.Per 2022 GRC Final Order in Docket No. UG-220067, CRM rates on Schedule 149 were set to zero as of January 7, 2023.

Low Income Program ~~Tracker Tariff~~

Effective Date

Average

Percentage

Increase (Decrease)

in Rates

Increase (Decrease)

in Revenue

(Dollars in Millions)

Effective Date

Average

Percentage

Increase (Decrease)

in Rates

Increase (Decrease)

in Revenue

(Dollars in Millions)

October 1, 2022

(0.04)%

$(0.4)

October 1, 2021

0.3%

$5.8

October 1, 2021

(0.3)

(3.0)

~~Residential Exchange Benefit~~Property Tax Tracker

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)
November 1, 2021 0.4% $(75.7)
October 12, 2019 0.01 (81.8)

~~Natural Gas Rates~~

~~Cost Recovery Mechanism~~

~~The following table sets forth cost recovery mechanism (CRM)~~property tax tracker 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, 2021 0.5% $4.9
November 1, 2020 1.2 10.6
November 1, 2019 0.8 7.0


Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
May 1, 2022	0.02%	$0.2
May 1, 2021	0.3	3.2
May 1, 2020	(0.3)	(2.8)

Purchased Gas Adjustment

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.

On October 28, 2021, the Washington Commission approved PSE's request for November 2021 PGA rates in Docket No. UG-210721, effective November 1, 2021. As part of that filing, PSE requested an annual revenue increase of $59.1 million; where PGA rates, under Schedule 101, increase annual revenue by $80.6 million, and the tracker rates under Schedule 106, decrease annual revenue by $21.5 million. ~~Those~~

The annual 2021 PGA rate increases ~~will be set~~were in addition to continuing the collection on the remaining balance of $69.4 million under Supplemental Schedule ~~106B.~~106B, which were set, in effect, through September 30, 2023 per the 2019 GRC.

On October 27, 2022, the Washington Commission approved PSE's request for PGA rates in Docket No. UG-220715, effective November 1, 2022. As part of that filing, PSE requested an annual revenue increase of $155.3 million; where PGA rates, under Schedule 101, increase annual revenue by $142.1 million, and the tracker rates under Schedule 106, increase annual revenue by $13.2 million.

On November 15, 2022, the FERC approved a settlement of a counterparty, FERC Docket No. RP17-346. Under the terms, PSE was allocated $24.2 million related to PSE natural gas services which was recorded on December 31, 2022 and included below. The 2022 GRC order requires PSE to amortize the refund in 2023 as a credit against natural gas costs and therefore pass back the refund to customers through the PGA mechanism.

The following table presents the PGA mechanism balances and activity at December 31, ~~2021~~2022 and December 31, ~~2020:~~2021:


Puget Energy and Puget Sound Energy	Puget Energy and Puget Sound Energy					Puget Energy and Puget Sound Energy
(Dollars in Thousands)	(Dollars in Thousands)	December 31,		December 31,		(Dollars in Thousands)	December 31,		December 31,
PGA receivable balance and activity	PGA receivable balance and activity	2021		2020		PGA receivable balance and activity	2022		2021
PGA receivable beginning balance	PGA receivable beginning balance	$	87,655	$	132,766	PGA receivable beginning balance	$	57,935	$	87,655
Actual natural gas costs	Actual natural gas costs	364,775		314,792		Actual natural gas costs	457,950		364,775
Allowed PGA recovery	Allowed PGA recovery	(396,236)		(363,886)		Allowed PGA recovery	(496,879)		(396,236)
Interest	Interest	1,741		3,983		Interest	1,674		1,741
PGA receivable ending balance		$	57,935	$	87,655
Refund from counterparty settlement						Refund from counterparty settlement	(24,216)		—
PGA (liability)/receivable ending balance						PGA (liability)/receivable ending balance	$	(3,536)	$	57,935

The following table sets forth the PGA rate adjustment 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, 2021 5.8% $59.1
November 1, 2020 7.7 70.0
October 1, 2020 (3.9) (35.5)
November 1, 20191
13.4 118.3
May 1, 20192
6.3 54.0

~~_______________~~

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

2.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.

~~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, 2021 0.3% $3.2
May 1, 2020 (0.3) (2.8)
May 1, 2019 (0.2) (1.6)

~~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, 2021 (0.2)% $(1.5)
May 1, 2020 0.4 3.5
May 1, 2019 0.1 1.1

~~Low Income Program Tracker Tariff~~

Effective Date

Average

Percentage

Increase (Decrease)

in Rates

Increase (Decrease)

in Revenue

(Dollars in Millions)

Effective Date

Average

Percentage

Increase (Decrease)

in Rates

Increase (Decrease)

in Revenue

(Dollars in Millions)

October 1, 2021

(0.3)%

$(3.0)

November 1, 2022

14.9%

$155.3

November 1, 2021

5.8

59.1

November 1, 2020

7.7

70.0

October 1, 2020

(3.9)

(35.5)

Other Proceedings

Voluntary Long-Term Renewable Energy

PSE offers Green Direct to larger customers (aggregated annual loads greater than ~~10,000 MWh)~~10,000-megawatt hours (MWh)) and government customers. The initial resource option offered under this rate schedule is a ~~new~~ wind generation 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.

The Washington Commission approved a second phase of the Green Direct product in 2018. The phase 2 project is the 150 MW Lund Hill Solar facility located in Klickitat County, Washington. The solar facility ~~is expected to achieve~~declared full commercial ~~operation in~~operations on October 19, 2022 and will serve an additional twenty customers who enrolled in 2018. On March 1, 2021, the associated power purchase agreement went into effect under an interim supply agreement for renewable energy delivered to PSE’s system; and thus, the phase 2 customers began receiving renewable energy under their agreement on March 1, 2021. All

Green Direct customers are now receiving a blend of the phase 1 wind and the renewable energy delivered under the phase 2 power purchase agreement.

Crisis Affected Customer Assistance Program

On April 6, 2020, PSE filed with the Washington Commission revisions to its currently effective ~~Tariff WN U-60.~~electric and natural gas service tariffs. The purpose of this filing iswas to incorporate into PSE’s low-income tariff a new temporary bill assistance program, Crisis Affected Customer Assistance Program ~~(CACAP)~~(CACAP-1) (Dockets No. UE-200331 and UG-200332), to mitigate the economic impact of the COVID-19 pandemic on PSE’s customers. CACAP ~~would allow~~allowed PSE customers facing financial hardship due to COVID-19 to receive up to $1,000 in bill assistance. The program ~~puts to immediate use~~made available $11.0 million in unspent low income funds from prior years, therefore resulting in no rate impact, and ~~supplements~~supplemented other forms of financial assistance. The program does not require an increase to rates and is 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 onCACAP-1 ran from 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 CACAP-1 program successfully distributed over $8.9 million in bill assistance funds to over 15,000 households from its inception in April 2020 through the program end date on September 30, 2020.

On March 28, 2021, the Washington Commission approved PSE’s ~~second Crisis Affected Customer Assistance Program (CACAP-2), effective April 12, 2021.~~ CACAP-2 ~~will provide up to $2,500 in bill assistance per year for each qualifying low-income household. The CACAP-2 total~~(Dockets No. UE-210137 and UG-210138). With a program budget isof $20.0 million for electric customers and $7.7 million for natural gas ~~customers. Natural gas funds may be used~~customers, CACAP-2, which ran from April 12, 2021, to March 29, 2022, provided up to $2,500 per year in bill assistance for ~~electric bills if necessary. Customers may apply~~arrearages for ~~CACAP-2 more than once during the 12-month program year of October-September.~~each qualifying low-income household.

On October 15, 2021, PSE submitted for the Washington Commission’s review and approval a Supplemental CACAP (Dockets No. UE-210792 and UG-210793) filing to continue assistance for PSE customers facing financial hardship due to COVID-19. The Washington Commission approved the Supplemental CACAP ~~would utilize~~program to be effective on November 15, 2021. The Supplemental CACAP utilized carry-over funds not expended in any prior years under PSE’s Schedule 129 Home Energy Lifeline ~~Program. The Supplemental CACAP benefits,~~Program (HELP), with a combined total budget of $34.5 million for both electric and natural gas residential customers ~~would be a combined total of $34.5 million and be capped~~(capped at $23.7 million and $10.8 million, respectively. Additionally, the Supplemental CACAP filing proposed to revise the CACAP-2 total program budget to $27.7 million for electric customers (instead of $20.0 million for electric customers and $7.7 million for natural gas customers)respectively). ~~The Supplemental CACAP budget for natural gas customers of $10.8 million would be used for both the CACAP-2 program and the Supplemental CACAP program benefits.~~

~~The~~ Supplemental CACAP benefits ~~would be available~~offered to PSE’s residential customers who have a past due balance on their PSE electric or natural gas service account and who have a total net household income which is at or below 200% of the federal poverty level guidelines, based on household, as determined by the Company. The Supplemental CACAP benefits would cover a qualifying residential customer’s past due balance, up to $2,500. PSE ~~would apply~~applied the Supplemental CACAP benefits ~~to qualifying residential service accounts~~ automatically, with an opt-out ~~option. The Supplemental CACAP was approved by~~option, in December 2021.

For additional information, see Note 4, "Regulation and Rates" in the ~~Washington Commission at the November 12, 2021 open meeting. Both CACAP-2 and Supplemental CACAP~~

would be administered until funds are exhausted. PSE has processed 27,004 COVID-19 bill assistance applications totaling $18.0 million and processed 46,633 Supplemental CACAP applications totaling $26.5 million asCombined Notes to Consolidated Financial Statements included in Item 8 of ~~December 31, 2021.~~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 refinance existing or issue new long-term debt, obtain access to new or renew existing credit facilities and could increase the cost of 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 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. For additional information, see "Financing Program" included in Item 7 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.

In 2021, the Washington Legislature adopted the Climate Commitment Act (CCA), which establishes a greenhouse gases (GHG) emissions cap-and-invest program that caps GHG emissions beginning on January 1, 2023 and makes further reductions to the cap annually through 2050. The Washington Department of Ecology (WDOE) published final regulations to implement the program on September 29, 2022, which became effective on October 30, 2022. WDOE also indicated that they will have subsequent rulemakings that will build off initial rulemaking as program implementation gets underway and progress with Washington State carbon goals are evaluated. See Part I Item 1 "Recent and Future Environmental Law and Regulation" in this report for further details on the CCA. Based on the rules passed in 2022, there is potential for PSE’s compliance with the CCA to result in increased costs to customers or amounts that PSE may not be able to recover through electric and natural gas rates. Potential risks associated with CCA compliance could include: the evolving nature of the CCA rulemaking as indicated by

WDOE, market uncertainty based on rule interpretation during implementation, unresolved recovery methodology for CCA’s impact on energy costs, company costs, customer rate impacts, and cash, liquidity and credit volatility.

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; therefore, PSE’s business has historically been recognized as a natural and regulated monopoly. However, PSE faces competition from public utility districts and municipalities or efforts by citizens organizing to form such entities that want to establish their own government-owned utility, as a result of which PSE may lose a number of customers. PSE also faces increasing competition for sales to its retail customers through alternative methods of electric energy generation, including solar and other self-generation 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, ~~2021,~~2022, and December 31, ~~2020.~~2021.

Non-GAAP Financial Measures – Electric and Natural Gas Margins

The following discussion includes financial information prepared in accordance with GAAP, as well as two other financial measures, electric margin and natural gas margin, that are considered “non-GAAP financial measures.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that includes adjustments that result in a presentation that is not defined by GAAP. 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 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.

The following table presents operating income and a reconciliation of utility electric and natural gas margins to the most directly comparable GAAP measure, operating income:


Puget Sound Energy	Puget Sound Energy					Puget Sound Energy
(Dollars in Thousands)	(Dollars in Thousands)	Year Ended December 31,				(Dollars in Thousands)	Year Ended December 31,
		2021		2020			2022		2021
Operating income (loss)	Operating income (loss)	$	580,147	$	509,192	Operating income (loss)	$	792,462	$	580,147
Electric utility revenue	Electric utility revenue	2,671,623		2,319,416		Electric utility revenue	2,961,457		2,671,623
Purchased electricity	Purchased electricity	(784,565)		(593,719)		Purchased electricity	(1,038,728)		(784,565)
Electric generation fuel	Electric generation fuel	(282,254)		(199,107)		Electric generation fuel	(348,159)		(282,254)
Residential exchange	Residential exchange	82,225		80,294		Residential exchange	77,715		82,225
Utility electric margin (non-GAAP)	Utility electric margin (non-GAAP)	$	1,687,029	$	1,606,884	Utility electric margin (non-GAAP)	$	1,652,285	$	1,687,029
Natural gas operating revenue	Natural gas operating revenue	$	1,067,418	$	980,913	Natural gas operating revenue	$	1,209,636	$	1,067,418
Purchased natural gas	Purchased natural gas	(398,553)		(362,872)		Purchased natural gas	(500,849)		(398,553)
Utility natural gas margin (non-GAAP)	Utility natural gas margin (non-GAAP)	$	668,865	$	618,041	Utility natural gas margin (non-GAAP)	$	708,787	$	668,865
Other revenue	Other revenue	$	66,620	$	26,121	Other revenue	$	45,080	$	66,620
Unrealized gain (loss) on derivative instruments, net	Unrealized gain (loss) on derivative instruments, net	13,785		(26,807)		Unrealized gain (loss) on derivative instruments, net	261,177		13,785
Other operation and maintenance expenses	Other operation and maintenance expenses	(629,864)		(597,048)		Other operation and maintenance expenses	(665,259)		(629,864)
Non-utility expense and other	Non-utility expense and other	(56,242)		(42,266)		Non-utility expense and other	(47,194)		(56,242)
Depreciation and amortization	Depreciation and amortization	(807,519)		(747,131)		Depreciation and amortization	(774,291)		(807,519)
Taxes other than income tax expense	Taxes other than income tax expense	(362,527)		(328,602)		Taxes other than income tax expense	(388,123)		(362,527)
Operating income (loss)	Operating income (loss)	$	580,147	$	509,192	Operating income (loss)	$	792,462	$	580,147

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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 for the years ended December 31, ~~2020,~~2021, to December 31, ~~2021:~~2022:

_______________

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

~~2020~~2021 compared to ~~2021~~2022

Electric Operating Revenue

Electric operating revenues increased ~~$352.2~~$289.8 million primarily due to increased retail sales of ~~$249.9~~$150.9 million, sales to other utilities and marketers of ~~$86.3 million, transportation and other revenue of $68.5~~$175.1 million, and other decoupling revenue of ~~$9.5~~$5.4 million; partially offset by a decrease in decoupling revenue of ~~$62.1~~$25.0 million and transportation and other revenue of $16.5 million. These items are discussed in detail below:

•Electric retail sales increased ~~$249.9~~$150.9 million due to an increase of ~~$148.4~~$85.2 million in rates compared to the prior year and an increase of ~~$101.5~~$65.7 million from an increase in retail electricity usage of ~~4.7%~~2.7%. The increase in rates is primarily due to the tariffs filed pursuant to the Company's ~~most recent~~2021 PCORC ~~GRC and PCA filing~~ effective July 1, 2021 ~~October 15, 2020~~ and ~~December~~the conservation service rider effective May 1, ~~2020, respectively.~~2022. See Management's Discussion and Analysis, "Regulation of PSE Rates and ~~Rates"~~Recovery of PSE Costs" included in Item 27 of this report for rate changes. ~~Residential~~The increase in retail usage was due to an increase in residential and commercial usage of 2.4% and 3.3%, respectively. Residential usage increased ~~4.6%~~due to a 5.5% increase in heating degree days due to lower than normal temperatures, primarily in the 2nd quarter of 2022 and ~~5.8%, respectively, driven by an~~a 6.6% increase in cooling ~~and heating~~ degree days due to higher than normal temperatures, primarily in the 3rd quarter of ~~13.6% and 8.5%, respectively, an~~2022. The increase in ~~retail customers of 1.3% compared~~commercial usage was driven by employees returning to ~~2020, and by COVID-19~~work after business shut downs ~~primarily impacting commercial customers~~and lack of staffing in ~~2020.~~2021 due to COVID-19.

•Sales to other utilities and marketers increased ~~$86.3~~$175.1 million primarily due to a ~~101.5%~~109.6% increase in ~~the market prices and a 12.5% increase in volumes. The increase to the market~~electric wholesale sale price ~~was~~ driven by ~~increases~~a nationwide increase in natural gas ~~prices due to constrained~~price, that fuel natural gas-fired electric generation, following worldwide natural gas supply ~~and~~constraints along with increased ~~demand. Higher sales~~demand from overseas markets. Additionally, wholesale sale volumes ~~were the result of~~ increased ~~volume from~~1.8%.

~~PSE's coal- and gas-fired generation which increased 22.6% and 15.6%, respectively in 2021, particularly in May-September 2021, driven by greater value in the market.~~

•Decoupling revenue decreased ~~$62.1~~$25.0 million, primarily attributable to a ~~$35.1~~$7.7 million and ~~$27.0~~$17.3 million decrease in delivery and fixed production cost (FPC) deferral revenues, respectively. This was driven mainly by ~~higher~~lower allowed revenue per customer and increased usage ~~in the current period compared to the same period in 2020~~for delivery deferral revenues as well as increased usage ~~as noted above in electric retail sales.~~for FPC deferral revenues. This resulted in ~~actual~~allowed revenues being ~~greater~~lower than ~~allowed~~actual decoupling deferral revenues by a greater margin in the current year ~~whereas in~~compared to the prior ~~year actual revenues were lower compared to allowed revenues.~~year.

•Other decoupling revenue increased ~~$9.5~~$5.4 million, primarily due to the amortization of prior year residential delivery overcollections beginning in May 2022. This was partially offset by a ~~$13.0~~$2.0 million ~~increase~~decrease related to GAAP alternative revenue program recognition guidelines. As of the year ~~to date~~ ended December 31, ~~2020,~~2021, there were $8.0 million of deferred 2020 GAAP alternative decoupling revenues that were ~~not anticipated to be collected within 24 months, and therefore~~recognized, which was ~~reserved. The full $8.0 million reserve was recognized in the first quarter of 2021 resulting in an increase of $16.0 million,~~ partially offset by $3.0 million in deferred 2021 GAAP alternative decoupling revenues. As of ~~2021 revenue currently reserved as its not anticipated to be collected within 24 month of~~the year ended December 31, 2022, there were $3.0 million of deferred 2021 ~~and a $3.5 million increase in collection of prior year undercollected~~GAAP alternative decoupling revenues ~~due to an increase in amortization rates and customer usage.~~that were recognized.

•Transportation and other revenue ~~increased $68.5~~decreased $16.5 million primarily due to no production tax credit (PTC) deferral revenue for the ~~following: (i)~~re-purpose of the PTCs in 2022 compared to $45.6 million in 2021 and a decrease of $32.6 million related to the IRS PLR which includes revenue recognition in 2021, see Management's Discussion and Analysis, "Regulation of PSE Rates and Recovery of PSE Costs" included in Item 7 of this report. The decreases were partially offset by an increase in net wholesale non-core natural gas sales of ~~$40.3~~$62.1 million, which was primarily due to a $130.8 million increase in wholesale sales driven by a ~~$74.2 million~~2.8% increase in gas sales ~~as the~~volume at an average price ~~of non-core gas increased 90.0%~~that was 71.8% higher in ~~2021~~2022 compared to ~~2020. The increase in non-core gas sales were partially offset by~~2021 and a ~~$63.0~~$107.7 million increase in the ~~total~~ cost of ~~the non-core~~ gas sold, which was also due to a ~~77.5%~~higher average price and increased volumes. Additionally, the increase in the ~~average price of~~net whole non-core gas ~~purchases. Higher gas prices in 2021~~sales was also ~~resulted in~~driven by a ~~$29.2~~$39.0 million increase in ~~gains on~~ gas financial hedges in 2021 compared to 2020; (ii) revenue recognition of $20.4 million as a result of the IRS PLR which concluded the EDIT methodology that was included in rates following the 2019 GRC order was impermissible, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 7 of this report for more information, and $4.6 million collected from customers in 2021 for an impact of $15.8 million (iii) an increase in production tax credits (PTCs) deferral revenue of $5.8 million for the re-purpose of the PTCs driven by an increase in current period taxable income; (iv) an increase of $5.4 million in transmission revenue primarily related to short-term point to point transmission sales; (v) an increase in advanced metering infrastructure (AMI) return deferral of $3.4 million and (vi) an increase of $3.3 million in rent from wireless pole contacts. These increases were partially offset by a decrease in revenue subject to refunds of $7.7 million primarily due to the passback of the regulatory deferral to customers for the tax rate decrease in the Tax Cuts and Jobs Act in 2020.hedging gains.

Electric Power Costs

Electric power costs increased ~~$272.1~~$324.6 million primarily due to an increase of ~~$190.8~~$254.2 million of purchased electricity costs, ~~and $83.1~~$65.9 million of electric generation fuel ~~costs.~~costs and a decrease in residential exchange credits of $4.5 million. These items are discussed in detail below:

•Purchased electricity expense increased ~~$190.8~~$254.2 million due to a ~~32.5%~~17.0% increase in wholesale ~~prices~~electric purchase volumes and a 13.0% increase in average wholesale purchase prices. The increase in volume was driven by a 25.8% increase in Mid-Columbia hydro, increased wind purchase volumes from Golden Hills and Clearwater, which commenced operations in 2022, and Powerex energy purchases that were added in 2022. Purchase volumes increased due to ~~prices trending higher~~a combination of an increase in ~~2021 compared to 2020 when prices were down~~load of 1.8% and a decrease in natural gas-fired generation volume of 17.5%, due to lower market heat rates as natural gas prices increased at a higher ~~production, mild weather and a surplus~~rate than power prices. The increase in wholesale purchase prices of 13.0% was primarily due to ~~decreased demands caused by COVID-19; partially offset by a 0.3% decrease~~the aforementioned increase in ~~wholesale electricity purchases.~~nationwide natural gas prices, which led to increases in all power prices.

•Electric generation fuel expense increased ~~$83.1~~$65.9 million ~~primarily~~driven by an $8.1 million increase in Colstrip Units 3 and 4 variable fuel expense due to a ~~$74.5 million~~6.1% increase in ~~combustion turbine (CT)~~coal fuel burned and a 12.0% increase in the average price per ton. Additionally, natural gas-fired generation fuel costs increased $57.6 million as CTunit production ~~increased 15.6% driven by~~costs were 51.2% higher ~~market heat rates, particularly between April - July 2021. Additionally, there was higher unit costs, the cost to produce power,~~ due to higher natural gas prices, as discussed above in ~~2021.~~sales to other utilities. This increase was partially offset by a 17.5% reduction in natural gas-fired generation volumes driven by lower market heat rates.

•Residential exchange credits decreased by $4.5 million due to a 0.4% change in the amount of credits to be passed back to customers effective November 1, 2021, see Management's Discussion and Analysis, "Regulation of PSE Rates and Recovery of PSE Costs" included in Item 7 of this report; partially offset by an increase in residential usage of 2.4% as discussed above in electric retail sales.

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

The following chart displays the changes in PSE’s natural gas margin for the years ended December 31, ~~2020,~~2021, to December 31, ~~2021:~~2022:

_______________

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

~~2020~~2021 compared to ~~2021~~2022

Natural Gas Operating Revenue

Natural gas operating revenue increased ~~$86.5~~$142.2 million primarily due to higher retail sales of ~~$100.9~~$149.7 million and transportation and other revenue of $10.6 million. This increase was partially offset by decreased decoupling revenue of ~~$8.7~~$14.3 million and ~~decreased~~ other decoupling revenue of ~~$5.3~~$3.8 million. These items are discussed in the following details:

•Natural gas retail sales increased ~~$100.9~~$149.7 million due to an increase in rates of ~~$60.3~~$92.8 million and an increase in natural gas load of ~~4.3%,~~5.2% or ~~$40.6~~$56.9 million of natural gas sales. The increase in rates is ~~primarily~~ due to the ~~PGA increase effective November 1, 2020 and the~~ tariffs ~~effective October 1, 2020~~ filed pursuant to the Company's most recent ~~GRC. See~~CRM and PGA effective November 1, 2021 and Conservation rider effective May 1, 2022, see Management's Discussion and Analysis, "Regulation of PSE Rates and ~~Rates"~~Recovery of PSE Costs" included in Item 7 of this report for natural gas rate changes. ~~Natural gas~~The increase in load is driven by an increase of commercial and residential usage of 9.2% and 3.5%, respectively. The increase in commercial usage was largely due to employees returning to work after business shut downs and lack of staffing in 2021 due to COVID-19. Residential usage

increased ~~primarily~~ due to an ~~increase in commercial customer usage of 7.7% driven by higher COVID-19 business shut downs in 2020, residential customer usage of 3.1% driven by an~~5.5% increase in heating degree days due to lower than normal temperatures, primarily in the 2nd quarter of ~~8.5% and an increase in natural gas customers of 1.1%.~~2022.

•Decoupling revenue decreased ~~$8.7~~$14.3 million, primarily attributable to increased usage in ~~the current period~~2022 and lower allowed revenue per customer compared to ~~the same period in 2020, as noted above in natural gas retail sales.~~2021. This resulted in actual natural gas revenues being ~~closer to~~higher than allowed natural gas revenues in the current period, ~~compared to the same period~~whereas in ~~the prior year.~~2021, actual revenues were lower than allowed revenues.

•Other decoupling revenue decreased ~~$5.3~~$3.8 million due to an increase in current period amortization of prior year ~~decoupling~~ revenues compared to ~~the same period in 2020.~~2021. This is attributable to anincreased usage in 2022 as well as increased amortization rates, both of which increase the rate at which deferral revenues are recovered from customers.

•Transportation and other revenue increased $10.6 million primarily due to LNG return deferral revenue of $18.9 million which started in ~~customer usage~~2022; partially offset by a decrease of $6.2 million related to the IRS PLR which included revenue recognition in 2021 and amortization of the PLR to offset recovery through rates ~~from increased cumulative deferral revenues to recover from customers.~~in 2022, see Management's Discussion and Analysis, "Regulation of PSE Rates and Recovery of PSE Costs" included in Item 7 of this report.

Natural Gas Energy Costs

Purchased natural gas expense increased ~~$35.7~~$102.3 million due to an increase in the PGA rates in November ~~2020~~2021 and an increase in natural gas usage of ~~4.3%~~5.2% as stated in the natural gas retail sales section above.

Other Operating Expenses and Other Income (Deductions)

The following chart displays the details of PSE's other operating expenses and other income (deductions) for the years ended December 31, ~~2020,~~2021, to December 31, ~~2021:~~2022:

~~2020~~2021 compared to ~~2021~~2022

Other Operating Expenses

•Net unrealized (gain) loss on derivative instruments increased ~~$40.6~~$247.4 million to a net gain of ~~$13.8~~$261.2 million for the ~~year-to-date~~year ended December 31, ~~2021.~~2022. The primary driver was the ~~increase~~change in the weighted average forward prices for electric and natural gas. Specifically, electric prices increased ~~41.4%~~128.1% resulting in ~~$31.4~~$236.3 million in gain for electric. Natural gas prices increased ~~26.3%~~5.3% resulting in ~~$92.4~~$117.1 million in gain for natural gas. These gains were partially offset by the net settlement of electric trades that were previously recorded as ~~$11.9~~$24.0 million in gain and natural gas trades previously recorded as ~~$71.3~~$82.0 million in gain.

•Utility Operations and Maintenance expense increased ~~$32.8~~$35.4 million primarily due to increases of (i) ~~$16.6~~$9.8 million in customer service expenses primarily driven by increased low income assistance; (ii) $6.2 million increase in the non-service cost component of the qualified pension net periodic benefit cost in 2022 compared to 2021; (iii) $5.3 million of other generation maintenance costs due to increased wind turbine maintenance; (iv) $5.0 million in administrative and general expenses due to additional vice presidents, ~~and~~ incentive and merit increases ~~customer service~~and IT costs related to technology growth and resumption of training and travel expenses in 2022 compared to 2021; (v) $4.8 million in Washington Commission filing fees related to GRC filings; and (vi) $2.4 million in miscellaneous distribution operations expenses due to ~~higher low income assistance and green power spending, outside services employed due~~training costs specific to higher legal costs and clean energy program costs, and uncollectible accounts; (ii) $14.5 million of distribution expense related to higher operations and maintenance costs associated with construction, vegetation management, inspections, maps and records and emergent outage work; (iii) $3.5 million of injuries and damages expense due to higher liability claims and insurance costs; (iv) $3.5 million related to higher CT plant operations costs; and (v) $2.1 million related to higher building maintenance, software and compliance costs. The increases were partially offset by decreased (i) customer records and collection expense of $3.8 million due to reduced call center and billing costs related to paperless billing adoption; (ii)$3.2 million of Colstrip operation costs and (iii) $3.1 million of distribution operations miscellaneous expenses driven by higher COVID-19 costs for service providers in 2020 as compared to 2021.electric operations.

•Non-utility and other expense ~~increased $14.0~~decreased $9.0 million primarily due to $12.9 million ~~related to the~~expenses associated with a 2021 PWI land sale, which was comprised of $11.0 million for the cost of the sale and $1.9 million of selling expenses. ~~Additionally, PSE~~This decrease was partially offset by an increase of $3.9 million related to biogas purchase expense.

5557

had an increase for the long-term incentive plan of $6.6 million due to estimated performance results and an increase of $7.4 million related to biogas purchase expense, as compared to the prior year. These increases were partially offset by a $7.0 million biogas settlement in 2020 and a decrease in supplemental executive retirement plan (SERP) costs of $5.0 million.

•Depreciation and amortization expense ~~increased $60.4~~decreased $33.2 million primarily driven by: (i) electric amortization ~~increased~~decreased by ~~$32.7~~$45.5 million or ~~54.7%~~51.7% from ~~2020. This increase is~~2021, primarily driven by $45.6 million less Production Tax Credit (PTC) amortization in 2022 as PSE fully utilized its PTC balance in 2021; (ii) common amortization decreased by $18.4 million or 20.6% from 2021, primarily driven by $25.1 million in net retirements of common technology assets. The Company invested heavily in technology solutions from 2017 - 2019, with a majority of useful lives between 3-5 years; and (iii) natural gas amortization decreased by $6.9 million or 41.6% from 2021, primarily driven by the ~~$5.8~~$5.5 million ~~change~~LNG depreciation expense deferral combined with net retirements of $20.1 million in PTC amortization, the completion of the amortization period for the regulatory liability with Microsoft power costs in 2020, and a $5.8 million increase in franchise amortization; (ii) common amortization increased by $9.3 million or 12.0% from 2020.natural gas technology assets. The ~~increase is primarily driven by a lower level of depreciation deferred for the get-to-zero (GTZ) projects due to the final 2019 GRC order~~decreases were partially offset by ~~$51.8 million in net retirements; (iii)~~(i) conservation amortization increased by ~~$3.6~~$13.8 million due to ~~an increase~~conservation rider rates effective May 1, 2022, see Management's Discussion and Analysis, "Regulation of PSE Rates and Recovery of PSE Costs" included in ~~retail usage~~Item 7 of ~~4.7% and 4.3% for electric and~~this report; (ii) natural gas ~~respectively; (iv)~~distribution depreciation increased by $10.7 million or 8.5% from 2021, primarily due to $242.0 million in LNG net additions combined with $175.2 million in net additions in gas distribution assets; (iii) electric distribution depreciation increased a net of $6.4 million or ~~4.3%~~4.2% from ~~2020. The increase is~~2021, primarily due to ~~$199.0~~$267.1 million in net additions of electric distribution assets; ~~and (v) natural gas distribution~~(iv) electric production depreciation increased ~~by $5.6~~a net of $3.3 million or ~~4.7%~~2.4% from ~~2020. The increase is~~2021, primarily due to ~~$233.1~~$19.2 million in net additions of electric production assets; and (v) common general plant depreciation increased a net of $2.7 million or 9.6% from 2021, primarily due to $42.1 million in ~~natural gas distribution assets.~~general plant additions offset by $45.0 million in retirements.

•Taxes other than income taxes increased ~~$33.9~~$25.6 million primarily due to an increase of ~~$17.7 million related to the state excise tax and $11.5~~$13.8 million related to municipal taxes driven by the increase in retail revenue in ~~2021~~2022 as compared to ~~2020.~~2021 and $10.1 million related to the state excise tax.

Other Income, Interest Expense and Income Tax Expense

•Other income/expense decreased ~~$8.3~~$14.9 million from net other income of $32.0 million in 2021 to $17.1 million in 2022. The decrease was primarily driven by (i) $7.1 million other income decrease due to a change in AMI return deferral per the 2022 GRC; (ii) $6.8 million other income decrease related to the deferred return for Puget LNG, per Washington Commission Docket No. UG-210918; (iii) $3.2 million other expense increase in non-utility write-offs driven by the Colstrip dry ash facilities exclusion from recovery in rate base per the 2022 GRC; and (iv) $3.1 million other income decrease in Washington Commission allowance for funds used during construction (AFUDC) due to a decrease in Washington Commission AFUDC rates in the first nine months of 2022 compared to 2021. These increases were partially offset by (i) a decrease of $6.2 million in the non-service cost component of the qualified pension net periodic benefit cost for 2022 compared to 2021.

•Interest expense increased $6.4 million primarily due to an increase of $9.2 million related to the ~~following expenses in 2020: (i) $6.3~~PSE $450.0 million ~~of SmartBurn, a pollution control technology that reduces nitrogen oxide, plant investment at Colstrip 3 & 4 which recovery~~

senior secured notes issued on September 15, 2021. This increase was ~~disallowed in 2020 per order of the Washington Commission in the Company's most recent GRC, (ii) write offs of $4.8 million of assets costs and (iii) strategic initiative costs of $3.1 million;~~ partially offset by a decrease of $2.9 million related to interest expense recognized in ~~PGA interest income of $2.2 million and an increase of $3.4 million of advertising expense in 2021 as compared to 2020.~~conjunction with PSE's deferred compensation liability.

•Income tax expense increased ~~$18.0~~$36.0 million primarily driven by an increase in pre-tax book income of $16.8 million, a combined increase in treasury grant amortization, net AFUDC, and political contributions of $11.6 million; partially offset by the amortization of unprotected EDIT of $10.4 million.income.

5658

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, ~~2020,~~2021, and December 31, ~~2021,~~2022, were as follows:

~~2020~~2021 compared to ~~2021~~2022

Summary Results of Operations

Puget Energy’s net income increased by ~~$78.1~~$153.6 million, which is primarily attributable to an increase in PSE's net income of ~~$61.8~~$154.9 million and a decrease in interest expense of ~~$23.1 million. The decrease in interest expense~~$20.1 million which is a result of lower interest rates on outstanding debt as ~~compared to the prior period. Additionally, in 2020,~~ Puget Energy ~~extinguished certain~~repaid $500.0 million of 6.00% notes and issued $500.0 million of senior secured notes ~~which resulted~~at an interest rate of 2.379% in June 2021; and Puget Energy repaid $450.0 million 5.625% notes in April 2022 and issued $450.0 million 4.224% notes in March 2022. Additionally, Puget Energy repaid a ~~loss of $13.5 million.~~$210.0 million term loan in June 2021. For further details, see Note 7, "Long-Term Debt" to the consolidated financial statements included in Item 8 of this report. These increases were partially offset by an increase in net loss of $16.0 million at PLNG due to additional operational expenses as PLNG commenced commercial operations in February 2022 and a decrease in income tax benefit of ~~$5.1~~$3.5 million ~~driven by a decrease~~due to an increase in ~~the pre-tax book loss in 2021.~~taxable income.

5759

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, ~~2021:~~2022:


		Payments Due Per Period											Payments Due Per Period
(Dollars in Thousands)	(Dollars in Thousands)	Total		2022		2023-2024		2025-2026		Thereafter		(Dollars in Thousands)	Total		2023		2024-2025		2026-2027		Thereafter
Contractual obligations:	Contractual obligations:											Contractual obligations:
Energy purchase obligations1	Energy purchase obligations1	$	7,594,344	$	1,532,258	$	1,968,091	$	1,223,342	$	2,870,653	Energy purchase obligations1	$	8,193,734	$	2,184,488	$	2,180,363	$	1,084,780	$	2,744,103
Long-term debt including interest2	Long-term debt including interest2	9,254,112		239,716		479,432		495,159		8,039,805		Long-term debt including interest2	9,014,396		239,716		496,376		774,979		7,503,325
Short-term debt including interest	Short-term debt including interest	140,000		140,000		—		—		—		Short-term debt including interest	357,000		357,000		—		—		—
Service contract obligations	Service contract obligations	467,036		77,622		159,658		147,902		81,854		Service contract obligations	416,055		84,095		165,553		86,752		79,655
Non-cancelable operating leases3	Non-cancelable operating leases3	272,221		23,945		46,717		36,762		164,797		Non-cancelable operating leases3	284,283		23,676		45,119		42,519		172,969
PSE finance leases3	PSE finance leases3	146,931		4,881		12,546		12,951		116,553		PSE finance leases3	142,468		6,383		12,942		13,261		109,882
Pension and other benefits funding and payments	Pension and other benefits funding and payments	67,129		21,784		12,488		11,798		21,059		Pension and other benefits funding and payments	59,961		22,444		11,249		14,960		11,308
Total PSE contractual cash obligations	Total PSE contractual cash obligations	17,941,773		2,040,206		2,678,932		1,927,914		11,294,721		Total PSE contractual cash obligations	18,467,897		2,917,802		2,911,602		2,017,251		10,621,242
Long-term debt including interest2	Long-term debt including interest2	2,397,803		516,599		139,590		482,450		1,259,164		Long-term debt including interest2	2,591,430		156,453		535,066		149,406		1,750,505
Total Puget Energy contractual cash obligations	Total Puget Energy contractual cash obligations	$	20,339,576	$	2,556,805	$	2,818,522	$	2,410,364	$	12,553,885	Total Puget Energy contractual cash obligations	$	21,059,327	$	3,074,255	$	3,446,668	$	2,166,657	$	12,371,747

____________________

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. Total energy purchase obligation as of December 31, 2022 does not include the Chelan PUD power purchase agreement that was executed on February 7, 2023. For additional information, see Note 16, "Commitments and Contingencies" to the consolidated financial statements included in Item 8 of this report.

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.

5860

The following are PSE’s and Puget Energy’s aggregate availability under commercial commitments as of December 31, ~~2021:~~2022:


		Amount of Available Commitments Expiration Per Period											Amount of Available Commitments Expiration Per Period
(Dollars in Thousands)	(Dollars in Thousands)	Total		2022		2023-2024		2025-2026		Thereafter		(Dollars in Thousands)	Total		Less than 1 Year		1-3 Years		3-5 Years		Thereafter
Commercial commitments:	Commercial commitments:											Commercial commitments:
PSE revolving credit facility1	PSE revolving credit facility1	$	800,000	$	—	$	800,000	$	—	$	—	PSE revolving credit facility1	$	800,000	$	—	$	—	$	800,000	$	—
Inter-company short-term debt2	Inter-company short-term debt2	30,000		—		—		—		30,000		Inter-company short-term debt2	30,000		—		—		—		30,000
Total PSE commercial commitments	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	Puget Energy revolving credit facility3	766,700		—		766,700		—		—		Puget Energy revolving credit facility3	681,400		—		—		681,400		—
Less: Inter-company short-term debt elimination2	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	Total Puget Energy commercial commitments	$	1,566,700	$	—	$	1,566,700	$	—	$	—	Total Puget Energy commercial commitments	$	1,481,400	$	—	$	—	$	1,481,400	$	—

_______________

1.As of December 31, ~~2021,~~2022, 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.~~May 2027. 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, ~~2021,~~2022, no loans or letters of credit were outstanding under the credit facility and ~~$140.0~~$357.0 million was outstanding under the commercial paper program. The credit agreement is syndicated among numerous lenders. Outside of the credit agreement, PSE has a ~~$2.5~~$2.3 million letter of credit in support of a long-term transmission ~~contract.~~contract and had $28.0 million issued under a standby letter of credit in support of natural gas purchases.

2.As of December 31, ~~2021,~~2022, 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, ~~2021,~~2022, Puget Energy had a revolving senior secured credit facility totaling $800.0 million, which matures in ~~October 2023.~~May 2027. 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, ~~2021,~~2022, there was ~~$33.3~~$118.6 million drawn and outstanding under the Puget Energy credit ~~facility.~~facility,of which $34.3 million was classified as long-term debt and $84.3 million was classified as short-term debt.

Off-Balance Sheet Arrangements

As of December 31, ~~2021,~~2022, the Company had no off-balance sheet arrangements that have or are reasonably likely to have a material effect on the Company's financial condition.

Utility Construction Program

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, support customer growth and to improve energy system reliability. ~~Due to business disruptions caused by the COVID-19 pandemic, the Company closely monitored and adjusted~~The Company's capital expenditures ~~resulting in a decrease of $39.1~~were $18.6 million ~~compared to~~higher than forecasted amounts for ~~2021.~~2022. The increase was primarily due to (i) higher storm and weather related outage & emergent response; (ii) accelerated thermal generation maintenance and (iii) technology expenditures related to compliance with the Climate Commitment Act, project management, and check-processing software. Construction expenditures, excluding equity allowance for funds used during construction (AFUDC), totaled ~~$922.1 million~~$1.0 billion in ~~2021.~~2022. Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:


Capital Expenditure Projections	Capital Expenditure Projections				Capital Expenditure Projections
(Dollars in Millions)	(Dollars in Millions)	2022	2023	2024	(Dollars in Millions)	2023	2024	2025
Total energy delivery, technology and facilities expenditures	Total energy delivery, technology and facilities expenditures	$973.9	$1,293.1	$1,292.1	Total energy delivery, technology and facilities expenditures	$1,146.7	$1,311.9	$1,304.2

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

5961

Capital Resources

Cash from Operations


Puget Sound Energy	Puget Sound Energy	Year Ended December 31,						Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	(Dollars in Thousands)	2021		2020		Change		(Dollars in Thousands)	2022		2021		Change
Net income	Net income	$	336,063	$	274,280	$	61,783	Net income	$	490,952	$	336,063	$	154,889
Non-cash items1	Non-cash items1	691,953		724,650		(32,697)		Non-cash items1	476,696		691,953		(215,257)
Changes in cash flow resulting from working capital2	Changes in cash flow resulting from working capital2	21,379		(57,578)		78,957		Changes in cash flow resulting from working capital2	(64,749)		21,379		(86,128)
Regulatory assets and liabilities	Regulatory assets and liabilities	(126,625)		(152,417)		25,792		Regulatory assets and liabilities	(90,335)		(126,625)		36,290
Purchased gas adjustment	Purchased gas adjustment	29,720		45,111		(15,391)		Purchased gas adjustment	37,256		29,720		7,536
Other non-current assets and liabilities3	Other non-current assets and liabilities3	(32,097)		(9,236)		(22,861)		Other non-current assets and liabilities3	(32,359)		(32,097)		(262)
Net cash (used in)/provided by operating activities	Net cash (used in)/provided by operating activities	$	920,393	$	824,810	$	95,583	Net cash (used in)/provided by operating activities	$	817,461	$	920,393	$	(102,932)

_______________

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, ~~2021,~~2022, compared to ~~2020~~2021

Cash generated from operations ~~for the year ended December 31, 2021, increased~~decreased by ~~$95.6~~$102.9 million, including a net income increase of ~~$61.8~~$154.9 million. The following are significant factors that impacted PSE's cash flows from operations:

•Cash flow adjustments resulting from non-cash items decreased ~~$32.7~~$215.3 million primarily due toto: (i) a ~~$40.6~~$247.4 million change from a net unrealized ~~loss~~gain on derivative instruments of ~~$26.8~~$13.8 million to a net unrealized gain on derivative instruments of ~~$13.8~~$261.2 million, ~~recognition~~(ii) a decrease in depreciation and amortization of $47.0 million, and (iii) a deferral of return and depreciation expenses for PSE's share of Tacoma LNG investment of $12.1 million. The decreases were partially offset by: (i) a $45.6 million change in PTC utilization, (ii) a $24.5 million change related to recognition of regulatory asset in 2021 as a result of the IRS PLR ~~which~~that concluded the EDIT methodology ~~that was~~ included in rates following the 2019 GRC order was impermissible, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 7 of this report for more information; deferred taxes of $23.9 million, $6.3 million related to loss in 2020 due to writing off the Smart Burn project at Colstrip, a $5.8 million change in PTC utilization, and equity AFUDC of $4.6 million, partially offset by increases in depreciation and amortization of $56.8 million, a decrease of amortization of TCJA related income tax expense over-collection of $12.5 million and(iii) increased conservation amortization of ~~$3.6~~$13.8 million, and (iv) deferred taxes of $6.5 million. For further discussion, see "Other Operating Expenses" in Item 7, Management's Discussion and ~~Analysis and Note 14, "Income Taxes" in Item 8.~~Analysis.

•Cash flows resulting from changes in working capital ~~increased $79.0~~decreased $86.1 million primarily ~~due~~due: (i) a cash outflow of $155.8 million in account receivable as its balance increased $252.3 million in the twelve months ended December 31, 2022 compared to an increase of $96.5 million during the same period of 2021; the increase was related to higher wholesale sales of natural gas in November and December of 2022 driven by lower temperatures and higher wholesale prices, (ii) higher balances in materials and supplies and fuel and natural gas inventory increased cash outflows by $23.9 million and $23.1 million respectively, and (iii) increased tax payments of $43.1 million as the result of higher profit in 2022 compared to 2021 and increased Washington state property and utility taxes. The cash outflows were partially offset by (i) an increase in accounts payable of ~~$75.5~~$136.6 million, which was driven by higher sales ~~volume of electricity and natural gas~~volumes and increased wholesale energy ~~prices; other increases include $17.2~~prices, (ii) higher accrued salary and wages of $7.2 million, ~~related to~~(iii) higher short-term accrual for the Supplemental Executive Retirement Plan of $4.7 million, (iv) increased annual Washington Commission filing fee payables of $5.9 million, and (v) lower prepayment balances ~~$18.9 million in taxes payable, $13.0 million in accrued salaries and wages, $11.9 million due to less SERP liability payments and~~of $5.2 ~~million in other accrued expenses. The increases of cash inflow were partially offset by cash outflow increase in accounts receivable of $62.7~~ million.

•Cash flows resulting from regulatory assets and liabilities increased ~~$25.8~~$36.3 million primarily due to: (i) a $19.6 million cash inflow was related to changes in deferral of storm excess costs, (ii) a $26.1 million increase in low income program as result of accrued higher cost in 2021 to assist pandemic (COVID-19) affected families, (iii) lower expenses and higher amortization led to an increase of $14.5 million cash inflow in property tax tracker, (iv) amortizing IRS PLR deferral balances contributed an addition of $14.3 million cash inflow, see Management's Discussion and Analysis, "Regulation of PSE Rates and Recovery of PSE Costs" included in Item 7 of this report. The cash inflows were partially offset by a year-over-year change in power cost adjustment receivable, which was relatively flat in 2021, ($3.3 million), and $32.6 million higher in ~~2020, $41.0 million,~~2022, resulting in a net cash ~~inflow~~outflow of ~~$44.3~~$35.9 million. The increase was partially offset by a decrease of $21.8 million with the second Crisis Affected Customer Assistance Program, see Note 4 "Regulation and Rates" in Item 8 of this report for more information.

•Cash flow resulting from purchased gas adjustment ~~(long-term)~~ ~~decreased $15.4~~increased $7.5 million, which was driven by ~~higher~~an increase in allowed PGA recovery that exceeded the increase in actual gas cost ~~with lower allowed PGA recovery~~ in ~~2021~~2022 compared to ~~2020.~~2021. Increased natural gas prices and higher sales volume led to a ~~$50.0~~$93.1 million ~~(or 15.9%)~~ increase in actual gas costs in ~~2021~~2022 compared to ~~2020.~~2021. Meanwhile, the total amount of allowed PGA recovery in ~~2021~~2022 increased ~~$32.3~~$100.6 million ~~(or 8.9%)~~ compared to ~~2020.~~2021. The combined effect led to year-over-year cash ~~outflow.~~inflow.

•~~Cash flow resulting from changes in other non-current assets and liabilities~~ ~~decreased $22.9 million primarily due to a decrease of $20.5 million in payroll taxes deferral and a decrease of $2.4 million in other long-term assets and liabilities.~~


Puget Energy	Puget Energy	Year Ended December 31,						Puget Energy	Year Ended December 31,
(Dollars in Thousands)	(Dollars in Thousands)	2021		2020		Change		(Dollars in Thousands)	2022		2021		Change
Net income	Net income	$	(75,214)	$	(91,563)	$	16,349	Net income	$	(76,607)	$	(75,214)	$	(1,393)
Non-cash items1	Non-cash items1	18,312		2,841		15,471		Non-cash items1	36,689		18,312		18,377
Changes in cash flow resulting from working capital2	Changes in cash flow resulting from working capital2	(26,229)		3,415		(29,644)		Changes in cash flow resulting from working capital2	1,355		(26,229)		27,584

Other non-current assets and liabilities3	Other non-current assets and liabilities3	(10,664)		(11,935)		1,271		Other non-current assets and liabilities3	(9,280)		(10,664)		1,384
Net cash (used in)/provided by operating activities	Net cash (used in)/provided by operating activities	$	(93,795)	$	(97,242)	$	3,447	Net cash (used in)/provided by operating activities	$	(47,843)	$	(93,795)	$	45,952

______________

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, ~~2021,~~2022, compared to ~~2020~~2021

Cash generated from operations for the year ended December 31, ~~2021,~~2022, in addition to the changes discussed at PSE above, increased by ~~$3.4~~$46.0 million compared to the same period in ~~2020,~~2021, which includes a net income ~~increase~~decrease of ~~$16.3~~$1.4 million. The remaining change was primarily impacted by the factors explained below:

•Non-cash items increased ~~$15.5~~$18.4 million primarily due to an increase of ~~$29.0~~$12.6 million in deferred taxes ~~partially offset by a decrease~~and an increase in amortization and depreciation of ~~$13.5 million related to extinguishment of debt reflected in financing activities in 2020.~~$5.5 million.

•Changes in cash flow resulting from working capital ~~decreased $29.6~~increased $27.6 million primarily due to: (i) a $13.8 million increase due to ~~a $8.0 million decrease related to changes~~the change in ~~eliminations of~~ PSE's intercompany account receivable and account payable balances with Puget LNG and Puget Energy, which are eliminated upon consolidation of Puget Energy, (ii) changes in tax payable added $15.1 million cash inflow, (iii) cash inflow of $3.5 million driven by reduction of accrued interest expense as result of lower interest rates on debt, as Puget Energy repaid $500.0 million of 6.00% notes and issued $500.0 million of senior secured notes at an ~~increase~~interest rate of 2.379% in June, 2021. Additionally, Puget Energy used an equity contribution from Puget Equico to pay off a $210.0 million term loan in June, 2021. The cash inflows were partially offset by cash outflow of ~~$13.0~~$3.9 million as result of Puget LNG commenced commercial operations in February 2022 and accrued $3.9 million in ~~tax payable and a decrease~~account receivable as of ~~$9.0 million in accrued interest, partially offset with a $0.4 million increase in other accrued expenses.~~

•~~Other non-current assets and liabilities~~ ~~decreased $1.3 million primarily due to change of the valuation of pension liability compared to the prior year.~~December 31, 2022.

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 prolonged economic stresses of the COVID-19 pandemic and ~~its impact on~~recent inflationary pressures, the ~~economy and capital markets, the Company~~company continues to ~~carefully~~closely 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. On July 23, 2020, S&P placed Puget Energy and PSE on CreditWatch with negative implications due the rate case outcome, but later revised to negative outlook. Fitch affirmed Puget Energy and PSE ratings but changed its outlook from stable to negative. On May 27, 2021, S&P revised Puget Energy’s and PSE’s ratings from negative to stable outlook. On June 1, 2021, Fitch also revised its outlook for PE and PSE to stable. Both actions were a result of the passage and signing into law of Washington Senate Bill 5295 which allows for multi-year rate plans and reduction of regulatory lag, as well as other actions taken by management to increase revenue via available rate recovery methods and management of internal expenses. Despite these actions, the rating agencies noted that a lack of sufficient regulatory rate relief over the relative near term could result in negative ratings implications. Although neither Puget Energy nor PSE have any debt whose maturity would be accelerated upon a ratings

downgrade, a credit rating downgrade may increase the cost of borrowing for Puget Energy and PSE in future long-term financings or under their existing credit facilities. Any increase in the cost of borrowing may 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. Additionally, a ratings downgrade could impact the Company's ability to issue dividends, see Dividend Payment Restriction below for further details. 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.

For information on Puget Energy and PSE dividends, long-term debt and credit facilities, see Note 5, “Dividend Payment Restrictions, Note 7, “Long-term Debt” and Note 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, ~~2021,~~2022, PSE could issue:

•Approximately ~~$1.8~~$1.9 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately ~~$2.9~~$3.2 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, ~~2021;~~2022; and

•Approximately ~~$933.0 million~~$1.0 billion of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately ~~$1.6~~$1.7 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, ~~2021.~~2022.

At December 31, ~~2021,~~2022, PSE had approximately ~~$8.1~~$8.6 billion in electric and natural gas rate base to support the interest coverage ratio limitation test for net earnings available for interest.

Shelf Registrations

On March 10, 2022, Puget Energy filed an S-3 Registration statement under which it may issue up to $1.0 billion aggregate principal amount of senior notes secured by Puget Energy's assets. As of the date of this report, $550.0 million was available to be issued. The shelf registration will expire in March 2025.

In August 2022, PSE filed an S-3 shelf registration statement under which it may issue up to $1.4 billion aggregate principal amount of senior notes secured by first mortgage bonds. As of the date of this report, $1.4 billion was available to be issued. The shelf registration will expire in August 2025.

Critical Accounting 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 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.

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 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, ~~2021,~~2022, in the amount of ~~$952.5~~$896.4 million and ~~$1,709.5~~$1,961.1 million, respectively, and regulatory assets and liabilities at December 31, ~~2020,~~2021, of ~~$918.1~~$952.5 million and ~~$1,685.2~~$1,709.5 million, respectively. Such amounts are amortized through a corresponding liability or asset account, respectively, with no impact to earnings. PSE expects to fully recover its regulatory assets and liabilities through its rates. If future recovery of costs ceases to be probable, PSE would be required to write off these regulatory assets and liabilities. In addition, if PSE 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 of PSE Rates and ~~Rates"~~Recovery of PSE Costs" included in Item 7 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.

Derivatives

ASC 815 requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value unless the contracts qualify for an exception. 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 Interconnection 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.

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 10, "Accounting for Derivative Instruments and Hedging Activities" and Note 11, "Fair Value Measurements" to the consolidated financial statements included in Item 8 of this report.

Environmental Remediation

The Company is subject to federal and state requirements for protection of the environment, including those for discharge of hazardous materials and remediation of contaminated sites. A potentially responsible party has joint and several liability under existing U.S. environmental laws. In instances where we have been designated a potentially responsible party by the Environmental Protection Agency or state environmental agency, we are potentially liable for the cost of remediating contamination at current work sites and former work sites. Such sites include former manufactured gas plants operated by PSE predecessors, such as Gas Works Park on the shore of Lake Union in Seattle, or contaminated facilities with other connections to PSE predecessors, such as the location of a long-defunct creosote manufacturer which had purchased waste products from PSE predecessors, the Quendall Terminals site on Lake Washington in Renton, Washington. In each case, PSE assesses, based on in-depth studies, expert analyses and legal reviews, our environmental remediation obligations related to contaminated sites, including assessments of ranges and probabilities of recoveries from other responsible parties and/or insurance carriers. PSE develops a range of reasonably estimable costs that includes a low and high end of a range for all remediation sites for which we have sufficient information. There are some potential remediation obligations where the costs of remediation cannot be reasonably estimated. Liabilities are recorded based on the best estimate or the low end of a range of reasonably possible costs expected to be incurred to remediate sites. It’s possible that costs are incurred in excess of the recorded amounts because of changes in laws and/or regulations, higher than expected costs and/or the discovery of new or additional contamination. The Company believes a significant portion of its past and future environmental remediation costs are recoverable from insurance companies, from third parties or from customers under a Washington Commission order.

For additional information see Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.

Fair Value

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" in this report.

Pension and Other Postretirement Benefits

PSE has a qualified defined benefit pension plan covering substantially all employees of PSE. PSE recognized qualified pension expense of ~~$21.4~~$14.7 million and ~~$17.1~~$21.4 million for the years ended December 31, ~~2021,~~2022, and ~~2020,~~2021, respectively. Of these amounts, approximately ~~48.7%~~48.3% and ~~50.6%~~48.7% were included in utility operations and maintenance expense in ~~2021~~2022 and ~~2020,~~2021, respectively, and the remaining amounts were capitalized. For the years ended December 31, ~~2021,~~2022, and ~~2020,~~2021, Puget Energy recognized incremental qualified pension income of ~~$10.4~~$8.7 million and ~~$11.3~~$10.4 million, respectively. In ~~2022,~~2023, it is expected that PSE and Puget Energy will recognize pension ~~expense~~income of ~~$15.7~~$0.4 million and incremental qualified pension income of ~~$8.7~~$3.5 million, respectively.

PSE has a SERP and recognized pension and other postretirement benefit expenses of ~~$4.3~~$4.7 million and ~~$5.0~~$4.3 million for the years ended December 31, ~~2021,~~2022, and ~~2020,~~2021, respectively. For the years ended December 31, ~~2021,~~2022, and ~~2020,~~2021, Puget Energy recognized incremental income of $0.2 million and ~~$0.3~~$0.2 million, respectively. In ~~2022,~~2023, it is expected that PSE and Puget Energy will recognize pension expense of ~~$4.7~~$2.4 million and incremental pension income of ~~$0.2~~$0.1 million, respectively.

PSE also has other limited postretirement benefit plans. PSE recognized income of $0.1 million and $0.1 million for the years ended December 31, ~~2021,~~2022, and ~~2020,~~2021, respectively. For the years ended December 31, ~~2021,~~2022, and ~~2020,~~2021, Puget Energy recognized incremental expense of $0.1 million ~~and $0.1 million, respectively.~~in both years. In ~~2022,~~2023, it is expected that PSE and Puget Energy will recognize expense of $0.1 million and incremental expense of $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 ~~2021,~~2022, the Company made cash contributions of $18.0 million to the qualified defined pension plan. Management is closely monitoring the funding status of its qualified pension plan. At December 31, ~~2021,~~2022, and ~~2020,~~2021, the Company’s qualified pension plan was ~~$63.6~~$69.3 million overfunded and ~~$14.7~~$63.6 million ~~underfunded~~overfunded as measured under GAAP, or ~~107.6%~~111.8% and ~~98.3%~~107.6% funded, respectively. As of January 1, ~~2022,~~2023, 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, ~~2022,~~2023, are expected to be at least $18.0 million, ~~$2.8~~$3.5 million and $0.3 million, respectively.

The discount rate used in accounting for pension and other benefit obligations increased from ~~2.70% in 2020 to~~ 3.00% in ~~2021.~~2021 to 5.60% in 2022. The discount rate used in accounting for pension and other benefit expense ~~decreased~~increased from ~~3.35% in 2020 to~~ 2.70% in ~~2021.~~2021 to 3.00% in 2022. The rate of return on plan assets for qualified pension benefits ~~decreased from 7.15% in 2020 to~~remains unchanged at 6.50% in ~~2021.~~both 2021 and 2022. The rate of return on plan assets for other benefits was 7.00% in both ~~2020~~2021 and ~~2021.~~

2022.

The follow 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	Puget Energy and Puget Sound Energy	Change in Assumption	Impact on Projected Benefit Obligation Increase /(Decrease)						Puget Energy and Puget Sound Energy	Change in Assumption	Impact on Projected Benefit Obligation Increase /(Decrease)
(Dollars in Thousands)	(Dollars in Thousands)		Pension Benefits		SERP		Other Benefits		(Dollars in Thousands)		Pension Benefits		SERP		Other Benefits
Increase in discount rate	Increase in discount rate	50 basis points	$	(49,299)	$	(1,248)	$	(494)	Increase in discount rate	50 basis points	$	(29,451)	$	(795)	$	(306)
Decrease in discount rate	Decrease in discount rate	50 basis points	54,765		1,328		541		Decrease in discount rate	50 basis points	32,186		840		330

Puget Energy Change in Assumption

Impact on 2021
Pension Expense
Increase /(Decrease)
(Dollars in Thousands)

Pension Benefits SERP

Other Benefits
Increase in discount rate 50 basis points

$ (3,652) $ (152)

$ 26
Decrease in discount rate 50 basis points

4,007 163

(24)
Increase in return on plan assets 50 basis points

$ (3,712) *

$ (25)
Decrease in return on plan assets 50 basis points

3,712 *

25


Puget Sound Energy		Change in Assumption	Impact on 2021 Pension Expense Increase /(Decrease)
Puget Energy									Puget Energy	Change in Assumption	Impact on 2022 Pension Expense Increase /(Decrease)
(Dollars in Thousands)	(Dollars in Thousands)		Pension Benefits		SERP		Other Benefits		(Dollars in Thousands)		Pension Benefits		SERP		Other Benefits
Increase in discount rate	Increase in discount rate	50 basis points	$	(3,652)	$	(153)	$	14	Increase in discount rate	50 basis points	$	(3,672)	$	(241)	$	4
Decrease in discount rate	Decrease in discount rate	50 basis points	4,007		163		(10)		Decrease in discount rate	50 basis points	3,942		256		(21)
Increase in return on plan assets	Increase in return on plan assets	50 basis points	$	(3,712)	*		$	(25)	Increase in return on plan assets	50 basis points	$	(3,926)	*		$	(27)
Decrease in return on plan assets	Decrease in return on plan assets	50 basis points	3,712		*		25		Decrease in return on plan assets	50 basis points	3,925		*		27


Puget Sound Energy	Change in Assumption	Impact on 2022 Pension Expense Increase /(Decrease)
(Dollars in Thousands)		Pension Benefits		SERP		Other Benefits
Increase in discount rate	50 basis points	$	(3,672)	$	(241)	$	3
Decrease in discount rate	50 basis points	3,942		256		(16)
Increase in return on plan assets	50 basis points	$	(3,926)	*		$	(27)
Decrease in return on plan assets	50 basis points	3,926		*		27

_______________

* Calculation not applicable.

Recently Adopted Accounting Pronouncements

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Energy Portfolio Management

PSE maintains energy risk policies and procedures to manage risks inherent to participating in wholesale energy markets that may have related effects on credit, tax, accounting, financing and liquidity. The nature of operating generation and distribution facilities, obtaining transmission service, securing fuel and other necessary services, and energy market participation generally is such that there is continuous exposure to various risks including market, asset reliability, operational, liquidity, model, and counterparty credit risk. PSE’s Energy Risk Management Committee establishes PSE’s risk management policies and procedures, and is responsible for reviewing risk tolerances and limits, establishing delegations of authority, maintaining systemic and procedural adequacy of control system, and monitoring compliance. The Energy Risk Management Committee is comprised of certain PSE officers and is overseen by the PSE Board of Directors.

PSE's objective is to minimize commodity price exposure and risks associated with volumetric variability in the natural gas and electric portfolios to ensure physical energy supplies are available to serve retail customer loads while managing portfolio risks to limit undesired impacts and optimizing the capacity value of energy supply assets. It is not engaged in the business of assuming risk for the purpose of speculative trading. PSE hedges open natural gas and electric positions to reduce both the portfolio risk and the volatility risk in prices.

PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools including a probabilistic risk system that models 250 simulations of how PSE’s natural gas and power portfolios will perform under various weather, hydroelectric and unit performance conditions. Based on the analytics from all of its models and tools, PSE enters into forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity options to manage its electric and natural gas portfolio risks. The forward physical electric and natural gas contracts are both fixed and variable (at index). To fix the price of wholesale electricity and natural gas, PSE may enter into fixed-for-floating swap ~~(financial)~~(derivative) contracts. PSE also utilizes natural gas options as an additional hedging instrument to

increase the hedging portfolio's flexibility to react to commodity price fluctuations while also allowing for participation in low price commodity markets.

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

Puget Energy and Puget Sound Energy December 31, 2021 December 31, 2020
(Dollars in Thousands) Assets Liabilities Assets Liabilities
Electric portfolio:
Current $ 61,291 $ 50,979 $ 16,862 $ 23,697
Long-term 13,538 34,445 5,682 23,225
Total Electric Portfolio $ 74,829 $ 85,424 $ 22,544 $ 46,922
Natural gas portfolio:
Current $ 66,919 $ 12,330 $ 16,153 $ 7,744
Long-term 12,659 6,520 3,123 6,608
Total Natural Gas Portfolio $ 79,578 $ 18,850 $ 19,276 $ 14,352
Total derivatives $ 154,407 $ 104,274 $ 41,820 $ 61,274


Puget Energy and Puget Sound Energy	December 31, 2022				December 31, 2021
(Dollars in Thousands)	Assets		Liabilities		Assets		Liabilities
Electric portfolio:
Current	$	267,811	$	79,668	$	61,291	$	50,979
Long-term	69,892		7,452		13,538		34,445
Total Electric Portfolio	$	337,703	$	87,120	$	74,829	$	85,424
Natural gas portfolio:
Current	319,218		45,308		66,919		12,330
Long-term	24,729		10,914		12,659		6,520
Total Natural Gas Portfolio	$	343,947	$	56,222	$	79,578	$	18,850
Total derivatives	$	681,650	$	143,342	$	154,407	$	104,274

At December 31, ~~2021,~~2022, the Company had total assets of ~~$154.4~~$681.7 million and total liabilities of ~~$104.3~~$143.3 million related to derivative contracts used to hedge the supply and cost of electricity and natural gas to serve PSE customers. As the gains and losses in the electric portfolio are realized, they will be recorded as either purchased power costs or electric generation fuel costs under the PCA mechanism. Any fair value adjustments relating to the natural gas business have been deferred in accordance with ASC 980, due to the PGA mechanism, which passes the cost of natural gas supply to customers. As the gains and losses on the hedges are realized in future periods, they will be recorded as natural gas costs under the PGA mechanism.

A hypothetical 10.0% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company’s derivative contracts by ~~$45.6~~$85.2 million.

The change in fair value of the Company's outstanding energy derivative instruments from December 31, ~~2020,~~2021, through December 31, ~~2021,~~2022, is summarized in the table below:


Puget Energy and Puget Sound Energy
Energy Derivative Contracts Gain (Loss)
(Dollars in Thousands)	December 31, ~~2021~~2022
~~Fair value of contracts outstanding at December 31, 2020~~	$	~~(19,454)~~
~~Contracts realized or otherwise settled during 2021~~	~~(141,910)~~
~~Change in fair value of derivatives~~	~~211,497~~
Fair value of contracts outstanding at December 31, 2021	$	50,133
Contracts realized or otherwise settled during 2022	(357,980)
Change in fair value of derivatives	846,155
Fair value of contracts outstanding at December 31, 2022	$	538,308

The fair value of the Company's outstanding derivative instruments at December 31, ~~2021,~~2022, based on pricing source and the period during which the instrument will mature, is summarized below:


Puget Energy and Puget Sound Energy Source of Fair Value	Puget Energy and Puget Sound Energy Source of Fair Value	Fair Value of Contracts by Settlement Year										Puget Energy and Puget Sound Energy Source of Fair Value	Fair Value of Contracts by Settlement Year
																							Puget Energy and Puget Sound Energy Source of Fair Value	Fair Value of Contracts by Settlement Year
(Dollars in Thousands)	(Dollars in Thousands)	2022		2023-2024		2025-2026		Thereafter		Total		(Dollars in Thousands)	2023		2024-2025		2026-2027		Thereafter		Total
Prices provided by external sources1	Prices provided by external sources1	$	77,317	$	18,840	$	(1,152)	$	—	$	95,005	Prices provided by external sources1	$	389,832	$	33,850	$	(1,325)	$	—	$	422,357
Prices based on internal models and valuation methods	Prices based on internal models and valuation methods	(12,415)		(29,588)		(2,869)		—		(44,872)		Prices based on internal models and valuation methods	72,222		35,862		7,867		—		115,951
Total fair value	Total fair value	$	64,902	$	(10,748)	$	(4,021)	$	—	$	50,133	Total fair value	$	462,054	$	69,712	$	6,542	$	—	$	538,308

_______________

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

For further details regarding both the fair value of derivative instruments and the impacts such instruments have on current period earnings, see Note 10, "Accounting for Derivative Instruments and Hedging Activities" and Note 11, "Fair Value Measurements" to the consolidated financial statements included in Item 8 of this report.

Contingent Features and Counterparty Credit Risk

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

PSE has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. PSE generally enters into the following master arrangements: WSPP, Inc. (WSPP) agreements which standardize physical power contracts in the electric industry; International Swaps and Derivatives Association (ISDA) agreements which standardize financial natural gas and electric contracts; and North American Energy Standards Board (NAESB) agreements which standardize physical natural gas contracts. PSE believes that entering into such agreements reduces the credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as right of set-off in the event of counterparty default. It is possible that volatility in energy commodity prices could cause PSE to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, PSE could suffer a material financial loss. In order to mitigate concentrated credit risk with a subset of counterparties, PSE ~~transacts~~enters into cleared transactions on the Intercontinental Exchange (ICE) for power futures contracts and ICE NGX for natural gas supply contracts.

Where deemed appropriate, and when allowed under the terms of the agreements, PSE may request collateral or other security from its counterparties to mitigate the potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure. As of December 31, ~~2021,~~2022, PSE held approximately ~~$662.4~~$775.8 million in standby letters of credit or limited parental guarantees and had ~~nine~~seven counterparties with unlimited parental guarantees, in support of various electric and natural gas transactions. The Company monitors counterparties for significant swings in credit default rates, credit rating changes by external rating agencies, ownership changes or financial distress. As of December 31, ~~2021,~~2022, approximately ~~66.2%~~80.4% of the Company's total energy portfolio

exposure was entered into with investment grade counterparties which, in the majority of cases, do not require collateral calls on the contracts. Counterparty credit risk may impact PSE's decisions on derivative accounting treatment.

Should a counterparty file for bankruptcy, which would be considered a default under master arrangements, PSE may terminate related contracts. Derivative accounting entries previously recorded would be reversed in the financial statements. PSE would compute any terminations receivable or payable, based on the terms of existing master agreements. The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors, such as credit default swaps and bond spreads, in determination of reserves. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty’s risk of default. The Company uses both default factors published by Standard & Poor’s and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted-average default tenor for that counterparty’s deals. The default tenor is determined by weighting the fair value and contract tenors for all deals by counterparty and arriving at an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.

The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against unrealized gain (loss) positions. As of December 31, ~~2021,~~2022, the Company was in a net ~~liability~~asset position with the majority of counterparties, so the default factors of counterparties did not have a significant impact on reserves for the period. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. PSE also transacts power futures contracts on the Intercontinental Exchange (ICE), and natural gas contracts on the ICE NGX platform. Execution of contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of December 31, ~~2021,~~2022, PSE had cash posted as collateral of ~~$12.8~~$23.2 million related to contracts executed on the ICE platform. ~~Also, as of December 31, 2021,~~In August 2022, PSE ~~had $24.0 million in cash posted as collateral and 0~~entered into a standby letter of credit ~~posted~~agreement with TD Bank allowing standby letter of credit postings of up to $50.0 million as a condition of transacting on the ICE NGX platform. As of December 31, 2022, PSE had $33.0 million in cash posted with ICE NGX and $28.0 million issued under the standby letter of credit agreement. PSE did not trigger any collateral requirements with any of its counterparties nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades during the twelve months ended December 31, ~~2021.~~2022.

Interest Rate Risk

The Company believes its interest rate risk primarily relates to the use of short-term debt instruments, variable-rate leases and anticipated long-term debt financing needed to fund capital requirements. The Company manages its interest rate risk through the issuance of mostly fixed-rate debt of various maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program, and its credit facilities to meet short-term funding needs. Short-term obligations are commonly refinanced with fixed-rate bonds or notes when needed and when interest rates are considered favorable.

The following table presents the carrying value and fair value of Puget Energy and Puget Sound Energy's long-term debt instruments:


Long-Term Debt Instruments	December 31, 2022				December 31, 2021
(Dollars in Thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Puget Energy	$	6,663,373	$	6,184,097	$	6,203,766	$	7,803,196
Puget Sound Energy	4,786,765		4,379,010		4,784,719		6,145,639

Long-Term Debt Instruments December 31, 2021 December 31, 2020
(Dollars in Thousands) Carrying Amount Fair Value Carrying Amount Fair Value
Puget Energy $ 6,203,766 $ 7,803,196 $ 5,892,440 $ 7,980,646
Puget Sound Energy 4,784,719 6,145,639 4,338,044 6,086,358

For further details regarding Puget Energy and Puget Sound Energy debt instruments, see Note 7, "Long-Term Debt" and Note 11, "Fair Value Measurements" to the consolidated financial statements included in Item 8 of this report.

From time to time, PSE may enter into treasury locks or forward starting swap contracts to hedge interest rate exposure related to an anticipated debt issuance. The ending balance in other comprehensive income (OCI) related to the forward starting swaps and previously settled treasury lock contracts at December 31, ~~2021,~~2022, was a net loss of ~~$4.6~~$4.2 million after-tax and accumulated amortization. This compares to an after-tax loss of ~~$5.0~~$4.6 million in OCI as of December 31, ~~2020.~~2021. All financial hedge contracts of this type are reviewed by an officer, presented to the Board of Directors, or a committee of the Board, as applicable and are approved prior to execution. PSE had no treasury locks or forward starting swap contracts outstanding at December 31, ~~2021.~~2022.

The Company may also enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. As of December 31, ~~2021,~~2022, the Company had no outstanding interest rate swap instruments.

6871

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


REPORTS:			Page
Report of Management and Statement of Responsibility			7073
Report of Independent Registered Public ~~Accounting~~Accounting Firm - Puget Energy			7174
Report of Independent Registered Public ~~Accounting~~Accounting Firm - Puget Sound Energy			7376

INDEX TO FINANCIAL STATEMENTS:
PUGET ENERGY:
Consolidated Statements of Income - Years Ended December 31, 20 2 12 , 20 202 1 , and ~~201~~20920			7578
Consolidated Statements of Comprehensive Income - Years Ended December 31, 20 2 12 , 2 002 201 , ~~201~~20920			7679
Consolidated Balance Sheets - December 31, 20 2 12 and 202021			7780
Consolidated Statements of Common Shareholder’s Equity - Years Ended December 31, 20 2 12 , 20 202 1 , and ~~201~~20920			7982
Consolidated Statements of Cash Flows - Years Ended December 31, 20 2 12 , 20 202 1 , and ~~201~~20920			8083

PUGET SOUND ENERGY:
Consolidated Statements of Income - Years Ended December 31, 20~~21,~~22, 2021, and 2020 ~~and 2019~~			8184
Consolidated Statements of Comprehensive Income - Years Ended December 31, 20~~21,~~22, 2021, 2020 ~~2019~~			8285
Consolidated Balance Sheets - DeDecember 31, 202 ~~cember 31, 2021~~2 and ~~2020~~2021			8386
Consolidated Statements of Common Shareholder’s Equity - Years Ended December 31, 20~~21,~~22, 2021, and 2020 ~~and 2019~~			8588
Consolidated Statements of Cash Flows - Years Ended December 31, 20~~21, 2020,~~2 2 , 20 2 1 , and ~~2019~~20 20			8689


NOTES to the Consolidated Financial Statements of Puget Energy and Puget Sound Energy:
Note 1.	Summary of Significant Accounting Policies	8790
Note 2.	New Accounting Pronouncements	9395
Note 3.	Revenue	949 6
Note 4.	Regulation and Rates	9599
Note 5.	Dividend Payment Restrictions	~~101~~105
Note 6.	Utility Plant	~~102~~106
Note 7.	Long-Term Debt	~~105~~109
Note 8.	Liquidity Facilities and Other Financing Arrangements	~~107~~110
Note 9.	Leases	~~108~~112
Note 10.	Accounting for Derivative Instruments and Hedging Activities	~~110~~114
Note 11.	Fair Value Measurements	~~113~~117
Note 12.	Employee Investment Plans	~~118~~120
Note 13.	Retirement Benefits	~~118~~121
Note 14.	Income Taxes	~~125~~128
Note 15.	Litigation	~~127~~131
Note 16.	Commitments and Contingencies	~~129~~131
Note 17.	Related Party Transactions	~~131~~133
Note 18.	Segment Information	~~131~~134
Note 19.	Accumulated Other Comprehensive Income (Loss)	~~132~~134




SCHEDULE:
I. Condensed Financial Information of Puget Energy - December 31, ~~2021,~~202 2 , and ~~2020,~~202 1 , and for the Years Ended December 31, 202 ~~2021,~~ 2 ~~2020,~~ , 202 1 , and 20 ~~2019~~20			~~134~~137
II. Valuation and Qualifying Accounts and Reserves - Years Ended December 31, ~~2021, 2020, 2019~~202 2 , 202 1 , 20 20			~~138~~140

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

6972

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 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/ Mary E. Kipp

/s/ Kazi Hasan

/s/ ~~Stephen J. King~~Stacy Smith

Mary E. Kipp

Kazi Hasan

~~Stephen J. King~~Stacy Smith

President and Chief Executive Officer

~~Senior~~Executive Vice President

and Chief Financial Officer

Controller and Principal

Accounting Officer

7073

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. 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, ~~2021,~~2022, 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, ~~2021~~2022 and ~~2020,~~2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2021~~2022 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, ~~2021,~~2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial 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.

7174

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 ~~$962.2~~$904.3 million of regulatory assets and ~~$1,791.1~~$2,025.5 million of regulatory liabilities as of December 31, ~~2021.~~2022. 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

Portland, Oregon

February ~~24, 2022~~23, 2023

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

7275

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. 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, ~~2021,~~2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Basis for Opinions

Definition and Limitations of Internal Control over Financial Reporting

7376

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 ~~$952.5~~$896.4 million of regulatory assets and ~~$1,709.5~~$1,961.1 million of regulatory liabilities as of December 31, ~~2021.~~2022. 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.

/s/ PricewaterhouseCoopers LLP

Portland, Oregon

February ~~24, 2022~~23, 2023

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

7477

PUGET ENERGY, INC.

~~CONSOLIDATED STATEMENTS OF INCOME~~

~~(Dollars in Thousands)~~

Year Ended December 31,
2021 2020 2019
Operating revenue:
Electric $ 2,671,623 $ 2,319,416 $ 2,497,041
Natural gas 1,067,418 980,913 875,371
Other 66,620 26,121 28,718
Total operating revenue 3,805,661 3,326,450 3,401,130
Operating expenses:
Energy costs:
Purchased electricity 784,565 593,719 652,560
Electric generation fuel 282,254 199,107 282,864
Residential exchange (82,225) (80,294) (79,187)
Purchased natural gas 398,553 362,872 290,976
Unrealized (gain) loss on derivative instruments, net (13,785) 26,807 3,574
Utility operations and maintenance 629,864 597,048 596,676
Non-utility expense and other 58,281 43,425 47,907
Depreciation and amortization 704,783 647,755 656,323
Conservation amortization 103,147 99,585 96,571
Taxes other than income taxes 362,527 328,602 333,858
Total operating expenses 3,227,964 2,818,626 2,882,122
Operating income (loss) 577,697 507,824 519,008
Other income (deductions):
Other income 57,483 58,759 59,905
Other expense (14,467) (23,207) (9,053)
Interest charges:
AFUDC 16,743 14,827 14,559
Interest expense (352,092) (373,822) (356,638)
Income (loss) before income taxes 285,364 184,381 227,781
Income tax (benefit) expense 24,515 1,664 17,073
Net income (loss) $ 260,849 $ 182,717 $ 210,708

~~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,
2021 2020 2019
Net income (loss) $ 260,849 $ 182,717 $ 210,708
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $15,686 and $(609) and $(1,846), respectively 59,005 (2,288) (6,947)
Other comprehensive income (loss) 59,005 (2,288) (6,947)
Comprehensive income (loss) $ 319,854 $ 180,429 $ 203,761

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

~~PUGET ENERGY, INC.~~

~~CONSOLIDATED BALANCE SHEETS~~

~~(Dollars in Thousands)~~

~~ASSETS~~
December 31,
2021 2020
Utility plant (at original cost, including construction work in progress of $870,204 and $712,204, respectively):
Electric plant $ 9,729,643 $ 9,200,231
Natural gas plant 4,498,198 4,227,532
Common plant 1,155,567 1,116,524
Less: Accumulated depreciation and amortization (4,031,458) (3,671,094)
Net utility plant 11,351,950 10,873,193
Other property and investments:
Goodwill 1,656,513 1,656,513
Other property and investments 324,897 324,184
Total other property and investments 1,981,410 1,980,697
Current assets:
Cash and cash equivalents 56,946 52,307
Restricted cash 46,204 29,544
Accounts receivable, net of allowance for doubtful accounts of $34,958 and $20,080, respectively 398,895 352,132
Unbilled revenue 271,606 221,871
Materials and supplies, at average cost 113,287 118,333
Fuel and natural gas inventory, at average cost 59,393 48,795
Unrealized gain on derivative instruments 128,210 33,015
Prepaid expenses and other 46,293 45,746
Power contract acquisition adjustment gain 17,274 14,874
Total current assets 1,138,108 916,617
Other long-term and regulatory assets:
Power cost adjustment mechanism 79,546 82,801
Purchased gas adjustment receivable 57,935 87,655
Regulatory assets related to power contracts 9,689 11,728
Other regulatory assets 815,058 747,651
Unrealized gain on derivative instruments 26,197 8,805
Power contract acquisition adjustment gain 63,660 80,900
Operating lease right-of-use asset 184,957 172,167
Other 163,374 80,751
Total other long-term and regulatory assets 1,400,416 1,272,458
Total assets $ 15,871,884 $ 15,042,965

~~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,
2021 2020
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding $ — $ —
Additional paid-in capital 3,523,532 3,313,532
Retained earnings 1,067,216 912,787
Accumulated other comprehensive income (loss), net of tax (27,432) (86,437)
Total common shareholder’s equity 4,563,316 4,139,882
Long-term debt:
First mortgage bonds and senior notes 4,662,000 4,212,000
Pollution control bonds 161,860 161,860
Long-term debt 1,583,300 1,724,700
Debt discount, issuance costs and other (203,394) (206,120)
Total long-term debt 6,203,766 5,892,440
Total capitalization 10,767,082 10,032,322
Current liabilities:
Accounts payable 444,384 342,404
Short-term debt 140,000 373,800
Current maturities of long-term debt 450,000 526,412
Accrued expenses:
Taxes 127,398 110,752
Salaries and wages 47,936 42,530
Interest 67,807 73,647
Unrealized loss on derivative instruments 63,309 31,441
Power contract acquisition adjustment loss 1,785 2,039
Operating lease liabilities 20,398 19,204
Other 62,406 73,385
Total current liabilities 1,425,423 1,595,614
Other Long-term and regulatory liabilities:
Deferred income taxes 912,484 810,729
Unrealized loss on derivative instruments 40,965 29,833
Regulatory liabilities 844,184 732,498
Regulatory liability for deferred income taxes 865,976 953,274
Regulatory liabilities related to power contracts 80,934 95,774
Power contract acquisition adjustment loss 7,904 9,689
Operating lease liabilities 172,510 160,980
Finance lease liabilities 105,303 320
Other deferred credits 649,119 621,932
Total long-term and regulatory liabilities 3,679,379 3,415,029
Commitments and contingencies (Note 16) 0 0
Total capitalization and liabilities $ 15,871,884 $ 15,042,965

~~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, 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
Net income (loss) — — — 260,849 — 260,849
Common stock dividend paid — — — (106,420) — (106,420)
Capital contribution — — 210,000 — — 210,000
Other comprehensive income (loss) — — — — 59,005 59,005
Balance at December 31, 2021 200 $ — $ 3,523,532 $ 1,067,216 $ (27,432) $ 4,563,316

~~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,
2021 2020 2019
Operating Activities:
Net Income (Loss) $ 260,849 $ 182,717 $ 210,708
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization 704,783 647,755 656,323
Conservation amortization 103,147 99,585 96,571
Deferred income taxes and tax credits, net (1,228) (6,287) 7,475
Net unrealized (gain) loss on derivative instruments (13,785) 26,807 3,574
(Gain) or loss on extinguishment of debt — 13,546 —
AFUDC - equity (27,806) (23,223) (15,802)
Production tax credit (45,562) (39,761) (68,622)
Other non-cash (9,284) 9,069 (4,639)
Funding of pension liability (18,000) (18,000) (18,000)
Regulatory assets and liabilities (126,625) (152,417) (79,233)
Purchased gas adjustment 29,720 45,111 (132,766)
Other long term assets and liabilities (24,761) (3,171) (16,098)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue (96,498) (32,994) 3,058
Materials and supplies 5,046 (2,649) (6,018)
Fuel and natural gas inventory (10,598) 3,287 1,268
Purchased gas adjustment — — 9,921
Prepayments and other (997) (18,242) (1,103)
Accounts payable 84,775 16,516 (116,311)
Taxes payable 16,646 10,773 (18,133)
Other (3,224) (30,854) 15,163
Net cash provided by (used in) operating activities 826,598 727,568 527,336
Investing activities:
Construction expenditures - excluding equity AFUDC (922,144) (908,136) (959,387)
Other 1,367 5,340 6,908
Net cash provided by (used in) investing activities (920,777) (902,796) (952,479)
Financing Activities:
Change in short-term debt, net (233,800) 197,800 (203,297)
Dividends paid (106,420) (45,421) (64,220)
Investment from parent 210,000 4,575 —
Proceeds from long-term debt and bonds issued 961,538 644,690 689,351
Redemption of bonds and notes (502,410) (450,000) —
Repayment of term loan and revolving credit (234,000) (159,400) —
Other 20,570 (1,311) 13,893
Net cash provided by (used in) financing activities 115,478 190,933 435,727
Net increase (decrease) in cash, cash equivalents, and restricted cash 21,299 15,705 10,584
Cash, cash equivalents, and restricted cash at beginning of period 81,851 66,146 55,562
Cash, cash equivalents, and restricted cash at end of period $ 103,150 $ 81,851 $ 66,146
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest) $ 329,894 $ 336,441 $ 328,703
Cash payments (refunds) for income taxes 22,647 4,974 10,616
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flow $ 89,958 $ 58,304 $ 58,329
Reclassification of Colstrip from utility plant to a regulatory asset — — 4,163
Recognition of finance lease eliminated from cash flows 105,176 — —

~~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,
		2021		2020		2019			2022		2021		2020
Operating revenue:	Operating revenue:							Operating revenue:
Electric	Electric	$	2,671,623	$	2,319,416	$	2,497,041	Electric	$	2,961,457	$	2,671,623	$	2,319,416
Natural gas	Natural gas	1,067,418		980,913		875,371		Natural gas	1,209,636		1,067,418		980,913
Other	Other	66,620		26,121		28,718		Other	50,069		66,620		26,121
Total operating revenue	Total operating revenue	3,805,661		3,326,450		3,401,130		Total operating revenue	4,221,162		3,805,661		3,326,450
Operating expenses:	Operating expenses:							Operating expenses:
Energy costs:	Energy costs:							Energy costs:
Purchased electricity	Purchased electricity	784,565		593,719		652,560		Purchased electricity	1,038,728		784,565		593,719
Electric generation fuel	Electric generation fuel	282,254		199,107		282,864		Electric generation fuel	348,159		282,254		199,107
Residential exchange	Residential exchange	(82,225)		(80,294)		(79,187)		Residential exchange	(77,715)		(82,225)		(80,294)
Purchased natural gas	Purchased natural gas	398,553		362,872		290,976		Purchased natural gas	500,849		398,553		362,872
Unrealized (gain) loss on derivative instruments, net	Unrealized (gain) loss on derivative instruments, net	(13,785)		26,807		3,574		Unrealized (gain) loss on derivative instruments, net	(261,177)		(13,785)		26,807
Utility operations and maintenance	Utility operations and maintenance	629,864		597,048		596,676		Utility operations and maintenance	665,259		629,864		597,048
Non-utility expense and other	Non-utility expense and other	56,242		42,266		44,403		Non-utility expense and other	59,804		58,281		43,425
Depreciation and amortization	Depreciation and amortization	704,372		647,546		656,220		Depreciation and amortization	663,232		704,783		647,755
Conservation amortization	Conservation amortization	103,147		99,585		96,571		Conservation amortization	116,942		103,147		99,585
Taxes other than income taxes	Taxes other than income taxes	362,527		328,602		333,858		Taxes other than income taxes	389,442		362,527		328,602
Total operating expenses	Total operating expenses	3,225,514		2,817,258		2,878,515		Total operating expenses	3,443,523		3,227,964		2,818,626
Operating income (loss)	Operating income (loss)	580,147		509,192		522,615		Operating income (loss)	777,639		577,697		507,824
Other income (deductions):	Other income (deductions):							Other income (deductions):
Other income	Other income	46,523		46,923		47,766		Other income	45,450		57,483		58,759
Other expense	Other expense	(14,467)		(23,207)		(9,053)		Other expense	(19,569)		(14,467)		(23,207)

Interest charges:	Interest charges:							Interest charges:
AFUDC	AFUDC	16,743		14,827		14,559		AFUDC	18,444		16,743		14,827
Interest expense	Interest expense	(248,624)		(247,213)		(243,815)		Interest expense	(347,921)		(352,092)		(373,822)
Income (loss) before income taxes	Income (loss) before income taxes	380,322		300,522		332,072		Income (loss) before income taxes	474,043		285,364		184,381
Income tax (benefit) expense	Income tax (benefit) expense	44,259		26,242		39,148		Income tax (benefit) expense	59,698		24,515		1,664
Net income (loss)	Net income (loss)	$	336,063	$	274,280	$	292,924	Net income (loss)	$	414,345	$	260,849	$	182,717

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,
	2022		2021		2020
Net income (loss)	$	414,345	$	260,849	$	182,717
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $708, $15,686 and $(609), respectively	2,658		59,005		(2,288)


Other comprehensive income (loss)	2,658		59,005		(2,288)
Comprehensive income (loss)	$	417,003	$	319,854	$	180,429

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

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

ASSETS


	December 31,
	2022		2021
Utility plant (at original cost, including construction work in progress of $861,801 and $870,204, respectively):
Electric plant	$	10,300,895	$	9,729,643
Natural gas plant	4,721,982		4,498,198
Common plant	1,103,783		1,155,567
Less: Accumulated depreciation and amortization	(4,341,789)		(4,031,458)
Net utility plant	11,784,871		11,351,950
Other property and investments:
Goodwill	1,656,513		1,656,513
Other property and investments	328,535		324,897
Total other property and investments	1,985,048		1,981,410
Current assets:
Cash and cash equivalents	105,740		56,946
Restricted cash	63,045		46,204
Accounts receivable, net of allowance for doubtful accounts of $41,962 and $34,958, respectively	673,236		398,895
Unbilled revenue	284,022		271,606

Materials and supplies, at average cost	132,172		113,287
Fuel and natural gas inventory, at average cost	94,075		59,393
Unrealized gain on derivative instruments	587,029		128,210
Prepaid expenses and other	41,940		46,293
Power contract acquisition adjustment gain	16,736		17,274
Total current assets	1,997,995		1,138,108
Other long-term and regulatory assets:
Power cost adjustment mechanism	112,207		79,546
Purchased gas adjustment receivable	—		57,935
Regulatory assets related to power contracts	7,904		9,689
Other regulatory assets	784,231		815,058
Unrealized gain on derivative instruments	94,621		26,197
Power contract acquisition adjustment gain	46,924		63,660
Operating lease right-of-use asset	193,509		184,957
Other	180,204		163,374
Total other long-term and regulatory assets	1,419,600		1,400,416
Total assets	$	17,187,514	$	15,871,884

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,
	2022		2021
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding	$	—	$	—
Additional paid-in capital	3,523,532		3,523,532
Retained earnings	1,465,331		1,067,216
Accumulated other comprehensive income (loss), net of tax	(24,774)		(27,432)
Total common shareholder’s equity	4,964,089		4,563,316
Long-term debt:
First mortgage bonds and senior notes	4,662,000		4,662,000
Pollution control bonds	161,860		161,860

Long-term debt	2,034,300		1,583,300
Debt discount, issuance costs and other	(194,787)		(203,394)
Total long-term debt	6,663,373		6,203,766
Total capitalization	11,627,462		10,767,082
Current liabilities:
Accounts payable	665,750		444,384
Short-term debt	441,300		140,000
Current maturities of long-term debt	—		450,000

Accrued expenses:
Taxes	116,098		127,398
Salaries and wages	60,537		47,936
Interest	62,148		67,807
Unrealized loss on derivative instruments	124,976		63,309
Power contract acquisition adjustment loss	1,638		1,785
Operating lease liabilities	20,342		20,398
Other	70,685		62,406
Total current liabilities	1,563,474		1,425,423
Other Long-term and regulatory liabilities:
Deferred income taxes	985,947		912,484
Unrealized loss on derivative instruments	18,366		40,965
Purchased gas adjustment liability	3,536		—
Regulatory liabilities	1,147,143		844,184
Regulatory liability for deferred income taxes	811,161		865,976
Regulatory liabilities related to power contracts	63,660		80,934
Power contract acquisition adjustment loss	6,266		7,904
Operating lease liabilities	181,265		172,510
Finance lease liabilities	102,518		105,303
Other deferred credits	676,716		649,119
Total long-term and regulatory liabilities	3,996,578		3,679,379
Commitments and contingencies (Note 16)
Total capitalization and liabilities	$	17,187,514	$	15,871,884

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 Paid-in Capital				Accumulated Other Comprehensive Income (Loss)
	Shares	Amount				Retained Earnings				Total Equity
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
Net income (loss)	—	—		—		260,849		—		260,849
Common stock dividend paid	—	—		—		(106,420)		—		(106,420)
Capital contribution	—	—		210,000		—		—		210,000
Other comprehensive income (loss)	—	—		—		—		59,005		59,005
Balance at December 31, 2021	200	$	—	$	3,523,532	$	1,067,216	$	(27,432)	$	4,563,316
Net income (loss)	—	—		—		414,345		—		414,345
Common stock dividend paid	—	—		—		(16,230)		—		(16,230)

Other comprehensive income (loss)	—	—		—		—		2,658		2,658
Balance at December 31, 2022	200	$	—	$	3,523,532	$	1,465,331	$	(24,774)	$	4,964,089

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,
	2022		2021		2020
Operating Activities:
Net Income (Loss)	$	414,345	$	260,849	$	182,717
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	663,232		704,783		647,755
Conservation amortization	116,942		103,147		99,585
Deferred income taxes and tax credits, net	17,941		(1,228)		(6,287)
Net unrealized (gain) loss on derivative instruments	(261,177)		(13,785)		26,807
(Gain) or loss on extinguishment of debt	—		—		13,546
AFUDC - equity	(28,310)		(27,806)		(23,223)
Production tax credit	—		(45,562)		(39,761)
Other non-cash	4,757		(9,284)		9,069
Funding of pension liability	(18,000)		(18,000)		(18,000)
Regulatory assets and liabilities	(90,335)		(126,625)		(152,417)
Purchased gas adjustment	37,256		29,720		45,111
Other long term assets and liabilities	(23,639)		(24,761)		(3,171)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	(258,188)		(96,498)		(32,994)
Materials and supplies	(18,885)		5,046		(2,649)
Fuel and natural gas inventory	(34,682)		(10,598)		3,287

Prepayments and other	4,186		(997)		(18,242)
Accounts payable	237,260		84,775		16,516
Taxes payable	(11,300)		16,646		10,773
Other	18,215		(3,224)		(30,854)
Net cash provided by (used in) operating activities	769,618		826,598		727,568
Investing activities:
Construction expenditures - excluding equity AFUDC	(1,004,713)		(922,144)		(908,136)
Other	(567)		1,367		5,340
Net cash provided by (used in) investing activities	(1,005,280)		(920,777)		(902,796)
Financing Activities:
Change in short-term debt, net	301,300		(233,800)		197,800
Dividends paid	(16,230)		(106,420)		(45,421)

Investment from parent	—		210,000		4,575
Proceeds from long-term debt and bonds issued	448,075		961,538		644,690
Redemption of bonds and notes	(450,000)		(502,410)		(450,000)
Repayment of term loan and revolving credit	—		(234,000)		(159,400)
Other	18,152		20,570		(1,311)
Net cash provided by (used in) financing activities	301,297		115,478		190,933
Net increase (decrease) in cash, cash equivalents, and restricted cash	65,635		21,299		15,705
Cash, cash equivalents, and restricted cash at beginning of period	103,150		81,851		66,146
Cash, cash equivalents, and restricted cash at end of period	$	168,785	$	103,150	$	81,851
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	320,656	$	329,894	$	336,441
Cash payments (refunds) for income taxes	46,785		22,647		4,974

Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flow	$	68,357	$	89,958	$	58,304

Recognition of finance lease eliminated from cash flows	454		105,176		—

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,
	2022		2021		2020
Operating revenue:
Electric	$	2,961,457	$	2,671,623	$	2,319,416
Natural gas	1,209,636		1,067,418		980,913
Other	45,080		66,620		26,121
Total operating revenue	4,216,173		3,805,661		3,326,450
Operating expenses:
Energy costs:
Purchased electricity	1,038,728		784,565		593,719
Electric generation fuel	348,159		282,254		199,107
Residential exchange	(77,715)		(82,225)		(80,294)
Purchased natural gas	500,849		398,553		362,872
Unrealized (gain) loss on derivative instruments, net	(261,177)		(13,785)		26,807
Utility operations and maintenance	665,259		629,864		597,048
Non-utility expense and other	47,194		56,242		42,266
Depreciation and amortization	657,349		704,372		647,546
Conservation amortization	116,942		103,147		99,585
Taxes other than income taxes	388,123		362,527		328,602
Total operating expenses	3,423,711		3,225,514		2,817,258
Operating income (loss)	792,462		580,147		509,192
Other income (deductions):
Other income	36,684		46,523		46,923
Other expense	(19,569)		(14,467)		(23,207)

Interest charges:
AFUDC	18,444		16,743		14,827
Interest expense	(256,774)		(248,624)		(247,213)
Income (loss) before income taxes	571,247		380,322		300,522
Income tax (benefit) expense	80,295		44,259		26,242
Net income (loss)	$	490,952	$	336,063	$	274,280

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,							Year Ended December 31,
		2021		2020		2019			2022		2021		2020
Net income (loss)	Net income (loss)	$	336,063	$	274,280	$	292,924	Net income (loss)	$	490,952	$	336,063	$	274,280
Other comprehensive income (loss):	Other comprehensive income (loss):							Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $17,925, $1,897 and $539, respectively		67,431		7,136		2,022
Amortization of treasury interest rate swaps to earnings, net of tax of $103, $102 and $102, respectively		384		385		385
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $2,580, $17,925 and $1,897, respectively								Net unrealized gain (loss) from pension and postretirement plans, net of tax of $2,580, $17,925 and $1,897, respectively	9,711		67,431		7,136
Amortization of treasury interest rate swaps to earnings, net of tax of $102, $103 and $102, respectively								Amortization of treasury interest rate swaps to earnings, net of tax of $102, $103 and $102, respectively	386		384		385

Other comprehensive income (loss)	Other comprehensive income (loss)	67,815		7,521		2,407		Other comprehensive income (loss)	10,097		67,815		7,521
Comprehensive income (loss)	Comprehensive income (loss)	$	403,878	$	281,801	$	295,331	Comprehensive income (loss)	$	501,049	$	403,878	$	281,801

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

8285

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

ASSETS


		December 31,					December 31,
		2021		2020			2022		2021
Utility plant (at original cost, including construction work in progress of $870,204 and $712,204, respectively):
Utility plant (at original cost, including construction work in progress of $861,801 and $870,204, respectively):						Utility plant (at original cost, including construction work in progress of $861,801 and $870,204, respectively):
Electric plant	Electric plant	$	11,535,976	$	11,035,402	Electric plant	$	12,071,531	$	11,535,976
Natural gas plant	Natural gas plant	5,054,622		4,786,419		Natural gas plant	5,276,156		5,054,622
Common plant	Common plant	1,177,598		1,139,120		Common plant	1,125,217		1,177,598
Less: Accumulated depreciation and amortization	Less: Accumulated depreciation and amortization	(6,416,246)		(6,087,748)		Less: Accumulated depreciation and amortization	(6,688,033)		(6,416,246)
Net utility plant	Net utility plant	11,351,950		10,873,193		Net utility plant	11,784,871		11,351,950
Other property and investments:	Other property and investments:					Other property and investments:
Other property and investments	Other property and investments	74,602		83,855		Other property and investments	80,076		74,602
Total other property and investments	Total other property and investments	74,602		83,855		Total other property and investments	80,076		74,602
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	50,043		51,177		Cash and cash equivalents	102,840		50,043
Restricted cash	Restricted cash	46,204		29,544		Restricted cash	63,045		46,204
Accounts receivable, net of allowance for doubtful accounts of $34,958 and $20,080, respectively		402,602		355,850
Accounts receivable, net of allowance for doubtful accounts of $41,962 and $34,958, respectively						Accounts receivable, net of allowance for doubtful accounts of $41,962 and $34,958, respectively	671,071		402,602
Unbilled revenue	Unbilled revenue	271,606		221,871		Unbilled revenue	284,014		271,606

Materials and supplies, at average cost	Materials and supplies, at average cost	113,287		118,333		Materials and supplies, at average cost	132,172		113,287
Fuel and natural gas inventory, at average cost	Fuel and natural gas inventory, at average cost	58,129		47,531		Fuel and natural gas inventory, at average cost	91,783		58,129
Unrealized gain on derivative instruments	Unrealized gain on derivative instruments	128,210		33,015		Unrealized gain on derivative instruments	587,029		128,210
Prepaid expenses and other	Prepaid expenses and other	46,293		45,746		Prepaid expenses and other	41,940		46,293
Total current assets	Total current assets	1,116,374		903,067		Total current assets	1,973,894		1,116,374
Other long-term and regulatory assets:	Other long-term and regulatory assets:					Other long-term and regulatory assets:
Power cost adjustment mechanism	Power cost adjustment mechanism	79,546		82,801		Power cost adjustment mechanism	112,207		79,546
Purchased gas adjustment receivable	Purchased gas adjustment receivable	57,935		87,655		Purchased gas adjustment receivable	—		57,935
Other regulatory assets	Other regulatory assets	815,058		747,651		Other regulatory assets	784,231		815,058
Unrealized gain on derivative instruments	Unrealized gain on derivative instruments	26,197		8,805		Unrealized gain on derivative instruments	94,621		26,197
Operating lease right-of-use asset	Operating lease right-of-use asset	184,957		172,167		Operating lease right-of-use asset	193,509		184,957
Other	Other	162,391		79,231		Other	176,833		162,391
Total other long-term and regulatory assets	Total other long-term and regulatory assets	1,326,084		1,178,310		Total other long-term and regulatory assets	1,361,401		1,326,084
Total assets	Total assets	$	13,869,010	$	13,038,425	Total assets	$	15,200,242	$	13,869,010

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

8386

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

CAPITALIZATION AND LIABILITIES


		Year Ended December 31,					Year Ended December 31,
		2021		2020			2022		2021
Capitalization:	Capitalization:					Capitalization:
Common shareholder’s equity:	Common shareholder’s equity:					Common shareholder’s equity:
Common stock $0.01 par value, 150,000,000 shares authorized, 85,903,791 shares outstanding	Common stock $0.01 par value, 150,000,000 shares authorized, 85,903,791 shares outstanding	$	859	$	859	Common stock $0.01 par value, 150,000,000 shares authorized, 85,903,791 shares outstanding	$	859	$	859
Additional paid-in capital	Additional paid-in capital	3,485,105		3,485,105		Additional paid-in capital	3,535,105		3,485,105
Retained earnings	Retained earnings	982,607		876,401		Retained earnings	1,438,163		982,607
Accumulated other comprehensive income (loss), net of tax	Accumulated other comprehensive income (loss), net of tax	(113,141)		(180,956)		Accumulated other comprehensive income (loss), net of tax	(103,044)		(113,141)
Total common shareholder’s equity	Total common shareholder’s equity	4,355,430		4,181,409		Total common shareholder’s equity	4,871,083		4,355,430
Long-term debt:	Long-term debt:					Long-term debt:
First mortgage bonds and senior notes	First mortgage bonds and senior notes	4,662,000		4,212,000		First mortgage bonds and senior notes	4,662,000		4,662,000
Pollution control bonds	Pollution control bonds	161,860		161,860		Pollution control bonds	161,860		161,860

Debt discount, issuance costs and other	Debt discount, issuance costs and other	(39,141)		(35,816)		Debt discount, issuance costs and other	(37,095)		(39,141)
Total long-term debt	Total long-term debt	4,784,719		4,338,044		Total long-term debt	4,786,765		4,784,719
Total capitalization	Total capitalization	9,140,149		8,519,453		Total capitalization	9,657,848		9,140,149
Current liabilities:	Current liabilities:					Current liabilities:
Accounts payable	Accounts payable	451,716		342,504		Accounts payable	664,457		451,716
Short-term debt	Short-term debt	140,000		373,800		Short-term debt	357,000		140,000
Current maturities of long-term debt		—		2,412

Accrued expenses:	Accrued expenses:					Accrued expenses:
Taxes	Taxes	133,406		107,254		Taxes	116,472		133,406
Salaries and wages	Salaries and wages	47,936		42,530		Salaries and wages	60,537		47,936
Interest	Interest	51,832		48,189		Interest	52,170		51,832
Unrealized loss on derivative instruments	Unrealized loss on derivative instruments	63,309		31,441		Unrealized loss on derivative instruments	124,976		63,309
Operating lease liabilities	Operating lease liabilities	20,398		19,204		Operating lease liabilities	20,342		20,398
Other	Other	62,406		73,385		Other	70,685		62,406
Total current liabilities	Total current liabilities	971,003		1,040,719		Total current liabilities	1,466,639		971,003
Other long-term and regulatory liabilities:	Other long-term and regulatory liabilities:					Other long-term and regulatory liabilities:
Deferred income taxes	Deferred income taxes	1,084,203		987,382		Deferred income taxes	1,139,600		1,084,203
Unrealized loss on derivative instruments	Unrealized loss on derivative instruments	40,965		29,833		Unrealized loss on derivative instruments	18,366		40,965
Purchased gas adjustment liability						Purchased gas adjustment liability	3,536		—
Regulatory liabilities	Regulatory liabilities	842,920		731,234		Regulatory liabilities	1,145,879		842,920
Regulatory liability for deferred income taxes	Regulatory liability for deferred income taxes	866,541		953,987		Regulatory liability for deferred income taxes	811,724		866,541
Operating lease liabilities	Operating lease liabilities	172,510		160,980		Operating lease liabilities	181,265		172,510
Finance lease liabilities	Finance lease liabilities	105,303		320		Finance lease liabilities	102,518		105,303
Other deferred credits	Other deferred credits	645,416		614,517		Other deferred credits	672,867		645,416
Total long-term and regulatory liabilities	Total long-term and regulatory liabilities	3,757,858		3,478,253		Total long-term and regulatory liabilities	4,075,755		3,757,858
Commitments and contingencies (Note 16)	Commitments and contingencies (Note 16)	0		0		Commitments and contingencies (Note 16)
Total capitalization and liabilities	Total capitalization and liabilities	$	13,869,010	$	13,038,425	Total capitalization and liabilities	$	15,200,242	$	13,869,010

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

8487

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(Dollars in Thousands)


		Common Stock			Additional				Accumulated Other					Common Stock			Additional Paid-in Capital								Accumulated Other Comprehensive Income (Loss)
		Shares	Amount		Paid-in Capital		Retained Earnings		Comprehensive Income (Loss)		Total Equity			Shares	Amount				Retained Earnings								Total Equity
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	Balance at December 31, 2019	85,903,791	$	859	$	3,485,105	$	751,193	$	(188,477)	$	4,048,680	Balance at December 31, 2019	85,903,791	$	859			$	3,485,105			$	751,193			$	(188,477)			$	4,048,680
Net income (loss)	Net income (loss)	—	—		—		274,280		—		274,280		Net income (loss)	—	—		—				274,280				—				274,280
Common stock dividend paid	Common stock dividend paid	—	—		—		(149,072)		—		(149,072)		Common stock dividend paid	—	—		—				(149,072)				—				(149,072)

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

Balance at December 31, 2020	Balance at December 31, 2020	85,903,791	$	859	$	3,485,105	$	876,401	$	(180,956)	$	4,181,409	Balance at December 31, 2020	85,903,791	$	859	$	3,485,105			$	876,401			$	(180,956)			$	4,181,409
Net income (loss)	Net income (loss)	—	—		—		336,063		—		336,063		Net income (loss)	—	—		—				336,063				—				336,063
Common stock dividend paid	Common stock dividend paid	—	—		—		(229,857)		—		(229,857)		Common stock dividend paid	—	—		—				(229,857)				—				(229,857)
Other comprehensive income (loss)	Other comprehensive income (loss)	—	—		—		—		67,815		67,815		Other comprehensive income (loss)	—	—		—				—				67,815				67,815
Balance at December 31, 2021	Balance at December 31, 2021	85,903,791	$	859	$	3,485,105	$	982,607	$	(113,141)	$	4,355,430	Balance at December 31, 2021	85,903,791	$	859	$	3,485,105			$	982,607			$	(113,141)			$	4,355,430
Net income (loss)													Net income (loss)	—	—		—				490,952				—				490,952
Common stock dividend paid													Common stock dividend paid	—	—		—				(35,396)				—				(35,396)
Capital Contribution													Capital Contribution	—	—		50,000				—				—				50,000
Other comprehensive income (loss)													Other comprehensive income (loss)	—	—		—				—				10,097				10,097
Balance at December 31, 2022													Balance at December 31, 2022	85,903,791	$	859	$	3,535,105			$	1,438,163			$	(103,044)			$	4,871,083

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

8588

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)


		Year Ended December 31,							Year Ended December 31,
		2021		2020		2019			2022		2021		2020
Operating Activities:	Operating Activities:							Operating Activities:
Net Income (Loss)	Net Income (Loss)	$	336,063	$	274,280	$	292,924	Net Income (Loss)	$	490,952	$	336,063	$	274,280
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:							Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	Depreciation and amortization	704,372		647,546		656,220		Depreciation and amortization	657,349		704,372		647,546
Conservation amortization	Conservation amortization	103,147		99,585		96,571		Conservation amortization	116,942		103,147		99,585
Deferred income taxes and tax credits, net	Deferred income taxes and tax credits, net	(8,652)		15,271		20,474		Deferred income taxes and tax credits, net	(2,103)		(8,652)		15,271
Net unrealized (gain) loss on derivative instruments	Net unrealized (gain) loss on derivative instruments	(13,785)		26,807		3,574		Net unrealized (gain) loss on derivative instruments	(261,177)		(13,785)		26,807

AFUDC - equity	AFUDC - equity	(27,806)		(23,223)		(15,802)		AFUDC - equity	(28,310)		(27,806)		(23,223)
Production tax credit	Production tax credit	(45,562)		(39,761)		(68,622)		Production tax credit	—		(45,562)		(39,761)
Other non-cash	Other non-cash	(19,761)		(1,575)		(15,154)		Other non-cash	(6,005)		(19,761)		(1,575)
Funding of pension liability	Funding of pension liability	(18,000)		(18,000)		(18,000)		Funding of pension liability	(18,000)		(18,000)		(18,000)
Regulatory assets and liabilities	Regulatory assets and liabilities	(126,625)		(152,417)		(79,173)		Regulatory assets and liabilities	(90,335)		(126,625)		(152,417)
Purchased gas adjustment	Purchased gas adjustment	29,720		45,111		(132,766)		Purchased gas adjustment	37,256		29,720		45,111
Other long term assets and liabilities	Other long term assets and liabilities	(14,097)		8,764		(8,967)		Other long term assets and liabilities	(14,359)		(14,097)		8,764
Change in certain current assets and liabilities:	Change in certain current assets and liabilities:							Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	Accounts receivable and unbilled revenue	(96,487)		(33,835)		7,650		Accounts receivable and unbilled revenue	(252,308)		(96,487)		(33,835)
Materials and supplies	Materials and supplies	5,046		(2,649)		(6,018)		Materials and supplies	(18,885)		5,046		(2,649)
Fuel and natural gas inventory	Fuel and natural gas inventory	(10,598)		3,287		1,210		Fuel and natural gas inventory	(33,654)		(10,598)		3,287
Purchased gas adjustment		—		—		9,921

Prepayments and other	Prepayments and other	(997)		(18,242)		(1,103)		Prepayments and other	4,186		(997)		(18,242)
Accounts payable	Accounts payable	92,007		16,549		(116,370)		Accounts payable	228,635		92,007		16,549
Taxes payable	Taxes payable	26,152		7,277		(18,016)		Taxes payable	(16,934)		26,152		7,277
Other	Other	6,256		(29,965)		15,371		Other	24,211		6,256		(29,965)
Net cash provided by (used in) operating activities	Net cash provided by (used in) operating activities	920,393		824,810		623,924		Net cash provided by (used in) operating activities	817,461		920,393		824,810
Investing Activities:	Investing Activities:							Investing Activities:
Construction expenditures - excluding equity AFUDC	Construction expenditures - excluding equity AFUDC	(908,273)		(876,437)		(919,271)		Construction expenditures - excluding equity AFUDC	(1,000,810)		(908,273)		(876,437)
Other	Other	1,367		5,340		6,908		Other	(567)		1,367		5,340
Net cash provided by (used in) investing activities	Net cash provided by (used in) investing activities	(906,906)		(871,097)		(912,363)		Net cash provided by (used in) investing activities	(1,001,377)		(906,906)		(871,097)
Financing Activities	Financing Activities							Financing Activities
Change in short-term debt, net	Change in short-term debt, net	(233,800)		197,800		(203,297)		Change in short-term debt, net	217,000		(233,800)		197,800
Dividends paid	Dividends paid	(229,857)		(149,072)		(164,575)		Dividends paid	(35,396)		(229,857)		(149,072)

Investment from parent	Investment from parent	—		—		210,000		Investment from parent	50,000		—		—
Proceeds from long-term debt and bonds issued	Proceeds from long-term debt and bonds issued	446,063		—		443,151		Proceeds from long-term debt and bonds issued	—		446,063		—
Redemption of bonds and notes	Redemption of bonds and notes	(2,410)		—		—		Redemption of bonds and notes	—		(2,410)		—
Other	Other	22,043		13,389		14,558		Other	21,950		22,043		13,389
Net cash provided by (used in) financing activities	Net cash provided by (used in) financing activities	2,039		62,117		299,837		Net cash provided by (used in) financing activities	253,554		2,039		62,117
Net increase (decrease) in cash, cash equivalents, and restricted cash	Net increase (decrease) in cash, cash equivalents, and restricted cash	15,526		15,830		11,398		Net increase (decrease) in cash, cash equivalents, and restricted cash	69,638		15,526		15,830
Cash, cash equivalents, and restricted cash at beginning of period	Cash, cash equivalents, and restricted cash at beginning of period	80,721		64,891		53,493		Cash, cash equivalents, and restricted cash at beginning of period	96,247		80,721		64,891
Cash, cash equivalents, and restricted cash at end of period	Cash, cash equivalents, and restricted cash at end of period	$	96,247	$	80,721	$	64,891	Cash, cash equivalents, and restricted cash at end of period	$	165,885	$	96,247	$	80,721
Supplemental cash flow information:	Supplemental cash flow information:							Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	Cash payments for interest (net of capitalized interest)	$	223,484	$	228,420	$	219,665	Cash payments for interest (net of capitalized interest)	$	233,746	$	223,484	$	228,420
Cash payments (refunds) for income taxes	Cash payments (refunds) for income taxes	38,442		11,521		19,269		Cash payments (refunds) for income taxes	93,058		38,442		11,521

Non-cash financing and investing activities:	Non-cash financing and investing activities:							Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flow	Accounts payable for capital expenditures eliminated from cash flow	$	89,958	$	58,304	$	58,329	Accounts payable for capital expenditures eliminated from cash flow	$	68,357	$	89,958	$	58,304
Reclassification of Colstrip from utility plant to a regulatory asset		—		—		4,163

Recognition of finance lease eliminated from cash flows	Recognition of finance lease eliminated from cash flows	105,176		—		—		Recognition of finance lease eliminated from cash flows	454		105,176		—

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

8689

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Summary of Significant Accounting Policies

Basis of Presentation

Puget Energy is an energy services holding company that owns Puget Sound Energy (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, Puget LNG, LLC (Puget LNG), which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma liquefied natural gas (LNG) facility. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that are incurred by PSE and 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 a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date.

The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company”. The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any ASC 805, “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 3.4%, ~~3.5%~~3.4%, and ~~3.4%~~3.5% in 2022, 2021, ~~2020,~~ and ~~2019,~~2020, respectively; depreciable natural gas utility plant was ~~2.8%~~2.9%, ~~2.9%~~2.8%, and ~~2.8%~~2.9% in 2022, 2021, ~~2020,~~ and ~~2019,~~2020, respectively; and depreciable common utility plant

was ~~6.8%~~7.1%, ~~7.3%~~6.8% and 7.3% in 2022, 2021, ~~2020,~~ and ~~2019,~~2020, respectively. The cost of removal is collected from PSE’s customers through depreciation expense and any excess is recorded as a regulatory liability.

Tacoma LNG Facility

OnIn February 1, 2022, the Tacoma LNG facility at the Port of Tacoma completed commissioning and ~~is expected to commence~~commenced commercial ~~operations in the first quarter of 2022.~~operations. In December 2019, the Puget Sound Clean Air Agency (PSCAA) issued the air quality permit for the facility, and the Pollution Hearings Control Board of Washington State upheld the approval following extended litigation. ~~When in-service, the~~The Tacoma LNG facility ~~will provide~~provides peak-shaving services to PSE’s natural gas customers, and ~~provide~~provides LNG as fuel to transportation customers, particularly in the marine market at a lower cost due to the facility's scale.

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. Per this allocation of costs, ~~$244.7~~$249.1 million of non-utility plant and ~~$231.6~~$244.7 million of construction work in progress related to Puget LNG's portion of the Tacoma LNG facility is reported in the Puget Energy "Other property and investments" financial statement line item as of December 31, ~~2021,~~2022, and December 31, ~~2020,~~2021, respectively. Additionally, $11.6 million, $1.3 million, ~~$0.6 million,~~ and ~~$1.2~~$0.6 million of operating costs are reported in the Puget Energy "Non-utility expense and other" financial statement line item in 2022, 2021, ~~2020,~~ and ~~2019,~~2020, respectively. Additionally, $245.7 million and $239.6 million of plant in service and ~~$207.7 million of~~ construction work in progress 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, ~~2021,~~2022, and December 31, ~~2020,~~2021, 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 LNG held in storage for future sales. The Company records ~~these items~~fuel inventory and natural gas inventory for unregulated operations at the lower of cost or net realizable value ~~method.~~and natural gas inventory for regulated operations at average cost.

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 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 AFUDC rate authorized by the Washington Commission for natural gas and electric utility plant additions effective December 19, 2017, was 7.60%. Effective October 1, 2020 for natural gas and October 15, 2020 for electric the authorized AFUDC rate is 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. 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 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 $292.8 million, $268.5 million and $240.8 million for 2022, 2021, and ~~$236.5 million for 2021,~~ 2020, ~~and 2019,~~ 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 soft rate cap of total revenue for decoupled rate schedules, where rate cap is applied to under-collected revenue and any over-collected revenues are passed back to customers at 100%. Any excess under-recovered revenue above the rate cap will be included in the following year's decoupled rate and the Company will only be able to recognize revenue below the rate cap of total revenue for decoupled rate schedules. For revenue deferrals exceeding the annual 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 per GAAP rules. The soft rate cap test, which limits the amount of revenues PSE can collect in its annual filings, is 5.0% for natural gas customers and 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 Credit Losses

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 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 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 electric wholesale receivables. The estimate of expected credit losses considers historical 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 at December 31, ~~2021,~~2022, and ~~2020:~~2021:


Puget Energy and Puget Sound Energy	Puget Energy and Puget Sound Energy					Puget Energy and Puget Sound Energy
(Dollars in Thousands)	(Dollars in Thousands)	Year Ended December 31,				(Dollars in Thousands)	Year Ended December 31,
Allowance for credit losses:	Allowance for credit losses:	2021		2020		Allowance for credit losses:	2022		2021
Beginning balance	Beginning balance	$	20,080	8,294		Beginning balance	$	34,958	20,080
Provision for credit loss expense1	Provision for credit loss expense1	27,204		23,292		Provision for credit loss expense1	28,316		27,204
Receivables charged-off	Receivables charged-off	(12,326)		(11,506)		Receivables charged-off	(21,312)		(12,326)

Total ending allowance balance	Total ending allowance balance	$	34,958	$	20,080	Total ending allowance balance	$	41,962	$	34,958

1 $~~2.8~~7.1 million and ~~$0.0~~$2.8 million of provision were deferred as cost specific to COVID-19 in ~~2021~~2022 and ~~2020,~~2021, respectively.

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. The cumulative annual cost threshold for deferral of storms under the mechanism is $10.0 million. 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 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 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. 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 had not generated taxable income with which to monetize the credits, they 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 were also recorded for 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 increase to revenue and deferred tax expense will be recorded as the PTCs are monetized. These entries will result in no net income impact. For the tax year ending December 31, 2022, there was no PTC monetized as there were no PTC carryforwards from 2021. For the tax years ending December 31, 2021 and 2020, $45.6 million and $39.8 million of PTCs were ~~estimated to be~~ monetized through tax ~~filings, respectively.~~filings.

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. For additional information, see Note 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 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

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 finance lease liabilities in our consolidated balance sheets.

ROU assets represent the right to use an underlying asset for the lease term, and consist of the 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 any initial direct costs incurred by the lessee. Lease liabilities 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 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~~Power Purchase Agreement (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 renewable energy credits 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 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 not the 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 ~~$19.0~~$14.6 million was recognized in purchased electricity on the Company's consolidated statements of income for the year ended December 31, ~~2021~~2022 and ~~$2.7~~$1.4 million is ~~included in accounts payable on the Company's consolidated balance sheet~~

~~for the year ended December 31, 2021. 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.~~2022. Purchased energy of $19.0 million was recognized in purchased electricity on the Company's consolidated statements of income and $2.7 million included in accounts payable on the Company's consolidated balance sheet for the year ended December 31, 2021.

On May 28, 2020, PSE entered into a PPA with Golden Hills Wind Farm, LLC (Golden Hills) pursuant to which Golden Hills 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. On April 29, 2022, Golden Hills commenced commercial operations. PSE has no equity investment in Golden Hills but is Golden Hills’s only customer. Based on the terms of the contract, PSE will receive all of the output of the facility, subject to curtailment rights. PSE has concluded that Golden Hills is a VIE and that PSE is not the 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 $18.3 million was recognized in purchased electricity on the Company's consolidated statements of income for the year ended December 31, 2022. There was no balance in accounts payable on the Company's balance sheet as of December 31, 2022.

On February 3, 2021, PSE entered into a PPA with Clearwater Wind Project, LLC (Clearwater) in which Clearwater will develop a wind generation facility on a site located in Rosebud, Custer and Garfield counties, Montana; and, once completed, sell energy and associated attributes to PSE over a term of 25 years. On November 8th, 2022, Clearwater commenced commercial operations. PSE has no equity investment in Clearwater but is Clearwater’s only customer. Based on the terms of the contract, PSE will receive all of the output of the facility, subject to curtailment rights. PSE has concluded that Clearwater is a VIE and that PSE is not the 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 $5.7 million was recognized in purchased electricity on the Company's consolidated statements of income for the year ended December 31, 2022. Additionally, $2.5 million was included in accounts payable on the Company's balance sheet as of December 31, 2022.

(2) New Accounting Pronouncements

Recently Adopted Accounting Guidance

Reference Rate Reform

In March 2020, the FASB issued ASU 2020-04, "Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting”. ASU 2020-04 provides temporary optional expedients and exceptions to the current guidance on contract modifications to ease the financial reporting burdens related to the expected market transition from London Interbank Offered Rate (LIBOR) and other interbank offered rates to alternative reference rates. In December 2022, the FASB issued ASU 2022-06, "Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848". ASU 2022-06 postpones the sunset date of Topic 848 from December 31, 2022 to December 31, 2024. The Company has ~~term loans, credit agreements, and~~ promissory notes that reference LIBOR. As of December 31, ~~2021,~~2022, the Company has not utilized any of the 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.~~2024.

Retirement Benefits

In 2018, the FASB issued ASU 2018-14, "Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the 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 relevant disclosures.

The amendments in this update are effective for fiscal years ending after December 15, 2020, for public business entities and for fiscal years ending after December 15, 2021, for all other entities. Early adoption is permitted for all entities. The Company adopted this standard for the year ended December 31, 2020. Refer to Note 13, "Retirement Benefits" to the consolidated financial statements.

~~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 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 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 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 be reported in accordance with previously applicable GAAP. Upon implementation as of January 1, 2020, the impact was immaterial and the Company did not record a transition adjustment to retained earnings.

Fair Value Measurement

In 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 the 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 did not have a material impact on the Company's results of operations, cash flows, or consolidated balance sheets.

~~Goodwill~~

~~In 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 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, 2019. The Company adopted this update in 2020, and it did not have a material impact on goodwill valuation.

(3) Revenue

The following ~~table presents~~tables present disaggregated revenue from contracts with customers, and other revenue by major ~~source:~~source for the years ended December 31, 2022, December 31, 2021, and December 31, 2020:


Puget Energy and Puget Sound Energy
(Dollars in Thousands)	Year Ended December 31, 2022
Revenue from contracts with customers:	Electric		Natural Gas		Other1		Total
Retail
Residential	$	1,381,858	$	808,376	$	—	$	2,190,234
Commercial	981,170		352,243		—		1,333,413
Industrial	116,712		25,096		—		141,808
Other	18,759		—		—		18,759
Wholesale	319,380		—		—		319,380
Transmission and transportation	47,027		20,332		—		67,359
Miscellaneous	13,065		718		50,069		63,852
Total revenue from contracts with customers	$	2,877,971	$	1,206,765	$	50,069	$	4,134,805
Total other revenue2	83,486		2,871		—		86,357
Total operating revenue	$	2,961,457	$	1,209,636	$	50,069	$	4,221,162

_____________
Puget Energy and
Puget Sound Energy
(Dollars in Thousands) Year Ended December 31,
Revenue from Contracts with Customers: 2021 2020 2019
Electric retail $ 2,348,356 $ 2,106,122 $ 2,132,522
Natural gas retail 1,036,411 938,061 870,457
Other 349,365 178,208 308,111
Total revenue from contracts with customers 3,734,132 3,222,391 3,311,090
Alternative revenue programs (31,510) 35,006 (18,634)
Other non-customer revenue 103,039 69,053 108,674
Total operating revenue $ 3,805,661 $ 3,326,450 $ 3,401,130

1Other includes $5.0 million of Puget LNG revenues recorded at Puget Energy.

2 Total other revenue includes revenues from derivatives and alternative revenue programs that are not considered revenues from contracts with customers.


Puget Energy and Puget Sound Energy
(Dollars in Thousands)	Year Ended December 31, 2021
Revenue from contracts with customers:	Electric		Natural Gas		Other		Total
Retail
Residential	$	1,318,326	$	722,003	$	—	$	2,040,329
Commercial	902,928		292,275		—		1,195,203
Industrial	108,267		21,741		—		130,008
Other	18,834		392		—		19,226
Wholesale	161,152		—		—		161,152
Transmission and transportation	43,753		20,030		—		63,783
Miscellaneous	47,948		9,863		66,620		124,431
Total revenue from contracts with customers	$	2,601,208	$	1,066,304	$	66,620	$	3,734,132
Total other revenue1	70,415		1,114		—		71,529
Total operating revenue	$	2,671,623	$	1,067,418	$	66,620	$	3,805,661

_____________

1 Total other revenue includes revenues from derivatives, PTC deferral revenue and alternative revenue programs that are not considered revenues from contracts with customers.


Puget Energy and Puget Sound Energy
(Dollars in Thousands)	Year Ended December 31, 2020
Revenue from contracts with customers:	Electric		Natural Gas		Other		Total
Retail
Residential	$	1,186,012	$	662,503	$	—	$	1,848,515
Commercial	791,898		251,740		—		1,043,638
Industrial	101,567		18,592		—		120,159
Other	26,644		5,227		—		31,871
Wholesale	66,345		—		—		66,345
Transmission and transportation	38,073		19,555		—		57,628
Miscellaneous	25,007		3,107		26,121		54,235
Total revenue from contracts with customers	$	2,235,546	$	960,724	$	26,121	$	3,222,391
Total other revenue1	83,870		20,189		—		104,059
Total operating revenue	$	2,319,416	$	980,913	$	26,121	$	3,326,450

_____________

1 Total other revenue includes revenues from derivatives, PTC deferral revenue and alternative revenue programs that are not considered revenues from contracts with customers.

Revenue at PSE is recognized when performance obligations under the terms of a contract or tariff with our customers are satisfied. Performance obligations are satisfied generally through performance of 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 transferring goods and 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 unbilled retail revenue. The 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 a 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 intra-month basis.

Electric Transmission and Natural Gas Transportation

Transmission and transportation tariff contracts include the 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.

Biogas

Biogas is a renewable natural gas fuel that PSE purchases and sells along with the renewable green attributes derived from the renewable natural gas. Biogas contracts include the performance obligations of biogas and renewable credit delivery upon PSE receiving produced biogas from its supplier. Transfer of control and 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 performance obligation of 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 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.

PWI Land Sale

On August 13, 2021, Puget Western, Inc. (PWI) a wholly-owned subsidiary of PSE sold a parcel of land that resulted in $23.2 million of other revenue from contracts with customers. PWI purchases, develops, and sells land holdings throughout PSE’s service territory; thus, the sale was reported as non-utility revenue of $23.2 million and non-utility expense of $12.9 million.

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 selling LNG over a 10-year delivery period beginning 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 allocated to the remaining performance obligations which 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:


Puget Energy
(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 has elected the 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 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 separate performance obligation, future volumes are wholly unsatisfied.

(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, ~~2021,~~2022, and ~~2020,~~2021, are included the following tables:


Puget Sound Energy	Puget Sound Energy	Remaining Amortization Period	December 31,		Puget Sound Energy		Remaining Amortization Period			December 31,
(Dollars in Thousands)	(Dollars in Thousands)		2021		2020				Remaining Amortization Period		2022		2021
Environmental remediation	Environmental remediation	(a)	$	127,977	$	102,647		Environmental remediation			$	141,893	$	127,977
Storm damage costs electric	Storm damage costs electric	4 years	127,789		108,491			Storm damage costs electric	3 to 5 years		127,524		127,789
PCA mechanism	PCA mechanism	N/A	79,546		82,801			PCA mechanism	N/A		112,207		79,546
Decoupling deferrals and interest (b)		Less than 2 years	79,125		88,504
Chelan PUD contract initiation	Chelan PUD contract initiation	9.8 years	69,699		76,787			Chelan PUD contract initiation	8.8 years		62,611		69,699
Deferred Washington Commission AFUDC	Deferred Washington Commission AFUDC	30 years	62,244		59,763			Deferred Washington Commission AFUDC	30 years		61,463		62,244
Baker Dam licensing operating and maintenance costs								Baker Dam licensing operating and maintenance costs	(b)		55,049		54,525
Get to zero depreciation expense deferral (c)								Get to zero depreciation expense deferral (c)	1 to 4 years		49,605		50,220
Lower Snake River								Lower Snake River	14.4 years		48,536		53,757
Decoupling deferrals and interest (d)								Decoupling deferrals and interest (d)	Less than 2 years		36,773		79,125
Unamortized loss on reacquired debt								Unamortized loss on reacquired debt	1 to 45 years		33,732		35,805
Advanced metering infrastructure								Advanced metering infrastructure	3 years		30,431		23,037
Washington Commission LNG								Washington Commission LNG	N/A		25,188		1,764
PGA receivable	PGA receivable	2 years	57,935		87,655			PGA receivable	2 years		—		57,935
Baker Dam licensing operating and maintenance costs		(c)	54,525		54,354
Lower Snake River		15.4 years	53,757		58,442
Get to zero depreciation expense deferral		N/A	50,220		53,236
Unamortized loss on reacquired debt		1 to 46 years	35,805		37,991
Generation plant major maintenance, excluding Colstrip								Generation plant major maintenance, excluding Colstrip	3 to 7 years		20,374		12,094
Low Income Program Costs								Low Income Program Costs	N/A		17,370		21,755
Property tax tracker	Property tax tracker	Less than 2 years	25,896		24,860			Property tax tracker	Less than 2 years		12,398		25,896
Advanced metering infrastructure		(a)	23,037		22,652
Low Income Program Costs		N/A	21,755		—
Private Letter Ruling EDIT		1 year	18,850		—
Generation plant major maintenance, excluding Colstrip		1 to 8 years	12,094		10,494
Energy conservation costs								Energy conservation costs	(a)		10,296		3,573
Washington Commission electric vehicle (c)								Washington Commission electric vehicle (c)	4 years		7,796		6,109
Regulatory filing fee deferral								Regulatory filing fee deferral	N/A		7,559		—
Snoqualmie licensing operating and maintenance costs	Snoqualmie licensing operating and maintenance costs	(c)	7,446		7,435			Snoqualmie licensing operating and maintenance costs	(b)		7,445		7,446
Washington Commission COVID-19								Washington Commission COVID-19	N/A		7,051		3,657
Water heater rental property loss								Water heater rental property loss	N/A		5,725		5,725
Mint Farm ownership and operating costs	Mint Farm ownership and operating costs	3.3 years	6,318		8,318			Mint Farm ownership and operating costs	2.3 years		4,317		6,318
Washington Commission electric vehicle		N/A	6,109		3,641
Water heater rental property loss		N/A	5,725		6,973
Colstrip major maintenance		(d)	4,035		4,335
Washington Commission COVID-19		N/A	3,657		—
Energy conservation costs		(a)	3,573		8,009
Colstrip major maintenance (c)								Colstrip major maintenance (c)	3 years		4,035		4,035
Various other regulatory assets	Various other regulatory assets	(a)	15,422		10,719			Various other regulatory assets	(a)		7,060		32,508
Total PSE regulatory assets	Total PSE regulatory assets		$	952,539	$	918,107		Total PSE regulatory assets			$	896,438	$	952,539
Deferred income taxes (e)	Deferred income taxes (e)	N/A	(866,541)		(953,987)			Deferred income taxes (e)	N/A		(811,724)		(866,541)
Cost of removal	Cost of removal	(f)	(563,129)		(508,707)			Cost of removal	(f)		(639,320)		(563,129)
PGA unrealized gain								PGA unrealized gain	N/A		(287,725)		(60,728)
Repurposed production tax credits	Repurposed production tax credits	N/A	(134,270)		(79,581)			Repurposed production tax credits	N/A		(133,855)		(134,270)
PGA unrealized gain		N/A	(60,728)		(4,925)
Decoupling liability	Decoupling liability	Less than 2 years	(36,506)		(16,448)			Decoupling liability	Less than 2 years		(63,206)		(36,506)
Treasury grants		2 years	(22,476)		(43,164)
Green direct	Green direct	N/A	(13,194)		(14,313)			Green direct	N/A		(11,837)		(13,194)
Gain on Sale Shuffleton		N/A	(4,892)		(11,131)
Production tax credits		(g)	—		(47,094)
Refund on counterparty settlement								Refund on counterparty settlement	1 year		(4,353)		—
PGA liability								PGA liability	2 years		(3,536)		—
Various other regulatory liabilities	Various other regulatory liabilities	(a)	(7,725)		(5,871)			Various other regulatory liabilities	(a)		(5,583)		(35,093)
Total PSE regulatory liabilities	Total PSE regulatory liabilities		(1,709,461)		(1,685,221)			Total PSE regulatory liabilities			(1,961,139)		(1,709,461)
PSE net regulatory assets (liabilities)	PSE net regulatory assets (liabilities)		$	(756,922)	$	(767,114)		PSE net regulatory assets (liabilities)			$	(1,064,701)	$	(756,922)

__________________

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

(b)~~Decoupling deferrals and interest includes a 24 month GAAP reserve of $3.0 million and $8.0 million for December 31, 2021 and 2020, respectively.~~

~~(c)~~The FERC license requires PSE to incur various O&M expenses over the life of the 40 year and 50 year license for Snoqualmie and Baker, respectively. The regulatory asset represents the net present value of future expenditures and will be offset by actual costs incurred.

~~(d)~~(c)Amortization ~~to be determined~~period approved in 2022 GRC, beginning January 2023.

(d)Decoupling deferrals and interest includes a ~~future rate filing.~~24 month GAAP reserve of zero and $3.0 million for December 31, 2022 and 2021, respectively.

(e)For additional information, see Note 14,"Income Taxes" to the consolidated financial statements included in Item 8 of this report.

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

~~(g)Amortize as PTCs are utilized on PSE's tax return.~~.

96100


Puget Energy	Puget Energy	Remaining Amortization Period	December 31,				Puget Energy	Remaining Amortization Period	December 31,
(Dollars in Thousands)	(Dollars in Thousands)		2021		2020		(Dollars in Thousands)		2022		2021
Total PSE regulatory assets	Total PSE regulatory assets	(a)	$	952,539	$	918,107	Total PSE regulatory assets	(a)	$	896,438	$	952,539
Puget Energy acquisition adjustments:	Puget Energy acquisition adjustments:						Puget Energy acquisition adjustments:
Regulatory assets related to power contracts	Regulatory assets related to power contracts	4 to 31 years	9,689		11,728		Regulatory assets related to power contracts	3 to 30 years	7,904		9,689

Total Puget Energy regulatory assets	Total Puget Energy regulatory assets		962,228		929,835		Total Puget Energy regulatory assets		904,342		962,228
Total PSE regulatory liabilities	Total PSE regulatory liabilities	(a)	(1,709,461)		(1,685,221)		Total PSE regulatory liabilities	(a)	(1,961,139)		(1,709,461)
Puget Energy acquisition adjustments:	Puget Energy acquisition adjustments:						Puget Energy acquisition adjustments:
Deferred income taxes	Deferred income taxes		565		713		Deferred income taxes		563		565
Regulatory liabilities related to power contracts	Regulatory liabilities related to power contracts	4 to 31 years	(80,934)		(95,774)		Regulatory liabilities related to power contracts	3 to 30 years	(63,660)		(80,934)
Various other regulatory liabilities	Various other regulatory liabilities	Varies	(1,264)		(1,264)		Various other regulatory liabilities	Varies	(1,264)		(1,264)
Total Puget Energy regulatory liabilities	Total Puget Energy regulatory liabilities		(1,791,094)		(1,781,546)		Total Puget Energy regulatory liabilities		(2,025,500)		(1,791,094)
Puget Energy net regulatory asset (liabilities)	Puget Energy net regulatory asset (liabilities)		$	(828,866)	$	(851,711)	Puget Energy net regulatory asset (liabilities)		$	(1,121,158)	$	(828,866)

____________________

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

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

In accordance with guidance provided by ASC 410, “Asset Retirement and Environmental Obligations (ARO),” PSE reclassified from accumulated depreciation to a regulatory liability $639.3 million and $563.1 million in 2022 and ~~$508.7 million in~~ 2021, ~~and 2020,~~ respectively, for the cost of removal of utility plant. These amounts are collected from PSE’s customers through depreciation rates.

General Rate Case Filing

PSE filed a general rate case (GRC) which includes a ~~three year~~three-year multiyear rate plan with the Washington Commission on January 31, 2022, requesting an overall increase in electric and natural gas rates of 13.6% and 13.0% respectively in 2023; 2.5% and 2.3%, respectively in 2024; and 1.2% and 1.8%, respectively, in 2025.PSE requested a return on equity of 9.9% in all three rate years.PSE requested an overall rate of return of 7.39% in 2023; 7.44% in 2024; and 7.49% in 2025.The filing requests recovery of forecasted plant additions through 2022 as required by ~~RCW~~Revised Code of Washington (RCW) 80.28.425 as well as forecasted plant additions through 2025, the final year of the multiyear rate plan. ~~The next phase~~

On January 6, 2023, the Washington Commission approved PSE’s natural gas rates in its compliance filing with an overall increase of $70.8 million or 6.4% in 2023 and $19.5 million or 1.65% in 2024, with an effective date of January 7, 2023. On January 10, 2023, the Washington Commission approved PSE’s electric rates in its compliance filing ~~will be to establish a procedural calendar for the adjudication~~with an overall increase of ~~the case.~~$247.0 million or 10.75% in 2023 and $33.1 million or 1.33% in 2024 with an effective date of January 11, 2023.

PSE filed 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. On July 8, 2020, the Washington Commission issued its order on PSE’s 2019 GRC. The ruling provided for a weighted cost of capital of 7.39% or 6.8% 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 PGA deferral to mitigate the impact of the rate increase in response to the economic uncertainty created by the COVID-19 pandemic. This reduced the electric revenue increase to approximately $0.9 million, or ~~0.05%~~0.1% and the natural gas increase to $1.3 million, or ~~0.15%~~0.2% and became effective October 15, 2020 and October 1, 2020, respectively.

~~On August 6, 2020,~~

101

In July 2021, PSE filed a petition for judicial review with the Superior Court of the State of Washington for King County 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 Internal Revenue Service (IRS) normalization and consistency rules.

~~PSE reviewed the original Washington Commission order including the ramifications of certain tax issues and requested~~received a Private Letter Ruling (PLR) ~~with~~from the IRS ~~regarding this matter. On October 7, 2020, PSE,~~which concluded that in the ~~Washington Commission and interveners agreed to dismiss the petition for judicial review. The agreement was based on a commitment from the Washington Commission that if the IRS ruling finds that~~2019 GRC the Washington Commission’s methodology for reversing plant-related excess deferred income taxes ~~is impermissible, the Washington Commission would open a proceeding to review and enact the changes~~

~~required by the IRS ruling. There~~ was ~~approximately $25.6 million in annual revenue requirement related to the 2019 GRC, which PSE requested it be allowed to track and recover.~~

~~On July 30, 2021, the IRS issued a PLR to PSE which concludes that the Washington Commission’s methodology for reversing plant-related excess deferred income taxes is~~ an impermissible methodology under the IRS normalization and consistency rules. The PLR ~~requires~~required adjustments to PSE's rates to bring PSE back into compliance with IRS rules. ~~Accordingly, on~~In September ~~28,~~ 2021, the Washington Commission ~~issued an~~amended its order ~~amending their order previously issued on July 8, 2020, to correct for items which were determined to be impermissible under IRS normalization and consistency rules as detailed~~ in accordance with the PLR. To reflect the impact of the PLR, PSE has recorded a regulatory asset and additional revenues of $24.5 million in its operating results through December 31, 2021, of which $5.6 million was collected from customers. Thus, theThe annualized overall rate impact iswas an increase of $15.8 million, or 0.7%, for electric and $3.1 million, or 0.3%, for natural gas for a total of $18.9 million with rates effective October 1, 2021. This led to ~~an overall~~a combined annualized net increase to electric rates of $77.1 million, or 3.7%, an increase of $17.5 million above the $59.6 million granted in the revised final order. The order also led to ~~an overall~~a combined annualized net increase to natural gas rates of $45.3 million, or 5.9%, an increase of $2.4 million above the $42.9 million granted in the revised final order. The Washington Commission maintained adjustments that 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 $48.3 million, or 2.3%, and the natural gas increase to $4.9 million, or 0.6%.

Power Cost Only Rate Case

On March 2, 2021, several of the parties to the PCORC reached ~~an unopposed~~a multiparty settlement in ~~principle.~~principle, which was unopposed. The settlement resulted in an estimated revenue increase of $65.3 million or 3.1%. A term of the settlement requires PSE to include in its next GRC (or another proceeding in 2022) the issue of whether the PCORC should continue, and further prohibits PSE from filing another PCORC before this issue is litigated. On June 1, 2021, the Washington Commission issued its Final Order approving and adopting the settlement and authorizing and requiring a power cost update through a compliance filing. On June 17, 2021, PSE filed a compliance filing with the Washington Commission with a revenue increase of $70.9 million or 3.3% due to the update on power costs with rates effective July 1, 2021. Per the 2022 GRC Final Order in Docket No. UE-220066, PCORC rates were set to zero as of January 11, 2023 and PSE agreed not to file a PCORC during 2023 and 2024, the two-year rate plan agreed to in the GRC settlement.

Revenue Decoupling ~~Filings~~Adjustment Mechanism

On July 8, 2020, the Washington Commission issued the final order in Dockets No. UE-190529 and UG-190530, which instructed PSE to extend the collection of amortization balances for electric decoupling delivery and fixed power cost sections originally filed through the annual May 2020 decoupling filing.The extension requires PSE to move amortization balances for electric decoupling as of August 31, 2020 to be collected from customers for a two-year period, instead of the originally approved one-year period.Additionally, through approving the electric cost of service, the final order approved the re-allocation of decoupling balances from Schedule 40 to the remaining electric decoupling groups.

On December 23, 2020, the Washington Commission approved PSE’s filing to update Schedule 142 decoupling amortization rates, with an effective date of January 1, 2021, by zeroing out rates still effective past October 15, 2020 on tariff sheet Schedule 142-H, which was replaced by rates on tariff sheet Schedule 142-I effective October 15, 2020.PSE included a true up of the over-collection amounts for the period of October 15, 2020 through December 31, 2020 in PSE’s annual May 2021 decoupling filing.

On June 1, 2021, the Washington Commission approved the multi-party settlement agreement which was filed within PSE’s PCORC filing. As part of this settlement agreement, the electric annual fixed power cost allowed revenue was updated to reflect changes in the approved revenue requirement. The changes took effect on July 1, 2021.

102

analysis indicated that ~~$3.0 million of~~ electric ~~deferred revenue will not be collected within 24 months of the annual period; therefore a reserve adjustment was booked to 2021 electric decoupling revenue. Natural~~and natural gas deferred revenue will be collected within 24 months of the annual period; therefore no reserve adjustment was booked to ~~2021~~2022 electric and natural gas decoupling revenue. This compares to ~~$8.0~~$3.0 million of electric deferred revenue not being collected within 24 months of the annual period in ~~2020;~~

2021; therefore, a reserve adjustment was booked to ~~2020~~2021 electric decoupling ~~revenue and natural~~revenue. Natural gas deferred revenue would be collected within 24 months of the annual period; therefore no reserve adjustment was booked to ~~2020~~2021 natural gas decoupling revenue.

Power Cost Adjustment Mechanism

Effective January 1, 2017, the following graduated 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

For the year ended December 31, ~~2021,~~2022, in its PCA mechanism, PSE under recovered its allowable costs by ~~$68.0~~$110.1 million of which ~~$36.7~~$74.6 million was apportioned to customers and ~~$1.7~~$1.5 million of interest was accrued on the deferred customer balance. This compares to an under recovery of allowable costs of ~~$76.1~~$68.0 million, for the year ended December 31, ~~2020,~~2021, of which ~~$44.0~~$36.7 million was apportioned to customers and accrued ~~$2.0~~$1.7 million of interest on the total deferred customer balance. ~~The under recovery in 2020 was included in the Power Cost Adjustment Clause filing, mentioned below.~~

Power Cost Adjustment Clause ~~Filing~~

On July 8, 2020, the Washington Commission issued the final order in Dockets No. UE-190529 and UG-190530, which instructed PSE to remove Schedule 95 collection on decoupling allowed rates for ~~Microsoft~~ Special Contracts, which ~~will be~~are included in allowed rates under the Decoupling Schedule 142 effective October 15, 2020.

PSE exceeded the $20.0 million cumulative deferral balance in its PCA mechanism in 2020. The surcharging of deferrals can be triggered by the Company when the balance in the deferral account is a credit of $20.0 million or more. During 2020, actual power costs were higher than baseline power ~~costs,~~costs; thereby, creating an under-recovery of $76.1 million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $32.1 million of the under-recovered amount, and customers were responsible for the remaining $44.0 million, or $46.0 million including interest. PSE filed to recover the deferred balance in Docket No. UE-210300, ~~effective December 1, 2021,~~ and the Washington Commission allowed the recovery effective December 1, 2021.

Additionally, PSE exceeded the $20.0 million cumulative deferral balance in its PCA mechanism in 2021. During 2021, actual power costs were higher than baseline power costs, thereby creating an under-recovery of $68.0 million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $31.3 million of the under-recovered amount, and customers were responsible for the remaining $36.7 million, or $38.4 million including interest. On October 27, 2022, the Washington Commission approved ~~PSE’s request on September~~PSE's 2021 PCA report that proposes to recover the deferred balance for 2021 PCA period by keeping the current rates and allowing recovery from January 1, 2023 through November 30, ~~2021.~~2023.

Purchased Gas Adjustment Mechanism

On October 28, 2021, the Washington Commission approved PSE's request for ~~November 2021~~ PGA rates in Docket No. UG-210721, effective November 1, 2021. As part of that filing, PSE requested an annual revenue increase of $59.1 million; where PGA rates, under Schedule 101, increase annual revenue by $80.6 million, and the tracker rates under Schedule 106, decrease annual revenue by $21.5 million. Those annual 2021 PGA rate increases ~~will be~~were set in addition to continuing the collection on the remaining balance of $69.4 million under Supplemental Schedule ~~106B.~~

106B, which were set, in effect, through September 30, 2023 per the 2019 GRC.

99103

The following table presents the PGA mechanism balances and activity at December 31, ~~2021~~2022 and December 31, ~~2020:~~2021:


Puget Sound Energy
Puget Energy and Puget Sound Energy						Puget Energy and Puget Sound Energy
(Dollars in Thousands)	(Dollars in Thousands)	At December 31,		At December 31,		(Dollars in Thousands)	At December 31,		At December 31,
PGA receivable balance and activity	PGA receivable balance and activity	2021		2020		PGA receivable balance and activity	2022		2021
PGA receivable beginning balance	PGA receivable beginning balance	$	87,655	$	132,766	PGA receivable beginning balance	$	57,935	$	87,655
Actual natural gas costs	Actual natural gas costs	364,775		314,792		Actual natural gas costs	457,950		364,775
Allowed PGA recovery	Allowed PGA recovery	(396,236)		(363,886)		Allowed PGA recovery	(496,879)		(396,236)
Interest	Interest	1,741		3,983		Interest	1,674		1,741
PGA receivable ending balance		$	57,935	$	87,655
Refund from counterparty settlement						Refund from counterparty settlement	(24,216)		—
PGA (liability)/receivable ending balance						PGA (liability)/receivable ending balance	$	(3,536)	$	57,935

Get to Zero Depreciation Deferral

On April 10, 2019, PSE filed an accounting petition with the Washington Commission, requesting authorization to defer depreciation expense associated with Get To Zero (GTZ) projects that were placed in service after June 30, 2018. The GTZ project consists of a number of short-lived technology upgrades. The depreciation expense associated with the GTZ projects with lives of 10 years or less that were placed in service after June 30, 2018, were deferred beginning May 1 per the petition request. For the year ended December 31, ~~2021~~2022 and December 31, ~~2020,~~2021, PSE deferred ~~$6.6~~$11.8 million and ~~$2.8~~$6.6 million of depreciation expense for GTZ, respectively. In addition to the deferral of depreciation expense, PSE had also requested to defer carrying charges on the GTZ deferral, to be calculated utilizing the ~~Company’s currently authorized after-tax~~FERC quarterly rate of ~~return, or 6.89%.~~return. The ~~ruling authorized PSE to amortize deferred GTZ expenses as proposed in the original~~2022 GRC filing. The ruling also allows continued deferral of the depreciation expense associated with GTZ investments not already approved for recovery with a book life of 10 years or less, through PSE's next GRC. Finally, the final order ~~set the rate at which PSE could defer~~authorized recovery of all remaining GTZ depreciation and ~~recover~~ carrying ~~charges from PSE’s authorized rate~~charge balances as of ~~return to the quarterly interest rate established by the FERC.~~December 2022. Finally, all GTZ deferrals ended as of December 2022.

Crisis Affected Customer Assistance Program

On April 6, 2020, PSE filed with the Washington Commission revisions to its currently effective ~~Tariff WN U-60.~~electric and natural gas service tariffs. The purpose of this filing iswas to incorporate into PSE’s low-income tariff a new temporary bill assistance program, Crisis Affected Customer Assistance Program ~~(CACAP)~~(CACAP-1) (Dockets No. UE-200331 and UG-200332), to mitigate the economic impact of the COVID-19 pandemic on PSE’s customers. ~~CACAP would allow~~CACAP-1 allowed PSE customers facing financial hardship due to COVID-19 to receive up to $1,000 in bill assistance. The program ~~puts to immediate use~~made available $11.0 million in unspent low income funds from prior years, therefore resulting in no rate impact, and ~~supplements~~supplemented other forms of financial assistance. The program does not require an increase to rates and is 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 onCACAP-1 ran from 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.~~September 30, 2020.

On October 15, 2021, PSE submitted for the Washington Commission’s review and approval a Supplemental CACAP (Dockets No UE-210792 and UG-210793) filing to continue assistance for PSE customers facing financial hardship due to COVID-19. The Washington Commission approved the Supplemental CACAP ~~would utilize~~program to be effective on November 15, 2021. The Supplemental CACAP utilized carry-over funds not expended in any prior years under PSE’s Schedule 129 Home Energy Lifeline ~~Program. The Supplemental CACAP benefits,~~Program (HELP), with a combined total budget of $34.5 million for both electric and natural gas residential customers ~~would be a combined total of $34.5 million and be capped~~(capped at $23.7 million and $10.8 million, respectively. Additionally, the Supplemental CACAP filing proposed to revise the CACAP-2 total program budget to $27.7 million for electric customers (instead of $20.0 million for electric customers and $7.7 million for natural gas customers)respectively). ~~The Supplemental CACAP budget for natural gas customers of $10.8 million would be used for both the CACAP-2 program and the Supplemental CACAP program benefits.~~

~~100~~104

~~approved by the Washington Commission at the November 12, 2021 open meeting. Both CACAP-2 and Supplemental CACAP would be administered until funds are exhausted.~~

Storm Loss Deferral Mechanism

The Washington Commission has defined deferrable weather-related events and provided that costs in excess of the annual cost threshold may be deferred for qualifying damage costs that meet the modified Institute of Electrical and Electronics Engineers outage criteria for system average interruption duration index. For the year ended December 31, ~~2021,~~2022, PSE incurred ~~$51.4~~$32.2 million in weather-related electric transmission and distribution system restoration costs, of which the Company deferred $21.4 million and $0.2 million as regulatory assets related to storms that occurred in 2022 and 2021, respectively. This compares to $51.4 million incurred in weather-related electric transmission and distribution system restoration costs for the year ended December 31, 2021, of which the Company deferred $40.9 million and $0.2 million as regulatory assets related to storms that occurred in 2021 and 2020, respectively. This compares to $21.8 million incurred in weather-related electric transmission and distribution system restoration costs for the year ended December 31, 2020, of which the Company deferred $11.2 million as regulatory assets related to storms that occurred in 2020. Under the 2017 GRC Order, the storm loss deferral mechanism approved the following: (i) the cumulative annual cost threshold for deferral of storms under the mechanism at $10.0 million; and (ii) qualifying events where the total qualifying cost is less than $0.5 million will not qualify for deferral and these costs will also not count toward the $10.0 million annual cost threshold.

Environmental Remediation

The Company is subject to environmental laws and regulations by the federal, state and local authorities and is required to undertake certain environmental investigative and remedial efforts as a result of these laws and regulations. The Company has been named by the Environmental Protection Agency (EPA), the Washington State Department of Ecology and/or other third parties as potentially responsible at several contaminated sites and former manufactured gas plant sites. In accordance with the guidance of ASC 450, “Contingencies,” the Company reviews its estimated future obligations and will record adjustments, if any, on a quarterly basis. Management believes it is probable and reasonably estimable that the impact of the potential outcomes of disputes with certain property owners and other potentially responsible parties will result in environmental remediation costs of ~~$69.0~~$84.4 million for natural gas and ~~$48.6~~$48.3 million for electric. The Company believes a significant portion of its past and future environmental remediation costs are recoverable from insurance companies, from third parties or from customers under a Washington Commission order. The Company is also subject to cost-sharing agreements with third parties regarding environmental remediation projects in Seattle, Tacoma, Everett, and Bellingham, Washington.

As of December 31, ~~2021,~~2022, the Company’s share of future remediation costs is estimated to be approximately ~~$62.1~~$61.5 million. The Company's deferred electric environmental costs are ~~$52.2~~$51.5 million and ~~$51.8~~$52.2 million at December 31, ~~2021~~2022 and ~~2020,~~2021, respectively, net of insurance proceeds. The Company's deferred natural gas environmental costs are ~~$75.8~~$90.4 million and ~~$50.9~~$75.8 million at December 31, ~~2021~~2022 and ~~2020,~~2021, respectively, net of insurance proceeds.

(5) Dividend Payment Restrictions

The payment of dividends by PSE to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE’s electric and natural gas mortgage indentures. At December 31, ~~2021,~~2022, approximately ~~$1.2~~$1.4 billion of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant.

Pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission. Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or, if its credit ratings are below investment grade, PSE’s ratio of earnings before interest, tax, depreciation and amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3.0 to 1.0. The common equity ratio, calculated on a regulatory basis, was ~~47.5%~~48.1% at December 31, ~~2021,~~2022, and the EBITDA to interest expense was ~~5.5~~5.0 to 1.0 for the twelve months ended December 31, ~~2021.~~2022.

Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission. Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than 2.0 to 1.0. Puget Energy's EBITDA to interest expense was ~~3.9~~3.7 to 1.0 for the twelve months ended December 31, ~~2021.~~

~~101~~

2022.

At December 31, ~~2021,~~2022, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

105

(6) Utility Plant

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


			Puget Energy				Puget Sound Energy						Puget Energy				Puget Sound Energy
Utility Plant	Utility Plant	Estimated Useful Life	December 31,				December 31,				Utility Plant	Estimated Useful Life1	December 31,				December 31,
(Dollars in Thousands)	(Dollars in Thousands)	(Years)	2021		2020		2021		2020		(Dollars in Thousands)	(Years)	2022		2021		2022		2021
Distribution plant	Distribution plant	20-65	$	7,488,629	$	7,028,731	$	9,026,042	$	8,592,720	Distribution plant	7-65	$	7,886,665	$	7,488,629	$	9,406,017	$	9,026,042
Production plant	Production plant	12-90	3,147,987		3,096,092		3,815,599		3,767,014		Production plant	3-90	3,131,578		3,147,987		3,780,910		3,815,599
Transmission plant	Transmission plant	43-75	1,556,666		1,494,781		1,663,559		1,601,731		Transmission plant	44-75	1,576,916		1,556,666		1,683,737		1,663,559
General plant	General plant	5-75	746,758		697,501		773,662		726,327		General plant	5-75	735,298		746,758		760,094		773,662
Intangible plant (including capitalized software)1		3-50	797,691		779,767		788,240		770,317
Intangible plant (including capitalized software)2											Intangible plant (including capitalized software)2	3-50	755,430		797,691		745,973		788,240
Plant acquisition adjustment	Plant acquisition adjustment	N/A	242,826		242,826		282,792		282,792		Plant acquisition adjustment	N/A	242,826		242,826		282,792		282,792
Underground storage	Underground storage	25-60	43,391		39,498		56,820		52,927		Underground storage	25-60	45,305		43,391		58,716		56,820
Liquefied natural gas storage	Liquefied natural gas storage	25-60	12,628		12,628		14,498		14,498		Liquefied natural gas storage	25-50	12,628		12,628		14,498		14,498
Plant held for future use	Plant held for future use	N/A	46,020		45,929		46,172		46,081		Plant held for future use	N/A	46,079		46,020		46,232		46,172
Recoverable Cushion Gas	Recoverable Cushion Gas	N/A	8,655		8,655		8,655		8,655		Recoverable Cushion Gas	N/A	8,784		8,655		8,784		8,655
Plant not classified	Plant not classified	N/A	316,933		384,794		316,933		384,794		Plant not classified	N/A	723,383		316,933		723,383		316,933
Finance leases, net of accumulated amortization2		N/A	105,020		881		105,020		881
Finance leases, net of accumulated amortization3											Finance leases, net of accumulated amortization3	N/A	99,967		105,020		99,967		105,020
Less: accumulated provision for depreciation	Less: accumulated provision for depreciation		(4,031,458)		(3,671,094)		(6,416,246)		(6,087,748)		Less: accumulated provision for depreciation		(4,341,789)		(4,031,458)		(6,688,033)		(6,416,246)
Subtotal	Subtotal		$	10,481,746	$	10,160,989	$	10,481,746	$	10,160,989	Subtotal		$	10,923,070	$	10,481,746	$	10,923,070	$	10,481,746
Construction work in progress	Construction work in progress		870,204		712,204		870,204		712,204		Construction work in progress		861,801		870,204		861,801		870,204
Net utility plant	Net utility plant		$	11,351,950	$	10,873,193	$	11,351,950	$	10,873,193	Net utility plant		$	11,784,871	$	11,351,950	$	11,784,871	$	11,351,950

_______________________

1.Estimated Useful Life years have been approved in the 2022 GRC.

2.Intangible assets include capitalized software and franchise agreements with useful lives ranging between 3-10 years and 10-50 years, respectively.

2.3.At December 31, ~~2021,~~2022, and ~~2020,~~2021, accumulated amortization of finance leases at Puget Energy and PSE was ~~$2.6~~$7.3 million and ~~$1.6~~$2.6 million, respectively.

Jointly owned generating plant service costs are included in utility plant service cost at the Company's ownership share. The Company provides financing for its ownership interest in the jointly owned utility plants. The following tables indicate the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, ~~2021.~~2022. These amounts are also included in the Utility Plant table ~~above.~~above, with the exception of Puget Energy's portion of the Tacoma LNG facility, which is reported in the Puget Energy "Other property and investments" financial statement line item. The Company's share of fuel costs and operating expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income.


Puget Energy	Puget Energy									Puget Energy
Jointly Owned Generating Plants (Dollars in Thousands)	Jointly Owned Generating Plants (Dollars in Thousands)	Energy Source (Fuel)	Company’s Ownership Share	Plant in Service at Cost		Construction Work in Progress		Accumulated Depreciation		Jointly Owned Generating Plants (Dollars in Thousands)	Energy Source (Fuel)	Company’s Ownership Share	Plant in Service at Cost		Construction Work in Progress		Accumulated Depreciation

Colstrip Units 3 & 4	Colstrip Units 3 & 4	Coal	25.00%	$	339,073	$	—	$	(153,950)	Colstrip Units 3 & 4	Coal	25.00%	$	321,767	$	—	$	(176,847)
Frederickson 1	Frederickson 1	Natural Gas	49.85	63,210		—		(18,215)		Frederickson 1	Natural Gas	49.85	63,348		—		(21,894)
Jackson Prairie	Jackson Prairie	Natural Gas	33.34	42,736		471		(10,867)		Jackson Prairie	Natural Gas	33.34	44,708		837		(12,178)
Tacoma LNG	Tacoma LNG	Natural Gas	various	—		484,299		—		Tacoma LNG	Natural Gas	various	494,795		2,936		(10,922)

~~102~~106


Puget Sound Energy	Puget Sound Energy									Puget Sound Energy
Jointly Owned Generating Plants (Dollars in Thousands)	Jointly Owned Generating Plants (Dollars in Thousands)	Energy Source (Fuel)	Company’s Ownership Share	Plant in Service at Cost		Construction Work in Progress		Accumulated Depreciation		Jointly Owned Generating Plants (Dollars in Thousands)	Energy Source (Fuel)	Company’s Ownership Share	Plant in Service at Cost		Construction Work in Progress		Accumulated Depreciation

Colstrip Units 3 & 4	Colstrip Units 3 & 4	Coal	25.00 %	$	597,009	$	—	$	(411,887)	Colstrip Units 3 & 4	Coal	25.00 %	$	579,019	$	—	$	(434,099)
Frederickson 1	Frederickson 1	Natural Gas	49.85	69,278		—		(24,283)		Frederickson 1	Natural Gas	49.85	69,415		—		(27,962)
Jackson Prairie	Jackson Prairie	Natural Gas	33.34	56,820		471		(24,952)		Jackson Prairie	Natural Gas	33.34	58,716		837		(26,186)
Tacoma LNG	Tacoma LNG	Natural Gas	various	—		239,566		—		Tacoma LNG	Natural Gas	various	245,690		503		(5,052)

In June 2019, Talen, the plant operator of Colstrip Units 1 and 2, announced a plan to shut down as of December 31, 2019. The Company retired Colstrip 1&2 from Utility Plant and transferred the unrecovered plant amount of $126.5 million to regulatory assets, offset by depreciation as included in base rates until the 2019 GRC became effective in October 2020. Consistent with the GRC settlement in 2017, monetization of the PTCs will fund the following: (i) Colstrip Community Transition Fund, (ii) unrecovered Colstrip plant and (iii) incurred decommissioning and remediation costs for Colstrip. At December 31, ~~2021,~~2022, and December 31, ~~2020,~~2021, the unrecovered plant for Colstrip 1&2 was fully offset with PTCs.

On September 2, 2022, PSE and Talen Energy reached an agreement to transfer PSE's ownership interest in Colstrip Units 3 and 4 to Talen Energy on December 31, 2025. Management evaluated Colstrip Units 3 and 4 and determined that the applicable held for sale accounting criteria were not met as of December 31, 2022. As such, Colstrip Units 3 and 4 are classified as Electric Utility Plant on the Company's balance sheet as of December 31, 2022.

Asset Retirement Obligation

The Company has recorded liabilities for steam generation sites, combustion turbine generation sites, wind generation sites, distribution and transmission poles, natural gas mains, liquefied natural gas storage sites, and leased facilities where disposal is governed by ASC 410-20 “Asset Retirement and Environmental Obligations" (ARO). The Company records its ARO liabilities for its electric transmission and distribution poles as well as gas distribution mains aligned with its underlying asset data with future estimates of retirements.

~~On April 17, 2015,~~For the ~~EPA published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (CCR) under the Resource Conservation and Recovery Act, Subtitle D. The CCR rule requires~~twelve months ended December 31, 2022, the Company ~~to perform an extensive study on~~reviewed the ~~effects of coal ash on~~estimated remediation costs at Colstrip and determined no change was warranted for the ~~environment~~Colstrip ARO liability for Colstrip Units 1 and ~~public health. The rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust,~~2 and ~~the catastrophic failure of coal ash surface impoundments.~~

~~The CCR rule~~Colstrip Units 3 and two legal agreements which include a consent decree with the Sierra Club and a settlement agreement with the Sierra Club and the National Wildlife Federation in 2016 made changes to the Company’s Colstrip operations, which were reviewed by the Company and the plant operator in 2015 and 2016. PSE had previously recognized a legal obligation in 2003 under the EPA rules to dispose of coal ash material at Colstrip.

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

4. For the twelve months ended December 31, 2021, the Company reviewed the estimated remediation costs at Colstrip and decreased the Colstrip ARO liability by $1.5 million for Colstrip Units 1 and 2, and $3.1 million for Colstrip Units 3 and 4. The 2021 decrease to Colstrip 1 and 2 is primarily due to remediation plans approved by the Montana Department of Environmental Quality under a 2012 settlement between the plant operator and the state for the remaining sites at Colstrip. The plant operator previously contested the approved plan for Colstrip Units 1 and 2 under the defined process in the settlement with the state and reached a settlement agreement regarding the ability to still present another option under the settlement terms and conditions. The Company had previously recorded these incremental costs in 2020 for remediation work on the older ponds under ASC 410-20 “Asset Retirement and Environmental Obligations" and ASC 410-30 “Environmental Remediation". For the twelve months ended December 31, ~~2020, the Company reviewed the estimated remediation costs at Colstrip~~2022 and increased the Colstrip ARO liability by $29.7 million for Colstrip Units 1 and 2, and $2.0 million for Colstrip Units 3 and 4. The environmental remediation liability for Colstrip Units 1 and 2 increased $39.0 million during the same period. The 2020 increase to these Colstrip related liabilities is primarily due to remediation plans approved by the Montana Department of Environmental Quality under a 2012 settlement between the plant operator and the state for the remaining sites at Colstrip. For the twelve months ended December 31, 2021, ~~and 2020,~~ the Company also recorded relief of ARO and environmental remediation liability of $6.9 million and $13.1 million, ~~and $9.6 million,~~ respectively.

~~103~~

In addition, the Company recorded Tacoma LNG facility ARO liability of ~~$3.8~~$3.9 million and ~~$3.3~~$3.8 million for PSE and ~~$3.7~~$3.8 million and ~~$7.4~~$3.7 million for Puget LNG as of December 31, ~~2021~~2022 and December 31, ~~2020,~~2021, respectively. The ~~2021~~2022 and ~~2020~~2021 increases to the Tacoma LNG facility ARO liabilities are primarily due to continued construction of the plant. In ~~2021,~~2022, the ARO liability associated with the Tacoma LNG facility was fully recorded as construction was essentially complete and commissioning activities are on-going.

107


Puget Energy and Puget Sound Energy	Puget Energy and Puget Sound Energy	December 31,				Puget Energy and Puget Sound Energy	December 31,
(Dollars in Thousands)	(Dollars in Thousands)	2021		2020		(Dollars in Thousands)	2022		2021
Asset retirement obligation at beginning of the period	Asset retirement obligation at beginning of the period	$	216,163	$	181,353	Asset retirement obligation at beginning of the period	$	209,041	$	216,163

Relief of liability	Relief of liability	(13,146)		(9,647)		Relief of liability	(6,867)		(13,146)
Revisions in estimated cash flows	Revisions in estimated cash flows	(46)		38,677		Revisions in estimated cash flows	1,519		(46)
Accretion expense	Accretion expense	6,070		5,780		Accretion expense	5,713		6,070
Asset retirement obligation at end of period1	Asset retirement obligation at end of period1	$	209,041	$	216,163	Asset retirement obligation at end of period1	$	209,406	$	209,041

___________________

1.Asset retirement obligations include ~~$3.7~~$3.8 million and ~~$7.4~~$3.7 million for Puget LNG held only at Puget Energy as of December 31, ~~2021,~~2022, and ~~2020,~~2021, respectively.

The Company has identified the following obligations, as defined by ASC 410, “ARO,” which were not recognized because the liability for these assets cannot be reasonably estimated at December 31, ~~2021:~~2022:

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

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

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

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

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

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

~~104~~108

(7) Long-Term Debt

The following table presents outstanding long-term debt due dates and principal amounts, net of debt discount, issuance and other costs and fair value adjustments as of ~~2021~~2022 and ~~2020:~~2021:


(Dollars in Thousands)	(Dollars in Thousands)			December 31,				(Dollars in Thousands)			December 31,
Series	Series	Type	Due	2021		2020		Series	Type	Due	2022		2021
Puget Sound Energy:	Puget Sound Energy:							Puget Sound Energy:
7.150%	7.150%	First Mortgage Bond	2025	$	15,000	$	15,000	7.150%	First Mortgage Bond	2025	$	15,000	$	15,000
7.200%	7.200%	First Mortgage Bond	2025	2,000		2,000		7.200%	First Mortgage Bond	2025	2,000		2,000
7.020%	7.020%	Senior Secured Note	2027	300,000		300,000		7.020%	Senior Secured Note	2027	300,000		300,000
7.000%	7.000%	Senior Secured Note	2029	100,000		100,000		7.000%	Senior Secured Note	2029	100,000		100,000
3.900%	3.900%	Pollution Control Bond	2031	138,460		138,460		3.900%	Pollution Control Bond	2031	138,460		138,460
4.000%	4.000%	Pollution Control Bond	2031	23,400		23,400		4.000%	Pollution Control Bond	2031	23,400		23,400
5.483%	5.483%	Senior Secured Note	2035	250,000		250,000		5.483%	Senior Secured Note	2035	250,000		250,000
6.724%	6.724%	Senior Secured Note	2036	250,000		250,000		6.724%	Senior Secured Note	2036	250,000		250,000
6.274%	6.274%	Senior Secured Note	2037	300,000		300,000		6.274%	Senior Secured Note	2037	300,000		300,000
5.757%	5.757%	Senior Secured Note	2039	350,000		350,000		5.757%	Senior Secured Note	2039	350,000		350,000
5.795%	5.795%	Senior Secured Note	2040	325,000		325,000		5.795%	Senior Secured Note	2040	325,000		325,000
5.764%	5.764%	Senior Secured Note	2040	250,000		250,000		5.764%	Senior Secured Note	2040	250,000		250,000
4.434%	4.434%	Senior Secured Note	2041	250,000		250,000		4.434%	Senior Secured Note	2041	250,000		250,000
5.638%	5.638%	Senior Secured Note	2041	300,000		300,000		5.638%	Senior Secured Note	2041	300,000		300,000
4.300%	4.300%	Senior Secured Note	2045	425,000		425,000		4.300%	Senior Secured Note	2045	425,000		425,000
4.223%	4.223%	Senior Secured Note	2048	600,000		600,000		4.223%	Senior Secured Note	2048	600,000		600,000
3.250%	3.250%	Senior Secured Note	2049	450,000		450,000		3.250%	Senior Secured Note	2049	450,000		450,000
2.893%	2.893%	Senior Secured Note	2051	450,000		—		2.893%	Senior Secured Note	2051	450,000		450,000
4.700%	4.700%	Senior Secured Note	2051	45,000		45,000		4.700%	Senior Secured Note	2051	45,000		45,000

*	*	Debt discount, issuance cost and other	*	(39,141)		(35,816)		*	Debt discount, issuance cost and other	*	(37,095)		(39,141)
Total PSE long-term debt	Total PSE long-term debt			$	4,784,719	$	4,338,044	Total PSE long-term debt			$	4,786,765	$	4,784,719
Puget Energy:	Puget Energy:							Puget Energy:
*	*	Fair value adjustment of PSE long-term debt	*	$	(156,849)	$	(165,357)	*	Fair value adjustment of PSE long-term debt	*	$	(148,341)	$	(156,849)
*	*	Revolving Credit Agreement	2023	33,300		14,700		*	Revolving Credit Agreement	2027	34,300		33,300
*		Term Loan Agreement1	2022	—		210,000
5.625%		Senior Secured Note2	2022	—		450,000
3.650%	3.650%	Senior Secured Note	2025	400,000		400,000		3.650%	Senior Secured Note	2025	400,000		400,000
2.379%	2.379%	Senior Secured Note	2028	500,000		—		2.379%	Senior Secured Note	2028	500,000		500,000
4.100%	4.100%	Senior Secured Note	2030	650,000		650,000		4.100%	Senior Secured Note	2030	650,000		650,000
4.224%								4.224%	Senior Secured Note	2032	450,000		—
*	*	Debt discount, issuance cost and other	*	(7,404)		(4,947)		*	Debt discount, issuance cost and other	*	(9,351)		(7,404)
Total Puget Energy long-term debt	Total Puget Energy long-term debt			$	6,203,766	$	5,892,440	Total Puget Energy long-term debt			$	6,663,373	$	6,203,766

___________________

*Not Applicable.

1.~~Term loan in the amount of $210.0 million was paid off on June 23, 2021.~~

2.~~5.625% Senior Secured Note in the amount of $450.0 million was classified on the Balance Sheet as current maturities of long-term debt as of July 31, 2021.~~

~~105~~

PSE's senior secured notes will cease to be secured by the pledged first mortgage bonds on the date (the "Substitution Date") that all of the first mortgage bonds issued and outstanding under the electric or natural gas utility mortgage indenture have been retired. As of December 31, ~~2021,~~2022, the latest maturity date of the first mortgage bonds, other than pledged first mortgage bonds, is December 22, 2025. On the Substitution Date, PSE will deliver to the trustee for PSE's senior secured notes substitute pledged first mortgage bonds to be issued under a new mortgage indenture. As a result, as of the Substitution Date PSE's outstanding senior secured notes and any future series of PSE's senior secured notes will be secured by substitute pledged first mortgage bonds.

109

Puget Energy Long-Term Debt

On May 19, 2020, Puget Energy issued $650.0 million of senior secured notes at an interest rate of 4.1%. The notes pay interest semi-annually and are due to mature on June 15, 2030. On May 26, 2020, proceeds from the issuance of the notes were used to pay $150.0 million under our term loan credit facility, pay $31.6 million of our revolving credit facility, and to redeem $450.0 million in principal amount of the 6.5% senior secured notes due December 15, 2020 and to pay related fees and expenses.

On June 18, 2020, Puget Energy redeemed the $450.0 million senior secured notes due December 15, 2020 and paid related fees and expenses for a total redemption price of $463.2 million. Excluding the repayment of the $450.0 million principal amount and $0.3 million of unamortized debt discount and issuance cost, the extinguishment incurred a $13.5 million loss, which includes $0.4 million of accrued interest expense and is reported in the Puget Energy "Interest Expense" line item as of December 31, 2020.

On June 14, 2021, Puget Energy issued $500.0 million of senior secured notes at an interest rate of 2.379%. The notes were issued for a period of 7 years, mature on June 15, 2028, and pay interest semi-annually on June 15 and December 15. Proceeds from the issuance of the notes were invested in short-term money market funds, then used to repay the Company’s $500.0 million 6.0% notes that matured on September 1, 2021.

On June 23, 2021, Puget Energy received an equity contribution from Puget Equico LLC, Puget Energy’s parent company. The proceeds from the equity contribution were used to pay off Puget Energy’s $210.0 million term ~~loan.~~loan on June 23, 2021.

~~At December 31, 2021,~~On March 10, 2022, Puget Energy ~~maintained~~filed an ~~$800.0 million credit facility, of which $33.3 million was drawn and outstanding under the facility.~~

~~Puget Sound Energy Long-Term Debt~~

~~On August 2, 2019, PSE filed a new shelf registration~~S-3 Registration statement under which it may issue up to $1.0 billion aggregate principal amount of senior notes secured by ~~first mortgage bonds.~~Puget Energy's assets. As of the date of this report, ~~$100.0~~$550.0 million was available to be issued. The shelf registration will expire in ~~August~~March 2025.

On March 17, 2022, Puget Energy issued $450.0 million of senior secured notes at an interest rate of 4.224%. The notes mature on March 15, 2032, and pay interest semi-annually on March 15 and September 15 of each year. Proceeds from the issuance of the notes were invested in short-term money market funds, and then used to repay Puget Energy's $450.0 million 5.625% notes that were originally scheduled to mature July 2022.

On April 28, 2022, Puget Energy redeemed the $450.0 million 5.625% senior secured notes due July 2022 and paid related expenses for a total redemption price of $457.2 million, which includes repayment of the $450.0 million principal amount and $7.2 million of accrued interest expense.

At December 31, 2022, Puget Energy maintained an $800.0 million credit facility. As of December 31, 2022, $118.6 million was drawn and outstanding under the facility, of which $34.3 million was classified as long-term debt and $84.3 million was classified as short-term debt.

Puget Sound Energy Long-Term Debt

On September 15, 2021, PSE issued $450.0 million of senior secured notes at an interest rate of 2.893%. The notes were issued for a period of 30 years, mature on September 15, 2051, and pay interest semi-annually on March 15 and September 15 of each year. The proceeds from the issuance will be used for repayment of commercial paper as well as general corporate purposes.

Long-Term Debt Maturities

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


(Dollars in Thousands)	(Dollars in Thousands)	2022		2023		2024		2025		2026		Thereafter		Total		(Dollars in Thousands)	2023		2024		2025		2026		2027		Thereafter		Total
Maturities of:	Maturities of:															Maturities of:
PSE	PSE	$	—	$	—	$	—	$	17,000	$	—	$	4,806,860	$	4,823,860	PSE	$	—	$	—	$	17,000	$	—	$	300,000	$	4,506,860	$	4,823,860
Puget Energy	Puget Energy	450,000		33,300		—		400,000		—		1,150,000		2,033,300		Puget Energy	—		—		400,000		—		$	34,300	1,600,000		2,034,300
Total long-term debt	Total long-term debt	$	450,000	$	33,300	$	—	$	417,000	$	—	$	5,956,860	$	6,857,160	Total long-term debt	$	—	$	—	$	417,000	$	—	$	334,300	$	6,106,860	$	6,858,160

~~106~~

(8) Liquidity Facilities and Other Financing Arrangements

As of December 31, ~~2021,~~2022, and ~~2020,~~2021, PSE had ~~$140.0~~$357.0 million and ~~$373.8~~$140.0 million in short-term debt outstanding, respectively. Outside of the consolidation of PSE’s short-term debt, Puget Energy had ~~no short-term debt~~$118.6 million drawn and outstanding ~~in either year as borrowings~~ under its credit facility, ~~are~~of which $34.3 million was classified as ~~long-term.~~long-term debt and $84.3 million was classified as short-term debt. PSE’s weighted-average interest rate on short-term debt, including borrowing rate, commitment fees and the amortization of debt issuance costs, during 2022 and 2021 was 6.1% and ~~2020 was~~ 1.6% ~~and 2.0%~~, respectively. As of December 31, ~~2021,~~2022, PSE and Puget Energy had several committed credit facilities that are described below.

110

Puget Sound Energy

Credit Facility

~~In October 2017,~~On May 16, 2022, PSE entered into a new $800.0 million credit facility ~~which consolidates~~to replace the ~~two previous facilities into a single, smaller~~existing facility. ~~All other features~~The terms and conditions, including fees, ~~interest rate options, letter of credit, same day swingline borrowings,~~ financial covenant, expansion feature and ~~accordion feature~~credit spreads remain substantially the same. The base interest rate on loans has changed to the Secured Overnight Financing Rate (SOFR), as the London Interbank Offer Rate (LIBOR) is being discontinued in 2023. The proceeds of the PSE credit facility are to be used for general corporate purposes. The maturity date of the credit facility is May 14, 2027. The credit facility includes a swingline feature allowing same day availability on borrowings up to $75.0 ~~million. The credit facility also~~million and has an expansion feature which, upon receipt of commitments from one or more lenders, ~~would~~could increase the total size of the facility up to $1.4 billion. ~~On September 25, 2019, with no changes to the size, terms or conditions, the maturity of the unsecured revolving credit facility was extended for one year. The facility now matures in October 2023.~~

The credit agreement is syndicated among numerous lenders and contains usual and customary affirmative and negative covenants that, among other things, ~~places~~place limitations on PSE's ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit agreement also contains a ~~financial covenant~~leverage ratio that requires the ratio of (a) total ~~debt~~funded indebtedness to (b) total capitalization ofto be 65% or ~~less.~~less at all times. PSE certifies its compliance with such covenants to participating banks each quarter. As of December 31, ~~2021,~~2022, PSE was in compliance with all applicable covenant ratios.

The credit agreement ~~provides PSE with the ability to borrow at different interest rate options. The credit agreement~~ allows PSE to borrow at ~~the bank's~~a prime based rate or to make floating rate advances at the ~~LIBOR~~SOFR, in either case, plus a spread that is based upon PSE's credit rating. PSE must pay a commitment fee on the unused portion of the credit facility. The spreads and the commitment fee depend on PSE's credit ratings. As of the date of this report, interest was calculated as SOFR plus 0.10% SOFR adjustment plus 1.25% spread over the ~~spread to the LIBOR is 1.25%~~adjusted SOFR rate and the commitment fee iswas 0.175%.

As of December 31, ~~2021,~~2022, no ~~amounts were~~amount was drawn ~~and outstanding~~ under PSE's credit ~~facility. No letters of credit were outstanding~~facility and ~~$140.0~~$357.0 million was outstanding under the commercial paper program. Outside of the credit agreement, PSE had a ~~$2.5~~$2.3 million letter of credit in support of a long-term transmission ~~contract.~~contract and had $28.0 million issued under a standby letter of credit in support of natural gas purchases.

Demand Promissory Note

In 2006, PSE entered into a revolving credit facility with Puget Energy, in the form of a credit agreement and a demand promissory note pursuant to which PSE may borrow up to $30.0 million from Puget Energy subject to approval by Puget Energy. Under the terms of the promissory note, PSE pays interest on the outstanding borrowings based on the lower of the weighted-average interest rates of PSE’s outstanding commercial paper or PSE’s senior unsecured revolving credit facility. Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%. As of December 31, ~~2021,~~2022, there was no outstanding balance under the promissory note.

Puget Energy

Credit Facility

~~In October 2017,~~On May 16, 2022, Puget Energy entered into a new $800.0 million credit facility to replace the existing facility. The terms and conditions, including fees, ~~interest rate options,~~ financial covenant, ~~and~~ expansion feature and credit spreads remain substantially the same. ~~On September 25, 2019, with no changes~~The base interest rate on loans has changed to the ~~size, terms or conditions,~~SOFR, as the ~~maturity~~LIBOR is being discontinued in 2023. The proceeds of the ~~unsecured revolving~~PE credit facility ~~was extended~~are to be used for ~~one year.~~general corporate purposes. The maturity date of the credit facility ~~now matures on October 25, 2023. As of December 31, 2021, there was~~ ~~$33.3 million~~ ~~drawn and outstanding under the facility.~~is May 14, 2027. The Puget Energy revolving senior secured credit facility also has an ~~expansion~~accordion feature, ~~which,~~ upon ~~the banks' approval, would~~receipt of commitments from one or more lenders, could increase the size of the facility up to $1.3 billion.

The revolving senior secured credit facility ~~provides~~allows Puget Energy ~~the ability~~ to borrow ~~at different interest rate options and includes variable fee levels. Interest rates may be~~ based on ~~the bank's~~a prime based rate or ~~LIBOR~~SOFR, in either case, plus a spread based on Puget Energy's credit ratings. Puget Energy must pay a commitment fee on the unused portion of the facility. As of December 31, 2022, there was $118.6 million drawn and outstanding under the facility, of which $34.3 million was classified as long-term debt and $84.3 million was classified as short-term debt. As of the date of this report, ~~the~~interest was calculated as SOFR plus 0.10% SOFR adjustment plus 1.75% spread over ~~LIBOR was 1.75%~~the adjusted SOFR rate and the commitment fee was 0.275%.

~~107~~

The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The credit agreement also contains a ~~maximum~~ leverage ratio ~~financial covenant as defined in~~that requires the ~~agreement governing the senior secured credit facility.~~ratio of (a) total funded indebtedness to (b) total capitalization to be 65% or less at all times. As of December 31, ~~2021,~~2022, Puget Energy was in compliance with all applicable covenants.

On September 26, 2022, PE borrowed $50.0 million on the credit facility and contributed the proceeds to PSE as an equity contribution. The equity proceeds were used for general corporate purposes.

111

(9) Leases

PSE has operating leases for buildings for corporate offices and operations, real estate for operating facilities and the PSE and PLNG LNG facility, land for our wind farms, and vehicles for PSE’s fleet. Finance leases represent office printers and office buildings. The leases have remaining lease terms of less than a year to 4847 years. PSE's right-of-use (ROU) assets and lease liabilities include options to extend leases when it is reasonably certain that PSE will exercise that option.

During 2021, mechanical completion was achieved for the Puget LNG facility which triggered an increase in the lease payments for the Port of Tacoma lease. This remeasurement resulted in an increase of the operating lease ROU asset and operating lease liabilities of $26.3 million, of which $0.4 million was recorded in current operating lease liabilities and $25.9 million was recorded in operating lease liabilities. Additionally, 2two finance leases commenced for service center facilities in Kent and Puyallup, Washington. The Kent lease has a term of 20 years and resulted in an increase of electric utility plant and finance lease liabilities of $45.1 million, of which $1.0 million was recorded in other current liabilities and $44.1 million was recorded in finance lease liabilities, respectively. The Puyallup lease has a term of 20 years and resulted in an increase in common utility plant and finance lease liabilities of $61.3 million, of which $0.4 million was recorded in other current liabilities and $59.9 million was recorded in finance lease liabilities.

During 2022, there were no material changes regarding the Company's leases.

The components of lease cost were as follows:


Puget Energy and Puget Sound Energy	Puget Energy and Puget Sound Energy	Year Ended December 31,		Year Ended December 31,		Puget Energy and Puget Sound Energy	Year Ended December 31,		Year Ended December 31,
(Dollars in Thousands)	(Dollars in Thousands)	2021		2020		(Dollars in Thousands)	2022		2021
Finance lease cost:	Finance lease cost:					Finance lease cost:
Amortization of right-of-use asset	Amortization of right-of-use asset	$	1,291	$	607	Amortization of right-of-use asset	$	2,465	$	1,291
Interest on lease liabilities	Interest on lease liabilities	358		34		Interest on lease liabilities	2,482		358
Total finance lease cost	Total finance lease cost	$	1,649	$	641	Total finance lease cost	$	4,947	$	1,649

Operating lease cost1	Operating lease cost1	$	23,983	$	21,983	Operating lease cost1	$	23,984	$	23,983

_______________

1.Includes ~~$1.4~~$1.5 million and ~~$1.0~~$1.4 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease or both of the years ended December 31, ~~2021~~2022 and December 31, ~~2020,~~2021, respectively.

~~108~~

Supplemental cash flow information related to leases was as follows:


Puget Energy and Puget Sound Energy	Puget Energy and Puget Sound Energy	Year Ended December 31,		Year Ended December 31,		Puget Energy and Puget Sound Energy	Year Ended December 31,		Year Ended December 31,
(Dollars in Thousands)	(Dollars in Thousands)	2021		2020		(Dollars in Thousands)	2022		2021
Cash paid for amounts included in the measurement of lease liabilities:	Cash paid for amounts included in the measurement of lease liabilities:					Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flow for operating leases	Operating cash flow for operating leases	$	16,440	$	15,305	Operating cash flow for operating leases	$	16,574	$	16,440
Investing cash flow for operating leases1	Investing cash flow for operating leases1	7,543		6,678		Investing cash flow for operating leases1	7,410		7,543
Operating cash flow for finance leases	Operating cash flow for finance leases	358		34		Operating cash flow for finance leases	2,482		358
Financing cash flow for finance leases	Financing cash flow for finance leases	1,291		607		Financing cash flow for finance leases	2,465		1,291
Non-cash disclosure upon commencement of new lease	Non-cash disclosure upon commencement of new lease					Non-cash disclosure upon commencement of new lease
Right-of-use assets obtained in exchange for new operating lease liabilities	Right-of-use assets obtained in exchange for new operating lease liabilities	$	4,820	$	6,302	Right-of-use assets obtained in exchange for new operating lease liabilities	$	5,338	$	4,820
Right-of-use assets obtained in exchange for new finance lease liabilities	Right-of-use assets obtained in exchange for new finance lease liabilities	105,176		—		Right-of-use assets obtained in exchange for new finance lease liabilities	—		105,176
Non-cash disclosure upon modification of existing lease	Non-cash disclosure upon modification of existing lease					Non-cash disclosure upon modification of existing lease
Modification of operating lease right-of-use assets	Modification of operating lease right-of-use assets	$	26,287	$	—	Modification of operating lease right-of-use assets	$	21,068	$	26,287

_______________

1 Includes ~~$1.4~~$1.5 million and ~~$1.0~~$1.4 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease for both of the years ended December 31, ~~2021~~2022 and December 31, ~~2020,~~2021, respectively.

112

Supplemental balance sheet information related to leases was as follows:


Puget Sound Energy
Puget Energy and Puget Sound Energy								Puget Energy and Puget Sound Energy
(Dollars in Thousands)	(Dollars in Thousands)	At December 31,			At December 31,			(Dollars in Thousands)	At December 31,			At December 31,
Operating Leases	Operating Leases	2021			2020			Operating Leases	2022			2021
Operating lease right-of-use asset	Operating lease right-of-use asset	$	184,957		$	172,167		Operating lease right-of-use asset	$	193,509		$	184,957

Operating leases liabilities current	Operating leases liabilities current	$	20,398		$	19,204		Operating leases liabilities current	$	20,342		$	20,398
Operating lease liabilities long-term	Operating lease liabilities long-term	172,510			160,980			Operating lease liabilities long-term	181,265			172,510
Total operating lease liabilities:	Total operating lease liabilities:	$	192,908		$	180,184		Total operating lease liabilities:	$	201,607		$	192,908

Finance Leases	Finance Leases							Finance Leases
Common plant	Common plant	$	61,227		$	881		Common plant	$	58,391		$	61,227
Electric plant	Electric plant	43,793			—			Electric plant	41,576			43,793
Total finance lease assets	Total finance lease assets	$	105,020		$	881		Total finance lease assets	$	99,967		$	105,020

Other current liabilities	Other current liabilities	$	1,742		$	475		Other current liabilities	$	3,167		$	1,742
Finance lease liabilities	Finance lease liabilities	105,303			320			Finance lease liabilities	102,518			105,303
Total finance lease liabilities	Total finance lease liabilities	$	107,045		$	795		Total finance lease liabilities	$	105,685		$	107,045

Weighted Average Remaining Lease Term	Weighted Average Remaining Lease Term							Weighted Average Remaining Lease Term
Operating leases	Operating leases	22.80 Years			18.97 Years			Operating leases	22.00 Years			22.80 Years
Finance leases	Finance leases	20.15 Years			2.00 Years			Finance leases	19.10 Years			20.15 Years

Weighted Average Discount Rate	Weighted Average Discount Rate							Weighted Average Discount Rate
Operating leases	Operating leases	3.27		%	3.59		%	Operating leases	3.62		%	3.27		%
Finance leases	Finance leases	3.07		%	2.98		%	Finance leases	3.07		%	3.07		%

~~109~~

The following ~~tables summarize~~table summarizes the Company’s estimated future minimum lease payments as of December 31, ~~2021:~~2022:


Maturities of lease liabilities		Future Minimum Lease Payments
Puget Energy and Puget Sound Energy						Puget Energy and Puget Sound Energy	Future Minimum Lease Payments
(Dollars in Thousands)	(Dollars in Thousands)	Future Minimum Lease Payments				(Dollars in Thousands)
At December 31,	At December 31,					At December 31,	Operating Leases		Finance Leases
2022		$	23,945	$	4,881
2023	2023	23,717		6,260		2023	$	23,676	$	6,383
2024	2024	23,000		6,286		2024	23,232		6,408
2025	2025	19,636		6,411		2025	21,887		6,534
2026	2026	17,126		6,540		2026	21,472		6,591
2027						2027	21,047		6,670
Thereafter	Thereafter	164,797		116,553		Thereafter	172,969		109,882
Total lease payments	Total lease payments	$	272,221	$	146,931	Total lease payments	$	284,283	$	142,468
Less imputed interest	Less imputed interest	(79,313)		(39,886)		Less imputed interest	(82,676)		(36,783)
Total net present value	Total net present value	$	192,908	$	107,045	Total net present value	$	201,607	$	105,685

113

(10) Accounting for Derivative Instruments and Hedging Activities

PSE employs various energy portfolio optimization strategies, but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks within the sharing mechanism of the ~~PCA.~~Power Cost Adjustment. Therefore, wholesale market transactions and PSE's related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility in costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy which extends out three years. PSE's hedging strategy includes a risk-responsive component for the core natural gas portfolio, which utilizes quantitative risk-based measures with defined objectives to balance both portfolio risk and hedge costs.

PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools. In order to manage risks effectively, PSE enters into forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. Currently, the Company does not apply cash flow hedge accounting, and therefore records all mark-to-market gains or losses through earnings.

The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program, and its credit facilities to meet short-term funding needs. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts.

~~110~~

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


Puget Energy and Puget Sound Energy	Puget Energy and Puget Sound Energy	Year Ended December 31,										Puget Energy and Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	(Dollars in Thousands)	Volumes (millions)		Assets1				Liabilities²				(Dollars in Thousands)	Volumes (millions)		Assets1				Liabilities²
		2021	2020	2021		2020		2021		2020			2022	2021	2022		2021		2022		2021
Electric portfolio derivatives	Electric portfolio derivatives	*	*	$	74,829	$	22,544	$	85,424	$	46,922	Electric portfolio derivatives	*	*	$	337,703	$	74,829	$	87,120	$	85,424
Natural gas derivatives (MMBtus)3	Natural gas derivatives (MMBtus)3	347	320	79,578		19,276		18,850		14,352		Natural gas derivatives (MMBtus)3	322	347	343,947		79,578		56,222		18,850
Total derivative contracts	Total derivative contracts			$	154,407	$	41,820	$	104,274	$	61,274	Total derivative contracts			$	681,650	$	154,407	$	143,342	$	104,274
Current	Current			128,210		33,015		63,309		31,441		Current			587,029		128,210		124,976		63,309
Long-term	Long-term			26,197		8,805		40,965		29,833		Long-term			94,621		26,197		18,366		40,965
Total derivative contracts	Total derivative contracts			$	154,407	$	41,820	$	104,274	$	61,274	Total derivative contracts			$	681,650	$	154,407	$	143,342	$	104,274

__________

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

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

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

*Electric portfolio derivatives consist of electric generation fuel of ~~238.0~~234.9 million One Million British Thermal Units (MMBtus) and purchased electricity of ~~8.1~~5.3 million megawatt hours (MWhs) at December 31, ~~2021,~~2022, and ~~212.2~~238.0 million MMBtus and ~~6.6~~8.1 million MWhs at December 31, ~~2020.~~2021.

It is the Company's policy to record all derivative transactions on a gross basis at the contract level without offsetting assets or liabilities. The Company generally enters into transactions using the following master agreements: WSPP, Inc. (WSPP) agreements, which standardize physical power contracts; International Swaps and Derivatives Association (ISDA) agreements, which standardize financial natural gas and electric contracts; and North American Energy Standards Board (NAESB) agreements, which standardize physical natural gas contracts. The Company believes that such agreements reduce credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as the right of set-off in the event of counterparty default. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount. For further details regarding the fair value of derivative instruments, see Note 11, "Fair Value Measurements", to the consolidated financial statements included in Item 8 of this report.

114

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


Puget Energy and Puget Sound Energy	Puget Energy and Puget Sound Energy																Puget Energy and Puget Sound Energy
December 31, 2021
December 31, 2022																	December 31, 2022
(Dollars in Thousands)	(Dollars in Thousands)	Gross Amount Recognized in the Consolidated Balance Sheet1		Gross Amounts Offset in the Consolidated Balance Sheet		Net of Amounts Presented in the Consolidated Balance Sheet			Gross Amounts Not Offset in the Consolidated Balance Sheet								(Dollars in Thousands)	Gross Amount Recognized in the Consolidated Balance Sheet1			Gross Amounts Offset in the Consolidated Balance Sheet		Net of Amounts Presented in the Consolidated Balance Sheet			Gross Amounts Not Offset in the Consolidated Balance Sheet
								Commodity Contracts2			Cash Collateral Received/Pledged			Net Amount						Commodity Contracts2					Cash Collateral Received/Pledged			Net Amount
Assets:	Assets:																					Assets:
Energy derivative contracts	Energy derivative contracts	$	154,407	$	—	$	154,407		$	(40,833)		$	—		$	113,574	Energy derivative contracts	$	681,650		$	—	$	681,650		$	(125,334)		$	—	$	556,316
Liabilities:	Liabilities:																Liabilities:
Energy derivative contracts	Energy derivative contracts	104,274		—		104,274			(40,833)			(1,743)			61,698		Energy derivative contracts	143,342			—		143,342			(125,334)			(5,661)		12,347

~~111~~


Puget Energy and Puget Sound Energy	Puget Energy and Puget Sound Energy																Puget Energy and Puget Sound Energy
December 31, 2020
December 31, 2021																	December 31, 2021
(Dollars in Thousands)	(Dollars in Thousands)	Gross Amount Recognized1		Gross Amounts Offset in the Consolidated Balance Sheet		Net of Amounts Presented in the Consolidated Balance Sheet			Gross Amounts Not Offset in the Consolidated Balance Sheet								(Dollars in Thousands)	Gross Amount Recognized1			Gross Amounts Offset in the Consolidated Balance Sheet		Net of Amounts Presented in the Consolidated Balance Sheet			Gross Amounts Not Offset in the Consolidated Balance Sheet
								Commodity Contracts2			Cash Collateral Received/Pledged			Net Amount						Commodity Contracts2					Cash Collateral Received/Pledged			Net Amount
Assets	Assets																					Assets
Energy Derivative Contracts	Energy Derivative Contracts	$	41,820	$	—	$	41,820		$	(21,696)		$	—		$	20,124	Energy Derivative Contracts	$	154,407		$	—	$	154,407		$	(40,833)		$	—	$	113,574
Liabilities	Liabilities																Liabilities
Energy Derivative Contracts	Energy Derivative Contracts	61,274		—		61,274			(21,696)			(9,343)			30,235		Energy Derivative Contracts	104,274			—		104,274			(40,833)			(1,743)		61,698

__________

1.All ~~Derivative Contract~~derivative contract deals are executed under ISDA, NAESB, and WSPP master agreements with right of set-off.

2.~~Balance sheet classification: Current~~Amounts reflect netting by Counterparty and ~~Long-term Unrealized loss on derivative instruments.~~right of set-off.

115

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


Puget Energy and Puget Sound Energy	Puget Energy and Puget Sound Energy		Year Ended December 31,						Puget Energy and Puget Sound Energy		Year Ended December 31,
(Dollars in Thousands)	(Dollars in Thousands)	Location	2021		2020		2019		(Dollars in Thousands)	Location	2022		2021		2020

Gas for Power Derivatives:	Gas for Power Derivatives:								Gas for Power Derivatives:
Unrealized	Unrealized	Unrealized gain (loss) on derivative instruments, net	$	26,686	$	5,534	$	16,970	Unrealized	Unrealized gain (loss) on derivative instruments, net	$	61,761	$	26,686	$	5,534
Realized	Realized	Electric generation fuel	76,504		5,246		10,828		Realized	Electric generation fuel	158,550		76,504		5,246
Power Derivatives:	Power Derivatives:								Power Derivatives:
Unrealized	Unrealized	Unrealized gain (loss) on derivative instruments, net	(12,901)		(32,341)		(20,544)		Unrealized	Unrealized gain (loss) on derivative instruments, net	199,416		(12,901)		(32,341)
Realized	Realized	Purchased electricity	(3,044)		(14,958)		48,686		Realized	Purchased electricity	20,917		(3,044)		(14,958)
Total gain (loss) recognized in income on derivatives	Total gain (loss) recognized in income on derivatives		$	87,245	$	(36,519)	$	55,940	Total gain (loss) recognized in income on derivatives		$	440,644	$	87,245	$	(36,519)

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

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

It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of December 31, ~~2021,~~2022, approximately ~~98.9%~~99.4% of the Company's energy portfolio exposure, excluding ~~NPNS~~normal purchase normal sale (NPNS) transactions, is with counterparties that are rated investment grade by rating agencies and ~~1.1%~~0.6% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies.

~~112~~

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

The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against unrealized gain (loss) positions. As of December 31, ~~2021,~~2022, the Company was in a net liability position with the majority of counterparties, so the default factors of counterparties did not have a significant impact on reserves for the period. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. PSE also transacts power futures contracts on the Intercontinental Exchange (ICE), and natural gas contracts on the ICE NGX exchange platform. Execution of contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of December 31, ~~2021,~~2022, PSE had cash posted as collateral of ~~$12.8~~$23.2 million related to contracts executed on the ICE platform. ~~Also, as of December 31, 2021,~~In August 2022, PSE ~~had $24.0 million in cash posted as collateral and 0~~entered into a standby letter of credit ~~posted~~agreement with TD Bank allowing standby letter of credit postings of up to $50.0 million as a condition of transacting on the ICE NGX platform. As of December 31, 2022, PSE had $33.0 million in cash posted with ICE NGX and $28.0 million issued under the standby letter of credit agreement. PSE did not trigger any collateral requirements with any of its counterparties nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades during the twelve months ended December 31, ~~2021.~~2022.

116

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


Puget Energy and Puget Sound Energy	Puget Energy and Puget Sound Energy	December 31,												Puget Energy and Puget Sound Energy	December 31,
(Dollars in Thousands)	(Dollars in Thousands)	2021						2020						(Dollars in Thousands)	2022						2021
Contingent Feature	Contingent Feature	Fair Value1 Liability		Posted Collateral		Contingent Collateral		Fair Value1 Liability		Posted Collateral		Contingent Collateral		Contingent Feature	Fair Value1 Liability		Posted Collateral		Contingent Collateral		Fair Value1 Liability		Posted Collateral		Contingent Collateral
Credit rating2	Credit rating2	$	52,537	$	—	$	52,537	$	26,966	$	—	$	26,966	Credit rating2	$	3,157	$	—	$	3,157	$	52,537	$	—	$	52,537
Requested credit for adequate assurance	Requested credit for adequate assurance	9,380		—		—		6,576		—		—		Requested credit for adequate assurance	4,157		—		—		9,380		—		—
Forward value of contract3	Forward value of contract3	1,743		12,782		N/A		9,343		20,903		N/A		Forward value of contract3	5,661		56,200		N/A		1,743		12,782		N/A
Total	Total	$	63,660	$	12,782	$	52,537	$	42,885	$	20,903	$	26,966	Total	$	12,975	$	56,200	$	3,157	$	63,660	$	12,782	$	52,537

_______________

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

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

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

(11) Fair Value Measurements

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

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

~~113~~

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

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

Financial assets and liabilities measured at fair value are classified in their entirety in the appropriate fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves, contract terms and prices, credit-risk adjustments, and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs as substantially all assumptions and inputs are observable in active

117

markets throughout the full term of the instruments. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas markets from an independent external pricing service.

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

Assets and Liabilities with Estimated Fair Value

The carrying values of cash and cash equivalents, restricted cash, and short-term debt as reported on the balance sheet are reasonable estimates of their fair value due to the short-term nature of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value of other investments of ~~$53.2~~$55.0 million and ~~$52.7~~$53.2 million at December 31, ~~2021,~~2022, and ~~2020,~~2021, respectively, are included in "Other property and investments" on the balance sheet. These values are also reasonable estimates of their fair value and classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar transactions.

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

~~114~~

The carrying values and estimated fair values were as follows:


Puget Energy	Puget Energy		December 31, 2021				December 31, 2020				Puget Energy		December 31, 2022				December 31, 2021
(Dollars in Thousands)	(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value		(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Financial liabilities:	Financial liabilities:										Financial liabilities:

Long-term debt (fixed-rate), net of discount1	Long-term debt (fixed-rate), net of discount1	2	$	6,170,466	$	7,769,896	$	5,667,740	$	7,755,946	Long-term debt (fixed-rate), net of discount1	2	$	6,629,073	$	6,149,797	$	6,170,466	$	7,769,896
Long-term debt (variable-rate), net of discount	Long-term debt (variable-rate), net of discount	2	33,300		33,300		224,700		224,700		Long-term debt (variable-rate), net of discount	2	34,300		34,300		33,300		33,300
Total	Total		$	6,203,766	$	7,803,196	$	5,892,440	$	7,980,646	Total		$	6,663,373	$	6,184,097	$	6,203,766	$	7,803,196

Puget Sound Energy	Puget Sound Energy		December 31, 2021				December 31, 2020				Puget Sound Energy		December 31, 2022				December 31, 2021
(Dollars in Thousands)	(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value		(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Financial liabilities:	Financial liabilities:										Financial liabilities:

Long-term debt (fixed-rate), net of discount2	Long-term debt (fixed-rate), net of discount2	2	$	4,784,719	$	6,145,639	$	4,338,044	$	6,086,358	Long-term debt (fixed-rate), net of discount2	2	$	4,786,765	$	4,379,010	$	4,784,719	$	6,145,639
Total	Total		$	4,784,719	$	6,145,639	$	4,338,044	$	6,086,358	Total		$	4,786,765	$	4,379,010	$	4,784,719	$	6,145,639

_______________

1.The carrying value includes debt issuances costs of ~~$22.7~~$21.5 million and $22.7 million for December 31, ~~2021,~~2022, and ~~2020,~~2021, respectively, which are not included in fair value.

2.The carrying value includes debt issuances costs of ~~$22.8~~$21.4 million and ~~$22.9~~$22.8 million for December 31, ~~2021,~~2022, and ~~2020,~~2021, respectively, which are not included in fair value.

118

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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


Puget Energy and Puget Sound Energy	Puget Energy and Puget Sound Energy	Fair Value						Fair Value						Puget Energy and Puget Sound Energy	Fair Value						Fair Value
		December 31, 2021						December 31, 2020							December 31, 2022						December 31, 2021
(Dollars in Thousands)	(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total		(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:	Assets:													Assets:
Electric Derivative Instruments	Electric Derivative Instruments	$	68,011	$	6,818	$	74,829	$	21,947	$	597	$	22,544	Electric Derivative Instruments	$	218,610	$	119,093	$	337,703	$	68,011	$	6,818	$	74,829
Gas Derivative Instruments	Gas Derivative Instruments	79,526		52		79,578		19,139		137		19,276		Gas Derivative Instruments	342,988		959		343,947		79,526		52		79,578
Total derivative assets	Total derivative assets	$	147,537	$	6,870	$	154,407	$	41,086	$	734	$	41,820	Total derivative assets	$	561,598	$	120,052	$	681,650	$	147,537	$	6,870	$	154,407
Liabilities:	Liabilities:													Liabilities:
Electric Derivative Instruments	Electric Derivative Instruments	$	35,854	$	49,570	$	85,424	$	22,607	$	24,315	$	46,922	Electric Derivative Instruments	$	84,105	$	3,015	$	87,120	$	35,854	$	49,570	$	85,424
Gas Derivative Instruments	Gas Derivative Instruments	16,678		2,172		18,850		13,080		1,272		14,352		Gas Derivative Instruments	55,136		1,086		56,222		16,678		2,172		18,850
Total derivative liabilities	Total derivative liabilities	$	52,532	$	51,742	$	104,274	$	35,687	$	25,587	$	61,274	Total derivative liabilities	$	139,241	$	4,101	$	143,342	$	52,532	$	51,742	$	104,274

~~115~~


Puget Energy and Puget Sound Energy	Puget Energy and Puget Sound Energy	Year Ended December 31,																		Puget Energy and Puget Sound Energy	Year Ended December 31,
Level 3 Roll-Forward Net Asset(Liability)		2021						2020						2019
Level 3 Roll-Forward Net Asset (Liability)																				Level 3 Roll-Forward Net Asset (Liability)	2022						2021						2020
(Dollars in Thousands)	(Dollars in Thousands)	Electric		Natural Gas		Total		Electric		Natural Gas		Total		Electric		Natural Gas		Total		(Dollars in Thousands)	Electric		Natural Gas		Total		Electric		Natural Gas		Total		Electric		Natural Gas		Total
Balance at beginning of period	Balance at beginning of period	$	(23,718)	$	(1,135)	$	(24,853)	$	(3,379)	$	1,282	$	(2,097)	$	1,362	$	1,673	$	3,035	Balance at beginning of period	$	(42,752)	$	(2,120)	$	(44,872)	$	(23,718)	$	(1,135)	$	(24,853)	$	(3,379)	$	1,282	$	(2,097)
Changes during period:	Changes during period:																			Changes during period:
Realized and unrealized energy derivatives	Realized and unrealized energy derivatives																			Realized and unrealized energy derivatives
Included in earnings1	Included in earnings1	(15,839)		—		(15,839)		(23,559)		—		(23,559)		3,558		—		3,558		Included in earnings1	180,533		—		180,533		(15,839)		—		(15,839)		(23,559)		—		(23,559)
Included in regulatory assets / liabilities	Included in regulatory assets / liabilities	—		(1,749)		(1,749)		—		(1,049)		(1,049)		—		3,151		3,151		Included in regulatory assets / liabilities	—		301		301		—		(1,749)		(1,749)		—		(1,049)		(1,049)
Settlements2	Settlements2	(3,195)		764		(2,431)		3,220		(1,368)		1,852		(11,265)		(4,708)		(15,973)		Settlements2	(21,972)		1,369		(20,603)		(3,195)		764		(2,431)		3,220		(1,368)		1,852
Transferred into Level 3	Transferred into Level 3	—		—		—		—		—		—		4,390		(398)		3,992		Transferred into Level 3	—		—		—		—		—		—		—		—		—
Transferred out Level 3	Transferred out Level 3	—		—		—		—		—		$	—	(1,424)		1,564		$	140	Transferred out Level 3	269		323		592		—		—		$	—	—		—		$	—
Balance at end of period	Balance at end of period	$	(42,752)	$	(2,120)	$	(44,872)	$	(23,718)	$	(1,135)	$	(24,853)	$	(3,379)	$	1,282	$	(2,097)	Balance at end of period	$	116,078	$	(127)	$	115,951	$	(42,752)	$	(2,120)	$	(44,872)	$	(23,718)	$	(1,135)	$	(24,853)

__________________

1.Income Statement classification: Unrealized ~~(gain) loss~~gain (loss) on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $147.1 million, $(21.6) million ~~$(21.3) million~~ and ~~$(3.2)~~$(21.3) million for the years ended December 31, 2022, 2021, ~~2020,~~ and ~~2019,~~2020, respectively.

2.The Company had no purchases or sales of options during the reported periods.

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

119

In order to determine which assets and liabilities are classified as Level 3, the Company receives market data from its independent external pricing service defining the tenor of observable market quotes. To the extent any of the Company's commodity contracts extend beyond what is considered observable as defined by its independent pricing service, the contracts are classified as Level 3. The actual tenor of what the independent pricing service defines as observable is subject to change depending on market conditions. Therefore, as the market changes, the same contract may be designated Level 3 one month and Level 2 the next, and vice versa. The changes of fair value classification into or out of Level 3 are recognized each month and reported in the Level 3 Roll-forward table above. The Company did not have any transfers between Level 2 and Level 1 during the years ended December 31, 2022, 2021, ~~2020,~~ and ~~2019.~~2020. The Company does transact at locations, or market price points, that are illiquid or for which no prices are available from the independent pricing service. In such circumstances the Company uses a more liquid price point and adjusts the price for transportation costs to the illiquid locations to serve as a proxy for market prices. Such transactions are classified as Level 3. The Company does not use internally developed models to make adjustments to significant unobservable pricing inputs.

The only significant unobservable input into the fair value measurement of the Company's Level 3 assets and liabilities is the forward price for electric and natural gas contracts.

~~116~~

Below are the forward price ranges for the Company's commodity contracts, as of December 31, ~~2021:~~2022:


Puget Energy and Puget Sound Energy	Puget Energy and Puget Sound Energy	Fair Value						Range						Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted		(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted
Electricity	Electricity	$	6,818	$	49,570	Discounted cash flow	Power Prices (per MWh)	$	21.88	$	119.38	$	61.51	Electricity	$	119,093	$	3,015	Discounted cash flow	Power Prices (per MWh)	$	55.79	$	291.03	$	131.51
Natural Gas	Natural Gas	$	52	$	2,172	Discounted cash flow	Natural Gas Prices (per MMBtu)	$	3.65	$	7.54	$	5.89	Natural Gas	$	959	$	1,086	Discounted cash flow	Natural Gas Prices (per MMBtu)	$	3.84	$	7.00	$	4.87

_______________

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

The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently, significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. At December 31, ~~2021,~~2022, a hypothetical 10% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by ~~$17.9~~$37.6 million.

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

Puget Energy records the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle.

ASC 360 requires long-lived assets to be tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. One such triggering event is a significant decrease in the forward market prices of power.

Puget Energy evaluated the triggering event criteria in ASC 360 during 2022 and 2021 and determined there was no indication of impairment of its power purchase contracts. During 2020, decreases in forward power prices and decreases in forecasted revenue and cost estimates indicated the carrying value of Puget Energy’s power purchase contracts may not have been recoverable. Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. In 2020, the following impairments were recorded to the Company's intangible asset contracts, with corresponding reductions to the regulatory liability as follows:

Puget Energy
(Dollars in Thousands)
Valuation Date Contract Name Carrying Value Fair Value Write Down
March 31, 2020 Rocky Reach $ 147,168 $ 94,603 $ 52,565
Total 2020 Impairments $ 52,565

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

~~117~~

~~Below are significant unobservable inputs used in estimating the impaired long-term power purchase contracts' fair value in 2020:~~

Puget Energy
Valuation Date Contract Unobservable Input Low High Average
March 31, 2020 Rocky Reach Power prices (per MWh) $ 10.23 $ 38.84 $ 24.43
Power contract costs per quarter (in thousands) 6,308 7,085 6,468

(12) Employee Investment Plans

The Company's Investment Plan is a qualified employee 401(k) plan, under which employee salary deferrals and after-tax contributions are used to purchase several different investment fund options. PSE’s contributions to the employee Investment Plan were $25.2 million, $23.6 million ~~$22.1 million~~ and ~~$21.7~~$22.1 million for the years 2022, 2021, ~~2020,~~ and ~~2019,~~2020, respectively. The employee Investment Plan eligibility requirements are set forth in the plan documents.

120

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

1.For employees under the Cash Balance retirement plan formula, PSE will match 100% of an employee's contribution up to 6.0% of plan compensation each paycheck, and will make an additional year-end contribution equal to 1.0% of base pay.

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

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

1.401(k) Company Matching: For non-represented, UA-represented and IBEW-represented employees PSE will match: 100% match on the first 3.0% of pay contributed and 50.0% match on the next 3.0% of pay contributed, such that an employee who contributes 6.0% of pay will receive 4.5% of pay in company match. Company matching will be immediately vested.

2.Company Contribution: For UA-represented employees will receive an annual company contribution of 4.0% of eligible pay placed in the Cash Balance retirement plan. Non-represented and IBEW-represented employees will receive an annual company contribution of 4.0% of eligible pay, placed either in the Investment Plan 401(k) plan or in PSE’s Cash Balance retirement plan. Non-represented and IBEW-represented employees will make a one-time election within 30 days of hire and direct that PSE put the 4.0% contribution either into the 401(k) plan or into an account in the Cash Balance retirement plan. The Company's 4.0% contribution will vest after three years of service.

(13) Retirement Benefits

PSE has a defined benefit pension plan (Qualified Pension Benefits) covering a substantial majority of PSE employees. For employees hired prior to 2014, pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates. Effective January 1, 2014, all new UA represented employees hired or rehired receive annual pay credits of 4.0% of eligible pay each year in the cash balance formula of the defined pension plan. Effective January 1, 2014 for non-represented employees, and December 12, 2014 for employees represented by the IBEW, newly hired or rehired employees receive annual employer contributions of 4.0% of eligible play each year into the cash balance formula of the defined benefit pension or 401k plan account. PSE also has a non-qualified Supplemental Executive Retirement Plan (SERP) for certain key senior management employees that closed to new participants in 2019. Effective 2019, PSE has an officer restoration benefit for new officers who join PSE or are promoted, such that company contributions under PSE’s applicable tax-qualified plan, which otherwise would have been credited if not for IRS limitations, are credited at 4.0% of earnings to an account with the Deferred Compensation Plan.

~~118~~

In addition to providing pension benefits, PSE provides legacy group health care and life insurance benefits (Other Benefits) for certain retired employees. These benefits are provided principally through an insurance company. The insurance premiums, paid primarily by retirees, are based on the benefits provided during the prior year. On June 11, 2019, the Company's Welfare Benefits Committee approved the termination of the Plan effective December 31, 2019, and the creation of a Retiree Health Reimbursement Account (HRA) Plan effective January 1, 2020.

Puget Energy's retirement plans were remeasured as a result of the merger in 2009, which represents the difference between Puget Energy and PSE's retirement plans. The components of service cost are included within utility operations and maintenance for PSE and within non-utility expense and other for Puget Energy while all non-service cost components are included in other income.

121

The following tables summarize the Company’s change in benefit obligation, change in plan assets and amounts recognized in the Statements of Financial Position for the years ended December 31, ~~2021,~~2022, and ~~2020:~~2021:


Puget Energy and Puget Sound Energy	Puget Energy and Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits				Puget Energy and Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	(Dollars in Thousands)	2021		2020		2021		2020		2021		2020		(Dollars in Thousands)	2022		2021		2022		2021		2022		2021
Change in benefit obligation:	Change in benefit obligation:													Change in benefit obligation:
Benefit obligation at beginning of period	Benefit obligation at beginning of period	$	849,383	$	774,305	$	46,742	$	63,000	$	12,114	$	11,627	Benefit obligation at beginning of period	$	834,960	$	849,383	$	43,155	$	46,742	$	11,654	$	12,114
Amendments	Amendments	—		—		—		—		205		44		Amendments	—		—		—		—		38		205
Service cost	Service cost	26,888		24,337		456		756		155		190		Service cost	26,351		26,888		557		456		217		155
Interest cost	Interest cost	22,381		25,180		1,183		1,464		302		368		Interest cost	24,263		22,381		1,253		1,183		311		302

Actuarial loss (gain)	Actuarial loss (gain)	(6,826)		69,413		828		3,663		(514)		604		Actuarial loss (gain)	(215,005)		(6,826)		(5,260)		828		(2,397)		(514)
Benefits paid	Benefits paid	(55,831)		(42,775)		(6,054)		(22,141)		(803)		(906)		Benefits paid	(80,226)		(55,831)		(7,659)		(6,054)		(808)		(803)
Medicare part D subsidy received	Medicare part D subsidy received	—		—		—		—		195		187		Medicare part D subsidy received	—		—		—		—		—		195
Administrative expense	Administrative expense	(1,035)		(1,077)		—		—		—		—		Administrative expense	(1,065)		(1,035)		—		—		—		—
Benefit obligation at end of period	Benefit obligation at end of period	$	834,960	$	849,383	$	43,155	$	46,742	$	11,654	$	12,114	Benefit obligation at end of period	$	589,278	$	834,960	$	32,046	$	43,155	$	9,015	$	11,654


Puget Energy and Puget Sound Energy	Puget Energy and Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits				Puget Energy and Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	(Dollars in Thousands)	2021		2020		2021		2020		2021		2020		(Dollars in Thousands)	2022		2021		2022		2021		2022		2021
Change in plan assets:	Change in plan assets:													Change in plan assets:
Fair value of plan assets at beginning of period	Fair value of plan assets at beginning of period	$	834,655	$	753,042	$	—	$	—	$	5,918	$	6,289	Fair value of plan assets at beginning of period	$	898,550	$	834,655	$	—	$	—	$	6,341	$	5,918
Actual return on plan assets	Actual return on plan assets	102,787		107,409		—		—		1,005		278		Actual return on plan assets	(176,537)		102,787		—		—		(550)		1,005
Employer contribution	Employer contribution	18,000		18,000		6,054		22,141		222		257		Employer contribution	18,000		18,000		7,659		6,054		207		222
Benefits paid	Benefits paid	(55,831)		(42,775)		(6,054)		(22,141)		(804)		(906)		Benefits paid	(80,226)		(55,831)		(7,659)		(6,054)		(808)		(804)
Administrative expense	Administrative expense	(1,061)		(1,021)		—		—		—		—		Administrative expense	(1,254)		(1,061)		—		—		—		—
Fair value of plan assets at end of period	Fair value of plan assets at end of period	$	898,550	$	834,655	$	—	$	—	$	6,341	$	5,918	Fair value of plan assets at end of period	$	658,533	$	898,550	$	—	$	—	$	5,190	$	6,341
Funded status at end of period	Funded status at end of period	$	63,590	$	(14,728)	$	(43,155)	$	(46,742)	$	(5,313)	$	(6,196)	Funded status at end of period	$	69,255	$	63,590	$	(32,046)	$	(43,155)	$	(3,825)	$	(5,313)


Puget Energy and Puget Sound Energy	Puget Energy and Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits				Puget Energy and Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	(Dollars in Thousands)	2021		2020		2021		2020		2021		2020		(Dollars in Thousands)	2022		2021		2022		2021		2022		2021
Amounts recognized in Consolidated Balance Sheet consist of:	Amounts recognized in Consolidated Balance Sheet consist of:													Amounts recognized in Consolidated Balance Sheet consist of:
Noncurrent assets	Noncurrent assets	$	63,590	$	—	$	—	$	—	$	—	$	—	Noncurrent assets	$	69,255	$	63,590	$	—	$	—	$	—	$	—
Current liabilities	Current liabilities	—		—		(2,822)		(6,763)		(280)		(293)		Current liabilities	—		—		(3,532)		(2,822)		(252)		(280)
Noncurrent liabilities	Noncurrent liabilities	—		(14,728)		(40,333)		(39,979)		(5,033)		(5,903)		Noncurrent liabilities	—		—		(28,514)		(40,333)		(3,573)		(5,033)
Net assets (liabilities)	Net assets (liabilities)	$	63,590	$	(14,728)	$	(43,155)	$	(46,742)	$	(5,313)	$	(6,196)	Net assets (liabilities)	$	69,255	$	63,590	$	(32,046)	$	(43,155)	$	(3,825)	$	(5,313)


Puget Energy and Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	2022		2021		2022		2021		2022		2021
Change in plan obligation and plan asset:
Projected benefit obligation	$	589,278	$	834,960	$	32,046	$	43,155	$	9,015	$	11,654
Accumulated benefit obligation	582,538		823,418		29,763		40,773		8,929		11,549
Fair value of plan assets	658,533		898,550		—		—		5,190		6,341

~~119~~122

Puget Energy and
Puget Sound Energy Qualified
Pension Benefits SERP
Pension Benefits Other
Benefits
(Dollars in Thousands) 2021 2020 2021 2020 2021 2020
Change in plan obligation and plan asset:
Projected benefit obligation $ 834,960 $ 849,383 $ 43,155 $ 46,742 $ 11,654 $ 12,114
Accumulated benefit obligation 823,418 837,455 40,773 44,033 11,549 12,070
Fair value of plan assets 898,550 834,655 — — 6,341 5,918

The following tables summarize Puget Energy's and PSE's pension benefit amounts recognized in accumulated other comprehensive income (AOCI) for the years ended December 31, ~~2021,~~2022, and ~~2020:~~2021:


Puget Energy	Puget Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits				Puget Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	(Dollars in Thousands)	2021		2020		2021		2020		2021		2020		(Dollars in Thousands)	2022		2021		2022		2021		2022		2021
Amounts recognized in Accumulated Other Comprehensive Income consist of:	Amounts recognized in Accumulated Other Comprehensive Income consist of:													Amounts recognized in Accumulated Other Comprehensive Income consist of:
Net loss (gain)	Net loss (gain)	$	24,859	$	98,010	$	9,571	$	11,738	$	(525)	$	600	Net loss (gain)	$	31,213	$	24,859	$	1,563	$	9,571	$	(1,964)	$	(525)
Prior service cost (credit)	Prior service cost (credit)	—		(1,904)		578		927		242		44		Prior service cost (credit)	—		—		289		578		259		242
Total	Total	$	24,859	$	96,106	$	10,149	$	12,665	$	(283)	$	644	Total	$	31,213	$	24,859	$	1,852	$	10,149	$	(1,705)	$	(283)


Puget Sound Energy	Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits				Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	(Dollars in Thousands)	2021		2020		2021		2020		2021		2020		(Dollars in Thousands)	2022		2021		2022		2021		2022		2021
Amounts recognized in Accumulated Other Comprehensive Income consist of:	Amounts recognized in Accumulated Other Comprehensive Income consist of:													Amounts recognized in Accumulated Other Comprehensive Income consist of:
Net loss (gain)	Net loss (gain)	$	127,111	$	210,317	$	10,103	$	12,504	$	(622)	$	489	Net loss (gain)	$	124,767	$	127,111	$	1,864	$	10,103	$	(2,056)	$	(622)
Prior service cost (credit)	Prior service cost (credit)	—		(1,513)		578		927		242		44		Prior service cost (credit)	—		—		289		578		258		242
Total	Total	$	127,111	$	208,804	$	10,681	$	13,431	$	(380)	$	533	Total	$	124,767	$	127,111	$	2,153	$	10,681	$	(1,798)	$	(380)

~~120~~

The following tables summarize Puget Energy's and PSE's net periodic benefit cost for the years ended December 31, 2022, 2021, ~~2020,~~ and ~~2019.~~2020.


Puget Energy	Puget Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits						Puget Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	(Dollars in Thousands)	2021		2020		2019		2021		2020		2019		2021		2020		2019		(Dollars in Thousands)	2022		2021		2020		2022		2021		2020		2022		2021		2020
Components of net periodic benefit cost:	Components of net periodic benefit cost:																			Components of net periodic benefit cost:
Service cost	Service cost	$	26,888	$	24,337	$	22,656	$	456	$	756	$	1,023	$	155	$	190	$	61	Service cost	$	26,351	$	26,888	$	24,337	$	557	$	456	$	756	$	217	$	155	$	190
Interest cost	Interest cost	22,381		25,180		28,913		1,183		1,464		2,314		302		368		410		Interest cost	24,263		22,381		25,180		1,253		1,183		1,464		311		302		368
Expected return on plan assets	Expected return on plan assets	(48,239)		(49,902)		(50,249)		—		—		—		(355)		(389)		(393)		Expected return on plan assets	(51,014)		(48,239)		(49,902)		—		—		—		(379)		(355)		(389)
Amortization of prior service cost (credit)	Amortization of prior service cost (credit)	(1,904)		(1,980)		(1,980)		349		349		331		6		—		—		Amortization of prior service cost (credit)	—		(1,904)		(1,980)		289		349		349		22		6		—
Amortization of net loss (gain)	Amortization of net loss (gain)	11,803		8,160		1,151		2,165		2,122		1,365		(39)		(82)		(374)		Amortization of net loss (gain)	6,381		11,803		8,160		2,471		2,165		2,122		(29)		(39)		(82)
Net periodic benefit cost	Net periodic benefit cost	$	10,929	$	5,795	$	491	$	4,153	$	4,691	$	5,033	$	69	$	87	$	(296)	Net periodic benefit cost	$	5,981	$	10,929	$	5,795	$	4,570	$	4,153	$	4,691	$	142	$	69	$	87

Puget Sound Energy Qualified
Pension Benefits SERP
Pension Benefits Other
Benefits
(Dollars in Thousands) 2021 2020 2019 2021 2020 2019 2021 2020 2019
Components of net periodic benefit cost:
Service cost $ 26,888 $ 24,337 $ 22,656 $ 456 $ 756 $ 1,023 $ 155 $ 190 $ 61
Interest cost 22,381 25,180 28,913 1,183 1,464 2,314 302 368 410
Expected return on plan assets (48,242) (49,910) (50,267) — — — (355) (389) (393)
Amortization of prior service cost (credit) (1,513) (1,573) (1,573) 349 349 333 6 — —
Amortization of net loss (gain) 21,862 19,043 12,877 2,344 2,385 1,733 (52) (137) (562)
Net periodic benefit cost $ 21,376 $ 17,077 $ 12,606 $ 4,332 $ 4,954 $ 5,403 $ 56 $ 32 $ (484)

123


Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2022		2021		2020		2022		2021		2020		2022		2021		2020
Components of net periodic benefit cost:
Service cost	$	26,351	$	26,888	$	24,337	$	557	$	456	$	756	$	217	$	155	$	190
Interest cost	24,263		22,381		25,180		1,253		1,183		1,464		311		302		368
Expected return on plan assets	(51,016)		(48,242)		(49,910)		—		—		—		(379)		(355)		(389)
Amortization of prior service cost (credit)	—		(1,513)		(1,573)		289		349		349		22		6		—
Amortization of net loss (gain)	15,080		21,862		19,043		2,648		2,344		2,385		(35)		(52)		(137)
Net periodic benefit cost	$	14,678	$	21,376	$	17,077	$	4,747	$	4,332	$	4,954	$	136	$	56	$	32

The following tables summarize Puget Energy's and PSE's benefit obligations recognized in other comprehensive income (OCI) for the years ended December 31, ~~2021,~~2022, and ~~2020:~~2021:


Puget Energy	Puget Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits				Puget Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	(Dollars in Thousands)	2021		2020		2021		2020		2021		2020		(Dollars in Thousands)	2022		2021		2022		2021		2022		2021
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:	Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:													Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	Net loss (gain)	$	(61,348)	$	11,851	$	828	$	3,663	$	(1,164)	$	715	Net loss (gain)	$	12,735	$	(61,348)	$	(5,260)	$	828	$	(1,468)	$	(1,164)
Amortization of net (loss) gain	Amortization of net (loss) gain	(11,803)		(8,160)		(2,164)		(2,122)		39		82		Amortization of net (loss) gain	(6,381)		(11,803)		(2,471)		(2,164)		29		39
Settlements, mergers, sales, and closures	Settlements, mergers, sales, and closures	—		—		(830)		(4,806)		—		—		Settlements, mergers, sales, and closures	—		—		(277)		(830)		—		—
Prior service cost (credit)	Prior service cost (credit)	—		—		—		—		205		44		Prior service cost (credit)	—		—		—		—		38		205
Amortization of prior service (cost) credit	Amortization of prior service (cost) credit	1,904		1,980		(349)		(349)		(6)		—		Amortization of prior service (cost) credit	—		1,904		(289)		(349)		(22)		(6)
Total change in other comprehensive income for year	Total change in other comprehensive income for year	$	(71,247)	$	5,671	$	(2,515)	$	(3,614)	$	(926)	$	841	Total change in other comprehensive income for year	$	6,354	$	(71,247)	$	(8,297)	$	(2,515)	$	(1,423)	$	(926)

~~121~~


Puget Sound Energy	Puget Sound Energy	Qualified Pension Benefit				SERP Pension Benefits				Other Benefits				Puget Sound Energy	Qualified Pension Benefit				SERP Pension Benefits				Other Benefits
(Dollars in Thousands)	(Dollars in Thousands)	2021		2020		2021		2020		2021		2020		(Dollars in Thousands)	2022		2021		2022		2021		2022		2021
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:	Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:													Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	Net loss (gain)	$	(61,345)	$	11,858	$	828	$	3,663	$	(1,164)	$	715	Net loss (gain)	$	12,736	$	(61,345)	$	(5,260)	$	828	$	(1,468)	$	(1,164)
Amortization of net (loss) gain	Amortization of net (loss) gain	(21,862)		(19,043)		(2,343)		(2,385)		53		137		Amortization of net (loss) gain	(15,080)		(21,862)		(2,648)		(2,343)		35		53
Settlements, mergers, sales, and closures	Settlements, mergers, sales, and closures	—		—		(886)		(5,248)		—		—		Settlements, mergers, sales, and closures	—		—		(331)		(886)		—		—
Prior service cost (credit)	Prior service cost (credit)	—		—		—		—		205		44		Prior service cost (credit)	—		—		—		—		38		205
Amortization of prior service (cost) credit	Amortization of prior service (cost) credit	1,513		1,573		(349)		(349)		(6)		—		Amortization of prior service (cost) credit	—		1,513		(289)		(349)		(22)		(6)
Total change in other comprehensive income for year	Total change in other comprehensive income for year	$	(81,694)	$	(5,612)	$	(2,750)	$	(4,319)	$	(912)	$	896	Total change in other comprehensive income for year	$	(2,344)	$	(81,694)	$	(8,528)	$	(2,750)	$	(1,417)	$	(912)

The aggregate expected contributions by the Company to fund the qualified pension plan, SERP and the other postretirement plans for the year ending December 31, ~~2022,~~2023, are expected to be at least $18.0 million, ~~$2.8~~$3.5 million and $0.3 million, respectively.

124

Assumptions

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


		Qualified Pension Benefits						SERP Pension Benefits						Other Benefits							Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
Benefit Obligation Assumptions		2021		2020		2019		2021		2020		2019		2021		2020		2019
Benefit Obligation Assumptions:																				Benefit Obligation Assumptions:	2022		2021		2020		2022		2021		2020		2022		2021		2020
Discount rate	Discount rate	3.00	%	2.70	%	3.35	%	3.00	%	2.70	%	3.35	%	3.00	%	2.70	%	3.35	%	Discount rate	5.60	%	3.00	%	2.70	%	5.60	%	3.00	%	2.70	%	5.60	%	3.00	%	2.70	%
Rate of compensation increase	Rate of compensation increase	4.50		4.50		4.50		4.50		4.50		4.50		4.50		4.50		4.50		Rate of compensation increase	4.50		4.50		4.50		4.50		4.50		4.50		4.50		4.50		4.50
Interest crediting rate	Interest crediting rate	4.00		4.00		4.00		N/A		N/A		N/A		N/A		N/A		N/A		Interest crediting rate	4.00		4.00		4.00		N/A		N/A		N/A		N/A		N/A		N/A

Benefit Cost Assumptions
Benefit Cost Assumptions:																				Benefit Cost Assumptions:
Discount rate	Discount rate	2.70		3.35		4.40		2.70		3.35		4.40		2.70		3.35		4.40		Discount rate	3.00		2.70		3.35		3.00		2.70		3.35		3.00		2.70		3.35
Return on plan assets	Return on plan assets	6.50		7.15		7.50		—		—		—		7.00		7.00		7.00		Return on plan assets	6.50		6.50		7.15		—		—		—		7.00		7.00		7.00
Rate of compensation increase	Rate of compensation increase	4.50		4.50		4.50		4.50		4.50		4.50		4.50		4.50		4.50		Rate of compensation increase	4.50		4.50		4.50		4.50		4.50		4.50		4.50		4.50		4.50
Interest crediting rate	Interest crediting rate	4.00		4.00		4.00		N/A		N/A		N/A		N/A		N/A		N/A		Interest crediting rate	4.00		4.00		4.00		N/A		N/A		N/A		N/A		N/A		N/A

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

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

The discount rates were determined by using market interest rate data and the weighted-average discount rate from the FTSE Pension Discount Curve (formerly known as the Citigroup Pension Liability Index ~~Curve.~~Curve). The Company also takes into account in determining the discount rate the expected changes in market interest rates and anticipated changes in the duration of the plan liabilities. The Company's projected benefit obligation for pension plans experienced an actuarial ~~loss~~gain of ~~$6.8~~$215.0 million in ~~2021.~~2022. This is primarily due to the ~~decrease~~increase in the discount rate used in measuring the benefit obligation. ~~As of December 31,2019, PSE terminated the previous group retiree~~

~~122~~

~~medical plan and created an HRA. As a result, medical inflation is no longer applicable in accounting for the related benefit obligation.~~

Plan Benefits

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


(Dollars in Thousands)	(Dollars in Thousands)	2022		2023		2024		2025		2026		2027-2031		(Dollars in Thousands)	2023		2024		2025		2026		2027		2028-2032
Qualified Pension total benefits	Qualified Pension total benefits	$	46,900	$	47,900	$	49,100	$	50,400	$	51,300	$	265,200	Qualified Pension total benefits	$	46,500	$	47,800	$	48,700	$	49,900	$	50,700	$	260,700
SERP Pension total benefits	SERP Pension total benefits	2,822		3,881		6,786		7,796		2,265		17,047		SERP Pension total benefits	3,532		1,844		7,634		2,271		10,956		7,479
Other Benefits total with Medicare Part D subsidy		962		925		896		877		860		4,012
Other Benefits total without Medicare Part D subsidy		962		925		896		877		860		4,012
Other Benefits total														Other Benefits total	912		890		881		879		854		3,829

125

Plan Assets

Plan contributions and the actuarial present value of accumulated plan benefits are prepared based on certain assumptions pertaining to interest rates, inflation rates and employee demographics, all of which are subject to change. Due to uncertainties inherent in the estimations and assumptions process, changes in these estimates and assumptions in the near term may be material to the financial statements.

The Company has a Retirement Plan Committee that establishes investment policies, objectives and strategies designed to balance expected return with a prudent level of risk. All changes to the investment policies are reviewed and approved by the Retirement Plan Committee prior to being implemented.

The Retirement Plan Committee invests trust assets with investment managers who have historically achieved above-median long-term investment performance within the risk and asset allocation limits that have been established. Interim evaluations are routinely performed with the assistance of an outside investment consultant.

To obtain the desired return needed to fund the pension benefit plans, the Retirement Plan Committee has established investment allocation percentages by asset classes as follows:


		Allocation							Allocation
Asset Class	Asset Class	Minimum		Target		Maximum		Asset Class	Minimum		Target		Maximum
Domestic large cap equity	Domestic large cap equity	25	%	31	%	40	%	Domestic large cap equity	25	%	31	%	40	%
Domestic small cap equity	Domestic small cap equity	—		9		15		Domestic small cap equity	—		9		15
Non-U.S. equity	Non-U.S. equity	10		25		30		Non-U.S. equity	10		25		30
Fixed income	Fixed income	15		25		30		Fixed income	25		35		40
Real estate	Real estate	—		—		10		Real estate	—		—		10
Absolute return		5		10		15

Cash	Cash	—		—		5		Cash	—		—		5

Plan Fair Value Measurements

ASC 715, “Compensation – Retirement Benefits” (ASC 715) directs companies to provide additional disclosures about plan assets of a defined benefit pension or other postretirement plan. The objectives of the disclosures are to disclose the following: (i) how investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies; (ii) major categories of plan assets; (iii) inputs and valuation techniques used to measure the fair value of plan assets; (iv) effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period; and (v) significant concentrations of risk within plan assets.

ASC 820 allows the reporting entity, as a practical expedient, to measure the fair value of investments that do not have readily determinable fair values on the basis of the net asset value per share of the investment if the net asset value of the investment is calculated in a matter consistent with ASC 946, “Financial Services – Investment Companies”. The standard requires disclosures about the nature and risk of the investments and whether the investments are probable of being sold at amounts different from the net asset value per share.

~~123~~126

The following table sets forth by level, within the fair value hierarchy, the qualified pension plan as of December 31, ~~2021,~~2022, and ~~2020:~~2021:

Recurring Fair Value Measures Recurring Fair Value Measures
December 31, 2021 December 31, 2020
(Dollars in Thousands) Level 1 Level 2 Other Total Level 1 Level 2 Other Total
Assets:
Common Stock
–Domestic
$ 249,021 $ 99 $ — $ 249,120 $ 228,247 $ 53 $ — $ 228,300
–Foreign
25,963 — — 25,963 19,216 — — 19,216
Government Securities 65,266 2,470 — 67,736 73,006 9,148 — 82,154
Corporate Securities
–Domestic
— 12,820 — 12,820 — 6,082 — 6,082
–Foreign
— 5,239 — 5,239 — 3,699 — 3,699
Cash and cash equivalents 3,638 (540) — 3,098 4,612 3,223 — 7,835
Investments measured at NAV
- Collective Investment Funds — — 359,861 359,861 — — 342,014 342,014
- Partnership — — 115,570 115,570 — — 107,137 107,137
- Mutual Funds — — 80,724 80,724 — — 82,103 82,103
- Other — — 1,434 1,434 — — 1,096 1,096
Net (payable) receivable — — (23,015) (23,015) — — (44,981) (44,981)
Total assets $ 343,888 $ 20,088 $ 534,574 $ 898,550 $ 325,081 $ 22,205 $ 487,369 $ 834,655


	Recurring Fair Value Measures								Recurring Fair Value Measures
	December 31, 2022								December 31, 2021
(Dollars in Thousands)	Level 1		Level 2		Other		Total		Level 1		Level 2		Other		Total
Assets:

Common Stock:
Domestic	$	175,969	$	298	$	—	$	176,267	$	249,021	$	99	$	—	$	249,120
Foreign	17,767		—		—		17,767		25,963		—		—		25,963
Government Securities	61,693		8,828		—		70,521		65,266		2,470		—		67,736
Corporate Securities:
Domestic	—		16,005		—		16,005		—		12,820		—		12,820
Foreign	—		6,525		—		6,525		—		5,239		—		5,239
Cash and cash equivalents	4,678		(632)		—		4,046		3,638		(540)		—		3,098
Investments measured at NAV:
Collective Investment Funds	—		—		262,910		262,910		—		—		359,861		359,861
Partnership	—		—		86,827		86,827		—		—		115,570		115,570
Mutual Funds	—		—		46,005		46,005		—		—		80,724		80,724
Other	—		—		846		846		—		—		1,434		1,434
Net (payable) receivable	—		—		(29,186)		(29,186)		—		—		(23,015)		(23,015)
Total assets	$	260,107	$	31,024	$	367,402	$	658,533	$	343,888	$	20,088	$	534,574	$	898,550

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


		Recurring Fair Value Measures								Recurring Fair Value Measures									Recurring Fair Value Measures								Recurring Fair Value Measures
		December 31, 2021								December 31, 2020									December 31, 2022								December 31, 2021
(Dollars in Thousands)	(Dollars in Thousands)	Level 1		Level 2		Other		Total		Level 1		Level 2		Other		Total		(Dollars in Thousands)	Level 1		Level 2		Other		Total		Level 1		Level 2		Other		Total
Assets:	Assets:																	Assets:
Money Markets	Money Markets	$	4	$	—	$	—	$	4	$	—	$	—	$	—	$	—	Money Markets	$	—	$	—	$	—	$	—	$	4	$	—	$	—	$	4
Mutual fund	Mutual fund	—		6,337		—		6,337		5,916		—		—		5,916		Mutual fund	—		5,190		—		5,190		—		6,337		—		6,337

Net (payable) receivable	Net (payable) receivable	—		—		—		—		—		—		2		2		Net (payable) receivable	—		—		—		—		—		—		—		—
Total assets	Total assets	$	4	$	6,337	$	—	$	6,341	$	5,916	$	—	$	2	$	5,918	Total assets	$	—	$	5,190	$	—	$	5,190	$	4	$	6,337	$	—	$	6,341

The following discussion provides information regarding the methods used in valuation of the various asset class investments held for the pension and other postretirement benefit plans.

•Mutual funds classified as Level 1 securities have pricing inputs that are based on unadjusted prices in an active market. Principal markets for equity prices include published exchanges such as NASDAQ and New York Stock Exchange (NYSE). Mutual fund assets not included in the fair value hierarchy are privately held funds. These funds are not actively traded and utilize net asset value (NAV) as a practical expedient to measure fair value.

•Common stock investments are traded in active markets on national and international securities exchanges and are valued at closing prices on the last business day of each period presented. They are classified as Level 1 securities.

•Corporate and some government debt securities are valued using pricing models maximizing the use of observable inputs for similar securities. This includes basing value on yields currently available on comparable securities of issuers with similar credit ratings. Some government debt securities have quoted prices such as certain treasury securities and are classified as Level 1 securities.

~~124~~127

•Cash and cash equivalents comprise mostly of money market funds and foreign currency held. Money market funds are classified as Level 1 instruments as pricing inputs are based on unadjusted prices in an active market while foreign currency held is classified as a Level 2 investment based on inputs that are indirectly observable.

•Investments in collective trust funds and partnerships are stated at the NAV as determined by the issuer of fund and are based on the fair value of the underlying investments held by the fund less its liabilities. The NAV is used as a practical expedient to estimate fair value. These funds are primarily invested in a blend of corporate and government debt securities as well as international equities.

(14) Income Taxes

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


Puget Energy	Puget Energy	Year Ended December 31,						Puget Energy	Year Ended December 31,
(Dollars in Thousands)	(Dollars in Thousands)	2021		2020		2019		(Dollars in Thousands)	2022		2021		2020
Charged to operating expenses:	Charged to operating expenses:							Charged to operating expenses:
Current:	Current:							Current:
Federal	Federal	$	25,395	$	7,962	$	9,424	Federal	$	41,198	$	25,395	$	7,962
State	State	721		7		164		State	628		721		7
Deferred:	Deferred:							Deferred:
Federal	Federal	(1,759)		(6,414)		7,357		Federal	17,866		(1,759)		(6,414)
State	State	158		109		128		State	6		158		109
Total income tax expense	Total income tax expense	$	24,515	$	1,664	$	17,073	Total income tax expense	$	59,698	$	24,515	$	1,664


Puget Sound Energy	Puget Sound Energy	Year Ended December 31,						Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	(Dollars in Thousands)	2021		2020		2019		(Dollars in Thousands)	2022		2021		2020
Charged to operating expenses:	Charged to operating expenses:							Charged to operating expenses:
Current:	Current:							Current:
Federal	Federal	$	52,616	$	10,607	$	18,093	Federal	$	81,597	$	52,616	$	10,607
State	State	670		383		570		State	869		670		383
Deferred:	Deferred:							Deferred:
Federal	Federal	(9,027)		15,252		20,485		Federal	(2,171)		(9,027)		15,252
State	State	—		—		—		State	—		—		—
Total income tax expense	Total income tax expense	$	44,259	$	26,242	$	39,148	Total income tax expense	$	80,295	$	44,259	$	26,242

~~125~~128

The following reconciliation compares pre-tax book income at the federal statutory rate of 21.0% to the actual income tax expense in the Statements of Income:


Puget Energy	Puget Energy	Year Ended December 31,									Puget Energy	Year Ended December 31,
(Dollars in Thousands)	(Dollars in Thousands)	2021			2020			2019			(Dollars in Thousands)	2022			2021			2020
Income taxes at the statutory rate	Income taxes at the statutory rate	$	59,927		$	38,720		$	47,834		Income taxes at the statutory rate	$	99,549		$	59,927		$	38,720
Increase (decrease):	Increase (decrease):										Increase (decrease):
Utility plant differences1	Utility plant differences1	$	(22,325)		$	(22,991)		$	(23,025)		Utility plant differences1	$	(23,028)		$	(22,325)		$	(22,991)
AFUDC, net	AFUDC, net	1,509			(6,095)			(4,462)			AFUDC, net	(3,567)			1,509			(6,095)
Executive compensation	Executive compensation	1,386			2,440			2,596			Executive compensation	1,821			1,386			2,440
Treasury grant amortization	Treasury grant amortization	(5,424)			(8,935)			(7,870)			Treasury grant amortization	(5,717)			(5,424)			(8,935)
Excess deferred tax amortization	Excess deferred tax amortization	(13,392)			(3,038)			—			Excess deferred tax amortization	(13,722)			(13,392)			(3,038)
Other–net	Other–net	2,834			1,563			2,000			Other–net	4,362			2,834			1,563
Total income tax expense	Total income tax expense	$	24,515		$	1,664		$	17,073		Total income tax expense	$	59,698		$	24,515		$	1,664
Effective tax rate	Effective tax rate	8.6		%	0.9		%	7.5		%	Effective tax rate	12.6		%	8.6		%	0.9		%


Puget Sound Energy	Puget Sound Energy	Year Ended December 31,									Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	(Dollars in Thousands)	2021			2020			2019			(Dollars in Thousands)	2022			2021			2020
Income taxes at the statutory rate	Income taxes at the statutory rate	$	79,868		$	63,110		$	69,735		Income taxes at the statutory rate	$	119,962		$	79,868		$	63,110
Increase (decrease):	Increase (decrease):										Increase (decrease):
Utility plant differences1	Utility plant differences1	$	(22,325)		$	(22,991)		$	(23,025)		Utility plant differences1	$	(23,028)		$	(22,325)		$	(22,991)
AFUDC, net	AFUDC, net	1,509			(6,095)			(4,462)			AFUDC, net	(3,567)			1,509			(6,095)
Executive compensation	Executive compensation	1,386			2,440			2,596			Executive compensation	1,821			1,386			2,440
Treasury grant amortization	Treasury grant amortization	(5,424)			(8,935)			(7,870)			Treasury grant amortization	(5,717)			(5,424)			(8,935)
Excess deferred tax amortization	Excess deferred tax amortization	(13,392)			(3,038)			—			Excess deferred tax amortization	(13,722)			(13,392)			(3,038)
Other–net	Other–net	2,637			1,751			2,174			Other–net	4,546			2,637			1,751
Total income tax expense	Total income tax expense	$	44,259		$	26,242		$	39,148		Total income tax expense	$	80,295		$	44,259		$	26,242
Effective tax rate	Effective tax rate	11.6		%	8.7		%	11.8		%	Effective tax rate	14.1		%	11.6		%	8.7		%

_______________

1.Utility plant differences include the reversal of excess deferred taxes using the average rate assumption method in the amount of $27.2 million and $27.6 million in ~~both~~2022 and 2021, ~~and 2020.~~respectively.

129

The Company’s net deferred tax liability at December 31, ~~2021,~~2022, and ~~2020,~~2021, is composed of amounts related to the following types of temporary differences:


Puget Energy	Puget Energy	At December 31,				Puget Energy	At December 31,
(Dollars in Thousands)	(Dollars in Thousands)	2021		2020		(Dollars in Thousands)	2022		2021
Utility plant and equipment	Utility plant and equipment	$	1,892,674	$	1,923,933	Utility plant and equipment	$	1,853,450	$	1,892,692
Unrealized gain on derivative instruments						Unrealized gain on derivative instruments	158,175		50,971
Other deferred tax liabilities	Other deferred tax liabilities	202,783		175,333		Other deferred tax liabilities	365,035		313,270
Subtotal deferred tax liabilities	Subtotal deferred tax liabilities	2,095,457		2,099,266		Subtotal deferred tax liabilities	2,376,660		2,256,933
Net operating loss carryforward	Net operating loss carryforward	(254,007)		(261,260)		Net operating loss carryforward	(234,825)		(254,007)
Net regulatory liability for income taxes	Net regulatory liability for income taxes	(865,976)		(953,274)		Net regulatory liability for income taxes	(811,161)		(865,976)
Production tax credit carryforward		—		(35,995)

Other deferred tax assets	Other deferred tax assets	(62,990)		(38,008)		Other deferred tax assets	(299,597)		(184,023)
Unrealized loss on derivative instruments						Unrealized loss on derivative instruments	(45,130)		(40,443)
Subtotal deferred tax assets	Subtotal deferred tax assets	(1,182,973)		(1,288,537)		Subtotal deferred tax assets	(1,390,713)		(1,344,449)
Total net deferred tax liabilities	Total net deferred tax liabilities	$	912,484	$	810,729	Total net deferred tax liabilities	$	985,947	$	912,484

~~126~~


Puget Sound Energy	Puget Sound Energy	At December 31,				Puget Sound Energy	At December 31,
(Dollars in Thousands)	(Dollars in Thousands)	2021		2020		(Dollars in Thousands)	2022		2021
Utility plant and equipment	Utility plant and equipment	$	1,892,674	$	1,923,933	Utility plant and equipment	$	1,852,644	$	1,892,674
Other, net deferred tax liabilities		121,060		91,438
Unrealized gain on derivative instruments						Unrealized gain on derivative instruments	143,147		31,940
Other deferred tax liabilities						Other deferred tax liabilities	279,612		225,753
Subtotal deferred tax liabilities	Subtotal deferred tax liabilities	2,013,734		2,015,371		Subtotal deferred tax liabilities	2,275,403		2,150,367
Net regulatory liability for income taxes	Net regulatory liability for income taxes	(866,541)		(953,987)		Net regulatory liability for income taxes	(811,724)		(866,541)
Production tax credit carryforward		—		(35,995)

Other deferred tax assets	Other deferred tax assets	(62,990)		(38,007)		Other deferred tax assets	(293,977)		(178,211)
Unrealized loss on derivative instruments						Unrealized loss on derivative instruments	(30,102)		(21,412)
Subtotal deferred tax assets	Subtotal deferred tax assets	(929,531)		(1,027,989)		Subtotal deferred tax assets	(1,135,803)		(1,066,164)
Total net deferred tax liabilities	Total net deferred tax liabilities	$	1,084,203	$	987,382	Total net deferred tax liabilities	$	1,139,600	$	1,084,203

The Company calculates its deferred tax assets and liabilities under ASC 740, “Income Taxes” (ASC 740). ASC 740 requires recording deferred tax balances, at the currently enacted tax rate, on assets and liabilities that are reported differently for income tax purposes than for financial reporting purposes. The utilization of deferred tax assets requires sufficient taxable income in future years. ASC 740 requires a valuation allowance on deferred tax assets when it is more likely than not that the deferred tax assets will not be realized. PSE fully utilized ~~it’s~~its PTC balance in 2021 and ~~has~~had no carryforwards at the end of 2021. Puget Energy’s net operating loss carryforwards expire from 2029 through 2037. Net operating losses generated in 2018 and thereafter have no expiration date. No valuation allowance has been provided for net operating loss carryforwards.

Unrecognized Tax Benefits

The Company accounts for uncertain tax positions under ASC 740, which clarifies the accounting for uncertainty in income taxes recognized in the financial statements. ASC 740 requires the use of a two-step approach for recognizing and measuring tax positions taken or expected to be taken in a tax return. First, a tax position should only be recognized when it is more likely than not, based on technical merits, that the position will be sustained upon challenge by the taxing authorities and taken by management to the court of last resort. Second, a tax position that meets the recognition threshold should be measured at the largest amount that has a greater than 50.0% likelihood of being sustained.

As of December 31, ~~2021,~~2022, and ~~2020,~~2021, the Company had no material unrecognized tax benefits. As a result, no interest or penalties were accrued for unrecognized tax benefits during the year.

On July 30, 2021, the IRS issued a PLR to PSE which concluded that the Washington Commission’s methodology for reversing plant-related excess deferred income taxes was an impermissible methodology under the IRS normalization and consistency rules. The PLR requires adjustments to PSE's rates to bring PSE back into compliance with IRS rules. Accordingly, on September 28, 2021, the Washington Commission issued an order amending their previous order to correct the impermissible methodology and adjust customer rates in accordance with the PLR. For more information, see Note 4, "Regulation and Rates," to the consolidated financial statements included in Item 8 of this report.

The Company has open tax years from ~~2018~~2019 through ~~2021.~~2022. The Company classifies interest as interest expense and penalties as other expense in the financial statements.

130

(15) Litigation

From time to time, the Company is involved in litigation or legislative rulemaking proceedings relating to its operations in the normal course of business. The following is a description of pending proceedings that are material to PSE’s operations:

Colstrip

PSE has a 50% ownership interest in Colstrip Units 1 and 2 and a 25% interest in each of Colstrip Units 3 and ~~4. As part of a settlement that was signed by all~~4, which are coal-fired generating units located in Colstrip, owners, Colstrip Units 1 and 2 owners, PSE and Talen Energy Corporation (Talen), agreed to retire the two oldest units (Units 1 and 2) at Colstrip no later than July 1, 2022. Depreciation rates were updated in the 2017 GRC, where PSE's depreciation increased for Colstrip Units 1 and 2 to recover plant costs to the expected shutdown date. Additionally,Montana. PSE has accelerated the depreciation of Colstrip Units 3 and 4 ~~per the terms of the GRC settlement,~~ to December 31, ~~2027.~~2025 as part of the 2019 GRC. The 2017 GRC ~~also~~ repurposed PTCs and hydro-related treasury grants to recover unrecovered plant costs and to fund and recover decommissioning and remediation costs for Colstrip Units 1 through 4. On September 2, 2022, PSE and Talen Energy reached an agreement to transfer PSE's ownership interest in Colstrip Units 3 and 4 to Talen Energy on December 31, 2025. Management evaluated Colstrip Units 3 and 4 and determined that the applicable held for sale accounting criteria were not met as of December 31, 2022. As such, Colstrip Units 3 and 4 are classified as Electric Utility Plant on the Company's balance sheet as of December 31, 2022.

Consistent with a June 2019 announcement, Talen permanently shut down Units 1 and 2 onat the end of 2019 due to operational losses associated with the Units. Colstrip Units 1 and 2 were retired effective December 31, 2019.

~~127~~

The Washington Clean Energy ~~Transition~~Transformation Act requires the Washington Commission to provide recovery of the investment, decommissioning, and remediation costs associated with the facilities that are not recovered through the repurposed ~~PTC's~~PTCs and hydro-related treasury grants. The full scope of decommissioning activities and costs may vary from the estimates that are available at this time. ~~Colstrip Unit 4 is classified as Electric Utility Plant on the balance sheet, see Note 6, "Utility Plant," to the consolidated financial statements in Item 8 of this report.~~

On May 4,19, 2021, PSE along with the Colstrip owners, Avista Corporation, PacifiCorp and Portland General Electric Company filed a lawsuit against the ~~state of~~ Montana ~~after Montana Governor Greg Gianforte signed Senate Bill 265 and 266 into law. The litigation challenged~~Attorney General challenging the constitutionality of Montana Senate Bill 266. On October 13, 2021, the United States District Court for the District of Montana issued a preliminary injunction finding it likely that Senate Bill 266 unconstitutionally violates the ~~commerce clause~~Commerce Clause and Contract Clause of the United States Constitution. Since then, a motion for summary judgment was filed requesting ~~that~~a permanent injunction against enforcement of Senate Bill 266. On September 29, 2022, the ~~findings of the preliminary injunction be made permanent. As of December 31, 2021, the Company is not able to predict the outcome, nor an amount or range of potential impact~~magistrate judge in the ~~event of an outcome that is adverse~~District Court proceeding issued a recommendation to the ~~Company’s interests.~~presiding U.S. District Court Judge that a permanent injunction against enforcement of Senate Bill 266 be granted. On October 18, 2022, the U.S. District Court Judge accepted in full the magistrate judge recommendation for a permanent injunction against enforcement of Senate Bill 266.

Puget LNG

In January 2018, the Puget Sound Clean Air Agency (PSCAA) determined a Supplemental Environmental Impact Statement (SEIS) was necessary in order to rule on the air quality permit for the facility. In December 2019, PSCAA issued the air quality permit for the facility, a decision which was appealed to the Washington Pollution Control Hearings Board (PCHB) by each of the Puyallup Tribe of Indians and nonprofit law firm Earthjustice. In November 2021, the PCHB affirmed the PSCAA ruling in PSE's favor. In December 2021, the PCHB decision was appealed with the Pierce County Superior Court by each of the Puyallup Tribe of Indians and nonprofit law firm Earthjustice. The appeal did not delay commissioning or commercial operations at the plant, which ~~was completed~~commenced on February 1, 2022. ~~Puget LNG is expected to commence commercial operations in 2022.~~

~~Regional Haze Rule~~

In January 2017, the EPA published revisions to the Regional Haze Rule. Among other things, these revisions delayed new Regional Haze review from 2018 to 2021, however the end date will remain 2028. In January 2018, the EPA announced that it was reconsidering certain aspects of these revisions and PSE is unable to predict the outcome. Challenges to the 2017 Regional Haze Revision Rule are being held in abeyance in the U.S. Court of Appeals for the D.C. Circuit, pending resolution of the EPA’s reconsideration of the rule.

~~Clean Air Act 111(d)/EPA Affordable Clean Energy Rule~~

In August 2018, the EPA proposed the Affordable Clean Energy (ACE) rule, pursuant to Section 111(d) of the Clean Air Act. The ACE rule was finalized in June 2019, and establishes emission guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired plants. On January 19, 2021 the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the ACE rule and remanded the record back to the Agency for further consideration consistent with its opinion, finding that it misinterpreted the Clean Air Act. That matter is now pending before the US Supreme Court.

~~Washington Clean Air Rule~~

The Washington Clean Air Rule (CAR) was adopted by the state of Washington’s Department of Ecology in September 2016 and was intended to reduce greenhouse gas emissions from “covered entities” located within Washington, including large manufacturers, petroleum producers and natural gas utilities, including PSE. In September 2016, PSE, along with Avista Corporation, Cascade Natural Gas Corporation and NW Natural, filed lawsuits in both the U.S. District Court for the Eastern District of Washington and in the Superior Court of the State of Washington for Thurston County challenging the CAR. In March 2018, the Superior Court of the State of Washington for Thurston County invalidated the CAR. After an appeal by the Washington Department of Ecology, in January 2020, the Washington Supreme Court affirmed that CAR is not valid for “indirect emitters”, meaning it does not apply to the sale of natural gas for use by customers. The court ruled, however, that the rule can be severed and is valid for direct emitters including electric utilities with permitted air emission sources, and remanded the case back to the Thurston County to determine which parts of the rule survive. The Department of Ecology and the four parties asked Thurston County to stay this case until the 2020 Washington State legislative session concluded; the Department of Ecology has asked the court to extend the stay until the COVID-19 pandemic is over. Meanwhile, the four companies moved to voluntarily dismiss the federal court litigation without prejudice in March 2020.

Notably, the Climate Commitment Act, adopted by the state of Washington in 2021, prohibits the Department of Ecology from adopting or enforcing a program that regulates greenhouse gas emissions from a stationary source except as provided in the Act, which could effectively preempt the CAR.

~~128~~

(16) Commitments and Contingencies

For the year ended December 31, ~~2021,~~2022, approximately ~~13.3%~~16.4% of the Company’s energy output was obtained at an average cost of approximately $0.034 per Kilowatt Hour (kWh) through long-term contracts with 3three of the Washington Public Utility Districts (PUDs) that own hydroelectric projects on the Columbia River. The purchase of power from the Columbia River projects is on a pro rata share basis under which the Company pays a proportionate share of the annual debt service, operating and maintenance costs and other expenses associated with each project, in proportion to the contractual share of power that PSE obtains from that project. In these instances, PSE’s payments are not contingent upon the projects being operable; therefore, PSE is required to make the payments even if power is not delivered. These projects are financed substantially through debt service payments and their annual costs should not vary significantly over the term of the contracts unless additional financing is required to meet the costs of major maintenance, repairs or replacements, or license requirements. The Company’s share of the costs and the output of the projects is subject to reduction due to various withdrawal rights of the PUDs and others over the contract lives.

131

The Company's expenses under these PUD contracts were as follows for the years ended December ~~31, :~~31:


(Dollars in Thousands)	(Dollars in Thousands)	2021		2020		2019		(Dollars in Thousands)	2022		2021		2020
PUD contract costs	PUD contract costs	$	117,812	$	116,874	$	87,135	PUD contract costs	$	149,575	$	117,812	$	116,874

As of December 31, ~~2021,~~2022, the Company purchased portions of the power output of the PUDs' projects as set forth in the following table:


			Company's Current Share of													Company's Share of
(Dollars in Thousands)	(Dollars in Thousands)	Contract Expiration	Percent of Output		Megawatt Capacity	Estimated 2022 Costs		2022 Debt Service Costs		Interest included in 2022 Debt Service Costs		Debt Outstanding		(Dollars in Thousands)	Contract Expiration	2023 Percent of Output		2023 Megawatt Capacity	Estimated 2023 Total Costs		2023 Debt Service Costs		Interest included in 2023 Debt Service Costs		Debt Outstanding
Chelan County PUD:
Chelan County PUD1:														Chelan County PUD1:
Rock Island Project	Rock Island Project	2031	30.0	%	187	$	43,568	$	12,074	$	5,484	$	99,510	Rock Island Project	2031	30.0	%	187	$	47,892	$	12,072	$	5,132	$	93,493
Rocky Reach Project	Rocky Reach Project	2031	30.0		390	43,942		5,056		2,090		36,723		Rocky Reach Project	2031	30.0		390	54,022		5,039		1,907		33,757
Douglas County PUD:
Wells Project1		2028	31.1		261	43,095		—		—		—
Grant County PUD:
Douglas County PUD2:														Douglas County PUD2:
Wells Project														Wells Project	2028	32.8		276	45,489		—		—		—
Grant County PUD3:														Grant County PUD3:
Priest Rapids Development	Priest Rapids Development	2052	0.6		6	1,749		894		450		11,276		Priest Rapids Development	2052	4.8		45	28,243		747		376		9,768
Wanapum Development	Wanapum Development	2052	0.6		7	1,749		894		450		11,276		Wanapum Development	2052	4.8		58	28,243		747		376		9,768
Total	Total				851	$	134,103	$	18,918	$	8,474	$	158,785	Total				956	$	203,889	$	18,605	$	7,791	$	146,786

_______________

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.

2.In March 2021, PSE entered into a new PPA with Chelan County PUD for additional Rocky Reach and Rock Island output. The contract ~~begins~~began on January 1, 2022, and continues through December 31, 2026. This agreement increases PSE’s share of output by 5% for each project, which equates to an additional capacity of 31MW for Rock Island and 65MW for Rocky Reach.

2.In March 2021, PSE entered into a new agreement with Douglas County PUD for the extension of the Wells Project Output that began on October 1, 2021, and continues through September 30, 2024. This agreement increases PSE's share of output by 5.5% for the Wells Project, which equates to an additional capacity of 46MW.

~~129~~3.In November 2022, PSE elected to take its portion of the Priest Rapid Meaningful Priority and was granted 4.13% share of the 2023 Priest Rapids Project output. This one-year contract begins on January 1, 2023, and continues through December 31, 2023. This agreement increases PSE's share of output by 4.13%, which equates to an additional capacity of 39MW for Priest Rapids Development and 51 MW for Wanapum Development.

The following table summarizes the Company’s estimated payment obligations for power purchases from the Columbia River projects, electric portfolio contracts and electric wholesale market transactions. These contracts have varying terms and may include escalation and termination provisions.


(Dollars in Thousands)	(Dollars in Thousands)	2022		2023		2024		2025		2026		Thereafter		Total		(Dollars in Thousands)	2023		2024		2025		2026		2027		Thereafter		Total
Columbia River projects	Columbia River projects	$	151,378	$	136,635	$	134,188	$	124,724	$	123,243	$	421,272	$	1,091,440	Columbia River projects	$	191,618	$	145,078	$	140,887	$	138,482	$	123,152	$	394,875	$	1,134,092

Electric portfolio contracts	Electric portfolio contracts	330,189		377,331		384,655		344,021		142,903		1,755,102		3,334,201		Electric portfolio contracts	380,559		385,807		345,257		142,273		133,903		1,776,703		3,164,502
Electric wholesale market transactions	Electric wholesale market transactions	300,027		62,821		62,761		11,616		11,616		—		448,841		Electric wholesale market transactions	414,278		148,628		11,616		11,616		—		—		586,138
Total	Total	$	781,594	$	576,787	$	581,604	$	480,361	$	277,762	$	2,176,374	$	4,874,482	Total	$	986,455	$	679,513	$	497,760	$	292,371	$	257,055	$	2,171,578	$	4,884,732

Total purchased power contracts provided the Company with approximately 15.3 million, 13.1 million ~~13.2 million~~ and ~~12.5~~13.2 million MWhs of firm energy at a cost of approximately $892.7 million, $631.4 million ~~$491.7 million~~ and ~~$550.6~~$491.7 million for the years 2022, 2021, ~~2020,~~ and ~~2019,~~2020, respectively.

132

Natural Gas Supply Obligations

The Company has entered into various firm supply, transportation and storage service contracts in order to ensure adequate availability of natural gas supply for its customers and generation requirements. The Company contracts for its long-term natural gas supply on a firm basis, which means the Company has a 100% daily take obligation and the supplier has a 100% daily delivery obligation to ensure service to PSE’s customers and generation requirements. The transportation and storage contracts, which have remaining terms from 1 year to 2322 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage.

The Company incurred demand charges of $138.3 million, $136.4 million, ~~$135.8 million,~~ and ~~$125.1~~$135.8 million for firm transportation, storage and peaking services for its natural gas customers for the years 2022, 2021, ~~2020,~~ and ~~2019.~~2020. The Company incurred demand charges of ~~$52.8~~$53.9 million, ~~$51.2~~$52.8 million, and $51.2 million for firm transportation, storage and peaking services for the natural gas supply for its combustion turbines for the years 2022, 2021, ~~2020,~~ and ~~2019.~~2020.

The following table summarizes the Company’s obligations for future natural gas supply and demand charges through the primary terms of its existing contracts. The quantified obligations are based on the FERC and ~~Canadian~~CER (Canadian Energy ~~Regulator~~Regulator) currently authorized rates, which are subject to change.


Natural Gas Supply and Demand Charge Obligations (Dollars in Thousands)	Natural Gas Supply and Demand Charge Obligations (Dollars in Thousands)	2022		2023		2024		2025		2026		Thereafter		Total		Natural Gas Supply and Demand Charge Obligations (Dollars in Thousands)	2023		2024		2025		2026		2027		Thereafter		Total
Natural gas wholesale market transactions	Natural gas wholesale market transactions	$	564,580	$	299,400	$	210,198	$	153,054	$	98,725	$	—	$	1,325,957	Natural gas wholesale market transactions	$	1,013,547	$	377,588	$	351,129	$	255,577	$	76,453	$	—	$	2,074,294
Firm transportation service	Firm transportation service	177,185		166,153		131,611		114,470		98,847		694,279		1,382,545		Firm transportation service	175,136		146,675		112,327		94,417		94,123		570,687		1,193,365
Firm storage service	Firm storage service	8,899		2,270		68		67		56		—		11,360		Firm storage service	9,350		7,923		7,448		7,432		7,352		1,838		41,343
Total	Total	$	750,664	$	467,823	$	341,877	$	267,591	$	197,628	$	694,279	$	2,719,862	Total	$	1,198,033	$	532,186	$	470,904	$	357,426	$	177,928	$	572,525	$	3,309,002

Service Contracts

The following table summarizes the Company’s estimated obligations for service contracts through the terms of its existing contracts.


Service Contract Obligations (Dollars in Thousands)	Service Contract Obligations (Dollars in Thousands)	2022		2023		2024		2025		2026		Thereafter		Total		Service Contract Obligations (Dollars in Thousands)	2023		2024		2025		2026		2027		Thereafter		Total
Energy production service contracts	Energy production service contracts	$	31,167	$	31,916	$	32,699	$	33,468	$	17,087	$	81,854	$	228,191	Energy production service contracts	$	33,971	$	34,812	$	35,772	$	18,728	$	19,221	$	79,655	$	222,159
Automated meter reading system	Automated meter reading system	46,455		47,517		47,526		48,249		49,098		—		238,845		Automated meter reading system	50,124		47,301		47,668		48,803		—		—		193,896
Total	Total	$	77,622	$	79,433	$	80,225	$	81,717	$	66,185	$	81,854	$	467,036	Total	$	84,095	$	82,113	$	83,440	$	67,531	$	19,221	$	79,655	$	416,055

Chelan PUD Power Purchase Agreement

On February 7, 2023, PSE and Chelan PUD entered into a new power purchase agreement, under which PSE will continue to purchase 25% of the total output from the Rocky Reach and Rock Island hydroelectric projects from November 1, 2031 through October 31, 2051. Estimated payment obligations under the new power sales agreement total $3.1 billion.

Other Commitments and Contingencies

For information regarding PSE's environmental remediation obligations, see Note 4, "Regulation and Rates," to the consolidated financial statements included in Item 8 of this report.

~~130~~

(17) Related Party Transactions

The Company identified no material related party transactions during the year ended December 31, ~~2021~~2022 and December 31, ~~2020.~~2021.

133

(18) Segment Information

Puget Energy and PSE operate 1one reportable segment referred to as the regulated utility segment. Puget Energy’s regulated utility operation generates, purchases and sells electricity and purchases, transports and sells natural gas. The service territory of PSE covers approximately 6,000 square miles in the state of Washington.

~~131~~

(19) Accumulated Other Comprehensive Income (Loss)

The following tables present the changes in the Company’s (loss) AOCI by component for the years ended December 31, 2022, 2021, ~~2020,~~ and ~~2019,~~2020, respectively:

Puget Energy Net unrealized gain (loss) and prior service cost on pension plans
Changes in AOCI, net of tax
(Dollars in Thousands) Total
Balance at December 31, 2018 $ (77,202) $ (77,202)
Other comprehensive income (loss) before reclassifications (7,337) (7,337)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax 390 390
Net current-period other comprehensive income (loss) (6,947) (6,947)
Balance at December 31, 2019 $ (84,149) $ (84,149)
Other comprehensive income (loss) before reclassifications (9,058) (9,058)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax 6,770 6,770
Net current-period other comprehensive income (loss) (2,288) (2,288)
Balance at December 31, 2020 $ (86,437) $ (86,437)
Other comprehensive income (loss) before reclassifications 49,226 49,226
Amounts reclassified from accumulated other comprehensive income (loss), net of tax 9,779 9,779
Net current-period other comprehensive income (loss) 59,005 59,005
Balance at December 31, 2021 $ (27,432) $ (27,432)
Puget Sound Energy Net unrealized gain (loss) and prior service cost on pension plans Net unrealized gain (loss) on treasury interest rate swaps
Changes in AOCI, net of tax
(Dollars in Thousands) Total
Balance at December 31, 2018 $ (185,130) $ (5,754) $ (190,884)
Other comprehensive income (loss) before reclassifications (8,096) — (8,096)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax 10,118 385 10,503
Net current-period other comprehensive income (loss) 2,022 385 2,407
Balance at December 31, 2019 $ (183,108) $ (5,369) $ (188,477)
Other comprehensive income (loss) before reclassifications (8,717) — (8,717)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax 15,853 385 16,238
Net current-period other comprehensive income (loss) 7,136 385 7,521
Balance at December 31, 2020 $ (175,972) $ (4,984) $ (180,956)
Other comprehensive income (loss) before reclassifications 49,265 — 49,265
Amounts reclassified from accumulated other comprehensive income (loss), net of tax 18,166 384 18,550
Net current-period other comprehensive income (loss) 67,431 384 67,815
Balance at December 31, 2021 $ (108,541) $ (4,600) $ (113,141)


Puget Energy	Net unrealized gain (loss) and prior service cost on pension plans
Changes in AOCI, net of tax
(Dollars in Thousands)			Total
Balance at December 31, 2019	$	(84,149)		$	(84,149)
Other comprehensive income (loss) before reclassifications	(9,058)			(9,058)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	6,770			6,770

Net current-period other comprehensive income (loss)	(2,288)			(2,288)
Balance at December 31, 2020	$	(86,437)		$	(86,437)
Other comprehensive income (loss) before reclassifications	49,226			49,226
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	9,779			9,779

Net current-period other comprehensive income (loss)	59,005			59,005
Balance at December 31, 2021	$	(27,432)		$	(27,432)
Other comprehensive income (loss) before reclassifications	(4,559)			(4,559)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	7,217			7,217

Net current-period other comprehensive income (loss)	2,658			2,658
Balance at December 31, 2022	$	(24,774)		$	(24,774)

~~132~~134



Puget Sound Energy	Net unrealized gain (loss) and prior service cost on pension plans		Net unrealized gain (loss) on treasury interest rate swaps
Changes in AOCI, net of tax
(Dollars in Thousands)					Total
Balance at December 31, 2019	$	(183,108)	$	(5,369)		$	(188,477)
Other comprehensive income (loss) before reclassifications	(8,717)		—			(8,717)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	15,853		385			16,238

Net current-period other comprehensive income (loss)	7,136		385			7,521
Balance at December 31, 2020	$	(175,972)	$	(4,984)		$	(180,956)
Other comprehensive income (loss) before reclassifications	49,265		—			49,265
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	18,166		384			18,550

Net current-period other comprehensive income (loss)	67,431		384			67,815
Balance at December 31, 2021	$	(108,541)	$	(4,600)		$	(113,141)
Other comprehensive income (loss) before reclassifications	(4,512)		—			(4,512)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	14,223		386			14,609

Net current-period other comprehensive income (loss)	9,711		386			10,097
Balance at December 31, 2022	$	(98,830)	$	(4,214)		$	(103,044)

Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2022, 2021, ~~2020,~~ and ~~2019,~~2020, respectively, are as follows:


Puget Energy	Puget Energy								Puget Energy
(Dollars in Thousands)	(Dollars in Thousands)								(Dollars in Thousands)
Details about accumulated other comprehensive income (loss) components	Details about accumulated other comprehensive income (loss) components	Affected line item in the statement where net income (loss) is presented	Amount reclassified from accumulated other comprehensive income (loss)						Details about accumulated other comprehensive income (loss) components	Affected line item in the statement where net income (loss) is presented	Amount reclassified from accumulated other comprehensive income (loss)
			2021		2020		2019				2022		2021		2020
Net unrealized gain (loss) and prior service cost on pension plans:	Net unrealized gain (loss) and prior service cost on pension plans:								Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost	Amortization of prior service cost	(a)	$	1,549	$	1,631	$	1,648	Amortization of prior service cost	(a)	$	(311)	$	1,549	$	1,631
Amortization of net gain (loss)	Amortization of net gain (loss)	(a)	(13,928)		(10,200)		(2,142)		Amortization of net gain (loss)	(a)	(8,824)		(13,928)		(10,200)
		Total before tax	(12,379)		(8,569)		(494)			Total before tax	(9,135)		(12,379)		(8,569)
		Tax (expense) or benefit	2,600		1,799		104			Tax (expense) or benefit	1,918		2,600		1,799
		Net of tax	(9,779)		(6,770)		(390)			Net of tax	(7,217)		(9,779)		(6,770)

Total reclassification for the period	Total reclassification for the period	Net of tax	$	(9,779)	$	(6,770)	$	(390)	Total reclassification for the period	Net of tax	$	(7,217)	$	(9,779)	$	(6,770)

__________

(a) These AOCI components are included in the computation of net periodic pension cost, see Note 13, "Retirement Benefits," to the consolidated financial statements included in Item 8 of this report for additional details.

135


Puget Sound Energy	Puget Sound Energy								Puget Sound Energy
(Dollars in Thousands)	(Dollars in Thousands)								(Dollars in Thousands)
Details about accumulated other comprehensive income (loss) components	Details about accumulated other comprehensive income (loss) components	Affected line item in the statement where net income (loss) is presented	Amount reclassified from accumulated other comprehensive income (loss)						Details about accumulated other comprehensive income (loss) components	Affected line item in the statement where net income (loss) is presented	Amount reclassified from accumulated other comprehensive income (loss)
			2021		2020		2019				2022		2021		2020
Net unrealized gain (loss) and prior service cost on pension plans:	Net unrealized gain (loss) and prior service cost on pension plans:								Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost	Amortization of prior service cost	(a)	$	1,158	$	1,224	$	1,240	Amortization of prior service cost	(a)	$	(311)	$	1,158	$	1,224
Amortization of net gain (loss)	Amortization of net gain (loss)	(a)	(24,153)		(21,291)		(14,048)		Amortization of net gain (loss)	(a)	(17,693)		(24,153)		(21,291)
		Total before tax	(22,995)		(20,067)		(12,808)			Total before tax	(18,004)		(22,995)		(20,067)
		Tax (expense) or benefit	4,829		4,214		2,690			Tax (expense) or benefit	3,781		4,829		4,214
		Net of tax	(18,166)		(15,853)		(10,118)			Net of tax	(14,223)		(18,166)		(15,853)

Net unrealized gain (loss) on treasury interest rate swaps:	Net unrealized gain (loss) on treasury interest rate swaps:								Net unrealized gain (loss) on treasury interest rate swaps:
Interest rate contracts	Interest rate contracts	Interest expense	(487)		(487)		(487)		Interest rate contracts	Interest expense	(488)		(487)		(487)
		Tax (expense) or benefit	103		102		102			Tax (expense) or benefit	102		103		102
		Net of tax	(384)		(385)		(385)			Net of tax	(386)		(384)		(385)
Total reclassification for the period	Total reclassification for the period	Net of tax	$	(18,550)	$	(16,238)	$	(10,503)	Total reclassification for the period	Net of tax	$	(14,609)	$	(18,550)	$	(16,238)

____________

~~133~~136

SCHEDULE I: CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY

Puget Energy

Condensed Statements of Income and Comprehensive Income (Loss)

(Dollars in Thousands)


		Year Ended December 31,							Year Ended December 31,
		2021		2020		2019			2022		2021		2020
Non-utility expense and other	Non-utility expense and other	$	(913)	$	(1,579)	$	(1,495)	Non-utility expense and other	$	(1,206)	$	(913)	$	(1,579)
Other income (deductions):	Other income (deductions):							Other income (deductions):
Equity in earnings of subsidiary	Equity in earnings of subsidiary	337,405		277,654		294,724		Equity in earnings of subsidiary	474,873		337,405		277,654

Interest income	Interest income	4,261		4,760		6,643		Interest income	8,458		4,261		4,760
Interest expense	Interest expense	(100,002)		(123,592)		(111,716)		Interest expense	(84,051)		(100,002)		(123,592)
Income tax benefit (expense)	Income tax benefit (expense)	20,098		25,474		22,552		Income tax benefit (expense)	16,271		20,098		25,474
Net income (loss)	Net income (loss)	$	260,849	$	182,717	$	210,708	Net income (loss)	$	414,345	$	260,849	$	182,717
Comprehensive income (loss)	Comprehensive income (loss)	$	319,854	$	180,429	$	203,761	Comprehensive income (loss)	$	417,003	$	319,854	$	180,429

See accompanying notes to the condensed financial statements.

~~134~~137

Puget Energy

Condensed Balance Sheets

(Dollars in Thousands)


		December 31,					December 31,
		2021		2020			2022		2021
Assets:	Assets:					Assets:
Investment in subsidiaries	Investment in subsidiaries	$	4,446,758	$	4,279,501	Investment in subsidiaries	$	4,938,998	$	4,446,758
Other property and investments:	Other property and investments:					Other property and investments:
Goodwill	Goodwill	1,656,513		1,656,513		Goodwill	1,656,513		1,656,513
Current assets:	Current assets:					Current assets:
Cash	Cash	6,386		790		Cash	1,528		6,386
Receivables from affiliates1	Receivables from affiliates1	233,258		211,411		Receivables from affiliates1	246,317		233,258
Income tax receivables	Income tax receivables	6,006		—		Income tax receivables	532		6,006
Total current assets	Total current assets	245,650		212,201		Total current assets	248,377		245,650
Long-term assets:	Long-term assets:					Long-term assets:
Deferred income taxes	Deferred income taxes	250,820		258,033		Deferred income taxes	231,976		250,820
Other	Other	984		1,520		Other	3,370		984
Total long-term assets	Total long-term assets	251,804		259,553		Total long-term assets	235,346		251,804
Total assets	Total assets	$	6,600,725	$	6,407,768	Total assets	$	7,079,234	$	6,600,725
Capitalization and liabilities:	Capitalization and liabilities:					Capitalization and liabilities:
Common equity	Common equity	$	4,563,316	$	4,139,882	Common equity	$	4,964,089	$	4,563,316
Long-term debt	Long-term debt	1,571,287		1,714,744		Long-term debt	2,020,734		1,571,287
Total capitalization	Total capitalization	6,134,603		5,854,626		Total capitalization	6,984,823		6,134,603
Current liabilities:	Current liabilities:					Current liabilities:
Accounts payable to affiliates1	Accounts payable to affiliates1	147		349		Accounts payable to affiliates1	133		147
Accrued taxes		—		3,334

Short-term debt						Short-term debt	84,300		—
Current maturities of long-term debt	Current maturities of long-term debt	450,000		524,000		Current maturities of long-term debt	—		450,000
Interest	Interest	15,975		25,459		Interest	9,978		15,975
Total current liabilities	Total current liabilities	466,122		553,142		Total current liabilities	94,411		466,122
Commitments and contingencies (Note 16)	Commitments and contingencies (Note 16)					Commitments and contingencies (Note 16)
Total capitalization and liabilities	Total capitalization and liabilities	$	6,600,725	$	6,407,768	Total capitalization and liabilities	$	7,079,234	$	6,600,725

_______________

1 Eliminated in consolidation.

See accompanying notes to the condensed financial statements.

~~135~~138

Puget Energy

Condensed Statements of Cash Flows

(Dollars in Thousands)


		Year Ended December 31,							Year Ended December 31,
		2021		2020		2019			2022		2021		2020
Operating activities:	Operating activities:							Operating activities:
Net cash provided by (used in) operating activities	Net cash provided by (used in) operating activities	$	143,691	$	38,280	$	68,724	Net cash provided by (used in) operating activities	$	(10,197)	$	143,691	$	38,280
Investing activities:	Investing activities:							Investing activities:
Investment in subsidiaries	Investment in subsidiaries	(21,783)		—		(210,000)		Investment in subsidiaries	(50,000)		(21,783)		—
(Increase) decrease in loan to subsidiary	(Increase) decrease in loan to subsidiary	—		(31,043)		(41,708)		(Increase) decrease in loan to subsidiary	(12,176)		—		(31,043)

Net cash provided by (used in) investing activities	Net cash provided by (used in) investing activities	(21,783)		(31,043)		(251,708)		Net cash provided by (used in) investing activities	(62,176)		(21,783)		(31,043)
Financing activities:	Financing activities:							Financing activities:
Dividends paid	Dividends paid	(106,420)		(45,421)		(64,220)		Dividends paid	(16,230)		(106,420)		(45,421)
Investment from Parent	Investment from Parent	210,000		4,575		—		Investment from Parent	—		210,000		4,575
Change in short-term debts, net								Change in short-term debts, net	84,300		—		—
Issuance of long-term debts	Issuance of long-term debts	515,475		644,690		246,200		Issuance of long-term debts	448,075		515,475		644,690
Redemption of long-term debts	Redemption of long-term debts	(734,000)		(609,400)		—		Redemption of long-term debts	(450,000)		(734,000)		(609,400)
Issue costs and others	Issue costs and others	(1,367)		(1,838)		(116)		Issue costs and others	1,370		(1,367)		(1,838)
Net cash provided by (used in) by financing activities	Net cash provided by (used in) by financing activities	(116,312)		(7,394)		181,864		Net cash provided by (used in) by financing activities	67,515		(116,312)		(7,394)
Increase (decrease) in cash	Increase (decrease) in cash	5,596		(157)		(1,120)		Increase (decrease) in cash	(4,858)		5,596		(157)
Cash at beginning of year	Cash at beginning of year	790		947		2,067		Cash at beginning of year	6,386		790		947
Cash at end of year	Cash at end of year	$	6,386	$	790	$	947	Cash at end of year	$	1,528	$	6,386	$	790

See accompanying notes to the condensed financial statements.

~~136~~139

NOTES TO CONDENSED FINANCIAL STATEMENTS

(1) Basis of Presentation

Puget Energy is an energy services holding company that conducts substantially all of its business operations through its regulated subsidiary, PSE. Puget Energy also has a wholly-owned non-regulated subsidiary, named Puget LNG, LLC (Puget LNG). Puget LNG was formed in November 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. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These financial statements, in which Puget Energy’s subsidiaries have been included using the equity method, should be read in conjunction with the consolidated financial statements and notes thereto of Puget Energy included in Item 8, "Financial Statements and Supplementary Data" of this report. Puget Energy owns 100% of the common stock of its subsidiaries.

Equity earnings of subsidiary included earnings from PSE and PLNG of $473.8 million, $335.0 million ~~$274.3 million~~ and ~~$292.9~~$274.3 million for the years ended December 31, 2022, 2021, ~~2020,~~ and ~~2019,~~2020, respectively, and business combination accounting adjustments under ASC 805 recorded at Puget Energy for PSE of $1.0 million, $2.4 million ~~$3.4 million~~ and ~~$2.9~~$3.4 million for the years ended December 31, 2022, 2021, ~~2020,~~ and ~~2019,~~2020, respectively. Investment in subsidiaries includes Puget Energy business combination accounting adjustments under ASC 805 that are recorded at Puget Energy.

(2) Long-Term Debt

For information concerning Puget Energy’s long-term debt obligations, see Note 7, "Long-Term Debt" to the consolidated financial statements included in Item 8 of this report.

(3) Commitments and Contingencies

For information concerning Puget Energy’s material contingencies and guarantees, see Note 16, "Commitments and Contingencies" to the consolidated financial statements included in Item 8 of this report.

~~137~~

SCHEDULE II: VALUATION AND QUALIFYING ACCOUNTS AND RESERVES


Puget Energy and Puget Sound Energy (Dollars in Thousands)	Puget Energy and Puget Sound Energy (Dollars in Thousands)	Balance at Beginning of Period		Additions Charged to Costs and Expenses		Deductions		Balance at End of Period		Puget Energy and Puget Sound Energy (Dollars in Thousands)	Balance at Beginning of Period		Additions Charged to Costs and Expenses		Deductions		Balance at End of Period
Year Ended December 31, 2022										Year Ended December 31, 2022
Accounts deducted from assets on balance sheet:										Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable										Allowance for doubtful accounts receivable	$	34,958	$	28,316	$	21,312	$	41,962
Year Ended December 31, 2021	Year Ended December 31, 2021									Year Ended December 31, 2021
Accounts deducted from assets on balance sheet:	Accounts deducted from assets on balance sheet:									Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable	Allowance for doubtful accounts receivable	$	20,080	$	27,204	$	12,326	$	34,958	Allowance for doubtful accounts receivable	$	20,080	$	27,204	$	12,326	$	34,958
Year Ended December 31, 2020	Year Ended December 31, 2020									Year Ended December 31, 2020
Accounts deducted from assets on balance sheet:	Accounts deducted from assets on balance sheet:									Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable	Allowance for doubtful accounts receivable	$	8,294	$	23,292	$	11,506	$	20,080	Allowance for doubtful accounts receivable	$	8,294	$	23,292	$	11,506	$	20,080
Year Ended December 31, 2019
Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable		$	8,408	$	17,633	$	17,747	$	8,294

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

None.

140

ITEM 9A. CONTROLS AND PROCEDURES

Puget Energy

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of Puget Energy’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, Puget Energy has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of December 31, ~~2021,~~2022, the end of the period covered by this report. Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of Puget Energy concluded that these disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There have been no changes in Puget Energy’s internal control over financial reporting during the quarter ended December 31, ~~2021,~~2022, that have materially affected, or are reasonably likely to materially affect, Puget Energy’s internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

Puget Energy’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Under the supervision and with the participation of Puget Energy’s President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, Puget Energy’s management assessed the effectiveness of internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, Puget Energy’s management concluded that its internal control over financial reporting was effective as of December 31, ~~2021.~~2022.

Puget Energy’s effectiveness of internal control over financial reporting as of December 31, ~~2021,~~2022, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

~~138~~

Puget Sound Energy

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of PSE’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, PSE has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of December 31, ~~2021,~~2022, the end of the period covered by this report. Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of PSE concluded that these disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There have been no changes in PSE’s internal control over financial reporting during the quarter ended December 31, ~~2021,~~2022, that have materially affected, or are reasonably likely to materially affect, PSE’s internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

PSE’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Under the supervision and with the participation of PSE’s President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, PSE’s management assessed the effectiveness of internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, PSE’s management concluded that its internal control over financial reporting was effective as of December 31, ~~2021.~~2022.

PSE’s effectiveness of internal control over financial reporting as of December 31, ~~2021,~~2022, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

141

ITEM 9B. OTHER INFORMATION

None.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

None.

~~139~~

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Board of Directors

As of February ~~24, 2022, eleven~~23, 2023, 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 ~~62,~~63, 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 previously served as Chief Executive Officer of Concure Oncology from March 2020 to November 2021. 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 Puget Energy and PSE boards.

Richard Dinneny, age ~~59,~~60, has been a director on the boards of both Puget Energy and PSE since April 17, 2019. Mr. Dinneny previously served as Senior Portfolio Manager, Infrastructure and Renewable Resources for British Columbia Investment Management Corporation (BCI) where he had the responsibility for all aspects of investing in infrastructure transactions from 2015 to May 31, 2021. Mr. Dinneny serves on the boards of Puget Energy and PSE as a representative of BCI’s ownership interests, pursuant to the terms of the Puget Energy and PSE bylaws.

Barbara Gordon, age ~~63,~~64, has been a director on the board of PSE since November ~~2017.~~2017 and on the board of Puget Energy since August 2022. Ms. Gordon previously served as a Vice President of the board of directors for Seattle-King County Habitat for Humanity, a non-profit organization (2016-2018). Prior to that time, Ms. Gordon served as Executive Vice President and Chief Customer Officer of Bellevue-based Apptio, a developer of technology business management software (2016-2017), 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.

Chris Parker, age ~~51,~~52, has been a director of both Puget Energy and PSE since February 22, 2022. Mr. Parker is currently a member of the Ontario Teachers’ Pension Plan North America Infrastructure team where he focuses on origination, execution and management of infrastructure investments. He joined Ontario Teachers’ Pension Plan in 2011 and has served on the board of directors of Northern Star Generation, Intergen, Express Pipeline, Ontario Teachers' New Zealand Forest Investments and Sydney Desalination Plant. He currently serves on the board of directors of Chicago Skyway. Prior to joining Ontario Teachers', Chris worked on power and utility investments at Brookfield Asset Management. Mr. Parker was selected by Clean Energy JV Sub 2, LP and pursuant to the Amended and Restated Bylaws of each of the Companies, will serve as an Owner

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Director on their respective Boards of Directors. Mr. Parker 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.

Grant Hodgkins, age ~~46,~~47, has been a director on the boards of both Puget Energy and PSE since December 31, 2020. Mr. Hodgkins is currently the Portfolio Manager, Infrastructure and Renewable Resources Group, for British Columbia Investment Management Corporation (BCI), which position he has held since September 2017, where he has 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, British Columbia. 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.

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Tom King, age ~~60,~~61, has been a director on the boards of both Puget Energy and PSE since April 17, 2019. Mr. King is currently the Interim CEO of Woodway Energy Infrastructure, an Intra State Pipeline, which position he has held since December 2022. He is also an 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 joint representative of Macquarie Washington Clean Energy Investment, L.P. and Ontario Teachers’ Pension Plan ownership interests, pursuant to the terms of the Puget Energy and PSE bylaws. Mr. King’s experience as an executive officer of regulated utilities and his extensive familiarity with managing operational change are among the reasons for his continuing service as a member of the Puget Energy and PSE boards.

Mary Kipp, age ~~54,~~55, has been a director on the boards of both Puget Energy and PSE since January 3, 2020. Ms. Kipp has served as President and Chief Executive officer since January 3, 2020, and was President of Puget Energy and PSE from August 2019 to December 2019. Prior to that time Ms. Kipp served as President, Chief Executive Officer and Director of El Paso Electric Company (El Paso) from May 2017 to August 2019. ~~Prior to that she served as Chief Executive Officer and Director of El Paso from December 2015 to May 2017, and President of El Paso from 2014 to 2015.~~ Ms. Kipp also serves on the board of ~~Energy Insurance Mutual Limited, an insurer and~~Hawaiian Electric Industries, Inc., owner of a provider of ~~risk management~~electric utility services ~~to utilities~~in Hawaii, and ~~the energy industry, and of~~ Boston Properties, Inc., a publicly traded developer, owner and manager of Class A office ~~properties .~~properties.

Jean-Paul Marmoreo, age ~~46,~~47, has been a director on the boards of both Puget Energy and PSE since September 3, 2021. Mr. Marmoreo is currently the Director Asset Management of OMERS Infrastructure Management Inc., since January 2019. He is currently on the boards of Calumet Concession Partners Inc., CannAmm GP Inc., and Commodore US Holding Corporation. Mr. Marmoreo previously served as Director of OMERS Infrastructure Management Inc. from February 2018 to January 2019 and Secretary of Airports Worldwide from April 2017 to August 2018. Mr. Marmoreo was selected by OMERS 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. Marmoreo 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.

Paul McMillan, age ~~67,~~68, 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 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. 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.

Diana Birkett Rakow, age 45, has been a director on the board of PSE since May 5, 2022. Ms. Rakow is currently the Senior Vice President of Public Affairs and Sustainability of Alaska Air Group, Inc., since November 2021. She previously served as Vice President of External Relations at Alaska Airlines from September 2017 to February 2021. Ms. Rakow also currently services as the current board chair for the Alaska Airlines Foundation, and serves on the boards of Philanthropy Northwest, the Bay Area Council, and the Pacific Science Center. An independent director not affiliated with any of the Company's investors, Ms. Rakow brings to the Board her expertise in ESG and climate strategy, governance and regulation.

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Aaron Rubin, age ~~44,~~45, has been a director on the boards of both Puget Energy and PSE since February 22, 2022. Mr. Rubin is currently responsible for Macquarie Asset Management’s Real Assets investment team that focuses on sustainable energy investments in the Americas. Since joining Macquarie in 2008, Mr. Rubin has had responsibility for investment origination and execution and the management of portfolio companies. Mr. Rubin currently serves on the board of directors of Cyrq Energy, Cleco Corporation and Lordstown Energy Center. Mr. Rubin was selected by Clean Energy JV Sub 1, LP 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. Rubin 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.

Martijn Verwoest, age ~~45,~~46, has been a director on the boards of both Puget Energy and PSE since April 17, 2019. Mr. Verwoest is currently the Head of Energy & Utilities at Stichting Pensioenfonds Zorg en Welzijn (PGGM), and is a member of their Infrastructure Investment Committee since 2007. From 2001 to 2007, he worked in PGGM’s public equity department. Mr. Verwoest 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 Zucchet, age ~~56,~~57, has been a director on the boards of both Puget Energy and PSE since April 17, 2019. Mr. Zucchet is currently the Managing Director at Ontario Municipal Employees Retirement System Infrastructure Management (OMERS)., which position he has held since January 2019. Since joining OMERS in 2003, Mr. Zucchet has led numerous transactions and had asset management responsibilities at a number of utility and generation companies in Canada and the United States. He 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 Boards, but will be reimbursed for out-of-pocket expenses.

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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 ~~Scott Armstrong,~~ Richard Dinneny, Paul McMillan, Tom King, ~~and~~ Jean-Paul Marmoreo and Diana Rakow are the members of the Audit Committee. The Board has determined that Paul McMillan 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 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.

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, 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 ~~2021,~~2022, 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~~named executive officers (Named Executive ~~Officers~~Officers) who are included in the Summary Compensation Table below. For ~~2021,~~2022, the Company’s Named Executive Officers and titles were:

•Mary E. Kipp, President and Chief Executive Officer (CEO);

•Kazi Hasan, ~~Senior~~Executive Vice President and Chief Financial Officer (CFO)~~, effective June 24, 2021;~~;

•~~Daniel A. Doyle, former Senior~~Allan (Wade) Smith, Executive Vice President and Chief ~~Financial~~Operating Officer, ~~(CFO) until June 24, 2021 and who retired~~ effective ~~September 1, 2021;~~

•~~Adrian J. Rodriguez, Senior Vice President Regulatory and Strategy, effective January 25, 2021;~~

•~~Steve R. Secrist, Senior Vice President, General Counsel, Chief Ethics and Compliance Officer;~~July 18, 2022;

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

•~~Booga K. Gilbertson, former~~Andy Wappler, Senior Vice President and Chief ~~Operations~~Customer Officer; and

•Steve R. Secrist, former Senior Vice President, General Counsel, Chief Ethics and Compliance Officer who retired effective ~~October~~December 1, ~~2021.~~2022.

This section also includes a discussion and analysis of the overall objectives of our compensation program and each element of compensation the Company 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, Meridian Compensation Partners, LLC (Meridian). The Committee recommends to the Board for approval both the salary level for our CEO, based on information provided by 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 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 information provided by Meridian and other relevant factors.

In ~~2021,~~2022, the 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 Company believes that total pay opportunity should be competitive with companies of similar size, revenue, industry and scope of operations. As described below in the discussion of ~~Compensation Program Elements (Role~~Role of Market ~~Data),~~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 (base salary and target annual and long-term incentive award opportunities) to the 50th percentile of the market data with variations by individual executive, as appropriate. The Company also recognizes the

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importance of providing retirement income. As such, the Committee reviews our retirement programs and provides benefits that are competitive with our peers.

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•Place a significant portion of each executive’s target incentive compensation at risk to align executive compensation with Company financial and operating performance. Under its “pay for performance” philosophy, the Company maintains an incentive compensation program that supports the Company’s business strategy 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, ~~79%~~77% of the target 2022 compensation of our CEO, Ms. ~~Kipp’s target 2021 compensation~~Kipp, was considered “at risk” compensation. By establishing goals, monitoring results, and rewarding achievement of goals, the Company seeks to focus executives on actions that will improve Company performance and enhance investor value, while also retaining key talent. The Committee annually evaluates and establishes the performance goals and targets for our annual and long-term incentive ~~programs~~programs.

•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~~groups 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 consistently 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 within a competitive range of the 50th percentile of industry practice, ~~with deviations~~recognizing that the Company operates in a highly competitive regional market. Individual executive pay position may vary from the 50th percentile as influenced by ~~individual~~the factors below. Actual executive ~~as described below. If~~compensation depends significantly on Company performance results, ~~are~~and can result in below ~~expectations, actual compensation is expected to be below this~~or above targeted ~~level. If Company performance exceeds target, actual compensation is expected to be above this targeted level.~~levels.

Individual pay adjustments are reviewed annually relative to the 50th percentile of national peer market pay, while also considering other factors, such as the executive’s recent performance, experience level, company performance, competitive pay in our region, retention of top talent 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 national peer market pay when that individual has a role with greater or lesser responsibility than the best comparison job, in response to regional market pressures, or when our executive’s experience ~~and performance differ~~differs from ~~those~~that typically found in the market.

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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 ~~2020~~2021 Energy Services Survey, comprised of utility and other companies similar in size and scope of operations to PSE. Based on Meridian's evaluation and its discussion with the Committee, five companies of similar scope were added to the 2021 peer group, while one was removed to ensure a broad comparison group. The 2226 companies in the custom market survey cut for ~~2021~~2022 pay decisions are shown below:


Custom Survey Peer Group	Custom Survey Peer Group						Custom Survey Peer Group
1.	1.	Alliant Energy	10.	Hawaiian Electric Industries, Inc.	19.	Southwest Gas	1.	Allete*	10.	Evergy	19.	PNM Resources
2.	2.	Ameren	11.	NiSource	20.	Spire, Inc.	2.	Alliant Energy	11.	Eversource Energy	20.	Portland General Electric
3.	3.	Atmos Energy	12.	Oncur	21.	UGI	3.	Ameren	12.	Hawaiian Electric Industries, Inc.	21.	PPL*
4.	4.	Avangrid	13.	OGE Energy	22.	WEC Energy Group	4.	Atmos Energy	13.	NiSource	22.	South Jersey Industries
5.	5.	Avista	14.	ONE Gas			5.	Avista	14.	Northwestern Energy*	23.	Southwest Gas
6.	6.	Cleco	15.	Pinnacle West Capital			6.	Black Hills*	15.	Oncor	24.	Spire
7	7	CMS Energy	16.	PNM Resources			7	CenterPoint*	16.	OGE Energy	25.	UGI
8	8	Evergy	17.	Portland General Electric			8	Cleco	17.	ONE Gas	26.	WEC Energy Group
9.	9.	Eversource Energy	18.	South Jersey Industries			9.	CMS Energy	18.	Pinnacle West Capital

*Added to the 2021 peer group. Avangrid was removed from the 2021 peer group.

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Based on Meridian’s evaluation, as well as discussion with the Committee, two companies in the market survey group for 2020 were removed due to either having non-regulated business operations or due to being acquired. South Jersey Industries was added to the group in 2021.

The market survey data from the companies above 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 2020~~At the time of the benchmarking study, the median revenue of the executive compensation peers was $3.5 billion, which was comparable to PSE’s annual revenues of ~~$3.3 billion at the time the peer group was developed.~~$3.5 billion. The proxy peer group was reviewed by Meridian to assess the continued relevancy of the companies and did not change from last year.


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

Base Salary

We recognize that it is necessary to provide executives with a fixed amount of regularly paid compensation that provides a balance to other at-risk pay elements. Base salaries are reviewed annually by the Committee based on its ~~median~~compensation philosophy, internal pay equity considerations and considerations specific to an individual such as an executive’s expertise, level of performance, experience in the role and contribution relative to others in the organization.

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Base Salary Adjustments for ~~2021~~2022

The Committee reviewed the base salaries of the Named Executive Officers in early ~~2021~~2022 and recommended base salary adjustments to the Board, except for Mr. ~~Hasan and Mr. Rodriguez,~~Smith, whose ~~salaries were~~salary was approved at hire in ~~2021.~~July 2022. The Committee also reviewed salaries during 2022 based on market pressures and the promotion of Mr. Hasan to Executive Vice President and recommended base salary increases. The Board approved the Committee’s salary recommendations as shown in the table below. The adjustments were effective March 1, ~~2021.~~2022 except for Ms. Kipp’s and Mr. Hasan’s who also received additional adjustments effective August 2022. Base salaries for ~~2021~~2022 generally remained at the 50th percentile of market among the comparator group. The salary increase percentages approved by the Board for Ms. Kipp, Mr. Doyle, and Mr. Secrist were similar to salary increases for other non-represented employees, and the salary increases for Ms. Gilbertson and Ms. Hopkins were adjusted to reflect their expanded roles in 2021.

Name

2020 Base Salary

2021 Base Salary

% Change
Mary E. Kipp $900,000 $930,000 3%
Kazi Hasan N/A 510,000 —
Daniel A. Doyle 547,363 566,521 3.5
Adrian J. Rodriguez N/A 530,000 —
Steve R. Secrist 483,626 500,553 3.5
Margaret F. Hopkins 350,000 414,000 18
Booga K. Gilbertson 428,145 470,531 9.9

~~2021~~


Name	2021 Base Salary	2022 Base Salary	% Change1
Mary E. Kipp	$930,000	$1,043,250	12%
Kazi Hasan	510,000	570,257	12
Allan (Wade) Smith	N/A	630,000	—
Margaret F. Hopkins	414,000	426,482	3
Andrew Wappler	390,326	402,036	3
Steve R. Secrist	500,553	515,570	3

1.Percentages are rounded.

2022 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.”~~Plan”. The plan is designed to incent our employees to achieve both (i) desired annual financial results, measured by EBITDA, and (ii) pre-established goals based on both 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 ~~2021,~~2022, the Company’s service quality commitment was measured by performance against ~~eight~~nine Service Quality Indicators (SQIs) covering three broad categories, set forth below. These are the same SQIs for which the Company is accountable to the Washington Commission. 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 ~~2021~~2022 were the same as those in ~~2020~~2021 and were as follows:

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

•Customer Service (1 SQI) - Calls answered “live” within 60 seconds by the customer care center.

•Operations Services (4(5 SQIs) - Gas emergency response, electric emergency response, non-storm outage duration as measured by the System Average Interruption Disruption Index (SAIDI), non-storm outage frequency, and on-time appointments.

The employee safety performance measure reflects the Company’s continued commitment to employee safety. 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 ~~2021~~2022 were:

•All employees attend a monthly safety “meeting in a box” presentation, or complete the same content ~~online.~~online, featuring employees from across PSE discussing their jobs and efforts to ensure the health and safety of themselves, their coworkers and our customers. The target completion rate is no less than 95%.

•All employees complete ~~a safety conversation with their supervisor or manager.~~training videos to help reduce musculoskeletal injuries in the field, officer and at home. 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~~functions similarly to the ~~eight~~nine 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 ~~2021,~~2022, 100% funding for the annual incentive plan required (i) achievement of 10 out of 10 customer service and safety measures (all ~~eight~~nine SQIs ~~SAIDI~~ and achievement of the safety measure) and (ii) target EBITDA performance. ~~Seven~~Eight of the ten

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customer service and safety measures were met, and EBITDA finished at ~~100.5%~~98.4% of target, so funding was less than 100%, as described further below.

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.

~~2021 Corporate Goals~~

In 2021, 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 2021 corporate goals and which have been communicated to our employees. Each employee has specific individual and team goals linked to driving strategies that meet one or more of the following ISP objectives:

•~~Safety~~ - ~~Our safety objective is our foundation: If nobody gets hurt today, we will feel safe and secure and be able to perform at our best.~~

•~~People~~ - When we’re safe, we can achieve our people objective of being a great place to work, with engaged employees who live our values, embrace an ownership culture and are motivated to drive results for our company and our customers.

•~~Process and Tools~~ - Engaged employees achieve our process and tools objective where results start with achieving operational excellence, with continuous improvement of our internal processes and tools so that we can increase efficiency, eliminate waste, improve reliability and enhance customer service.

•~~Customer- We now have the fundamentals to achieve our customer objective of delivering greater value and being our customer’s energy partner of choice in a competitive marketplace.~~

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

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~~2021~~2022 Annual Incentive Plan Results

For ~~2021,~~2022, achievement of the corporate goals under the annual incentive plan was at ~~100.5%~~98.4% of target for EBITDA. PSE EBITDA was ~~$1,372.2~~$1,293.6 million, and SQI ~~SAIDI~~ and safety achievement was 78 out of 10, leading to a funding level for ~~2021~~2022 of ~~53.77%~~73.5% for the annual incentive plan for the ~~named executive officers.~~Named Executive Officers.

Funding levels for ~~2021~~2022 at maximum, target, and threshold are shown in the table below:

Annual Incentive Performance Payout Scale and Actual Performance

Performance Measure (Dollars in Millions)

2021 EBITDA

SQI, SAIDI& Safety*

Funding Level

Performance Measure (Dollars in Millions)

2022 EBITDA

SQI, SAIDI& Safety*

Funding Level

Maximum

1,843.6

10/10

200%

Maximum

1,775.3

10/10

200%

Target

1,365.6

10/10

100

Target

1,315.0

10/10

100

Threshold

1,229.0

6/10

Threshold

1,183.5

6/10

2021 Actual Performance

1,372.2

7/10

53.77

2022 Actual Performance

1,293.6

8/10

73.5

_______________

* Combined SQI ~~SAIDI &~~and Safety results of 6/10 or better and minimum EBITDA of ~~$1,229.0~~$1,183.5 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%)

No bonus is earned unless at least the 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 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 ~~2021.~~2022. The adjustments for individual performance are noted in the "Bonus" column onof the Summary Compensation table and did not materially change the amounts resulting from ~~2021~~2022 achievement of the corporate goals. The Board approved the incentive amounts shown below (inclusive of adjustments for performance for each Ms. Kipp and Mr. Hasan), which will be paid in March ~~2022:~~2023:


Name	Name	Target Incentive (% of Base Salary)	2021 Actual Incentive Paid		2021 Actual Incentive (% of Base Salary)	Name	Target Incentive (% of Base Salary)	2022 Actual Incentive Paid		2022 Actual Incentive (% of Base Salary)
Mary E. Kipp	Mary E. Kipp	100 (75)%	$	575,043	62.0%	Mary E. Kipp	115%	$	1,058,168	101.0%
Kazi Hasan**		65 (48.75)	107,264		21
Daniel A. Doyle***		65 (48.75)	132,338		23
Adrian J. Rodriguez		65 (48.75)	207,649		39
Kazi Hasan*						Kazi Hasan*	80	352,109		62
Allan (Wade) Smith*						Allan (Wade) Smith*	80	179,895		29
Margaret F. Hopkins						Margaret F. Hopkins	65	193,565		45
Andrew Wappler						Andrew Wappler	65	182,469		45
Steve R. Secrist	Steve R. Secrist	65 (48.75)	174,938		35	Steve R. Secrist	65	246,314		48
Margaret F. Hopkins		65 (48.75)	137,474		33
Booga K. Gilbertson		65 (48.75)	123,433		26

* ~~The~~Mr. Hasan’s annual incentive ~~targets for all participants were reduced for the 2021 performance year to 75% of normal~~is based on time as ~~part of budgetary steps taken in 2021 to manage operating expenses~~Senior Vice President (65%) and ~~ensure credit metrics were maintained.This reduced amount~~time as Executive Vice President (80%); Mr. Smith’s annual incentive is ~~shown in parentheses and only applies to 2021.~~

**~~Mr. Hasan will receive a total of $270,000 for 2021 (including the amount shown above, pro-rated~~prorated for time worked in ~~2021) per~~2022 since his ~~offer of employment.~~

*** Mr. Doyle and Ms. Gilbertson'shire. His target annual incentive ~~targets were 65%, but based on plan rules as a retiree, their awards were pro-rated for time worked in 2021.~~is 80% of base salary.

Long-Term Incentive Compensation

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

~~For the 2020-2022 and 2021-2023 grant cycles,~~Long-term incentive payments are based on achievement of a Return on Equity (ROE) metric, subject to achievement of a threshold EBITDA goal. Under this goal, EBITDA during the applicable three-year performance

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cycle must meet or exceed 90% of target EBITDA for a payment to occur. Assuming the EBITDA threshold is met, the grant cycles are funded based on

149

the three-year average ROE metric. ROE reflects the income earned on our equity investment. The LTI Plan payments ultimately paid may range from 0% to 200% of target, depending on performance.

The Committee recommends for Board approval a targeted LTI grant value in dollars for each ~~executive, which is expressed as a percentage of base salary.~~executive. 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 2019-2021 LTI plan cycle was denominated in units, determined by dividing the target LTI grant value by the unit value on the grant date. The initial per-unit value was measured at the Puget Holdings level and subsequent unit values are calculated annually by an independent auditing firm or based on market transactions. For the 2019-2021 LTIP grant, 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 2019-2021 grant cycle was based on achievement of the ROE metric measured over a three-year performance cycle.

Executives generally must be employed on the ~~date completing~~last day of the performance cycle to receive a cash payment under the LTI Plan, except in the event of retirement, disability or death.

~~2021-2023~~2022-2024 Long-Term Incentive Plan Target Awards

Consistent with prior years, target LTI Plan awards for the ~~2021-2023~~2022-2024 performance cycle were ~~calculated based on a percentage of an executive's annual base salary,~~denominated in dollars, taking into account the executive's level of responsibility within the Company and the corresponding market data. Ms. Kipp’s target LTI Plan grant was increased to ~~274% of base salary~~$3,700,000 to align with market pay levels. The other percentages were unchanged from amounts established for the 2020-2022 performance cycle. As part of his employment offer, Mr. Hasan's target grant was established as a dollar figure rather than a percentage and aligned to market data based on recommendations from Meridian. Target LTI Plan award amounts for the ~~2021-2023~~2022-2024 performance cycle are shown in the following table.


Name						Target Long Term Incentive ~~(% of Base Salary)~~ ($)
Mary E. Kipp						~~274%~~$3,700,000
Kazi Hasan						$750,000*1,000,000
~~Daniel A. Doyle~~Allan (Wade) Smith						~~95%~~1,260,000
~~Adrian J. Rodriguez~~Margaret F. Hopkins						95405,000
Andrew Wappler						380,000
Steve R. Secrist						95
~~Margaret F. Hopkins~~						95
~~Booga K. Gilbertson~~						95490,000

*~~As described above, Mr. Hasan's grant upon employment was expressed as a dollar figure and not a percentage of base salary.~~

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Details of the target grants and expected values at target, threshold and maximum performance levels can be found in the ~~“2021~~“2022 Grants of Plan-Based Awards” table below.

Long-Term Incentive Plan Performance ~~2019-2021~~2020-2022 Performance Cycle Results and Payouts

The ~~2019-2021~~2020-2022 performance cycle has now ended. Amounts payable as a result of award vesting are shown in the following table:

•Performance on the ROE component of the grant ~~was an average of 103.1% of target. The ROE component funded~~finished at ~~117.7%~~80% of target, ~~units.~~which was below the plan’s threshold for funding. The Committee recommended and the Board approved a payment at 110% of target funding level, in recognition of the initial targets being set prior to the COVID global pandemic and the impact that had on business and regulatory conditions.

Name

Target Incentive
(% of Base Salary)1

ROE Component
Units Granted/Paid
2019-2021
Actual LTIP Paid2
Mary E. Kipp3

220%

23,112.6/27,203.6 $ 2,813,665
Kazi Hasan3
$125,000 1,534.9/1,806.6 186,855
Adrian J. Rodriguez3
31.6% 2,073.3/2,440.2 252,394
Steve R. Secrist

95

5,371/6,321.7 653,850
Margaret F. Hopkins

50

2,001/2,355.2 243,596


Name	Target Incentive ($)1	2020-2022 LTIP Paid2
Mary E. Kipp	$2,385,000	$2,623,500
Kazi Hasan2	375,000	412,500
Allan (Wade) Smith2	—	—
Margaret F. Hopkins	293,125	322,438
Andrew Wappler	169,178	186,096

______________

1 Target LTI Plan incentive is ~~a percentage of 2019 base salary when~~ the ~~grants were made~~dollar target level set in 2019 with a unit price of $81.86, except that grants made to each of Mr. Hasan and Mr. Rodriguez as part of offers of employment had unit prices of $81.44 and $80.87, respectively.. Mr. Rodriguez's target grant of 95% of base salary was prorated at 33.3%2020.

2 ~~2019-2021 actual LTI Plan amount payable is equal to the unit price of $103.43 multiplied by earned ROE component units.~~

3 In connection with ~~Ms. Kipp's~~Mr. Hasan's commencement of employment in ~~2019, she~~2021, he was eligible to participate in the 2019-2021 performance cycle at a target amount that reflected full participation at her then LTIP target to incentivize performance following commencement of employment at a unit price of $81.86. In connection with Mr. Hasan's and Mr. Rodriguez's commencement of employment in 2021, each were eligible to participate in the 2019-20212020-2022 performance cycle at a target amount that reflected reduced participation during the performance cycle but was intended to incentivize performance following commencement of employment. In connection with Mr. Smith’s commencement of employment in 2022, he was granted retention incentives described in the “Other Compensation” section below. He did not receive a grant in the 2020-2022 LTIP performance cycle.

150

In connection with Mr. ~~Doyle’s~~Secrist’s retirement, he was eligible to receive a pro-rated portion of his LTI grants for the ~~2019-2021,~~ 2020-2022, 2021-2023 and ~~2021-2023~~2022-2024 performance cycles in accordance with the LTI Plan in the amounts of ~~$625,627, $0~~$505,389, $233,641 and ~~$81,806,~~$134,260, respectively, paid in March 2022. In connection with Ms. Gilbertson’s retirement, she was eligible to receive a pro-rated portion of her LTI grant for the 2019-2021, 2020-2022 and 2021-2023 performance cycles at retirement in the amounts of $506,406, $0 and $101,917, respectively, paid in March 2022.2023.

Retirement Plans –– Executive Retirement Plans and Retirement Plan

The Company maintains 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 executive retirement plans, these executives would receive lower percentages of replacement income during retirement than other employees. All the Named Executive Officers ~~participate~~participated in executive retirement plans during ~~2021—Mr. Secrist, and~~2022, Ms. Hopkins and Mr. Wappler participate in the SERP and Ms. Kipp, Mr. Hasan and Mr. ~~Rodriguez~~Smith participate in the Officer Restoration Benefit, as part of the Deferred Compensation Plan for Key Employees. Mr. ~~Doyle and Ms. Gilbertson~~Secrist participated in the SERP until ~~their departures~~his departure in ~~2021.~~2022. Additional information regarding the SERP, Officer Restoration Benefit and the Retirement Plan is shown in the ~~“2021~~“2022 Pension Benefits” table.

~~149~~

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 ~~“2021 Non-qualified~~“2022 Nonqualified Deferred Compensation” table.

Post-Termination Benefits

The Committee periodically reviews existing change in control and severance arrangements for the peer group companies.Based on this information, the Committee has determined not to extend such arrangements to current and newly hired executives.No executive officers have employment agreements that would provide severance benefits.Certain compensation programs, such as the LTI Plan, have provisions that would apply in the event of a change in control.

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, ~~2021.~~2022.

Other Compensation

The Company also provides the Named Executive Officers with benefits and limited perquisites. To attract qualified candidates, the Company may provide certain payments to executives in connection with an offer of employment, including payments to offset their relocation expenses.

In connection with his offer of employment Mr. Hasan was eligible to receive a signing bonus of $100,000 and a relocation payment of $175,000, grossed up for taxes, to assist with moving expenses. Both amounts must be repaid if Mr. Hasan resigns or is terminated for cause within 24 months of employment. Mr. Hasan was also eligible to receive a bonus of $270,000, to be reduced by the amount he received under the annual incentive plan for 2021. Subject to continued employment,in 2021, Mr. Hasan is eligible to receive a retention bonus of $250,000 in each of March 2022 and March ~~2023. Mr. Hasan is also eligible~~2023, subject to participate in the 2020-2022 performance cycle under the LTI Plan based on a target grant of $375,000 in addition to participation in the other performance periods for which disclosure is provided above.continued employment.

In connection with ~~Mr. Rodriguez’s commencement~~his offer of employment, heMr. Smith was eligible to receive a signing bonus of ~~$132,500~~$900,000 and a relocation payment of ~~$132,500,~~$150,000, grossed up for taxes, to assist with moving expenses. Both amounts must be repaid if Mr. ~~Rodriguez~~Smith resigns or is terminated for cause within 24 months of employment. Subject to continued employment, Mr. ~~Rodriguez~~Smith is eligible to receive a retention bonus of $630,000 in March 2023, $150,000 in July 2023 (after one year of service) and $1,260,000 in December 2026. Mr. Smith is also eligible to participate in the ~~2020-2022~~2021-2023 performance cycle under the LTI Plan based on a target grant of ~~66.7% of base salary~~$945,000 in addition to participation in the ~~other~~2022-2024 performance ~~periods~~cycle for which disclosure is provided above.

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 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. These perquisites generally do not make up a significant portion of executive

151

compensation and did not exceed $10,000 in total for each Named Executive Officer in ~~2021.~~2022. 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~~the 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.

~~150~~

Impact of Accounting and Tax 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 tax impact of various program designs to balance the potential cost to the Company with the benefit/value to the executive. As a result of changes in federal tax law effective in 2018, the Company is now subject to IRS section 162(m). Section 162(m) limits the tax deductibility of compensation paid to certain executive 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 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 executives focus ~~executives~~ on interests important to the Company and its investors and customers and creates a record of their results. In structuring its incentive programs, the Company also strives to balance and moderate risk to the Company from such programs: individual award opportunities are defined and subject to limits, goal funding is based on collective company performance, annual incentive awards are balanced by long-term incentive awards that measure performance over three years, performance targets are based on management’s operating plan (which includes providing good customer service), and all incentive awards to individual executives are subject to discretionary review by management, the Committee and/or the Board. As a result, the Committee and the Board believe that the programs’ design do not have risks that are reasonably likely to have a material adverse effect on the Company and also provide appropriate incentive opportunities for executives to achieve Company goals that support the interests of our investors and customers.

Compensation and Leadership Development Committee Report

The Board delegates responsibility to the Compensation and Leadership Development Committee to establish and oversee the Company’s executive compensation program. Each member of the Committee served during all of ~~2021.~~2022, except Mr. Rubin who joined February 22, 2022.

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, ~~2021,~~2022, for filing with the SEC.

Compensation and Leadership

Development Committee of

Puget Energy, Inc.

Puget Sound Energy, Inc.

Steven Zucchet, chair,

Scott Armstrong

Barbara Gordon

~~Mary McWilliams~~Aaron Rubin, effective February 22, 2022

Martijn Verwoest

~~151~~152

Summary Compensation Table

The following information is provided for the year ended December 31, ~~2021,~~2022, (and for prior years where applicable) with respect to the Named Executive Officers during ~~2021.~~2022. The positions listed below are at Puget Energy and PSE, except that Ms. ~~Gilbertson~~Hopkins and ~~Ms. Hopkins~~Mr. Wappler are executives of PSE only. Positions listed are those held by the Named Executive Officers as of December 31, ~~2021.~~2022. 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 Compensation3
All Other Compensation4
Total
Mary E. Kipp, 2021 $ 923,923 $ — $ — $ — $ 3,388,708 $ — $ 101,614 $ 4,414,245
President and 2020 891,667 — — — 2,847,229 — 1,557,670 5,296,566
Chief Executive Officer5
2019 252,540 — — — 1,876,398 — 813,893 2,942,831
Kazi Hasan, Senior Vice President and Chief Financial Officer6
2021 243,409 262,736 — — 294,118 — 315,817 1,116,080
Daniel A. Doyle 2021 400,453 132,338 264,116 753,806 1,550,713
Former Senior Vice President 2020 544,041 — — — 1,304,379 824,333 60,602 2,733,355
and Chief Financial Officer7
2019 521,399 — — — 1,608,655 964,614 63,555 3,158,223
Adrian J. Rodriguez, Senior Vice President Regulatory and Strategy8
2021 475,318 132,500 — — 460,043 — 248,821 1,316,682
Steve R. Secrist 2021 497,096 828,788 524,937 49,050 1,899,871
Senior Vice President 2020 479,287 — — — 1,105,450 658,689 51,325 2,294,751
General Counsel, Chief Ethics & Compliance Officer9
2019 459,165 — — — 1,291,097 786,634 53,517 2,590,413
Margaret F. Hopkins 2021 400,984 — — — 381,070 505,621 37,694 1,325,369
Senior Vice President Shared Services and CIO10
2020 345,328 — — — 461,260 499,683 39,064 1,345,335
Booga K. Gilbertson 2021 365,633 — — — 123,433 454,034 633,044 1,576,144
Former Senior Vice President, Chief Operations Officer11
2020 420,406 — — — 870,111 794,245 43,169 2,127,931


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
Mary E. Kipp	2022	$	991,585	$	176,361	$	—	$	—	$	3,505,307	$	—	$	87,678	$	4,760,931
President and,	2021	$	923,923	$	—	$	—	$	—	$	3,388,708	$	—	$	101,614	$	4,414,245
Chief Executive Officer5	2020	891,667		—		—		—		2,847,229		—		1,557,670		5,296,566
Kazi Hasan, Executive Vice	2022	542,348		308,685		—		—		705,924		—		54,849		1,611,806
President and Chief Financial Officer6	2021	243,409		262,736		—		—		294,118		—		315,817		1,116,080
Allan (Wade) Smith, Executive Vice President and Chief Operating Officer7	2022	262,500		900,000		—		—		179,895		—		223,747		1,566,142
Margaret F. Hopkins	2022	423,946		—		—		—		516,002		60,088		42,761		1,042,797
Senior Vice President Shared	2021	400,984		—		—		—		381,070		505,621		37,694		1,325,369
Services and CIO8	2020	345,328		—		—		—		461,260		499,683		39,064		1,345,335
Andrew Wappler
Senior Vice President and Chief Customer Officer9	2022	399,645		—		—		—		368,565		—		29,104		797,314
Steve R. Secrist	2022	491,021								246,314		343,636		923,664		2,004,635
Former Senior Vice President	2021	497,096		—		—		—		828,788		524,937		49,050		1,899,871
General Counsel, Chief Ethics & Compliance Officer10	2020	479,287		—		—		—		1,105,450		658,689		51,325		2,294,751

_______________

1.Reflects individual performance above target as described in the "Compensation Discussion and Analysis," section titled "~~2021~~2022 Annual Incentive Plan Results". for each of Ms. Kipp and Mr. Hasan. For Mr. Hasan, ~~and Mr. Rodriguez~~ also reflects a retention bonus of $250,000 paid in 2022 in connection with the terms of his 2021 offer of employment.. For Mr. Smith also reflects a signing ~~bonuses~~bonus paid in connection with commencement of employment in ~~2021,~~2022, in the ~~amounts~~amount of ~~$100,000 and $132,500, respectively.~~$900,000.

2.For ~~2021,~~2022, reflects annual cash incentive compensation paid under the ~~2021~~2022 Goals and Incentive Plan and cash incentive compensation paid under the LTI Plan for the ~~2019-2021~~2020-2022 performance cycle. Cash incentive amounts were paid in early ~~2022~~2023 or deferred at the executive's election. The ~~2021~~2022 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 ~~2022.~~2023.

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 ~~2021,~~2022, updated interest rates relative to those used for ~~2020~~2021 have generally resulted in smaller increases in value than in prior years. Information regarding these pension plans is set forth in further detail under ~~“2021~~“2022 Pension Benefits.” The change in pension value amounts for ~~2021~~2022 are: Ms. Kipp, $0; ~~Mr..~~Mr. Hasan, $0; Mr. ~~Doyle, $264,116;~~Smith, $0; Ms. Hopkins, $60,088; Mr. ~~Rodriguez,~~Wappler, $0; and Mr. Secrist, $524,937; Ms. Hopkins, $505,621; and Ms. Gilbertson, $451,676. Also included in this column are the portions of Deferred Compensation Plan earnings that are considered above market. Only Ms. Gilbertson had these earnings for 2021 in the amount of $2,358. See the “2021 Nonqualified Deferred Compensation” table for all Deferred Compensation Plan earnings.$343,636.

4.All Other Compensation for ~~2021~~2022 is shown in detail in the table below.

5.Ms. Kipp joined PSE and Puget Energy as President on August 31, 2019, and became President and CEO on January 3, 2020.

6.Mr. Hasan joined PSE and Puget Energy as Senior Vice President and Chief Financial Officer on June 24, 2021.

7.Mr. ~~Doyle~~Smith joined PSE and Puget Energy as ~~Senior~~Executive Vice President and Chief ~~Financial~~Operating Officer on ~~November 28, 2011, and retired effective September 1, 2021.~~July 18, 2022.

8.~~Mr. Rodriguez joined PSE and Puget Energy as Senior Vice President Regulatory and Strategy on January 25, 2021. .~~

9.~~Mr. Secrist has worked at PSE since May 1989.~~

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

~~11.~~9.~~Ms. Gilbertson~~Mr. Wappler has worked at PSE since ~~1991,~~February 2008.

10.Mr. Secrist has worked at PSE since May 1989 and retired effective ~~October~~December 1, ~~2021.~~2022.

~~152~~153

Detail of All Other Compensation


Name	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		$	—		$	92,078		$	9,537	Mary E. Kipp		$	5,000		$	70,381		$	12,297
Kazi Hasan	Kazi Hasan		175,000			10,858			129,959		Kazi Hasan		—			45,804			9,045
Daniel A. Doyle			2,500			38,558			712,748
Adrian J. Rodriguez			134,500			13,050			101,271
Allan (Wade) Smith											Allan (Wade) Smith		150,000			11,025			62,722
Margaret F. Hopkins											Margaret F. Hopkins		—			36,585			6,176
Andrew Wappler											Andrew Wappler		—			21,200			7,904
Steve R. Secrist	Steve R. Secrist		1,390			42,138			5,522		Steve R. Secrist		2,500			41,569			879,596
Margaret F. Hopkins			—			31,625			6,069
Booga K. Gilbertson			712			19,801			612,531

_______________

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 $2,500 for the other Named Executive Officers. For Mr. ~~Hasan and Mr. Rodriguez,~~Smith, also includes a relocation ~~payments~~payment of ~~$175,000 and $132,500, respectively,~~$150,000, as described in "Other Compensation" of the ~~Compensation~~"Compensation Discussion and ~~Analysis, "Other Compensation.~~Analysis."

2.Includes Company contributions during ~~2021~~2022 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, ~~$24,450;~~$25,325; Mr. Hasan, ~~$10,858;~~$23,376; Mr. ~~Doyle, $20,250;~~Smith, $11,025; Ms. Hopkins $17,205; Mr. ~~Rodriguez, $13,050;,~~Wappler, $21,200; and Mr. Secrist, ~~$17,584; Ms. Hopkins $16,243; and Ms. Gilbertson $19,801.~~$18,402. Company contributions to the Deferred Compensation Plan are as follows: Ms. Kipp, ~~$67,628;~~$45,056; Mr. Hasan, $22,428; Mr. Smith, $0; Ms. Hopkins, $19,3802; Mr. ~~Doyle, $18,308; Mr. Rodriguez,~~Wappler, $0; and Mr. Secrist, ~~$24,554; Ms. Hopkins, $15,382; and Ms. Gilbertson, $0.~~$23,167.

3.Reflects the value of imputed income for life insurance and Company paid premiums on supplemental disability insurance for all Named Executive Officers. For Mr. ~~Hasan and Mr. Rodriguez~~Smith, also includes the amount of a tax ~~gross-ups~~gross-up on relocation payments of ~~$125,485 and $97,597, respectively,~~$58,548, as described in the ~~Compensation~~"Compensation Discussion and Analysis," “Other Compensation". For Mr. ~~Doyle and Ms. Gilbertson~~Secrist also includes pro-rated payment of LTI Plan grants at retirement, per the LTI Plan terms: ~~Mr. Doyle 2019-2021 $625,627;~~ 2020-2022 $0$505,389; 2021-2023, $233,641; and ~~2021-2023, $81,806; and Ms. Gilbertson 2019-2021, $506,406; 2020-2022, $0; and 2021-2023, $101,917.~~2022-2024, $134,260.

~~153~~154

~~2021~~2022 Grants of Plan-Based Awards

The following table presents information regarding ~~2021~~2022 grants of non-equity annual incentive awards and LTI Plan awards, including, as applicable, the range of potential payouts for the awards.

Estimated Future Payouts under Non-Equity
Incentive Plan Awards
Name

Grant Date

Grant Target Value

Threshold

Target

Maximum
Mary E. Kipp

Annual Incentive1

1/1/2021

$ 279,000

$ 930,000

$ 1,860,000
LTI Plan 2021-20232

2/25/2021

2,548,200

1,274,100

2,584,200

5,096,400
Kazi Hasan

Annual Incentive1
6/24/2021 $ 52,042 $ 173,474 $ 346,948
LTI Plan 2019-20213
6/24/2021 125,000 62,500 125,000 250,000
LTI Plan 2020-20223
6/24/2021 375,000 187,500 375,000 750,000
LTI Plan 2021-20232
6/24/2021 750,000 375,000 750,000 1,500,000
Daniel A. Doyle

Annual Incentive1,4
1/1/2021 $55,236 $184,119 $ 368,239
LTI Plan 2021-20232,4
2/25/2021 538,195 269,097 538,195 1,076,390
Adrian J. Rodriguez

Annual Incentive1

1/25/2021

$ 96,550

$ 321,832

$ 643,664
LTI Plan 2019-20213
1/25/2021 167,667 83,834 167,667 335,334
LTI Plan 2020-20223
1/25/2021 335,835 167,918 335,835 671,670
LTI Plan 2021-20232

2/25/2021

503,500

251,750

503,500

1,007,000
Steve R. Secrist

Annual Incentive1

1/1/2021

$97,608

$325,359

$ 650,719
LTI Plan 2021-20232

2/25/2021

475,525

237,763

475,525

951,051
Margaret F. Hopkins

Annual Incentive1

1/1/2021

$ 91,754

$ 305,845

$ 611,690
LTI Plan 2021-20232

2/25/2021

447,004

223,502

447,004 894,009
Booga K. Gilbertson

Annual Incentive1,4

1/1/2021

$80,742

$269,139

$ 538,278
LTI Plan 2021-20234

2/25/2021

393,357

196,679

393,357

786,714


		Estimated Future Payouts under Non-Equity Incentive Plan Awards
Name	Grant Date	Grant Target Value	Threshold		Target		Maximum
Mary E. Kipp
Annual Incentive1	1/1/2022		$	359,921	$	1,199,738	$	2,399,475
LTI Plan 2022-20242	2/24/2022	3,700,000	1,850,000		3,700,000		7,400,000
Kazi Hasan
Annual Incentive1	1/1/2022		$	119,765	$	399,217	$	798,434
LTI Plan 2022-20242	2/24/2022	1,000,000	500,000		1,000,000		2,000,000
Allan (Wade) Smith
Annual Incentive1	7/18/2022		$	69,930	$	233,100	$	466,200
LTI Plan 2021-20233	7/18/2022	945,000	472,500		945,000		1,890,000
LTI Plan 2022-20242	7/18/2022	1,260,000	630,000		1,260,000		2,520,000
Margaret F. Hopkins
Annual Incentive1	1/25/2022		$	83,164	$	277,214	$	554,428
LTI Plan 2022-20242	2/24/2022	405,000	202,500		405,000		810,000
Andrew Wappler
Annual Incentive1	1/1/2022		$	78,397	$	261,323	$	522,647
LTI Plan 2022-20242	2/24/2022	380,000	190,000		380,000		760,000
Steve R. Secrist
Annual Incentive1,4	1/1/2022		$	100,536	$	335,121	$	670,241
LTI Plan 2022-20244	2/24/2022	490,000	245,000		490,000		980,000

_______________

1.As described in the “Compensation Discussion and Analysis,” the ~~2021~~2022 Goals and Incentive Plan had dual funding triggers in ~~2021~~2022 of ~~$1,229.0~~$1,183.5 million EBITDA and SQI performance of 6/10. Payment would be $0 if either trigger is not met. The threshold estimate assumes ~~$1,229.0~~$1,183.5 million EBITDA and SQI/Safety measure performance at 6/10. The target estimate assumes ~~$1,365.6~~$1,315.0 million EBITDA and SQI/Safety measure performance at 10/10. The maximum estimate assumes ~~$1,843.6~~$1,775.3 million EBITDA or higher and SQI/Safety measure performance at 10/10. ~~Awards~~The award for Mr. ~~Hasan and Mr. Rodriguez were~~Smith was pro-rated for time worked in ~~2021~~2022 per the plan.

2.As described in the “Compensation Discussion and Analysis,” LTI Plan grants for the ~~2021-2023~~2022-2024 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.~~

3.In connection with Mr. ~~Hasan's and Mr. Rodriguez's~~Smith’s commencement of employment, ~~each~~he was eligible to participate in the LTI Plan for the performance cycle indicated, but at a reduced participation level, as described in the "Compensation Discussion and Analysis.".

4.Mr. ~~Doyle and Ms. Gilbertson~~Secrist received full grants aton the grant ~~date~~dates in the amounts shown, but upon retirement had earned pro-rate portions per the plans, in the amounts shown in the Summary Compensation Table for ~~2021.~~2022.

~~154~~155

~~2021~~2022 Pension Benefits

The Company and its affiliates maintain two pension plans: the Retirement Plan and the SERP, in addition to an Officer Restoration Benefit as part of the Deferred Compensation Plan. The following table provides information for the participating 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, except Ms. Kipp and Mr. Hasan, who participate just in the Officer Restoration Benefit (which is reported separately below) and Mr. ~~Rodriguez~~Smith who participates in the Retirement Plan and the Officer Restoration Benefit.


Name	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
Mary E. Kipp3	Mary E. Kipp3	Retirement Contribution	2.3		$	—		$	—	Mary E. Kipp3	Retirement Contribution	3.3		$	—		$	—
		Restoration Benefit	2.3		—		—				Restoration Benefit	3.3		—		—
Kazi Hasan3	Kazi Hasan3	Retirement Contribution	.5		—		—			Kazi Hasan3	Retirement Contribution	1.5		—		—
		Restoration Benefit	.5		—		—				Restoration Benefit	1.5		—		—
Daniel A. Doyle		Retirement Plan	9.7		—		418,569
Allan (Wade) Smith										Allan (Wade) Smith	Retirement Plan	4		—		—
		SERP	9.7		—		4,073,681				Restoration Benefit	4		—		—
Adrian J. Rodriguez3		Retirement Contribution	.9		11,600		—
Margaret F. Hopkins										Margaret F. Hopkins	Retirement Plan	13.3		373,812		—
											SERP	13.3		2,520,357		—
Andrew Wappler										Andrew Wappler	Retirement Plan	14.8		512,011		—
		Restoration Benefit	.9		—		—				SERP	14.8		2,513,830		—
Steve R. Secrist	Steve R. Secrist	Retirement Plan	32.6		897,024		—			Steve R. Secrist	Retirement Plan	33.5		979,620			—
		SERP	32.6		4,594,485		—				SERP	33.5		—			4,855,525
Margaret F. Hopkins		Retirement Plan	12.3		409,454			—
		SERP	12.3		2,460,269			—
Booga K. Gilbertson		Retirement Plan	35.6		912,812		—
		SERP	35.6		3,431,837			—

_______________

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, ~~2021,~~2022, 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 ~~3.00%~~5.60%, and the post-retirement mortality assumption is based on the ~~2022~~2023 417(e) unisex mortality table. Annuity benefits are converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of ~~1.07%~~1.41%, ~~2.68%~~3.09%, and ~~3.36%~~3.58% (the 24-month average of the underlying rates as of September ~~2021)~~2022), except that payments assumed to occur during ~~2022~~2023 use segment rates in effect for ~~2022~~2023 (this does not apply to any Named Executive Officers this year). These assumptions are consistent with the ones used for the Retirement Plan and the SERP for financial reporting purposes for ~~2021.~~2022. 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, ~~2020,~~2021, for the benefits earned as of that date using the assumptions used for financial reporting purposes for ~~2020.~~2021. These assumptions included assumed cash balance interest credits of 4.0%, a discount assumption of ~~2.70%~~3.00% and post-retirement mortality assumption based on the ~~2021~~2022 417(e) unisex mortality table. Annuity benefits were converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of ~~2.22%~~1.07%, ~~3.38%~~2.68%, and ~~3.92%~~3.36% (the 24-month average of the underlying rates as of September ~~2020)~~2021). Other assumptions used to determine the value as of December 31, ~~2020,~~2021, were the same as those used for December 31, ~~2021.~~2022.

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, ~~2021.~~2022. Each SERP-eligible Named Executive Officer was vested in his or her SERP benefits as of December 31, ~~2021.~~2022.

~~155~~156

Name

Estimated Lump Sum

~~Steve R. Secrist~~

~~4,886,309~~

Margaret F. Hopkins

~~2,866,213~~3,162,728

Andrew Wappler

3,126,019

_______________________

33.. Ms. Kipp, Mr. Hasan and Mr. ~~Rodriguez~~Smith do not have SERP benefits as that plan was closed prior to their joining PSE. Ms. Kipp and Mr. Hasan do not have a Retirement Plan benefit, as upon hire, each elected to have their 4% company retirement contribution made to their 401(k) accounts. Based on service through December 31, ~~2021~~2022 these 401(k) accounts had values of: Ms. Kipp, ~~$34,093;~~$40,932; Mr. Hasan, $20,105; and Mr. ~~Hasan, $9,651.~~Smith, $10,500. Ms. Kipp, Mr. Hasan and Mr. ~~Rodriguez~~Smith also participate in the Officer Restoration Benefit Plan as described below, with vesting after three years of service. The value of these Officer Restoration accounts based on service through December 31, ~~2021~~2022 are: Ms. Kipp, ~~$76,960;~~$127,426; and Mr. ~~Rodriguez, $7,413.~~Hasan, $20,294, Mr. ~~Hasan's~~Smith's first Officer Restoration account contribution will be made in ~~2022.~~2023.

4.As a result of retirement on ~~September~~December 1, ~~2021,~~2022, Mr. ~~Doyle~~Secrist received a SERP lump sum in the amount of ~~$4,073,681,~~$4,855,525, calculated per the plan and paid according to Mr. Doyle's payment election. Additionally, as a result of retirement on October 1, 2021, Ms. Gilbertson became eligible for her SERP benefit which will commence payments in 2025, according to Ms. Gilbertson'sSecrist's 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 participating 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 ~~2021,~~2022, the limit was ~~$290,000.~~$305,000. For ~~2022,~~2023, the limit is ~~$305,000.~~$330,000. 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 ~~2021~~2022 and ~~2022,~~2023, 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.~~65 (employees designated as casual employees by PSE and who have reached age 65 or employees who have applied for long-term disability and have reached age 65 may commence benefits without terminating employment). 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, ~~2021,~~2022, all the Named Executive Officers, except Ms. Kipp, Mr. Hasan and Mr. ~~Rodriguez~~Smith were vested in their benefits under the Retirement Plan and, hence, would be eligible to commence benefit payments upon termination.

The normal form of benefit payment for unmarried participants is a straight life annuity providing monthly payments for the remainder of the participant’s life, with no death benefits. The straight life annuity payable on or after the participant's normal retirement age is actuarially equivalent to the balance in the participant’s Cash Balance Account as of the date of distribution. For married participants, the normal form of benefit payment is an actuarially equivalent joint and 50% survivor annuity with a “pop-up” feature providing reduced monthly payments (as compared to the straight life annuity) for the remainder of the participant’s life and, upon the participant’s death, monthly payments to the participant’s surviving spouse for the remainder of the spouse’s life in an amount equal to 50% of the amount being paid to the participant. Under the pop-up feature, if the participant’s spouse predeceases the participant, the participant’s monthly payments increase to the level that would have been provided under the straight life annuity. In addition, the Retirement Plan provides several other annuity payment options and a lump sum payment option that can be elected by participants. All payment options are actuarially equivalent to the straight life annuity. However, in no event will the amount of the lump sum payment be less than the balance in the participant’s Cash Balance Account as of the date of distribution (in some instances the amount of the lump sum

~~156~~157

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 (or promoted to officer) 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, have been exempted from the age 55 vesting requirement. All the participating Named Executive Officers with SERP eligibility 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 ~~“2021~~“2022 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

~~157~~158

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.~~eligible for this benefit. Ms. Kipp, Mr. Hasan and Mr. ~~Rodriguez~~Smith participate 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 for each within the Deferred Compensation Plan.

~~2021~~2022 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 ~~2021~~2022 and year-end account balances under the Deferred Compensation Plan.


Name	Name	Executive Contributions in 20211			Registrant Contributions in 20212			Aggregate Earnings in 20213			Aggregate Withdrawals/ Distributions			Aggregate Balance at December 31, 20214			Name	Executive Contributions in 20221			Registrant Contributions in 20222			Aggregate Earnings in 20223			Aggregate Withdrawals/ Distributions			Aggregate Balance at December 31, 20224
Mary E. Kipp	Mary E. Kipp		$	1,084,486		$	67,628		$	167,903		$	—		$	1,660,065	Mary E. Kipp		$	1,016,624		$	45,056		$	—		$	—		$	2,370,392
Kazi Hasan	Kazi Hasan		2,125			—			107			—			2,232		Kazi Hasan		46,452			22,428			—			—			66,433
Daniel A. Doyle			16,208			18,308			100,664			1,548,251			—
Adrian J. Rodriguez			—			—			—			—			—
Allan (Wade) Smith																	Allan (Wade) Smith		—			—			—			—			—
Margaret F. Hopkins																	Margaret F. Hopkins		30,028			19,380			—			—			871,753
Andrew Wappler																	Andrew Wappler		—			—			—			—			—
Steve R. Secrist	Steve R. Secrist		32,883			24,554			31,300			—			413,622		Steve R. Secrist		31,058			23,167			—			(292,308)			133,943
Margaret F. Hopkins			138,978			15,382			108,618						963,093
Booga K. Gilbertson			—			—			81,404			987,234			—

_______________

1.The amount in this column reflects elective deferrals by the executive of salary, annual incentive compensation or LTI Plan awards paid in ~~2021.~~2022. Deferred salary amounts are: Ms. Kipp, ~~$221,933;~~$0; Mr. Hasan, ~~$2,125;~~$46,452; Mr. ~~Doyle, $16,208;~~Smith, $0; Ms. Hopkins, $30,028; Mr. ~~Rodriguez,~~Wappler, $0; and Mr. Secrist, ~~$32,883; Ms. Hopkins, $23,663; and Ms. Gilbertson, $0.~~$30,889. Deferred annual incentive compensation and LTI Plan award amounts are $0 for all Named Executives, except for Ms. Kipp who deferred ~~$156,128~~$172,524 in incentive compensation and ~~$706,425~~$844,100 in LTIPlan awards and ~~Ms. Hopkins~~Mr. Secrist who deferred ~~$26,202~~$169 in annual incentive ~~compensation and $89,112 in LTI Plan awards.~~compensation.. The amounts are also included in the applicable column of the Summary Compensation Table for ~~2021.~~2022.

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 ~~2021.~~2022.

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~~None of the executives received above market earnings on these ~~amounts are included in the Change in Pension Value and Non-qualified Deferred Compensation Earnings column of the Summary Compensation Table for 2021.~~amounts.

4.Of the amounts in this column, the amounts in the table below have also been reported in the Summary Compensation Table for 2022, 2021, ~~2020,~~ and ~~2019.~~2020.


Name	Name	Reported for 2021			Reported for 2020			Reported for 2019			Name	Reported for 2022			Reported for 2021			Reported for 2020
Mary E. Kipp	Mary E. Kipp		$	1,084,486		$	242,609		$	64,500	Mary E. Kipp		$	1,016,624		$	1,084,486		$	242,609
Kazi Hasan	Kazi Hasan		2,125			—			—		Kazi Hasan		46,452			2,125			—
Daniel A. Doyle			16,208			59,358			66,403
Adrian J. Rodriguez			—			—			—
Allan (Wade) Smith											Allan (Wade) Smith		—			—			—
Margaret F. Hopkins											Margaret F. Hopkins		30,028			138,978			156,861
Andrew Wappler											Andrew Wappler		—			—			—
Steve R. Secrist	Steve R. Secrist		32,883			61,665			67,034		Steve R. Secrist		31,058			32,883			61,665
Margaret F. Hopkins			138,978			156,861			—
Booga K. Gilbertson			—			75,893			—

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

~~158~~

equals the additional matching and any other employer contribution under the 401(k) plan that would have been credited to an electing executive’s 401(k) plan account if the Internal Revenue Code limitations were not in place and if deferrals under the Deferred Compensation Plan were instead made to the 401(k) plan. The annual cash balance restoration amount equals the

159

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 participants with deferrals prior to 2012, an interest crediting fund was ~~available.~~available; however this does not apply to any of 2022’s Named Executive Officers. The tracking funds differ from the investment funds offered in the 401(k) plan. The ~~2021~~2022 calendar year returns of these tracking funds were:


Vanguard Total Bond Market Index		~~-1.65%~~(13.15)	%
Vanguard 500 Index		~~28.66~~(18.15)
Vanguard Money Market Index		~~.01~~
~~Interest Crediting Fund (pre-2012 deferrals)~~1.55	~~3.03~~

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 from available alternatives. 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~~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. 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.

~~159~~

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,

160

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~~

PSE has no ~~Executive Employment Agreements (Employment Agreements)~~employment agreements with any ~~Covered Executives.~~executive officers, including the Named Executive Officers.

Estimated Potential Incremental Payments upon Termination or Change in Control

The amounts shown in the table below assume that the termination of employment of a Named Executive Officer or a change in control was effective as of December 31, ~~2021.~~2022. 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. Mr. ~~Doyle and Ms. Gilbertson were~~Secrist was not employed as of as of December 31, ~~2021~~2022 and ~~are~~is not included in the table. The pro-rated LTI Plan amounts payable to ~~them~~him in connection with ~~their retirements~~his retirement pursuant to the terms of the LTI Plan are disclosed in the “Details of All Other Compensation” section of the Summary Compensation Table, which aggregate amount ~~for Mr. Doyle~~ was ~~$707,433 and for Ms. Gilbertson, was $608,323.~~$873,290.


		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			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	Mary E. Kipp	$	—	$	—	$	—	$	—	$	—	Mary E. Kipp	$	—	$	—	$	—	$	—	$	—
Long Term Incentive Plan	Long Term Incentive Plan	4,499,085		4,499,085		—		3,580,571		3,580,571		Long Term Incentive Plan	5,313,294		5,313,294		—		4,885,438		4,885,438
Supplemental Life Insurance	Supplemental Life Insurance	—		—		—		—		3,120,000		Supplemental Life Insurance	—		—		—		—		3,885,975
Total Estimated Incremental Value	Total Estimated Incremental Value	$	4,499,085	$	4,499,085	$	—	$	3,580,571	$	6,700,571	Total Estimated Incremental Value	$	5,313,294	$	5,313,294	$	—	$	4,885,438	$	8,771,413
Kazi Hasan	Kazi Hasan	$	—	$	—	$	—	$	—	$	—	Kazi Hasan	$	—	$	—	$	—	$	—	$	—
Long Term Incentive Plan	Long Term Incentive Plan	490,005		490,005		—		412,574		412,574		Long Term Incentive Plan	1,207,500		1,207,500		—		1,054,103		1,053,103
Supplemental Life Insurance	Supplemental Life Insurance	—		—		—		—		1,173,000		Supplemental Life Insurance	—		—		—		—		1,482,806
Total Estimated Incremental Value	Total Estimated Incremental Value	$	490,005	$	490,005	$	—	$	412,574	$	1,585,574	Total Estimated Incremental Value	$	1,207,500	$	1,207,500	$	—	$	1,054,103	$	2,535,909
Adrian J. Rodriguez		$	—	$	—	$	—	$	—	$	—
Long Term Incentive Plan		530,880		530,880		—		448,596		448596
Supplemental Life Insurance		—		—		—		—		1,219,000
Total Estimated Incremental Value		$	530,880	$	530,880	$	—	$	448,596	$	1,667,596
Steve R. Secrist		$	—	$	—	$	—	$	—	$	—
Allan (Wade) Smith												Allan (Wade) Smith	$	—	$	—	$	—	$	—	$	—
Long Term Incentive Plan	Long Term Incentive Plan	1,007,018		1,007,018		—		796,694		796,694		Long Term Incentive Plan	1,048,950		1,048,950		—		808,419		808419
Supplemental Life Insurance	Supplemental Life Insurance	—		—		—		—		1,152,272		Supplemental Life Insurance	—		—		—		—		1,668,000
Total Estimated Incremental Value	Total Estimated Incremental Value	$	1,007,018	$	1,007,018	$	—	$	796,694	$	1,948,966	Total Estimated Incremental Value	$	1,048,950	$	1,048,950	$	—	$	808,419	$	2,476,419
Margaret F. Hopkins	Margaret F. Hopkins	$	—	$	—	$	—	$	—	$	—	Margaret F. Hopkins	$	—	$	—	$	—	$	—	$	—
Long Term Incentive Plan	Long Term Incentive Plan	464,201		464,201		—		378,126		378,126		Long Term Incentive Plan	690,318		690,318		—		626,529		626,529
Supplemental Life Insurance	Supplemental Life Insurance	—		—		—		—		952,338		Supplemental Life Insurance	—		—		—		—		980,911
Total Estimated Incremental Value	Total Estimated Incremental Value	$	464,201	$	464,201	$	—	$	378,126	$	1,330,464	Total Estimated Incremental Value	$	690,318	$	690,318	$	—	$	626,529	$	1,607,440
Andrew Wappler												Andrew Wappler	$	—	$	—	$	—	$	—	$	—
Long Term Incentive Plan												Long Term Incentive Plan	411,328		411,328		—		375,219		375,219
Supplemental Life Insurance												Supplemental Life Insurance	—		—		—		—		924,683
Total Estimated Incremental Value												Total Estimated Incremental Value	$	411,328	$	411,328	$	—	$	375,219	$	1,299,902

~~160~~161

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 ~~2021,~~2022, our last completed fiscal year:

•The annual total compensation of our CEO reported in the ~~2021~~2022 Summary Compensation Table, was ~~$4,414,245.~~$4,760,931.

•The median of the annual total compensation of all our employees (excluding our CEO) was ~~$128,800.~~$126,400.

As a result, for ~~2021~~2022 the ratio of annual total compensation of our Chief Executive Officer to the median of our annual total compensation of all employees was ~~34:~~38:1.

We identified our median employee by examining the total cash compensation we paid during ~~2021~~2022 to all individuals, excluding our CEO, who were employed by us on December 31, ~~2021,~~2022, which totaled approximately ~~3,189~~3,250 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.

After identifying the median employee based on total cash compensation for ~~2021,~~2022, we calculated annual total compensation for such employee for ~~2021~~2022 using the same methodology we use for our named executive officers as set forth in the ~~2021~~2022 Summary Compensation Table in accordance with the requirements of Item 402 (c)(2)(x) of Regulation S-K. Annual total compensation for ~~2021~~2022 for our median employee included annual salary, annual incentives, and company contributions towards benefits including retirement. Annual total compensation for ~~2021~~2022 for our CEO consists of the amount reported in the "Total" column of our ~~2021~~2022 Summary Compensation Table.

Director Compensation for Fiscal Year ~~2021~~2022

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 ~~2021~~2022 for service as directors. We refer to these directors as 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: ~~Chris Hind,~~ Grant Hodgkins, Jean-Paul Marmoreo, Chris Parker, Aaron Rubin, Martijn Verwoest, and Steven Zucchet.

As described in further detail below, the Company’s non-employee director compensation program in ~~2021~~2022 consisted of quarterly retainer cash fees of $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	Name	Fees Earned		Nonqualified Deferred Compensation Earnings1		Total		Name	Fees Earned		Nonqualified Deferred Compensation Earnings1		Total
Scott Armstrong	Scott Armstrong	$	193,420	$	—	$	193,420	Scott Armstrong	$	235,534	$	—	$	235,534
Richard Dinneny								Richard Dinneny	177,200		—		177,200
Barbara Gordon	Barbara Gordon	173,925		—		173,925		Barbara Gordon	192,200		—		192,200
Steve Hooper		—		154,549		154,549
Thomas King	Thomas King	175,600		—		175,600		Thomas King	177,200		—		177,200
Paul McMillan	Paul McMillan	186,600		—		186,600		Paul McMillan	188,200		—		188,200
Mary McWilliams		171,600		—		171,600
Richard Dinneny		102,967		—		102,967
Diana Rakow								Diana Rakow	114,000		—		114,000

_______________

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

~~161~~

Non-employee Director Compensation Program

The ~~2021~~2022 non-employee director compensation program is based on the principles that the level of non-employee director compensation should be based on Board and committee responsibilities and should be competitive with comparable companies.

The ~~2021~~2022 compensation program for non-employee directors was as follows:

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

2.A $1,600 per meeting fee ($800 for telephonic) will be paid when the number of Board or Committee meetings exceed six per year (not applicable to Asset Management Committee calls).

162

In ~~2021,~~2022, 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, $3,750;

3.Chair of the Governance Committee, $3,750;

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

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

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

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

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 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. Non-employee directors are permitted to make changes in measurement fund allocations quarterly. ~~Steve Hooper is the only independent board member to defer any director fees during 2021.~~

~~162~~163

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, ~~2021,~~2022, 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 February ~~24, 2022.~~23, 2023.

Beneficial Ownership Table of Puget Energy and PSE


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

_______________

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 LLC (Puget Holdings and together with Puget Intermediate, the Parent Entities), 6860141 Canada Inc. as trustee for British Columbia Investment Management Corporation (BCI), PIP2PX (Pad) Ltd. (PIP2PX) and PIP2GV (Pad) Ltd. ((PIP2GV), and together with Clean Energy JV Sub 1, LP (JV Sub 1), Clean Energy JV Sub 2, LP (JV Sub 2), Ontario Municipal Employee Retirement System (OMERS), PGGM Vermogensbeheer B.V. (PGGM), 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, 2022:~~23, 2023:

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

•The address of the principal office of OMERS is 900-100 Adelaide Street West, Toronto, Ontario, Canada, M5H E02.

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

•The address of the principal office of JV Sub 1 is 125 West 55th Street, Level 15 New York, NY 10019.

•The address of the principal office of JV Sub 2 is 5650 Yonge Street Toronto, Ontario, M2M 4H5 Canada.

•The address of the principal office of BCI is 750 Pandora Ave, Victoria, British Columbia, Canada V8W 0E4.

•The address of the principal office of PIP2PX and PIP2GV is 10250, 101 Street NW, Edmonton, Alberta, Canada T5J 3P4.

2 Pursuant to that certain Pledge Agreement dated as of May 10, 2010, as amended on February 10, 2012, and as further amended and extended as of April 15, 2014, 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, which Credit Agreement was amended and restated by the Second Amended and Restated Credit Agreement dated May 16, 2022 among Puget Energy, Inc. as Borrower, JP Morgan Chase Bank N.A. as Administrative Agent, 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.~~2015, May 19, 2020, June 14, 2020, and March 17, 2022.

3Pursuant to that certain Borrower's Security Agreement dated as of May 10, 2010, as amended on February 10, 2012, and as further amended and extended as of April 15, 2014, 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, which Credit Agreement was amended and restated by the Second Amended and Restated Credit Agreement dated May 16, 2022 among Puget Energy Inc., as Borrower, JPMorgan Chase Bank N.A., as Administrative Agent, and the lenders party thereto and (b) the senior secured notes issued on December 6, 2010, June 3, ~~2011,~~2011May 12, 2015, May 19, 2020, June ~~15, 2012~~1514, 20122020 and May 12, ~~2015.~~2015March 17, 2022.

~~163~~164

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.

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, Scott Armstrong ~~(member~~and Barbara Gordon (members of the Boards of both Puget Energy and ~~PSE,~~PSE) and ~~Barbara Gordon~~Diana Rakow (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 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

165

which is less than the greater of $1.0 million or one percent of such other company’s consolidated gross revenue, determined

~~164~~

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. Armstrong and Ms. ~~McWilliams~~Rakow 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. Armstrong, 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 (PCAOB ID No. 238), the Company’s independent registered public accounting firm, for the years ended December 31, ~~2021,~~2022, and ~~2020~~2021 were as follows:


		2021				2020					2022				2021
(Dollars in Thousands)	(Dollars in Thousands)	Puget Energy		PSE		Puget Energy		PSE		(Dollars in Thousands)	Puget Energy		PSE		Puget Energy		PSE
Audit fees1	Audit fees1	$	2,547	$	2,299	$	2,598	$	2,346	Audit fees1	$	2,881	$	2,611	$	2,547	$	2,299
Audit related fees2	Audit related fees2	308		80		152		—		Audit related fees2	239		43		308		80

Other fees3	Other fees3	54		54		52		52		Other fees3	60		60		54		54
Total	Total	$	2,909	$	2,433	$	2,802	$	2,398	Total	$	3,180	$	2,714	$	2,909	$	2,433

_______________

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 ~~2021~~2022 fees are estimated and include an aggregate amount of ~~$1.7~~$2.2 million billed to Puget Energy and ~~$1.6~~$1.8 million billed to PSE through December ~~2021.~~2022.

2.Consists of work performed in connection with registration statements and other regulatory audits. Audit related fees for Puget Energy contain amounts related to the PLNG Assess and Recommend ~~procedures, which did not have any fees associated in 2020.~~procedures.

3.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, 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 ~~2021~~2022 and ~~2020,~~2021, all audit and non-audit services were pre-approved.

~~165~~

166

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

a)Documents filed as part of this report:

1) Financial Statements

2) Financial Statement Schedules. Financial Statement Schedules of the Company, as required for the years

ended December 31, 2022, 2021, ~~2020,~~ and ~~2019,~~2020, 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.

~~166~~167

EXHIBIT INDEX

Certain of the following exhibits are filed herewith. Certain other of the following exhibits have heretofore been filed with the SEC and are incorporated herein by reference.


	~~2.1~~	Agreement and Plan of Merger, dated October 25, 2007, by and among Puget Energy, Inc. Padua Holdings LLC, Padua Intermediate Holdings Inc. and Padua Merger Sub Inc. (incorporated herein by reference to Exhibit 2.1 to Puget Energy’s Current Report on Form 8-K, dated October 25, 2007, Commission File No. 1-16305).
	3 .13.1	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 .23.2	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).
*	3.3	Amended and Restated Bylaws of Puget Energy, ~~Inc. dated February 6, 2009,~~Inc ., as amended by the First Amendment to the Amended and ~~Restated~~Res tated Bylaws of Puget Energy ~~Inc.~~Inc ., dated January 6, ~~2022.~~2022 (incorporated herein by reference to Exhi bit 3.3 to Puget Energy's Current Rep ort on Form 10-K, dated Febr uary 25, 2022, Commission File No. 1-16305).
*	3.4	Amended and Restated Bylaws of Puget Sound Energy, Inc. ~~dated February 6, 2009,~~, as amended by the ~~First~~F irst Amendment to the Amended and Restated Bylaws of ~~Puget~~Pu get Sound Energy, Inc. dated January 6, 2022
*	~~3.5~~	~~First Amendment~~(incorporated herein by reference to ~~the Amended and Restated Bylaws of Puget Energy, Inc. dated January 6, 2022~~
*	~~3.6~~	~~First Amendment~~Exhibit 3.4 to ~~the Amended and Restated Bylaws of~~ Puget Sound ~~Energy, Inc.,~~Energy's Current Report on F orm 10-K, dated ~~January 6,~~Feb ruary 25, 2022, Commission File No. 1-04393).
***	4.1	Indenture between Puget Sound Energy, Inc. and U.S. Bank National Association (as successor to State Street Bank and Trust Company) defining the rights of the holders of Puget Sound Energy’s senior notes (incorporated herein by reference to Exhibit 4-a to Puget Sound Energy’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1998, Commission File No. 1-4393).
	4.2	First, Second, Third, Fourth, and 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; Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated May 28, 2003, Commission File No. 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 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.

~~167~~


***						Commission File No. 1-4393); Exhibit 4.4 to Post-Effective Amendment No. 2 to Puget Sound Energy’s Registration Statement on Form S-3, filed February 9, 2009.
						Registration No. 333-132497-01; Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated September 13, 2006.

168


***		Commission File No. 1-4393; Exhibit 4.1 to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2007. Commission File No. 1-4393; and Exhibit 4.5 to Post-Effective Amendment No. 2 to Puget Sound Energy’s Registration Statement on Form S-3, filed February 9, 2009.
		Registration No. 333-132497-01); Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated September 8, 2009, Commission File No. 1-4393.
		Commission File No. 1-4393; Exhibit 4.28 to Puget Sound Energy's Current Report on 10-K for fiscal year ended December 31, 2004.
	4.5	Eighty-eighth, Eighty-ninth and Ninetieth Supplemental Indentures defining the rights of the holders of Puget Sound Energy's Electric Utility First Mortgage Bonds (incorporated herein by reference to Exhibits 4.1 through 4.3 to Puget Sound Energy's Report on Form 10-Q for the quarter ended March 31, 2012, Commission File No. 1-4393).
		Exhibits 4.1 through 4.3: 4.1, 4.2, 4.3.
	4.6	Ninety-first and Ninety-second supplemental Indentures defining the rights of the holders of Puget Sound Energy’s Electric Utility First Mortgage Bonds (incorporated herein by reference to Exhibit 4.6 to Puget Sound Energy’s Registration Statement on Form S-3, filed January 24, 2014. Registration No. 333-193555 and to Exhibit 4.4 to Puget Sound Energy’s Current Report on Form 8-K filed May 29, 2013).
	4.7	Indenture of First Mortgage, dated as of April 1, 1957, defining the rights of the holders of Puget Sound Energy’s Gas Utility First Mortgage Bonds (incorporated herein by reference to Puget Sound Energy’s Registration Statement on Form S-3ASR, filed March 13, 2009, Registration No. 333-157960).
	4.8	First, Sixth, Seventh, Sixteenth and Seventeenth Supplemental Indenture to the Gas Utility First Mortgage, dated as of April 1, 1957, August 1, 1966, February 1, 1967, June 1, 1977, and August 9, 1978, respectively (incorporated herein by reference to Exhibits 4.26 through and including 4.30 to Puget Sound Energy's Registration Statement on Form S-3, filed March 13, 2009, Registration No. 333-157960).
		Exhibits 4.26 through 4.30: 4.26, 4.27, 4.28, 4.29, 4.30.
***	4.9	Twenty-second Supplemental Indenture to the Gas Utility First Mortgage, dated as of July 15, 1986 (incorporated herein by reference to Exhibit 4-B.20 to Washington Natural Gas Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 1986, Commission File No. 0-951).
***	4.10	Twenty-seventh Supplemental Indenture to the Gas Utility First Mortgage, dated as of September 1, 1990 (incorporated herein by reference to Exhibit 4.12 to Post-Effective Amendment No. 2 to Puget Sound Energy’s Registration Statement on Form S-3, filed February 9, 2009, Registration No. 333-132497-01).
***	4.11	Twenty-eighth through Thirty-sixth Supplemental Indentures to the Gas Utility First Mortgage (incorporated herein by reference to Exhibit 4-A to Washington Natural Gas Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1993, Commission File No. 0-951; Exhibit 4-A to Washington Natural Gas Company’s Registration Statement on Form S-3, Registration No. 33-49599; Exhibit 4-A to Washington Natural Gas Company’s Registration Statement on Form S-3, Registration No. 33-61859; Exhibit 4.30 to Puget Sound Energy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, Commission File No. 1-4393; Exhibits 4.22 and 4.23 to Puget Sound Energy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2005. Commission File No. 1-4393; Exhibits 4.22 and 4.23 to Puget Sound Energy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2007, Commission File No. 1-4393; and Exhibit 4.14 to Post-Effective Amendment No. 2 to Puget Sound Energy’s Registration Statement on Form S-3, filed February 9, 2009, Registration No. 333-132497-01).
	4.12	Unsecured Debt Indenture, dated as of May 18, 2001, between Puget Sound Energy, Inc. and The Bank of New York Mellon Trust Company, N.A. (as successor to Bank One Trust Company, N.A.) defining the rights of the holders of Puget Sound Energy’s unsecured debentures (incorporated herein by reference to Exhibit 4.3 to Puget Sound Energy’s Current Report on Form 8-K, dated May 18, 2001, Commission File No. 1-4393).
	4.13	Second Supplemental Indenture to the Unsecured Debt Indenture, dated June 1, 2007, between Puget Sound Energy, Inc. and The Bank of New York Mellon Trust Company, N.A. defining the rights of Puget Sound Energy’s Series A Enhanced Junior Subordinated Notes due June 1, 2067 (incorporated herein by reference to Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated May 30, 2007, Commission File No. 1-4393).
	4.14	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).

~~168~~


			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).

169


	4.17	First 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 December 15, 2020 (incorporated by reference to Exhibit 4.2 to Puget Energy's Current Report on Form 8-K, filed December 7, 2010, Commission File No. 1-16305).
	~~4.17~~4.18	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).
	~~4.18~~4.19	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).
	~~4.19~~4.20	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).
	~~4.20~~4.21	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).
	~~4.21~~4.22	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).
	~~4.22~~4.23	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~~4.24	Fifth Supplemental Indenture dated May 19, 2020 relating to Puget Energy's 4.1% Senior Secured Notes due 2030 (Incorporated herein by reference to Exhibit 4.1 to Puget Energy's Current Report on Form 8-K Filed May 19, 2020, Commission File No. 1-16305).
	4.25	Sixth Supplemental Indenture dated June 14, 2021 relating to Puget Energy's 2.379% Senior Secured Notes due 2028 (incorporated herein by reference to Exhibit 4.1 to Puget Energy's Current Report on Form 8-K Filed June 21, 2021, Commission File No. 1-16305).
	4.26	Seventh Supplemental Indenture dated March 17, 2022 relating to Puget Energy's 4.224% Senior Secured Notes due 2032 (incorporated herein by reference to Exhibit 4.1 to Puget Energy's Current Report on Form 8-K Filed March 18, 2022, Commission File No. 1-16305).
***	10.1	First Amendment dated as of October 4, 1961 to Power Sales Contract between Public Utility District No. 1 of Chelan County, Washington and Puget Sound Energy, Inc., relating to the Rocky Reach Project (incorporated herein by reference to Exhibit 10.1 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
***	10.2	First Amendment dated February 9, 1965 to Power Sales Contract between Public Utility District No. 1 of Douglas County, Washington and Puget Sound Energy, Inc., relating to the Wells Development (incorporated herein by reference to Exhibit 10.2 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
***	10.3	Contract dated November 14, 1957 between Public Utility District No. 1 of Chelan County, Washington and Puget Sound Energy, Inc., relating to the Rocky Reach Project (incorporated herein by reference to Exhibit 10.3 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
***	10.4	Power Sales Contract dated as of November 14, 1957 between Public Utility District No. 1 of Chelan County, Washington and Puget Sound Energy, Inc., relating to the Rocky Reach Project (incorporated herein by reference to Exhibit 10.4 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
***	10.5	Power Sales Contract dated May 21, 1956 between Public Utility District No. 2 of Grant County, Washington and Puget Sound Energy, Inc., relating to the Priest Rapids Project (incorporated herein by reference to Exhibit 10.5 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
***	10.6	First Amendment to Power Sales Contract dated as of August 5, 1958 between Puget Sound Energy, Inc. and Public Utility District No. 2 of Grant County, Washington, relating to the Priest Rapids Development (incorporated herein by reference to Exhibit 10.6 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
***	10.7	Power Sales Contract dated June 22, 1959 between Public Utility District No. 2 of Grant County, Washington and Puget Sound Energy, Inc., relating to the Wanapum Development (incorporated herein by reference to Exhibit 10.7 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).

170


***	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).

~~169~~


***	10.10	Construction and Ownership Agreement dated as of July 30, 1971 between The Montana Power Company and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 10.10 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
***	10.11	Operation and Maintenance Agreement dated as of July 30, 1971 between The Montana Power Company and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 10.11 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
***	10.12	Contract dated June 19, 1974 between Puget Sound Energy, Inc. and P.U.D. No. 1 of Chelan County (incorporated herein by reference to Exhibit 10.12 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
***	10.13	Transmission Agreement dated April 17, 1981 between the Bonneville Power Administration and Puget Sound Energy, Inc. (Colstrip Project) (incorporated herein by reference to Exhibit (10)-55 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
***	10.14	Transmission Agreement dated April 17, 1981 between the Bonneville Power Administration and Montana Intertie Users (Colstrip Project) (incorporated herein by reference to Exhibit (10)-56 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
***	10.15	Ownership and Operation Agreement dated as of May 6, 1981 between Puget Sound Energy, Inc. and other Owners of the Colstrip Project (Colstrip 3 and 4) (incorporated herein by reference to Exhibit (10)-57 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
***	10.16	Colstrip Project Transmission Agreement dated as of May 6, 1981 between Puget Sound Energy, Inc. and Owners of the Colstrip Project (incorporated herein by reference to Exhibit (10)-58 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
***	10.17	Common Facilities Agreement dated as of May 6, 1981 between Puget Sound Energy, Inc. and Owners of Colstrip 1 and 2, and 3 and 4 (incorporated herein by reference to Exhibit (10)-59 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
***	10.18	Amendment dated as of June 1, 1968, to Power Sales Contract between Public Utility District No. 1 of Chelan County, Washington and Puget Sound Energy, Inc. (Rocky Reach Project) (incorporated herein by reference to Exhibit (10)-66 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
***	10.19	Transmission Agreement dated as of December 30, 1987 between the Bonneville Power Administration and Puget Sound Energy, Inc. (Rock Island Project) (incorporated herein by reference to Exhibit (10)-74 to Report on Form 10-K for the fiscal year ended December 31, 1988, Commission File No. 1-4393).
***	10.20	Amendment No. 1 to the Colstrip Project Transmission Agreement dated as of February 14, 1990 among The Montana Power Company, The Washington Water Power Company (Avista), Portland General Electric Company, PacifiCorp and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit (10)-91 to Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393).
***	10.21	Amendment of Seasonal Exchange Agreement, dated December 4, 1991 between Pacific Gas and Electric Company and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit (10)-107 to Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393).
***	10.22	Capacity and Energy Exchange Agreement, dated as of October 4, 1991 between Pacific Gas and Electric Company and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit (10)-108 to Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393).
***	10.23	General Transmission Agreement dated as of December 1, 1994 between the Bonneville Power Administration and Puget Sound Energy, Inc. (BPA Contract No. DE-MS79-94BP93947) (incorporated herein by reference to Exhibit 10.115 to Report on Form 10-K for the fiscal year ended December 31, 1994, Commission File No. 1-4393).
***	10.24	PNW AC Intertie Capacity Ownership Agreement dated as of October 11, 1994 between the Bonneville Power Administration and Puget Sound Energy, Inc. (BPA Contract No. DE-MS79-94BP94521) (incorporated herein by reference to Exhibit 10.116 to Report on Form 10-K for the fiscal year ended December 31, 1994, Commission File No. 1-4393).
	10.25	Amendment to Gas Transportation Service Contract dated July 31, 1991 between Washington Natural Gas Company and Northwest Pipeline Corporation (incorporated herein by reference to Exhibit 10-E.2 to Washington Natural Gas Company’s Form 10-K for the fiscal year ended September 30, 1995, Commission File No. 1-11271).

171


			10.26			Firm Transportation Service Agreement dated January 12, 1994 between Northwest Pipeline Corporation and Washington Natural Gas Company for firm transportation service from Jackson Prairie (incorporated herein by reference to Exhibit 10-P to Washington Natural Gas Company’s Form 10-K for the fiscal year ended September 30, 1994, Commission File No. 1-11271).
			10.27			Product Sales Contract dated December 13, 2001 and Amendment No. 1 thereto, between Public Utility District No. 2 of Grant County, Washington, and Puget Sound Energy, Inc., relating to the Priest Rapids Project (incorporated herein by reference to Exhibit 10-1 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended June 30, 2002, File No. 1-4393).

~~170~~


	10.28	Reasonable Portion Power Sales Contract dated December 13, 2001 and Amendment No. 1 thereto, between Public Utility District No. 2 of Grant County, Washington, and Puget Sound Energy, Inc., relating to the Priest Rapids Project (incorporated herein by reference to Exhibit 10-2 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended June 30, 2002, Commission File No. 1-4393).
	10.29	Additional Products Sales Agreement dated December 13, 2001, and Amendment No. 1 thereto, between Public Utility District No. 2 of Grant County, Washington, and Puget Sound Energy, Inc., relating to the Priest Rapids Project (incorporated herein by reference to Exhibit 10.3 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended June 30, 2002, Commission File No. 1-4393).
**	10.30	Form of Executive Employment Agreement with Executive Officers (incorporated herein by reference to Exhibit 10.1 to Puget Energy's and Puget Sound Energy's Current Report on Form 8-K, dated April 3, 2009, Commission file Nos. 1-16305 and 1-4393).
**	10.31	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 and Puget Sound Energy's Report on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305 and 1-4393).
**	10.32	Puget Sound Energy, Inc. Amended and Restated Supplemental Executive Retirement Plan effective January 1, 2013. (incorporated herein by reference 10.35 to Puget Energy's and Puget Sound Energy's Report on Form 10-K for the fiscal year ended December 31, 2012, Commission File Nos. 1-16305 and 1-4393).
**	10.33	Puget Sound Energy, Inc. Amended and Restated Deferred Compensation Plan for Key Employees effective January 1, 2009. (incorporated herein by reference to Exhibit 10.40 to Puget Energy's and Puget Sound Energy's Report on Form 10-K for the fiscal year ended December 31, 20018, Commission File No. 1-6305).
**	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 and Puget Sound Energy's Report on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305 and 1-4393)
**	10.35	Summary of Director Compensation (incorporated herein by reference to Exhibit 10.38 to Puget Energy's and Puget Sound Energy's Report on Form 10-K for the fiscal year ended December 31, 2015, Commission File No. 1-16305 and 1-4393.)
**	10.36	Puget Sound Energy, Inc. Supplemental Death Benefit Plan for Executive Employees, effective October1, 2000, as amended (incorporated herein by reference to Exhibit 10.45 to Puget Energy's and Puget Sound Energy's Report on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305).
**	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 and Puget Sound Energy's Report on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305 and 1-4393).
**	10.38	Puget Sound Energy, Inc. Supplemental Disability Plan for Executive Employees, effective October 1, 2000 as amended (incorporated herein by reference to Exhibit 10.47 to Puget Energy's and Puget Sound Energy's Report on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305 and 1-4393).
**	10.39	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 and Puget Sound Energy's Report on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305 and 1-4393).
**	10.40	Puget Energy, Inc. Amended and Restated 2005 Long-Term Incentive Plan, effective January 21, 2016 (incorporated herein by reference to Exhibit 10.43 to Puget Energy's and Puget Sound Energy's Report on Form 10-K for the fiscal year ended December 31, 2015, Commission File No. 1-16305 and 1-4393).
**	10.41	Second Amended and Restated Credit Agreement dated ~~October 25, 2017,~~May 16, 2022 among Puget Energy Inc., as Borrower, JPMorgan ~~Chase Bank~~Cha se Ba nk N.A., as Administrative Agent, and the ~~lenders~~l enders party ~~thereto. (incorporated~~ther e to. (incorporated by ~~reference~~r eference to Exhibit 10.1 to ~~Puget~~P uget Energy's Current Report on Form ~~8-K,~~8 -K, filed ~~October 31, 2017,~~May 23, 2022, Commission File No. 1-16305).
	10.42	Amended and Restated Credit Agreement dated ~~October 25, 2017,~~May 16, 2022, among Puget Sound Energy, Inc., as Borrower, Mizuho Bank, ~~Ltd.~~Lt d., as ~~Administrative~~Adm inistrative Agent, and the lenders party thereto. (incorporated by reference to ~~Exhibits~~Exhibit 10.2 to Puget Sound ~~Energy's~~En ergy's Current Report on Form 8-K , filed ~~October 31, 2017,~~May 23, 2022, Commission file No. 1-4393).

172


**	10.43	Purchase Agreement, dated June 4, 2018, between Puget Sound Energy, Inc. 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).
	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.

~~171~~


*	21.2	Subsidiaries of Puget Sound Energy, Inc.
*	22.1	Issuers of Guaranteed Securities and Affiliates Whose Securities Collateralize Securities of the Registrant
*	23.1	Consent of PricewaterhouseCoopers LLP for Puget Sound Energy, Inc.
*	23.2	Consent of PricewaterhouseCoopers LLP for Puget Energy, Inc.
*	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 – Mary E. ~~Kipp~~.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 –K a zi–Kazi Hasan
*	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 – 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 – Kazi ~~Hasan~~.Hasan.
*	32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 – 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 – ~~Kazi Hasan~~.Kazi Hasan.
*	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, ~~2020,~~2022, filed on February ~~25, 2021,~~23, 2023, formatted inas Inline XBRL: (i) the Consolidated Statement of Income, (ii) the Consolidated Statements of Comprehensive Income, (iii) the Consolidated Balance Sheets, (iii) the Consolidated Statements of Cash Flows, 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.

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

~~172~~173

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 ~~24, 2022~~23, 2023

Date:

February ~~24, 2022~~23, 2023

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


Signature	Title	Date
	(Puget Energy and PSE unless otherwise noted)

/s/ Mary E. Kipp	President and	February ~~24, 2022~~23, 2023
(Mary E. Kipp)	Chief Executive Officer

/s/ Kazi Hasan	~~Senior~~Executive Vice President and
(Kazi Hasan)	Chief Financial Officer

/s/ ~~Stephen J. King~~Stacy Smith	Controller and Principal Accounting Officer
(~~Stephen J. King)~~Stacy Smith)

/s/ Scott Armstrong	Director
(Scott Armstrong)

/s/ Jean-Paul Marmoreo	Director
(Jean-Paul Marmoreo)

/s/ Tom King	Director
(Tom King)

/s/ Richard Dinneny	Director
(Richard Dinneny)

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

/s/ Chris Parker	Director
(Chris Parker)

174


/s/ Paul McMillan			Director
(Paul McMillan)

/s/ Aaron Rubin			Director
(Aaron Rubin)

/s/ Grant Hodgkins			Director
(Grant Hodgkins)

/s/ Martijn Verwoest			Director
(Martijn Verwoest)

/s/ Steven Zucchet			Director
(Steven Zucchet)

/s/ Diana Birkett Rakow			Director of PSE Only
(Diana Birkett Rakow)

~~173~~175


	December 31,					December 31,
Retail Revenue by Class	2021		2020		Percent	2021		2020		Percent
(Dollars in Thousands)	Electric				Change	Natural Gas				Change
Residential	$	1,318,320	$	1,186,013	11.2%	$	722,002	$	662,502	9.0%
Commercial	902,928		791,898		14.0	292,217		253,526		15.3
Industrial	108,267		101,567		6.6	21,726		19,064		14.0
Other	38,054		37,864		0.5	20,104		17,296		16.2
Total	$	2,367,569	$	2,117,342	11.8%	$	1,056,049	$	952,388	10.9%


Puget Energy
(Dollars in Thousands)
Valuation Date	Contract Name	Carrying Value		Fair Value		Write Down
March 31, 2020	Rocky Reach	$	147,168	$	94,603	$	52,565
Total 2020 Impairments						$	52,565


Puget Energy
Valuation Date	Contract	Unobservable Input	Low		High		Average
March 31, 2020	Rocky Reach	Power prices (per MWh)	$	10.23	$	38.84	$	24.43
		Power contract costs per quarter (in thousands)	6,308		7,085		6,468


Name	2020 Base Salary	2021 Base Salary	% Change
Mary E. Kipp	$900,000	$930,000	3%
Kazi Hasan	N/A	510,000	—
Daniel A. Doyle	547,363	566,521	3.5
Adrian J. Rodriguez	N/A	530,000	—
Steve R. Secrist	483,626	500,553	3.5
Margaret F. Hopkins	350,000	414,000	18
Booga K. Gilbertson	428,145	470,531	9.9


Name	Target Incentive (% of Base Salary)1	ROE Component Units Granted/Paid	2019-2021 Actual LTIP Paid2
Mary E. Kipp3	220%	23,112.6/27,203.6	$	2,813,665
Kazi Hasan3	$125,000	1,534.9/1,806.6	186,855
Adrian J. Rodriguez3	31.6%	2,073.3/2,440.2	252,394
Steve R. Secrist	95	5,371/6,321.7	653,850
Margaret F. Hopkins	50	2,001/2,355.2	243,596