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, 2023

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

 For the transition period from ___________ to ___________

 Commission
 File Number

 Exact name of registrant as specified in its charter,
 state of incorporation,
 address of principal executive offices, zip code
 telephone number

 I.R.S.
 Employer
 Identification
 Number

 1-16305

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

 91-1969407

 1-4393

 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

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 N/A
 N/A

 Securities registered pursuant to Section 12(g) of the Act: None
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 Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
 Yes
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 Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
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 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.
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 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).

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 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.
 Large accelerated filer
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 Accelerated filer
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 Non-accelerated Filer

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 Smaller reporting company
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 Emerging growth company
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 Large accelerated filer
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 Accelerated filer
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 Non-accelerated Filer

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 Smaller reporting company
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 Emerging growth company
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 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.

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 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.

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 Yes
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 /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.

 Page

 Definitions

 Forward-Looking Statements

 1. Business

 General

 Regulation and Rates

 Electric Utility Operating Statistics

 Electric Supply

 Natural Gas Utility Operating Statistics

 Natural Gas Supply for Natural Gas Customers

 Integrated Resource Plans, Resource Acquisition and Development

 Energy Efficiency

 Environment

 Recent and Future Environmental Law and Regulation

 Human Capital Resources

 Information About Our Executive Officers

 1A. Risk Factors

 1B. Unresolved Staff Comments

 1C. Cybersecurity

 2. Properties

 3. Legal Proceedings

 4. Mine Safety Disclosures

 5. Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

 6. [Reserved]

 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

 7A. Quantitative and Qualitative Disclosures about Market Risk

 8. Financial Statements and Supplementary Data

 Report of Management and Statement of Responsibility

 Report of Independent Registered Public Accounting Firm – Puget Energy

 Report of Independent Registered Public Accounting Firm – Puget Sound Energy

 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 9A. Controls and Procedures

 9B. Other Information

 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

 10. Directors, Executive Officers and Corporate Governance

 11. Executive Compensation

 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters

 13. Certain Relationships and Related Transactions, and Director Independence

 14. Principal Accountant Fees and Services

 15. Exhibits and Financial Statement Schedules

 16. Form 10-K Summary

 Exhibit Index

 Signatures

 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

 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

 PTC
 Production Tax Credit

 PUDs
 Washington Public Utility Districts

 Puget Equico
 Puget Equico, LLC

 Puget Holdings
 Puget Holdings, LLC

 RCW

 Revised Code of Washington

 SEC
 United States Securities and Exchange Commission

 SERP
 Supplemental Executive Retirement Plan

 SOFR
 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 natural gas distribution and sales, 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, landslides, fires and wildfires (either affecting or caused by PSE's facilities or infrastructure), extreme weather conditions 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, impose extraordinary costs, and subject the Company to liability;

 •
 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 Washington Clean Energy Transformation Act (CETA) and the Washington 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 PSE's operational territory, which could have effects on customer usage and PSE's revenue and expenses;

 •
 Regional or national weather conditions (including conditions and events associated with climate change), wildfires, droughts, earthquakes, and other natural disasters, 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 and terms 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;

 •
 General economic and political conditions, such as the effects of geopolitical tensions related to the ongoing Russia-Ukraine and Israel-Hamas conflicts, recessions, fuel prices, international currency fluctuations, corruption, political instability, acts of war, and local and national elections;

 •
 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;

 •
 PSE's ability to attract, retain, and compensate employees while operating within a region of high demand for skilled workers resulting in significant competition and wage pressure;

 •
 The ability to obtain insurance coverage, the availability of insurance for certain specific losses, including those arising from catastrophic events such as wildfires 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 and the ability to pay dividends;

 •
 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 heating, 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.

 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 and operating 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 British Columbia Investment Management Corporation (BCIMC), the Alberta Investment Management Corporation (AIMCo), Ontario Municipal Employee Retirement System (OMERS), PGGM Vermogensbeheer B.V., Macquarie Washington Clean Energy Investment, L.P., and Ontario Teachers' Pension Plan Board. 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 table presents the number of PSE customers for electric and natural gas as of December 31, 2023 and 2022:

 Customer Count by Class
 2023

 2022

 Percent

 2023

 2022

 Percent

 (in thousands)

 Change

 Change

 1,084
 1,072
 1.1%
 0.6%

 0.7
 —

 —
 —

 Other
 —
 —
 —
 —

 Total1

 1,230
 1,217
 1.1%
 0.6%

 1 At December 31, 2023, and 2022, approximately 425,996 and 423,382 customers purchased both electricity and natural gas from PSE, respectively.

 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 a 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 lower 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 to recognize fixed revenue per customer from residential, commercial and industrial customers for the recovery of electric transmission and distribution, natural gas operations and general administrative costs. 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, 2023 and gross utility plant by category and percentages as of December 31, 2023:

 Utility Plant Additions/Retirements 5-Year Total
 2019 - 2023

 Common

 Additions
 $
 1,921,344
 $
 1,397,378
 $
 411,460

 Retirements
 (1,033,169)
 (139,569)
 (479,930)

 Net utility plant
 $
 888,175
 $
 1,257,809
 $
 (68,470)

 Utility Plant in Service

 Common

 Distribution
 $
 4,989,007
 41.6%
 $
 5,101,390
 94.8%
 $
 —
 —%

 Generation
 4,084,846
 34.1
 3,239
 0.1
 —
 —

 Transmission
 1,701,878
 14.2
 —
 —
 —
 —

 General plant & other
 1,207,563
 10.1
 275,697
 5.1
 1,028,489
 100.0

 Total (excluding CWIP)
 $
 11,983,294
 $
 5,380,326
 $
 1,028,489

 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 track specific costs during a previous period and (ii) riders that project cost recovery during a forward-looking 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 that are included in decoupling rates:

 Rate Filings

 Baseline rates
 Yes

 Yes

 Expedited rate filing rider
 Yes

 Yes

 Rates not subject to refund rate adjustment

 Yes

 Yes

 Rates subject to refund rate adjustment

 Yes

 Yes

 General Rate Case Filing
 PSE filed a GRC which includes a two year multiyear rate plan (MYRP) with the Washington Commission on February 15, 2024, requesting an overall increase in electric and natural gas rates of 6.7% and 19.0% respectively in rate year one (expected to approximate calendar year 2025) and 8.5% and 2.1%, respectively in rate year two (expected to approximate calendar year 2026). PSE requested a return on equity of 9.95% for the first rate year beginning in 2025 and 10.5% for the second rate year beginning in 2026. PSE requested an overall rate of return of 7.65% in rate year one and 7.99% in rate year two. The filing requests recovery of forecasted plant additions through 2024 as required by RCW 80.28.425 as well as forecasted plant additions through 2026, the final year of the MYRP. The next phase of the filing will be to establish a procedural calendar for the adjudication of the case. The Company estimates the agreed upon rates from this proceeding will become effective by statute approximately 11 months after filings.
 On December 22, 2022, the Washington Commission issued an order on PSE's 2022 GRC, which was filed on January 31, 2022, that approved a weighted cost of capital of 7.16%, or 6.62% after-tax, a capital structure of 49.0% in common equity in 2023 and 2024, and a return on equity of 9.4%. On January 6, 2023, the Washington Commission approved PSE's natural gas rates in its compliance filing with an overall net revenue change of $70.8 million or 6.4% in 2023 and $19.5 million or 1.7% 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 with an overall net revenue change of $247.0 million or 10.8% in 2023 and $33.1 million or 1.3% in 2024 with an effective date of January 11, 2023. Per the 2022 GRC Final Order in Docket No. UE-220066, rates approved in PSE's power cost only rate case (PCORC) in Docket No. UE-200980 were set to zero as of January 11, 2023, and PSE agreed not to file a PCORC during 2023 and 2024, the period covered by the two-year rate plan agreed to in the GRC settlement.
 Prior rates were subject to the 2019 GRC and included a weighted cost of capital of 7.39% or 6.8% after-tax, a capital structure of 48.5% in common equity, and a return on equity of 9.4%. The annualized overall rate impacts were an electric revenue increase of $48.3 million, or 2.3%, and a natural gas increase of $4.9 million, or 0.6%, effective October 1, 2021. For further information, see Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of the Company's Form 10-K for the period ended December 31, 2022.

 Power Cost Only Rate Case
 A 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. In the 2022 GRC settlement, PSE agreed not to file a PCORC during 2023 and 2024, the two-year rate plan agreed to in the GRC settlement. As noted earlier, per the 2022 GRC Final Order in Docket No. UE-220066, rates set in PSE's last PCORC were set to zero as of January 11, 2023.

 Revenue Decoupling Adjustment Mechanism
 While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses monthly, PSE's decoupling mechanism, Schedule 142, help mitigate the impact of weather on operating revenue and net income. The Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues to recognize fixed revenue per customer from residential, commercial and industrial customers for the recovery of electric transmission and distribution, natural gas operations and general administrative costs 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 fixed, per customer basis regardless of actual consumption levels. PSE's energy supply costs, which are part of the power cost adjustment (PCA) and purchased gas adjustment (PGA) mechanisms, are not included in the decoupling mechanism. The revenue recorded under the decoupling mechanisms is not affected by consumption; however delivery revenue is affected by customer growth, while fixed production costs 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 Rate Filings
 Bill Discount Rate Rider
 The Schedule 129D rider tariff implements surcharges to collect the costs incurred by the Company in providing the rate discounts specified in Schedule 7BDR, including administrative costs approved in Docket No. UE-230692.

 Clean Energy Implementation Tracker
 The Schedule 141CEI tariff implements surcharges to collect the costs incurred and associated with the Company's clean energy implementation plan (CEIP). This schedule will recover the costs associated with the Company's approved CEIP in Docket No. UE-210795 that are not recovered in the other tariff schedules. In the 2022 GRC settlement, PSE agreed to propose the inclusion of these costs as part of base rates or the associated tariff schedules implementing PSE's MYRP in its next GRC. For further details regarding the GRC, see Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.

 Colstrip Adjustment Rider
 The Schedule 141COL implements surcharges and/or credits to collect or pass back the costs incurred or benefits realized associated with Colstrip 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 CETA.

 Conservation Service Rider
 The Schedule 120 tariff 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.

 Energy Charge Credit Recovery Adjustment
 The Schedule 141A 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.

 Federal Incentive Tracker
 The Schedule 95A 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 Schedule 129 low income tracker tariff recovers changes in costs for the low income bill payment assistance program as approved in 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 rates to reflect changes in actual sales and costs. Rates change annually on October 1.

 Power Cost Adjustment Clause
 The power cost adjustment clause for schedule 95 includes a supplemental filing, variable power cost update and/or PCORC updates. The supplemental filing revises the Schedule 95 in accordance with the petition of PSE for approval of its power cost adjustment mechanism annual report. The variable power cost update is a compliance filing to revise Schedule 95 in accordance with the settlement agreement in the last GRC.

 Power Cost Adjustment Mechanism
 PSE currently has a PCA mechanism, under tariff Schedule 95, 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 (temperature, wind and solar variables), hydroelectric and power market conditions and forecasts. 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 up to $17 million

 100%

 100%

 —%

 —%

 Over or under collected between $17 million - $40 million

 Over or under collected beyond $40 million

 Property Tax Tracker
 The purpose of the Schedule 140 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. 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.

 Rates Not Subject to Refund Rate Adjustment
 The purpose of the Schedule 141N tariff is to recover costs approved during a MYRP period that are not subject to refund and that are above the level of base rates set in the MYRP as authorized and approved in Docket No. UE-220066.

 Rates Subject to Refund Rate Adjustment
 The purpose of the Schedule 141R tariff is to charge customers the provisional rates subject to refund approved in a MYRP, for property granted recovery as authorized and approved in Docket No. UE-220066. PSE will file an annual review March 31st of each year, which will be reviewed by the Washington Commission.

 Residential and Farm Energy Exchange Benefit
 The residential exchange program, Schedule 194, passes through the residential exchange program benefits that PSE receives from the Bonneville Power Administration (BPA). Rates change biennially.

 Transportation Electrification Plan Adjustment Rider
 Schedule 141TEP implements surcharges to collect costs associated with the implementation of the Company's transportation electrification plan.

 Voluntary Long Term Renewable Energy Charge and Credit
 The Schedule 139 provides a resource option energy charge for customers taking service in the voluntary renewable energy Green Direct program. This tariff, as authorized in the Washington Commission Docket No. UE-220066, provides a methodology for calculating energy charge credits for energy related power costs components of the energy charge of the customer's electric service schedule. There is also a supplemental energy charge credit to account for the energy related recovery of prior year's power cost adjustment deferral that is being recovered under the supplemental rate in Schedule 95.

 Natural Gas Rate Filings
 Bill Discount Rate Rider
 The Schedule 129D tariff bill discount rate rider collects the costs incurred by the Company in providing the rate discounts specified in Schedule 23BDR, including administrative costs approved in Docket No. UG-230693.

 Climate Commitment Act - Greenhouse Gas Emissions Cap and Invest Adjustment
 The Schedule 111 tariff is to implement a surcharge to recover the costs and to provide benefits through credits to certain customers from the Company's implementation of Washington State greenhouse gas (GHG) emission cap and invest program as prescribed by the CCA and codified in law within RCW 70A.65.

 Conservation Service Rider
 The Schedule 120 tariff 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), Schedule 149, 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 MYRP. Effective January 7, 2023, PSE no longer uses the CRM annual filing to recover these pipeline replacement program investments.

 Distribution Pipeline Provisional Recovery Adjustment
 The purpose of the Schedule 141D tariff is to implement surcharges 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.

 Low Income Program
 The Schedule 129 low income tracker tariff recovers changes in costs for the low income bill payment assistance program as approved in Washington Commission Docket No. 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 natural gas rates to reflect changes in actual sales and costs. Rates change annually on October 1.

 Property Tax Tracker
 The purpose of the Schedule 140 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. 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
 The PGA mechanism, which includes Schedule 101 and Schedule 106 tariffs, 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 costs. Rates typically change annually on November 1, although out-of-cycle rate changes are allowed at other times of the year if needed.

 Rates Not Subject to Refund Rate Adjustment
 The purpose of the Schedule 141N tariff is to recover costs approved during a MYRP period that are not subject to refund and that are above the level of base rates set in the MYRP as authorized and approved in Docket No. UG-220067.

 Rates Subject to Refund Rate Adjustment
 The purpose of the Schedule 141R tariff is to charge customers the provisional rates subject to refund approved in a MYRP, for property granted recovery as authorized and approved in Docket No. UG-220067. PSE will file an annual review March 31st of each year, which will be reviewed by the Washington Commission.

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

 ELECTRIC UTILITY OPERATING STATISTICS

 2023
 2022
 2021

 Generation and purchased power, MWh

 Company-controlled resources
 14,894,381
 11,198,936
 12,949,384

 Contracted resources
 11,806,074
 10,422,069
 8,624,183

 Non-firm energy purchased
 2,910,517
 4,922,194
 4,491,714

 Total generation and purchased power
 29,610,972
 26,543,199
 26,065,281

 Less: losses and Company use
 (1,113,911)
 (1,318,609)
 (1,481,152)

 Total energy, MWh
 28,497,061
 25,224,590
 24,584,129

 Electric energy sales, MWh

 11,387,971
 11,753,057
 11,479,045

 8,637,063
 8,677,178
 8,402,057

 1,070,933
 1,113,909
 1,082,718

 Other customers
 76,495
 76,407
 79,998

 Total energy sales to customers
 21,172,462
 21,620,551
 21,043,818

 Sales to other utilities and marketers
 7,324,599
 3,604,039
 3,540,311

 Total energy sales, MWh
 28,497,061
 25,224,590
 24,584,129

 2,270,474
 2,300,711
 2,246,244

 Electric energy sales and transportation, MWh
 30,767,535
 27,525,301
 26,830,373

 Electric operating revenue by classes

 $
 1,514,149
 $
 1,381,858
 $
 1,318,320

 1,071,385
 981,170
 902,928

 123,548
 116,712
 108,267

 Other customers
 21,199
 18,734
 18,067

 Total operating revenue from customers
 2,730,281
 2,498,474
 2,347,582

 23,573
 22,353
 19,987

 Sales to other utilities and marketers
 502,391
 329,589
 154,533

 Decoupling revenue
 (35,621)
 (37,423)
 (12,452)

 Other decoupling revenue1

 16,635
 (12,067)
 (17,506)

 Miscellaneous operating revenue2

 108,608
 160,531
 179,479

 Total electric operating revenue
 $
 $
 $
 2,671,623

 Number of customers served (average):

 1,077,406
 1,065,508
 1,053,027

 134,375
 133,521
 132,581

 3,187
 3,222
 3,267

 Other
 8,156
 8,047
 7,886

 Total customers
 1,223,233
 1,210,402
 1,196,859

 1.Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve.
 2.Includes revenues from non-core gas, transmission, Schedule 87 tax surcharge, rent from electric property and pole rentals, AMI return deferrals, and other revenues.

 ELECTRIC UTILITY OPERATING STATISTICS (Continued)

 2023
 2022
 2021

 Average kWh used per customer:

 10,570
 11,030
 10,901

 64,276
 64,987
 63,373

 336,032
 345,720
 331,410

 Other
 9,379
 9,495
 10,144

 Average revenue per customer:

 $
 1,405
 $
 1,297
 $
 1,252

 7,973
 7,348
 6,810

 38,766
 36,223
 33,140

 Other
 2,599
 2,328
 2,291

 Average retail revenue per kWh sold:

 $
 0.1330
 $
 0.1176
 $
 0.1148

 0.1240
 0.1131
 0.1075

 0.1154
 0.1048
 0.1000

 Other
 0.2771
 0.2452
 0.2258

 Average retail revenue per kWh sold
 $
 0.1290
 $
 0.1156
 $
 0.1116

 Heating degree days
 4,313
 4,715
 4,471

 Percent of normal - NOAA1 30-year average

 98.1
 %
 105.2
 %
 99.2
 %

 1.National Oceanic and Atmospheric Administration (NOAA).

 Electric Supply
 At December 31, 2023, 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 6,512 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, 2023, and 2022:
 Peak Power Resources
 Energy Production

 2023
 2022
 2023
 2022

 MW
 %
 MW
 %
 MWh
 %
 MWh
 %

 Purchased resources:

 Columbia River PUD contracts1

 13.9%
 13.0%
 3,296,048
 11.1%
 4,351,894
 16.4%

 Other hydroelectric
 1.6
 1.5
 491,898
 1.7
 497,229
 1.9

 Other producers
 1,252
 19.1
 1,352
 20.6
 5,264,589
 17.8
 4,224,027
 15.9

 Wind/solar
 13.8
 13.7
 2,803,223
 9.5
 1,419,839
 5.3

 Biomass
 0.3
 0.3
 135,153
 0.5
 83,814
 0.3

 Short-term wholesale energy purchases
 N/A
 —
 N/A
 —
 2,725,680
 9.2
 4,767,460
 18.0

 Total purchased
 3,173
 48.7%
 3,226
 49.1%
 14,716,591
 49.8%
 15,344,263
 57.8%

 Company-controlled resources:

 Hydroelectric
 4.0%
 4.0%
 699,907
 2.4%
 758,615
 2.9%

 Coal
 5.7
 5.6
 2,673,671
 9.0
 2,726,665
 10.3

 Natural gas/oil
 1,931
 29.7
 1,931
 29.5
 9,954,456
 33.5
 6,028,682
 22.7

 Wind/solar
 11.9
 11.8
 1,566,347
 5.3
 1,684,974
 6.3

 Other2

 —
 —
 —
 —
 —
 —

 Total company-controlled
 3,339
 51.3%
 3,339
 50.9%
 14,894,381
 50.2%
 11,198,936
 42.2%

 Total resources
 6,512
 6,565
 29,610,972
 26,543,199

 1.Net of 47 MW and 40 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, 2023, and 2022, respectively.
 2.It is estimated that the Glacier Battery Storage has delivered approximately 1,648.4 and 1,646.9 MWh as of December 31, 2023, and 2022, respectively.

 Company–Owned Electric Generation Resources
 At December 31, 2023, 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
 1984 & 1986

 Mint Farm
 Natural gas combined cycle
 2007; acquired 2008; upgraded 2017

 Goldendale
 Natural gas combined cycle
 2004, acquired 2007, upgraded 2016

 Frederickson Unit 1 (49.85% interest)
 Natural gas combined cycle
 2002; added duct firing 2005

 Lower Snake River
 Wind
 2012

 Wild Horse
 Wind
 2006 & 2009

 Hopkins Ridge
 Wind
 2005 & 2008

 Fredonia Units 1 & 2
 Dual-fuel combustion turbines
 1984

 Frederickson Units 1 & 2
 Dual-fuel combustion turbines
 1981

 Whitehorn Units 2 & 3
 Dual-fuel combustion turbines
 1981

 Fredonia Units 3 & 4
 Dual-fuel combustion turbines
 2001

 Ferndale
 Natural gas co-generation
 1994; acquired 2012

 Encogen
 Natural gas co-generation
 1993; acquired 1999

 Sumas
 Natural gas co-generation
 1993; acquired 2008

 Upper Baker River
 Hydroelectric
 1959; unit 2 upgraded 1997, upgraded 2021

 Lower Baker River
 Hydroelectric
 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 (WDOE) limits flow to 2,500 cubic feet and therefore output to 47.7MW.

 Columbia River Electric Energy Supply Contracts
 During 2023, approximately 11.1% 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, 2023, PSE's portion of the power output of the PUDs' projects are set forth below:

 Company's Annual Share (Approximate)

 Project
 Contract Expiration Year
 Percent of Output
 MW Capacity

 Chelan County PUD1:

 Rock Island Project
 2031
 30.0
 %

 Rocky Reach Project
 2031
 30.0

 Douglas County PUD2:

 Wells Project
 2028
 32.8

 Grant County PUD3:

 Priest Rapids Development
 2052
 4.8

 Wanapum Development
 2052
 4.8

 Total

 ____________
 1 PSE currently purchases output from Chelan County PUD's Rock Island and Rocky Reach hydroelectric projects under three separate contracts: 1) a contract for 25% of output that was executed in February 2006 and expires October 31, 2031. In 2023, PSE executed a new contract extending this 25% share of output through October 2051; 2) a contract executed in March 2021 for 5% of output that began on January 1, 2022 and continues through December 31, 2026; and 3) a contract executed during 2023 to purchase an additional 5% of output for each, from January 1, 2024 through December 31, 2028.
 2 PSE currently purchases output from Douglas County PUD's Wells hydroelectric project under two separate contracts: 1) a contract executed in March 2017 with a variable share output (average 11.82% in 2024) that began on September 1, 2018 and ends September 30, 2028; and 2) a contract executed in March 2021 for 5.5% of output from October 1, 2021 through September 30, 2024. In 2023, PSE executed a new contract extending this 5.5% share of output through September 30, 2029.
 3 PSE currently purchases output from Grant County PUD's Wanapum and Priest Rapids hydroelectric developments under two separate contracts: 1) a contract that was executed on December 13, 2001 and began November 1, 2005 under which PSE receives 0.64% of output through expires March 31, 2052; and 2) a contract entered in November 2023 for 4.18% of output that begins on January 1, 2024, and continues through December 31, 2024. PSE reserves the right to renew the latter contract on an annual basis.

 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. On November 14, 2022, PSE submitted a notice of termination with PG&E to terminate the agreement on December 31, 2027.
 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 $47.1 million in the year ended December 31, 2023, 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 GHG revenues, transfer revenues and flexible ramping revenues.
 PSE has entered into multiple varying 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.
 PSE expects to meet its forecasted peak load with a mix of owned and contracted power supply assets delivered on contracted transmission with the remainder being supplied with PSE-owned transmission. In 2023, PSE had 5,040 MW and 595 MW of total transmission demand contracted with the BPA and other utilities, respectively. PSE's portfolio of contracted and owned transmission agreements enables the Company to take advantage of favorable power supply conditions across the WECC in lieu of operating owned generation assets to achieve cost savings.

 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 natural gas turbine dispatch depends on favorable market heat rates, which can and do vary significantly for a variety of reasons. Gas supply purchases are made 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 financial hedges to manage the cost of natural gas for power production. 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 inventory value as of December 31, 2023 and 2022:

 2023
 2022

 Natural gas volumes for power in storage at year end, therms (thousands):

 Jackson Prairie
 13,374
 5,450

 Plymouth LNG (in LNG form)
 1,761
 1,223

 Clay Basin

 7,629
 —

 NATURAL GAS UTILITY OPERATING STATISTICS

 2023
 2022
 2021

 Natural gas operating revenue by classes (Dollars in Thousands):

 $
 911,734
 $
 808,376
 $
 722,002

 376,391
 324,743
 270,708

 25,472
 22,965
 19,664

 37,099
 29,582
 23,571

 Total retail natural gas sales
 1,350,696
 1,185,666
 1,035,945

 Transportation services
 34,321
 20,381
 20,104

 Decoupling revenue
 23,116
 (4,008)
 10,254

 Other decoupling revenue1

 (3,405)
 (15,561)
 (11,807)

 Other
 19,640
 23,158
 12,922

 Total natural gas operating revenue
 $
 1,424,368
 $
 $
 1,067,418

 Number of customers served (average):

 815,454
 809,965
 801,186

 56,934
 56,824
 56,477

 2,260
 2,260
 2,277

 Total customers
 875,118
 869,532
 860,438

 Natural gas volumes, therms (thousands):

 587,635
 632,145
 611,028

 285,197
 294,879
 270,022

 22,168
 23,467
 22,794

 49,275
 49,322
 46,115

 Total retail natural gas volumes, therms
 944,275
 999,813
 949,959

 Transportation volumes
 192,043
 219,059
 219,805

 Total volumes
 1,136,318
 1,218,872
 1,169,764

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

 NATURAL GAS UTILITY OPERATING STATISTICS (Continued)

 2023
 2022
 2021

 Working natural gas volumes in storage at year end, therms (thousands):

 Jackson Prairie
 79,045
 79,463
 82,080

 Clay Basin
 81,394
 80,242
 74,540

 Tacoma LNG
 4,746
 —

 Gig Harbor LNG

 Plymouth LNG
 —
 —

 Average therms used per customer:

 5,009
 5,189
 4,781

 9,809
 10,384
 10,011

 182,500
 181,331
 165,881

 960,215
 1,038,194
 999,114

 Average revenue per customer:

 $
 1,118
 $
 $

 6,611
 5,715
 4,793

 11,271
 10,162
 8,636

 137,404
 108,757
 84,788

 171,605
 96,592
 91,382

 Average revenue per therm sold:

 $
 1.552
 $
 1.279
 $
 1.182

 1.320
 1.101
 1.003

 1.149
 0.979
 0.863

 0.753
 0.600
 0.511

 Average retail revenue per therm sold
 $
 1.430
 $
 1.186
 $
 1.091

 $
 0.179
 $
 0.093
 $
 0.091

 Heating degree days
 4,313
 4,715
 4,471

 Percent of normal - NOAA 30-year average
 98.1
 %
 105.2
 %
 99.2
 %

 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, and NWP's Plymouth LNG facility; 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 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 369,600 Dth per day of the firm withdrawal capacity and over 8.4 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.
 The remaining Jackson Prairie storage capacity of 84,200 Dth per day of firm withdrawal capacity and over 1.4 million 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 four years and has rights to extend such agreements. Of this total, PSE designates 11.7 million Dth of storage capacity and 97,400 Dth per day of firm withdrawal capacity to serve natural gas customers. The remaining Clay Basin storage capacity of 10,000 Dth per day of firm withdrawal capacity and 1.2 million Dth of storage capacity is currently designated to PSE's power portfolio.

 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. Of this total, PSE designates 15,000 Dth per day of the firm withdrawal capacity and 60,000 Dth of storage capacity to serve natural gas customers. The remaining Plymouth storage capacity of 55,500 Dth per day of firm withdrawal capacity and 181,700 Dth of storage capacity is currently designated to PSE's power portfolio 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 natural gas customers as well as 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 natural gas customers. 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 a 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
 On February 1, 2022, the Tacoma LNG facility at the Port of Tacoma completed commissioning and commenced commercial operations. The Tacoma LNG facility provides up to approximately 85,000 Dth per day peak-shaving services to PSE's natural gas customers, and provides LNG as fuel to transportation customers via Puget Energy's non-regulated subsidiary Puget LNG. Pursuant to an order by the Washington Commission, PSE is allocated 43.0% of the unassigned common capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility, and Puget LNG is allocated the remaining 57.0% of the unassigned common capital and operating costs. Other common capital and operating costs are allocated using specific or prescribed allocators based on the nature of the cost. The portion of the Tacoma LNG facility allocated to PSE 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. On May 25, 2023, PSE requested a rate increase of $47.6 million, or 3.5% filed under Docket No. UG-230393 with the Washington Commission. A final ruling on this filing is expected by April 25, 2024.

 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 (NGTL), Foothills Pipe Lines (Foothills) and Enbridge Westcoast Energy (Westcoast). GTN, NGTL, 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 520,900 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 397,100 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 218,400 Dth per day of firm transportation capacity on NWP to supply natural gas to its electric generating facilities. In addition, PSE holds over 84,200 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 21 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 six years. PSE has other firm transportation capacity on Westcoast's pipeline, which supplies the electric generating facilities, totaling 88,400 Dth per day, with remaining terms of seven 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 NGTL and Foothills pipelines, each totaling approximately 79,000 Dth per day, with remaining terms of seven years and an option for PSE to renew its rights on the capacity on NGTL and Foothills pipelines. PSE has other firm transportation capacity on NGTL and Foothills pipelines, which supplies the electric generating facilities, each totaling approximately 41,000 Dth per day, with remaining terms of five years. PSE's firm transportation capacity for its natural gas customers on the GTN pipeline, totaling over 77,000 Dth per day, with a remaining term of two years and PSE has a first right-of-refusal to extend such contracts under current FERC rules. PSE has other firm transportation capacity on GTN pipeline, which supplies the electric generating facilities, totaling 40,600 Dth per day, with remaining terms of five years. 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.

 Integrated Resource Plans, Resource Acquisition and Development
 PSE is required by the Washington Commission and state law to file natural gas and electric integrated resource plans (IRP). In 2021, PSE submitted its 2021 natural gas IRP and on March 31, 2023 submitted its 2023 natural gas IRP to the Washington Commission. Specific to electric, Washington Administrative Code 480-100-625 requires PSE to file an electric IRP every four years and a progress report every two years beginning in 2023. In 2021, PSE submitted its electric IRP and on March 31, 2023 PSE submitted its 2023 electric progress report.
 One key consideration included in the IRP is capacity. For the 2023 electric progress report, based on the cumulative capacity need by year, the capacity shortfalls are:

 2024
 2025
 2026
 2027
 2028

 Projected MW shortfall/(surplus)
 1,336
 1,848
 2,096

 Due to growing regional concerns pertaining to capacity within the short-term market, PSE plans to phase out its reliance on firm short-term market purchases by over 200 MW per year starting in 2024 until PSE reaches zero reliance on firm short-term market purchases by 2029. With the expected elimination of Colstrip units 3 and 4 from PSE's energy supply portfolio starting in 2026, which removes approximately 370 MW of coal generation 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 of 174 MW in 2024 increases to 1,336 MW, 1,848 MW and 2,096 MW by 2026, 2027 and 2028, respectively. The expected capacity needs reflect the mix of energy efficiency programs deemed cost effective in the 2023 Progress Report. As part of the Washington CETA, PSE must achieve sales with renewable or non-emitting resources of at least 80% by 2030 and 100% by 2045. Another aspect of the IRP relates to PSE's current transmission portfolio, which includes approximately 1,500 MW of firm transmission rights that deliver energy from the Mid Columbia trading hub to the PSE load center.
 On February 10, 2023, the FERC approved a voluntary regional resource adequacy program that PSE plans to participate in along with other utilities in the western United States and Canada. The program is intended to help the region anticipate its future power supply needs as natural gas-fired and coal power plants retire and are replaced by variable renewable energy resources such as wind and solar.

 Energy Efficiency
 PSE is required under Washington state law to pursue all available electric and natural gas 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 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 the natural gas plants and Colstrip are governed by the federal Clean Air Act (CAA) and its state counterparts, 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 GHGs, and thus are also subject to any current or future GHG or climate change legislation or regulation including the CCA and the 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 electric distribution and transmission lines that can be impacted by laws related to species protection. Several species of fish have been listed as threatened or endangered under the federal Endangered Species Act (ESA), which influences hydroelectric operations, and may affect PSE operations, potentially representing cost exposure and operational constraints. Similarly, there are several avian and terrestrial species that have been listed as threatened or endangered under the ESA or are protected by the federal 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 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 and/or released. The primary cleanup laws to which PSE is subject include the federal Comprehensive Environmental Response, Compensation and Liability Act and, in Washington, the Model Toxics Control Act. PSE is also subject to applicable remediation laws in 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 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 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, including PCB waste from pre-1979 electrical equipment. These actions are regulated by the federal Solid Waste Disposal Act (as amended by the Resource Conservation and Recovery Act) and Toxic Substances Control Act, and state hazardous or dangerous waste regulations 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, and PSE construction projects above a certain threshold are governed by the federal Clean Water Act, which includes the Oil Pollution Act amendments, as well as their state counterparts. 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.

 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 decarbonization and the reduction and mitigation of GHG emissions, including passage of CETA, the CCA, and the Clean Fuels Standard. As a result, the Company announced a goal to be coal free by 2025 consistent with CETA requirements, and net zero carbon emissions for electric and natural gas operations (i.e., known methane leaks from pipeline system) as well as electric supply by 2030. Further, the Company set an aspirational goal to be net zero by 2045 for natural gas sales and to go beyond reducing PSE's own GHG footprint by helping Washington address GHG emissions from the transportation sector by upgrading transmission and distribution infrastructure to accommodate more widespread electric vehicle (EV) adoptions and providing liquefied natural gas for maritime transportation. The Company considers the cost of the decarbonization efforts to date, as well as future efforts, in its IRP process and development of transformational customer programs, and will continue to engage in climate change and GHG emissions policy development.

 Greenhouse Gas Emission Reporting
 PSE is required to submit, on an annual basis, a report of its GHG emissions to the WDOE including emissions from all individual power plants emitting over 10,000 tons per year of GHGs, electric distribution and transmission line losses, certain natural gas distribution facilities and operations, and natural gas sales. Emissions exceeding 25,000 tons per year of GHGs from these sources must also be reported to the U.S. Environmental Protection Agency (EPA).
 The most recent data indicate that PSE's total GHG emissions (direct and indirect) from its electric supply portfolio in 2022 were 9.46 million metric tons of carbon dioxide equivalents. Approximately 28.4% of total electric supply portfolio GHG emissions (approximately 2.68 million metric tons) are associated with PSE's ownership and contractual interests in Colstrip. Compared to 2021, total emissions increased by 3.7%. This trend is due primarily to an increase in output from Colstrip Units 3 and 4 from increased electric demand and decreased availability of PSE renewable generation and natural gas generation.
 PSE's overall emissions strategy continues to add new renewable resources to its generation portfolio and 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.
 PSE's GHG emissions resulting from the complete combustion of natural gas provided to end-users on PSE's distribution systems were 5.78 million metric tons of carbon dioxide equivalents.

 Executive Orders Addressing Environmental Issues
 Since entering office, President Biden issued several executive orders that are likely to affect PSE's environmental obligations. The 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
 On August 16, 2022, the Inflation Reduction Act (IRA) was signed into 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. The Company continues to evaluate the impacts and opportunities associated with the IRA on its operations and financial condition, and anticipates utilization of tax credits under the IRA in future periods. As of December 31, 2023, the IRA had no material impact to the Company's financial condition or results of operations.

 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 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, the 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. In January 2021, the EPA issued a framework for determining when standards are appropriate for GHG emissions from stationary source categories under CAA section 111(b)(1)(A).
 In August 2015, the EPA issued a final rule under Section 111(d) of the CAA, referred to as the Clean Power Plan (CPP), to regulate GHG emissions from existing power plants. In June 2019, the EPA repealed the CPP rule and replaced it with the Affordable Clean Energy (ACE) rule, which established emission guidelines for states to develop plans to address GHG emissions from existing coal-fired plants. In January 2021, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the ACE rule and remanded it to the Agency for further consideration consistent with its opinion, after finding that the EPA had misinterpreted the CAA when adopting the ACE rule. The Supreme Court granted review of the D.C. Circuit's decision and in June 2022, the Supreme Court found that the EPA lacked clear congressional authority to require generation shifting under Section 111(d). In response to this decision, the D.C. Circuit recalled its partial mandate vacating the ACE Rule and granted a motion by the EPA to hold pending challenges to the ACE Rule in abeyance while the EPA developed a replacement rule.
 On May 23, 2023, the EPA published a proposed rule to repeal the ACE Rule, revise the NSPS under Section 111(b) for GHG emissions from new fossil fuel-fired stationary combustion turbine electric generating units (EGUs) and from fossil-fuel fired steam generating units that undertake a large modification, and establish emissions guidelines under Section 111(d) for GHG emissions from existing fossil fuel-fired steam generating EGUs and from the largest, most frequently operating

 stationary combustion turbines. On November 20, 2023, the EPA issued a Supplemental Notice of Proposed Rulemaking regarding mechanisms to help ensure that the proposed Section 111(d) regulations can be implemented without adversely affecting the reliability of the electrical grid. The EPA has indicated that it anticipates issuing a final rule in April 2024.

 Washington Climate Commitment Act
 In 2021, the Washington Legislature adopted the CCA, which establishes a GHG emissions cap-and-invest program that requires covered entities, including electric and gas utilities, to purchase allowances to cover their GHG emissions with a cap on available allowances beginning on January 1, 2023 that declines annually through 2050. The Washington Department of Ecology (WDOE) published final regulations on September 29, 2022, which became effective on October 30, 2022. Allowances can be obtained through quarterly auctions, or bought and sold on a secondary market.
 As an electric 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 load, and all electricity generated by Washington 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, which is discussed below, PSE receives emission allowances from WDOE at no cost through 2050 for direct emissions associated with electricity used to serve Washington State load to eliminate the cost burden of the program on electric ratepayers.
 As a gas utility, PSE is required to obtain emission allowances for GHG emissions associated with (i) natural gas supplied to customers and (ii) any natural gas system associated facilities with emissions that exceed 25,000 metric tons of carbon dioxide equivalent per year. PSE receives some no-cost emission allowances from WDOE to mitigate impacts to natural gas ratepayers. WDOE's allocation of no-cost allowances to PSE is based on a percentage of PSE baseline natural gas system related emissions (determined from 2015-2019 natural gas system related emissions) and declines annually in proportion with the Washington State carbon goals reaching zero no-cost allowances in 2050.
 Offset credit use is limited and is not additive to allowances; the WDOE subtracts any offsets used from the total allowance budget. In the first compliance period, 2023-2026, participating entities can cover up to 5% of their emissions with offset credits, and can cover an additional 3% with credits from projects on federally recognized Tribal lands. In the second compliance period, 2027-2030, the general limit drops to 4%, with an additional 2% from projects on Tribal lands.
 In 2023, the WDOE announced an intent to pursue an agreement with California to link with its cap and trade program which is administered by the California Air Resources Board.

 Washington Clean Energy Transformation Act
 In May 2019, Washington passed the CETA, which supports Washington's clean energy economy and transitioning to a clean, affordable, and reliable energy future. The CETA requires all electric utilities to eliminate coal-fired generation from their electric supply to customers 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). 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. The Company intends to seek recovery of any costs associated with CETA through the regulatory process. On December 17, 2021, PSE filed its Final CEIP, which proposed a plan for the implementation of CETA for 2022-2025 and associated project costs. On June 6, 2023, the Washington Commission approved PSE's CEIP, subject to conditions. On November 2, 2023, PSE filed a Biennial CEIP Update with the Commission.

 Regional Haze Rule
 In January 2017, the EPA revised 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. As such, states were required to prepare State Implementation Plans (SIPs) for the second planning period by July 31, 2021. Washington submitted its SIP revision in January 2022. Montana submitted its SIP revision in August 2022. The EPA has yet to take final action on either SIP and is subject to pending litigation in the U.S. District Court for the District of Columbia seeking to require the EPA to take action on these SIPs, as well as SIPs for several other states.

 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, in 2012 the operator of Colstrip and the state of Montana entered into an Administrative Order on 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 and remanded some of its provisions back to the EPA. As a result of that decision and certain other developments, the 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. Most recently, in May 2023, the EPA published a proposed rule to expand the scope of the units subject to the federal CCR regulations to include inactive surface impoundments at inactive generating facilities, as well as "CCR management units" at facilities otherwise subject to federal CCR regulation. 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 the EPA to develop a federal permitting program. Currently, Montana has not applied for a state permit program, and the EPA has not yet finalized a federal permitting program.

 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.

 Employee Overview
 At December 31, 2023, PSE had approximately 3,340 full-time equivalent employees. Approximately 1,050 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 Company has two contracts with the IBEW; one ratified effective April 1, 2020, and will expire March 31, 2026 and a second ratified effective May 1, 2023 and will expire April 30, 2027.
 Puget Energy does not have any employees. PSE's employees provide services to Puget Energy and PSE charges for their 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, 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, 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.

 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 retirement programs, including a 401(k) plan. For 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, two retirement contribution sources from PSE are provided:
 •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 on company retirement benefits 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.

 Information About Our Executive Officers
 The executive officers of Puget Energy as of March 5, 2024, 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

 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

 D. A. Doyle

 Chief Financial Officer since September 26, 2023; Senior Vice President from June 2021 to September 2021; Senior Vice President and Chief Financial Officer from November 2011 to June 2021; Principal of AntlerCrest Advisory, LLC since September 2021

 L. Luebbe

 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 Director Environmental Services from 2005 to March 2022

 S. W. Smith

 Controller and Principal Accounting Officer since December 19, 2022; Manager, Revenue Requirements from September 2019 to December 2022; Manager, Energy and Derivatives Accounting from July 2018 to August 2019

 The executive officers of PSE as of March 5, 2024, 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

 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

 D. A. Doyle

 Chief Financial Officer since September 25, 2023; Senior Vice President from June 2021 to September 2021; Senior Vice President and Chief Financial Officer from November 2011 to June 2021; Principal of AntlerCrest Advisory, LLC since September 2021

 L. Luebbe

 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 Director Environmental Services from 2005 to March 2022

 A. August

 Senior Vice President, Chief Customer and Transformation Officer since July 27, 2023; Vice President, Officer of Utility Partnerships and Innovation at Pacific Gas and Electric Company from 2022 to 2023; Vice President, Officer of Business Development and Customer Engagement at Pacific Gas and Electric Company from 2020 to 2022; Senior Director, Business Energy Solutions at Pacific Gas and Electric Company from 2016 to 2020

 M. Steuerwalt

 Senior Vice President, External Affairs since September 29, 2023; Teaching Associate Professor at Evans School of Public Policy, University of Washington since 2017; Partner at Insight Strategic Partners from April 2017 to September 2023

 R. Roberts

 Senior Vice President, Energy Resources since January 8, 2024; Vice President, Energy Supply from November 2020 to January 2024; Director Generation and Natural Gas Storage from February 2018 to November 2020

 M. Vargo

 Senior Vice President, Energy Operations since January 8, 2024; Vice President Corporate Shared Services from July 24, 2023 to January 7, 2024; Chief Operating Officer at Seattle City Light from June 2021 to July 2023, Deputy Chief Operating Officer at Seattle Light from January 2020 to May 2021; Network, Substations and Service Operations Director at Seattle City Light from August 2016 to December 2019

 S. Upton

 Chief Information Officer since March 2023; Partner at Fortium Partners since January 2023, Chief Information Officer at Solomon Partners from January 2021 to January 2023; Global Chief Operating Officer at Credit Suisse from December 1997 – April 2020

 S. W. Smith

 Controller and Principal Accounting Officer since December 19, 2022; Manager, Revenue Requirements from September 2019 to December 2022; Manager, Energy and Derivatives Accounting from July 2018 to August 2019

 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 and environmental advocacy groups and various consumers of energy, who have differing regulatory perspectives and concerns but who collectively share a common objective of limiting rate increases proposed by the Company and keeping the Company's rates as low as possible over time. Policies and regulatory actions by these regulators and intervening parties 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. Traditionally, the Washington Commission determined the rates PSE may charge its electric and natural gas retail customers based, in part, on historic costs during a particular test year, adjusted for certain normalizing adjustments. In 2021, Washington enacted into state law Engrossed Substitute Senate Bill (ESSB) 5295, which among other things amended RCW 80.28 to require electric and natural gas utilities to file forward looking MYRPs as part of their general rate case filings. PSE filed its first rate case under this updated statute in 2022 in Dockets UE-220066 and UG-220067 and the Washington Commission subsequently approved rates in this case predicated on a projection of costs expected to occur during the rate years of the MYRP. The changes to RCW 80.28 did not materially change the recovery of power and natural gas costs. As has been the case for many years, power costs 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. Similarly, 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 state law that requires PSE to share its excess earnings above the authorized rate of return with customers. In addition to requiring electric and natural gas utilities to file MYRPs, ESSB 5295 also requires PSE to defer revenues that are in excess of 50 basis points higher than the authorized rate of return. The deferred amounts may be refunded to customers or applied in some other way as determined by the Washington Commission. The earnings test is performed 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. In contrast to the PGA mechanism which is a direct pass through of costs, the PCA mechanism provides 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 and snowpack;
 • 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, vendor, 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 or of third-party vendors on whom we may rely to host, maintain, modify, and update our 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 such as wildfires and catastrophic events, including terrorist acts, may adversely affect PSE's business and expose the Company to liability. Events such as wildfires, earthquakes, floods, tornadoes and other extreme weather

 events, explosions, 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, cause reputational harm 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.
 Wildfires and other natural disasters affecting PSE's infrastructure may expose PSE to liability for personal injury, loss of life, and property damage. The risk of catastrophic and severe wildfires has increased in the western U.S. giving rise to the potential for large damage claims against utilities for fire-related losses. Climate change may worsen hot and dry summer conditions, which increase the likelihood and magnitude of damages that may be caused by fires burning into or allegedly originating from PSE's equipment. Wildfires alleged to have been caused by PSE's transmission, distribution, or generation infrastructure, or that allegedly result from PSE's or its contractors' operating or maintenance practices, could expose PSE to claims for fire suppression and clean-up costs, evacuation costs, fines and penalties, and liability for economic damages, personal injury, loss of life, property damage, and environmental pollution, whether based on claims of negligence, trespass, or otherwise.
 PSE maintains insurance coverage for natural disasters and catastrophic events like wildfires, sabotage and terrorism, but insurance coverage is subject to the terms and limitations of the available policies and may not be sufficient in scope or amount to cover PSE's ultimate liability. The availability of insurance coverage has been and will likely continue to be limited, and has been and will likely continue to result in higher deductibles, higher premiums, and more restrictive policy terms to the extent commercially sourced insurance remains available.
 An increase in wildfires and other extreme events, even in areas beyond PSE's service territory, has and will likely continue to negatively impact insurance markets and availability and cost of our insurance coverage. Coverage limits within insurance policies could result in material self-insured costs if there are events that are not covered by PSE's insurance policies. PSE may be unable to fully recover costs in excess of insurance through customer rates or regulatory mechanisms and, even if such recovery is possible, it could take several years to collect. If the amount of insurance is insufficient or otherwise unavailable, and if PSE is unable to fully recover in rates the costs of uninsured losses, PSE's financial condition, results of operations, or cash flows could be materially affected.

 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. There is potential that PSE may not be able to recover all of its costs for such expenditures through electric and natural gas rates in a timely manner. Other risks related to PSE's compliance with such regulations include, but are not limited to: changes to ratemaking by state and federal regulators, including recovery methodologies over PSE's energy costs, market uncertainty, customer rate impacts, customer satisfaction and loyalty, cash liquidity and credit volatility.
 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 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.

 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. An abundance of low, stably priced natural gas, contrasted by 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, creates conflicting strategic challenges related to the Company's 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 generally greater in the winter months associated with heating, however summer weather events can result in material impacts. 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.
 Climate change could also have significant physical effects in PSE's operational territory, such as increased frequency and severity of storms, wind, droughts, heat waves, wildfires, floods, cold weather events, and other extreme weather events. Such extreme weather events could impact transmission, distribution, and generation facilities, resulting in service interruptions and extended or mass outages, which may adversely impact operations and financial results. Costs incurred due to such events may not be recovered through rates if not approved for recovery by the Washington Commission. Additionally, extreme weather events impact customer energy needs and can significantly impact demand, thus increasing wholesale prices for power that PSE purchases to serve customers. PSE has regulatory mechanisms in place to mitigate the effects of price volatility, however, such mechanisms require regulatory approval and may not function as intended.

 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 maintains emergency planning and training programs to allow PSE to quickly respond to extreme events that interrupt service to customers. To respond to these extreme events, PSE relies upon the availability of outside contractors (including industry-wide mutual assistance from third party public utilities) which may impact service restoration timing and the quality of service provided to PSE's customers. In addition, a slow or ineffective response to extreme events and the magnitude or the event itself may have an adverse effect on earnings as customers may be without electricity and natural gas for an extended periods 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 to perform necessary utility functions to provide service to customers. 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 construction and maintenance, 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 generally compensated in connection with such transactions, the level of compensation is subject to regulatory approval and may not fully compensate PSE for the loss of customers and related revenues, which could negatively affect PSE's future financial condition.

 Changes in customer growth and customer usage may have an adverse impact on PSE's financial condition. Changes in the number of customers and customer usage are driven by many variables including, but not limited to: population changes in PSE's service territory, expansion or loss of service area, inflationary pressures and economic conditions, changes to customer needs and expectations, regulatory environment and state and federal legislation, customer-generated power, demand response, and transportation electrification. Such factors may adversely impact the Company by increasing competition, decreasing customer satisfaction and loyalty, and customers seeking alternative sources of energy. In contrast, some factors, such as transportation electrification and electric heating sources, among others, may result in unexpected demand for energy, which could lead to PSE being required to purchase power at higher-costs to meet peak demands. Further, changes in such customer use could necessitate the need for PSE to accelerate investment in additional generation, distribution, transmission, and storage resources beyond current resource planning. Such changes could result in significant expenditures by PSE or reduce revenue and thus adversely affect PSE financially. There is potential that PSE may not be able to recover all of its costs for such expenditures through electric and natural gas rates in a timely manner.

 PSE may face risks related to health crises such as epidemics, pandemics and other outbreaks that could have a material adverse impact on our business and results of operations. We face various risks related to health crises such as epidemics, pandemics and other outbreaks, which may materially impact our results of operations, financial condition and ongoing operations. As most recently evidenced by the COVID-19 pandemic, health crises can adversely affect economic activity within Washington and the United States of America, and more specifically, our business and results of operations, by, among other things, reducing customer demand for electricity and natural gas, reducing the availability and productivity of our employees, contractors and vendors, increasing our costs, delaying payments from our customers and increasing uncollectible accounts, delaying and disrupting supply chains, disrupting the financial markets which negatively impacted on our ability to access, and cost of, capital, deteriorating our financial metrics and ability to meet the covenants of our credit facilities, and disrupting our ability to meet customer requirements.

 PSE could be adversely affected by disruptions in the global economy and rising geopolitical tensions, such as those caused by the ongoing military conflicts between Israel and Hamas and 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 and military conflicts, such as the conflict between Israel and Hamas, 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 operations and supply chain, and ultimately, PSE's ability to serve customer demand and needs on timely basis, which may negatively impact PSE's financial performance.

 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, adversely affect the ability to access one or more financial markets, their ability to pay dividends and service outstanding debt obligations.

 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 May 14, 2027. There was $261.5 million outstanding under the facility as of December 31, 2023. 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 May 14, 2027. As of December 31, 2023, 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, 2023, had approximately $5.2 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 Secured Overnight Financing Rate (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.

 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 2024 and beyond as well as the timing of the recovery of such contributions in GRCs could adversely 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 48.1% at December 31, 2023, and the EBITDA to interest expense ratio was 5.2 to 1.0 for the twelve-months ended December 31, 2023.
 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. Disruptions 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

 Changes in legislation, regulation, and government policy may have a material adverse effect on the Company's business. The Company is subject to numerous laws and regulations that materially impact operations and financial condition. Specific legislation and regulations, including proposals, that impact the Company include, but are not limited to, tax reform, utility regulation, carbon reduction, climate change and environmental regulation, accounting regulations, and infrastructure regulation. Changes in current laws and regulations, proposed legislation and the interpretation of such laws and regulations could have a material adverse impact on the Company's financial condition and results of operations. Commonly, laws and related regulations are inherently complex, and thus, the Company must make judgments and interpretations about the application of the law and corresponding impacts to our operations and financial condition. Disputes over interpretations of laws may be settled with the relevant authority overseeing certain laws and regulation, upon appeal or through litigation.
 A citizen sponsored initiative to repeal the CCA is currently pending before the Washington legislature. The legislature could enact it and repeal the CCA, take no action, or propose a competing measure. If the legislature takes no action during the 2024 legislative session ending March 7, 2024, the initiative will be placed on the ballot for the next statewide general election in November 2024 for voter consideration. If the legislature enacts a competing measure, both alternatives would go before the voters in November 2024. At this time PSE cannot predict the outcome of such a vote.

 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 results of operations and financial condition could be adversely affected by 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. Continued inflationary pressures, an economic downturn, or a recession could also negatively impact customer use or ability to pay for services rendered and reduce revenues and cash flows, thus adversely affecting results of operations. While regulatory mechanisms exist to partially 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 1C. CYBERSECURITY
 PSE maintains a comprehensive business continuity plan that includes the identification, assessment and management of risks arising from various avenues, including cyber. Business continuity includes action plans to respond to and remedy information technology (IT) outages, attacks, and other cyber threats, which are maintained between two specific plans, the IT disaster recovery plan and the cybersecurity incident response plan (CSIRP). The CSIRP specifies guidance for various cyber related risks to ensure business continuity and timely reporting of incidents to various governing bodies, including the SEC. The CSIRP is a perpetually updated plan that is managed by the Chief Information Security Officer (CISO) and Chief Information Officer (CIO). PSE's CIO has served in various roles in IT and IT security for over 15 years, including serving as Chief Operating Officer or Chief Information Officer primarily in the financial services industry. Further, the CIO holds an undergraduate degree in computer science. PSE's CISO has over 15 years of experience managing IT security across different industries and companies. Additionally, the CISO holds an undergraduate degree and has been a Certified Information Systems Security Professional for over 15 years.
 As part of the CSIRP, PSE maintains a standalone team of IT security and risk management professionals in the Cyber Defense Center (CDC). The CDC is responsible for implementing the CSIRP, including the identification and ongoing monitoring and response to all cyber events and risks, including risks associated with the Company's use of third-party service providers, which impact the Company. To identify, defend, detect and respond to cyber events, PSE performs various on-going activities, such as, proactive privacy and cybersecurity reviews of systems and applications, monitoring threat intelligence information feeds, penetration testing to test security controls, conducting employee trainings, and monitoring emerging laws and regulations related to data protection and information security. Additionally, the Company conducts tabletop exercises to simulate our response to cybersecurity incidents. Depending on the nature of the incident, PSE may engage consultants, assessors, or other third-parties to assist in the assessment, testing, remediation, and/or management of cyber incidents.
 Once cyber incidents are identified in the CDC, a risk assessment is performed as part of the CSIRP by the CDC. The risk assessment includes quantitative and qualitative considerations determined by a committee of individuals, including, among others, the Controller, CISO and Chief Ethics and Compliance Officer, that report to the Chief Financial Officer, CIO, and Senior Vice President General Counsel and Chief Sustainability Officer. Any cyber incidents that exceed set thresholds in the CSIRP are then escalated to the aforementioned committee for a materiality assessment and disclosure considerations.
 The Company's Audit Committee oversees management's process for identifying and mitigating cybersecurity risks. Periodically, the CISO presents cyber incidents and risks to the audit committee as part of the board of directors' oversight of risks from cybersecurity threats. The Audit Committee's oversight includes understanding existing and new cybersecurity risks and status on management's response and mitigation plans.
 As of December 31, 2023, the Company was not aware of (i) any cybersecurity incidents, or (ii) any specific cybersecurity threats, that, in either case, materially affected or are reasonably likely to materially affect the business, strategy, results of operations, or financial condition of the Company. However, we can provide no assurance that there will not be cybersecurity threats or incidents in the future or that they will not materially affect PSE, including our business, strategy, results of operations, or financial condition. For more information regarding risk from cybersecurity threats, see Item 1A. "Risk Factors" included in this report.

 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
 Contingencies arising out of the Company's normal course of business existed as of December 31, 2023. Litigation is subject to numerous uncertainties and the Company is unable to predict the ultimate outcome of these matters. For further details, see Note 16, "Commitments and Contingencies" to the consolidated financial statements included in Item 8 of this report.
 SEC regulations require the Company to disclose certain information about proceedings arising under federal, state or local environmental provisions if the Company reasonably believes that such proceedings may result in monetary sanctions above a stated threshold. Pursuant to the SEC regulations and given the size of the Company's operations, PSE elected a threshold of $1 million for purposes of determining whether disclosure of any such proceedings is required. As of the date of this filing, we are not aware of any matters that exceed this threshold and meet the definition for disclosure.
 For information on litigation or legislative rulemaking proceedings, see Note 15, "Litigation" to the consolidated financial statements included in Item 8 of this report. For information on environmental remediation, see Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.

 ITEM 4. MINE SAFETY DISCLOSURES
 Not applicable.

 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 2023, 2022, and 2021, 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 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 2023 compared to 2022. For discussion related to the results of operations and changes in financial condition for 2022 compared to 2021 refer to Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations in our fiscal year 2022 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 SEC that attempt to advise interested parties of the risks and factors that may affect Puget Energy's and PSE's business, prospects and results of operations.

 Overview

 Puget Energy is an energy services holding company and substantially all of its operations are conducted through its 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 and operating the non-regulated activity of the Tacoma liquefied natural gas (LNG) 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 British Columbia Investment Management Corporation (BCIMC), the Alberta Investment Management Corporation (AIMCo), Ontario Municipal Employee Retirement System (OMERS), PGGM Vermogensbeheer B.V., Macquarie Washington Clean Energy Investment, L.P., and Ontario Teachers' Pension Plan Board. Puget Energy and PSE are collectively referred to herein as "the Company."
 PSE generates revenue and cash flow primarily from the sale of electric and natural gas services to residential and commercial customers within a service territory covering approximately 6,000 square miles, principally in the Puget Sound region of the state of Washington. PSE continually balances its load requirements, generation resources, purchase power agreements, and market purchases to meet customer demand. The Company's external financing requirements principally reflect the cash needs of its construction program, its schedule of maturing debt and certain operational needs. PSE requires access to bank and capital markets to meet its financing needs.
 Factors affecting PSE's performance are set forth in this "Overview" section, as well as in other sections of the Management's Discussion and Analysis.

 Non-GAAP Financial Measures
 The following discussion includes financial information prepared in accordance with U.S. Generally Accepted Accounting Principles (GAAP), as well as return on equity (ROE) excluding unrealized gains and losses on derivative instruments (net income plus unrealized losses and/or minus unrealized gains on derivative instruments divided by average common equity) that is considered a "non-GAAP financial measure". Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that includes adjustments that result in a 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 2023 and 2022:
 2023
 2022

 Earnings
 Average Common Equity
 Return on Equity
 Earnings
 Average Common Equity
 Return on Equity

 Return on equity
 $131,059
 $4,960,936
 2.6%
 $490,952
 $4,613,257
 10.6%

 Less/Plus: Unrealized gains and losses on derivative instruments, after-tax
 224,751
 —
 *
 (206,330)
 —
 *

 Plus: Equity adjustments1

 —
 70,908
 *
 —
 (108,984)
 *

 Plus: Impact of average of monthly average (AMA)
 —
 (77,648)
 *
 —
 127,482
 *

 Return on AMA equity
 $355,810
 $4,954,196
 7.2%
 $284,622
 $4,631,755
 6.1%

 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 2022 and 2019 GRC is 9.4% for natural gas and electric effective January 1, 2023 for the 2022 GRC and for natural gas and electric effective October 1, 2020 and October 15, 2020, respectively for the 2019 GRC.
 *Not meaningful and/or applicable.

 The Company's 2023 return on AMA equity was 7.2%, which is lower than the authorized regulated ROE primarily due to the following:
 • Regulated equity (rate base multiplied by equity percent) was $683.7 million lower than AMA equity for the year ended December 31, 2023. 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.
 • Plant placed in service which receives deferred accounting treatment, but for which the equity return is not yet able to be recognized, consisting of the AMI and Tacoma LNG investments, which resulted in $22.9 million of deferred return that has not yet been recognized impacting ROE by negative 0.5%.
 • Plant placed in service earlier than planned resulted in higher depreciation expense and a lower rate of return in the amount of $17.8 million on an after-tax basis for the year ended December 31, 2023, for an impact on ROE of negative 0.4%.
 • Power cost recovery was $20.7 million higher than the amount allowed in rates on an after-tax basis for the year ended December 31, 2023, for an impact on ROE of positive 0.4%.

 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, significant in service projects such as, AMI and Tacoma LNG, and growth in rate base since the last 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%.

 Factors and Trends Affecting PSE's Performance
 PSE's ongoing regulatory requirements and operational needs necessitated the investment of substantial capital in 2023 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 subject to the Company's power cost adjustment mechanism 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;
 • Deferral of excess revenues if earnings exceed PSE's authorized rate of return (ROR) by more than 0.5%;
 • 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, such as the Climate Commitment Act (CCA);
 • 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 or refund previously collected revenues;
 • Changes in customer growth and customer usage;
 • 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;
 • Cybersecurity incidents and/or 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 and its impact on the supply chain and prices of goods and services;
 • Natural disasters such as wildfires, earthquakes, hurricanes, floods, landslides and windstorms, the rise in frequency and magnitude of extreme temperature events, and possible accidents, explosions, fires or mechanical breakdowns affecting or caused by PSE's facilities or infrastructure may increase the Company's costs, impact PSE's generation, transmission and distribution systems, subject the Company to increased liability, and/or adversely affect its operations;
 • Risks due to health crises, such as epidemics and 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; and
 • Legislative, regulatory, code, and/or ordinance changes that impact operations, electric and natural gas availability, sales, transmission, delivery, and/or restrictions.

 Regulation of PSE Rates and Recovery of PSE Costs
 PSE's regulatory requirements, environmental compliance and operational needs require the investment of substantial capital in 2023 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 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. Prior to 2023, the Washington Commission required that rates be determined based on historic test year costs plus weather normalized assumptions. Incremental customer growth and sales typically did not provide sufficient revenue to cover general cost increases due to regulatory lag and attrition. Therefore, the Company would seek rate relief through rate cases with the Washington Commission, which would determine whether the Company's expenses and capital investments were reasonable and prudent for the provision of cost-effective, reliable and safe electric and natural gas service. If the Washington Commission determined that a capital investment was not reasonable or prudent, the costs (including return on any resulting rate base) related to such capital investment would 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 the natural gas business's financial performance due to the natural gas business being mostly decoupled.
 In May 2021, the Washington Governor signed legislation passed by the state legislature that requires investor-owned utilities to file a forward looking multi-year rate plan (MYRP) 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. Under the law, while utilities are required to file a MYRP (at least two years in length) the Washington Commission is not required to approve them. To the extent the Washington Commission approves a MYRP, utilities are bound to the first and second year of the MYRP but may 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 that level must be deferred for refunds to customers or another determination by the Washington Commission in a subsequent adjudicative proceeding. The Washington Commission must also set performance measurements to assess a natural gas or electric company operating under a MYRP.

 General Rate Case Filing
 PSE filed a GRC which includes a two year MYRP with the Washington Commission on February 15, 2024, requesting an overall increase in electric and natural gas rates of 6.7% and 19.0% respectively in rate year one (expected to approximate calendar year 2025) and 8.5% and 2.1%, respectively in rate year two (expected to approximate calendar year 2026). PSE requested a return on equity of 9.95% for the first rate year beginning in 2025 and 10.5% for the second rate year beginning in 2026. PSE requested an overall rate of return of 7.65% in 2025 and 7.99% in 2026. The filing requests recovery of forecasted plant additions through 2024 as required by RCW 80.28.425 as well as forecasted plant additions through 2026, the final year of the MYRP. The next phase of the filing will be to establish a procedural calendar for the adjudication of the case. The Company estimates the agreed upon rates from this proceeding will become effective by statute approximately 11 months after filings.
 On December 22, 2022, the Washington Commission issued an order on PSE's 2022 GRC that approved a weighted cost of capital of 7.16%, or 6.62% after-tax, a capital structure of 49.0% in common equity and a return on equity of 9.4%. On January 6, 2023, the Washington Commission approved PSE's natural gas rates with an overall net revenue change of $70.8 million or 6.4% in 2023 and $19.5 million or 1.7% in 2024, with an effective date of January 7, 2023. On January 10, 2023, the Washington Commission approved PSE's electric rates with an overall net revenue change of $247.0 million or 10.8% in 2023 and $33.1 million or 1.3% in 2024 with an effective date of January 11, 2023. For additional information, see Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.

 Climate Commitment Act Deferral
 On December 29, 2022, PSE filed accounting petitions with the Washington Commission requesting authorization to defer costs and revenues associated with the Company's compliance with the CCA codified in law within Revised Code of Washington (RCW) 70A.65. On February 28, 2023, in Order 01 under Docket No. UE-220974 and UG-220975, the Washington Commission granted PSE approval to defer the cost of emission allowances to comply with the CCA and the proceeds from no-cost allowances consigned to auction beginning January 1, 2023. As such, PSE concluded it was appropriate to defer and seek recovery of CCA costs not currently included in rates. As of December 31, 2023, PSE deferred $184.4

 million of CCA compliance costs for natural gas and electric liabilities and recorded $83.0 million related to the proceeds from the sale of consigned GHG emission allowances.
 On August 3, 2023, the Washington Commission approved PSE's request for CCA rates in Docket No. UG-230470, subject to refund, effective October 1, 2023, to recover the estimated ongoing allowance costs and proportionate pass back of credits to customers from estimated auction proceeds during the period of August 2023 through December 2023. Overall, the proposal included a new revenue requirement of $104.7 million related to the Washington state carbon reduction charge, mitigated by a new revenue requirement decrease of $87.9 million related to the Washington state carbon reduction credit.
 On October 26, 2023, the Washington Commission approved PSE's request for CCA rates in Docket No. UG-230756, subject to refund, effective November 1, 2023, to recover the estimated ongoing allowance costs and proportionate pass back of credits to customers from estimated auction proceeds during the period of January 2023 through September 2023. The recovery of ongoing allowance costs and pass back of credits is consistent with the approved accounting petitions in Dockets No. UG-220975 and UG-230471. As part of this filing PSE requested an annual revenue increase of $27.2 million.
 For further details, see Note 4, "Regulation and Rates," to the consolidated financial statements included in Item 8 of this report.

 Revenue Decoupling Adjustment Mechanism
 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. The Washington Commission approved removing 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. The Washington Commission approved removing 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, 2023, 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 is required 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 electric and natural gas deferred revenue would be collected within 24 months of the annual period; therefore, no reserve adjustment was booked to 2023 electric or natural gas decoupling revenue.
 The Washington Commission approved the following PSE requests to change rates for prior deferrals under its electric and natural gas decoupling mechanisms:

 Effective Date

 Average
 Percentage
 in Rates

 in Revenue
 (Dollars in Millions)1

 Electric:

 (1.5)%
 $(37.6)

 May 1, 20222

 (1.0)
 (23.5)

 May 1, 20213

 1.0
 21.4

 Natural Gas:

 (1.3)%
 $(16.4)

 (0.7)
 (7.4)

 May 1, 2021
 1.5
 15.0

 ___________________

 1.For electric and natural gas rates effective May 1, 2023, May 1, 2022, and May 1, 2021, 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.

 Electric Rates
 The following table sets forth rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE's revenue based on the effective dates. For further information on descriptions of the rate adjustments, see Business, "Regulation and Rates" included in Item 1 of this report:

 Schedule

 Docket

 Effective Date

 Average
Percentage
in Rates
in Revenue
(Dollars in Millions)

 Bill discount rate rider

 129D

 230692
 October 1, 2023
 0.5%
 $11.9

 Clean energy implementation

 141CEI

 230591
 September 1, 2023
 0.9
 31.4

 Colstrip adjustment rider

 141COL

 230808
 0.03
 0.9

 2.2
 50.3

 Conservation service rider

 230139
 (0.2)
 (6.3)

 220137
 1.0
 21.6

 Energy charge credit recovery

 141A

 230825
 (0.1)
 (2.0)

 1.5
 35.3

 Federal incentive tracker

 95A

 220794
 January 1, 20231

 1.3
 1.0

 210821
 January 1, 2022
 0.1
 (28.2)

 200897
 January 1, 2021
 0.3
 (29.5)

 Low income program

 230694
 October 1, 2023
 (1.0)
 (25.9)

 220656
 October 1, 2022
 1.1
 25.8

 210674
 October 1, 2021
 0.3
 5.8

 Power adjustment clause - Schedule 95

 Supplemental

 230318
 December 1, 2023
 1.0
 27.4

 200893
 December 1, 20202

 2.1
 43.9

 2024 variable power cost update

 230805
 6.1
 160.9

 2020 PCORC3

 200980
 October 1, 2021
 3.3
 70.9

 Property tax tracker

 230219
 (0.2)
 (4.4)

 220234
 (0.3)
 (5.8)

 Rates not subject to refund

 141N

 230320
 (3.1)
 (76.2)

 7.9
 182.5

 Rates subject to refund

 141R

 230320
 4.2
 105.6

 4.0
 91.7

 Residential and exchange benefit3

 230792
 November 1, 2023
 (0.4)
 (9.9)

 210575
 November 1, 2021
 0.4
 7.9

 Transportation electrification plan

 141TEP

 240067
 March 1, 2024
 0.04
 1.2

 230040
 March 1, 2023
 0.2
 6.0

 Voluntary long term renewable energy charge and credit

 —
 (0.02)

 (0.2)
 (4.7)

 ____________________
 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.
 2.The Schedule 95 Supplemental PCA mechanism rates from the prior year that recovers the 2022 imbalance (effective December 1, 2023).
 3.Schedule 95 update through power cost only rate case (PCORC) filing. Per the 2022 GRC Final Order in Docket No. UE-220066, PCORC rates were set to zero as of January 11, 2023.
 4.Total credit to be passed back to eligible customers is $88.1 million and $72.6 million for 2023 and 2021, respectively.

 Natural Gas Rates
 The following natural gas rate schedules were filed with the Washington Commission or approved by the Washington Commission. For further information on descriptions of the filings, see Business, "Regulation and Rates" included in Item 1 of this report.

 Natural gas

 Schedule
 Docket
 Effective Date
 Average
Percentage
in Rates
in Revenue
(Dollars in Millions)

 Bill discount rate rider

 129D

 230693
 October 1, 2023
 1.1%
 $13.1

 CCA - greenhouse gas emissions cap & invest

 230968
 3.0
 29.1

 230756
 November 1, 2023
 2.1
 27.2

 230470
 October 1, 20231

 3.2
 16.8

 Conservation service rider
 230140
 0.4
 4.7

 220138
 0.3
 3.2

 Cost recovery mechanism for pipeline replacement

 220067
 January 7, 2023
 (2.0)
 (22.6)

 220590
 November 1, 2022
 0.4
 4.6

 210678
 November 1, 2021
 0.5
 4.9

 Distribution pipeline provisional recovery

 141D

 220067
 (0.01)
 (0.1)

 January 7, 2023
 0.3
 3.0

 Low income program

 230695
 October 1, 2023
 0.2
 1.9

 220657
 October 1, 2022
 (0.04)
 (0.4)

 210675
 October 1, 2021
 (0.3)
 (3.0)

 Property tax tracker

 230220
 (0.02)
 (0.2)

 220235
 0.02
 0.2

 Purchased gas adjustment

 101, 106

 230769
 November 1, 2023
 (24.2)
 (309.4)

 220715
 November 1, 2022
 14.9
 155.3

 210721
 November 1, 2021
 5.8
 59.1

 Rates not subject to refund
 141N
 230889
 (2.3)
 (27.6)

 220067
 January 7, 2023
 (0.1)
 (1.6)

 Rates subject to refund

 141R

 230889
 4.0
 47.2

 230323
 November 1, 2023
 (0.1)
 (1.4)

 220067
 January 7, 2023
 4.1
 45.5

 ____________________
 1.Per UG-230740, the tariff was effective October 1, 2023 until December 31, 2023 and would recover costs and pass back credits from August 1, 2023 to December 31, 2023.

 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, could increase the cost of issuing long-term debt and maintaining credit facilities, and could impact the Company's ability to pay dividends. 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, climate change and endangered species protection, waste handling and disposal (including generation by-products such as coal ash), remediation of contaminated sites and the environmental impacts of siting new facilities also impact the Company's operations. PSE must spend significant 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 CCA, which establishes a greenhouse gases (GHG) emissions cap-and-invest program that requires covered entities to purchase allowances to cover their GHG emissions with a cap on available allowances beginning on January 1, 2023 that declines 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. The WDOE also indicated that it will have subsequent rulemakings building off initial rulemaking while program implementation is underway and progress with Washington 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.
 While the Washington Commission has approved the recovery of natural gas CCA-related costs, which has led to increases in costs to customers, it has indicated these revenues are subject-to-refund, and there is a risk PSE may ultimately not be able to recover all costs. Electric CCA-related costs have not yet been approved for recovery at this time and it is uncertain what obligation may be borne by customers or at risk for recovery. PSE faces continued risks associated with the program, including the evolving nature of the CCA rulemaking and related interpretation of the rules, 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
 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, 2023, and December 31, 2022.

 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:

 2023
 2022

 Operating income (loss)
 $
 335,452
 $
 792,462

 Electric utility revenue

 Purchased electricity
 (1,110,572)
 (1,038,728)

 Electric generation fuel
 (457,287)
 (348,159)

 Residential exchange
 77,223
 77,715

 Utility electric margin (non-GAAP)
 $
 1,855,231
 $
 1,652,285

 Natural gas operating revenue
 $
 1,424,368
 $

 Purchased natural gas
 (641,371)
 (500,849)

 Utility natural gas margin (non-GAAP)
 $
 782,997
 $
 708,787

 Other revenue
 $
 16,383
 $
 45,080

 Unrealized gain (loss) on derivative instruments, net
 (284,495)
 261,177

 Other operation and maintenance expenses
 (735,278)
 (665,259)

 Non-utility expense and other
 (28,658)
 (47,194)

 (865,969)
 (774,291)

 Taxes other than income tax expense
 (404,759)
 (388,123)

 Operating income (loss)
 $
 335,452
 $
 792,462

 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, 2022, to December 31, 2023:

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

 2022 compared to 2023
 Electric Operating Revenue
 Electric operating revenues increased $384.4 million primarily due to increased retail sales of $231.8 million, sales to other utilities and marketers of $172.8 million, other decoupling revenue of $28.7 million and decoupling revenue of $1.8 million, which were partially offset by a decrease in transportation and other revenue of $50.8 million. These items are discussed in detail below:
 • Electric retail sales increased $231.8 million due to an increase of $283.6 million in rates compared to the prior year, partially offset by a decrease of $51.8 million from a decrease in retail electricity usage of 2.1%. The increase in rates is primarily due to the tariffs filed pursuant to the Company's most recent GRC effective January 11, 2023. See "Regulation of PSE Rates and Recovery of PSE Costs" included in this Item 7 of this report for electric rate changes. The decrease in retail usage was due to a decrease in residential, commercial and industrial usage of 3.1%, 0.5% and 3.9%, respectively. Customer usage decreased due to a decrease in heating and cooling degree days of 8.5% and 6.0%, respectively, in 2023 as compared to 2022.
 • Sales to other utilities and marketers increased $172.8 million primarily due to a 103.2% increase in wholesale sale volumes due to increased volume from PSE natural gas-fired generation, which increased 72.5% in 2023 compared to 2022. Lower natural gas fuel prices made natural gas-fired generation more economic to dispatch in 2023 compared to 2022. This increase was partially offset by a decrease in electric wholesale sales price of 24.9%.

 • Decoupling revenue increased $1.8 million, attributable to a $13.5 million decrease and a $15.3 million increase in delivery and fixed production cost (FPC) deferral revenues, respectively. The decrease in delivery deferral revenue was primarily driven by increased actual rates, whereas the increase in FPC deferral revenue was primarily driven by decreased usage.
 • Other decoupling revenue increased $28.7 million, primarily due to changes in amortization rates. For the year ended December 31, 2023, prior year overcollection deferrals from residential customers were amortized at a higher rate compared to the same period in 2022. A higher percentage of amortization related to prior year overcollection results in more revenue recognized in the current period. This was partially offset by a $3.0 million decrease related to GAAP alternative revenue program recognition guidelines. As of the year ended December 31, 2022, there were $3.0 million of deferred 2021 GAAP alternative decoupling revenues that were recognized. There were no such revenues recognized in 2023.
 • Transportation and other revenue decreased $50.8 million primarily due to a $63.5 million decrease in net wholesale non-core natural gas sales and a $2.5 million energy charge credit recovery adjustment approved in the 2022 GRC, which was partially offset by an increase of $16.8 million due to the IRS Private Letter Ruling in 2022, which included amortization to offset recovery through rates in 2022. The decrease in wholesale non-core natural gas sales was primarily driven by a decrease of $56.6 million in financial hedging gains in 2023 compared to 2022 due to a decrease in natural gas prices. Additionally, net wholesale non-core natural gas sales decreased $6.9 million which was primarily driven by a 34.1% decrease in both the average price of natural gas sales and purchases in 2023 compared to 2022.

 Electric Power Costs
 Electric power costs increased $181.4 million primarily due to an increase of $71.8 million of purchased electricity costs and $109.1 million of electric generation fuel costs. These items are discussed in detail below:
 • Purchased electricity expense increased $71.8 million primarily due to increased wholesale purchase prices, which were 11.9% higher in 2023 compared to 2022, driven by open market purchases as well as two winter peaking power purchase agreements that began after September 2022, a power purchase agreement for energy produced at the Puget Sound Refinery Cogeneration Facility that began after July 2023, and the Clearwater Wind Project that began commercial operations in November 2022. The increase from wholesale purchase prices were partially offset by a 4.4% decrease in wholesale electricity purchases.
 • Electric generation fuel expense increased $109.1 million primarily due to a $106.4 million increase in natural gas fuel costs as a result of a 72.5% increase in PSE natural gas-fired generation as discussed in sales to other utilities and marketers above. Higher costs from increased production were partially offset by lower natural gas prices which drove a 20.8% decrease in average unit production costs.

 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, 2022, to December 31, 2023:

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

 2022 compared to 2023
 Natural Gas Operating Revenue
 Natural gas operating revenue increased $214.7 million primarily due to higher retail sales of $165.0 million, decoupling revenue of $27.1 million, other decoupling revenue of $12.2 million and transportation and other revenue of $10.4 million. These items are discussed in the following details:
 • Natural gas retail sales increased $165.0 million due to an increase in rates of $233.9 million partially offset by a decrease in natural gas load of 5.6% or $68.8 million of natural gas sales. The increase in rates is due to the tariffs filed pursuant to the Company's PGA and GRC effective November 1, 2022 and January 7, 2023, respectively, and was partially offset by a decrease in the Company's most recent PGA rates effective November 2023. See "Regulation of PSE Rates and Recovery of PSE Costs" included in this Item 7 of this report for natural gas rate changes. The decrease in load is driven by a decrease of commercial and residential usage of 3.3% and 7.0%, respectively. Customer usage decreased due to a decrease in heating degree days of 8.5% in 2023 as compared to 2022.

 • Decoupling revenue increased $27.1 million, primarily due to decreased natural gas usage, as mentioned above, in 2023 compared to 2022, which was caused by higher average temperatures.
 • Other decoupling revenue increased $12.2 million due to increased amortization rates for prior year overcollection deferrals and decreased amortization rates for undercollection deferrals compared to the same period in 2022. A higher percentage of amortization related to prior year overcollection resulted in more revenue recognized in the current period.
 • Transportation and other revenue increased $10.4 million primarily due to an increase in transportation revenue of $8.3 million and $3.1 million related to the IRS PLR which included amortization of the PLR to offset recovery through rates in 2022.

 Natural Gas Energy Costs
 Purchased natural gas expense increased $140.5 million primarily due to an increase in the PGA rates in November 2022 and was partially offset by a decrease in the PGA rates in November 2023 and a decrease in natural gas usage of 5.6% 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, 2022, to December 31, 2023:

 2022 compared to 2023
 Other Operating Expenses
 • Net unrealized (gain) loss on derivative instruments changed $545.7 million to a net loss of $284.5 million for the year ended December 31, 2023. The primary driver was the change in the weighted average forward prices for electric and natural gas. Specifically, the change in electric weighted average forward price decreased 156.4%, which resulted in $280.0 million in loss for electric, as well as net settlement of electric trades that were previously recorded as $48.2 million in gain. Natural gas prices decreased 85.1% resulting in $328.2 million loss for natural gas. These losses were partially offset by the natural gas trades previously recorded as $110.6 million in loss.
 • Utility Operations and Maintenance expense increased $70.0 million primarily due to increases in the following: (i) $10.7 million related to transportation electrification and CEIP trackers; (ii) $9.5 million in customer service expense due to increased low-income assistance; (iii) $9.4 million in outside consulting fees related to corporate strategic planning; (iv) $7.1 million related to higher administration expenses related to customer collections and records processing; (v) $6.6 million in pension related expenses; (vi) $5.6 million related to increased steam generation maintenance expenses related to boilers and other equipment; (vii) $5.2 million of administrative and general expenses related to the CEIP and other strategic projects; (viii) $4.1 million related to injuries and damages expense; and (ix) $4.0 million related to higher distribution operations expense. These increases were partially offset by a decrease of $7.4 million of maintenance related natural gas-fired electric generating equipment.
 • Non-utility and other expense decreased $18.4 million primarily due to a decrease of $22.1 million related to biogas purchase expense, driven by a decrease in both volume of biogas purchased and average biogas purchase price.

 • Depreciation and amortization expense increased $91.7 million primarily driven by (i) $41.0 million increase in electric amortization from 2022 primarily driven by $21.9 million less Lower Snake River treasury grant amortization credits in 2023 compared to 2022, $12.1 million addition of 2022 storm cost amortized in 2023, and $6.8 million in Get to Zero (GTZ) electric tranche amortization; (ii) $27.1 million increase in natural gas distribution depreciation from 2022 primarily due to $188.6 million in net additions in natural gas distribution assets; (iii) $11.0 million increase in electric distribution depreciation from 2022 primarily due to $279.8 million in net additions of electric distribution assets; (iv) $10.7 million increase in electric production depreciation from 2022 primarily due to $51.1 million in net additions of electric production assets; (v) $6.4 million increase in natural gas amortization from 2022 primarily driven by a $3.6 million increase in GTZ natural gas tranche amortization; and (vi) $4.4 million increase in conservation amortization due to conservation rider rates effective May 1, 2023, see "Regulation of PSE Rates and Recovery of PSE Costs" included in this Item 7 of this report. These increases were partially offset by: (i) $5.2 million decrease in electric general plant and other depreciation from 2022 primarily driven by a $5.1 million decrease in asset retirement costs in 2023 compared to 2022 and (ii) $2.7 million decrease in common general plant from 2022, driven by the timing of retirements during 2023, which were offset by additions in the fourth quarter of 2023.
 • Taxes other than income taxes increased $16.6 million primarily due to an increase of $14.7 million related to municipal taxes driven by the increase in retail revenue in 2023 as compared to 2022 and $11.6 million related to the state excise tax. These increases were partially offset by a decrease of $7.7 million in property taxes.

 Other Income, Interest Expense and Income Tax Expense
 • Other income/expense increased $32.4 million from net other income of $17.1 million in 2022 to $49.5 million in 2023, due to an increase of $27.5 million in other income and a decrease of $4.8 million in other expense. The increase was primarily driven by the following increases: (i) $13.0 million in taxable interest and dividend income due to an increase in PCA customer interest and interest earned on short-term investments of excess cash; (ii) $10.2 million in AFUDC due to an increase in eligible construction work in progress; (iii) $6.6 million in the non-service cost component of the qualified pension net periodic benefit cost for 2023 compared to 2022; (iv) $3.2 million in other expense related to a 2022 write-off of the Colstrip dry ash facilities; and (v) $2.2 million in gain on corporate life insurance policies. These increases in other income and other expense were partially offset by a decrease of $2.3 million in AMI due to a change in AMI return deferral per the 2022 GRC.
 • Interest expense increased $22.1 million primarily due to (i) $13.5 million increase in interest expense due to the May 2023 PSE bond issuance; (ii) $9.2 million increase related to interest expense recognized on the PGA liability; and (iii) $3.5 million increase in interest expense recognized in conjunction with PSE's deferred compensation liability. These increases were partially offset by a decrease of $3.3 million in monetized PTC interest expense.
 • Income tax expense decreased $86.9 million primarily driven by a decrease in pre-tax book income.

 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, 2022, and December 31, 2023, were as follows:

 2022 compared to 2023
 Summary Results of Operations
 Puget Energy's net income decreased by $360.6 million, which is primarily attributable to a decrease in PSE's net income of $359.9 million and a decrease in other operating revenue and income of $7.3 million due to a decrease in pension non-service cost of $6.3 million. These decreases were partially offset by a decrease in interest expense of $4.6 million driven by a decrease of $8.2 million on a senior note that retired in 2022, a decrease of $9.3 million due to Puget LNG interest expense, which is eliminated during consolidation, an increase in interest expense of $9.3 million related to the revolving credit agreement and an increase of $2.9 million due to a senior note issued in 2022. For further information, see Note 7, "Long-Term Debt" and Note 8, "Liquidity" to the consolidated financial statements included in Item 8 of this report.

 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, 2023:

 Payments Due Per Period

 Total
 2024
 2025-2026
 2027-2028

 Contractual obligations:

 Energy purchase obligations1

 $
 11,464,428
 $
 1,616,568
 $
 2,207,218
 $
 1,340,562
 $
 6,300,080

 Long-term debt including interest2

 9,801,650
 261,508
 538,743
 797,503
 8,203,896

 Short-term debt including interest
 336,600
 336,600
 —
 —
 —

 Service contract obligations
 277,501
 34,702
 71,504
 74,469
 96,826

 Non-cancelable operating leases3

 281,595
 24,390
 48,180
 44,205
 164,820

 PSE finance leases3

 136,423
 6,586
 13,357
 13,401
 103,079

 Pension and other benefits funding and payments
 51,242
 20,846
 11,074
 7,825
 11,497

 Total PSE contractual cash obligations
 22,349,439
 2,301,200
 2,890,076
 2,277,965
 14,880,198

 Long-term debt including interest2

 2,400,677
 72,153
 520,466
 608,556
 1,199,502

 Short-term debt including interest
 273,434
 273,434
 —
 —
 —

 Total Puget Energy contractual cash obligations
 $
 25,023,550
 $
 2,646,787
 $
 3,410,542
 $
 2,886,521
 $
 16,079,700

 ____________________
 1.Energy purchase contracts were entered into as part of PSE's obligation to serve retail electric and natural gas customers' energy requirements. As a result, costs are generally recovered either through base retail rates or adjustments to retail rates as part of the power and natural gas cost adjustment mechanisms.
 2.For individual long-term debt maturities, see Note 7, "Long-Term Debt," to the consolidated financial statements included in Item 8 of this report. For Puget Energy, the amount above excludes the fair value adjustments related to the merger.
 3.For additional information, see Note 9, "Leases" to the consolidated financial statements included in Item 8 of this report.

 For additional information regarding PSE's and Puget Energy's commercial commitments see Note 8, "Liquidity Facilities and Other Financing Arrangements" to the consolidated financial statements included in Item 8 of this report.

 Off-Balance Sheet Arrangements
 As of December 31, 2023, 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. The Company does have standby letter of credit arrangements. For more information, see Note 8 "Liquidity Facilities and Other Financing Arrangements" to the consolidated financial statements included in Item 8 of this report.

 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. The Company's capital expenditures were $381.0 million higher than forecasted amounts for 2023. The increase was primarily due to (i) new generation resource acquisition, higher natural gas construction and electric first response, and unplanned thermal maintenance; (ii) pull-forward of cable remediation work, Tono and Buckley substation work, and Sammamish-Juanita transmission line project, and (iii) delayed Energize Eastside and Smart Grid projects. Construction expenditures, excluding equity allowance for funds used during construction (AFUDC), totaled $1.5 billion in 2023.

 Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:

 Capital Expenditure Projections

 (Dollars in Millions)
 2024
 2025
 2026

 Total energy delivery, technology and facilities expenditures
 $1,716.0
 $1,936.4
 $2,231.7

 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.

 Capital Resources
 Cash from Operations

 2023
 2022
 Change

 Net income
 $
 $
 $
 (359,893)

 Non-cash items1

 990,519
 476,696
 513,823

 Changes in cash flow resulting from working capital2

 (174,908)
 (64,749)
 (110,159)

 Regulatory assets and liabilities
 153,069
 (90,335)
 243,404

 Purchased gas adjustment
 152,763
 37,256
 115,507

 GHG emission allowances
 (129,195)
 —
 (129,195)

 Other non-current assets and liabilities3

 (32,247)
 (32,359)

 Net cash (used in)/provided by operating activities
 $
 1,091,060
 $
 817,461
 $
 273,599

 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, accounts payable and accrued expenses.
 3.Other non-current assets and liabilities include funding of pension liability.

 Year Ended December 31, 2023, compared to 2022
 Cash generated from operations increased by $273.6 million despite a decrease in net income of $359.9 million. The following are significant factors that impacted PSE's cash flows from operations:
 • Cash flow adjustments resulting from non-cash items increased $513.8 million, primarily due to: (i) a $545.7 million change from a net unrealized gain on derivative instruments of $261.2 million to a net unrealized loss on derivative instruments of $284.5 million, (ii) an increase in depreciation and amortization of $87.3 million, (iii) increased conservation amortization of $4.4 million and (iv) a deferral of return and depreciation expenses for PSE's share of Tacoma LNG investment of $4.2 million. The increases were partially offset by: (i) a decrease in deferred taxes of $118.3 million and (ii) a decrease in equity AFUDC of $10.7 million. For further discussion, see "Other Operating Expenses" in Item 7, Management's Discussion and Analysis.
 • Cash flows resulting from changes in working capital decreased $110.2 million primarily due to: (i) accounts payable decreased faster than the same period last year that led to increased cash outflows of $469.3 million, (ii) higher prepayment balances of $37.6 million, (iii) higher balances in materials and supplies increased cash outflows of $22.4 million, (iv) increased cash outflow of $7.7 million related to the timing of transmission deposits, (v) an increased cash outflow of $11.1 million related to higher incentive payments and (vi) higher Washington Commission annual filing fees of $6.0 million. The decreases were partially offset by: (i) cash inflows of $389.0 million in accounts receivable and unbilled revenue as the balance decreased $136.7 million in the twelve months ended December 31, 2023 compared to an increase of $252.3 million during the same period of 2022; (ii) lower balances in

 fuel and natural gas inventory led to cash inflow of $39.7 million, and (iii) an increase of $3.2 million due to a higher tax payable balance.
 • Cash flows resulting from regulatory assets and liabilities increased $243.4 million primarily due to: (i) $181.4 million cash proceeds received from the sale of consigned GHG emission allowances, which is required to be returned to customers and (ii) $96.4 million of cash inflow from power cost adjustment receivable, which was due to actual power costs being lower than baseline rates in 2023, whereas actual power costs were higher than baseline rates in 2022. The increases were partially offset by: (i) a $21.0 million decrease in cash flows related to the amortization of IRS PLR deferred balances and (ii) $6.7 million decrease in cash flow caused by greater accrual of bad debt deferral related to COVID-19 in 2023 compared to 2022.
 • Cash flow resulting from purchased gas adjustment increased $115.5 million, which was mainly driven by a decrease in actual natural gas costs and an increase in allowed PGA recovery in 2023 compared to 2022. Decreased natural gas prices led to a $62.4 million, or 13.6%, decrease in actual natural gas costs in 2023 compared to 2022. Meanwhile, the total amount of allowed PGA recovery in 2023 increased $25.0 million, or 5.0%, compared to 2022. In addition, there was a $28.1 million refund (including interest) from a counterparty settlement received in January 2023.
 • Cash flow resulting from GHG emission allowances decreased $129.2 million, which was driven by obtaining Washington emission allowances for GHG emissions associated with the Company's electric and natural gas business activities in compliance with the CCA.

 2023
 2022
 Change

 Net income
 $
 (77,319)
 $
 (76,607)
 $
 (712)

 Non-cash items1

 42,770
 36,689
 6,081

 Changes in cash flow resulting from working capital2

 (649)
 1,355
 (2,004)

 Other non-current assets and liabilities3

 (2,467)
 (9,280)
 6,813

 Net cash (used in)/provided by operating activities
 $
 (37,665)
 $
 (47,843)
 $
 10,178

 1.Non-cash items include depreciation, amortization, deferred income taxes, net unrealized (gain) loss on derivative instruments, (Gain) or loss on extinguishment of debt and other miscellaneous non-cash items.
 2.Changes in working capital include receivables, unbilled revenue, materials/supplies, fuel/gas inventory, income taxes, prepayments, accounts payable and accrued expenses.
 3.Other non-current assets and liabilities include funding of pension liability.

 Year Ended December 31, 2023, compared to 2022
 Cash generated from operations for the year ended December 31, 2023, in addition to the changes discussed at PSE above, increased by $10.2 million compared to the same period in 2022, which includes a net income decrease of $0.7 million. The remaining change was primarily impacted by the factors explained below:
 • Changes in cash flow resulting from non-cash items increased $6.1 million, primarily due to higher non-cash inflows of $5.5 million related to changes in deferred taxes.
 • Changes in cash flow resulting from working capital decreased $2.0 million primarily due to: (i) a $8.4 million increase of cash outflows due to the change in PSE's intercompany accounts receivable and account payable balances with Puget LNG and Puget Energy, which are eliminated upon consolidation of Puget Energy and (ii) a $5.4 million cash outflow due to changes in tax payable. The decreases were partially offset by: (i) a cash inflow of $5.9 million driven by reduction of accrued interest expense as result of lower interest rates on debt, as Puget Energy issued $450.0 million of senior secured notes at an interest rate of 4.224% in March 2022 and repaid $450.0 million of 5.625% notes in April 2022, (ii) a cash inflow of $4.3 million due to balance changes in account receivable related to Puget LNG and (iii) lower balances in fuel and natural gas inventory specific to Puget LNG led to a cash inflow of $1.5 million.
 • Changes in other non-current assets and liabilities increased $6.8 million mainly due to a $3.7 million cash inflow related to nonrecurring fees incurred in 2022 associated with the Puget Energy credit facility that was entered into in May 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 operating and construction programs. Puget Energy and PSE continue to have reasonable access to the capital and credit markets.
 As of December 31, 2023, both Puget Energy and PSE have stable outlooks from Moody's, Fitch, and S&P. Although neither Puget Energy nor PSE have any debt whose maturity would be accelerated upon a ratings downgrade, management continually monitors the credit rating environment for both Puget Energy and PSE as 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 could negatively impact Puget Energy and PSE's future results of operations as well as future liquidity, access to debt capital resources and financial condition. Additionally, a ratings downgrade could impact the Company's ability to issue dividends. 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 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 term, due to continuing strategic and risk mitigation imperatives and the necessity of providing safe, reliable and resilient service levels to customers.
 For information on Puget Energy and PSE dividends, long-term debt including S-3 shelf registrations, 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, 2023, PSE could issue:
 • Approximately $1.6 billion of additional first mortgage bonds under PSE's electric mortgage indenture based on approximately $2.6 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, 2023; and
 • Approximately $1.1 billion of additional first mortgage bonds under PSE's natural gas mortgage indenture based on approximately $1.8 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, 2023.
 At December 31, 2023, PSE had approximately $9.3 billion in electric and natural gas rate base to support the interest coverage ratio limitation test for net earnings available for interest.

 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, 2023, in the amount of $1,212.0 million and $1,914.9 million, respectively, and regulatory assets and liabilities at December 31, 2022, of $896.4 million and $1,961.1 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 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 the 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, and 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 (e.g. 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 the 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, the solvency of other liable parties 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 and/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.

 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 $0.3 million and $14.7 million for the years ended December 31, 2023, and 2022, respectively. Of these amounts, approximately 46.6% and 48.3% were included in utility operations and maintenance expense in 2023 and 2022, respectively, and the remaining amounts were capitalized. For the years ended December 31, 2023, and 2022, Puget Energy recognized incremental qualified pension income of $2.4 million and $8.7 million, respectively. In 2024, it is expected that PSE and Puget Energy will recognize pension income of $5.6 million and incremental qualified pension income of $2.6 million, respectively.
 PSE has a SERP and other limited postretirement benefit plans, for which expenses for the years ended December 31, 2023 and 2022 were immaterial for both PSE and PE. Further, PSE and PE expect to recognize immaterial expenses in 2024 related to the SERP and other limited postretirement benefit plans.
 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 2023, 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, 2023, and 2022, the Company's qualified pension plan was $136.9 million overfunded and $69.3 million overfunded as measured under GAAP, or 121.0% and 111.8% funded, respectively. As of January 1, 2024, 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, 2024, are expected to be at least $18.0 million, $2.0 million and $0.2 million, respectively.
 The discount rate used in accounting for pension and other benefit obligations decreased from 5.60% in 2022 to 5.30% in 2023. The discount rate used in accounting for pension and other benefit expense increased from 3.00% in 2022 to 5.60% in 2023. The rate of return on plan assets for qualified pension benefits increased from 6.50% in 2022 to 6.75% in 2023. The rate of return on plan assets for other benefits was 7.00% in both 2022 and 2023.
 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):

 Change in Assumption

 Impact on Projected
 Benefit Obligation
 Increase /(Decrease)

 SERP

 Other Benefits

 Increase in discount rate

 $
 (29,442)

 $
 (720)

 $
 (293)

 Decrease in discount rate

 32,256

 Change in Assumption

 Impact on 2023
 Pension Expense
 Increase /(Decrease)

 SERP

 Other Benefits

 Increase in discount rate

 $
 (2,354)
 $

 $
 (29)

 Decrease in discount rate

 2,383

 Increase in return on plan assets

 $
 (3,752)
 *

 $
 (21)

 Decrease in return on plan assets

 3,752
 *

 Change in Assumption

 Impact on 2023
 Pension Expense
 Increase /(Decrease)

 SERP

 Other Benefits

 Increase in discount rate

 $
 $

 $
 (31)

 Decrease in discount rate

 1,504

 Increase in return on plan assets

 $
 (3,752)
 *

 $
 (21)

 Decrease in return on plan assets

 3,752
 *

 * 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. The Audit Committee of the Company's Board of Directors annually approves the Company's energy risk policies and procedures which includes a review of established risk tolerances and limits for the energy supply portfolio.
 When managing the electric and natural gas portfolios, PSE's primary objectives are to: (1) minimize commodity price exposure and risks associated with volumetric variability, (2) ensure physical energy supplies are available to serve retail customer-loads, while (3) limiting undesired impacts or portfolio risks, and (4) 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, price 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 (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

 Assets
 Liabilities
 Assets
 Liabilities

 Electric portfolio:

 Current
 $
 62,929
 $
 107,195
 $
 267,811
 $
 79,668

 Long-term
 30,099
 19,744
 69,892
 7,452

 Total Electric Portfolio
 $
 93,028
 $
 126,939
 $
 337,703
 $
 87,120

 Natural gas portfolio:

 Current
 11,296
 78,593
 319,218
 45,308

 Long-term
 5,225
 18,305
 24,729
 10,914

 Total Natural Gas Portfolio
 $
 16,521
 $
 96,898
 $
 343,947
 $
 56,222

 Total derivatives
 $
 $
 $
 $

 At December 31, 2023, the Company had total assets of $109.5 million and total liabilities of $223.8 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 $45.9 million.

 The change in fair value of the Company's outstanding energy derivative instruments from December 31, 2022, through December 31, 2023, is summarized in the table below:

 Puget Energy and Puget Sound Energy

 Energy Derivative Contracts Gain (Loss)

 Fair value of contracts outstanding at December 31, 2022
 $
 538,308

 Contracts realized or otherwise settled during 2023
 (339,224)

 Change in fair value of derivatives
 (313,372)

 Fair value of contracts outstanding at December 31, 2023
 $
 (114,288)

 The fair value of the Company's outstanding derivative instruments at December 31, 2023, based on pricing source and the period during which the instrument will mature, is summarized below:

 Puget Energy and Puget Sound Energy
Source of Fair Value
 Fair Value of Contracts by Settlement Year

 2024
 2025-2026
 2027-2028
 Total

 Prices provided by external sources1

 $
 (124,231)
 $
 (17,983)
 $
 (3,187)
 $
 —
 $
 (145,401)

 Prices based on internal models and valuation methods
 12,668
 18,847
 (402)
 —
 31,113

 Total fair value
 $
 (111,563)
 $
 $
 (3,589)
 $
 —
 $
 (114,288)

 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 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, 2023, PSE held approximately $787.0 million in standby letters of credit or limited parental guarantees and had 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, 2023, approximately 81.2% 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, 2023, 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 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, 2023, PSE had cash posted as collateral of $12.4 million related to contracts executed on the ICE platform. As a condition of transacting on the ICE NGX platform as well as participating in the Washington state carbon allowance auctions, PSE maintains a standby letter of credit agreement with TD Bank. As of December 31, 2023, PSE had no cash posted with ICE NGX, and $51.0 million was issued under the standby letter of credit agreement in support of natural gas and carbon allowance purchases. 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, 2023.

 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

 Carrying Amount
 Carrying Amount

 $
 $
 6,855,503
 $
 6,663,373
 $
 6,184,097

 5,007,483
 4,379,010

 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, 2023, was a net loss of $3.8 million after-tax and accumulated amortization. This compares to an after-tax loss of $4.2 million in OCI as of December 31, 2022. 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, 2023.
 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, 2023, the Company had no outstanding interest rate swap instruments.

 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 REPORTS:
 Page

 Report of Management and Statement of Responsibility

 Report of Independent Registered Public Accounting Firm - Puget Energy

 Report of Independent Registered Public Accounting Firm - Puget Sound Energy

 INDEX TO FINANCIAL STATEMENTS:

 PUGET ENERGY:

 Consolidated Statements of Income - Years Ended December 31, 2023, 2022, and 2021

 Consolidated Statements of Comprehensive Income - Years Ended December 31, 2023, 2022, and 2021

 Consolidated Balance Sheets - December 31, 2023 and 2022

 Consolidated Statements of Common Shareholder's Equity - Years Ended December 31, 2023, 2022, and 2021

 Consolidated Statements of Cash Flows - Years Ended December 31, 2023, 2022, and 2021

 PUGET SOUND ENERGY:

 Consolidated Statements of Income - Years Ended December 31, 2023, 2022, and 2021

 Consolidated Statements of Comprehensive Income - Years Ended December 31, 2023, 2022, and 2021

 Consolidated Balance Sheets - December 31, 2023 and 2022

 Consolidated Statements of Common Shareholder's Equity - Years Ended December 31, 2023, 2022, and 2021

 Consolidated Statements of Cash Flows - Years Ended December 31, 2023, 2022, and 2021

 NOTES to the Consolidated Financial Statements of Puget Energy and Puget Sound Energy:

 Note 1.
 Summary of Significant Accounting Policies

 Note 2.
 New Accounting Pronouncements

 Note 3.
 Revenue

 Note 4.
 Regulation and Rates

 Note 5.
 Dividend Payment Restrictions

 Note 6.
 Utility Plant

 Note 7.
 Long-Term Debt

 Note 8.
 Liquidity Facilities and Other Financing Arrangements

 Note 9.
 Leases

 Note 10.
 Accounting for Derivative Instruments and Hedging Activities

 Note 11.
 Fair Value Measurements

 Note 12.
 Employee Investment Plans

 Note 13.
 Retirement Benefits

 Note 14.
 Income Taxes

 Note 15.
 Litigation

 Note 16.
 Commitments and Contingencies

 Note 17.
 Accumulated Other Comprehensive Income (Loss)

 SCHEDULE:

 I. Condensed Financial Information of Puget Energy - December 31, 2023, and 2022, and for the Years Ended December 31, 2023, 2022, and 2021

 II. Valuation and Qualifying Accounts and Reserves - Years Ended December 31, 2023, 2022, 2021

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

 REPORT OF MANAGEMENT AND STATEMENT OF RESPONSIBILITY

 AND

 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 Compliance and Ethics 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 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 and Ethics 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/ Daniel Doyle

 /s/ Stacy Smith

 Daniel Doyle

 Stacy Smith

 President and Chief Executive Officer

 Chief Financial Officer

 Controller and Principal
 Accounting Officer

 Report of Independent Registered Public Accounting Firm

 To the Board of Directors and Shareholder of Puget Energy, Inc.

 Opinions on the Financial Statements and Internal Control over Financial Reporting

 We have audited the consolidated financial statements, including the related notes and financial statement schedules, of Puget Energy, Inc. 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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 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, 2023, 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.

 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 $1,218.2 million of regulatory assets and $1,962.4 million of regulatory liabilities as of December 31, 2023. Management accounts for the Company's regulated operations in accordance with the Financial Accounting Standards Board's (FASB) accounting guidance for regulated operations, which requires deferral of certain costs or losses that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. The FASB's accounting guidance for regulated operations similarly requires deferral of revenues or gains that are expected to be returned to customers in the future. This accounting is appropriate as long as rates are established by or subject to approval by independent third-party regulators; rates are designed to recover the specific enterprise's cost of service; and in view of demand for service, it is reasonable to assume that rates set at levels that will recover costs can be charged to and collected from customers. As disclosed by management, the regulatory assets and liabilities are expected to be fully recovered through the Company's rates. If future recovery of costs ceases to be probable, management would be required to write off the regulatory assets and liabilities. In addition, if management determines that it no longer meets the criteria for continued application of the FASB's accounting guidance for regulated operations, management could be required to write off its regulatory assets and liabilities related to those operations not meeting the FASB's requirements.

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

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

 /s/ PricewaterhouseCoopers LLP
 Seattle, Washington

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

 Report of Independent Registered Public Accounting Firm

 To the Board of Directors and Shareholder of Puget Sound Energy, Inc.

 Opinions on the Financial Statements and Internal Control over Financial Reporting

 We have audited the consolidated financial statements, including the related notes and financial statement schedule, of Puget Sound Energy, Inc. 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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 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, 2023, 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.

 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 $1,212.0 million of regulatory assets and $1,914.9 million of regulatory liabilities as of December 31, 2023. Management accounts for the Company's regulated operations in accordance with the Financial Accounting Standards Board's (FASB) accounting guidance for regulated operations, which requires deferral of certain costs or losses that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. The FASB's accounting guidance for regulated operations similarly requires deferral of revenues or gains that are expected to be returned to customers in the future. This accounting is appropriate as long as rates are established by or subject to approval by independent third-party regulators; rates are designed to recover the specific enterprise's cost of service; and in view of demand for service, it is reasonable to assume that rates set at levels that will recover costs can be charged to and collected from customers. As disclosed by management, the regulatory assets and liabilities are expected to be fully recovered through the Company's rates. If future recovery of costs ceases to be probable, management would be required to write off the regulatory assets and liabilities. In addition, if management determines that it no longer meets the criteria for continued application of the FASB's accounting guidance for regulated operations, management could be required to write off its regulatory assets and liabilities related to those operations not meeting the FASB's requirements.

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

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

 /s/ PricewaterhouseCoopers LLP
 Seattle, Washington

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

 CONSOLIDATED STATEMENTS OF INCOME

 2023
 2022
 2021

 Operating revenue:

 $
 $
 $
 2,671,623

 Natural gas
 1,423,276
 1,067,418

 Other
 47,431
 50,069

 4,816,574
 4,221,162
 3,805,661

 Operating expenses:

 Energy costs:

 Purchased electricity
 1,110,572
 1,038,728
 784,565

 Electric generation fuel
 457,287
 348,159
 282,254

 Residential exchange
 ( 77,223)
 ( 77,715)
 ( 82,225)

 Purchased natural gas
 641,371
 500,849
 398,553

 Unrealized (gain) loss on derivative instruments, net
 284,495
 ( 261,177)
 ( 13,785)

 Utility operations and maintenance
 735,278
 665,259
 629,864

 Non-utility expense and other
 56,515
 59,804
 58,281

 751,335
 663,232
 704,783

 Conservation amortization
 121,340
 116,942
 103,147

 Taxes other than income taxes
 404,538
 389,442
 362,527

 Total operating expenses
 4,485,508
 3,443,523
 3,227,964

 Operating income (loss)
 331,066
 777,639
 577,697

 Other income (deductions):

 Other income
 66,829
 45,450
 57,483

 Other expense
 ( 14,765)
 ( 19,569)
 ( 14,467)

 Interest charges:

 AFUDC
 24,687
 18,444
 16,743

 Interest expense
 ( 381,511)
 ( 347,921)
 ( 352,092)

 Income (loss) before income taxes
 26,306
 474,043
 285,364

 Income tax (benefit) expense
 ( 27,434)
 59,698
 24,515

 $
 $
 $

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

 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 2023
 2022
 2021

 $
 $
 $

 Other comprehensive income (loss):

 Net unrealized gain (loss) from pension and postretirement plans, net of tax of $ 8,916, $ 708 and $ 15,686, respectively

 2,658

 2,658

 Comprehensive income (loss)
 $
 96,053
 $
 417,003
 $
 319,854

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

 CONSOLIDATED BALANCE SHEETS

 ASSETS

 2023
 2022

 Utility plant (at original cost, including construction work in progress of $ 1,156,265 and $ 861,801, respectively):

 Electric plant
 $
 11,304,995
 $
 10,300,895

 Natural gas plant
 4,928,725
 4,721,982

 Common plant
 1,003,519
 1,103,783

 Less: Accumulated depreciation and amortization
 ( 4,643,833)
 ( 4,341,789)

 Net utility plant
 12,593,406
 11,784,871

 Other property and investments:

 Goodwill
 1,656,513
 1,656,513

 Other property and investments
 312,353
 328,535

 Total other property and investments
 1,968,866
 1,985,048

 Current assets:

 Cash and cash equivalents
 148,548
 105,740

 Restricted cash
 66,027
 63,045

 Accounts receivable, net of allowance for doubtful accounts of $ 38,211 and $ 41,962, respectively

 546,701
 673,236

 Unbilled revenue
 243,342
 284,022

 Materials and supplies, at average cost
 173,445
 132,172

 Fuel and natural gas inventory, at average cost
 87,510
 94,075

 74,225
 587,029

 Prepaid expenses and other
 76,279
 41,940

 Power contract acquisition adjustment gain
 16,358
 16,736

 Total current assets
 1,432,435
 1,997,995

 Other long-term and regulatory assets:

 Power cost adjustment mechanism
 48,427
 112,207

 Regulatory assets related to power contracts
 6,266
 7,904

 Other regulatory assets
 1,163,551
 784,231

 35,324
 94,621

 Power contract acquisition adjustment gain
 30,566
 46,924

 Operating lease right-of-use asset
 194,321
 193,509

 Other
 259,291
 180,204

 Total other long-term and regulatory assets
 1,737,746
 1,419,600

 $
 17,732,453
 $
 17,187,514

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

 CONSOLIDATED BALANCE SHEETS

 CAPITALIZATION AND LIABILITIES

 2023
 2022

 Capitalization:

 Common shareholder's equity:

 Common stock $ 0.01 par value, 1,000 shares authorized, 200 shares outstanding

 $
 —
 $
 —

 Additional paid-in capital

 Retained earnings
 1,419,311
 1,465,331

 Accumulated other comprehensive income (loss), net of tax
 17,539
 ( 24,774)

 Total common shareholder's equity
 4,960,382
 4,964,089

 Long-term debt:

 First mortgage bonds and senior notes
 5,062,000
 4,662,000

 Pollution control bonds
 161,860
 161,860

 Long-term debt
 2,000,000
 2,034,300

 Debt discount, issuance costs and other
 ( 187,218)
 ( 194,787)

 Total long-term debt
 6,663,373

 Total capitalization
 11,997,024
 11,627,462

 Current liabilities:

 Accounts payable
 455,942
 665,750

 Short-term debt
 598,100
 441,300

 Accrued expenses:

 Taxes
 102,627
 116,098

 Salaries and wages
 68,726
 60,537

 Interest
 63,829
 62,148

 Unrealized loss on derivative instruments
 185,788
 124,976

 Power contract acquisition adjustment loss
 1,487
 1,638

 Operating lease liabilities
 21,629
 20,342

 Other
 68,590
 70,685

 Total current liabilities
 1,566,718
 1,563,474

 Other Long-term and regulatory liabilities:

 Deferred income taxes
 950,229
 985,947

 Unrealized loss on derivative instruments
 38,049
 18,366

 Purchased gas adjustment liability
 132,082
 3,536

 Regulatory liabilities
 1,022,457
 1,147,143

 Regulatory liability for deferred income taxes
 760,961
 811,161

 Regulatory liabilities related to power contracts
 46,924
 63,660

 Power contract acquisition adjustment loss
 4,779
 6,266

 Operating lease liabilities
 180,754
 181,265

 Finance lease liabilities
 99,512
 102,518

 Compliance obligation
 168,879
 —

 Other deferred credits
 764,085
 676,716

 Total long-term and regulatory liabilities
 4,168,711
 3,996,578

 Commitments and contingencies (Note 16)

 Total capitalization and liabilities
 $
 17,732,453
 $
 17,187,514

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

 CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY

 Common Stock
 Additional Paid-in Capital
 Accumulated Other Comprehensive Income (Loss)

 Shares
 Amount
 Retained Earnings
 Total Equity

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

 —
 —
 —
 —

 —
 —
 —
 ( 106,420)
 —
 ( 106,420)

 Capital contribution
 —
 —
 210,000
 —
 —
 210,000

 —
 —
 —
 —

 Balance at December 31, 2021
 $
 —
 $
 $
 1,067,216
 $
 ( 27,432)
 $
 4,563,316

 —
 —
 —
 —

 —
 —
 —
 ( 16,230)
 —
 ( 16,230)

 —
 —
 —
 —
 2,658
 2,658

 Balance at December 31, 2022
 $
 —
 $
 $
 1,465,331
 $
 ( 24,774)
 $
 4,964,089

 —
 —
 —
 —

 —
 —
 —
 ( 99,760)
 —
 ( 99,760)

 —
 —
 —
 —

 Balance at December 31, 2023
 $
 —
 $
 $
 1,419,311
 $
 17,539
 $
 4,960,382

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

 CONSOLIDATED STATEMENTS OF CASH FLOWS

 2023
 2022
 2021

 Operating Activities:

 Net Income (Loss)
 $
 $
 $

 Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 751,335
 663,232
 704,783

 Conservation amortization
 121,340
 116,942
 103,147

 Deferred income taxes and tax credits, net
 ( 94,835)
 17,941
 ( 1,228)

 Net unrealized (gain) loss on derivative instruments
 284,495
 ( 261,177)
 ( 13,785)

 AFUDC - equity
 ( 39,012)
 ( 28,310)
 ( 27,806)

 Production tax credit
 —
 —
 ( 45,562)

 Other non-cash
 9,966
 4,757
 ( 9,284)

 Funding of pension liability

 Regulatory assets and liabilities
 153,069
 ( 90,335)
 ( 126,625)

 Purchased gas adjustment
 152,763
 37,256
 29,720

 GHG emission allowances
 ( 129,195)
 —
 —

 Other long term assets and liabilities
 ( 16,714)
 ( 23,639)
 ( 24,761)

 Change in certain current assets and liabilities:

 Accounts receivable and unbilled revenue
 138,646
 ( 258,188)
 ( 96,498)

 Materials and supplies
 ( 41,273)
 ( 18,885)
 5,046

 Fuel and natural gas inventory
 6,565
 ( 34,682)
 ( 10,598)

 Prepayments and other
 ( 33,402)
 4,186
 ( 997)

 Accounts payable
 ( 244,030)
 237,260
 84,775

 Taxes payable
 ( 13,471)
 ( 11,300)
 16,646

 Other
 11,408
 18,215
 ( 3,224)

 Net cash provided by (used in) operating activities
 1,053,395
 769,618
 826,598

 Investing activities:

 Construction expenditures - excluding equity AFUDC
 ( 1,466,565)
 ( 1,004,713)
 ( 922,144)

 Other
 14,047
 ( 567)
 1,367

 Net cash provided by (used in) investing activities
 ( 1,452,518)
 ( 1,005,280)
 ( 920,777)

 Financing Activities:

 Change in short-term debt, net
 122,500
 301,300
 ( 233,800)

 Dividends paid
 ( 99,760)
 ( 16,230)
 ( 106,420)

 Investment from parent
 —
 —
 210,000

 Proceeds from long-term debt and bonds issued
 396,488
 448,075
 961,538

 Redemption of bonds and notes
 —
 ( 450,000)
 ( 502,410)

 Repayment of term loan and revolving credit
 —
 —
 ( 234,000)

 Other
 25,685
 18,152
 20,570

 Net cash provided by (used in) financing activities
 444,913
 301,297
 115,478

 Net increase (decrease) in cash, cash equivalents, and restricted cash
 45,790
 65,635
 21,299

 Cash, cash equivalents, and restricted cash at beginning of period
 168,785
 103,150
 81,851

 Cash, cash equivalents, and restricted cash at end of period
 $
 214,575
 $
 168,785
 $
 103,150

 Supplemental cash flow information:

 Cash payments for interest (net of capitalized interest)
 $
 339,677
 $
 320,656
 $
 329,894

 Cash payments (refunds) for income taxes
 71,817
 46,785
 22,647

 Non-cash financing and investing activities:

 Accounts payable for capital expenditures eliminated from cash flow
 $
 97,892
 $
 68,357
 $
 89,958

 Seller financing accrued liabilities for capital expenditures eliminated from cash flows

 21,739
 —
 —

 Recognition of finance lease eliminated from cash flows
 1,245
 105,176

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

 CONSOLIDATED STATEMENTS OF INCOME

 2023
 2022
 2021

 Operating revenue:

 $
 $
 $
 2,671,623

 Natural gas
 1,424,368
 1,067,418

 Other
 16,383
 45,080

 4,786,618
 4,216,173
 3,805,661

 Operating expenses:

 Energy costs:

 Purchased electricity
 1,110,572
 1,038,728
 784,565

 Electric generation fuel
 457,287
 348,159
 282,254

 Residential exchange
 ( 77,223)
 ( 77,715)
 ( 82,225)

 Purchased natural gas
 641,371
 500,849
 398,553

 Unrealized (gain) loss on derivative instruments, net
 284,495
 ( 261,177)
 ( 13,785)

 Utility operations and maintenance
 735,278
 665,259
 629,864

 Non-utility expense and other
 28,658
 47,194
 56,242

 744,629
 657,349
 704,372

 Conservation amortization
 121,340
 116,942
 103,147

 Taxes other than income taxes
 404,759
 388,123
 362,527

 Total operating expenses
 4,451,166
 3,423,711
 3,225,514

 Operating income (loss)
 335,452
 792,462
 580,147

 Other income (deductions):

 Other income
 64,230
 36,684
 46,523

 Other expense
 ( 14,765)
 ( 19,569)
 ( 14,467)

 Interest charges:

 AFUDC
 24,687
 18,444
 16,743

 Interest expense
 ( 285,148)
 ( 256,774)
 ( 248,624)

 Income (loss) before income taxes
 124,456
 571,247
 380,322

 Income tax (benefit) expense
 ( 6,603)
 80,295
 44,259

 $
 $
 $

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

 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 2023
 2022
 2021

 $
 $
 $

 Other comprehensive income (loss):

 Net unrealized gain (loss) from pension and postretirement plans, net of tax of $ 9,434, $ 2,580 and $ 17,925, respectively

 44,265
 9,711
 67,431

 Amortization of treasury interest rate swaps to earnings, net of tax of $ 103, $ 102 and $ 103, respectively

 44,650
 10,097
 67,815

 Comprehensive income (loss)
 $
 175,709
 $
 501,049
 $
 403,878

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

 CONSOLIDATED BALANCE SHEETS

 ASSETS

 2023
 2022

 Utility plant (at original cost, including construction work in progress of $ 1,156,265 and $ 861,801, respectively):

 Electric plant
 $
 13,043,559
 $
 12,071,531

 Natural gas plant
 5,480,496
 5,276,156

 Common plant
 1,024,319
 1,125,217

 Less: Accumulated depreciation and amortization
 ( 6,954,968)
 ( 6,688,033)

 Net utility plant
 12,593,406
 11,784,871

 Other property and investments:

 Other property and investments
 69,808
 80,076

 Total other property and investments
 69,808
 80,076

 Current assets:

 Cash and cash equivalents
 144,825
 102,840

 Restricted cash
 66,027
 63,045

 Accounts receivable, net of allowance for doubtful accounts of $ 38,211 and $ 41,962, respectively

 546,463
 671,071

 Unbilled revenue
 243,342
 284,014

 Materials and supplies, at average cost
 173,445
 132,172

 Fuel and natural gas inventory, at average cost
 85,726
 91,783

 74,225
 587,029

 Prepaid expenses and other
 76,260
 41,940

 Total current assets
 1,410,313
 1,973,894

 Other long-term and regulatory assets:

 Power cost adjustment mechanism
 48,427
 112,207

 Other regulatory assets
 1,163,551
 784,231

 35,324
 94,621

 Operating lease right-of-use asset
 194,321
 193,509

 Other
 256,617
 176,833

 Total other long-term and regulatory assets
 1,698,240
 1,361,401

 $
 15,771,767
 $
 15,200,242

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

 CONSOLIDATED BALANCE SHEETS

 CAPITALIZATION AND LIABILITIES

 2023
 2022

 Capitalization:

 Common shareholder's equity:

 Common stock $ 0.01 par value, 150,000,000 shares authorized, 85,903,791 shares outstanding

 $
 $

 Additional paid-in capital
 3,635,105
 3,535,105

 Retained earnings
 1,473,218
 1,438,163

 Accumulated other comprehensive income (loss), net of tax
 ( 58,394)
 ( 103,044)

 Total common shareholder's equity
 5,050,788
 4,871,083

 Long-term debt:

 First mortgage bonds and senior notes
 5,062,000
 4,662,000

 Pollution control bonds
 161,860
 161,860

 Debt discount, issuance costs and other
 ( 39,813)
 ( 37,095)

 Total long-term debt

 Total capitalization
 10,234,835
 9,657,848

 Current liabilities:

 Accounts payable
 457,965
 664,457

 Short-term debt
 336,600
 357,000

 Accrued expenses:

 Taxes
 102,775
 116,472

 Salaries and wages
 68,726
 60,537

 Interest
 53,834
 52,170

 Unrealized loss on derivative instruments
 185,788
 124,976

 Operating lease liabilities
 21,629
 20,342

 Other
 68,590
 70,685

 Total current liabilities
 1,295,907
 1,466,639

 Other long-term and regulatory liabilities:

 Deferred income taxes
 1,078,847
 1,139,600

 Unrealized loss on derivative instruments
 38,049
 18,366

 Purchased gas adjustment liability
 132,082
 3,536

 Regulatory liabilities
 1,021,193
 1,145,879

 Regulatory liability for deferred income taxes
 761,621
 811,724

 Operating lease liabilities
 180,754
 181,265

 Finance lease liabilities
 99,512
 102,518

 Compliance obligation
 168,879
 —

 Other deferred credits
 760,088
 672,867

 Total long-term and regulatory liabilities
 4,241,025
 4,075,755

 Commitments and contingencies (Note 16)

 Total capitalization and liabilities
 $
 15,771,767
 $
 15,200,242

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

 CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY

 Common Stock
 Additional Paid-in Capital
 Accumulated Other Comprehensive Income (Loss)

 Shares
 Amount
 Retained Earnings
 Total Equity

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

 —
 —
 —
 —

 —
 —
 —
 ( 229,857)
 —
 ( 229,857)

 —
 —
 —
 —
 67,815
 67,815

 Balance at December 31, 2021
 85,903,791
 $
 $
 3,485,105
 $
 982,607
 $
 ( 113,141)
 $
 4,355,430

 —
 —
 —
 —

 —
 —
 —
 ( 35,396)
 —
 ( 35,396)

 Capital contribution

 —
 —
 50,000
 —
 —
 50,000

 —
 —
 —
 —
 10,097
 10,097

 Balance at December 31, 2022
 85,903,791
 $
 $
 3,535,105
 $
 1,438,163
 $
 ( 103,044)
 $
 4,871,083

 —
 —
 —
 —

 —
 —
 —
 ( 96,004)
 —
 ( 96,004)

 Capital contribution

 —
 —
 —
 —

 —
 —
 —
 —
 44,650
 44,650

 Balance at December 31, 2023
 85,903,791
 $
 $
 3,635,105
 $
 1,473,218
 $
 ( 58,394)
 $
 5,050,788

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

 CONSOLIDATED STATEMENTS OF CASH FLOWS

 2023
 2022
 2021

 Operating Activities:

 Net Income (Loss)
 $
 $
 $

 Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 744,629
 657,349
 704,372

 Conservation amortization
 121,340
 116,942
 103,147

 Deferred income taxes and tax credits, net
 ( 120,394)
 ( 2,103)
 ( 8,652)

 Net unrealized (gain) loss on derivative instruments
 284,495
 ( 261,177)
 ( 13,785)

 AFUDC - equity
 ( 39,012)
 ( 28,310)
 ( 27,806)

 Production tax credit
 —
 —
 ( 45,562)

 Other non-cash
 ( 539)
 ( 6,005)
 ( 19,761)

 Funding of pension liability

 Regulatory assets and liabilities
 153,069
 ( 90,335)
 ( 126,625)

 Purchased gas adjustment
 152,763
 37,256
 29,720

 GHG emission allowances
 ( 129,195)
 —
 —

 Other long term assets and liabilities
 ( 14,247)
 ( 14,359)
 ( 14,097)

 Change in certain current assets and liabilities:

 Accounts receivable and unbilled revenue
 136,711
 ( 252,308)
 ( 96,487)

 Materials and supplies
 ( 41,273)
 ( 18,885)
 5,046

 Fuel and natural gas inventory
 6,057
 ( 33,654)
 ( 10,598)

 Prepayments and other
 ( 33,383)
 4,186
 ( 997)

 Accounts payable
 ( 240,714)
 228,635
 92,007

 Taxes payable
 ( 13,697)
 ( 16,934)
 26,152

 Other
 11,391
 24,211
 6,256

 Net cash provided by (used in) operating activities
 1,091,060
 817,461
 920,393

 Investing Activities:

 Construction expenditures - excluding equity AFUDC
 ( 1,465,925)
 ( 1,000,810)
 ( 908,273)

 Other
 14,047
 ( 567)
 1,367

 Net cash provided by (used in) investing activities
 ( 1,451,878)
 ( 1,001,377)
 ( 906,906)

 Financing Activities

 Change in short-term debt, net
 ( 20,400)
 217,000
 ( 233,800)

 Dividends paid
 ( 96,004)
 ( 35,396)
 ( 229,857)

 Investment from parent
 50,000
 —

 Proceeds from long-term debt and bonds issued
 396,488
 —
 446,063

 Redemption of bonds and notes
 —
 —
 ( 2,410)

 Other
 25,701
 21,950
 22,043

 Net cash provided by (used in) financing activities
 405,785
 253,554
 2,039

 Net increase (decrease) in cash, cash equivalents, and restricted cash
 44,967
 69,638
 15,526

 Cash, cash equivalents, and restricted cash at beginning of period
 165,885
 96,247
 80,721

 Cash, cash equivalents, and restricted cash at end of period
 $
 210,852
 $
 165,885
 $
 96,247

 Supplemental cash flow information:

 Cash payments for interest (net of capitalized interest)
 $
 253,835
 $
 233,746
 $
 223,484

 Cash payments (refunds) for income taxes
 116,795
 93,058
 38,442

 Non-cash financing and investing activities:

 Accounts payable for capital expenditures eliminated from cash flow
 $
 97,892
 $
 68,357
 $
 89,958

 Seller financing accrued liabilities for capital expenditures eliminated from cash flows

 21,739
 —
 —

 Recognition of finance lease eliminated from cash flows
 1,245
 105,176

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

 COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 (1) Summary of Significant Accounting Policies

 Basis of Presentation
 Puget Energy 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 and operating 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.

 Segment Information
 Puget Energy and PSE operate one reportable segment referred to as the regulated utility segment. Puget Energy's regulated utility operation generates, purchases and sells electricity and purchases, transports and sells natural gas.

 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.

 Construction Work in Progress
 Construction work in progress represents construction materials, progress payments on major equipment contracts, engineering costs, AFUDC and other costs directly associated with construction projects. Such costs classified as construction work in progress are included within utility plant on the balance sheet. At completion of such projects, these costs are transferred to utility plant in service. Capitalized costs associated with construction activities are charged to operations and maintenance expenses when recoverability is no longer probable.

 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 %, 3.4 %, and 3.4 % in 2023, 2022, and 2021, respectively; depreciable natural gas utility plant was 3.2 %, 2.9 %, and 2.8 % in 2023, 2022, and 2021, respectively; and depreciable common utility plant was 6.5 %, 7.1 % and 6.8 % in 2023, 2022, and 2021, respectively. The cost of removal is collected from PSE's customers through depreciation expense and any excess is recorded as a regulatory liability.

 Related Party Transactions
 The Company identified no material related party transactions during the years ended December 31, 2023, December 31, 2022 and December 31, 2021.

 Tacoma LNG Facility
 In February 2022, the Tacoma LNG facility at the Port of Tacoma completed commissioning and commenced commercial 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. The Tacoma LNG facility provides peak-shaving services to PSE's natural gas customers, and 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, $ 240.5 million and $ 249.1 million of non-utility plant 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, 2023, and December 31, 2022, respectively. Additionally, $ 27.5 million, $ 11.6 million, and $ 1.3 million of operating costs are reported in the Puget Energy "Non-utility expense and other" financial statement line item in 2023, 2022, and 2021, respectively. Further, $ 235.6 million and $ 241.1 million of plant in service 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, 2023, and December 31, 2022, 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 fuel inventory and natural gas inventory for unregulated operations at the lower of cost or net realizable value 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.

 Greenhouse Gas Emission Allowances
 PSE is required to obtain emission allowances or offset credits for greenhouse gas (GHG) emissions associated with electricity it generates or imports into Washington and natural gas supplied to customers in accordance with the cap-and-invest program included in the Climate Commitment Act (CCA). PSE records allocated and purchased emission allowances at cost, similar to an inventory method, and includes purchased emissions allowances in current assets and long-term assets reported in the "GHG emission allowances" line item on the consolidated balance sheets. PSE measures the compliance obligation at the weighted average cost of allowances held plus the fair value of additional allowances required to satisfy the obligation after adjustment for applicable no-cost allowances received. PSE includes the obligation in current liabilities and long-term liabilities reported in the "Compliance obligations" line item on the consolidated balance sheets based on the dates the allowances are to be surrendered. Consistent with ASC 980, PSE defers costs and revenues associated with the cap-and-invest program through regulatory assets and liabilities.

 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 Washington Commission authorized an AFUDC rate, calculated using its allowed rate of return for utility plant additions. The AFUDC rate authorized was 7.39 % effective October 1, 2020 for natural gas and October 15, 2020 for electric. Per the 2022 GRC, the AFUDC rate authorized is 7.16 % effective January 7, 2023 for natural gas and January 11, 2023 for electric.
 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 excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $ 319.1 million, $ 292.8 million and $ 268.5 million for 2023, 2022, and 2021, 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
 The Company 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, 2023, and 2022:

 Allowance for credit losses:
 2023
 2022

 Beginning balance
 $
 41,962
 $
 34,958

 Provision for credit loss expense1

 34,724
 28,316

 Receivables charged-off
 ( 38,475)
 ( 21,312)

 Total ending allowance balance
 $
 38,211
 $
 41,962

 _____________
 1 $ 17.1 million and $ 7.1 million of provision related to balances of deferred costs specific to COVID-19 as of December 31, 2023 and 2022, 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 the storm loss deferral mechanism is $ 10.0 million. Additionally, costs may only be deferred if the outage meets the Institute of Electrical and Electronics Engineers 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. There was no PTC monetized in the tax years ended December 31, 2023 and 2022. For the tax year ended December 31, 2021, $ 45.6 million of PTCs were monetized through tax 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 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 land 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
 In April 2017, PSE entered into a power purchase agreement (PPA) with Skookumchuck Wind Energy Project, LLC (Skookumchuck) pursuant to which Skookumchuck would develop a wind generation facility and sell bundled energy and associated attributes, namely renewable energy certificates (RECs), to PSE over a term of 20 years. Skookumchuck commenced commercial operation in November 2020. In May 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 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. In February 2021, PSE entered into a PPA with Clearwater Wind Project, LLC (Clearwater) in which Clearwater would develop a wind generation facility and sell energy and associated attributes to PSE over a term of 25 years. On November 8, 2022, Clearwater commenced commercial operations. For each of the aforementioned PPAs, PSE has no equity investment in the generation facilities, but is the only customer of each facility. PSE has concluded that Skookumchuck, Golden Hills, and Clearwater represent variable interest entities (VIE) and that PSE is not the primary beneficiary of these VIEs since it does not control the commercial and operating activities of the facilities. Additionally, PSE does not have the obligation to absorb losses or receive benefits. As a result, PSE does not consolidate the VIEs.
 Purchased energy of $ 86.0 million and $ 38.6 million were recognized in purchased electricity on the Company's consolidated statements of income for the year ended December 31, 2023 and December 31, 2022, respectively. Additionally, $ 14.6 million and $ 3.9 million were included in accounts payable on the Company's balance sheet as of December 31, 2023 and December 31, 2022, respectively.

 (2) New Accounting Pronouncements

 Recently Adopted Accounting Guidance
 Reference Rate Reform
 In March 2020, the FASB issued Accounting Standards Updated (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. As of December 31, 2023, the Company is not aware of any current agreements that reference LIBOR and thus, has not utilized any practical expedients. The Company continues to monitor whether any new agreements are entered into which reference LIBOR and if the expedients would be utilized through the allowed period of December 31, 2024.

 Accounting Standards Issued but Not Yet Adopted
 Reportable Segment Disclosures
 In November 2023, the FASB issued ASU 2023-07, "Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures". ASU 2023-07 is intended to improve the disclosures for reportable segments and provide more detailed information about a reportable segment's expenses. This will require disclosure of significant segment expense categories, amounts for each reportable segment, disclosure of the title and position of the Chief Operating Decision Maker and how they use the measure of the segments profit or loss to assess performance and allocate resources. ASU 2023-07 will be effective for the Company in fiscal years beginning after December 15, 2023, and interim periods in fiscal years beginning after December 15, 2024. As the amendment contemplates changes in disclosures only, it is not expected to have a material impact on the Company's results of operations, cash flows, or consolidated balance sheets; however, the Company continues to assess the impacts of the amendment.

 Income Tax Disclosures
 In December 2023, the FASB issued ASU 2023-09, "Income Taxes (Topic 740): Improvements to Income Tax Disclosures". ASU 2023-09 will require disclosure of specific categories in a tabular rate reconciliation using both percentages and currency amounts, and provide additional information for reconciling items that meet a quantitative threshold. Further requirements include a qualitative description of the tax jurisdictions, an explanation of the reconciling items disclosed and disclosure regarding income taxes paid. ASU 2023-09 will eliminate the requirement to disclose the nature and estimate of range in unrecognized tax benefits and disclosures of the cumulative amount of each type of temporary difference when a deferred tax liability is not recognized. ASU 2023-09 will be effective for the Company in annual periods beginning after December 15, 2024. As the amendment contemplates changes in disclosures only, it is not expected to have a material impact on the Company's results of operations, cash flows, or consolidated balance sheets; however, the Company continues to assess the impacts of the amendment.

 (3) Revenue

 The following tables present disaggregated revenue from contracts with customers, and other revenue by major source for the years ended December 31, 2023, December 31, 2022, and December 31, 2021:

 Year Ended December 31, 2023

 Revenue from contracts with customers:
 Other1

 Total

 Retail

 $
 1,514,149
 $
 851,906
 $
 —
 $
 2,366,055

 1,071,385
 383,431
 —
 1,454,816

 123,548
 29,149
 —
 152,697

 Other
 21,199
 —
 —
 21,199

 Wholesale
 498,251
 —
 —
 498,251

 Transmission and transportation
 46,141
 24,265
 —
 70,406

 Miscellaneous2

 25,231
 94,193
 47,431
 166,855

 Total revenue from contracts with customers
 $
 3,299,904
 $
 1,382,944
 $
 47,431
 $
 4,730,279

 Total other revenue3

 45,963
 40,332
 —
 86,295

 $
 $
 1,423,276
 $
 47,431
 $
 4,816,574

 _____________
 1. Other includes $ 31.0 million of Puget LNG revenues recorded at Puget Energy.
 2. Miscellaneous natural gas revenue includes $ 98.4 million for the regulatory offset of CCA auction proceeds passed back to customers.
 3. Total other revenue includes revenues from derivatives and alternative revenue programs that are not considered revenues from contracts with customers.

 Year Ended December 31, 2022

 Revenue from contracts with customers:
 Other1

 Total

 Retail

 $
 1,381,858
 $
 808,376
 $
 —
 $
 2,190,234

 981,170
 352,243
 —
 1,333,413

 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
 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

 $
 $
 $
 50,069
 $
 4,221,162

 _____________
 1. Other 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.

 Year Ended December 31, 2021

 Revenue from contracts with customers:
 Other
 Total

 Retail

 $
 1,318,326
 $
 722,003
 $
 —
 $
 2,040,329

 902,928
 292,275
 —
 1,195,203

 108,267
 21,741
 —
 130,008

 Other
 18,834
 —
 19,226

 Wholesale
 161,152
 —
 —
 161,152

 Transmission and transportation
 43,753
 20,030
 —
 63,783

 Miscellaneous
 47,948
 9,863
 124,431

 Total revenue from contracts with customers
 $
 2,601,208
 $
 1,066,304
 $
 $
 3,734,132

 Total other revenue1

 70,415
 1,114
 —
 71,529

 $
 2,671,623
 $
 1,067,418
 $
 $
 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.

 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:

 2024
 2025
 2026
 2027
 2028
 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, 2023, and 2022, are included in the following tables:

 Remaining Amortization Period

 2023
 2022

 Climate Commitment Act recovery

 N/A
 $
 186,550
 $
 —

 Environmental remediation
 (a)
 182,697
 141,893

 Automated meter reading

 20 years
 104,159
 —

 Storm damage costs electric
 3 to 5 years

 95,754
 127,524

 PGA unrealized loss

 N/A

 80,376
 —

 Deferred Washington Commission AFUDC
 30 years
 58,648
 61,463

 Baker Dam licensing operating and maintenance costs
 (b)
 55,641
 55,049

 Chelan PUD contract initiation
 7.8 years
 55,523
 62,611

 PCA mechanism
 N/A
 48,427
 112,207

 Lower Snake River
 13.4 years
 43,220
 48,536

 Washington Commission LNG
 N/A
 42,247
 28,335

 Energy conservation costs
 (a)
 37,560
 10,296

 Unamortized loss on reacquired debt
 1 to 44 years

 31,626
 33,732

 Decoupling deferrals and interest

 Less than 2 years

 31,398
 36,773

 Get to zero depreciation expense deferral (c)
 1 to 3 years

 29,185
 49,605

 Colstrip tracker expenditures

 N/A

 26,253
 —

 Washington Commission COVID-19
 N/A
 17,097
 7,051

 Generation plant major maintenance, excluding Colstrip
 2 to 9 years

 16,941
 20,374

 Regulatory filing fee deferral
 N/A
 14,582
 7,559

 Advanced metering infrastructure
 N/A

 12,094
 30,431

 Snoqualmie licensing operating and maintenance costs
 (b)
 7,428
 7,445

 Washington Commission electric vehicle (c)
 3 years
 5,755
 7,796

 Water heater rental property loss
 3 years
 3,847
 5,725

 Colstrip major maintenance (c)
 2 years
 2,690
 4,035

 Mint Farm ownership and operating costs
 1.3 years
 2,317
 4,317

 Property tax tracker
 Less than 2 years

 —
 12,398

 Various other regulatory assets
 (a)
 19,963
 21,283

 Total PSE regulatory assets
 $
 1,211,978
 $
 896,438

 Deferred income taxes (d)

 N/A
 $
 ( 761,621)
 $
 ( 811,724)

 Cost of removal
 (e)

 ( 682,058)
 ( 639,320)

 PGA liability
 2 years
 ( 132,082)
 ( 3,536)

 Repurposed production tax credits
 N/A
 ( 126,482)
 ( 133,855)

 Climate Commitment Act auction proceeds

 N/A

 ( 84,485)
 —

 Decoupling liability
 Less than 2 years

 ( 60,664)
 ( 63,206)

 Colstrip tracker recovery

 N/A

 ( 31,390)
 —

 Property tax tracker
 Less than 2 years

 ( 11,135)
 —

 Green direct
 N/A
 ( 10,442)
 ( 11,837)

 Bill discount rate deferral

 N/A

 ( 6,579)
 —

 PGA unrealized gain
 N/A
 —
 ( 287,725)

 Various other regulatory liabilities
 (a)
 ( 7,958)
 ( 9,936)

 Total PSE regulatory liabilities
 $
 ( 1,914,896)
 $
 ( 1,961,139)

 PSE net regulatory assets (liabilities)
 $
 ( 702,918)
 $
 ( 1,064,701)

 __________________
 (a)Amortization periods vary depending on the timing of underlying transactions.
 (b)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.
 (c)Amortization period approved in 2022 GRC, beginning January 2023.
 (d)For additional information, see Note 14,"Income Taxes" to the consolidated financial statements included in Item 8 of this report.
 (e)The balance is dependent upon the cost of removal of underlying assets and the life of utility plant.
.

 Remaining Amortization Period

 2023
 2022

 Total PSE regulatory assets
 (a)
 $
 1,211,978
 $
 896,438

 Puget Energy acquisition adjustments:

 Regulatory assets related to power contracts
 3 to 30 years

 6,266
 7,904

 Total Puget Energy regulatory assets
 $
 1,218,244
 $
 904,342

 Total PSE regulatory liabilities
 (a)
 $
 ( 1,914,896)
 $
 ( 1,961,139)

 Puget Energy acquisition adjustments:

 Deferred income taxes

 Regulatory liabilities related to power contracts
 3 to 30 years

 ( 46,924)
 ( 63,660)

 Various other regulatory liabilities
 Varies
 ( 1,264)
 ( 1,264)

 Total Puget Energy regulatory liabilities
 $
 ( 1,962,424)
 $
 ( 2,025,500)

 Puget Energy net regulatory asset (liabilities)
 $
 ( 744,180)
 $
 ( 1,121,158)

 ____________________
 (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 $ 682.1 million and $ 639.3 million in 2023 and 2022, 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 GRC which includes a two year multiyear rate plan (MYRP) with the Washington Commission on February 15, 2024, requesting an overall increase in electric and natural gas rates of 6.7 % and 19.0 % respectively in rate year one (expected to approximate calendar year 2025) and 8.5 % and 2.1 %, respectively in rate year two (expected to approximate calendar year 2026). PSE requested a return on equity of 9.95 % for the first rate year beginning in 2025 and 10.5 % for the second rate year beginning in 2026. PSE requested an overall rate of return of 7.65 % in rate year one and 7.99 % in rate year two. The filing requests recovery of forecasted plant additions through 2024 as required by RCW 80.28.425 as well as forecasted plant additions through 2026, the final year of the MYRP. The next phase of the filing will be to establish a procedural calendar for the adjudication of the case. The Company estimates the agreed upon rates from this proceeding will become effective by statute approximately 11 months after filings.
 On December 22, 2022, the Washington Commission issued an order on PSE's 2022 general rate case (GRC), which was filed on January 31, 2022, that approved a weighted cost of capital of 7.16 %, or 6.62 % after-tax, a capital structure of 49.0 % in common equity in 2023 and 2024, and a return on equity of 9.4 %. On January 6, 2023, the Washington Commission approved PSE's natural gas rates in its compliance filing with an overall net revenue change of $ 70.8 million or 6.4 % in 2023 and $ 19.5 million or 1.7 % 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 with an overall net revenue change of $ 247.0 million or 10.8 % in 2023 and $ 33.1 million or 1.3 % in 2024 with an effective date of January 11, 2023. Per the 2022 GRC Final Order in Docket No. UE-220066, rates approved in PSE's power cost only rate case (PCORC) in Docket No. UE-200980 were set to zero as of January 11, 2023, and PSE agreed not to file a PCORC during 2023 and 2024, the period covered by the two -year rate plan agreed to in the GRC settlement.
 Prior rates were subject to the 2019 GRC and included 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 annualized overall rate impacts were an electric revenue increase of $ 48.3 million, or 2.3 %, and a natural gas increase of $ 4.9 million, or 0.6 %, effective October 1, 2021. For further information, see Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of the Company's Form 10-K for the period ended December 31, 2022.

 Climate Commitment Act Deferral
 On December 29, 2022, PSE filed accounting petitions with the Washington Commission requesting authorization to defer costs and revenues associated with the Company's compliance with the Climate Commitment Act (CCA) codified in law within Revised Code of Washington (RCW) 70A.65. On February 28, 2023, in Order 01 under Docket No. UE-220974 and UG-220975, the Washington Commission granted PSE approval to defer the cost of emission allowances to comply with the CCA and the proceeds from no-cost allowances consigned to auction beginning January 1, 2023. On August 3, 2023, the Washington Commission approved PSE's request for CCA rates in Docket No. UG-230470, subject to refund, effective October 1, 2023, to recover the estimated ongoing allowance costs and proportionate pass back of credits to customers from estimated auction proceeds during the period of August 2023 through December 2023. On October 26, 2023, the Washington Commission approved PSE's request for CCA rates in Docket No. UG-230756, subject to refund, effective November 1, 2023, to recover the estimated ongoing allowance costs and proportionate pass back of credit to customers from estimated auction proceeds during the period of January 2023 through September 2023. The recovery of ongoing allowance costs and pass back of credits is consistent with the approved accounting petitions in Dockets No. UG-220975 and UG-230471. As of December 31, 2023, PSE deferred $ 184.4 million of CCA compliance costs for natural gas and electric liabilities. Additionally, PSE will consign for auction at least the minimum amount of no-cost emission allowances allocated for natural gas operations in compliance with the CCA, the proceeds of which will be used for the benefit of natural gas customers, as determined by the Washington Commission. PSE will not record a regulatory liability to defer the proceeds until consigned allowances are sold at auction. As of December 31, 2023, PSE recorded $ 83.0 million related to the proceeds from the sale of consigned GHG emission allowances.
 In October 2022, the Washington Department of Ecology (WDOE) published final regulations to implement the cap and invest program. The WDOE also indicated that it will have subsequent rulemakings building off initial rulemaking as program implementation is underway and progress with Washington State carbon goals are evaluated. One component of the CCA rules stipulates the WDOE shall provide qualifying electric utilities, such as PSE, with no-cost allowances based on the cost burden of the program to electric customers, which is derived using a forecast of emissions. An additional component of the CCA rules stipulates that the allocation of no-cost allowances may be adjusted once a year under a "true-up mechanism" which takes into account the cumulative total of no-cost allowances issued to an electric utility relative to the electric utility's reported GHG emissions. Such adjustments will be made in the fourth quarter of the following year, at which time WDOE could add allowances to an electric utility's account if such account has an allowance deficit, or withhold future allocated allowances going forward if such account had previously allocated excess allowances. WDOE has not provided further guidance or rules specifying how such adjustments will be determined. As a result, the Company cannot predict the impact of such adjustments.
 WDOE provided an initial allocation of no-cost allowances to electric utilities on April 24, 2023. However, qualifying electric utilities were allowed to submit revised emissions forecasts approved by the Washington Commission to WDOE by July 30, 2023. PSE filed its revised forecast of 2023 emission under Docket No. UE 220797, which was approved by the Washington Commission on July 27, 2023, and approved by the WDOE on September 27, 2023. Accordingly, the Company's compliance obligation as of December 31, 2023, reflects the revised allowance allocation.
 Following the September 27, 2023 WDOE decision, PSE's no-cost allowance allocation will be set for 2023 until the fourth quarter of 2024 when there is an opportunity to request a "true-up" of no-cost allowances under the aforementioned adjustment mechanism. However, as of December 31, 2023, due to the uncertainty around implementation of the adjustment mechanism PSE did not adjust the CCA electric compliance obligation anticipating an adjustment to no cost allowances to reported 2023 electric GHG emissions and does not plan to make such adjustment until a formal true-up allocation has been granted by the WDOE.

 Revenue Decoupling Adjustment Mechanism
 In June 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 and took effect on July 1, 2021.
 In September 2021, the Washington Commission approved the 2019 GRC filing. As part of this filing, the annual electric and natural 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 natural 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, 2023, 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. Based on the analyses in 2023 and 2022, no reserve adjustment was recorded as of December 31, 2023 and 2022.

 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 up to $17 million

 %
 %
 —
 %
 —
 %

 Over or under collected between $17 million - $40 million

 Over or under collected beyond $40 million

 For the year ended December 31, 2023, in its PCA mechanism, PSE over recovered its allowable costs by $ 51.1 million of which $ 24.9 million was apportioned to customers and $ 3.9 million of interest was accrued on the deferred customer balance. This compares to an under recovery of allowable costs of $ 110.1 million, for the year ended December 31, 2022, of which $ 74.6 million was apportioned to customers and accrued $ 1.5 million of interest on the total deferred customer balance.

 Power Cost Adjustment Clause
 PSE exceeded the $ 20.0 million cumulative deferral balance in its PCA mechanism in 2022. During 2022, actual power costs were higher than baseline power costs, thereby, creating an under-recovery of $ 110.1 million. Under the terms of the PCA's sharing mechanism for under-recovered power costs, PSE absorbed $ 39.0 million of the under-recovered amount, and customers were responsible for the remaining $ 71.1 million, or $ 76.4 million, including interest and adjusted for revenue sensitive items. On April 28, 2023, PSE filed the 2022 PCA report under Docket No. UE-230313 that proposed a recovery of the deferred balance, which included a revenue requirement increase of 0.9 % in overall bill for all customers, with rates proposed to go into effect from December 1, 2023 through December 31, 2024.
 PSE also exceeded the $ 20.0 million cumulative deferral balance in its PCA mechanism in 2021, as actual power costs were higher than baseline power costs, thereby creating an under-recovery of $ 68.0 million. 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. In October 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.
 On September 29, 2023, PSE filed its variable power cost rates update as part of the 2022 GRC Order requirement under Docket No. UE-220066. The filing was approved in part on December 22, 2023, with updated rates effective January 1, 2024.

 Purchased Gas Adjustment Mechanism
 In October 2021, the Washington Commission approved PSE's request for 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 were set in addition to continuing the collection on the remaining balance of $ 69.4 million under Supplemental Schedule 106B, which were set, in effect, through September 30, 2023, per the 2019 GRC.
 In October 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.

 In November 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.
 On October 26, 2023, the Washington Commission approved PSE's request for PGA rates in Docket No. UG-230769, effective November 1, 2023. As part of that filing, PSE requested an annual revenue decrease of $ 309.4 million, where PGA rates, under Schedule 101, decrease annual revenue by $ 93.9 million, and the tracker rates under Schedule 106, decrease annual revenue by $ 215.5 million. The annual 2023 PGA rate decreases include the aforementioned counterparty settlement pass back of $ 28.1 million under Supplemental Schedule 106B.
 The following table presents the PGA mechanism balances and activity at December 31, 2023 and December 31, 2022:

 PGA receivable balance and activity
 2023
 2022

 PGA receivable beginning balance
 $
 ( 3,536)
 $
 57,935

 Actual natural gas costs
 404,897
 457,950

 Allowed PGA recovery
 ( 521,882)
 ( 496,879)

 Interest
 ( 7,639)
 1,674

 Refund from counterparty settlement
 ( 3,922)
 ( 24,216)

 PGA (liability)/receivable ending balance
 $
 ( 132,082)
 $
 ( 3,536)

 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, 2023, PSE incurred $ 8.1 million in weather-related electric transmission and distribution system restoration costs, of which the Company deferred zero and $ 2.1 million as regulatory assets related to storms that occurred in 2023 and 2022, respectively. This compares to $ 32.2 million incurred in weather-related electric transmission and distribution system restoration costs for the year ended December 31, 2022, 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. 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 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 WDOE and/or other third parties as potentially responsible or liable at several contaminated sites, including 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. The adjustments recorded are based on the best estimate or the low end of a range of reasonably possible costs expected to be incurred by the Company based on its currently understood legal exposure at applicable sites. It is reasonably possible that incurred costs exceed the recorded amounts due to changes in laws and/or regulations, higher than expected costs due to changes in labor market or supply chain, evolving technology, unforeseen and/or the discovery of new or additional contamination. The Company currently estimates that a significant portion of its past and future environmental remediation costs are recoverable from insurance companies, from third parties, and/or from customers under a Washington Commission order. The Company is subject to cost-sharing agreements with third parties regarding environmental remediation projects in Seattle, Tacoma, Everett, and Bellingham, Washington. As of December 31, 2023, the Company's share of future remediation costs is estimated to be approximately $ 72.9 million.

 The following table summarizes changes in the Company's environmental remediation regulatory assets for the years ended December 31, 2023, and 2022:

 2023
 2022

 Environmental remediation regulatory asset beginning balance

 $
 141,893
 $
 127,977

 Remediation cost amortization, net of recoveries

 ( 4,521)
 ( 1,226)

 Changes in estimates1

 45,325
 15,142

 Environmental remediation regulatory asset ending balance

 $
 182,697
 $
 141,893

 1. Driven in significant part by the Quendall Terminals site on Lake Washington in Renton, Washington. The site represents contaminated facilities from a long defunct creosote manufacturer which had purchased waste products from PSE predecessors. In addition, it was driven by an increase in estimate at the shared site of Gas Works Park on Lake Union in Seattle, Washington, which was previously a gas manufacturing plant.

 The following table summarizes changes in the Company's environmental remediation liabilities for the years ended December 31, 2023, and 2022:

 2023
 2022

 Environmental remediation liabilities beginning balance

 $
 135,052
 $
 119,929

 Payments made, net of recoveries

 ( 495)
 ( 1,343)

 Changes in estimates1

 45,883
 16,466

 Environmental remediation liabilities ending balance

 $
 180,440
 $
 135,052

 1. Driven in significant part by the Quendall Terminals site on Lake Washington in Renton, Washington. The site represents contaminated facilities from a long defunct creosote manufacturer which had purchased waste products from PSE predecessors. In addition, it was driven by an increase in estimate at the shared site of Gas Works Park on Lake Union in Seattle, Washington, which was previously a gas manufacturing plant.

 (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, 2023, approximately $ 1.7 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 48.1 % at December 31, 2023, and the EBITDA to interest expense was 5.2 to 1.0 for the twelve months ended December 31, 2023.
 PSE's ability to pay dividends is also limited by the terms of its credit facilities, pursuant to which PSE is not permitted to pay dividends during any Event of Default (as defined in the facilities), or if the payment of dividends would result in an Event of Default, such as failure to comply with certain financial covenants.
 Puget Energy's ability to pay dividends is also limited by the merger order issued by the Washington Commission. Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy's ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to

 such date is equal to or greater than 2.0 to 1.0. Puget Energy's EBITDA to interest expense was 3.9 to 1.0 for the twelve months ended December 31, 2023.
 At December 31, 2023, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

 (6) Utility Plant

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

 Utility Plant
 Estimated Useful Life1

 (Years)
 2023
 2022
 2023
 2022

 Distribution plant
 7 - 65

 $
 8,298,893
 $
 7,886,665
 $
 9,804,018
 $
 9,406,017

 Production plant
 3 - 90

 3,173,514
 3,131,578
 3,805,294
 3,780,910

 Transmission plant
 44 - 75

 1,595,566
 1,576,916
 1,701,878
 1,683,737

 General plant
 5 - 75

 717,017
 735,298
 738,996
 760,094

 Intangible plant (including capitalized software)2

 3 - 50

 586,749
 755,430
 577,291
 745,973

 Plant acquisition adjustment
 N/A
 242,826
 242,826
 282,792
 282,792

 Underground storage
 25 - 60

 46,761
 45,305
 60,171
 58,716

 Liquefied natural gas storage
 25 - 50

 224,337
 12,628
 226,208
 14,498

 Plant held for future use
 N/A
 59,409
 46,079
 59,561
 46,232

 Recoverable cushion gas

 N/A
 8,784
 8,784
 8,784
 8,784

 Plant not classified
 N/A
 1,032,004
 723,383
 1,032,002
 723,383

 Finance leases, net of accumulated amortization3

 N/A
 95,114
 99,967
 95,114
 99,967

 Less: accumulated provision for depreciation
 ( 4,643,833)
 ( 4,341,789)
 ( 6,954,968)
 ( 6,688,033)

 Subtotal
 $
 11,437,141
 $
 10,923,070
 $
 11,437,141
 $
 10,923,070

 Construction work in progress
 1,156,265
 861,801
 1,156,265
 861,801

 Net utility plant
 $
 12,593,406
 $
 11,784,871
 $
 12,593,406
 $
 11,784,871

 _______________________
 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.
 3.At December 31, 2023, and 2022, accumulated amortization of finance leases at Puget Energy and PSE was $ 13.2 million and $ 7.3 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, 2023. These amounts are also included in the Utility Plant table 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.

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

 Colstrip Units 3 & 4
 Coal
 25.00 %
 $
 323,435
 $
 —
 $
 ( 207,709)

 Frederickson 1
 49.85
 68,006
 —
 ( 27,144)

 Jackson Prairie
 33.34
 46,171
 2,100
 ( 13,986)

 Tacoma LNG
 various
 497,413
 2,747
 ( 24,026)

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

 Colstrip Units 3 & 4
 Coal
 25.00 %
 $
 580,451
 $
 —
 $
 ( 464,725)

 Frederickson 1
 49.85
 73,658
 —
 ( 32,795)

 Jackson Prairie
 33.34
 60,171
 2,100
 ( 27,986)

 Tacoma LNG
 various
 247,073
 ( 11,600)

 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 and abandonment accounting criteria were not met as of December 31, 2023. As such, Colstrip Units 3 and 4 are classified as Electric Utility Plant on the Company's balance sheet as of December 31, 2023.

 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.
 For the twelve months ended December 31, 2023 and 2022, the Company reviewed the estimated remediation costs at Colstrip and determined no change was warranted for the Colstrip ARO liability for Colstrip Units 1 and 2 and Colstrip Units 3 and 4. For the twelve months ended December 31, 2023 and 2022, the Company recorded relief of ARO and environmental remediation liability of $ 6.0 million and $ 6.9 million, respectively.
 In addition, the Company recorded Tacoma LNG facility ARO liability of $ 4.1 million and $ 3.9 million for PSE and $ 4.0 million and $ 3.8 million for Puget LNG as of December 31, 2023 and December 31, 2022, respectively. In 2023, the ARO liability associated with the Tacoma LNG facility was fully recorded as construction was completed.

 Puget Energy and Puget Sound Energy

 2023
 2022

 Asset retirement obligation at beginning of the period
 $
 209,406
 $
 209,041

 Relief of liability
 ( 5,998)
 ( 6,867)

 Revisions in estimated cash flows
 ( 2,206)
 1,519

 Accretion expense
 5,832
 5,713

 Asset retirement obligation at end of period1

 $
 207,034
 $
 209,406

 ___________________
 1.Asset retirement obligations include $ 4.0 million and $ 3.8 million for Puget LNG held only at Puget Energy as of December 31, 2023, and 2022, 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, 2023:

 • 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.

 Beaver Creek Wind Project
 Beaver Creek is a utility-scale wind project located in Stillwater County, Montana, with an expected nameplate capacity of 248 MW that is expected to commence commercial operations in 2025. On September 15, 2023, PSE executed a membership interest purchase agreement with Caithness Beaver Creek, LLC for a 100% ownership interest in Caithness Montana Wind, LLC, which closed on December 1, 2023. Total consideration is expected to be $ 44.6 million of which $ 23.8 million has been paid as of December 31, 2023 and the remaining balance is expected to be paid in the first quarter of 2025. On December 1, 2023, PSE entered into a turbine supply agreement with GE Renewables North America, LLC to purchase 88 wind turbines. Total consideration is expected to be $ 266.9 million of which $ 213.5 million has been paid as of December 31, 2023 and the remaining balance is expected to paid throughout 2024 and the first quarter of 2025 as turbines are delivered and the project is completed. As of December 31, 2023, $ 283.9 million was recorded to construction work in progress in conjunction with the Beaver Creek wind project.
 On January 26, 2024, PSE entered into a balance of plant agreement to complete the design and construction of the project. Total consideration is expected to be approximately $ 129.4 million.

 (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 at December 31, 2023 and 2022:

 Series
 Type
 Due
 2023
 2022

 Puget Sound Energy:

 7.150 %
 First Mortgage Bond
 2025
 $
 15,000
 $
 15,000

 7.200 %
 First Mortgage Bond
 2025
 2,000
 2,000

 7.020 %
 2027

 7.000 %
 2029

 3.900 %
 Pollution Control Bond
 2031
 138,460
 138,460

 4.000 %
 Pollution Control Bond
 2031
 23,400
 23,400

 5.483 %
 2035

 6.724 %
 2036

 6.274 %
 2037

 5.757 %
 2039
 350,000
 350,000

 5.795 %
 2040
 325,000
 325,000

 5.764 %
 2040

 4.434 %
 2041

 5.638 %
 2041

 4.300 %
 2045
 425,000
 425,000

 4.223 %
 2048

 3.250 %
 2049

 2.893 %
 2051

 4.700 %
 2051
 45,000
 45,000

 5.448 %
 2053
 400,000
 —

 *
 Debt discount, issuance cost and other
 *
 ( 39,813)
 ( 37,095)

 Total PSE long-term debt
 $
 $

 Puget Energy:

 *
 Fair value adjustment of PSE long-term debt
 *
 $
 ( 139,834)
 $
 ( 148,341)

 *
 Revolving Credit Agreement
 2027
 —
 34,300

 3.650 %
 2025
 400,000
 400,000

 2.379 %
 2028
 500,000
 500,000

 4.100 %
 2030
 650,000
 650,000

 4.224 %
 2032

 *
 Debt discount, issuance cost and other
 *
 ( 7,571)
 ( 9,351)

 Total Puget Energy long-term debt
 $
 $
 6,663,373

 ___________________
 * Not Applicable.

 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, 2023, 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.

 Puget Energy Long-Term Debt
 On March 10, 2022, Puget Energy filed an S-3 shelf 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.
 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.

 Puget Sound Energy Long-Term Debt
 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, $ 1.0 billion was available to be issued. The shelf registration will expire in August 2025.
 On May 18, 2023, PSE issued $ 400.0 million of green senior secured notes at an interest rate of 5.448 %. The notes mature on June 1, 2053 and pay interest semi-annually in arrears on June 1 and December 1 of each year, commencing December 1, 2023. Net proceeds from the issuance of the notes were deposited into the Company's general account and are intended to be used for allocation to eligible projects, as defined in PSE's sustainable financing framework, which was published in May 2023. Eligible projects are expenditures incurred and investments made related to development and acquisition of some or all of the following types of projects: (i) renewable energy, (ii) energy efficiency, (iii) clean transportation, (iv) biodiversity conservation, (v) climate change adaptation, (vi) water and wastewater management, (vii) pollution prevention and control, and (viii) green innovation.

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

 2024
 2025
 2026
 2027
 2028
 Total

 Maturities of:

 PSE
 $
 —
 $
 17,000
 $
 —
 $
 $
 —
 $
 4,906,860
 $
 5,223,860

 —
 400,000
 —
 —
 500,000
 1,100,000
 2,000,000

 Total long-term debt
 $
 —
 $
 417,000
 $
 —
 $
 $
 500,000
 $
 6,006,860
 $
 7,223,860

 (8) Liquidity Facilities and Other Financing Arrangements

 As of December 31, 2023, and 2022, PSE had $ 336.6 million and $ 357.0 million in short-term debt outstanding, respectively. Outside of the consolidation of PSE's short-term debt, Puget Energy had $ 261.5 million and $ 84.3 million, in short-term debt, drawn and outstanding under its credit facility as of December 31, 2023, and 2022, respectively. PSE's weighted-average interest rate on short-term debt, including borrowing rate, commitment fees and the amortization of debt issuance costs, during 2023 and 2022 was 9.0 % and 6.1 %, respectively. As of December 31, 2023, PSE and Puget Energy had several committed credit facilities that are described below.

 Credit Facility
 In May 2022, PSE entered into a new $ 800.0 million credit facility to replace the existing facility. The terms and conditions, including fees, financial covenant, expansion feature and 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) was discontinued on June 30, 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 and has an expansion feature which, upon receipt of commitments from one or more lenders, could increase the total size of the facility up to $ 1.4 billion.

 The credit agreement is syndicated among numerous lenders and contains usual and customary affirmative and negative covenants that, among other things, place limitations on PSE's ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit agreement also contains a leverage ratio that requires the ratio of (a) total funded indebtedness to (b) total capitalization to be 65.0 % or less at all times. PSE certifies its compliance with such covenants to participating banks each quarter. As of December 31, 2023, PSE was in compliance with all applicable covenant ratios.
 The credit agreement allows PSE to borrow at a prime based rate or to make floating rate advances at the 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 adjusted SOFR rate and the commitment fee was 0.175 %. As of December 31, 2023, no amount was drawn under PSE's credit facility and $ 336.6 million was outstanding under the commercial paper program.
 Outside of the credit facility, PSE maintains a standby letter of credit with TD Bank allowing for standby letter of credit postings of up to $ 150.0 million as a condition of transacting on the ICE NGX platform as well as participating in the Washington state carbon allowance auctions. As of December 31, 2023, $ 51.0 million was issued under a standby letter of credit in support of natural gas and carbon allowance purchases. Additionally, PSE had a $ 2.1 million letter of credit in support of a long-term transmission contract.

 Demand Promissory Note
 In May 2023, PSE amended and restated its revolving credit facility with Puget Energy, in the form of a credit agreement and a demand promissory note (Note) pursuant to which PSE may borrow up to $ 200.0 million from Puget Energy subject to approval by Puget Energy. Under the terms of the Note, PSE pays interest based on Puget Energy's credit facility interest rate, which is SOFR plus 0.10 % SOFR adjustment, plus 1.75 % spread over the adjusted SOFR rate. As of December 31, 2023, there was no outstanding balance under the promissory note.

 Credit Facility
 In May 2022, Puget Energy entered into a new $ 800.0 million credit facility to replace the existing facility. The terms and conditions, including fees, financial covenant, expansion feature and credit spreads remain substantially the same. The base interest rate on loans has changed to the SOFR, as the LIBOR was discontinued on June 30, 2023. The proceeds of the Puget Energy credit facility are to be used for general corporate purposes. The maturity date of the credit facility is May 14, 2027. The Puget Energy revolving senior secured credit facility also has an accordion feature, upon 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 Puget Energy the ability to borrow based on a prime based rate or 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 the date of this report, interest was calculated as SOFR plus 0.10 % SOFR adjustment plus 1.75 % spread over the adjusted SOFR rate and the commitment fee was 0.275 %. As of December 31, 2023, Puget Energy had $ 261.5 million in short-term debt, drawn and outstanding under its credit facility. As of December 31, 2022, Puget Energy had $ 118.6 million drawn and outstanding under its credit facility, of which $ 34.3 million was classified as long-term debt and $ 84.3 million was classified as short-term debt.
 The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The credit agreement also contains a leverage ratio that requires the ratio of (a) total funded indebtedness to (b) total capitalization to be 65.0 % or less at all times. As of December 31, 2023, Puget Energy was in compliance with all applicable covenants.
 In September 2022, Puget Energy borrowed $ 50.0 million on its credit facility and contributed the proceeds to PSE as an equity contribution. The equity proceeds were used for general corporate purposes. In August 2023, Puget Energy borrowed $ 100.0 million on its credit facility and contributed the proceeds to PSE as an equity contribution. The equity proceeds were used for general corporate purposes.

 (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 46 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.

 The components of lease cost were as follows:

 2023
 2022

 Finance lease cost:

 Amortization of right-of-use asset
 $
 3,891
 $
 2,465

 Interest on lease liabilities
 3,237
 2,482

 Total finance lease cost
 $
 7,128
 $
 4,947

 Operating lease cost1

 $
 23,891
 $
 23,984

 1.Includes $ 1.7 million and $ 1.5 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease or both of the years ended December 31, 2023 and December 31, 2022, respectively.

 Supplemental cash flow information related to leases was as follows:

 2023
 2022

 Cash paid for amounts included in the measurement of lease liabilities:

 Operating cash flow for operating leases
 $
 15,990
 $
 16,574

 Investing cash flow for operating leases1

 7,901
 7,410

 Operating cash flow for finance leases
 3,237
 2,482

 Financing cash flow for finance leases
 3,891
 2,465

 Non-cash disclosure upon commencement of new lease

 Right-of-use assets obtained in exchange for new operating lease liabilities
 $
 10,462
 $
 5,338

 Right-of-use assets obtained in exchange for new finance lease liabilities
 1,245
 —

 Non-cash disclosure upon modification of existing lease

 Modification of operating lease right-of-use assets
 $
 6,912
 $
 21,068

 1 Includes $ 1.7 million and $ 1.5 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease for both of the years ended December 31, 2023 and December 31, 2022, respectively.

 Supplemental balance sheet information related to leases was as follows:

 Operating Leases
 2023
 2022

 Operating lease right-of-use asset
 $
 194,321
 $
 193,509

 Operating leases liabilities current
 $
 21,629
 $
 20,342

 Operating lease liabilities long-term
 180,754
 181,265

 Total operating lease liabilities:
 $
 202,383
 $
 201,607

 Finance Leases

 Common plant
 $
 55,756
 $
 58,391

 Electric plant
 39,358
 41,576

 Total finance lease assets
 $
 95,114
 $
 99,967

 Other current liabilities
 $
 3,371
 $
 3,167

 Finance lease liabilities
 99,512
 102,518

 Total finance lease liabilities
 $
 102,883
 $
 105,685

 Weighted Average Remaining Lease Term

 Operating leases
 21.3 Years
 22.0 Years

 Finance leases
 18.0 Years
 19.1 Years

 Weighted Average Discount Rate

 Operating leases
 3.75
 %
 3.62
 %

 Finance leases
 3.08
 %
 3.07
 %

 The following table summarizes the Company's estimated future minimum lease payments as of December 31, 2023:

 Future Minimum Lease Payments

 Operating Leases
 Finance Leases

 2024

 $
 24,390
 $
 6,586

 2025

 24,284
 6,648

 2026

 23,896
 6,709

 2027

 23,497
 6,731

 2028

 20,708
 6,670

 164,820
 103,079

 Total lease payments
 $
 281,595
 $
 136,423

 Less imputed interest
 ( 79,212)
 ( 33,540)

 Total net present value
 $
 202,383
 $
 102,883

 Leases Not Yet Commenced
 On September 20, 2023, PSE entered into a tolling agreement to purchase the energy and capacity associated with a 132.5 MW facility. The tolling agreement represents a lease to PSE, and is expected to commence in October 2025. PSE expects the future minimum lease payments to be $ 91.0 million over the five year period beginning in October 2025.

 On December 12, 2023, PSE entered into a lease for an operations training facility located in Puyallup, Washington. The lease is expected to commence in 2025 and PSE expects the future minimum lease payments to be $ 116.0 million over the 20 year term. Construction of the facility will be managed and contracted by the lessor, however, PSE will have involvement in the design of the facility.

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

 Volumes (millions)
 Assets1

 Liabilities

 2023
 2022
 2023
 2022
 2023
 2022

 Electric portfolio derivatives
 *
 *
 $
 93,028
 $
 337,703
 $
 126,939
 $
 87,120

 Natural gas derivatives (MMBtus)3

 16,521
 343,947
 96,898
 56,222

 Total derivative contracts
 $
 $
 $
 $

 Current
 $
 74,225
 $
 587,029
 $
 185,788
 $
 124,976

 Long-term
 35,324
 94,621
 38,049
 18,366

 Total derivative contracts
 $
 $
 $
 $

 __________
 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 315.6 million One Million British Thermal Units (MMBtus) and purchased electricity of 2.3 million megawatt hours (MWhs) at December 31, 2023, and 234.9 million MMBtus and 5.3 million MWhs at December 31, 2022.

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

 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

 Energy derivative contracts
 $
 $
 —
 $
 $
 ( 82,206)
 $
 —
 $
 27,343

 Liabilities:

 Energy derivative contracts
 —
 ( 82,206)
 ( 84)
 141,547

 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

 Assets

 Energy derivative contracts

 $
 $
 —
 $
 $
 ( 125,334)
 $
 —
 $
 556,316

 Liabilities

 Energy derivative contracts

 —
 ( 125,334)
 ( 5,661)
 12,347

 __________
 1.All derivative contract deals are executed under ISDA, NAESB, and WSPP master agreements with right of set-off.
 2.Amounts reflect netting by Counterparty and right of set-off.

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

 Location
 2023
 2022
 2021

 Gas for Power Derivatives:

 Unrealized
 Unrealized gain (loss) on derivative instruments, net
 $
 ( 155,774)
 $
 61,761
 $
 26,686

 Realized
 Electric generation fuel
 47,930
 158,550
 76,504

 Power Derivatives:

 Unrealized
 Unrealized gain (loss) on derivative instruments, net
 ( 128,721)
 199,416
 ( 12,901)

 Realized
 Purchased electricity
 69,136
 20,917
 ( 3,044)

 Total gain (loss) recognized in income on derivatives
 $
 ( 167,429)
 $
 440,644
 $
 87,245

 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, 2023, approximately 98.8 % of the Company's energy portfolio exposure, excluding normal purchase normal sale (NPNS) transactions, is with counterparties that are rated investment grade by rating agencies and 1.2 % are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies.
 The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors in the determination of reserves, such as credit default swaps and bond 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, 2023, 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, 2023, PSE had cash posted as collateral of $ 12.4 million related to contracts executed on the ICE platform. As a condition of transacting on the ICE NGX platform as well as participating in the Washington state carbon allowance auctions, PSE maintains a standby letter of credit agreement with TD Bank. As of December 31, 2023, PSE had no cash posted with ICE NGX, and $ 51.0 million was issued under the standby letter of credit agreement in support of natural gas and carbon allowance purchases. 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, 2023.

 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:

 2023
 2022

 Contingent Feature
 Fair Value1
 Liability

 Posted
Collateral
 Contingent
Collateral
 Fair Value1
 Liability

 Posted
Collateral
 Contingent
Collateral

 Credit rating2

 $
 13,384
 $
 —
 $
 13,384
 $
 3,157
 $
 —
 $
 3,157

 Requested credit for adequate assurance
 53,427
 —
 —
 4,157
 —
 —

 Forward value of contract3

 12,429
 N/A
 5,661
 56,200
 N/A

 Total
 $
 66,895
 $
 12,429
 $
 13,384
 $
 12,975
 $
 56,200
 $
 3,157

 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.

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

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

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

 The Company considers its electric and natural gas contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes 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 $ 44.6 million and $ 55.0 million at December 31, 2023, and 2022, 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 long-term notes were estimated using the discounted cash flow method with U.S. Treasury yields and Company's credit spreads as inputs, interpolating to the maturity date of each issue.

 The carrying values and estimated fair values were as follows:

 Level
 Carrying Value
 Carrying Value

 Financial liabilities:

 Long-term debt (fixed-rate), net of discount1

 $
 $
 6,855,503
 $
 6,629,073
 $
 6,149,797

 Long-term debt (variable-rate), net of discount
 —
 —
 34,300
 34,300

 Total
 $
 $
 6,855,503
 $
 6,663,373
 $
 6,184,097

 Level
 Carrying Value
 Carrying Value

 Financial liabilities:

 Long-term debt (fixed-rate), net of discount2

 $
 $
 5,007,483
 $
 $
 4,379,010

 Total
 $
 $
 5,007,483
 $
 $
 4,379,010

 1.The carrying value includes debt issuances costs of $ 21.0 million and $ 21.5 million for December 31, 2023, and 2022, respectively, which are not included in fair value.
 2.The carrying value includes debt issuances costs of $ 21.2 million and $ 21.4 million for December 31, 2023, and 2022, respectively, which are not included in fair value.

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

 Level 3
 Total
 Level 3
 Total

 Electric derivative instruments

 $
 42,254
 $
 50,774
 $
 93,028
 $
 218,610
 $
 119,093
 $
 337,703

 Gas derivative instruments

 11,647
 4,874
 16,521
 342,988
 343,947

 Total derivative assets
 $
 53,901
 $
 55,648
 $
 $
 561,598
 $
 120,052
 $

 Liabilities:

 Electric derivative instruments

 $
 103,427
 $
 23,512
 $
 126,939
 $
 84,105
 $
 3,015
 $
 87,120

 Gas derivative instruments

 95,875
 1,023
 96,898
 55,136
 1,086
 56,222

 Compliance obligation

 168,879
 —
 168,879
 —
 —
 —

 Total derivative liabilities
 $
 368,181
 $
 24,535
 $
 392,716
 $
 139,241
 $
 4,101
 $

 Level 3 Roll-Forward Net Asset (Liability)
 2023
 2022
 2021

 Total
 Total
 Total

 Balance at beginning of period
 $
 116,078
 $
 ( 127)
 $
 115,951
 $
 ( 42,752)
 $
 ( 2,120)
 $
 ( 44,872)
 $
 ( 23,718)
 $
 ( 1,135)
 $
 ( 24,853)

 Changes during period:

 Realized and unrealized energy derivatives

 Included in earnings1

 ( 56,656)
 —
 ( 56,656)
 180,533
 —
 180,533
 ( 15,839)
 —
 ( 15,839)

 Included in regulatory assets / liabilities
 —
 4,906
 4,906
 —
 —
 ( 1,749)
 ( 1,749)

 Settlements2

 ( 32,377)
 ( 1,098)
 ( 33,475)
 ( 21,972)
 1,369
 ( 20,603)
 ( 3,195)
 ( 2,431)

 Transferred into Level 3
 —
 —
 —
 —
 —
 —
 —
 —
 —

 Transferred out Level 3
 —
 —
 —

 Balance at end of period
 $
 27,262
 $
 3,851
 $
 31,113
 $
 116,078
 $
 ( 127)
 $
 115,951
 $
 ( 42,752)
 $
 ( 2,120)
 $
 ( 44,872)

 __________________
 1.Income Statement classification: Unrealized gain (loss) on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $( 17.3) million, $ 147.1 million and $( 21.6) million for the years ended December 31, 2023, 2022, and 2021, 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.
 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, 2023, 2022, and 2021. 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.
 Below are the forward price ranges for the Company's commodity contracts, as of December 31, 2023:

 Range

 Assets1

 Liabilities1

 Valuation Technique
 Unobservable Input
 Low
 High
 Weighted

 Electricity
 $
 50,774
 $
 23,512
 Discounted cash flow
 Power Prices (per MWh)
 $
 69.51
 $
 188.63
 $
 99.55

 $
 4,874
 $
 1,023
 Discounted cash flow
 Natural Gas Prices (per MMBtu)
 $
 2.20
 $
 6.28
 $
 3.55

 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, 2023, 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 $ 16.9 million.

 Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis
 Puget Energy records the fair value of its intangible assets in accordance with ASC 360, "Property, Plant, and Equipment," (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle.
 ASC 360 requires long-lived assets to be tested for 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 2023 and 2022 and determined there was no indication of impairment of its power purchase contracts.

 (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 $ 28.9 million, $ 25.2 million and $ 23.6 million for the years 2023, 2022, and 2021, respectively. The employee Investment Plan eligibility requirements are set forth in the plan documents.
 Non-represented employees and United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry (UA) represented employees hired before January 1, 2014, and International Brotherhood of Electrical Workers Local Union 77 (IBEW) represented employees hired before December 12, 2014, have the following company contributions:
 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: 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 pay 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.
 In addition to providing pension benefits, PSE provides legacy group health care and life insurance benefits (Other Benefits) for certain retired employees. The group health care benefit is provided via a Retiree Health Reimbursement Account (HRA) Plan effective January 1, 2020. The life insurance benefits are provided principally through an insurance company.
 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.
 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, 2023, and 2022:

 SERP
 Other

 2023
 2022
 2023
 2022
 2023
 2022

 Change in benefit obligation:

 Benefit obligation at beginning of period
 $
 589,278
 $
 834,960
 $
 32,046
 $
 43,155
 $
 9,015
 $
 11,654

 Amendments
 —
 —
 —
 —

 Service cost
 18,530
 26,351

 Interest cost
 32,375
 24,263
 1,589
 1,253

 Curtailment loss / (gain)
 —
 —
 ( 2,772)
 —
 —
 —

 Actuarial loss (gain)
 8,469
 ( 215,005)
 ( 661)
 ( 5,260)
 ( 52)
 ( 2,397)

 Benefits paid
 ( 38,258)
 ( 80,226)
 ( 3,521)
 ( 7,659)
 ( 1,067)
 ( 808)

 Administrative expense
 ( 1,291)
 ( 1,065)
 —
 —
 —
 —

 Benefit obligation at end of period
 $
 609,103
 $
 589,278
 $
 26,824
 $
 32,046
 $
 8,597
 $
 9,015

 SERP
 Other

 2023
 2022
 2023
 2022
 2023
 2022

 Change in plan assets:

 Fair value of plan assets at beginning of period
 $
 658,533
 $
 898,550
 $
 —
 $
 —
 $
 5,190
 $
 6,341

 Actual return on plan assets
 109,028
 ( 176,537)
 —
 —
 ( 550)

 Employer contribution
 18,000
 18,000
 3,521
 7,659

 Benefits paid
 ( 38,258)
 ( 80,226)
 ( 3,521)
 ( 7,659)
 ( 1,067)
 ( 808)

 Administrative expense
 ( 1,292)
 ( 1,254)
 —
 —
 —
 —

 Fair value of plan assets at end of period
 $
 746,011
 $
 658,533
 $
 —
 $
 —
 $
 5,085
 $
 5,190

 Funded status at end of period
 $
 136,908
 $
 69,255
 $
 ( 26,824)
 $
 ( 32,046)
 $
 ( 3,512)
 $
 ( 3,825)

 SERP
 Other

 2023
 2022
 2023
 2022
 2023
 2022

 Amounts recognized in Consolidated Balance Sheet consist of:

 Noncurrent assets
 $
 136,908
 $
 69,255
 $
 —
 $
 —
 $
 —
 $
 —

 Current liabilities
 —
 —
 ( 1,978)
 ( 3,532)
 ( 225)
 ( 252)

 Noncurrent liabilities
 —
 —
 ( 24,846)
 ( 28,514)
 ( 3,287)
 ( 3,573)

 Net assets (liabilities)
 $
 136,908
 $
 69,255
 $
 ( 26,824)
 $
 ( 32,046)
 $
 ( 3,512)
 $
 ( 3,825)

 SERP
 Other

 2023
 2022
 2023
 2022
 2023
 2022

 Change in plan obligation and plan asset:

 Projected benefit obligation
 $
 609,103
 $
 589,278
 $
 26,824
 $
 32,046
 $
 8,597
 $
 9,015

 Accumulated benefit obligation
 601,981
 582,538
 26,824
 29,763
 8,487
 8,929

 Fair value of plan assets
 746,011
 658,533
 —
 —
 5,085
 5,190

 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, 2023, and 2022:

 SERP
 Other

 2023
 2022
 2023
 2022
 2023
 2022

 Amounts recognized in Accumulated Other Comprehensive Income consist of:

 Net loss (gain)
 $
 ( 16,257)
 $
 31,213
 $
 ( 1,870)
 $
 1,563
 $
 ( 2,052)
 $
 ( 1,964)

 Prior service cost (credit)
 —
 —
 —

 Total
 $
 ( 16,257)
 $
 31,213
 $
 ( 1,870)
 $
 1,852
 $
 ( 1,742)
 $
 ( 1,705)

 SERP
 Other

 2023
 2022
 2023
 2022
 2023
 2022

 Amounts recognized in Accumulated Other Comprehensive Income consist of:

 Net loss (gain)
 $
 74,851
 $
 124,767
 $
 ( 1,613)
 $
 1,864
 $
 ( 2,124)
 $
 ( 2,056)

 Prior service cost (credit)
 —
 —
 —

 Total
 $
 74,851
 $
 124,767
 $
 ( 1,613)
 $
 2,153
 $
 ( 1,814)
 $
 ( 1,798)

 The following tables summarize Puget Energy's and PSE's net periodic benefit cost for the years ended December 31, 2023, 2022, and 2021.

 SERP
 Other

 2023
 2022
 2021
 2023
 2022
 2021
 2023
 2022
 2021

 Components of net periodic benefit cost:

 Service cost
 $
 18,530
 $
 26,351
 $
 26,888
 $
 $
 $
 $
 $
 $

 Interest cost
 32,375
 24,263
 22,381
 1,589
 1,253
 1,183

 Expected return on plan assets
 ( 50,641)
 ( 51,014)
 ( 48,239)
 —
 —
 —
 ( 297)
 ( 379)
 ( 355)

 Amortization of prior service cost (credit)
 —
 —
 ( 1,904)

 Amortization of net loss (gain)
 ( 2,447)
 6,381
 11,803
 —
 2,471
 2,165
 ( 210)
 ( 29)
 ( 39)

 Net periodic benefit cost
 $
 ( 2,183)
 $
 5,981
 $
 10,929
 $
 1,876
 $
 4,570
 $
 4,153
 $
 $
 $

 SERP
 Other

 2023
 2022
 2021
 2023
 2022
 2021
 2023
 2022
 2021

 Components of net periodic benefit cost:

 Service cost
 $
 18,530
 $
 26,351
 $
 26,888
 $
 $
 $
 $
 $
 $

 Interest cost
 32,375
 24,263
 22,381
 1,589
 1,253
 1,183

 Expected return on plan assets
 ( 50,641)
 ( 51,016)
 ( 48,242)
 —
 —
 —
 ( 297)
 ( 379)
 ( 355)

 Amortization of prior service cost (credit)
 —
 —
 ( 1,513)

 Amortization of net loss (gain)
 —
 15,080
 21,862
 2,648
 2,344
 ( 230)
 ( 35)
 ( 52)

 Net periodic benefit cost
 $
 $
 14,678
 $
 21,376
 $
 1,920
 $
 4,747
 $
 4,332
 $
 $
 $

 The following tables summarize Puget Energy's and PSE's benefit obligations recognized in other comprehensive income (OCI) for the years ended December 31, 2023, and 2022:

 SERP
 Other

 2023
 2022
 2023
 2022
 2023
 2022

 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:

 Net loss (gain)
 $
 ( 49,917)
 $
 12,735
 $
 ( 3,433)
 $
 ( 5,260)
 $
 ( 298)
 $
 ( 1,468)

 Amortization of net (loss) gain
 2,447
 ( 6,381)
 —
 ( 2,471)

 Settlements, mergers, sales, and closures
 —
 —
 ( 145)
 ( 277)
 —
 —

 Prior service cost (credit)
 —
 —
 —
 —

 Amortization of prior service (cost) credit
 —
 —
 ( 144)
 ( 289)
 ( 28)
 ( 22)

 Total change in other comprehensive income for year
 $
 ( 47,470)
 $
 6,354
 $
 ( 3,722)
 $
 ( 8,297)
 $
 ( 37)
 $
 ( 1,423)

Pension Benefit
 SERP
 Other

 2023
 2022
 2023
 2022
 2023
 2022

 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:

 Net loss (gain)
 $
 ( 49,916)
 $
 12,736
 $
 ( 3,433)
 $
 ( 5,260)
 $
 ( 298)
 $
 ( 1,468)

 Amortization of net (loss) gain
 —
 ( 15,080)
 ( 44)
 ( 2,648)

 Settlements, mergers, sales, and closures
 —
 —
 ( 145)
 ( 331)
 —
 —

 Prior service cost (credit)
 —
 —
 —
 —

 Amortization of prior service (cost) credit
 —
 —
 ( 144)
 ( 289)
 ( 28)
 ( 22)

 Total change in other comprehensive income for year
 $
 ( 49,916)
 $
 ( 2,344)
 $
 ( 3,766)
 $
 ( 8,528)
 $
 ( 17)
 $
 ( 1,417)

 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, 2024, are expected to be at least $ 18.0 million, $ 2.0 million and $ 0.2 million, respectively.

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

 Benefit Obligation Assumptions:
 2023
 2022
 2021
 2023
 2022
 2021
 2023
 2022
 2021

 Discount rate
 5.30
 %
 5.60
 %
 3.00
 %
 5.30
 %
 5.60
 %
 3.00
 %
 5.30
 %
 5.60
 %
 3.00
 %

 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
 4.00
 4.00
 4.00
 N/A
 N/A
 N/A
 N/A
 N/A
 N/A

 Benefit Cost Assumptions:

 Discount rate
 5.60
 3.00
 2.70
 5.60
 3.00
 2.70
 5.60
 3.00
 2.70

 Return on plan assets
 6.75
 6.50
 6.50
 —
 —
 —
 7.00
 7.00
 7.00

 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
 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). 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 of $ 8.5 million in 2023. This is primarily due to the change of census data, which increases the expected 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:

 2024
 2025
 2026
 2027
 2028
 2029-2033

 Qualified Pension total benefits
 $
 43,500
 $
 44,500
 $
 45,400
 $
 46,100
 $
 46,700
 $
 243,900

 SERP Pension total benefits
 1,978
 7,058
 2,347
 4,517
 1,673
 7,908

 Other Benefits total
 3,589

 Plan Assets
 Plan contributions and the actuarial present value of accumulated plan benefits are prepared based on certain assumptions pertaining to interest rates, inflation rates and employee demographics, all of which are subject to change. Due to uncertainties inherent in the estimations and assumptions process, changes in these estimates and assumptions in the near term may be material to the financial statements.
 The Company has a Retirement Plan Committee that establishes investment policies, objectives and strategies designed to balance expected return with a prudent level of risk. All changes to the investment policies are reviewed and approved by the Retirement Plan Committee prior to being implemented.
 The Retirement Plan Committee invests trust assets with investment managers who have historically achieved above-median long-term investment performance within the risk and asset allocation limits that have been established. Interim evaluations are routinely performed with the assistance of an outside investment consultant.
 To obtain the desired return needed to fund the pension benefit plans, the Retirement Plan Committee has established investment allocation percentages by asset classes as follows:

 Allocation

 Asset Class
 Minimum
 Target
 Maximum

 Domestic large cap equity
 %
 %
 %

 Domestic small cap equity
 —

 Non-U.S. equity

 Fixed income

 Cash
 —
 —

 Plan Fair Value Measurements
 ASC 715, "Compensation – Retirement Benefits" (ASC 715) directs companies to provide additional disclosures about plan assets of a defined benefit pension or other postretirement plan. The objectives of the disclosures are to disclose the

 following: (i) how investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies; (ii) major categories of plan assets; (iii) inputs and valuation techniques used to measure the fair value of plan assets; (iv) effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period; and (v) significant concentrations of risk within plan assets.
 ASC 820 allows the reporting entity, as a practical expedient, to measure the fair value of investments that do not have readily determinable fair values on the basis of the net asset value per share of the investment if the net asset value of the investment is calculated in a matter consistent with ASC 946, "Financial Services – Investment Companies". The standard requires disclosures about the nature and risk of the investments and whether the investments are probable of being sold at amounts different from the net asset value per share.
 The following table sets forth by level, within the fair value hierarchy, the qualified pension plan as of December 31, 2023, and 2022:

 Recurring Fair Value Measures
 Recurring Fair Value Measures

 Level 1
 Other
 Total
 Level 1
 Other
 Total

 Common Stock:

 Domestic

 $
 130,288
 $
 $
 —
 $
 130,569
 $
 175,969
 $
 $
 —
 $
 176,267

 Foreign

 13,767
 —
 —
 13,767
 17,767
 —
 —
 17,767

 Government Securities
 73,243
 12,709
 —
 85,952
 61,693
 8,828
 —
 70,521

 Corporate Securities:

 Domestic

 —
 14,787
 —
 14,787
 —
 16,005
 —
 16,005

 Foreign

 —
 8,829
 —
 8,829
 —
 6,525
 —
 6,525

 Mutual Funds

 81,130
 —
 —
 81,130
 —
 —
 —
 —

 Cash and cash equivalents
 2,846
 —
 3,082
 4,678
 ( 632)
 —
 4,046

 Investments measured at NAV:

 Collective Investment Funds
 —
 —
 297,780
 297,780
 —
 —
 262,910
 262,910

 Partnership
 —
 —
 91,845
 91,845
 —
 —
 86,827
 86,827

 Mutual Funds
 —
 —
 48,116
 48,116
 —
 —
 46,005
 46,005

 Other
 —
 —
 —
 —

 Net (payable) receivable
 —
 —
 ( 29,974)
 ( 29,974)
 —
 —
 ( 29,186)
 ( 29,186)

 $
 301,274
 $
 36,842
 $
 407,895
 $
 746,011
 $
 260,107
 $
 31,024
 $
 367,402
 $
 658,533

 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

 Level 1
 Other
 Total
 Level 1
 Other
 Total

 Mutual fund
 $
 —
 $
 5,085
 $
 —
 $
 5,085
 $
 —
 $
 5,190
 $
 —
 $
 5,190

 $
 —
 $
 5,085
 $
 —
 $
 5,085
 $
 —
 $
 5,190
 $
 —
 $
 5,190

 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 quoted 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.
 • 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:

 2023
 2022
 2021

 Charged to operating expenses:

 Current:

 Federal
 $
 66,086
 $
 41,198
 $
 25,395

 State
 1,317

 Deferred:

 Federal
 ( 94,860)
 17,866
 ( 1,759)

 State

 Total income tax expense
 $
 ( 27,434)
 $
 59,698
 $
 24,515

 2023
 2022
 2021

 Charged to operating expenses:

 Current:

 Federal
 $
 112,168
 $
 81,597
 $
 52,616

 State
 1,626

 Deferred:

 Federal
 ( 120,397)
 ( 2,171)
 ( 9,027)

 State
 —
 —
 —

 Total income tax expense
 $
 ( 6,603)
 $
 80,295
 $
 44,259

 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:

 2023
 2022
 2021

 Income taxes at the statutory rate
 $
 5,524
 $
 99,549
 $
 59,927

 Increase (decrease):

 Utility plant differences1

 $
 ( 23,806)
 $
 ( 23,028)
 $
 ( 22,325)

 AFUDC, net
 ( 4,017)
 ( 3,567)
 1,509

 Executive compensation
 1,544
 1,821
 1,386

 Treasury grant amortization
 ( 750)
 ( 5,717)
 ( 5,424)

 Excess deferred tax amortization
 ( 8,689)
 ( 13,722)
 ( 13,392)

 State taxes, net
 1,070

 Other–net
 1,690
 3,857
 2,416

 Total income tax expense
 $
 ( 27,434)
 $
 59,698
 $
 24,515

 Effective tax rate
 ( 104.3)
 %
 12.6
 %
 8.6
 %

 2023
 2022
 2021

 Income taxes at the statutory rate
 $
 26,136
 $
 119,962
 $
 79,868

 Increase (decrease):

 Utility plant differences1

 $
 ( 23,806)
 $
 ( 23,028)
 $
 ( 22,325)

 AFUDC, net
 ( 4,017)
 ( 3,567)
 1,509

 Treasury grant amortization
 ( 750)
 ( 5,717)
 ( 5,424)

 Excess deferred tax amortization
 ( 8,689)
 ( 13,722)
 ( 13,392)

 State taxes, net
 1,291

 Other–net
 3,232
 5,678
 3,481

 Total income tax expense
 $
 ( 6,603)
 $
 80,295
 $
 44,259

 Effective tax rate
 ( 5.3)
 %
 14.1
 %
 11.6
 %

 1.Utility plant differences include the reversal of excess deferred taxes using the average rate assumption method in the amount of $ 27.8 million and $ 27.2 million in 2023 and 2022, respectively.

 The Company's net deferred tax liability at December 31, 2023, and 2022, is composed of amounts related to the following types of temporary differences:

 2023
 2022

 Utility plant and equipment
 $
 1,799,505
 $
 1,853,450

 34,175
 158,175

 Other deferred tax liabilities
 373,667
 365,035

 Subtotal deferred tax liabilities
 2,207,347
 2,376,660

 Net operating loss carryforward
 ( 210,238)
 ( 234,825)

 Net regulatory liability for income taxes
 ( 760,961)
 ( 811,161)

 Other deferred tax assets
 ( 285,919)
 ( 344,727)

 Subtotal deferred tax assets
 ( 1,257,118)
 ( 1,390,713)

 Total net deferred tax liabilities
 $
 950,229
 $
 985,947

 2023
 2022

 Utility plant and equipment
 $
 1,796,476
 $
 1,852,644

 23,005
 143,147

 Other deferred tax liabilities
 296,323
 279,612

 Subtotal deferred tax liabilities
 2,115,804
 2,275,403

 Net regulatory liability for income taxes
 ( 761,621)
 ( 811,724)

 Other deferred tax assets
 ( 275,336)
 ( 324,079)

 Subtotal deferred tax assets
 ( 1,036,957)
 ( 1,135,803)

 Total net deferred tax liabilities
 $
 1,078,847
 $
 1,139,600

 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. Puget Energy's net operating loss carryforwards expire from 2031 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.
 As of December 31, 2023, and 2022, the Company had no material unrecognized tax benefits. As a result, no interest or penalties were accrued for unrecognized tax benefits during the year.
 The Company has open tax years from 2020 through 2023. The Company classifies interest as interest expense and penalties as other expense in the financial statements.

 (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, which are coal-fired generating units located in Colstrip, Montana. PSE has accelerated the depreciation of Colstrip Units 3 and 4 to December 31, 2025 as part of the 2019 GRC. The 2017 GRC 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. Additional costs beyond those covered by PTCs and hydro-related treasury grants are being recovered through a separate Colstrip tariff as part of the 2022 GRC. In 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. Although PSE and Talen Energy signed an

 agreement in 2022 involving the transfer of PSE's ownership to Talen at the end of 2025, Talen emerged from a Chapter 11 bankruptcy in May 2023 without approval of the agreement, so the parties have agreed to continue discussions about the status of PSE's ownership stake. Management evaluated Colstrip Units 3 and 4 and determined that the applicable held for sale and abandonment accounting criteria were not met as of December 31, 2023. As such, Colstrip Units 3 and 4 are classified as Electric Utility Plant on the Company's balance sheet as of December 31, 2023.
 Consistent with a June 2019 announcement, Talen permanently shut down Units 1 and 2 at the end of 2019 due to operational losses associated with the Units. Colstrip Units 1 and 2 were retired effective December 31, 2019. The Washington Clean Energy 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 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.
 In May 2021, PSE along with the Colstrip owners, Avista Corporation, PacifiCorp and Portland General Electric Company, filed a lawsuit against the Montana Attorney General challenging the constitutionality of Montana Senate Bill 266. On September 28, 2022, the magistrate judge in the District Court proceeding issued a recommendation to the presiding U.S. District Court Judge that a permanent injunction against enforcement of Senate Bill 266 be granted. In October 2022, the U.S. District Court Judge accepted in full the magistrate judge's recommendation for a permanent injunction against enforcement of Senate Bill 266. The Court entered judgment and a permanent injunction in favor of PSE and the Colstrip owners on November 15, 2022. No party filed a notice of appeal.

 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 commenced on February 1, 2022. On February 4, 2022, the court transferred the appeal to the Washington Court of Appeals Division II (Wash. Ct. App. Div. II) for direct review. On December 26, 2023 the Wash. Ct. App. Div. II affirmed the PCHB decision on all counts.

 (16) Commitments and Contingencies

 For the year ended December 31, 2023, approximately 11.1 % of the Company's energy output was obtained at an average cost of approximately $ 0.053 per Kilowatt Hour (kWh) through long-term contracts with three of the Washington Public Utility Districts (PUDs) that own hydroelectric projects on the Columbia River. The purchase of power from the Columbia River projects is on a pro rata share basis under which the Company pays a proportionate share of the annual debt service, operating and maintenance costs and other expenses associated with each project, in proportion to the contractual share of power that PSE obtains from that project. In these instances, PSE's payments are not contingent upon the projects being operable; therefore, PSE is required to make the payments even if power is not delivered. These projects are financed 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.
 The Company's expenses under these PUD contracts were as follows for the years ended December 31:

 2023
 2022
 2021

 PUD contract costs
 $
 174,385
 $
 149,575
 $
 117,812

 As of December 31, 2023, the Company purchased portions of the power output of the PUDs' projects as set forth in the following table:
 Company's Share of

 Contract
Expiration
 2024 Percent of Output
 2024 Megawatt Capacity
 Estimated 2024 Total Costs
 2024 Debt Service Costs
 Interest included in 2024 Debt Service Costs
 Debt Outstanding

 Chelan County PUD1:

 Rock Island Project
 2051
 35.0
 %
 $
 68,410
 $
 17,645
 $
 4,059
 $
 105,617

 Rocky Reach Project
 2051
 35.0
 84,453
 6,838
 2,015
 35,555

 Douglas County PUD2:

 Wells Project
 2029
 17.3
 28,310
 —
 —
 —

 Grant County PUD3:

 Priest Rapids Development
 2052
 4.8
 28,781
 4,061

 Wanapum Development
 2052
 4.8
 28,781
 4,061

 Total
 $
 238,735
 $
 25,141
 $
 6,426
 $
 149,294

 1.PSE currently purchases output from Chelan County PUD's Rock Island and Rocky Reach hydroelectric projects under three separate contracts: 1) a contract for 25 % of output that was executed in February 2006 and expires October 31, 2031. In 2023, PSE executed a new contract extending this 25 % share of output through October 2051; 2) a contract executed in March 2021 for 5 % of output that began on January 1, 2022 and continues through December 31, 2026; and 3) a contract executed during 2023 to purchase an additional 5 % of output for each from January 1, 2024 through December 31, 2028.
 2.PSE currently purchases output from Douglas County PUD's Wells hydroelectric project under two separate contracts: 1) a contract executed in March 2017 with a variable share output (average 11.82 % in 2024) that began on September 1, 2018 and ends September 30, 2028; and 2) a contract executed in March 2021 for 5.5 % of output from October 1, 2021 through September 30, 2024. In 2023, PSE executed a new contract extending this 5.5 % share of output through September 30, 2029.
 3.PSE currently purchases output from Grant County PUD's Wanapum and Priest Rapids hydroelectric developments under two separate contracts: 1) a contract that was executed on December 13, 2001 and began November 1, 2005 under which PSE receives 0.64 % of output through expires March 31, 2052; and 2) a contract entered in November 2023 for 4.18 % of output that begins on January 1, 2024, and continues through December 31, 2024. PSE reserves the right to renew the latter contract on an annual basis.

 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.

 2024
 2025
 2026
 2027
 2028
 Total

 Columbia River projects
 $
 226,616
 $
 196,843
 $
 196,722
 $
 179,740
 $
 180,995
 $
 3,431,358
 $
 4,412,274

 Electric portfolio contracts
 459,999
 416,634
 192,381
 184,277
 175,788
 2,044,137
 3,473,216

 Electric wholesale market transactions
 202,692
 55,432
 12,125
 —
 —
 —
 270,249

 Total
 $
 889,307
 $
 668,909
 $
 401,228
 $
 364,017
 $
 356,783
 $
 5,475,495
 $
 8,155,739

 Total purchased power contracts provided the Company with approximately 14.7 million, 15.3 million and 13.1 million MWhs of firm energy at a cost of approximately $ 851.6 million, $ 892.7 million and $ 631.4 million for the years 2023, 2022, and 2021, respectively.

 Natural Gas Supply Obligations
 The Company has entered into various firm supply, transportation and storage service contracts in order to ensure adequate availability of natural gas supply for its customers and generation requirements. The Company contracts for its long-term

 natural gas supply on a firm basis, which means the Company has a 100 % daily take obligation and the supplier has a 100 % daily delivery obligation to ensure service to PSE's customers and generation requirements. The transportation and storage contracts, which have remaining terms from 1 year to 21 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage.
 The Company incurred demand charges of $ 137.6 million, $ 138.3 million, and $ 136.4 million for firm transportation, storage and peaking services for its natural gas customers for the years 2023, 2022, and 2021. The Company incurred demand charges of $ 60.5 million, $ 53.9 million, and $ 52.8 million for firm transportation, storage and peaking services for the natural gas supply for its combustion turbines for the years 2023, 2022, and 2021.
 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 Energy Regulator (CER) currently authorized rates, which are subject to change.

 Natural Gas Supply and Demand Charge Obligations
 2024
 2025
 2026
 2027
 2028
 Total

 Natural gas wholesale market transactions
 $
 535,134
 $
 466,669
 $
 327,471
 $
 190,303
 $
 96,129
 $
 —
 $
 1,615,706

 Firm transportation service
 182,771
 163,644
 161,471
 163,028
 159,435
 818,802
 1,649,151

 Firm storage service
 9,356
 9,350
 8,476
 8,189
 2,678
 5,783
 43,832

 Total
 $
 727,261
 $
 639,663
 $
 497,418
 $
 361,520
 $
 258,242
 $
 824,585
 $
 3,308,689

 Service Contracts
 The following table summarizes the Company's estimated obligations for energy production service contracts through the terms of its existing contracts.

 Service Contract Obligations
 2024
 2025
 2026
 2027
 2028
 Total

 Energy production service contracts
 $
 34,702
 $
 35,391
 $
 36,113
 $
 36,848
 $
 37,621
 $
 96,826
 $
 277,501

 Legal Matters
 Washington Climate Commitment Act
 In 2021, the Washington Legislature adopted the CCA, which establishes a GHG emissions cap-and-invest program that requires covered entities, including electric and natural gas utilities, to purchase allowances to cover their GHG emissions with a cap on available allowances beginning on January 1, 2023 that declines annually through 2050. WDOE published final regulations to implement the program on September 29, 2022, which became effective on October 30, 2022. WDOE also indicated that there will be subsequent rulemakings building off initial rulemaking as program implementation proceeds and Washington carbon goals is evaluated.
 One component of the CCA rules stipulates that GHG emissions associated with exported electricity are covered emissions and require an allowance offset to the extent these exports are not sourced from a non-emitting resource. Another component of the CCA rules stipulates GHG emissions associated with imported electricity are covered emissions and require an allowance offset for the first jurisdictional deliverer serving as the electricity importer for that electricity. Per RCW 70A.65.010(42)(d), imported electricity does not include electricity imports of unspecified electricity that are netted by exports of unspecified electricity to any jurisdiction not covered by a linked program by the same entity within the same hour. Under this definition, hourly power transmission data is required to determine PSE's net imported electricity compliance obligation. Although the Company is actively engaged in determining the hourly net generation, imports and exports, the methodology for netting these components by hour that will be required by the WDOE to calculate the compliance obligation is uncertain, and PSE expects further rulemaking and agency interpretations to clarify this uncertainty in future periods. Due to the estimation uncertainty as of the date of this disclosure, the company considered a range of outcomes depending on the proportion of exported electricity that is sourced from non-emitting resources and whether all unspecified electricity imports and exports fully net on an hourly basis, none net, or a portion do. As of December 31, 2023, the Company's estimated the range of possible outcomes to be between $ 95.9 and $ 280.2 million depending on the methodology applied in netting unspecified electricity imports and exports. Since no amount in the range represents a better estimate than any other amount, the Company accrued to the minimum amount in the range. As existing uncertainties are resolved in future periods, any change in compliance costs as a result of such estimated additional liabilities would be deferred under ASC 980 as a regulatory asset consistent with Docket No. UE-220974, as these amounts may be recoverable from customers in future utility rates.

 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.

 (17) 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, 2023, 2022, and 2021, respectively:

 Net unrealized gain (loss) and prior service cost on pension plans

 Changes in AOCI, net of tax

 Total

 Balance at December 31, 2020
 $
 ( 86,437)
 $
 ( 86,437)

 49,226
 49,226

 Amounts reclassified from accumulated other comprehensive income (loss), net of tax
 9,779
 9,779

 Balance at December 31, 2021
 $
 ( 27,432)
 $
 ( 27,432)

 ( 4,559)
 ( 4,559)

 Amounts reclassified from accumulated other comprehensive income (loss), net of tax
 7,217
 7,217

 2,658
 2,658

 Balance at December 31, 2022
 $
 ( 24,774)
 $
 ( 24,774)

 44,277
 44,277

 Amounts reclassified from accumulated other comprehensive income (loss), net of tax
 ( 1,964)
 ( 1,964)

 Balance at December 31, 2023
 $
 17,539
 $
 17,539

 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

 Total

 Balance at December 31, 2020
 $
 ( 175,972)
 $
 ( 4,984)
 $
 ( 180,956)

 49,265
 —
 49,265

 Amounts reclassified from accumulated other comprehensive income (loss), net of tax
 18,166
 18,550

 67,431
 67,815

 Balance at December 31, 2021
 $
 ( 108,541)
 $
 ( 4,600)
 $
 ( 113,141)

 ( 4,512)
 —
 ( 4,512)

 Amounts reclassified from accumulated other comprehensive income (loss), net of tax
 14,223
 14,609

 9,711
 10,097

 Balance at December 31, 2022
 $
 ( 98,830)
 $
 ( 4,214)
 $
 ( 103,044)

 44,277
 —
 44,277

 Amounts reclassified from accumulated other comprehensive income (loss), net of tax
 ( 12)

 44,265
 44,650

 Balance at December 31, 2023
 $
 ( 54,565)
 $
 ( 3,829)
 $
 ( 58,394)

 Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2023, 2022, and 2021, respectively, are as follows:

 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)

 2023
 2022
 2021

 Net unrealized gain (loss) and prior service cost on pension plans:

 Amortization of prior service cost
 (a)
 $
 ( 172)
 $
 ( 311)
 $
 1,549

 Amortization of net gain (loss)
 (a)
 2,658
 ( 8,824)
 ( 13,928)

 Total before tax
 2,486
 ( 9,135)
 ( 12,379)

 Tax (expense) or benefit
 ( 522)
 1,918
 2,600

 1,964
 ( 7,217)
 ( 9,779)

 Total reclassification for the period
 $
 1,964
 $
 ( 7,217)
 $
 ( 9,779)

 __________
 (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.

 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)

 2023
 2022
 2021

 Net unrealized gain (loss) and prior service cost on pension plans:

 Amortization of prior service cost
 (a)
 $
 ( 172)
 $
 ( 311)
 $
 1,158

 Amortization of net gain (loss)
 (a)
 ( 17,693)
 ( 24,153)

 Total before tax
 ( 18,004)
 ( 22,995)

 Tax (expense) or benefit
 ( 3)
 3,781
 4,829

 ( 14,223)
 ( 18,166)

 Net unrealized gain (loss) on treasury interest rate swaps:

 Interest rate contracts
 Interest expense
 ( 488)
 ( 488)
 ( 487)

 Tax (expense) or benefit

 ( 385)
 ( 386)
 ( 384)

 Total reclassification for the period
 $
 ( 373)
 $
 ( 14,609)
 $
 ( 18,550)

 ____________
 (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.

 SCHEDULE I: CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY

 Condensed Statements of Income and Comprehensive Income (Loss)

 2023
 2022
 2021

 Non-utility expense and other
 $
 ( 1,466)
 $
 ( 1,206)
 $
 ( 913)

 Other income (deductions):

 Equity in earnings of subsidiary
 110,719
 474,873
 337,405

 Interest income
 17,863
 8,458
 4,261

 Interest expense
 ( 88,739)
 ( 84,051)
 ( 100,002)

 Income tax benefit (expense)
 15,363
 16,271
 20,098

 $
 $
 $

 Comprehensive income (loss)
 $
 96,053
 $
 417,003
 $
 319,854

 See accompanying notes to the condensed financial statements.

 Condensed Balance Sheets

 2023
 2022

 Investment in subsidiaries
 $
 5,096,133
 $
 4,938,998

 Other property and investments:

 Goodwill
 1,656,513
 1,656,513

 Current assets:

 Cash
 1,596
 1,528

 Receivables from affiliates1

 256,417
 246,317

 Prepaid expenses and other

 —

 Income tax receivables

 Total current assets
 258,128
 248,377

 Long-term assets:

 Deferred income taxes
 207,192
 231,976

 Other
 2,673
 3,370

 Total long-term assets
 209,865
 235,346

 $
 7,220,639
 $
 7,079,234

 Capitalization and liabilities:

 Common equity
 $
 4,960,382
 $
 4,964,089

 Long-term debt
 1,988,609
 2,020,734

 Total capitalization
 6,948,991
 6,984,823

 Current liabilities:

 Accounts payable to affiliates1

 Short-term debt
 261,500
 84,300

 Interest
 9,995
 9,978

 Total current liabilities
 271,648
 94,411

 Commitments and contingencies (Note 16)

 Total capitalization and liabilities
 $
 7,220,639
 $
 7,079,234

 1 Eliminated in consolidation.

 See accompanying notes to the condensed financial statements.

 Condensed Statements of Cash Flows

 2023
 2022
 2021

 Operating activities:

 Net cash provided by (used in) operating activities
 $
 64,506
 $
 ( 10,197)
 $
 143,691

 Investing activities:

 Investment in subsidiaries
 ( 100,000)
 ( 50,000)
 ( 21,783)

 (Increase) decrease in loan to subsidiary
 ( 9,753)
 ( 12,176)
 —

 Net cash provided by (used in) investing activities
 ( 109,753)
 ( 62,176)
 ( 21,783)

 Financing activities:

 Dividends paid
 ( 99,760)
 ( 16,230)
 ( 106,420)

 Investment from Parent
 —
 —
 210,000

 Change in short-term debts, net
 142,900
 84,300
 —

 Issuance of long-term debts
 —
 448,075
 515,475

 Redemption of long-term debts
 —
 ( 450,000)
 ( 734,000)

 Issue costs and others
 2,175
 1,370
 ( 1,367)

 Net cash provided by (used in) by financing activities
 45,315
 67,515
 ( 116,312)

 Increase (decrease) in cash
 ( 4,858)
 5,596

 Cash at beginning of year
 1,528
 6,386

 Cash at end of year
 $
 1,596
 $
 1,528
 $
 6,386

 See accompanying notes to the condensed financial statements.

 NOTES TO CONDENSED FINANCIAL STATEMENTS

 (1) Basis of Presentation

 Puget Energy is an energy services holding company that conducts substantially all of its business operations through its regulated subsidiary, PSE. Puget Energy also 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 $ 114.8 million, $ 473.8 million and $ 335.0 million for the years ended December 31, 2023, 2022, and 2021, respectively, and business combination accounting adjustments under ASC 805 recorded at Puget Energy for PSE of $( 4.1) million, $ 1.0 million and $ 2.4 million for the years ended December 31, 2023, 2022, and 2021, 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.

 SCHEDULE II: VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

 Balance at
Beginning of
Period
 Additions
Charged to
Costs and
Expenses
 Deductions
 Balance
at End
of Period

 Year Ended December 31, 2023

 Accounts deducted from assets on balance sheet:

 Allowance for doubtful accounts receivable
 $
 41,962
 $
 34,724
 $
 38,475
 $
 38,211

 Year Ended December 31, 2022

 Accounts deducted from assets on balance sheet:

 Allowance for doubtful accounts receivable
 $
 34,958
 $
 28,316
 $
 21,312
 $
 41,962

 Year Ended December 31, 2021

 Accounts deducted from assets on balance sheet:

 Allowance for doubtful accounts receivable
 $
 20,080
 $
 27,204
 $
 12,326
 $
 34,958

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

 None.

 ITEM 9A. CONTROLS AND PROCEDURES

 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 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, 2023, the end of the period covered by this report. Based upon that evaluation, the President and Chief Executive Officer 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, 2023, 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 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, 2023.
 Puget Energy's effectiveness of internal control over financial reporting as of December 31, 2023, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

 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 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, 2023, the end of the period covered by this report. Based upon that evaluation, the President and Chief Executive Officer 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, 2023, 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 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, 2023.
 PSE's effectiveness of internal control over financial reporting as of December 31, 2023, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

 ITEM 9B. OTHER INFORMATION
 During the three months ended December 31, 2023, none of the Company's directors or officers (as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934) adopted, terminated or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K of the Securities Act of 1933).

 ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

 None.

 ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 Board of Directors
 As of March 5, 2024, thirteen directors constitute Puget Energy's Board of Directors and fourteen 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 64, has been a director on the board 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 61, 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 65, has been a director on the board of PSE since November 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.

 Christine Gregoire, age 76, has been a director on the board of both Puget Energy and PSE since February 24, 2023. Ms. Gregoire is Chief Executive Officer of Challenge Seattle (2015 – Present), an alliance of Seattle-area business leaders focused on civic improvement initiatives. Prior to that time, Ms. Gregoire served two terms as the Governor of the State of Washington from 2005 to 2013. Before serving as Governor, Ms. Gregoire served for three terms as the Attorney General of the State of Washington (1993 to 2005). In addition to her role as CEO of Challenge Seattle, Ms. Gregoire has served as the former chair of the Fred Hutch Cancer Research Center, a member of the National Bipartisan Governor's Council and as Chair of the

 National Export-Import Bank Advisory Board. An independent director not affiliated with any of the Company's investors, Ms. Gregoire brings to the Board her extensive executive leadership experience, her deep knowledge of Washington's legal, political and regulatory participants and processes, and her intimate familiarity with multiple communities and constituencies across the Company's service territory.

 Chris Parker, age 53, 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 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.

 Julia Hamm, age 47, has been a director on the board of both Puget Energy and PSE since May 1, 2023. Ms. Hamm is a member of the board of directors and chair of the compensation committee of Voltera, an electric fleet charging infrastructure company, a role she has held since 2022, and a member of the board of directors of the California Mobility Center, a role she has held since 2021. Ms. Hamm is also the founder and a current board member of Solar Energy Trade Shows, which manages the Solar Power International energy industry trade show. Prior to this, Ms. Hamm served as the president and CEO of Smart Electric Power Alliance, a non-profit company, from 2004-2022. Ms. Hamm serves on the boards of Puget Energy and PSE as a representative of PGGM Vermogensbeheer B.V., pursuant to the terms of the Puget Energy and PSE bylaws.

 Grant Hodgkins, age 48, 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.

 Tom King, age 62, 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 56, 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. Ms. Kipp also serves on the board of Hawaiian Electric Industries, Inc., owner of a provider of electric utility services in Hawaii, and Boston Properties, Inc., a publicly traded developer, owner and manager of Class A office properties. Ms. Kipp is also a member of Challenge Seattle, an alliance of Seattle-area business leaders focused on civic improvement initiatives, since 2020.

 Jenine Krause, age 52, has been a director on the boards of both Puget Energy and PSE since February 2, 2024. Ms. Krause is currently a managing director at OMERS Infrastructure Management, Inc. Prior to joining OMERS in 2022, Ms. Krause was CEO of Enercare Inc., a home and commercial service and energy solutions company; previously she held senior roles at Bell Canada across numerous business units. In addition to PSE and Puget Energy, Ms. Krause is a board member of

 Beanfield Technologies, a Canadian fiber infrastructure network, BridgeTex Pipeline Company, a Texas pipeline operator, and LifeLabs, a Canadian laboratory testing services provider. Pursuant to the Amended and Restated Bylaws of each of the Companies, Ms. Krause will serve as an Owner Director on their respective Boards of Directors on behalf of OMERS. Ms. Krause will not receive any director compensation from the Companies for her service as an Owner Director on the Boards, but will be reimbursed for out-of-pocket expenses.

 Paul McMillan, age 69, 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 46, 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 sustainability and climate strategy, governance and regulation.

 Aaron Rubin, age 46, 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.

 Steven Zucchet, age 58, 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.

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

 Audit Committee
 The Puget Energy and PSE Boards of Directors have both established an Audit Committee. Directors Richard Dinneny, Paul McMillan, Tom King, Jenine Krause 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.

 ITEM 11. EXECUTIVE COMPENSATION

 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 2023, nor were they formerly Company officers or had any relationship otherwise requiring disclosure. Each member of the Committee meets the independence requirements of the SEC and the New York Stock Exchange (NYSE).

 Compensation Discussion and Analysis
 This section provides information about the compensation program for the Company's named executive officers (Named Executive Officers) who are included in the Summary Compensation Table below. For 2023, the Company's Named Executive Officers and titles were:
 • Mary E. Kipp, President and Chief Executive Officer (CEO);
 • Daniel A. Doyle, interim Chief Financial Officer (CFO), effective September 26, 2023, serving as a consultant. Mr. Doyle previously served as Senior Vice President and CFO at the Company from 2011 until his retirement in 2021;
 • Kazi Hasan, former Executive Vice President and CFO who terminated employment effective September 26, 2023;
 • Lorna Luebbe, Senior Vice President, General Counsel and Chief Sustainability Officer;
 • Aaron August, Senior Vice President, Chief Customer and Transformation Officer, effective July 27, 2023;
 • Ronald J. Roberts, Vice President Energy Supply; and
 • Allan (Wade) Smith, former Executive Vice President and Chief Operating Officer, who terminated employment effective December 15, 2023.

 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 who are employees. Mr. Doyle is not an employee and does not participate in the programs listed below. Mr. Doyle's compensation is described in the Other Compensation section below.

 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 2023, 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 Role of Market Data, the Committee, with the support of Meridian, annually compares executive compensation levels to external market data from similar companies in our industry and generally targets each element of target total direct compensation (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 importance of providing retirement income. As such, the Committee reviews our retirement programs and provides benefits that are competitive with our peers.
 • 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, 83% of the target 2023 compensation of our CEO, Ms. 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, which are approved by the Board.
 • 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 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, recognizing that the Company operates in a highly competitive regional market. Individual executive pay position may vary from the 50th percentile as influenced by the factors below. Actual executive compensation depends significantly on Company performance results, and can result in below or above targeted 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 differs from that typically found in the market.

 Role of Market Data
 The Company uses market data compiled by Meridian to inform its pay decisions on base salary, target annual incentives and target long-term incentive awards. Market data is obtained from both industry-specific surveys and proxy statements of public companies selected for inclusion in the Company's custom executive compensation peer group. The market survey data were sourced from a select cut from the Willis Towers Watson 2022 Energy Services Survey, comprised of utility and other companies similar in size and scope of operations to PSE.

 The 26 companies in the custom market survey cut for 2023 pay decisions are the same as those used for the 2022 pay decisions and are shown below:

 Custom Survey Peer Group

 1.
 Allete

 10.
 Evergy
 19.
 PNM Resources

 2.
 Alliant Energy
 11.
 Eversource Energy
 20.
 Portland General Electric

 3.
 Ameren
 12.
 Hawaiian Electric Industries, Inc.
 21.
 PPL

 4.
 Atmos Energy
 13.
 NiSource
 22.
 South Jersey Industries

 5.
 Avista
 14.
 Northwestern Energy

 23.
 Southwest Gas

 6.
 Black Hills

 15.
 Oncor
 24.
 Spire

 CenterPoint

 16.
 OGE Energy
 25.
 UGI

 Cleco
 17.
 ONE Gas
 26.
 WEC Energy Group

 9.
 CMS Energy
 18.
 Pinnacle West Capital

 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 17 companies, all but one of which overlapped with the companies included in the market survey data. At the time of the benchmarking study, the median revenue of the executive compensation peers was $4.0 billion, which was comparable to PSE's annual revenues of $4.2 billion. The proxy peer group was reviewed by Meridian to assess the continued relevancy of the companies and based on their analysis recommended two companies to be added to the group.

 Proxy Peer Group

 1.
 Alliant Energy
 7.
 Eversource Energy
 13.
 PNM Resources

 2.
 Ameren
 8.
 Idacorp
 14.
 Portland General Electric

 3.
 Atmos Energy
 9.
 NiSource
 15.
 PPL*

 4.
 Avista
 10.
 OGE Energy*

 16.

 Spire

 5.
 CMS Energy
 11.
 ONE Gas

 17.

 WEC Energy Group

 6.
 Evergy
 12.
 Pinnacle West Capital

 *Added to the 2023 peer group.

 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 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.

 Base Salary Adjustments for 2023
 The Committee reviewed the base salaries of the Named Executive Officers in early 2023 and recommended base salary adjustments to the Board, except for Mr. August, whose salary was approved at hire in July 2023 and Mr. Doyle, whose

 compensation is described below under Other Compensation. The Board approved the Committee's salary recommendations as shown in the table below. The adjustments were effective March 1, 2023. Base salaries for 2023 generally remained at the 50th percentile of market among the comparator group.

 Name

 2022 Base Salary

 2023 Base Salary

 % Change

 $1,043,250
 $1,080,000
 3.5%

 570,257
 595,974
 4.5

 480,000
 496,800
 3.5

 N/A

 460,000
 —

 425,000
 439,875
 3.5

 630,000
 652,050
 3.5

 2023 Annual Incentive Compensation
 All PSE employees, including the Named Executive Officers (other than Mr. Doyle), are eligible to participate in an annual incentive program referred to as the "Goals and Incentive Plan". The plan is designed to incent our employees to achieve both (i) desired annual financial results, measured by EBITDA, calculated as earnings before interest, taxes, depreciation and amortization, and (ii) pre-established goals based on both a service quality commitment to customers and an employee safety measure. EBITDA was selected as a performance goal because it provides a financial measure of cash flows generated from the Company's annual operating performance.
 For 2023, the Company's service quality commitment was measured by performance against nine Service Quality Indicators (SQIs) covering three broad categories, set forth below. These are the same SQIs for which the Company is accountable to the Washington Commission. 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 www. PSE.com/PerformanceReportCards.
 The SQIs for 2023 were the same as those in 2022 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 (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 2023 were:
 • All employees view a monthly PSE People safety video, 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%.
 • Use of the hazard reporting system. To raise awareness of hazards in all areas of the Company (office, home or field), employees will use the hazard reporting system. The target is a 10% increase of submissions from the 2022 baseline number.
 • All employees complete an online mental health training course, consisting of four videos during 2023. The target completion rate is no less than 95%.
 Annual incentive funding is decreased if a SQI is not achieved. The employee safety measure functions similarly to the nine SQIs in determining the funding of the annual incentive plan. That is, if the safety measure is not achieved, annual incentive funding will be decreased by 10%, in the same way as a missed SQI.
 In 2023, 100% funding for the annual incentive plan required (i) achievement of 10 out of 10 customer service and safety measures (all nine SQIs and achievement of the safety measure) and (ii) target EBITDA performance. Nine of the ten customer service and safety measures were met. For the one SQI measure not met, System Average Interruption Duration Index (SAIDI), the Board considered the measure met for incentive purposes based on PSE's overall strong performance and the noteworthy progress achieved at improving reliability. EBITDA finished at 98.3% of target, so funding was less than 100%, as described further below.

 2023 Annual Incentive Plan Results
 For 2023, achievement of the corporate goals under the annual incentive plan was at 98.3% of target for EBITDA. PSE EBITDA was $1,487.6 million, and SQI and safety achievement was 10 out of 10, met or deemed met, leading to a funding level for 2023 of 91.4% for the annual incentive plan for the eligible Named Executive Officers.

 Funding levels for 2023 at maximum, target, and threshold are shown in the table below:
 Annual Incentive Performance Payout Scale and Actual Performance

 Performance Measure (Dollars in Millions)

 2023 EBITDA

 SQI, SAIDI& Safety*

 Funding Level

 Maximum
 $
 2,043.0

 10/10

 200%

 Target
 1,514.0

 10/10

 Threshold
 1,362.6

 6/10

 2023 Actual Performance

 1,487.6

 10/10

 91.4

 * Combined SQI and Safety results of 6/10 or better and minimum EBITDA of $1,326.6 million are required for any annual incentive plan funding
 SQI 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 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 is two times each Named Executive Officer's target incentive. Executives generally must be employed on the last day of the calendar year to receive a payment, except in the event of retirement, disability or death.
 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 2023. The adjustments for individual performance are noted in the "Bonus" column of the Summary Compensation table and did not materially change the amounts resulting from 2023 achievement of the corporate goals. The Board approved the incentive amounts shown below, which will be paid in March 2024:

 Name

 Target Incentive
 (% of Base Salary)

 2023 Actual
 Incentive Paid

 2023 Actual Incentive (% of Base Salary)

 115%

 $
 1,135,188

 105.0%

 Kazi Hasan*
 —
 —

 295,149
 59.0

 Aaron August*

 65*

 118,306
 26.0

 221,125
 50.0

 Allan (Wade) Smith*
 —
 —

 * Mr. August's annual incentive is prorated for time worked in 2023 since his hire. His target annual incentive is 65% of base salary. Mr. Hasan and Mr. Smith were not employed at December 31, 2023 and as a result, were not eligible for a 2023 annual incentive payment. Mr. Doyle did not participate in the annual incentive plan.

 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. Long term incentive plan (LTI Plan) grants are denominated and paid in cash, if at least threshold performance measures are met over a three-year performance cycle. Long term incentive performance measures can vary for each performance cycle.
 Long-term incentive payments for the 2021-2023 and 2022-2024 cycles 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 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 the three-year average ROE metric. ROE reflects the income earned on our equity investment.
 For the 2023-2025 cycle, the long term incentive program is based on three measures that are evaluated separately:
 • An environmental measure (carbon intensity) with a 10% weighting;
 • Strategic Initiatives with an overall 35% weighting; and
 • Total Return with a 55% weighting.
 The 2021-2023 and 2022-2024 LTI Plan payments ultimately paid may range from 0% to 200% of target, depending on performance; while the 2023-2025 LTI Plan payments may range from 0% to 173% of target, depending on performance.
 The Committee recommends for Board approval a targeted LTI grant value in dollars for each 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.
 Executives generally must be employed on the last day of the performance cycle to receive a cash payment under the LTI Plan, except in the event of retirement, disability or death.

 2023-2025 Long-Term Incentive Plan Target Awards
 Consistent with prior years, target LTI Plan awards for the 2023-2025 performance cycle were 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 $3,875,000 to align with market pay levels. Target LTI Plan award amounts for the 2023-2025 performance cycle are shown in the following table:

 Name

 Target Long Term Incentive ($)

 $3,875,000

 Kazi Hasan*
 1,200,000

 525,000

 380,000

 Allan (Wade) Smith*
 1,600,000

 * Mr. Hasan and Mr. Smith forfeited their LTI Plan grants upon termination of their employment in 2023.

 Details of the target grants and expected values at target, threshold and maximum performance levels can be found in the "2023 Grants of Plan-Based Awards" table below.

 Long-Term Incentive Plan Performance 2021-2023 Performance Cycle Results and Payouts
 The 2021-2023 performance cycle has now ended. Amounts payable as a result of award vesting are shown in the following table:
 • The threshold EBITDA goal of $3,902.9 million was satisfied for the performance cycle. Performance on the ROE component of the grant finished at 6.59%, which was 91.2% of target, above the plan's threshold for funding, but below target, which would have resulted in funding of 64.7% of target. The Committee recommended and the Board approved a payment of 105% of target funding level, in recognition of the Company's significant progress on clean energy objectives and other achievements that contribute toward the long term value of the company, resulting in the payment of the following LTI Plan amounts:

 Name

 Target Long Term Incentive
 ($)1

 2021-2023
 LTIP Paid2

 $2,548,200
 $2,675,610

 Kazi Hasan2

 750,000
 N/A

 74,186
 77,895

 Aaron August2

 262,500
 275,625

 165,880
 174,174

 Allan (Wade) Smith2

 950,000
 N/A

 1 Target LTI Plan incentive is the dollar target level set in 2021.
 2 In connection with Mr. August's commencement of employment in 2023, he was eligible to participate in the 2021-2023 performance cycle at a target amount that reflected reduced participation during the performance cycle but was intended to incentivize performance following commencement of employment. Mr. Hasan and Mr. Smith forfeited their 2021-2023 LTI Plan grants upon termination of their employment in 2023.

 Retirement Plans
 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 (other than Mr. Doyle) participated in the executive retirement plan, which is the Officer Restoration Benefit as part of the Deferred Compensation Plan for Key Employees during 2023. Additional information regarding the Officer Restoration Benefit and the Retirement Plan is shown in the "2023 Pension Benefits" table.

 Deferred Compensation Plan
 The Named Executive Officers are eligible to participate in the Deferred Compensation Plan for Key Employees (Deferred Compensation Plan). The Deferred Compensation Plan provides eligible executives an opportunity to defer up to 100% of base salary, annual incentive bonuses and earned LTI Plan awards, plus receive additional Company contributions made by PSE into an account that has three investment tracking fund choices. The funds mirror performance in major asset classes of bonds, stocks, and an interest crediting fund that changes rates quarterly. The Deferred Compensation Plan is intended to allow the executives to defer current income, without being limited by the Internal Revenue Code contribution limitations for 401(k) plans and therefore have a deferral opportunity similar to other employees as a percentage of eligible compensation. The Company contributions are also intended to restore benefits not available to executives under PSE's tax-qualified plans due to Internal Revenue Code limitations on compensation and benefits applicable to those plans. Additional information regarding the Deferred Compensation Plan is shown in the "2023 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, 2023.

 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 reviewing recent market target compensation for the CEO position, and actual performance of the Company over the period 2021-2023, the Committee identified a gap in actual pay for Ms. Kipp compared to market and recommended an additional payment, which the Board approved for 2023 in the amount of $1,593,000.
 Mr. Doyle, who previously retired as Senior Vice President and CFO from the Company in 2021, is CFO on a contract basis, beginning September 26, 2023. Mr. Doyle will be paid $750,000 for the duration of his time as CFO during 2023 and 2024, as well as housing expenses.
 In connection with his offer of employment, Mr. August was eligible to receive a signing bonus of $390,000 and a relocation payment of $175,000, grossed up for taxes, to assist with moving expenses. Both amounts must be repaid if Mr. August resigns or is terminated for cause within 24 months of employment. Subject to continued employment, Mr. August is eligible to receive a retention bonus of $250,000 in March 2024. In addition to participation in the 2021-2023 performance cycle under the LTI Plan, Mr. August is also eligible to participate in the 2022-2024 performance cycle based on a target grant value of $393,750 and in the 2023-2025 performance cycle for which disclosure is provided above.
 The eligible Named Executive Officers 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 compensation and did not exceed $10,000 in total for each Named Executive Officer in 2023. 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 annual incentives, because 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.

 Incentive Compensation Recovery Policy
 The Board adopted an Incentive Compensation Recovery Policy, effective October 2, 2023, that is intended to comply with Rule 10D-1 of the Securities Exchange Act of 1934 and NYSE listing standards. The policy applies to current and former executive officers of the Company as defined in Rule 10D-1, including the Named Executive Officers, and will be administered by the Committee. In the event the Company is required to prepare an accounting restatement to correct material noncompliance with a financial reporting requirement under U.S. federal securities laws, it is the Company's policy to recover erroneously awarded incentive-based compensation received by its executive officers in accordance with the terms of the policy.

 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 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 2023, except Ms. Hamm who joined May 11, 2023.
 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, 2023, for filing with the SEC.

 Compensation and Leadership
 Development Committee of

 Steven Zucchet, chair,
 Scott Armstrong
 Barbara Gordon
 Julia Hamm, effective May 11, 2023
 Aaron Rubin

 Summary Compensation Table
 The following information is provided for the year ended December 31, 2023, (and for prior years where applicable) with respect to the Named Executive Officers during 2023. The positions listed below are at Puget Energy and PSE, except that Mr. August, Mr. Roberts and Mr. Smith are executives of PSE only. Positions listed are those held by the Named Executive Officers as of December 31, 2023 (or for former Named Executive Officers, immediately prior to termination of employment). Salary and incentive compensation includes amounts deferred at the executive's election.

 Name and Principal Position
 Year
 Salary
 Bonus1

 Stock Awards
 Option Awards
 Non-Equity Incentive Plan Compensation2

 Change in Pension Value and Nonqualified Deferred Compensation Earnings3

 All Other Compensation4

 Total

 2023

 $
 1,072,507
 $
 —
 $
 —
 $
 —
 $
 3,810,798
 $
 —
 $
 1,687,813
 $
 6,571,118

 President and,
 2022

 991,585
 176,361
 —
 —
 3,505,307
 —
 87,678
 4,760,931

 Chief Executive Officer5

 2021

 923,923
 —
 —
 —
 3,388,708
 —
 101,614
 4,414,245

 Dan Doyle, Interim CFO (effective 9/26)6

 2023

 —
 —
 —
 —
 —
 —
 360,265
 360,265

 Kazi Hasan, Former CFO (until 9/26)

 2023

 459,123
 —
 —
 —
 —
 1,615,480
 2,324,603

 Executive Vice President and Chief Financial Officer10

 2022

 542,348
 308,685
 —
 —
 705,924
 —
 54,849
 1,611,806

 Lorna Luebbe, SVP General Counsel and Chief Sustainability Officer8

 2023

 493,371
 —
 —
 —
 373,044
 5,269
 32,201
 903,885

 Aaron Alan August, SVP Chief Customer and Strategy Officer7

 2023

 177,727
 390,000
 —
 —
 393,931
 —
 248,932
 1,210,590

 Ronald J Roberts, VP Energy Supply9

 2023

 436,838
 120,102
 —
 —
 395,299
 11,062
 38,381
 1,001,682

 Allan (Wade) Smith, former Executive Vice President and,

 2023

 647,548
 780,000
 —
 —
 —
 —
 35,367
 1,462,915

 Chief Operating Officer (until 12/15)11

 2022

 262,500
 900,000
 —
 —
 179,895
 —
 223,747
 1,566,142

 1.Reflects individual performance above target as described in the "Compensation Discussion and Analysis," section titled "2023 Annual Incentive Plan Results" for Ms. Kipp. For Mr. Hasan reflects a retention bonus of $250,000 paid in 2023 in connection with the terms of his 2021 offer of employment.. For Mr. August reflects a signing bonus paid in connection with commencement of employment in 2023. For Mr. Roberts reflects a retention bonus paid in 2023. For Mr. Smith reflects retention bonuses paid in connection with commencement of employment in 2022, in the amounts of $630,000 and $150,000.
 2.For 2023, reflects annual cash incentive compensation paid under the 2023 Goals and Incentive Plan and cash incentive compensation paid under the LTI Plan for the 2021-2023 performance cycle. Cash incentive amounts were paid in early 2024 or deferred at the executive's election. The 2023 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 2024.
 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 2023, updated interest rates relative to those used for 2022 have generally resulted in smaller increases in value than in prior years. Information regarding these pension plans is set forth in further detail under "2023 Pension Benefits." The change in pension value amounts for 2023 are: Ms. Kipp, $0; Mr. August, $0; Ms. Luebbe, $5,269; and Mr. Roberts, $11,062. Mr. Doyle retired from the company in 2021 and is not accruing any additional pension benefits.
 4.All Other Compensation for 2023 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. Doyle was Senior Vice President and CFO at the Company from 2011 until his retirement in 2021 and returned as Interim CFO under contract on September 26, 2023.
 7.Mr. August joined PSE and Puget Energy as Senior Vice President and Chief Customer and Transformation Officer on July 27, 2023.
 8.Ms. Luebbe has worked at PSE since 2002 and became Senior Vice President General Counsel and Chief Sustainability Officer on December 1, 2022.
 9.Mr. Roberts has worked at PSE since 2010 and became Vice President Energy Supply on November 9, 2020.
 10.Mr. Hasan joined PSE and Puget Energy as Senior Vice President and Chief Financial Officer on June 24, 2021 and terminated employment effective September 26, 2023.
 11.Mr. Smith joined PSE and Puget Energy as Executive Vice President and Chief Operating Officer on July 18, 2022 and terminated employment effective December 15, 2023.

 Detail of All Other Compensation
 Name

 Perquisites and Other
 Personal Benefits1

 Registrant Contributions
 to Defined Contribution
 and Deferred Compensation
 Plans2

 Other3

 $
 5,000

 $
 77,517

 $
 1,605,297

 Daniel A. Doyle

 —
 —
 360,265

 7,500
 47,344
 1,560,636

 —
 23,899
 8,301

 175,000
 3,450
 70,482

 —
 23,848
 14,533

 —
 25,350
 10,017

 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. August, also includes a relocation payment of $175,000, as described in "Other Compensation" of the "Compensation Discussion and Analysis."
 2.Includes Company contributions during 2023 to PSE's Investment Plan (a tax qualified 401(k) plan) and the Deferred Compensation Plan. Company 4401(k) contributions are as follows: Ms. Kipp, $27,050; Mr. August, $3,450; Ms. Luebbe, $22,767; Mr. Roberts, $17,865; Mr. Hasan, $27,050; and Mr. Smith, $25,350. Company contributions to the Deferred Compensation Plan are as follows: Ms. Kipp, $50,467; Mr. August, $0; Ms. Luebbe, $1,132; Mr. Roberts, $5,982; Mr. Hasan, $20,294; and Mr. Smith, $0.
 3.Reflects the value of imputed income for life insurance and Company paid premiums on supplemental disability insurance for all Named Executive Officers. For Ms. Kipp also includes a special payment in 2023 of $1,593,000 as described in the "Compensation Discussion and Analysis," "Other Compensation". For Mr. August, also includes the amount of a tax gross-up on relocation payments of $67,934, as described in the "Compensation Discussion and Analysis," "Other Compensation". For Mr. Doyle includes amounts paid under contract for services and housing expenses. For Mr. Hasan, also includes a severance payment.

 2023 Grants of Plan-Based Awards
 The following table presents information regarding 2023 grants of non-equity annual incentive awards and LTI Plan awards, including, as applicable, the range of potential payouts for the awards. Mr. Doyle is not eligible for these grants. Mr. Hasan and Mr. Smith forfeited eligibility for their 2023 grants when they terminated employment in 2023.

 Estimated Future Payouts under Non-Equity
 Incentive Plan Awards

 Name

 Grant Date

 Grant Target Value

 Threshold

 Target

 Maximum

 $
 372,600

 $
 2,242,000

 $
 2,484,000

 3,875,000

 2,131,250

 3,875,000

 6,684,375

 $
 143,034
 $
 476,779
 $
 953,558

 1,200,000
 660,000
 1,200,000
 2,070,000

 $
 96,876

 $
 322,920

 $
 645,840

 330,000

 1,035,000

 7/27/2023

 $
 38,802
 $
 129,342
 $
 258,683

 LTI Plan 2021-20233

 7/7/2023

 262,500
 131,250
 262,500
 525,000

 LTI Plan 2022-20243

 7/27/2023

 393,750
 196,875
 393,750
 787,500

 7/27/2023

 525,000
 288,750
 525,000
 905,625

 $
 65,981

 $
 219,938

 $
 439,875

 380,000

 209,000

 380,000

 655,500

 $
 156,492
 $
 521,640
 $
 1,043,280

 1,260,000
 693,000
 1,260,000
 2,173,500

 1.As described in the "Compensation Discussion and Analysis," the 2023 Goals and Incentive Plan had dual funding triggers in 2023 of $1,362.6 million EBITDA and SQI performance of 6/10. Payment would be $0 if either trigger is not met. The threshold estimate assumes $1,362.6 million EBITDA and SQI/Safety measure performance at 6/10. The target estimate assumes $1,514.0 million EBITDA and SQI/Safety measure performance at 10/10. The maximum estimate assumes $2,043.0 million EBITDA or higher and SQI/Safety measure performance at 10/10. The award for Mr. August was pro-rated for time worked in 2023 per the plan.
 2.As described in the "Compensation Discussion and Analysis," LTI Plan grants for the 2023-2025 performance cycle were allocated to three measures. The environmental measure (10% weighting) funds at 100% if met; the Strategic Initiatives measure (35% weighting) funds at 50% at threshold, 100% at target and 150% at maximum; the Total Return measure (55% weighting) funds at 50% at threshold, 100% at target and 200% at maximum. The performance measures are evaluated independently, but if each finished at threshold, target and maximum, the overall funding levels would be 55%, 100%, and 173%, respectively.
 3.In connection with Mr. August's commencement of employment, 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.".

 2023 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. None of the named executives are eligible for the SERP 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 Officer Restoration Benefit. 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, Mr. Hasan and Mr. August, who participate just in the Officer Restoration Benefit (which is reported separately below). Mr. Hasan was paid the Officer Restoration Benefit amount with his deferred compensation balance upon termination. Mr. Smith had not vested in their retirement benefits prior to leaving the Company and any previously reported unvested amounts were forfeited.

 Name

 Plan Name

 Number of Years
 Credited Service

 Present Value
 of Accumulated
 Benefit 1

 Payments
 During Last
 Fiscal Year

 Mary E. Kipp2

 Retirement Contribution

 4.3

 $
 —

 $
 —

 Restoration Benefit

 4.3

 —

 —

 Retirement Contribution

 21.2

 445,582

 —

 Restoration Benefit

 21.2

 —

 —

 Retirement Plan

 0.4

 —

 —

 Restoration Benefit

 0.4

 —

 —

 Retirement Plan

 13.2

 361,834

 —

 Restoration Benefit

 13.2

 —

 —

 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 are the actuarial present values as of December 31, 2023, of the benefits earned as of that date and payable at normal retirement age (age 65 for the Retirement Plan). Future cash balance interest credits are assumed to be 4.0% annually. The discount assumption is 5.30%, and the post-retirement mortality assumption is based on the 2024 417(e) unisex mortality table. Annuity benefits are converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 3.62%, 4.46%, and 4.52% (the 24-month average of the underlying rates as of September 2023), except that payments assumed to occur during 2024 use segment rates in effect for 2024 (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 2023. In order to determine the change in pension values for the Summary Compensation Table, the values of the Retirement Plan benefits were also calculated as of December 31, 2022, for the benefits earned as of that date using the assumptions used for financial reporting purposes for 2022. These assumptions included assumed cash balance interest credits of 4.0%, a discount assumption of 5.60% and post-retirement mortality assumption based on the 2023 417(e) unisex mortality table. Annuity benefits were converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 1.41%, 3.09%, and 3.58% (the 24-month average of the underlying rates as of September 2022). Other assumptions used to determine the value as of December 31, 2022, were the same as those used for December 31, 2023.
 2.None of the Named Executive Officers have SERP benefits as that plan was closed prior to their joining PSE. Ms. Kipp, Mr. Hasan and Mr. August 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, 2023 these 401(k) accounts had values of: Ms. Kipp, $49,930 and Mr. Hasan, $23,637. Mr. August's account will reflect balances in 2024. All of the Named Executive Officers 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, 2023 are: Ms. Kipp, $138,898; Ms. Luebbe, $1,168; and Mr. Roberts, $10,044. Mr. August's first Officer Restoration account contribution will be made in 2024.

 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 2023, the limit was $330,000. For 2024, the limit is $345,000. 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 2023 and 2024, 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 (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, 2023, all the Named Executive Officers, eligible for the Retirement Plan, except Mr. Smith, were vested in their benefits under the Retirement Plan and, hence, would be eligible to commence benefit payments upon termination. Ms. Kipp and Mr. August are not eligible for the Retirement Plan, as each elected at employment to have the Company's 4% retirement contribution made to the Company's 401(k) plan. Prior to leaving the Company, Mr. Hasan was not eligible for the Retirement Plan and Mr. Smith had not vested in his benefits under the Retirement Plan and, accordingly, forfeited those benefits upon termination.
 The normal form of benefit payment for unmarried participants is a straight life annuity providing monthly payments for the remainder of the participant's life, with no death benefits. The straight life annuity payable on or after the participant's normal retirement age is actuarially equivalent to the balance in the participant's Cash Balance Account as of the date of distribution. For married participants, the normal form of benefit payment is an actuarially equivalent joint and 50% survivor annuity with a "pop-up" feature providing reduced monthly payments (as compared to the straight life annuity) for the remainder of the participant's life and, upon the participant's death, monthly payments to the participant's surviving spouse for the remainder of the spouse's life in an amount equal to 50% of the amount being paid to the participant. Under the pop-up feature, if the participant's spouse predeceases the participant, the participant's monthly payments increase to the level that would have been provided under the straight life annuity. In addition, the Retirement Plan provides several other annuity payment options and a lump sum payment option that can be elected by participants. All payment options are actuarially equivalent to the straight life annuity. However, in no event will the amount of the lump sum payment be less than the balance in the participant's Cash Balance Account as of the date of distribution (in some instances the amount of the lump sum distribution may be greater than the balance in the Cash Balance Account due to differences in the mortality table and interest rates used to calculate actuarial equivalency).
 If a vested participant dies before his or her Retirement Plan benefit is paid, or commences to be paid, then the participant's Retirement Plan benefit will be paid to his or her beneficiary(ies). If a participant dies after his or her Retirement Plan benefit has commenced to be paid, then any death benefit will be governed by the form of payment elected by the participant.

 Supplemental Executive Retirement Plan
 The SERP provides a benefit to participating Named Executive Officers that supplements the retirement income provided to the executives by the Retirement Plan. The Company closed the SERP plan to new participants as of August 1, 2019. None of the Named Executive Officers participate in the SERP

 Officer Restoration Benefit
 The Officer Restoration Benefit provides a benefit to participating officers that supplements the retirement income provided to the executives. All the Named Executive Officers 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.

 2023 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 2023 and year-end account balances under the Deferred Compensation Plan.

 Name

 Executive Contributions
 in 20231

 Registrant Contributions in 20232

 Aggregate Earnings
 in 20233

 Aggregate Withdrawals/
 Distributions

 Aggregate Balance at December 31, 20234

 $
 64,350

 $
 50,467

 $
 346,786

 $
 —

 $
 2,831,995

 38,248
 20,294
 7,612
 (134,587)
 —

 —
 1,132
 —
 1,168

 —
 —
 —
 —
 —

 69,894
 5,982
 39,506
 —
 324,500

 —
 —
 —
 —
 —

 1.The amount in this column reflects elective deferrals by the executive of salary, annual incentive compensation or LTI Plan awards paid in 2023. Deferred salary amounts are: Ms. Kipp, $64,350; Mr. Hasan, $22,956; Mr. August, $0; Ms. Luebbe, $0; Mr. Roberts, $69,894; and Mr. Smith, $0. Deferred annual incentive compensation and LTI Plan award amounts are $0 for all Named Executives, except for Mr. Hasan who deferred $7,042 in incentive compensation and $8,250 in LTI Plan awards. The amounts are also included in the applicable column of the Summary Compensation Table for 2023.
 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 2023.
 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. None of the executives received above market earnings on these amounts.
 4.Of the amounts in this column, the amounts in the table below have also been reported in the Summary Compensation Table for 2023, 2022, and 2021.

 Name
 Reported for 2023

 Reported for 2022

 Reported for 2021

 $
 114,816

 $
 1,016,624

 $
 1,084,486

 58,542
 46,452
 2,125

 1,132
 —
 —

 —
 —
 —

 75,877

 —

 —

 —
 —
 —

 Deferred Compensation Plan
 The Named Executive Officers are eligible to participate in the Deferred Compensation Plan and may defer up to 100% of base salary, annual incentive compensation and LTI Plan payments. In addition, each year, executives are eligible to receive Company contributions under the Deferred Compensation Plan to restore benefits not available to them under the Company's tax-qualified plans due to limitations imposed by the Internal Revenue Code. The annual investment plan restoration amount equals the additional matching and any other employer contribution under the 401(k) plan that would have been credited to an electing executive's 401(k) plan account if the Internal Revenue Code limitations were not in place and if deferrals under the

 Deferred Compensation Plan were instead made to the 401(k) plan. The annual cash balance restoration amount equals the actuarial equivalent of any reductions in an executive's accrued benefit under the Retirement Plan due to Internal Revenue Code limitations or as a result of deferrals under the Deferred Compensation Plan. An executive must generally be employed on the last day of the year to receive these Company contributions, unless he or she retires or dies during the year in which case the Company will contribute a prorated amount.
 The Named Executive Officers choose how to credit deferred amounts among three investment tracking funds. The tracking funds mirror performance in major asset classes of bonds, stocks, and a money market index. For participants with deferrals prior to 2012, an interest crediting fund was available; however this does not apply to any of 2023's Named Executive Officers. The tracking funds differ from the investment funds offered in the 401(k) plan. The 2023 calendar year returns of these tracking funds were:

 Vanguard Total Bond Market Index

 5.72
 %

 Vanguard 500 Index

 26.24

 Vanguard Money Market Index

 5.09

 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 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.

 LTI Plan Awards
 If a Named Executive Officer's employment terminates due to disability or death, the executive or his or her estate will be paid a pro-rata portion of LTI Plan awards that were granted in a prior year. In the case of retirement at normal retirement age or approved early retirement, pro-rata LTI Plan awards will be paid in the first quarter following the year of retirement, based

 on performance through the prior year. In the event of a change in control in which awards are not assumed or substituted, outstanding LTI Plan awards will be paid on a pro-rata basis at the higher of (i) target performance or (ii) actual performance achieved during the performance cycle ending with the fiscal quarter that precedes the change in control.

 Employment Agreements
 PSE has no employment agreements with any 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, 2023. 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. As Mr. Hasan and Mr. Smith were not employed as of December 31, 2023 and Mr. Doyle is not an employee, they are not included in the table:

 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

 $
 —

 $
 —

 $
 —
 $
 —

 $
 —

 Long Term Incentive Plan

 6,305,950

 6,305,950

 —

 5,781,383

 5,781,383

 Supplemental Life Insurance

 —

 —

 —

 —

 4,044,000

 Total Estimated Incremental Value

 $
 6,305,950

 $
 6,305,950

 $
 —

 $
 5,781,383

 $
 9,825,383

 $
 —

 $
 —

 $
 —

 $
 —

 $
 —

 Long Term Incentive Plan

 540,186

 540,186

 Supplemental Life Insurance
 —
 —
 —
 —
 1,142,640

 Total Estimated Incremental Value
 $
 540,186

 $
 540,186

 $

 $

 $
 1,616,051

 $
 —
 $
 —
 $
 —
 $
 —
 $
 —

 Long Term Incentive Plan
 699,563
 699,563
 —
 643,305
 643,305

 Supplemental Life Insurance

 —

 —

 —

 —

 1,058,000

 Total Estimated Incremental Value

 $
 699,563

 $
 699,563

 $
 —

 $
 643,305

 $
 1,701,305

 $
 —

 $
 —

 $
 —

 $
 —

 $
 —

 Long Term Incentive Plan

 472,180

 472,180

 Supplemental Life Insurance

 —

 —

 —

 —

 1,011,713

 Total Estimated Incremental Value

 $
 472,180

 $
 472,180

 $

 $

 $
 1,444,610

 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 2023, our last completed fiscal year:
 • The annual total compensation of our CEO reported in the 2023 Summary Compensation Table, was $6,571,118.
 • The median of the annual total compensation of all our employees (excluding our CEO) was $148,119.

 As a result, for 2023 the ratio of annual total compensation of our Chief Executive Officer to the median of our annual total compensation of all employees was 44.4.
 We identified our median employee by examining the total cash compensation we paid during 2023 to all individuals, excluding our CEO, who were employed by us on December 31, 2023, which totaled approximately 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 2023, we calculated annual total compensation for such employee for 2023 using the same methodology we use for our named executive officers as set forth in

 the 2023 Summary Compensation Table in accordance with the requirements of Item 402 (c)(2)(x) of Regulation S-K. Annual total compensation for 2023 for our median employee included annual salary, annual incentives, and company contributions towards benefits including retirement. Annual total compensation for 2023 for our CEO consists of the amount reported in the "Total" column of our 2023 Summary Compensation Table.

 Director Compensation for Fiscal Year 2023
 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 2023 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: Grant Hodgkins, Jenine Krause, Chris Parker, Aaron Rubin, and Steven Zucchet.
 As described in further detail below, the Company's non-employee director compensation program in 2023 consisted of quarterly retainer cash fees of $45,500. Additional quarterly retainer amounts associated with serving as Chair of the Board, chairing Board committees, serving on the Audit Committee and meeting fees were also paid in cash.

 Name

 Fees Earned
 Nonqualified
 Deferred
 Compensation
 Earnings1

 Total

 Scott Armstrong

 $
 261,800

 $
 —

 $
 261,800

 Richard Dinneny

 191,000

 —
 191,000

 Barbara Gordon

 204,400

 —

 204,400

 Christine Gregoire
 166,833
 166,833

 Julia Hamm
 123,733
 —
 123,733

 Thomas King

 191,000

 —

 191,000

 Paul McMillan

 206,000

 —

 206,000

 Diana Rakow

 187,000

 —

 187,000

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

 Non-employee Director Compensation Program
 The 2023 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 2023 compensation program for non-employee directors was as follows:
 1.A base cash quarterly retainer fee of $45,500;
 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).

 In 2023, non-employee directors were paid the following additional cash quarterly retainer fees:
 1.Independent Board Chairman, $18,750;
 2.Chair of the Compensation and Leadership Development Committee, $5,000;
 3.Chair of the Governance Committee, $5,000;
 4.Chair of the Business Planning Committee, $5,000
 5.Chair of the Audit Committee, $5,000; and
 6.Each member of the Audit Committee other than the chair, $1,250.

 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 IRS Section 501(c)(3) tax exempt status and are located in and served the people of PSE's service territory in Washington.

 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.

 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, 2023, 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 March 5, 2024.

 Beneficial Ownership Table of Puget Energy and PSE

 Number of Beneficially
 Owned Shares

 Name

 Puget Equico LLC and affiliates
 2001, 2

 —

 —

 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 March 5, 2024:
 • 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 May 12, 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 May 12, 2015, May 19, 2020, June 14, 2020 and March 17, 2022.

 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 Ethics and 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 Ethics and Compliance Officer will be reviewed according to the following procedures:
 1.If the Chief Ethics and 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 Ethics and 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.
 Dan Koch, former Vice President of Energy Delivery who reported to the Chief Executive Officer for a period of time during the year ended December 31, 2023, is married to Catherine Koch, who is sole owner of Reimagine Energy Consulting. Reimagine Energy Consulting was paid $0.3 million for services provided to PSE in 2023 by Ms. Koch. This work was performed under the supervision of PSE's Senior Vice President of External Affairs.

 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, Barbara Gordon, and Christine Gregoire (members of the Boards of both Puget Energy and PSE) and 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 which is less than the greater of $1.0 million or one percent of such other company's consolidated gross revenue, determined for the most recent fiscal year. These categorical standards will not apply, however, to the extent that Puget Energy or PSE would be required to disclose an arrangement as a related person transaction pursuant to Item 404 of Regulation S-K.
 The Boards considered all relationships between its directors and Puget Energy and PSE (and their respective subsidiaries), including some that are not required to be disclosed in this report as related-person transactions. Mr. Armstrong and Ms. 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, 2023, and 2022 were as follows:

 2023
 2022

 PSE
 PSE

 Audit fees1

 $
 3,138
 $
 2,848
 $
 2,881
 $
 2,611

 Audit related fees2

 Other fees3

 Total
 $
 3,426
 $
 3,136
 $
 3,180
 $
 2,714

 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 2023 fees are estimated and include an aggregate amount of $2.2 million billed to Puget Energy and $2.0 million billed to PSE through December 2023.
 2.Consists of work performed in connection with registration statements and other regulatory audits.
 3.Consists of software and research tools, as well as sustainability reporting fees in 2023.
 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 2023 and 2022, all audit and non-audit services were pre-approved.

 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, 2023, 2022, and 2021, 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.

 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.

 3.1

 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).

 3.2

 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., as amended by the First Amendment to the Amended and Restated Bylaws of Puget Energy Inc., dated January 6, 2022 (incorporated herein by reference to Exhibit 3.3 to Puget Energy's Current Report on Form 10-K, dated February 25, 2022, Commission File No. 1-16305).

 3.4

 Amended and Restated Bylaws of Puget Sound Energy, Inc., as amended by the First Amendment to the Amended and Restated Bylaws of Puget Sound Energy, Inc. dated January 6, 2022 (incorporated herein by reference to Exhibit 3.4 to Puget Sound Energy's Current Report on Form 10-K, dated February 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 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 Sound Energy's Current Report on Form 8-K, dated November 2, 2000.

 Commission File No. 1-4393; Exhibit 4.2 to Puget Sound Energy's Current Report on Form 8-K dated May 28, 2003.

 Commission File No. 1-4393; Exhibit 4.28 to Puget Sound Energy's Report on Form 10-K for the fiscal year ended December 31, 2004.

 Commission File No. 1-4393; Exhibit 4.1 to Puget Sound Energy's Current Report on Form 8-K, dated May 23, 2005.

 Commission File No. 1-4393; Exhibit 4.30 to Puget Sound Energy's Report on Form 10-K for the fiscal year ended December 31, 2005.

 ***

 Commission File No. 1-4393); Exhibit 4.4 to Post-Effective Amendment No. 2 to Puget Sound Energy's Registration Statement on Form S-3, filed February 9, 2009.

 Registration No. 333-132497-01; Exhibit 4.1 to Puget Sound Energy's Report on Form 8-K, dated September 13, 2006.

 ***

 Commission File No. 1-4393; Exhibit 4.1 to Puget Sound Energy's Report on Form 10-K for the fiscal year ended December 31, 2007. Commission File No. 1-4393; 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).

 Exhibit 4.4 and 4.6: 4.4, 4.6.

 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).

 4.16

 Indenture between Wells Fargo Bank, National Association and Puget Energy, Inc. dated as of December 6, 2010 (incorporated by reference to Exhibits 4.1 and 4.2 to Puget Energy's Current Report on Form 8-K, filed December 7, 2010, Commission File No. 1-16305).

 4.17

 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).

 4.18

 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).

 4.19

 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).

 4.20

 Trust Indenture, dated as of May 1, 2013 (the "Indenture"), by and between the City of Forsyth, Rosebud County, Montana 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).

 4.21

 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).

 4.22

 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).

 4.23

 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).

 4.24

 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).

 ***
 10.8
 Agreement to Amend Power Sales Contracts dated July 30, 1963 between Public Utility District No. 2 of Grant County, Washington and Puget Sound Energy, Inc., relating to the Wanapum Development (incorporated herein by reference to Exhibit 10.8 to Puget Sound Energy's Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).

 ***
 10.9
 Power Sales Contract executed as of September 18, 1963 between Public Utility District No. 1 of Douglas County, Washington and Puget Sound Energy, Inc., relating to the Wells Development (incorporated herein by reference to Exhibit 10.9 to Puget Sound Energy's Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).

 ***
 10.10
 Construction and Ownership Agreement dated as of July 30, 1971 between The Montana Power Company and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 10.10 to Puget Sound Energy's Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).

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

 ***
 10.12
 Contract dated June 19, 1974 between Puget Sound Energy, Inc. and P.U.D. No. 1 of Chelan County (incorporated herein by reference to Exhibit 10.12 to Puget Sound Energy's Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).

 ***
 10.13
 Transmission Agreement dated April 17, 1981 between the Bonneville Power Administration and Puget Sound Energy, Inc. (Colstrip Project) (incorporated herein by reference to Exhibit (10)-55 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).

 ***
 10.14
 Transmission Agreement dated April 17, 1981 between the Bonneville Power Administration and Montana Intertie Users (Colstrip Project) (incorporated herein by reference to Exhibit (10)-56 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).

 ***
 10.15
 Ownership and Operation Agreement dated as of May 6, 1981 between Puget Sound Energy, Inc. and other Owners of the Colstrip Project (Colstrip 3 and 4) (incorporated herein by reference to Exhibit (10)-57 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).

 *

 10.16

 Colstrip Project Transmission Agreement dated as of September 27, 2013 among Northwestern Corporation, Puget Sound Energy, Inc. and Avista Corporation, Portland General Electric Company and PacifiCorp.

 ***
 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 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).

 ***
 10.21

 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).

 ***
 10.22

 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).

 ***
 10.23

 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).

 10.24

 Amendment to Gas Transportation Service Contract dated July 31, 1991 between Washington Natural Gas Company and Northwest Pipeline Corporation (incorporated herein by reference to Exhibit 10-E.2 to Washington Natural Gas Company's Form 10-K for the fiscal year ended September 30, 1995, Commission File No. 1-11271).

 10.25

 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).

 10.26

 Product Sales Contract dated December 13, 2001 and Amendment No. 1 thereto, between Public Utility District No. 2 of Grant County, Washington, and Puget Sound Energy, Inc., relating to the Priest Rapids Project (incorporated herein by reference to Exhibit 10-1 to Puget Sound Energy's Report on Form 10-Q for the quarter ended June 30, 2002, File No. 1-4393).

 10.27

 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).

 10.28

 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).

 **

 10.29

 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).

 **

 10.30

 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).

 **

 10.31

 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).

 * **

 10.32

 Summary of Director Compensation.

 **

 10.33

 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).

 * **

 10.34

 Amendment to Puget Sound Energy, Inc. Supplemental Death Benefit Plan for Executive Employees.

 **

 10.35

 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).

 10.36

 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. (incorporated by reference to Exhibit 10.1 to Puget Energy's Current Report on Form 8-K, filed May 23, 2022, Commission File No. 1-16305).

 10.37

 Amended and Restated Credit Agreement dated May 16, 2022, among Puget Sound Energy, Inc., as Borrower, Mizuho Bank, Ltd., as Administrative Agent, and the lenders party thereto. (incorporated by reference to Exhibit 10.2 to Puget Sound Energy's Current Report on Form 8-K, filed May 23, 2022, Commission file No. 1-4393).

 *
 21.1

 Subsidiaries of Puget Energy, Inc.

 *
 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.

 *
 31.2

 Certification of Puget Energy, Inc. - Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 – Daniel A. Doyle.

 *
 31.3

 Certification of Puget Sound Energy, Inc. - Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 – Mary E. Kipp.

 *
 31.4

 Certification of Puget Sound Energy, Inc. – Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 – Daniel A. Doyle.

 *
 32.1

 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 – Mary E. Kipp.

 *
 32.2

 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 – Daniel A. Doyle.

 *

 97.1

 Puget Energy, Inc. and Puget Sound Energy, Inc. NYSE Executive Compensation Recoupment Policy.

 *

 *
 101.INS

 *
 101.SCH

 *
 101.CAL

 *
 101.DEF

 *
 101.LAB

 *
 101.PRE

 *

 *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.

 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.

 /s/ Mary E. Kipp

 /s/ Mary E. Kipp

 President and Chief Executive Officer

 President and Chief Executive Officer

 Date:

 Date:

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

 (Puget Energy and PSE unless otherwise noted)

 /s/ Mary E. Kipp
 President and

 (Mary E. Kipp)
 Chief Executive Officer

 /s/ Daniel Doyle
 Chief Financial Officer

 (Daniel Doyle)

 /s/ Stacy Smith
 Controller and Principal Accounting Officer

 (Stacy Smith)

 /s/ Scott Armstrong

 (Scott Armstrong)

 /s/ Richard Dinneny

 (Richard Dinneny)

 /s/ Barbara Gordon

 (Barbara Gordon)

 /s/ Christine Gregoire

 (Christine Gregoire)

 /s/ Julia Hamm

 (Julia Hamm)

 /s/ Grant Hodgkins

 (Grant Hodgkins)

 /s/ Tom King

 (Tom King)

 /s/ Jenine Krause

 (Jenine Krause)

 /s/ Paul McMillan

 (Paul McMillan)

 /s/ Chris Parker

 (Chris Parker)

 /s/ Diana Birkett Rakow

 Director of PSE Only

 (Diana Birkett Rakow)

 /s/ Aaron Rubin

 (Aaron Rubin)

 /s/ Steven Zucchet

 (Steven Zucchet)