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, 2024

 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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 N/A

 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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 /X/

 Yes
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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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 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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 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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 Yes
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 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 Obligation

 aMW
 Average Megawatt

 ASC
 Accounting Standards Codification

 ASU
 Accounting Standards Update

 BPA
 Bonneville Power Administration

 CAA

 Clean Air Act

 CCA
 Washington Climate Commitment Act

 CEIP
 Clean Energy Implementation Plan

 CETA
 Washington Clean Energy Transformation Act

 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
 U.S. 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

 IBEW
 International Brotherhood of Electrical Workers

 IOU

 Investor Owned Utility

 IRP
 Integrated Resource Plan

 IRS
 Internal Revenue Service

 ISDA
 International Swaps and Derivatives Association

 ISP

 Integrated System Plan

 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

 MMBtu
 One Million British Thermal Units

 MW
 Megawatt (one MW equals one thousand kW)

 MWh
 Megawatt Hour (one MWh equals one thousand kWh)

 MYRP
 Multi-Year Rate Plan

 NAESB
 North American Energy Standards Board

 NOAA
 National Oceanic and Atmospheric Administration

 NPNS
 Normal Purchase Normal Sale

 NWP
 Northwest Pipeline, LLC

 NYSE
 New York Stock Exchange

 OCI
 Other Comprehensive Income

 PCA
 Power Cost Adjustment

 PCORC
 Power Cost Only Rate Case

 PGA
 Purchased Gas Adjustment

 PSE

 PTC
 Production Tax Credit

 PUDs
 Washington Public Utility Districts

 Puget Equico
 Puget Equico, LLC

 Puget Holdings
 Puget Holdings, LLC

 Puget LNG
 Puget LNG, LLC

 RCW
 Revised Code of Washington

 SEC
 United States Securities and Exchange Commission

 SERP
 Supplemental Executive Retirement Plan

 SOFR
 Secured Overnight Financing Rate

 UA
 The United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada

 VIE
 Variable Interest Entity

 Washington Commission
 Washington Utilities and Transportation Commission

 WDOE
 Washington Department of Ecology

 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 executive orders, tariffs and trade restrictions, 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, pandemics or similar significant events, trade restrictions including tariffs, 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 Middle East conflicts, recessions, tariffs and trade restrictions, fuel prices, international currency fluctuations, sanctions, 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; and 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 enacted, amended or proposed in Washington and other municipalities in PSE's service territory, which may impact PSE's operations by, among others: changing system planning; changing existing statutory targets; instituting electrification requirements; or establishing Washington Commission requirements.

 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 quarterly 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. PSE is primarily engaged in the business of electric transmission, distribution and generation as well as 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, 2024 and 2023:

 Customer Count by Class
 2024

 2023

 Percent

 2024

 2023

 Percent

 (in thousands)

 Change

 Change

 1,099
 1,084
 1.4%
 0.4%

 —
 —

 —
 50.0

 Other
 12.5
 —
 —
 —

 Total1

 1,246
 1,230
 1.3%
 0.5%

 1 At December 31, 2024 and 2023, approximately 428,440 and 425,996 customers purchased both electricity and natural gas from PSE, respectively.

 PSE's revenues and associated expenses fluctuate 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 influence customer energy usage and affect PSE's billed revenue and energy supply expenses. PSE's electric and natural gas sales are generally greatest during winter months. This is due to variations in energy usage by customers, primarily driven by weather conditions. PSE normally experiences its highest retail energy sales with corresponding higher power costs during the winter heating season, which occurs in the first and fourth quarters of the year, and lower sales with corresponding lower power costs in the third quarter of the year. Fluctuations in weather conditions will affect PSE's billed revenue and energy supply expenses from month to month. PSE's decoupling mechanisms for electric and natural gas operations normalizes the impact of weather on operating revenue and net income. Under the decoupling mechanisms, 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.

 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. For additional information, see Business, "Regulation and Rates" included in this Item 1 of this report and Part II, Item 8, Note 4, "Regulation and Rates" to the consolidated financial statements included in this report.

 Capital Expenditures
 The following tables present PSE's capital expenditures for the five-year period ended December 31, 2024 and gross utility plant by category and percentages as of December 31, 2024:

 Utility Plant Additions/Retirements 5-Year Total
 2020 - 2024

 Common

 Additions
 $
 2,541,164
 $
 1,501,482
 $
 445,071

 Retirements
 (666,589)
 (137,495)
 (493,492)

 Net utility plant
 $
 1,874,575
 $
 1,363,987
 $
 (48,421)

 Utility Plant in Service

 Common

 Distribution
 $
 5,374,697
 42.2%
 $
 5,420,508
 96.0%
 $
 —
 —%

 Generation
 4,207,739
 33.0
 3,239
 0.1
 —
 —

 Transmission
 2,015,060
 15.8
 —
 —
 —
 —

 General plant & other
 1,153,605
 9.0
 220,133
 3.9
 1,052,581
 100.0

 Total (excluding CWIP)
 $
 12,751,101
 $
 5,643,880
 $
 1,052,581

 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 annual 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 a website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. Information may also be obtained via the SEC 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 which are developed by the North American Electric Reliability Corporation (NERC), certified by the FERC and enforced by the Western Electricity Coordinating Council (WECC) in PSE's operating territory.
 Rate mechanisms include: (i) trackers that record 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 Included in Decoupling Rates

 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
 Washington state law requires IOUs to file a forward looking 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 and are subject to 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.
 For further information regarding PSE's GRC filings, see Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.

 Rate Filings for both Electric and Natural Gas
 Bill Discount Rate Rider
 The Schedule 129D rider tariff implements surcharges to collect the costs incurred by the Company in providing the rate discounts including administrative costs specified in Schedule 7BDR, approved in Docket No. UE-230692 for electric and Schedule 23BDR, approved in Docket No. UG-230693 for natural gas.

 Conservation Service Rider
 The Schedule 120 tariff electric and natural gas conservation riders collect revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 to collect the current year's annual budget and to true-up variances from the forecasted conservation expenditures from the prior year, as well as actual compared to the forecasted load set in rates.

 Low Income Program
 The Schedule 129 tracker tariff recovers changes in costs for the low income bill payment assistance program as approved in Docket No. UE-011570 and UG-011571 for electric and natural gas, respectively. 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 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 a variable tariff rate. The mechanism acts as a tracker rate schedule and collects the total amount of property taxes assessed. The rate is adjusted each year in May based on that year's assessed property taxes and a 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 Nos. UE-220066.and UG-220067 for electric and natural gas, respectively.

 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 Nos. UE-220066 and UG-220067 for electric and natural gas, respectively. PSE will file an annual review March 31st of each year, which will be reviewed by the Washington Commission.

 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 mitigates 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, which mitigates the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues are recovered on a 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
 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 recovers 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; therefore it is part of base rates as of the effective date of the 2024 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 tariff 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.

 Energy Charge Credit Recovery Adjustment
 The Schedule 141A tariff 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
 Schedule 95A passes the benefits associated with the wind-related treasury grants through to customers. The filing results in a credit pass-back to customers for the 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 versus forecast load being different than the forecasted load set in rates. The final rate change from this program occurred on January 1, 2023.

 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 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

 Power Cost Only Rate Case
 A PCORC is a limited scope proceeding to reset power cost rates. The PCORC proceeding also allows 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. 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.

 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
 Schedule 139 provides an 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.

 Wildfire Prevention Tracker
 The Schedule 141WFP tracker implements surcharges to collect the costs incurred and investments associated with the Company's Wildfire Mitigation and Response Plan such as the electric IOU presentations filed in Docket No. U-210254. This schedule recovers the costs associated with the Company's Wildfire Mitigation and Response Plan that are not recovered in other tariff schedules. Such costs included in this rate adjustment may include, but are not limited to: liability insurance premiums attributable to wildfire coverage; amortization of previous deferrals from Docket No. UE-231048; and operations and maintenance expense, depreciation and return on rate base for projects or services that enable Wildfire Mitigation and Response Plan implementation or wildfire-related costs. The Schedule 141WFP was approved in PSE's 2024 GRC Order under Docket No. UE-240004 and was not in effect during 2024.

 Natural Gas Rate Filings
 Climate Commitment Act - Greenhouse Gas Emissions Cap and Invest Adjustment
 The Schedule 111 tariff implements a surcharge to recover the costs, and 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.

 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, as authorized in Washington Commission Docket No. UG-220067.

 Liquefied Natural Gas
 The purpose of the Schedule 141LNG tariff is to establish a new tariff schedule which will allow recovery of costs incurred for the development, construction and operation of the Tacoma LNG facility as authorized in Washington Commission Docket No. UG-210918.

 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.

 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

 2024
 2023
 2022

 Generation and purchased power, MWh

 Company-controlled resources
 14,295,586
 14,894,381
 11,198,936

 Contracted resources
 11,545,827
 11,806,074
 10,422,069

 Non-firm energy purchased
 3,054,018
 2,910,517
 4,922,194

 Total generation and purchased power
 28,895,431
 29,610,972
 26,543,199

 Less: losses and Company use
 (1,049,357)
 (1,113,911)
 (1,318,609)

 Total energy, MWh
 27,846,074
 28,497,061
 25,224,590

 Electric energy sales, MWh

 11,462,977
 11,387,971
 11,753,057

 8,570,573
 8,637,063
 8,677,178

 1,057,368
 1,070,933
 1,113,909

 Other customers
 77,822
 76,495
 76,407

 Total energy sales to customers
 21,168,740
 21,172,462
 21,620,551

 Sales to other utilities and marketers
 6,677,334
 7,324,599
 3,604,039

 Total energy sales, MWh
 27,846,074
 28,497,061
 25,224,590

 2,307,813
 2,270,474
 2,300,711

 Electric energy sales and transportation, MWh
 30,153,887
 30,767,535
 27,525,301

 Electric operating revenue by classes

 $
 1,677,599
 $
 1,514,149
 $
 1,381,858

 1,159,596
 1,071,385
 981,170

 131,869
 123,548
 116,712

 Other customers
 23,507
 21,199
 18,734

 Total operating revenue from customers
 2,992,571
 2,730,281
 2,498,474

 18,723
 23,573
 22,353

 Sales to other utilities and marketers
 281,186
 502,391
 329,589

 Decoupling revenue
 (39,900)
 (35,621)
 (37,423)

 Other decoupling revenue1

 35,536
 16,635
 (12,067)

 Miscellaneous operating revenue2

 44,579
 108,608
 160,531

 Total electric operating revenue
 $
 $
 $
 2,961,457

 Number of customers served (average):

 1,091,599
 1,077,406
 1,065,508

 134,993
 134,375
 133,521

 3,175
 3,187
 3,222

 Other
 8,269
 8,156
 8,047

 Total customers
 1,238,160
 1,223,233
 1,210,402

 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)

 2024
 2023
 2022

 Average kWh used per customer:

 10,501
 10,570
 11,030

 63,489
 64,276
 64,987

 333,029
 336,032
 345,720

 Other
 9,411
 9,379
 9,495

 Average revenue per customer:

 $
 1,537
 $
 1,405
 $
 1,297

 8,590
 7,973
 7,348

 41,534
 38,766
 36,223

 Other
 2,843
 2,599
 2,328

 Average retail revenue per kWh sold:

 $
 0.1463
 $
 0.1330
 $
 0.1176

 0.1353
 0.1240
 0.1131

 0.1247
 0.1154
 0.1048

 Other
 0.3021
 0.2771
 0.2452

 Average retail revenue per kWh sold
 $
 0.1414
 $
 0.1290
 $
 0.1156

 Heating degree days
 4,380
 4,313
 4,715

 Percent of normal - NOAA1 30-year average

 101.0
 %
 98.1
 %
 105.2
 %

 1.National Oceanic and Atmospheric Administration (NOAA).

 Electric Supply
 At December 31, 2024, 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 6,524 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, 2024 and 2023:
 Peak Power Resources
 Energy Production

 2024
 2023
 2024
 2023

 MW
 %
 MW
 %
 MWh
 %
 MWh
 %

 Purchased resources:

 Columbia River PUD contracts1

 14.1%
 13.9%
 3,284,849
 11.4%
 3,296,048
 11.1%

 Other hydroelectric
 1.6
 1.6
 513,535
 1.8
 491,898
 1.7

 Other producers
 1,252
 19.2
 1,252
 19.1
 4,698,079
 16.3
 5,264,589
 17.8

 Wind/solar
 13.7
 13.8
 2,911,308
 10.1
 2,803,223
 9.5

 Biomass
 0.3
 0.3
 128,213
 0.4
 135,153
 0.5

 Short-term wholesale energy purchases
 N/A
 —
 N/A
 —
 3,063,861
 10.6
 2,725,680
 9.2

 Total purchased
 3,185
 48.9%
 3,173
 48.7%
 14,599,845
 50.6%
 14,716,591
 49.8%

 Company-controlled resources:

 Hydroelectric
 4.0%
 4.0%
 869,257
 3.0%
 699,907
 2.4%

 Coal
 5.7
 5.7
 2,195,159
 7.6
 2,673,671
 9.0

 Natural gas/oil
 1,931
 29.6
 1,931
 29.7
 9,309,858
 32.2
 9,954,456
 33.5

 Wind/solar
 11.8
 11.9
 1,921,312
 6.6
 1,566,347
 5.3

 Other2

 —
 —
 —
 —
 —
 —

 Total company-controlled
 3,339
 51.1%
 3,339
 51.3%
 14,295,586
 49.4%
 14,894,381
 50.2%

 Total resources
 6,524
 6,512
 28,895,431
 29,610,972

 1.Net of 35 MW and 47 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, 2024, and 2023, respectively.
 2.It is estimated that the Glacier Battery Storage has delivered approximately 1,649.1 and 1,648.4 MWh as of December 31, 2024, and 2023, respectively.

 Company–Owned Electric Generation Resources
 At December 31, 2024, 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 WDOE limits flow to 2,500 cubic feet and therefore output to 47.7MW.

 Columbia River Electric Energy Supply Contracts
 During 2024, approximately 11.4% of PSE's energy supply was obtained through long-term contracts with three 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, 2024, 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
 2051
 35.0
 %

 Rocky Reach Project
 2051
 35.0

 Douglas County PUD2:

 Wells Project
 2029
 17.3

 Grant County PUD3:

 Priest Rapids Development
 2052
 4.8

 Wanapum Development
 2052
 4.8

 Total

 ____________
 1 As of December 31, 2024, PSE purchased 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 purchased output from Douglas County PUD's Wells hydroelectric project under two separate contracts: 1) a contract executed in March 2017 with a variable share of output (average 11.8% in 2024) that began on September 1, 2018 and ends September 30, 2028; and 2) a contract executed in September 2023 for 5.5% of output from October 1, 2024 through September 30, 2029.
 3 PSE purchased 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 March 31, 2052; and 2) a contract entered in November 2023 for 4.18% of output that began on January 1, 2024, and continued through December 31, 2024. PSE renewed the latter contract on an annual basis in August 2024 for continued delivery during the 2025 calendar year.

 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 150 MW of existing BPA transmission for the EIM market. Participation has resulted in reduced costs for PSE customers of approximately $61.0 million in the year ended December 31, 2024, 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, 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 2024, PSE had 5,721 MW and 1,553 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 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. These hedges 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, 2024 and 2023:

 2024
 2023

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

 Jackson Prairie
 13,494
 13,374

 Plymouth LNG (in LNG form)
 1,735
 1,761

 Clay Basin

 9,856
 7,629

 NATURAL GAS UTILITY OPERATING STATISTICS

 2024
 2023
 2022

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

 Residential1

 $
 796,889
 $
 868,462
 $
 808,376

 Commercial firm1

 344,014
 356,650
 324,743

 24,679
 25,472
 22,965

 25,944
 37,099
 29,582

 Total retail natural gas sales
 1,191,526
 1,287,683
 1,185,666

 Transportation services1

 34,706
 29,210
 20,381

 Decoupling revenue
 33,232
 23,116
 (4,008)

 Other decoupling revenue2

 (9,728)
 (3,405)
 (15,561)

 Other1

 242,518
 87,764
 23,158

 Total natural gas operating revenue
 $
 1,492,254
 $
 1,424,368
 $
 1,209,636

 Number of customers served (average):

 819,413
 815,454
 809,965

 Commercial firm
 57,102
 56,934
 56,824

 2,245
 2,260
 2,260

 Total customers
 879,219
 875,118
 869,532

 Natural gas volumes, therms (thousands):

 573,739
 587,635
 632,145

 Commercial firm
 285,657
 285,197
 294,879

 21,061
 22,168
 23,467

 41,922
 49,275
 49,322

 Total retail natural gas volumes, therms
 922,379
 944,275
 999,813

 Transportation volumes
 188,336
 192,043
 219,059

 Total volumes
 1,110,715
 1,136,318
 1,218,872

 NATURAL GAS UTILITY OPERATING STATISTICS (Continued)

 2024
 2023
 2022

 Average therms used per customer:

 Commercial firm
 5,003
 5,009
 5,189

 9,381
 9,809
 10,384

 161,238
 182,500
 181,331

 946,412
 960,215
 1,038,194

 Average revenue per customer:

 Residential1

 $
 $
 1,065
 $

 Commercial firm1

 6,025
 6,264
 5,715

 10,993
 11,271
 10,162

 99,785
 137,404
 108,757

 Transportation1

 174,402
 146,050
 96,592

 Average revenue per therm sold:

 $
 1.389
 $
 1.478
 $
 1.279

 Commercial firm
 1.204
 1.251
 1.101

 1.172
 1.149
 0.979

 0.619
 0.753
 0.600

 Average retail revenue per therm sold1

 $
 1.292
 $
 1.364
 $
 1.186

 Transportation1

 $
 0.184
 $
 0.152
 $
 0.093

 Heating degree days
 4,380
 4,313
 4,715

 Percent of normal - NOAA 30-year average
 101.0
 %
 98.1
 %
 105.2
 %

 1.For comparability to 2024 reporting, certain 2023 revenues related to the regulatory offset of CCA auction proceeds passed back to customers through retail revenues were reclassified within this table among: residential, commercial, transportation and other.
 2.Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve.

 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. PSE also utilizes stores of natural gas within the distribution system, held at PSE owned peaking facilities, Tacoma LNG and Gig Harbor LNG, as well as NWP's Plymouth LNG. In addition, PSE may interrupt 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.
 The following table presents the working natural gas volumes in storage as of December 31, 2024 and 2023:

 2024
 2023

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

 Jackson Prairie
 82,036
 79,045

 Clay Basin
 91,301
 81,394

 Tacoma LNG
 4,900
 4,746

 Gig Harbor LNG1

 Plymouth LNG

 1.For comparability to 2024 reporting, 2023 Gig Harbor LNG volumes were converted from Dth to therms.

 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. The facility is used primarily for intermediate peaking purposes due to its ability to deliver a large volume of natural gas in a short time period. When combined with capacity contracted from NWP's stake in Jackson Prairie, PSE holds firm withdrawal capacity of 453,800 Dth per day, and over 9.8 million Dth of storage capacity at the Jackson Prairie facility. Of this total, PSE designates 397,100 Dth per day of the firm withdrawal capacity and over 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 56,700 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 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 three 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 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 and to serve PSE's generation fleet during peak periods on a daily or intra-day basis. In addition, PSE holds 15,000 Dth/day of firm pipeline capacity from Plymouth for 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
 Operational since February 2022, 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 regulated by the Washington Commission.
 On April 24, 2024, the Washington Commission issued Final Order 07 under Docket No. UG-230393. On May 3, 2024, PSE made the compliance filing required by Final Order 07. On May 24, 2024, Public Counsel and the Puyallup Tribe of Indians each filed a petition for judicial review of the Washington Commission's Final Order 07. The petitions were filed in Thurston County Superior Court and have been consolidated. For additional information, see Note 4, "Regulation and Rates" in the Combined Notes to Consolidated Financial Statements included in Item 8 of this report.

 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 535,900 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 303,900 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 month 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 five 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 six years and an option for PSE to renew its rights under the Westcoast contract. PSE has firm transportation capacity for its natural gas customers on NGTL and Foothills pipelines, each totaling approximately 79,700 Dth per day, with remaining terms of six 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 41,400 Dth per day, with remaining terms of four years. PSE has firm transportation capacity for its natural gas customers on the GTN pipeline, totaling over 77,000 Dth per day, with a remaining term of six years and PSE has a first right-of-refusal to extend such contracts under current FERC rules. PSE has other firm transportation capacity on GTN pipeline, which supplies the electric generating facilities, totaling 40,600 Dth per day, with remaining terms of four years. PSE holds 259,000 Dth per day of firm capacity on CNGC to connect generating facilities to the pipeline grid with a remaining term 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 through several methods including open-bidding and prearrangement, and they may recover up to the cost of such capacity. PSE participates in capacity releases to mitigate a portion of the demand charges related to unutilized storage and has acquired some firm pipeline and storage service through capacity release provisions to serve its growing service territory and electric generation portfolio. 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 an ISP that combines natural gas and electric planning. Previously, Washington Administrative Code (WAC) 480-100-625 required PSE to file a natural gas IRP every two years. PSE submitted its 2021 and 2023 natural gas IRP on February 19, 2021 and March 31, 2023, respectively, to the Washington Commission. WAC 480-100-625 required PSE to file an electric IRP every four years and a progress report every two years beginning in 2023. PSE submitted its 2021 electric IRP on April 1, 2021 and submitted its progress report related to the 2021 electric IRP on March 31, 2023. PSE's first ISP will be due by April 2027.
 One key consideration included in the electric IRP is capacity. Based on the cumulative capacity need by year, the capacity (surplus)/shortfalls are:

 2025
 2026
 2027
 2028
 2029

 Projected MW (surplus)/shortfall

 (59)
 1,109
 1,169
 1,378

 Due to growing regional concerns pertaining to capacity within the short-term market, PSE plans to no longer rely on firm short-term market purchases and PSE's energy supply actions in 2024 reduced capacity shortfalls in future years compared to 2023 projected capacity needs. 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 surplus of 59 MW is expected to be a shortfall of 1,378 MW by 2029. The projected capacity above reflects the mix of energy efficiency programs deemed cost effective in the 2023 Progress Report and new resource additions. 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.
 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.

 Grid Resilience and Innovation Partnerships Program
 In 2021, the Infrastructure Investment and Jobs Act was signed into law, which among other investments and programs, established the U.S. Department of Energy's (DOE) Grid Resilience and Innovation Partnerships (GRIP) Program. The GRIP program was established to enhance grid flexibility and improve the resilience of the power system against growing threats of extreme weather and climate change. PSE has been selected for three grant awards under the GRIP program either through individual applications or participating in consortium grant applications: (i) PSE participated in the North Plains Connector grant consortium along with other utilities in the Pacific Northwest region that on August 7, 2024 was selected for a grant of $700.0 million of federal cost sharing; (ii) PSE applied for the Skagit River Valley Transformation for Climate Resiliency project that was selected on October 18, 2024 for a grant of $45.8 million of federal cost sharing; and (iii) PSE partnered in a coalition with E Source and other Pacific Northwest utilities on the Increasing Energy Resilience via Technology Investment Acceleration project, which was selected on October 18, 2024 for a grant of $77.0 million of federal cost sharing. As of the time of this report, all three grants must complete award negotiations and proceed to a signed award with the DOE in order to receive federal cost sharing funds and, pursuant to recently signed Executive Orders, the federal government's activities with respect to such awards has been temporarily paused. Thus, at this time, the Company cannot predict the timing or amount of federal cost sharing that may be received.

 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.
 As the rider mechanisms do not mitigate the gross margin erosion associated with reduced energy sales resulting from the Company's energy efficiency efforts, PSE received approval in 2017 from the Washington Commission for continuation of electric and natural gas decoupling mechanisms. 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 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 federal, state and local environmental laws and regulations, including executive orders and tariffs. PSE's operations may be negatively impacted by federal budget and efficiency measures such as government workforce reductions and changes to federal grant programs that affect environmental laws and regulations. For more information regarding these risks, see Item 1A, "Risk Factors" included in this report.
 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 a partial ownership of Colstrip. The federal Clean Air Act (CAA), along with its state counterparts, govern each of the natural gas plants and Colstrip and all have CAA Title V operating permits, which must be renewed every five years. This renewal process is closely monitored by PSE due to the potential impact and additional cost to plants. As these facilities also emit GHGs, they 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). 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 operations at the hydroelectric plants, the wind farms and the transmission and distribution systems, potentially representing cost exposure and operational constraints.

 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, as well as the federal regulations addressing coal combustion residuals, for its ownership interest in Colstrip. Under these laws, PSE may be subject to agency orders to carry out site remediation as these laws impose joint and several liability on any current owner, past owner, operator of a contaminated site or transporter, 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, the Toxic Substances Control Act, and state hazardous or dangerous waste regulations that impose complex requirements on handling and disposing of regulated substances.

 Water Protection
 The federal Clean Water Act, including the Oil Pollution Act amendments and state counterparts, governs PSE facilities that discharge wastewater or storm water, store bulk petroleum products, and PSE construction projects above a certain threshold. This includes most generation facilities, 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 federal and state laws and regulations, and local siting, critical area and zoning ordinances. These requirements may 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 adopted at a federal, state or local level 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. 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 is planning to eliminate coal from its energy supply portfolio by the end of 2025 and achieve net zero carbon emissions for its electric supply by 2030, consistent with CETA requirements. Further, the Company set an aspirational goal to be net zero by 2045 for natural gas sales (which will likely require future policy, regulatory and/or customer preference changes and technology innovation), 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 has considered the cost of the decarbonization efforts to date, as well as future efforts, in its IRP process (and will do so going forward in its ISP process) and has developed plans for transformational customer programs, and continues 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 and other facilities that emit 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 EPA.
 The most recent data indicate that PSE's total GHG emissions (direct and indirect) from its electric supply portfolio, which is based on electricity to serve customer load in 2023 was 9.35 million metric tons of carbon dioxide equivalents. Approximately 29.3% of total electric supply portfolio GHG emissions (approximately 2.74 million metric tons) are associated with PSE's ownership and contractual interests in coal generation. Compared to 2022, total emissions decreased by 0.1%.
 PSE's overall emissions reduction strategy, in compliance with CETA is to add new renewable or non-emitting resources to its generation portfolio and make a concerted effort to manage customers' needs with an appropriate balance of new renewable or non-emitting generation, existing generation owned and/or operated by PSE, significant energy efficiency efforts and remove coal generation from its portfolio by January 1, 2026.
 PSE's GHG emissions resulting from the complete combustion of natural gas provided to end-users on PSE's distribution systems in 2023 were 6.19 million metric tons of carbon dioxide equivalents.

 Executive Orders Addressing Environmental Issues
 Since entering office, President Trump has issued several executive orders that are likely to affect PSE's federal environmental obligations. The executive orders purport to revoke several existing executive orders and federal environmental mandates, including among other things, notification of withdrawal from the Paris Agreement on climate change and other commitments under the United Nations Framework on Climate Change, which had required commitments to reduce GHG emissions, as well as a pause on permitting efforts for wind projects, federal workforce reductions, and possible cessation of certain disbursements under the Inflation Reduction Act and changes to other federal programs.

 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, 2024, 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, 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 9, 2024, the EPA published a final 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 fossil-coal-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. While the EPA previously proposed to include emissions guidelines for GHG emissions from the largest, most frequently operating stationary combustion turbines, the EPA did not finalize these requirements. Instead, on March 26, 2024, the EPA opened a non-rulemaking regulatory docket seeking public input on requirements for these stationary combustion turbines. According to the EPA's Fall 2024 Unified Agenda, the EPA intends to issue a proposed rule in February 2025.
 The 2024 standards are subject to a pending challenge in the D.C Circuit. On February 5, 2025, the EPA filed an unopposed motion requesting a 60-day abeyance of the suit to allow new EPA leadership to familiarize themselves with these issues and determine how they wish to proceed, which was granted by the D.C. Circuit on February 19, 2025.

 Criteria Pollutant Emissions Limits for New, Modified, and Reconstructed Stationary Combustion Turbines
 On December 13, 2024, the EPA published a proposed rule that would revise the NSPS regulating criteria pollutant emissions from new, modified, and reconstructed stationary combustion turbines subject to 40 C.F.R. Subparts GG or KKKK. The EPA is proposing more stringent nitrogen oxide (NOx) emissions standards based on a determination that BSER is combustion controls and selective catalytic reduction (SCR) technology. The EPA is proposing to retain the existing sulfur dioxide (SO2) standards, based on its finding that BSER remains the use of pipeline natural gas and distillate fuels. If finalized, the standards would apply to affected sources that begin construction, modification, or reconstruction after December 13, 2024,

 the date of publication of the proposal in the Federal Register. The EPA is subject to a consent decree deadline to sign a final rule by November 12, 2025.

 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, then declining annually through 2050. The 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 (i) electricity generated in Washington (ii) electricity imported into the state to serve Washington load, and (iii) 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 accordance with the requirements of the CCA.
 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 and Quebec to link with their cap and trade programs.

 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 (i) eliminate coal-fired generation from their in-state electric supply to customers by December 31, 2025; (ii) be carbon-neutral by January 1, 2030 through a combination of non-emitting electric generation, renewable generation, and/or alternative compliance options; and (iii) make 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 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. Based on a consent decree in this litigation, the EPA must take final action on Montana's SIP by November 30, 2025, and on Washington's SIP by September 25, 2025.
 In April 2024, the EPA opened a non-rulemaking regulatory docket seeking public input on the Agency's efforts to update and revise the Regional Haze Rule in advance of the third planning period, which is currently scheduled to begin in 2028. On December 23, 2024, the EPA published a proposed rule to extend the deadline for states to submit regional haze SIP revisions for the third planning period, from July 31, 2028, to July 31, 2031. The EPA has indicated that it plans to propose revisions to the Regional Haze Rule in a separate rulemaking, although no proposal has currently been issued.

 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 was originally self-implementing, but can now be implemented through permit programs in certain states and is directly enforceable by the federal government in all states. The rule addresses the following risks from coal ash disposal: leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash containment structures. These risks may be mitigated by establishing technical design, operation and maintenance, closure and post closure care requirements for CCR landfills and surface impoundments, as well as 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 that 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 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. 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. This proposal was finalized in May 2024 and became effective in November 2024, and extends federal regulation (including groundwater monitoring, closure, and corrective action requirements) to historic placements or disposal of CCR at power plant facilities, including Colstrip. The final rule is currently subject to challenge in the U.S. Court of Appeals for the D.C. Circuit.
 Finally, 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. The Company does not tolerate violence and/or threatening behavior, and employees are expected to treat one another with mutual respect and dignity. PSE complies with all federal, state, and local employment laws, and prohibits 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, 2024, PSE had approximately 3,257 full-time equivalent employees. Approximately 1,009 PSE employees are represented by the IBEW or the 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 and Puget LNG do not have any employees. PSE's employees provide services to Puget Energy, including Puget LNG 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, 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 reward program. 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: for 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 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 community and non-discrimination values. 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.
 • Non-discrimination: PSE is committed to fostering a welcoming workplace free of discrimination, where all employees have a voice. PSE seeks to be our customers' clean energy partner of choice and values cultivating an environment that authentically reflects the communities we serve. PSE's employees are critical to our mission and the Company is committed to creating opportunities for engagement. PSE has nine active and voluntary employee resource groups (ERGs) that benefit their members and the Company by integrating different perspectives, and providing additional insight into how to solve problems, innovate, and meet customer needs. PSE also participates with regional and national member organizations that work to strengthen our connections with the communities we serve and advance industry best practices.

 Information About Our Executive Officers
 The executive officers of Puget Energy as of February 20, 2025, 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

 J. Martin

 Senior Vice President and Chief Financial Officer since May 2024; Vice President, Undergrounding, at Pacific Gas & Electric Company from 2022 to 2024; Vice President, Supply Chain and Chief Procurement Officer at Pacific Gas & Electric Company from 2019 to 2022; Vice President, Business Finance and Planning at Pacific Gas & Electric Company from 2016 to 2019

 L. Luebbe

 Senior Vice President, Chief Sustainability Officer and General Counsel since December 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 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 February 20, 2025, 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

 J. Martin

 Senior Vice President and Chief Financial Officer since May 2024; Vice President, Undergrounding, at Pacific Gas & Electric Company from 2022 to 2024; Vice President, Supply Chain and Chief Procurement Officer at Pacific Gas & Electric Company from 2019 to 2022; Vice President, Business Finance and Planning at Pacific Gas & Electric Company from 2016 to 2019

 L. Luebbe

 Senior Vice President, Chief Sustainability Officer and General Counsel since December 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 2023; Vice President, Officer of Utility Partnerships and Innovation at Pacific Gas & 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 2023; Teaching Associate Professor at Evans School of Public Policy, University of Washington since 2017; Partner at Insight Strategic Partners from 2017 to 2023

 R. Roberts

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

 S. Upton

 Chief Information Officer and Head of Corporate Services since May 2024; Chief Information Officer from March 2023 to May 2024; Partner at Fortium Partners since 2023, Chief Information Officer at Solomon Partners from 2021 to 2023; Global Chief Operating Officer at Credit Suisse from 1997 to 2020

 S. W. Smith

 Controller and Principal Accounting Officer since December 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 may impair PSE's business operations. If any of the following risks 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. These parties have differing regulatory perspectives and concerns, but 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. PSE filed its second general rate case under this updated statute in February 2024 in Dockets UE-240004 and UG-240005. 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 high prices and volatile markets for purchased power, tariffs, 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. The cost of purchased power and natural gas are influenced by many factors, including but not limited to, high prices in western wholesale markets during periods when PSE has insufficient energy resources to meet its energy supply needs, government regulations and actions including tariffs, changes to federal grant programs and government staff reductions and/or purchases in wholesale markets of high volumes of energy at prices above the amount recoverable in retail rates. Additional factors, which may contribute to PSE's insufficient energy supply include:
 • 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, regulations and policies, or any changes in the interpretation or enforcement of existing laws, regulations and policies that necessitate significant investments in our generating facilities or increase costs or delays in the development of future generating facilities including delays associated with federal workforce reductions and budget cuts;
 • 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 supported 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. This could 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 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. In addition, PSE 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, pipeline assets and 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, insufficient 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 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 alleged to have resulted 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 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 able to recover costs through customer rates or regulatory mechanisms; however it may not be possible to recover the full costs and 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. To match PSE's energy needs and available resources, PSE engages in wholesale purchases and sales of electric capacity and energy and 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 contractually required payments or delivery of energy supply 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 that could adversely affect PSE's financial results. Although PSE prepares for the probability of default by counterparties, the actual exposure of 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 or reinterpreted environmental laws and regulations affecting PSE's operations, or restricting the use of products sold by PSE, may be adopted, which could impact PSE or its facilities. Compliance with these or other future regulations could require significant expenditures or reduce revenue and thus adversely affect PSE financially. While PSE may be able to recover costs through customer rates or regulatory mechanisms, it may not be possible to recover the full costs and it could take several years to collect. Other risks related to PSE's regulatory compliance 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 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. Uncertainty surrounding PSE's energy resource portfolio exists due in part to the potential changes in regulatory standards, impacts of new and existing laws and regulations, individuals and organizations seeking to combat climate change and the need to obtain various regulatory approvals. An abundance of low and stably priced natural gas, contrasted by environmental, regulatory, and other concerns surrounding coal-fired generation resources, fossil fuel infrastructure bans, 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, 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 could increase in scope and frequency as a result of 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 influenced by weather patterns resulting from seasonal variations, which 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 also result in material impacts on demand. 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 affect 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 only 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. This plan relies on the availability of a variety of resources, including but not limited to: inventory on hand, inventory available for purchase from outside suppliers and outside contractors (including industry-wide mutual assistance from third-party public utilities). Each of these 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 period of time.

 PSE depends on its work force and third party vendors to perform certain important services and may be negatively affected by its inability to attract and retain professional and technical employees or the unavailability of vendors. PSE is subject to workforce factors, including but not limited to loss or retirement of key personnel and availability of qualified personnel. PSE's ability to implement a workforce succession plan is dependent upon PSE's ability to employ and retain skilled professional and technical workers. Without a skilled workforce, PSE's ability to provide quality service to PSE's customers and to meet regulatory requirements could affect PSE's earnings. In addition, 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 able to perform necessary utility functions and 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 lack 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, economic and geopolitical conditions, changes to customer needs and expectations, regulatory environment and state and federal legislation including the enforcement of such legislations, regulations and policies, customer-generated power, demand response, and transportation electrification. Such factors may adversely impact the Company by increasing competition, decreasing customer satisfaction and loyalty, and causing customers to seek 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. More specifically, our business and results of operations may be adversely impacted by 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 thus increasing uncollectible accounts, delaying and disrupting supply chains and disrupting the financial markets. This may negatively impact the rates or ability to access capital, deteriorate our financial metrics and our ability to meet the covenants of our credit facilities, and disrupt our ability to meet customer requirements.

 PSE could be adversely affected by disruptions in the global economy and rising geopolitical tensions. Our business, financial condition and results of operations have been impacted in the past and may be impacted in the future by disruptions in the global economy. For example, in response to 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 and economic tensions (including the implementation of tariffs or other trade restrictions by the U.S. or retaliatory actions by other governments) and military conflicts (including the conflict in the Middle East), could result in increased trade barriers or restrictions on global trade, sanctions, cyberattacks, supply chain disruptions, and increased costs, including raw material and energy costs. The impact of these events may adversely affect our business operations, supply chain, and ultimately, PSE's ability to serve customer demand and needs on timely basis, which may negatively impact PSE's financial performance. In addition, these events, including tariffs and trade restrictions, could have a similar impact on our suppliers and certain customers, which could have a negative impact on our financial condition, results of operations and cash flows.

 The changing resource composition of the region and within PSE's generation portfolio may be insufficient to meet customers' energy demands. Growing variance in actual and forecasted load or generation could impact the cost of balancing generation resources and may inhibit the Company's ability to meet retail load obligations or make PSE more reliant on wholesale markets, which could have a significant impact on energy costs. Furthermore, as climate change results in more frequent extreme weather conditions and seasonal fluctuations become more pronounced, the variability of load and generation increase. As the Company and other utilities in the region continue to add solar- and wind-powered generation capacity, each of which is a climate-dependent resource, the Company's ability to reliably and cost effectively serve retail loads may become more challenging, adversely impacting the Company's financial condition, customer satisfaction, and reputation.

 Increased competition from other industries and entities may impact the Company's ability and cost to acquire generation and transmission resources. Entities, primarily in the technology sector, could enter into power purchase agreements or other resource acquisition agreements to meet their growing energy needs and carbon emission targets. The potential increase in competition for energy resources, including generation and transmission, may be influenced by a variety of factors, including by (1) entities' commitments to reduce carbon emissions and their increased reliance on renewable energy sources, (2) increasing demand for additional cloud computing infrastructure, and (3) growing demand for more data centers to support artificial intelligence products and services. Such competition for energy resources, including renewable energy resources, may impact the Company's ability to acquire generation and transmission resources reliably and cost effectively to serve customer demand. As a result, the Company's financial condition and results of operations may be adversely impacted.

 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 or credit market disruptions, a downgrade of Puget Energy's or PSE's credit rating, the unavailability of borrowings or the imposition of restrictions on borrowings 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. This could adversely affect the ability to access one or more financial markets, 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 $338.4 million outstanding under the facility as of December 31, 2024. 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, 2024, 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, 2024, had approximately $6.0 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 thus 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. 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, which 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 2025 and beyond, as well as the timing of the recovery of such contributions in GRCs, could adversely affect 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, 2024, and the EBITDA to interest expense ratio was 4.6 to 1.0 for the twelve-months ended December 31, 2024.
 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 federal, state and local laws, regulations and policies, including executive orders, that materially impact operations and financial condition. Specific laws, regulations and policies, including executive orders, and proposals, that impact the Company include, but are not limited to: tax reform, utility regulations, carbon reduction, climate change and environmental regulations, accounting regulations, federal grant programs, incentives and funding policies, infrastructure regulations, tariffs and trade restrictions and budget and efficiency measures, including any actual or potential reduction in the federal workforce. Changes in current laws, regulations and policies, proposed legislations, regulations or policies, including executive orders, or a change in the interpretation or enforcement of such laws, regulations and policies 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. Changes in federal, state, and local office holders may also increase the rate of change, interpretation and enforcement of these laws and regulations.

 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. 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 and would likely have an adverse effect on the Company's results of operations and financial condition. 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 help 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, a risk assessment is performed by the CDC, in accordance with the CSIRP. 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 thresholds set 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, 2024, 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, 2024. 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 $1.0 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, 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 their respective common stock. During 2024, 2023, and 2022, 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 2024 compared to 2023. For discussion related to the results of operations and changes in financial condition for 2023 compared to 2022 refer to Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations in our fiscal year 2023 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, which has the sole purpose of owning and operating the non-regulated activity of the Tacoma liquefied natural gas (LNG) facility. Puget Holdings indirectly owns all of Puget Energy's common stock. 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), the Ontario Municipal Employees Retirement System (OMERS), PGGM Vermogensbeheer B.V., Macquarie Washington Clean Energy Investment, L.P., and the 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 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." 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 2024 and 2023:
 2024
 2023

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

 Return on equity
 $346,148
 $5,307,338
 6.5%
 $131,059
 $4,960,936
 2.6%

 Less/Plus: Unrealized gains and losses on derivative instruments, after-tax
 (26,790)
 —
 *
 224,751
 —
 *

 Plus: Equity adjustments1

 —
 16,460
 *
 —
 70,908
 *

 Plus: Impact of average of monthly average (AMA)
 —
 106,805
 *
 —
 (77,648)
 *

 Return on AMA equity
 $319,358
 $5,430,603
 5.9%
 $355,810
 $4,954,196
 7.2%

 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 following chart displays the Company's return on AMA equity compared to its authorized regulated ROE for the year ended December 31, 2024:

 The Company's 2024 return on AMA equity was 5.9%, which is lower than the 9.4% authorized regulated ROE primarily due to the following:
 • Deferred return on equity related to AMI and Tacoma LNG investments, resulted in a reduction of $22.8 million, or 0.4% to ROE.
 • Regulatory disallowance as ordered by the Washington Commission specific to certain portions of PSE's deferred return on its investment in the Tacoma LNG facility, resulted in a reduction of $19.9 million, or 0.4% to ROE.
 • Power cost expense was higher in 2024 than the amount allowed in rates, which was primarily driven by a cold weather event in January 2024. Higher power costs resulted in a reduction of $36.8 million, or 0.7% to ROE.
 • Capital related items led to increased interest expense of $49.9 million, or 0.9% to ROE, which was driven by (i) higher working capital, timing of capital recovery and higher than filed cost of capital contributing to $26.0 million of higher interest expense and (ii) lower than planned CWIP resulting in $23.9 million in lower AFUDC.
 • Other expenses including $23.5 million of below the line expenses, which are not recoverable in rates, as well as $12.0 million of regulatory deferred interest expense and $23.6 million in higher than allowed operations and maintenance costs and other costs, which in total resulted in a reduction of $59.1 million, or 1.1% to ROE.

 Factors and Trends Affecting PSE's Performance
 PSE's ongoing regulatory requirements and operational needs necessitated the investment of substantial capital in 2024, which will continue 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, 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 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 operational 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, cybersecurity 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 or the rise in frequency and magnitude of extreme temperature events; 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, including tariffs and trade restrictions, that impact operations, electric and natural gas availability, sales, transmission, costs and/or delivery.

 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 2024 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.
 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. Washington law and the Washington Commission also set natural gas conservation achievement standards for PSE. The effects of achieving these standards will, however, have only a minor negative impact on the natural gas business's financial performance due to the natural gas business being mostly decoupled.
 In 2021, the Washington Governor signed legislation, which was passed by the state legislature, that requires IOUs to file a forward looking 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.
 In 2024, the Washington Governor signed the Washington Decarbonization Act for Large Combination Utilities, introduced as House Bill 1589, which requires PSE to file an integrated system plan that among other things: include scenarios that, if adopted and approved, would achieve GHG reductions equal to the PSE share of GHG emissions reductions under the statewide GHG emissions reduction limits; achieve two percent of electric load annually with conservation and energy efficiency resources unless the Washington Commission finds that a higher target is cost effective; includes low-income electrification programs; includes a 10-year clean energy action plan for implementing CETA at the lowest reasonable cost and at an acceptable resource adequacy standard; and the law consolidates multiple existing system plans into an integrated plan, which will be followed by three years of rulemaking and planning prior to the submission in 2027 of PSE's first integrated system plan to the Washington Commission. The law also clarifies the application of certain regulatory mechanisms for PSE, including a Certificate of Necessity (CN) and usage of CWIP. For additional information on PSE's GRC filings, see Note 4, "Regulation and Rates" in the Combined Notes to Consolidated Financial Statements included in Item 8 of this report.
 On March 29, 2024, senate bill 5950 approved Washington State's operating budget, which included $150.0 million for public and private utilities to provide one-time bill rebates for low-and moderate-income residential electric customers. PSE received a total of $45.9 million during the third quarter of 2024, and provided rebates to low-and moderate-income residential electric customers.

 General Rate Case Filing
 PSE filed a GRC, which included a two year MYRP with the Washington Commission on February 15, 2024. It also included a request for 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 rate year one, beginning in 2025 and 10.5% for rate year two, 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.
 On January 15, 2025, the Washington Commission issued an order on PSE's 2024 GRC, that approved a weighted cost of capital of 7.52% in 2025 and 7.64% in 2026, a capital structure of 49.0% in common equity in 2025 and 50.0% in 2026, and a return on equity of 9.8% in 2025 and 9.9% in 2026. On January 28, 2025, the Washington Commission approved PSE's electric and natural gas rates in its compliance filing with an overall net revenue change for electric of $378.2 million or 13.3% in 2025 and $191.0 million or 5.9% in 2026 and an overall net revenue change for natural gas of $110.0 million or 10.6% in 2025 and $20.0 million or 1.8% in 2026, with an effective date of January 29, 2025. PSE filed a petition for reconsideration on January 24, 2025 and multiple parties filed petitions for reconsideration and a motion for clarification on January 27, 2025. The Washington Commission will determine what, if any, further action will be taken with respect to these petitions by March 17, 2025.
 For additional information, see Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.

 Rate Schedules
 The following tables set forth electric and natural gas 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.

 Electric Rates:

 Schedule
 Docket
 Effective Date
 Average Percentage
 Increase (Decrease)
 in Rates

 Increase (Decrease)
in Revenue
(Dollars in Millions)

 Bill discount rate rider
 129D
 240874
 January 1, 2025
 0.1%
 $3.5

 230692
 0.5
 11.9

 Clean energy implementation
 141CEI

 (0.8)
 (23.6)

 230591
 September 1, 2023
 0.9
 31.4

 Colstrip adjustment rider
 141COL
 240729
 January 1, 20252

 0.1
 4.1

 230808
 0.03
 0.9

 2.2
 50.3

 Conservation service rider
 240138
 0.7
 20.7

 230139
 (0.2)
 (6.3)

 220137
 May 1, 2022
 1.0
 21.6

 Energy charge credit recovery3

 141A
 240934
 January 1, 2025
 0.04
 1.2

 230825
 (0.1)
 (2.0)

 1.5
 35.3

 Federal incentive tracker
 95A
 220794
 January 1, 20234

 1.3
 1.0

 210821
 January 1, 2022
 0.1
 (28.2)

 Low income program
 240645
 October 1, 2024
 (1.1)
 (33.3)

 240194
 2.7
 29.2

 230694
 (1.0)
 (25.9)

 220656
 October 1, 2022
 1.1
 25.8

 Power adjustment clause - Schedule 95

 (5.7)
 (161.6)

 Supplemental5

 240288
 October 1, 2024
 0.1
 3.8

 2024 variable power cost update
 230805
 6.1
 160.9

 Supplemental6

 230318
 December 1, 2023
 1.0
 27.4

 2020 PCORC7

 200980
 October 1, 2021
 3.3
 70.9

 Property tax tracker
 240200
 (0.7)
 (18.7)

 230219
 (0.2)
 (4.4)

 220234
 May 1, 2022
 (0.3)
 (5.8)

 Rates not subject to refund
 141N

 (5.6)
 (160.9)

 230320
 (3.1)
 (76.2)

 7.9
 182.5

 Rates subject to refund
 141R

 (5.4)
 (152.8)

 230320
 4.2
 105.6

 4.0
 91.7

 Residential and exchange benefit8

 230792
 November 1, 2023
 (0.4)
 (9.9)

 Revenue decoupling adjustment mechanism

 240221
 (0.3)
 (9.5)

 230206
 May 1, 20239

 (1.5)
 (37.6)

 220227
 May 1, 20229,10

 (1.0)
 (23.5)

 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)

 Wildfire prevention tracker

 141WFP

 0.8
 22.1

 ____________________
 1.Approved in 2024 GRC Final Order in Docket No. UE-240004, effective January 29, 2025.
 2.The Washington Commission has set the matter for adjudication, which allows the rates to be collected beginning January 1, 2025, but notes this does not represent a resolution or final determination. For additional information, see Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.
 3.The Schedule 139 Energy Charge Credit will annually increase by 2.0% every January 1st per Dockets UE-220066 and UG-220067, 2022 GRC Settlement Stipulation and Agreement for Green Direct Program.
 4.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 were expected to be over-distributed and the 2024 rate was set to zero.
 5.The Schedule 95 Supplemental PCA mechanism rates recover 2023 PCA imbalance credit of $22.2 million to be passed back to customers, and a provisional 2024 surcharge of $98.2 million, which creates a $76.0 million net balance amortized from October 1, 2024 through December 31, 2025.
 6.The Schedule 95 Supplemental PCA mechanism rates from the prior year recover the 2022 imbalance (effective December 1, 2023), which will end December 31, 2024.
 7.Schedule 95 update through PCORC filing. Per the 2022 GRC Final Order in Docket No. UE-220066, PCORC rates were set to zero as of January 11, 2023.
 8.Total credit to be passed back to eligible customers is $88.1 million for 2023.
 9.For rates effective May 1, 2023 and May 1, 2022, there were no excess earnings that impacted the approved revenue change.
 10.For the 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.

 Natural Gas Rates:

 Natural gas
 Schedule
 Docket
 Effective Date
 Average
Percentage
Increase (Decrease)
in Rates
 Increase (Decrease)
in Revenue
(Dollars in Millions)

 Bill discount rate rider
 129D
 240875
 January 1, 2025
 (1.1)%
 $(13.1)

 230693
 1.1
 13.1

 CCA - greenhouse gas emissions cap & invest1

 240884
 January 1, 2025
 (5.4)
 (65.8)

 230968
 3.0
 29.1

 230756
 November 1, 2023
 2.1
 27.2

 230470
 3.2
 16.8

 Conservation service rider
 240139
 0.7
 6.8

 230140
 0.4
 4.7

 220138
 May 1, 2022
 0.3
 3.2

 Cost recovery mechanism for pipeline replacement2

 220067
 January 7, 2023
 (2.0)
 (22.6)

 220590
 November 1, 2022
 0.4
 4.6

 Distribution pipeline provisional recovery
 141D
 230393
 May 11, 2024
 (0.02)
 (0.2)

 220067
 (0.01)
 (0.1)

 January 7, 2023
 0.3
 3.0

 Liquefied natural gas

 141LNG

 230393
 May 11, 2024
 3.1
 42.7

 Low income program
 240646
 October 1, 2024
 (4.5)
 (53.1)

 240195
 4.6
 10.2

 230695
 0.2
 1.9

 220657
 October 1, 2022
 (0.04)
 (0.4)

 Property tax tracker
 240201
 (0.5)
 (5.6)

 230220
 (0.02)
 (0.2)

 220235
 May 1, 2022
 0.02
 0.2

 Purchased gas adjustment
 101, 106
 240708
 November 1, 2024
 10.6
 124.4

 230769
 November 1, 2023
 (24.2)
 (309.4)

 220715
 November 1, 2022
 14.9
 155.3

 Rates not subject to refund
 141N
 240005
 January 29, 20253

 0.3
 3.0

 230393
 May 11, 2024
 0.08
 1.1

 230889
 (2.3)
 (27.6)

 220067
 January 7, 2023
 (0.1)
 (1.6)

 Rates subject to refund
 141R
 240005
 January 29, 20253

 (5.8)
 (59.5)

 230889
 4.0
 47.2

 230323
 November 1, 2023
 (0.1)
 (1.4)

 220067
 January 7, 2023
 4.1
 45.5

 Revenue decoupling adjustment mechanism

 240222
 2.7
 28.0

 230207
 (1.3)
 (16.4)

 220228
 May 1, 20224

 (0.7)
 (7.4)

 ____________________
 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. For additional information on the Climate Commitment Act Deferral, see Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.
 2.Per the 2022 GRC Final Order in Docket No. UG-220067, Schedule 149 rates were set to zero as of January 7, 2023.
 3.Approved in 2024 GRC Final Order in Docket No. UG-240005, effective January 29, 2025.
 4.For rates effective May 1, 2022, there were no excess earnings that impacted the approved revenue change.

 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 outstanding debt 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 this Item 7 of this report.

 Regulatory Compliance Costs and Expenditures
 PSE's operations are subject to extensive federal, state and local laws and regulations, which impact electric system reliability, natural gas pipeline system safety and energy market transparency, among other areas. The Company's operations are also impacted by environmental laws and regulations related to air and water quality, climate change, avian and endangered species protection, waste handling, waste disposal, remediation of contaminated sites and the environmental impacts of new facilities. 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.
 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 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. 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 led to increases in costs to customers, the Washington Commission also indicated these revenues are subject-to-refund, which introduces the risk that PSE may not be able to recover all costs. Electric CCA-related costs have not been approved for recovery at this time and it is uncertain whether these costs will be passed to customers. PSE faces continued risks associated with the program, including the evolving nature of the CCA rulemaking, related interpretation of the rules, credit volatility and unresolved recovery methodology for the CCA's impact on energy costs, company costs and customer rate impacts.
 Compliance with these or other future regulations, such as those pertaining to climate change, could require significant capital expenditures by PSE, which 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, municipalities and efforts by citizens organizing to form such entities that want to establish their own government-owned utility, which could cause PSE to lose a number of customers. PSE's natural gas customers may also elect to use heating oil, propane or other fuels instead of using and purchasing natural gas. 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.
 Additionally, PSE faces increasing competition from other entities, primarily in the technology sector, where several large companies have entered into power purchase agreements to meet their growing energy needs. This capacity will largely be used to fulfill commitments for additional cloud computing and artificial intelligence data centers, reduce carbon emissions and increase reliance on renewable energy sources. The increasing competitive pressure may impact the Company's ability to acquire generation and transmission resources and/or increase the cost to acquire such resources.

 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, 2024 and December 31, 2023.

 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:

 2024
 2023

 Operating income (loss)
 $
 602,120
 $
 335,452

 Electric utility revenue

 Purchased electricity
 (1,196,897)
 (1,110,572)

 Electric generation fuel
 (336,725)
 (457,287)

 Residential exchange
 85,175
 77,223

 Utility electric margin (non-GAAP)
 $
 1,884,248
 $
 1,855,231

 Natural gas operating revenue
 $
 1,492,254
 $
 1,424,368

 Purchased natural gas
 (679,433)
 (641,371)

 Utility natural gas margin (non-GAAP)
 $
 812,821
 $
 782,997

 Other revenue
 $
 $
 16,383

 Unrealized gain (loss) on derivative instruments, net
 33,911
 (284,495)

 Other operation and maintenance expenses
 (785,088)
 (735,278)

 (21,664)
 (28,658)

 (918,472)
 (865,969)

 Taxes other than income tax expense
 (403,918)
 (404,759)

 Operating income (loss)
 $
 602,120
 $
 335,452

 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, 2023 to December 31, 2024:

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

 2023 compared to 2024
 Electric Operating Revenue
 Electric operating revenues decreased $13.3 million primarily due to decreases in sales to other utilities of $221.2 million, transportation and other revenue of $69.0 million and decoupling revenue of $4.3 million, partially offset by increases in retail sales of $262.3 million and other decoupling revenue of $18.9 million. These items are discussed in detail below:
 • Electric retail sales increased $262.3 million due to an increase of $261.7 million in rates compared to the prior year. The increase in rates is primarily due to the tariffs filed pursuant to the Company's 2024 variable power cost update effective January 1, 2024 and rate increases from the 2022 GRC. See "Regulation of PSE Rates and Recovery of PSE Costs" included in this Item 7 of this report.
 • Sales to other utilities decreased $221.2 million primarily due to a 38.6% decrease in the average price of electric wholesale sales and an 8.8% decrease in wholesale sales volume. Lower wholesale power prices were a result of lower natural gas prices and compounded by moderate loads during the period. The decrease in wholesale sales volume was driven by an environment where it was less economic to dispatch PSE units leading to a reduction in total combustion turbine (CT) and coal generation of 6.5% and 17.9%, respectively. Additionally, a planned major maintenance outage also reduced coal generation.

 • Decoupling revenue decreased $4.3 million which was attributable to a $10.3 million decrease in delivery deferral revenues; partially offset by a $6.0 million increase in fixed production cost deferral revenues. This was driven primarily by changes in decoupling volumetric rates in 2024.
 • Other decoupling revenue increased $18.9 million, primarily due to changes in amortization rates. In 2024, more overcollected balances were amortized as compared to 2023.
 • Transportation and other revenue decreased $69.0 million primarily due to a $68.2 million decrease in net wholesale non-core natural gas sales and a decrease of $7.3 million in transmission revenue. The decrease in wholesale non-core natural gas sales was primarily driven by an increase of $51.4 million in financial hedging costs in 2024 compared to 2023 as natural gas hedges moved to a loss in 2024 as compared to a gain in 2023. Additionally, net wholesale non-core natural gas sales decreased $16.5 million which was primarily driven by a 54.8% decrease in the average price of natural gas sold. These decreases were partially offset by an increase in the amortization of unspent low income program funds of $8.1 million, see "Regulation of PSE Rates and Recovery of PSE Costs" included in Item 7 of this report.

 Electric Power Costs
 Electric power costs decreased $42.2 million primarily due to a decrease of $120.6 million of electric generation fuel costs and an $8.0 million increase in residential exchange credits, partially offset by an increase of $86.3 million of purchased electricity costs. These items are discussed in detail below:
 • Purchased electricity expense increased $86.3 million primarily due to increased wholesale purchase prices, which were 8.6% higher in 2024 compared to 2023. Higher average wholesale purchase prices were driven by open market purchases as well as PPA contracts added after December 31, 2023. This was partially offset by wholesale electricity purchase volumes that decreased marginally by 0.8% in 2024 compared to 2023.
 • Electric generation fuel expense decreased $120.6 million primarily due to a $113.9 million decrease in natural gas fuel costs resulting from lower natural gas prices and decreased gas-fired CT generation of 9.6%. Further, Colstrip fuel expense decreased $6.6 million driven by a reduction of coal generation by 17.9% in 2024 as compared to 2023.
 • Residential exchange credits increased by $8.0 million due to a 0.4% change in the amount of credits to be passed back to customers effective November 1, 2023 and an increase in residential usage of 0.7%; see "Regulation of PSE Rates and Recovery of PSE Costs" included in this Item 2 of this report.

 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, 2023 to December 31, 2024:

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

 2023 compared to 2024
 Natural Gas Operating Revenue
 Natural gas operating revenue increased $67.9 million primarily driven by higher transportation and other revenue of $160.3 million and decoupling revenue of $10.1 million; partially offset by a decrease in retail sales of $96.2 million,and other decoupling revenue of $6.3 million. These items are discussed in the following details:
 • Natural gas retail sales decreased $96.2 million due to a decrease in rates of $71.3 million and a decrease in natural gas load of 2.3% or $24.9 million of natural gas sales. The decrease in rates is due to a decrease in the Company's most recent PGA rates effective November 2023 and a pass back of CCA auction proceeds, which were partially offset by an increase in rates driven by Schedule 111 that includes a charge for CCA allowance costs. 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 residential, interruptible and commercial firm usage of 2.4%, 14.9% and 5%, respectively. The decrease in natural gas load was driven by a 1.3% decrease in heating degree days in the first and fourth quarters of 2024 as compared to 2023.

 • Decoupling revenue increased $10.1 million, primarily due to decreased natural gas usage, as mentioned above, in 2024 compared to 2023.
 • Other decoupling revenue decreased $6.3 million primarily due to decreases in amortization rates related to prior period undercollections.
 • Transportation and other revenue increased $160.3 million primarily due to $181.7 million related to the regulatory offset of CCA auction proceeds passed back to customers, which were passed through to customers as credits on billed revenue included within natural gas retail revenues above and an increase in transportation revenue of $5.9 million. The increases were partially offset by (i) a decrease of $24.9 million due to the disallowance of the Company's deferred return on its investment in the Tacoma LNG Facility that was recorded between February 1, 2022, and January 11, 2023 as well as deferred return from the year ended December 31, 2023 included in rates under Schedule 141LNG; and (ii) deferral related to the bill discount rider of $7.4 million. See Note 4, "Regulation and Rates" included in Item 8 of this report for further details on the Washington Commission's order on Tacoma LNG.

 Natural Gas Energy Costs
 Purchased natural gas expense increased $38.1 million primarily due to an increase of $223.5 million in amortization of deferred CCA emission allowance costs, which were passed through to customers as billed revenue included within natural gas retail revenues above. The increase was partially offset by a decrease in the PGA rates in November 2023 and a decrease in natural gas usage of 2.3% 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, 2023 to December 31, 2024:

 2023 compared to 2024
 Other Operating Expenses
 • Net unrealized (gain) loss on derivative instruments changed $318.4 million to a net loss of $33.9 million for the year ended December 31, 2024. The change was due to the deferral of unrealized gain or loss on derivative instruments consistent with the approved accounting petition in Docket No. UE-240773. For further details, see Note 4, "Regulation and Rates" and Note 10, "Accounting for Derivative Instruments and Hedging Activities" in the Combined Notes to Consolidated Financial Statements included in Item 8 of this report.
 • Utility Operations and Maintenance expense increased $49.8 million primarily due to increases in the following: (i) $34.3 million due to an increase in Schedule 129 - low income program in electric and natural gas rates, see "Regulation of PSE Rates and Recovery of PSE Costs" included in this Item 7 of this report, (ii) $5.5 million in pension related expenses, (iii) $4.0 million related to distribution overhead lines from increased storm events and (iv) $3.3 million related to maintenance on other power generation and electric equipment.
 • Non-utility and other expense decreased $7.1 million due to a decrease of $9.9 million in biogas purchase expenses driven by a reduction in biogas purchased in 2024 compared to 2023.

 • Depreciation and amortization expense increased $52.5 million primarily due to: (i) $15.8 million increase in conservation amortization due to increases in conservation rates effective May 1, 2024, (ii) $10.5 million increase in electric distribution depreciation from 2023 primarily driven by net additions of electric distribution underground conductors and device assets, (iii) $6.1 million in electric and common amortization primarily driven by net additions of computer software assets, (iv) $5.7 million increase in electric transmission depreciation primarily driven by net additions of electric transmission poles and fixtures, (v) $5.4 million increase in natural gas amortization driven by net additions of natural gas computer software assets and a reduction in deferrals of LNG amortization, and (vi) $4.7 million increase in natural gas distribution depreciation primarily driven by net additions in natural gas distribution plastic mains assets.

 Other Income, Interest Expense and Income Tax Expense
 • Other income/expense increased $31.0 million from net other income of $49.5 million in 2023 to net other income of $80.5 million in 2024, due to an increase of $35.8 million in other income that was partially offset by an increase of $4.8 million in other expense. The increase in other income was primarily due to (i) a $20.5 million increase in equity AFUDC due to an increase in eligible CWIP and AFUDC rates, (ii) an increase in taxable interest and dividend income of $4.6 million driven by interest income related to the investment of bond proceeds from the June 2024 bond issuances and (iii) an increase of $5.5 million for the non-service cost component of the qualified pension net periodic benefit cost. These increases to other income were partially offset by a $2.3 million reduction to the corporate life insurance gain. The increase in other expense was primarily due to $2.6 million related to the disallowance of certain natural gas quality pretreatment equipment and natural gas distribution mains per the Washington Commission order under Docket No. UG-230393 and $2.4 million related to Colstrip major maintenance. For further details on the bond proceeds see Note 7, "Long-Term Debt" in the Combined Notes to Consolidated Financial Statements included in Item 8 of this report.
 • Interest expense increased $23.4 million primarily due to an increase of $32.8 million in interest expense due to the May 2023 and June 2024 PSE bond issuances and $6.1 million related to the CCA natural gas recovery. This was partially offset by an increase in debt AFUDC of $13.0 million due to an increase in eligible CWIP and AFUDC rates and a decrease of $2.7 million in interest expense related to the PGA.
 • Income tax expense increased $59.2 million primarily driven by an increase in pre-tax book income and an $8.7 million increase caused by the discontinuance in 2023 of the 3-year amortization of the unprotected excess deferred income taxes associated with the Tax Cuts and Jobs Act.

 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, 2023 and December 31, 2024, were as follows:

 2023 compared to 2024
 Summary Results of Operations
 Puget Energy's net income increased by $211.5 million, which is primarily attributable to: (i) an increase in PSE's net income of $215.1 million, (ii) an increase in PLNG's net income of $8.2 million and (iii) an increase of tax benefit of $3.2 million. These increases were partially offset by an increase in interest expense of $13.8 million related to higher amounts drawn on Puget Energy's revolving credit agreement.

 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, 2024:

 Payments Due Per Period

 Total
 2025
 2026-2027
 2028-2029

 Contractual obligations:

 Energy purchase obligations1

 $
 14,178,664
 $
 1,745,285
 $
 2,280,470
 $
 1,690,570
 $
 8,462,339

 Long-term debt including interest2

 11,212,499
 322,524
 906,914
 660,867
 9,322,194

 Short-term debt including interest
 40,000
 40,000
 —
 —
 —

 Service contract obligations
 263,047
 36,920
 81,171
 84,462
 60,494

 Non-cancelable operating leases3

 262,253
 24,687
 49,327
 34,302
 153,937

 PSE finance leases3

 131,468
 7,097
 14,163
 14,070
 96,138

 Pension and other benefits funding

 49,445
 8,170
 4,860
 10,786

 Total PSE contractual cash obligations
 26,137,376
 2,202,142
 3,340,215
 2,489,131
 18,105,888

 Long-term debt including interest2

 2,328,662
 462,913
 115,106
 596,726
 1,153,917

 Short-term debt including interest
 365,283
 365,283
 —
 —
 —

 Total Puget Energy contractual cash obligations
 $
 28,831,321
 $
 3,030,338
 $
 3,455,321
 $
 3,085,857
 $
 19,259,805

 ____________________
 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, 2024, 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 were designed to meet regulatory requirements, support customer growth and improve energy system safety and reliability. The Company's capital expenditures were $145.0 million less than forecasted amounts for 2024. The decrease was primarily due to: (i) timing and project schedule constraints associated with strategic project spend, (ii) project savings related to electric reliability initiatives, (iii) timing of project spend associated with generation projects, (iv) timing and transition to PPA agreements that reduced capital expenditures related to product development, and (v) timing of project spend associated with IT projects. Construction expenditures, excluding equity AFUDC, totaled $1.6 billion in 2024.

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

 Capital Expenditure Projections

 (Dollars in Millions)
 2025
 2026
 2027

 Total energy delivery, technology and facilities expenditures
 $
 1,676.1
 $
 1,789.6
 $
 2,421.1

 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

 2024
 2023
 Change

 Net income
 $
 $
 $
 215,089

 Non-cash items1

 826,834
 990,519
 (163,685)

 Changes in cash flow resulting from working capital2

 43,156
 (174,908)
 218,064

 Regulatory assets and liabilities
 (89,838)
 153,069
 (242,907)

 Purchased gas adjustment
 (73,426)
 152,763
 (226,189)

 (154,728)
 (129,195)
 (25,533)

 Other non-current assets and liabilities3

 (19,058)
 (32,247)
 13,189

 Net cash (used in)/provided by operating activities
 $
 879,088
 $
 1,091,060
 $
 (211,972)

 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, 2024, compared to 2023
 Cash generated from operations decreased by $212.0 million despite an increase in net income of $215.1 million. The following are significant factors that impacted PSE's cash flows from operations:
 • Cash flow adjustments resulting from non-cash items decreased $163.7 million, primarily due to: (i) a $318.4 million change from a net unrealized loss on derivative instruments of $284.5 million to a net unrealized gain on derivative instruments of $33.9 million. The change was due to the deferral of unrealized gain or loss on derivative instruments consistent with the approved accounting petition in Docket No. UE-240773 and (ii) a decrease in equity AFUDC of $20.5 million. The decreases were partially offset by: (i) an increase in deferred taxes of $110.2 million, (ii) an increase in depreciation and amortization of $36.7 million, (iii) increased conservation amortization of $15.8 million and (iv) a deferral of return and depreciation expenses for PSE's share of Tacoma LNG investment of $10.0 million.
 • Cash flows resulting from changes in working capital increased $218.1 million primarily due to: (i) cash inflows from accounts payable increased $318.9 million due to a $78.2 million increase in 2024 and a decrease of $240.7 million in 2023, (ii) lower prepayment balances of $24.5 million, (iii) an increase of $16.7 million due to higher taxes payable and (iv) an increase in materials and supplies, which increased less in 2024 compared to 2023 that led to cash inflows of $12.9 million. The increases were partially offset by cash outflows of $159.4 million in accounts receivable and unbilled revenue as the balance increased $22.7 million in 2024 compared to a decrease of $136.7 million during 2023.

 • Cash flows resulting from regulatory assets and liabilities decreased $242.9 million primarily due to: (i) $76.6 million of cash outflow from power cost adjustment receivable, which was due to actual power costs being higher than baseline rates in 2024, whereas actual power costs were lower than baseline rates in 2023, (ii) $56.8 million of cash outflow from storm damage costs primarily due to the damage caused by a significant windstorm event in November 2024, (iii) $29.6 million decrease due to changes in property tax tracker, (iv) $26.4 million of cash outflow driven by higher expenses incurred for conservation in 2024 compared to 2023, (v) $20.6 million of cash outflow related to low income programs, primarily driven by an $18.3 million decrease due to recovery of the Crisis Affected Customer Assistance Program through Schedule 129 in 2023, at which point the program was fully recovered, thus there was no recovery in 2024, (vi) $20.0 million of cash outflow related to revenue decoupling mechanism, which the overcollection deferral decreased $17.2 million in 2024 compared to an increase of $2.8 million in 2023 and (vii) $9.9 million decrease in cash flow from incremental deferrals related to COVID-19 in 2024 compared to 2023.
 • Cash flow resulting from purchased gas adjustment decreased $226.2 million, which was mainly driven by an increase in actual natural gas costs and a decrease in allowed PGA recovery in 2024 compared to 2023. Increased natural gas prices led to a $12.3 million, or 3.1%, increase in actual natural gas costs in 2024 compared to 2023. Meanwhile, the total amount of allowed PGA recovery in 2024 decreased $185.7 million, or 35.6%, compared to 2023. In addition, a $28.1 million decrease was due to a refund (including interest) from a counterparty settlement received in January 2023.
 • Cash flows resulting from changes in GHG emission allowances decreased $25.5 million that 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.
 • Cash flow resulting from other non-current assets and liabilities increased $13.2 million primarily due to: (i) increased accruals related to the Company's long-term incentive plan of $6.0 million and (ii) $7.0 million driven by lower balances related to the residential exchange program.

 2024
 2023
 Change

 Net income
 $
 (80,893)
 $
 (77,319)
 $
 (3,574)

 Non-cash items1

 26,651
 42,770
 (16,119)

 Changes in cash flow resulting from working capital2

 (649)
 1,242

 Other non-current assets and liabilities3

 (2,616)
 (2,467)
 (149)

 Net cash (used in)/provided by operating activities
 $
 (56,265)
 $
 (37,665)
 $
 (18,600)

 ______________
 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, 2024, compared to 2023
 Cash generated from operations for the year ended December 31, 2024, in addition to the changes discussed at PSE above, decreased by $18.6 million compared to the same period in 2023, which includes a net income decrease of $3.6 million. The remaining change was primarily impacted by the factors explained below:
 • Changes in cash flow resulting from non-cash items decreased $16.1 million primarily due to higher non-cash inflows of $16.1 million related to changes in deferred taxes.

 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, 2024, both Puget Energy and PSE have stable outlooks from Moody's, Fitch, and S&P. Although neither Puget Energy nor PSE have any outstanding 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
 PSE's future long-term financings may be limited in type and amount due to provisions over 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, 2024, PSE could issue:
 • Approximately $0.9 billion of additional first mortgage bonds under PSE's electric mortgage indenture based on approximately $1.6 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, 2024; and
 • Approximately $1.2 billion of additional first mortgage bonds under PSE's natural gas mortgage indenture based on approximately $2.0 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, 2024.
 At December 31, 2024, PSE had approximately $9.8 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 are 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 charged to PSE 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 regulatory assets and liabilities as of December 31, 2024, in the amount of $1,416.5 million and $1,855.6 million, respectively, and regulatory assets and liabilities as of December 31, 2023, of $1,212.0 million and $1,914.9 million, respectively. These amounts are amortized through a corresponding liability or asset account, 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 these off. 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 subject to regulatory accounting and ASC 980 are the PCA and PGA mechanisms. The PCA and PGA mechanisms mitigate the impact of commodity price volatility and are approved by the Washington Commission on a periodic basis. The PCA mechanism provides for a sharing of costs that vary from baseline rates over a graduated scale. The variable cost of natural gas supply is reflected in customer bills through the PGA mechanism. PSE expects to fully recover or refund these regulatory balances through its rates. 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.

 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 such as forward physical and financial contracts and swaps to manage its energy resource portfolio and interest rate exposure. 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.
 Historically, electric contracts that did not meet the NPNS exception were marked-to-market to current earnings in the statements of income, while natural gas derivative contracts qualified for deferral under ASC 980 due to the PGA mechanism. On December 19, 2024, the Washington Commission approved PSE's accounting petition in Docket No. UE-240773 to offset any derivative assets or liabilities, entered into in order to serve electric customers, with a regulatory asset or liability, thus deferring the unrealized gains or losses. Therefore, as of December 31, 2024 the unrealized gains and losses on both electric and natural gas derivative contracts qualified for deferral under ASC 980.
 PSE values derivative instruments based on daily quoted prices from an independent external pricing service. The Company regularly confirms the validity of pricing service's quoted prices (e.g. Level 2 in the fair value hierarchy) by comparing the quoted commodity contracts value 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

 relies on 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 price volatility risk. The exposure position is determined by using a probabilistic risk assessment (PRA) 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 existing and former work sites. Such sites include former manufactured gas plants and contaminated facilities operated by PSE predecessors, such as Gas Works Park on the shore of Lake Union in Seattle and a long-defunct creosote manufacturer, which had purchased waste products from PSE predecessors (e.g. Quendall Terminals site on Lake Washington in Renton, Washington), respectively. In each case, PSE assesses the environmental remediation obligations related to the contaminated sites based on in-depth studies, which include assessments of the probabilities of recovery from other responsible parties and/or insurance carriers, expert analyses and legal reviews. 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, third parties and/or 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 (i.e. exit price). However, as permitted under ASC 820, the Company utilizes a mid-market pricing convention, which is 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 income of $5.1 million and expense of $0.3 million for the years ended December 31, 2024, and 2023, respectively. Of these amounts, approximately 45.8% and 46.6% were included in utility operations and maintenance expense in 2024 and 2023, respectively and the remaining amounts were capitalized. For the years ended December 31, 2024, and 2023, Puget Energy recognized incremental qualified pension income of $2.7 million and $2.4 million, respectively. In 2025, it is expected that PSE and Puget Energy will recognize pension income of $7.2 million and incremental qualified pension income of $4.8 million, respectively.
 PSE has a SERP and other limited postretirement benefit plans, for which expenses for the years ended December 31, 2024 and 2023 were immaterial for both PSE and PE. Further, PSE and PE expect to recognize immaterial expenses in 2025 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 2024, 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, 2024, and 2023, the Company's qualified pension plan was $195.7 million overfunded and $136.9 million overfunded as measured under GAAP, or 133.9% and 121.0% funded, respectively. As of January 1, 2025, 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, 2025, are expected to be at least $18.0 million, $6.8 million and $0.2 million, respectively.
 The discount rate used in accounting for pension and other benefit obligations increased from 5.30% in 2023 to 5.80% in 2024. The discount rate used in accounting for pension and other benefit expense decreased from 5.60% in 2023 to 5.30% in 2024. The rate of return on plan assets for qualified pension benefits increased from 6.75% in 2023 to 7.00% in 2024. The rate of return on plan assets for other benefits was 7.00% in both 2023 and 2024.
 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

 $
 (26,828)

 $
 (570)

 $
 (262)

 Decrease in discount rate

 29,311

 Change in Assumption

 Impact on 2024
 Pension Expense
 Increase /(Decrease)

 SERP

 Other Benefits

 Increase in discount rate

 $
 (2,449)
 $

 $
 (29)

 Decrease in discount rate

 2,601
 (50)

 Increase in return on plan assets

 $
 (3,923)
 *

 $
 (21)

 Decrease in return on plan assets

 3,922
 *

 Change in Assumption

 Impact on 2024
 Pension Expense
 Increase /(Decrease)

 SERP

 Other Benefits

 Increase in discount rate

 $
 $

 $
 (30)

 Decrease in discount rate

 (71)

 Increase in return on plan assets

 $
 (3,923)
 *

 $
 (21)

 Decrease in return on plan assets

 3,922
 *

 * 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. It is comprised of certain PSE officers, which is overseen by the PSE Board of Directors. The committee is responsible for reviewing risk tolerances and limits, establishing delegations of authority, maintaining systemic and procedural adequacy of control system, and monitoring compliance. 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: (i) minimize commodity price exposure and risks associated with volumetric variability, (ii) ensure physical energy supplies are available to serve retail customer-loads, while (iii) limiting undesired impacts or portfolio risks and (iv) 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 assessment (PRA) 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 ability to flexibly 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
 $
 29,274
 $
 166,632
 $
 62,929
 $
 107,195

 Long-term
 6,067
 152,874
 30,099
 19,744

 Total Electric Portfolio
 $
 35,341
 $
 319,506
 $
 93,028
 $
 126,939

 Natural gas portfolio:

 Current
 3,317
 51,811
 11,296
 78,593

 Long-term
 18,614
 5,225
 18,305

 Total Natural Gas Portfolio
 $
 3,495
 $
 70,425
 $
 16,521
 $
 96,898

 Total derivatives
 $
 $
 $
 $

 At December 31, 2024, the Company had total assets of $38.8 million and total liabilities of $389.9 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. 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. Any fair value adjustments relating to the electric and natural gas businesses have been deferred in accordance with ASC 980.
 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 $82.3 million.
 The change in fair value of the Company's outstanding energy derivative instruments from December 31, 2023, through December 31, 2024, 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, 2023
 $
 (114,288)

 Contracts realized or otherwise settled during 2024
 266,924

 Change in fair value of derivatives
 (503,731)

 Fair value of contracts outstanding at December 31, 2024
 $
 (351,095)

 The fair value of the Company's outstanding derivative instruments at December 31, 2024, 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

 2025
 2026-2027
 2028-2029
 Total

 Prices provided by external sources1

 $
 (133,052)
 $
 (38,709)
 $
 (5,616)
 $
 —
 $
 (177,377)

 Prices based on internal models and valuation methods
 (52,800)
 (51,045)
 (16,318)
 (53,555)
 (173,718)

 Total fair value
 $
 (185,852)
 $
 (89,754)
 $
 (21,934)
 $
 (53,555)
 $
 (351,095)

 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 types of 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 exposure 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 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 considered in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure. As of December 31, 2024, PSE held approximately $790.2 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, 2024, approximately 93.0% of the Company's total energy portfolio exposure was entered into with investment grade counterparties, which typically 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 or loss positions. As of December 31, 2024, 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, 2024, PSE had cash posted as collateral of $7.8 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, 2024, PSE had no cash posted with ICE NGX, and $6.6 million was issued under the standby letter of credit agreement in support of natural gas and carbon allowance purchases. In support of purchase power contracts, PSE posted cash collateral of $15.0 million and maintained two standby letters of credit in the amounts of $60.0 million and $13.5 million. 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, 2024.

 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 with 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 Company may also enter into swaps or other financial hedge instruments to manage the interest rate risk associated with the debt.
 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

 $
 $
 6,966,211
 $
 $
 6,855,503

 5,492,999
 5,007,483

 For further details regarding Puget Energy and PSE 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, 2024, was a net loss of $3.4 million after-tax and accumulated amortization. This compares to an after-tax loss of $3.8 million in OCI as of December 31, 2023. 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, 2024.
 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, 2024, 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, 2024, 2023, and 202 2

 Consolidated Statements of Comprehensive Income - Years Ended December 31, 2024, 2023, and 202 2

 Consolidated Balance Sheets - December 31, 2024 and 202 3

 Consolidated Statements of Common Shareholder's Equity - Years Ended December 31, 2024, 2023, and 202 2

 Consolidated Statements of Cash Flows - Years Ended December 31, 2024, 2023, and 202 2

 PUGET SOUND ENERGY:

 Consolidated Statements of Income - Years Ended December 31, 2024, 2023, and 202 2

 Consolidated Statements of Comprehensive Income - Years Ended December 31, 2024, 2023, and 202 2

 Consolidated Balance Sheets - December 31, 2024 and 2023

 Consolidated Statements of Common Shareholder's Equity - Years Ended December 31, 2024, 2023, and 202 2

 Consolidated Statements of Cash Flows - Years Ended December 31, 2024, 2023, and 2022

 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)

 Note 18

 Segment Information

 SCHEDULE:

 I. Condensed Financial Information of Puget Energy - December 31, 2024, and 2023, and for the Years Ended December 31, 2024, 2023, and 2022

 II. Valuation and Qualifying Accounts and Reserves - Years Ended December 31, 2024, 2023, 2022

 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/ Jamie Martin

 /s/ Stacy Smith

 Jamie Martin

 Stacy Smith

 President and Chief Executive Officer

 Sr VP & 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, 2024, 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, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 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, 2024, 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 Controls 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 $1,421.3 million of regulatory assets and $1,886.8 million of regulatory liabilities as of December 31, 2024. 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, 2024, 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, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 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, 2024, 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 Controls 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 $1,416.5 million of regulatory assets and $1,855.6 million of regulatory liabilities as of December 31, 2024. 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

 2024
 2023
 2022

 Operating revenue:

 $
 $
 $
 2,961,457

 Natural gas
 1,488,570
 1,423,276
 1,209,636

 Other
 34,950
 47,431
 50,069

 4,856,215
 4,816,574
 4,221,162

 Operating expenses:

 Energy costs:

 Purchased electricity
 1,196,897
 1,110,572
 1,038,728

 Electric generation fuel
 336,725
 457,287
 348,159

 Residential exchange
 ( 85,175)
 ( 77,223)
 ( 77,715)

 Purchased natural gas
 679,433
 641,371
 500,849

 Unrealized (gain) loss on derivative instruments, net
 ( 33,911)
 284,495
 ( 261,177)

 Utility operations and maintenance
 785,088
 735,278
 665,259

 46,056
 56,515
 59,804

 787,986
 751,335
 663,232

 Conservation amortization
 137,147
 121,340
 116,942

 Taxes other than income taxes
 398,773
 404,538
 389,442

 Total operating expenses
 4,249,019
 4,485,508
 3,443,523

 Operating income (loss)
 607,196
 331,066
 777,639

 Other income (deductions):

 Other income
 102,882
 66,829
 45,450

 Other expense
 ( 19,566)
 ( 14,765)
 ( 19,569)

 Interest charges:

 AFUDC
 37,660
 24,687
 18,444

 ( 432,194)
 ( 381,511)
 ( 347,921)

 Income (loss) before income taxes
 295,978
 26,306
 474,043

 Income tax (benefit) expense
 30,723
 ( 27,434)
 59,698

 $
 $
 $

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

 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 2024
 2023
 2022

 $
 $
 $

 Other comprehensive income (loss):

 Net unrealized gain (loss) from pension and postretirement plans, net of tax of $ 9,144, $ 8,916 and $ 708, respectively

 2,658

 2,658

 Comprehensive income (loss)
 $
 290,884
 $
 96,053
 $
 417,003

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

 CONSOLIDATED BALANCE SHEETS

 ASSETS

 2024
 2023

 Utility plant (at original cost, including construction work in progress of $ 1,577,695 and $ 1,156,265, respectively):

 Electric plant
 $
 12,476,380
 $
 11,304,995

 Natural gas plant
 5,178,523
 4,928,725

 Common plant
 1,089,618
 1,003,519

 Less: Accumulated depreciation and amortization
 ( 5,101,926)
 ( 4,643,833)

 Net utility plant
 13,642,595
 12,593,406

 Other property and investments:

 Goodwill
 1,656,513
 1,656,513

 Other property and investments
 307,813
 312,353

 Total other property and investments
 1,964,326
 1,968,866

 Current assets:

 Cash and cash equivalents
 101,836
 148,548

 Restricted cash
 38,865
 66,027

 Accounts receivable, net of allowance for doubtful accounts of $ 40,436 and $ 38,211, respectively

 538,930
 546,701

 Unbilled revenue
 273,420
 243,342

 Materials and supplies, at average cost
 201,847
 173,445

 Fuel and natural gas inventory, at average cost
 88,964
 87,510

 Unrealized gain on derivative instruments
 32,591
 74,225

 43,592

 Prepaid expenses and other
 83,851
 75,342

 Power contract acquisition adjustment gain
 4,122
 16,358

 Total current assets
 1,408,018
 1,432,435

 Other long-term and regulatory assets:

 Power cost adjustment mechanism
 61,202
 48,427

 Regulatory assets related to power contracts
 4,779
 6,266

 Other regulatory assets
 1,355,291
 1,163,551

 Unrealized gain on derivative instruments
 6,245
 35,324

 Power contract acquisition adjustment gain
 26,444
 30,566

 Operating lease right-of-use asset
 181,397
 194,321

 Other
 310,094
 259,291

 Total other long-term and regulatory assets
 1,945,452
 1,737,746

 $
 18,960,391
 $
 17,732,453

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

 CONSOLIDATED BALANCE SHEETS

 CAPITALIZATION AND LIABILITIES

 2024
 2023

 Capitalization:

 Common shareholder's equity:

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

 $
 —
 $
 —

 Additional paid-in capital
 3,816,332
 3,523,532

 Retained earnings
 1,508,705
 1,419,311

 Accumulated other comprehensive income (loss), net of tax
 43,168
 17,539

 Total common shareholder's equity
 5,368,205
 4,960,382

 Long-term debt:

 First mortgage bonds and senior notes
 5,845,000
 5,062,000

 Pollution control bonds
 161,860
 161,860

 Long-term debt
 1,600,000
 2,000,000

 Debt discount, issuance costs and other
 ( 182,941)
 ( 187,218)

 Total long-term debt

 Total capitalization
 12,792,124
 11,997,024

 Current liabilities:

 Accounts payable
 549,710
 455,942

 Short-term debt
 378,400
 598,100

 Current maturities of long-term debt
 417,000
 —

 Accrued expenses:

 Taxes
 105,080
 102,627

 Salaries and wages
 74,294
 68,726

 Interest
 66,113
 63,829

 Unrealized loss on derivative instruments
 218,443
 185,788

 Power contract acquisition adjustment loss
 1,074
 1,487

 Operating lease liabilities
 22,761
 21,629

 43,592

 Other
 105,605
 67,653

 Total current liabilities
 1,982,072
 1,566,718

 Other Long-term and regulatory liabilities:

 Deferred income taxes
 997,680
 950,229

 Unrealized loss on derivative instruments
 171,488
 38,049

 Purchased gas adjustment liability
 58,657
 132,082

 Regulatory liabilities
 1,075,620
 1,022,457

 Regulatory liability for deferred income taxes
 721,907
 760,961

 Regulatory liabilities related to power contracts
 30,566
 46,924

 Power contract acquisition adjustment loss
 3,705
 4,779

 Operating lease liabilities
 166,700
 180,754

 Finance lease liabilities
 96,850
 99,512

 73,049
 168,879

 Other deferred credits
 789,973
 764,085

 Total long-term and regulatory liabilities
 4,186,195
 4,168,711

 Commitments and contingencies (Note 16)

 Total capitalization and liabilities
 $
 18,960,391
 $
 17,732,453

 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, 2021

 $
 —
 $
 3,523,532
 $
 1,067,216
 $
 ( 27,432)
 $
 4,563,316

 —
 —
 —
 —

 —
 —
 —
 ( 16,230)
 —
 ( 16,230)

 —
 —
 —
 —
 2,658
 2,658

 Balance at December 31, 2022

 $
 —
 $
 3,523,532
 $
 1,465,331
 $
 ( 24,774)
 $
 4,964,089

 —
 —
 —
 —

 —
 —
 —
 ( 99,760)
 —
 ( 99,760)

 —
 —
 —
 —

 Balance at December 31, 2023

 $
 —
 $
 3,523,532
 $
 1,419,311
 $
 17,539
 $
 4,960,382

 —
 —
 —
 —

 —
 —
 —
 ( 175,861)
 —
 ( 175,861)

 —
 —
 —
 —

 —
 —
 —
 —

 Balance at December 31, 2024
 $
 —
 $
 3,816,332
 $
 1,508,705
 $
 43,168
 $
 5,368,205

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

 CONSOLIDATED STATEMENTS OF CASH FLOWS

 2024
 2023
 2022

 Operating Activities:

 Net Income (Loss)
 $
 $
 $

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

 787,986
 751,335
 663,232

 Conservation amortization
 137,147
 121,340
 116,942

 Deferred income taxes and tax credits, net
 ( 747)
 ( 94,835)
 17,941

 Net unrealized (gain) loss on derivative instruments
 ( 33,911)
 284,495
 ( 261,177)

 AFUDC - equity
 ( 59,466)
 ( 39,012)
 ( 28,310)

 Other non-cash
 22,476
 9,966
 4,757

 Funding of pension liability

 Regulatory assets and liabilities
 ( 89,838)
 153,069
 ( 90,335)

 Purchased gas adjustment
 ( 73,426)
 152,763
 37,256

 ( 154,728)
 ( 129,195)
 —

 Other long term assets and liabilities
 ( 3,674)
 ( 16,714)
 ( 23,639)

 Change in certain current assets and liabilities:

 Accounts receivable and unbilled revenue
 ( 22,307)
 138,646
 ( 258,188)

 Materials and supplies
 ( 28,402)
 ( 41,273)
 ( 18,885)

 Fuel and natural gas inventory
 ( 1,526)
 6,565
 ( 34,682)

 Prepayments and other
 ( 8,873)
 ( 33,402)
 4,186

 Accounts payable
 79,184
 ( 244,030)
 237,260

 Taxes payable
 2,453
 ( 13,471)
 ( 11,300)

 Other
 23,220
 11,408
 18,215

 Net cash provided by (used in) operating activities
 822,823
 1,053,395
 769,618

 Investing Activities:

 Construction expenditures - excluding equity AFUDC
 ( 1,609,715)
 ( 1,466,565)
 ( 1,004,713)

 Other
 1,872
 14,047
 ( 567)

 Net cash provided by (used in) investing activities
 ( 1,607,843)
 ( 1,452,518)
 ( 1,005,280)

 Financing Activities:

 Change in short-term debt, net
 ( 219,700)
 122,500
 301,300

 Dividends paid
 ( 175,861)
 ( 99,760)
 ( 16,230)

 —
 —

 Proceeds from long-term debt and bonds issued
 793,892
 396,488
 448,075

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

 Other
 20,015
 25,685
 18,152

 Net cash provided by (used in) financing activities
 711,146
 444,913
 301,297

 Net increase (decrease) in cash, cash equivalents, and restricted cash
 ( 73,874)
 45,790
 65,635

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

 Cash, cash equivalents, and restricted cash at end of period
 $
 140,701
 $
 214,575
 $
 168,785

 Supplemental cash flow information:

 Cash payments for interest (net of capitalized interest)
 $
 376,317
 $
 339,677
 $
 320,656

 Cash payments (refunds) for income taxes
 37,065
 71,817
 46,785

 Non-cash financing and investing activities:

 Accounts payable for capital expenditures eliminated from cash flow
 $
 110,311
 $
 97,892
 $
 68,357

 Seller financing accrued liabilities for capital expenditures eliminated from cash flow

 1,700
 21,739
 —

 Capital expenditures due to change in ARO estimate eliminated from cash flow

 20,255
 ( 2,206)
 1,520

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

 CONSOLIDATED STATEMENTS OF INCOME

 2024
 2023
 2022

 Operating revenue:

 $
 $
 $
 2,961,457

 Natural gas
 1,492,254
 1,424,368
 1,209,636

 Other
 16,383
 45,080

 4,825,231
 4,786,618
 4,216,173

 Operating expenses:

 Energy costs:

 Purchased electricity
 1,196,897
 1,110,572
 1,038,728

 Electric generation fuel
 336,725
 457,287
 348,159

 Residential exchange
 ( 85,175)
 ( 77,223)
 ( 77,715)

 Purchased natural gas
 679,433
 641,371
 500,849

 Unrealized (gain) loss on derivative instruments, net
 ( 33,911)
 284,495
 ( 261,177)

 Utility operations and maintenance
 785,088
 735,278
 665,259

 21,664
 28,658
 47,194

 781,325
 744,629
 657,349

 Conservation amortization
 137,147
 121,340
 116,942

 Taxes other than income taxes
 403,918
 404,759
 388,123

 Total operating expenses
 4,223,111
 4,451,166
 3,423,711

 Operating income (loss)
 602,120
 335,452
 792,462

 Other income (deductions):

 Other income
 100,071
 64,230
 36,684

 Other expense
 ( 19,566)
 ( 14,765)
 ( 19,569)

 Interest charges:

 AFUDC
 37,660
 24,687
 18,444

 ( 321,550)
 ( 285,148)
 ( 256,774)

 Income (loss) before income taxes
 398,735
 124,456
 571,247

 Income tax (benefit) expense
 52,587
 ( 6,603)
 80,295

 $
 $
 $

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

 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 2024
 2023
 2022

 $
 $
 $

 Other comprehensive income (loss):

 Net unrealized gain (loss) from pension and postretirement plans, net of tax of $ 9,710, $ 9,434 and $ 2,580, respectively

 27,761
 44,265
 9,711

 Amortization of treasury interest rate swaps to earnings, net of tax of $ 101, $ 103 and $ 102, respectively

 28,147
 44,650
 10,097

 Comprehensive income (loss)
 $
 374,295
 $
 175,709
 $
 501,049

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

 CONSOLIDATED BALANCE SHEETS

 ASSETS

 2024
 2023

 Utility plant (at original cost, including construction work in progress of $ 1,577,695 and $ 1,156,265, respectively):

 Electric plant
 $
 14,188,252
 $
 13,043,559

 Natural gas plant
 5,726,641
 5,480,496

 Common plant
 1,110,364
 1,024,319

 Less: Accumulated depreciation and amortization
 ( 7,382,662)
 ( 6,954,968)

 Net utility plant
 13,642,595
 12,593,406

 Other property and investments:

 Other property and investments
 71,005
 69,808

 Total other property and investments
 71,005
 69,808

 Current assets:

 Cash and cash equivalents
 100,105
 144,825

 Restricted cash
 38,865
 66,027

 Accounts receivable, net of allowance for doubtful accounts of $ 40,436 and $ 38,211, respectively

 539,072
 546,463

 Unbilled revenue
 273,420
 243,342

 Materials and supplies, at average cost
 201,847
 173,445

 Fuel and natural gas inventory, at average cost
 87,118
 85,726

 Unrealized gain on derivative instruments
 32,591
 74,225

 43,592

 Prepaid expenses and other
 83,835
 75,323

 Total current assets
 1,400,445
 1,410,313

 Other long-term and regulatory assets:

 Power cost adjustment mechanism
 61,202
 48,427

 Other regulatory assets
 1,355,291
 1,163,551

 Unrealized gain on derivative instruments
 6,245
 35,324

 Operating lease right-of-use asset
 181,397
 194,321

 Other
 308,204
 256,617

 Total other long-term and regulatory assets
 1,912,339
 1,698,240

 $
 17,026,384
 $
 15,771,767

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

 CONSOLIDATED BALANCE SHEETS

 CAPITALIZATION AND LIABILITIES

 2024
 2023

 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
 3,927,905
 3,635,105

 Retained earnings
 1,665,370
 1,473,218

 Accumulated other comprehensive income (loss), net of tax
 ( 30,247)
 ( 58,394)

 Total common shareholder's equity
 5,563,887
 5,050,788

 Long-term debt:

 First mortgage bonds and senior notes
 5,845,000
 5,062,000

 Pollution control bonds
 161,860
 161,860

 Debt discount, issuance costs and other
 ( 45,835)
 ( 39,813)

 Total long-term debt

 Total capitalization
 11,524,912
 10,234,835

 Current liabilities:

 Accounts payable
 550,765
 457,965

 Short-term debt
 40,000
 336,600

 Current maturities of long-term debt
 17,000
 —

 Accrued expenses:

 Taxes
 105,754
 102,775

 Salaries and wages
 74,294
 68,726

 Interest
 56,215
 53,834

 Unrealized loss on derivative instruments
 218,443
 185,788

 Operating lease liabilities
 22,761
 21,629

 43,592

 Other
 105,605
 67,653

 Total current liabilities
 1,234,429
 1,295,907

 Other long-term and regulatory liabilities:

 Deferred income taxes
 1,117,492
 1,078,847

 Unrealized loss on derivative instruments
 171,488
 38,049

 Purchased gas adjustment liability
 58,657
 132,082

 Regulatory liabilities
 1,074,427
 1,021,193

 Regulatory liability for deferred income taxes
 722,558
 761,621

 Operating lease liabilities
 166,700
 180,754

 Finance lease liabilities
 96,850
 99,512

 73,049
 168,879

 Other deferred credits
 785,822
 760,088

 Total long-term and regulatory liabilities
 4,267,043
 4,241,025

 Commitments and contingencies (Note 16)

 Total capitalization and liabilities
 $
 17,026,384
 $
 15,771,767

 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, 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)

 —
 —
 —
 —

 —
 —
 —
 —
 44,650
 44,650

 Balance at December 31, 2023

 85,903,791
 $
 $
 3,635,105
 $
 1,473,218
 $
 ( 58,394)
 $
 5,050,788

 —
 —
 —
 —

 —
 —
 —
 ( 153,996)
 —
 ( 153,996)

 —
 —
 —
 —

 —
 —
 —
 —
 28,147
 28,147

 Balance at December 31, 2024

 85,903,791
 $
 $
 3,927,905
 $
 1,665,370
 $
 ( 30,247)
 $
 5,563,887

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

 CONSOLIDATED STATEMENTS OF CASH FLOWS

 2024
 2023
 2022

 Operating Activities:

 Net Income (Loss)
 $
 $
 $

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

 781,325
 744,629
 657,349

 Conservation amortization
 137,147
 121,340
 116,942

 Deferred income taxes and tax credits, net
 ( 10,232)
 ( 120,394)
 ( 2,103)

 Net unrealized (gain) loss on derivative instruments
 ( 33,911)
 284,495
 ( 261,177)

 AFUDC - equity
 ( 59,466)
 ( 39,012)
 ( 28,310)

 Other non-cash
 11,971
 ( 539)
 ( 6,005)

 Funding of pension liability

 Regulatory assets and liabilities
 ( 89,838)
 153,069
 ( 90,335)

 Purchased gas adjustment
 ( 73,426)
 152,763
 37,256

 ( 154,728)
 ( 129,195)
 —

 Other long term assets and liabilities
 ( 1,058)
 ( 14,247)
 ( 14,359)

 Change in certain current assets and liabilities:

 Accounts receivable and unbilled revenue
 ( 22,687)
 136,711
 ( 252,308)

 Materials and supplies
 ( 28,402)
 ( 41,273)
 ( 18,885)

 Fuel and natural gas inventory
 ( 1,392)
 6,057
 ( 33,654)

 Prepayments and other
 ( 8,876)
 ( 33,383)
 4,186

 Accounts payable
 78,216
 ( 240,714)
 228,635

 Taxes payable
 2,979
 ( 13,697)
 ( 16,934)

 Other
 23,318
 11,391
 24,211

 Net cash provided by (used in) operating activities
 879,088
 1,091,060
 817,461

 Investing Activities:

 Construction expenditures - excluding equity AFUDC
 ( 1,608,947)
 ( 1,465,925)
 ( 1,000,810)

 Other
 1,872
 14,047
 ( 567)

 Net cash provided by (used in) investing activities
 ( 1,607,075)
 ( 1,451,878)
 ( 1,001,377)

 Financing Activities:

 Change in short-term debt, net
 ( 296,600)
 ( 20,400)
 217,000

 Dividends paid
 ( 153,996)
 ( 96,004)
 ( 35,396)

 50,000

 Proceeds from long-term debt and bonds issued
 793,892
 396,488
 —

 Other
 20,009
 25,701
 21,950

 Net cash provided by (used in) financing activities
 656,105
 405,785
 253,554

 Net increase (decrease) in cash, cash equivalents, and restricted cash
 ( 71,882)
 44,967
 69,638

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

 Cash, cash equivalents, and restricted cash at end of period
 $
 138,970
 $
 210,852
 $
 165,885

 Supplemental cash flow information:

 Cash payments for interest (net of capitalized interest)
 $
 276,081
 $
 253,835
 $
 233,746

 Cash payments (refunds) for income taxes
 67,888
 116,795
 93,058

 Non-cash financing and investing activities:

 Accounts payable for capital expenditures eliminated from cash flow
 $
 110,311
 $
 97,892
 $
 68,357

 Seller financing accrued liabilities for capital expenditures eliminated from cash flow

 1,700
 21,739
 —

 Capital expenditures due to change in ARO estimate eliminated from cash flow

 20,255
 ( 2,206)
 1,520

 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," 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. The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

 Utility Plant
 Puget Energy and PSE capitalize, at original cost, additions to utility plant, including renewals and betterments. Costs include indirect costs such as engineering, supervision, certain taxes, pension and other employee benefits and an allowance for funds used during construction (AFUDC). Replacements of minor items of property are included in maintenance expense. When the utility plant is retired and removed from service, the original cost of the property is charged to accumulated depreciation and costs associated with removal of the property, less salvage, are charged to the cost of removal regulatory liability.

 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 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 finance leases, intangibles such as certain 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 2024, 2023, and 2022, respectively; depreciable natural gas utility plant was 3.2 %, 3.2 %, and 2.9 % in 2024, 2023, and 2022, respectively; and depreciable common utility plant was 6.6 %, 6.5 % and 7.1 % in 2024, 2023, and 2022, 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, 2024, December 31, 2023 and December 31, 2022.

 Tacoma LNG Facility
 Operational since February 2022, the Tacoma LNG facility at the Port of Tacoma 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. 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.
 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, $ 234.8 million and $ 240.5 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, 2024, and December 31, 2023, respectively. Additionally, $ 25.2 million, $ 27.5 million, and $ 11.6 million of operating costs are reported in the Puget Energy "Non-utility expense and other" financial statement line item in 2024, 2023 and 2022, respectively. Further, $ 229.0 million and $ 235.6 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, 2024, and December 31, 2023, 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 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 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 rate used. AFUDC is capitalized as a part of the cost of utility plant; the debt portion is credited to interest expense, while the 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, which is 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. Per the 2024 GRC, the AFUDC rate authorized is 7.52 % in 2025 and 7.64 % in 2026 effective January 29, 2025.
 To the extent amounts calculated using this rate exceed the AFUDC calculated rate using the 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 $ 329.9 million, $ 319.1 million and $ 292.8 million for 2024, 2023, and 2022, 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 PCA mechanism and 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, 2024, and 2023:

 Allowance for credit losses:
 2024
 2023

 Beginning balance
 $
 38,211
 $
 41,962

 Provision for credit loss expense1

 43,573
 34,724

 Receivables charged-off
 ( 41,348)
 ( 38,475)

 Total ending allowance balance
 $
 40,436
 $
 38,211

 _____________
 1 $ 37.1 million and $ 17.1 million of provision related to balances of deferred costs specific to COVID-19 as of December 31, 2024 and 2023, 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 under the 2017 GRC is $ 10.0 million. Under the 2024 GRC, the cumulative annual cost threshold for the storm loss deferral mechanism is $ 9.4 million in 2025 and $ 9.6 million in 2026. 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.

 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 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.
 On December 19, 2024, the Washington Commission approved the Company's accounting petition in Docket No. UE-240773 to defer any incurred unrealized gains or losses on derivative instruments entered into to serve electric customers, and as such PSE has recognized regulatory assets and/or liabilities, thus deferring the unrealized gains or losses. As of December 31, 2024, the fair value of these derivatives were recorded on the Company's balance sheet as a derivative asset of $ 38.8 million and a derivative liability of $ 389.9 million. The difference of $ 351.1 million has been recorded as a regulatory asset in accordance with the accounting treatment approved by the Washington Commission.

 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 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 $ 88.9 million, $ 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, 2024, December 31, 2023 and December 31, 2022, respectively. Additionally, $ 11.6 million and $ 14.6 million were included in accounts payable on the Company's balance sheets as of December 31, 2024 and December 31, 2023, 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 postponed the sunset date of Topic 848 from December 31, 2022 to December 31, 2024. As of December 31, 2024, the Company is not aware of any current agreements that reference LIBOR and thus, has not utilized any practical expedients.

 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 requires 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 is effective for the

 Company in fiscal years beginning after December 15, 2023, and interim periods in fiscal years beginning after December 15, 2024. As of December 31, 2024, the Company's disclosures are consistent with 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 eliminates 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 of December 31, 2024, the Company's disclosures are consistent with the amendment.

 Accounting Standards Issued but Not Yet Adopted
 Income Statement Reporting Comprehensive Income Disclosures
 In November 2024, the FASB issued ASU 2024-03, "Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures ". ASU 2024-03 will require disclosure of specific cost and expense information in the notes to the financial statements. Disclosure shall include inventory purchases, employee compensation, depreciation and intangible asset amortization presented in the face of the income statement for continuing operations. It shall also include certain amounts already disclosed under GAAP in the same disclosure as other disaggregation requirements as well as disclose a qualitative description and the amount of selling expenses. ASU 2024-03 will be effective for the Company in annual periods beginning after December 15, 2026. The amendment contemplates changes in disclosures only and 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, 2024, December 31, 2023, and December 31, 2022:

 Year Ended December 31, 2024

 Revenue from contracts with customers:
 Other1

 Total

 Retail

 $
 1,677,599
 $
 796,889
 $
 —
 $
 2,474,488

 1,159,596
 367,988
 —
 1,527,584

 131,869
 26,764
 —
 158,633

 Other
 23,601
 —
 —
 23,601

 Wholesale
 286,364
 —
 —
 286,364

 Transmission and transportation
 33,911
 30,874
 —
 64,785

 Miscellaneous2

 35,274
 246,708
 34,950
 316,932

 Total revenue from contracts with customers
 $
 3,348,214
 $
 1,469,223
 $
 34,950
 $
 4,852,387

 Total other revenue3

 ( 15,519)
 19,347
 —
 3,828

 $
 $
 1,488,570
 $
 34,950
 $
 4,856,215

 _____________
 1. Other includes $ 34.7 million of Puget LNG revenues recorded at Puget Energy.
 2. Miscellaneous natural gas revenue includes $ 253.0 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, 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

 $
 2,961,457
 $
 1,209,636
 $
 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, 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 "Revenue from Contracts with Customers". 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.

 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, Puget LNG entered into a contract with one customer where Puget LNG is selling LNG over a 10 -year delivery period beginning April 1, 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, the Company expects to recognize this revenue over the following time periods:

 2025
 2026
 2027
 2028
 2029
 Total

 Remaining Performance Obligations
 $
 19,554
 $
 19,454
 $
 19,454
 $
 19,454
 $
 19,454
 $
 82,681
 $
 180,051

 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, 2024, and 2023, are included in the following tables:

 Remaining Amortization Period

 2024
 2023

 PCA unrealized loss

 N/A
 $
 284,166
 $
 —

 Environmental remediation
 (a)
 180,245
 182,697

 Storm damage costs electric
 1 to 4 years

 120,431
 95,754

 Automated meter reading
 19 years
 98,572
 104,159

 Energy conservation costs
 (a)
 75,373
 37,560

 PGA unrealized loss
 N/A
 66,929
 80,376

 PCA mechanism
 N/A
 61,202
 48,427

 Baker Dam licensing operating and maintenance costs
 (b)
 56,201
 55,641

 Deferred Washington Commission AFUDC
 30 years
 55,427
 58,648

 Decoupling deferrals and interest
 Less than 2 years

 51,838
 31,398

 Chelan PUD contract initiation
 6.8 years
 48,435
 55,523

 Climate Commitment Act auction proceeds

 N/A
 43,538
 186,550

 Washington Commission LNG
 N/A
 38,070
 42,247

 Washington Commission COVID-19
 N/A
 37,089
 17,097

 Lower Snake River
 12.4 years
 35,429
 43,220

 Unamortized loss on reacquired debt
 3 to 43 years

 29,680
 31,626

 Regulatory filing fee deferral (c)

 2 years

 26,543
 14,582

 Various other regulatory assets
 (a)
 107,325
 126,473

 Total PSE regulatory assets
 $
 1,416,493
 $
 1,211,978

 Cost of removal
 (d)

 $
 ( 748,095)
 $
 ( 682,058)

 Deferred income taxes (e)

 N/A
 ( 722,558)
 ( 761,621)

 Repurposed production tax credits
 N/A
 ( 110,746)
 ( 126,482)

 Climate Commitment Act recovery

 N/A
 ( 97,694)
 ( 84,485)

 Decoupling liability
 Less than 2 years

 ( 63,890)
 ( 60,664)

 PGA liability
 2 years
 ( 58,657)
 ( 132,082)

 Bill discount rate deferral
 N/A
 ( 20,567)
 ( 6,579)

 Various other regulatory liabilities
 (a)
 ( 33,435)
 ( 60,925)

 Total PSE regulatory liabilities
 $
 ( 1,855,642)
 $
 ( 1,914,896)

 PSE net regulatory assets (liabilities)
 $
 ( 439,149)
 $
 ( 702,918)

 __________________
 (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 50 year license for Baker. The regulatory asset represents the net present value of future expenditures and will be offset by actual costs incurred.
 (c)Amortization period approved in 2024 GRC, beginning January 29, 2025.
 (d)The balance is dependent upon the cost of removal of underlying assets and the life of utility plant.
 (e)For additional information, see Note 14,"Income Taxes" to the consolidated financial statements included in Item 8 of this report.

 Remaining Amortization Period

 2024
 2023

 Total PSE regulatory assets
 (a)
 $
 1,416,493
 $
 1,211,978

 Puget Energy acquisition adjustments:

 Regulatory assets related to power contracts
 3 to 30 years

 4,779
 6,266

 Total Puget Energy regulatory assets
 $
 1,421,272
 $
 1,218,244

 Total PSE regulatory liabilities
 (a)
 $
 ( 1,855,642)
 $
 ( 1,914,896)

 Puget Energy acquisition adjustments:

 Deferred income taxes

 Regulatory liabilities related to power contracts
 3 to 30 years

 ( 30,566)
 ( 46,924)

 Various other regulatory liabilities
 Varies
 ( 1,193)
 ( 1,264)

 Total Puget Energy regulatory liabilities
 $
 ( 1,886,750)
 $
 ( 1,962,424)

 Puget Energy net regulatory asset (liabilities)
 $
 ( 465,478)
 $
 ( 744,180)

 ____________________
 (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 $ 748.1 million and $ 682.1 million in 2024 and 2023, 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 included 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 rate year one beginning in 2025 and 10.5 % for rate year two, 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.
 On January 15, 2025, the Washington Commission issued an order on PSE's 2024 GRC that approved a weighted cost of capital of 7.52 % in 2025 and 7.64 % in 2026, a capital structure of 49.0 % in common equity in 2025 and 50.0 % in 2026, and a return on equity of 9.8 % in 2025 and 9.9 % in 2026. On January 28, 2025, the Washington Commission approved PSE's electric and natural gas rates in its compliance filing with an overall net revenue change for electric of $ 378.2 million or 13.3 % in 2025 and $ 191.0 million or 5.9 % in 2026 and an overall net revenue change for natural gas of $ 110.0 million or 10.6 % in 2025 and $ 20.0 million or 1.8 % in 2026, with an effective date of January 29, 2025. PSE filed a petition for reconsideration on January 24, 2025 and multiple parties filed petitions for reconsideration and a motion for clarification on January 27, 2025. The Washington Commission will determine what, if any, further action will be taken with respect to these petitions by March 17, 2025.
 On April 24, 2024, the Washington Commission issued Final Order 07 under Docket No. UG-230393. The order determined that PSE acted prudently in developing and constructing the Tacoma LNG Facility after the initial decision to build in September 2016. Further, there were two main outcomes that resulted from the order. First, the Washington Commission did not authorize recovery of the portion of the Company's deferred return on its investment in the Tacoma LNG Facility that was recorded between February 1, 2022, the date the facility was placed into service, and January 11, 2023, the date PSE's 2022 GRC rates went into effect. Second, the Washington Commission directed PSE to increase the allocation of distribution pipeline investment to Puget LNG. The Washington Commission determined that the allocation should be tied to the relative flow of natural gas across these facilities, resulting in a higher allocation to Puget LNG than was originally filed. On May 3, 2024, PSE made the compliance filing required by Final Order 07. On May 24, 2024, Public Counsel and the Puyallup Tribe of Indians each filed a petition for judicial review of the Washington Commission's Final Order 07. The petitions were filed in Thurston County Superior Court and are expected to be consolidated. Both petitions allege that the Washington Commission

 (i) failed to properly apply the updated public interest standard, (ii) failed to disallow all costs related to PSE's redesign of the pipeline and development of waste gas disposal methods, and (iii) failed to conduct an independent determination of reasonable attorney fees.
 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 PCORC 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. Per the 2022 GRC Final Order in Docket No. UG-220067, PSE was authorized to seek recovery of the costs related to the Tacoma LNG Facility concurrent with its 2023 PGA filing.
 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.

 PCA and PGA Unrealized Loss
 On December 19, 2024, the Washington Commission approved the Company's accounting petition in Docket No. UE-240773 to offset any derivative assets or liabilities, entered into in order to serve electric customers, with a regulatory asset or liability, thus deferring the unrealized gains or losses. 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.

 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.
 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 credits to customers from estimated auction proceeds during the period of January 2023 through September 2023.
 On November 22, 2023, PSE filed proposed revisions to its natural gas rates to incorporate allowance costs and auction proceeds in Docket UG-230968. In the filing PSE sought to update rates pertaining to amounts deferred from January 2023 through September 2023 and to add new language to the tariff that would enable PSE to fund decarbonization projects using a portion of the projected no cost allowances revenues. The request, as revised by PSE on December 19, 2023, represented a revenue increase of $ 29.1 million. The Washington Commission suspended the tariff sheets but allowed the rates to go into effect on an interim basis, subject to refund, on January 1, 2024. The Washington Commission had a hearing for the issue of risk sharing of CCA compliance costs on October 9, 2024 and has not yet issued an order.
 As of December 31, 2024, PSE has not sought cost recovery for its allowance costs for electric operations. The ongoing recovery of allowance costs and pass back of proceeds from the sale of consigned no-cost allowances for PSE's natural gas operations is consistent with the approved accounting petitions in Dockets No. UG-220975 and UG-230471. As of December 31, 2024, PSE recorded a regulatory liability of $ 97.7 million which represents the amounts to date collected in customer natural gas rates for CCA obligation costs, net of the expense incurred for the purchase of allowances for electric and natural gas operations. Additionally, PSE will continue to 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 continue to be used for the benefit of natural gas customers, as determined by the Washington Commission. PSE does not record a regulatory liability to defer the proceeds until consigned allowances are sold at auction. As of December 31, 2024, PSE recorded a regulatory asset of $ 43.5 million, which represents the proceeds from the sale of consigned natural gas GHG

 emission allowances passed back through customer rates, net of proceeds received from the sale of consigned allowances sold at auction.

 Colstrip Adjustment Rider
 On September 30, 2024, PSE filed proposed revisions to rates under the Colstrip Adjustment Rider Schedule 141COL with the Washington Commission, seeking to recover actual and forecasted costs for Colstrip Units 3 and 4 for calendar year 2025. The proposed revisions would increase PSE's annual revenues by $ 4.1 million, or 0.1 %. The Washington Commission Staff identified concerns regarding certain capital investments related to the Colstrip coal-fired generating facility, particularly in light of the Clean Energy Transformation Act's mandate to remove coal-fired generation facility costs from rates by December 31, 2025. On December 23, 2024, the Washington Commission issued Order 01, requiring PSE to file revised tariff pages by December 23, 2024, with rates effective January 1, 2025, subject to refund pending final determination. The Washington Commission has set the matter for adjudication and a prehearing conference to set the procedural schedule will be held during the first quarter of 2025. The Washington Commission's order allows the rates to be collected beginning January 1, 2025, but explicitly notes this does not represent a resolution or final determination of any matter raised in Docket No. UE-240729.

 Revenue Decoupling Adjustment Mechanism
 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 as of December 31, 2024, $ 0.2 million and zero reserve adjustment was recorded to electric and natural gas decoupling as of December 31, 2024 and zero reserve adjustment was recorded to electric and natural gas decoupling as of December 31, 2023.

 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, 2024, in its PCA mechanism, PSE under recovered its allowable costs by $ 123.3 million of which $ 86.5 million was apportioned to customers and $ 3.9 million of interest was accrued on the deferred customer balance. This compares to an over recovery of allowable costs of $ 51.1 million, for the year ended December 31, 2023, of which $ 24.9 million was apportioned to customers and accrued $ 3.9 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.
 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.

 PSE exceeded the $ 20.0 million cumulative deferral balance in its PCA mechanism in 2023. During 2023, actual power costs were lower than baseline power costs, thereby, creating an over-recovery of $ 51.1 million. Under the terms of the PCA's sharing mechanism for over-recovered costs, PSE's share of the over-recovery was $ 26.2 million and customers were due the remaining $ 24.9 million, or $ 22.2 million, including interest and adjusted for revenue sensitive items.
 On April 30, 2024, PSE filed the 2023 PCA compliance report, in Docket No. 240288, that proposed to pass back 2023 deferred balances from October 1, 2024 to December 31, 2025, resulting in credits to customers of $ 22.2 million. Additionally, PSE requested to recover the forecasted 2024 deferred balance of $ 98.2 million from October 1, 2024 to December 31, 2025. On September 26, 2024, the Washington Commission approved the filing as proposed with rates going into effect October 1, 2024 and January 1, 2025.

 Purchased Gas Adjustment Mechanism
 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.
 On October 24, 2024, the Washington Commission approved PSE's request for PGA rates in Docket No. UG-240708, effective November 1, 2024. As part of that filing, PSE requested an annual overall revenue increase of $ 124.4 million, where PGA rates, under Schedule 101, decrease annual revenue by $ 2.6 million and the tracker rates, under Schedule 106, increase annual revenue by $ 127.0 million. The revenue increase in Schedule 106 is primarily due to the cessation of the counterparty refund of $ 28.1 million, mentioned above, that was amortized as a credit in 2023 and $ 142.8 million in commodity deferrals that were passed back to customers.
 The following table presents the PGA mechanism balances and activity as of December 31, 2024 and December 31, 2023:

 PGA (liability)/receivable balance and activity

 2024
 2023

 PGA (liability)/receivable beginning balance

 $
 ( 132,082)
 $
 ( 3,536)

 Actual natural gas costs
 416,067
 404,897

 Allowed PGA recovery
 ( 336,170)
 ( 521,882)

 Interest
 ( 6,472)
 ( 7,639)

 Refund from counterparty settlement
 —
 ( 3,922)

 PGA (liability)/receivable ending balance
 $
 ( 58,657)
 $
 ( 132,082)

 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, 2024, PSE incurred $ 74.5 million in weather-related electric transmission and distribution system restoration costs, of which the Company deferred $ 58.9 million and zero as regulatory assets related to storms that occurred in 2024 and 2023, respectively. This compares to $ 8.1 million incurred in weather-related electric transmission and distribution system restoration costs for the year ended December 31, 2023, of which the Company deferred zero and $ 2.1 million as regulatory assets related to storms that occurred in 2023 and 2022, 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, 2024, the Company's share of future remediation costs is estimated to be approximately $ 73.0 million.

 The following table summarizes changes in the Company's environmental remediation regulatory assets for the years ended December 31, 2024, and 2023:

 2024
 2023

 Environmental remediation regulatory asset beginning balance

 $
 182,697
 $
 141,893

 Remediation cost amortization, net of recoveries

 ( 3,732)
 ( 4,521)

 Changes in estimates1

 1,280
 45,325

 Environmental remediation regulatory asset ending balance

 $
 180,245
 $
 182,697

 1. The 2023 change was 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, 2024, and 2023:

 2024
 2023

 Environmental remediation liabilities beginning balance

 $
 180,440
 $
 135,052

 Payments made, net of recoveries

 ( 10)
 ( 495)

 Changes in estimates1

 45,883

 Environmental remediation liabilities ending balance

 $
 181,155
 $
 180,440

 1. The 2023 change was 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, 2024, approximately $ 1.8 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, 2024, and the EBITDA to interest expense was 4.6 to 1.0 for the twelve months ended December 31, 2024.
 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 3.5 to 1.0 for the twelve months ended December 31, 2024.
 At December 31, 2024, 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)
 2024
 2023
 2024
 2023

 Distribution plant
 7 - 65

 $
 8,983,586
 $
 8,298,893
 $
 10,474,294
 $
 9,804,018

 Production plant
 12 - 90

 3,310,663
 3,173,514
 3,928,187
 3,805,294

 Transmission plant
 44 - 75

 1,908,891
 1,595,566
 2,015,060
 1,701,878

 General plant
 5 - 75

 805,960
 717,017
 826,918
 738,996

 Intangible plant (including capitalized software)2

 3 - 50

 716,038
 586,749
 706,576
 577,291

 Plant acquisition adjustment
 N/A
 242,827
 242,826
 282,792
 282,792

 Underground storage
 25 - 60

 50,047
 46,761
 63,004
 60,171

 Liquefied natural gas storage
 25 - 50

 256,144
 224,337
 257,909
 226,208

 Plant held for future use
 N/A
 59,657
 59,409
 59,809
 59,561

 Recoverable cushion gas

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

 Plant not classified
 N/A
 733,184
 1,032,004
 733,184
 1,032,002

 Finance leases, net of accumulated amortization3

 N/A
 91,045
 95,114
 91,045
 95,114

 Less: accumulated provision for depreciation
 ( 5,101,926)
 ( 4,643,833)
 ( 7,382,662)
 ( 6,954,968)

 Subtotal
 $
 12,064,900
 $
 11,437,141
 $
 12,064,900
 $
 11,437,141

 Construction work in progress
 1,577,695
 1,156,265
 1,577,695
 1,156,265

 Net utility plant
 $
 13,642,595
 $
 12,593,406
 $
 13,642,595
 $
 12,593,406

 _______________________
 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, 2024, and 2023, accumulated amortization of finance leases at Puget Energy and PSE was $ 18.3 million and $ 13.2 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, 2024. 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 %
 $
 324,451
 $
 —
 $
 ( 233,934)

 Frederickson 1
 49.85
 68,006
 —
 ( 32,767)

 Jackson Prairie
 33.34
 48,174
 ( 14,196)

 Tacoma LNG
 various
 497,290
 3,545
 ( 36,847)

 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 %
 $
 581,467
 $
 —
 $
 ( 490,950)

 Frederickson 1
 49.85
 73,658
 —
 ( 38,418)

 Jackson Prairie
 33.34
 63,004
 ( 29,025)

 Tacoma LNG
 various
 246,893
 ( 17,916)

 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. However, Talen emerged from a Chapter 11 bankruptcy in May 2023 without approval of the 2022 transfer agreement, which the parties agree makes the transfer agreement unenforceable. Given that the transfer contemplated by that agreement will not proceed, PSE entered into an agreement with NorthWestern Energy on July 30, 2024 to transfer PSE's ownership interest in Colstrip Units 3 and 4 to NorthWestern Energy on December 31, 2025. Management evaluated the agreement with Northwestern Energy and determined that abandonment accounting criteria was met as of December 31, 2024. Thus, PSE will apply abandonment accounting on the transfer date of December 31, 2025, until that date Colstrip Units 3 and 4 are classified as Electric Utility Plant on the Company's balance sheet as of December 31, 2024.

 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". 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, 2024, the Company reviewed the estimated remediation costs related to the Beaver Creek Wind Project and determined that $ 18.8 million was warranted for the ARO liability. No ARO liability was warranted as of December 31, 2023.
 For the twelve months ended December 31, 2024, the Company reviewed the estimated remediation costs at Colstrip and determined $ 7.9 million was warranted for the Colstrip ARO liability for Colstrip Units 1-4, compared to no change for the 12 months ended December 31, 2023. For the twelve months ended December 31, 2024 and 2023, the Company recorded relief of ARO and environmental remediation liability of $ 6.0 million and $ 6.0 million, respectively.
 In addition, the Company recorded Tacoma LNG facility ARO liability of $ 4.2 million and $ 4.1 million for PSE and $ 4.1 million and $ 4.0 million for Puget LNG held only at Puget Energy as of December 31, 2024 and December 31, 2023, respectively.

 2024
 2023

 ARO beginning balance

 $
 207,034
 $
 209,406

 New ARO recognized in the period

 18,811
 —

 Relief of liability
 ( 6,049)
 ( 5,998)

 Revisions in estimated cash flows
 9,471
 ( 2,206)

 Accretion expense
 6,676
 5,832

 ARO ending balance

 $
 235,943
 $
 207,034

 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, 2024:
 • 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, 2024 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 $ 234.6 million has been paid as of December 31, 2024 and the remaining balance is expected to be paid in the first quarter of 2025, as turbines are delivered and the project is completed. 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 $ 145.4 million. As of December 31, 2024, $ 506.5 million was recorded to construction work in progress in conjunction with the Beaver Creek wind project.

 Appaloosa Solar Project
 Appaloosa Solar Project is a utility-scale solar project located in Garfield County, Washington, with an expected nameplate capacity of 142 MW that is expected to commence commercial operations in 2026. On December 22, 2023, PSE executed and closed a membership interest purchase agreement with HQC Solar Holdings 1, LLC for a 100% ownership interest in Appaloosa Solar Project LLC. Total consideration is expected to be $ 20.3 million, of which $ 18.6 million was paid as of December 31, 2024 and the remaining balance is expected to be paid in 2026. On August 30, 2024, PSE entered into an Engineering, Procurement, and Construction agreement to complete the design and construction of the project. Total consideration is expected to be approximately $ 266.8 million. As of December 31, 2024, $ 27.2 million was recorded to construction work in progress in conjunction with the Appaloosa solar project.

 (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, 2024 and 2023:

 Series
 Type
 Due
 2024
 2023

 Puget Sound Energy:

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

 7.200 %
 First Mortgage Bond
 2025
 —
 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

 5.330 %
 2034
 —

 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

 5.685 %
 2054
 —

 *
 Debt discount, issuance cost and other
 *
 ( 45,835)
 ( 39,813)

 Total PSE long-term debt
 $
 $

 Puget Energy:

 *
 Fair value adjustment of PSE long-term debt
 *
 $
 ( 131,326)
 $
 ( 139,834)

 3.650 %
 2025
 —

 2.379 %
 2028
 500,000
 500,000

 4.100 %
 2030
 650,000
 650,000

 4.224 %
 2032

 *
 Debt discount, issuance cost and other
 *
 ( 5,780)
 ( 7,571)

 Total Puget Energy long-term debt
 $
 $

 ___________________
 * 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, 2024, 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
 In March 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.

 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, $ 200.0 million was available to be issued. The shelf registration will expire in August 2025.
 On June 11, 2024, PSE issued $ 400.0 million of senior secured notes at an interest rate of 5.330 %. The notes mature on June 15, 2034 and pay interest semi-annually in arrears on June 15 and December 15 of each year, commencing on December 15, 2024. Proceeds from the issuance of the notes were invested in short-term money market funds, used to pay down outstanding commercial paper and for general corporate purposes.
 On June 11, 2024, PSE issued $ 400.00 million of green senior secured notes at an interest rate of 5.685 %. The notes mature on June 15, 2054 and pay interest semi-annually in arrears on June 15 and December 15 of each year, commencing on December 15, 2024. Net proceeds from the issuance of the notes were invested in short-term money market funds 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.
 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:

 2025
 2026
 2027
 2028
 2029
 Total

 Maturities of:

 PSE
 $
 17,000
 $
 —
 $
 $
 —
 $
 $
 5,606,860
 $
 6,023,860

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

 Total long-term debt
 $
 417,000
 $
 —
 $
 $
 500,000
 $
 $
 6,706,860
 $
 8,023,860

 (8) Liquidity Facilities and Other Financing Arrangements

 As of December 31, 2024 and 2023, PSE had $ 40.0 million and $ 336.6 million in short-term debt outstanding, respectively. Outside of the consolidation of PSE's short-term debt, Puget Energy had $ 338.4 million and $ 261.5 million, in short-term debt, drawn and outstanding under its credit facility as of December 31, 2024 and 2023, respectively. PSE's weighted-average interest rate on short-term debt, including borrowing rate, commitment fees and the amortization of debt

 issuance costs, during 2024 and 2023 was 8.5 % and 9.0 %, respectively. As of December 31, 2024, 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 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, 2024, 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, 2024, no amount was drawn under PSE's credit facility and $ 40.0 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, 2024, $ 6.6 million was issued under a standby letter of credit with TD Bank in support of natural gas and carbon allowance purchases. Additionally, PSE had a $ 1.9 million letter of credit in support of a long-term transmission contract. In support of purchase power contracts, PSE posted cash collateral of $ 15.0 million and maintained two standby letters of credit in the amounts of $ 60.0 million and $ 13.5 million.

 Demand Promissory Note
 On May 19, 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, 2024, 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 %.
 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, 2024, Puget Energy was in compliance with all applicable covenants.
 On August 31, 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.

 On June 17, 2024, Puget Equico LLC, Puget Energy's parent company, contributed $ 292.8 million as an equity contribution to Puget Energy. Puget Energy then contributed $ 292.8 million to PSE as an equity contribution. The proceeds from the equity contribution 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 Puget 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 45 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:

 2024
 2023

 Finance lease cost:

 Amortization of right-of-use asset
 $
 3,915
 $
 3,891

 Interest on lease liabilities
 3,192
 3,237

 Total finance lease cost
 $
 7,107
 $
 7,128

 Operating lease cost1

 $
 24,993
 $
 23,891

 1.Includes $ 1.7 million and $ 1.7 million allocated to Puget LNG at Puget Energy related to the Port of Tacoma lease for the years ended December 31, 2024 and December 31, 2023, respectively.

 Supplemental cash flow information related to leases was as follows:

 2024
 2023

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

 Operating cash flow for operating leases
 $
 17,038
 $
 15,990

 Investing cash flow for operating leases1

 7,955
 7,901

 Operating cash flow for finance leases
 3,192
 3,237

 Financing cash flow for finance leases
 3,915
 3,891

 Non-cash disclosure upon commencement of new lease

 Right-of-use assets obtained in exchange for new operating lease liabilities
 $
 4,093
 $
 10,462

 Right-of-use assets obtained in exchange for new finance lease liabilities
 1,832
 1,245

 Non-cash disclosure upon modification of existing lease

 Modification of operating lease right-of-use assets
 $
 1,996
 $
 6,912

 1 Includes $ 1.7 million and $ 1.7 million allocated to Puget LNG at Puget Energy related to the Port of Tacoma lease for the years ended December 31, 2024 and December 31, 2023, respectively.

 Supplemental balance sheet information related to leases was as follows:

 Operating Leases
 2024
 2023

 Operating lease right-of-use asset
 $
 181,397
 $
 194,321

 Operating leases liabilities current
 $
 22,761
 $
 21,629

 Operating lease liabilities long-term
 166,700
 180,754

 Total operating lease liabilities:
 $
 189,461
 $
 202,383

 Finance Leases

 Common plant
 $
 53,594
 $
 55,756

 Natural gas plant

 —

 Electric plant
 37,141
 39,358

 Total finance lease assets
 $
 91,045
 $
 95,114

 Other current liabilities
 $
 3,786
 $
 3,371

 Finance lease liabilities
 96,850
 99,512

 Total finance lease liabilities
 $
 100,636
 $
 102,883

 Weighted Average Remaining Lease Term

 Operating leases
 21.2 Years
 21.3 Years

 Finance leases
 16.9 Years
 18.0 Years

 Weighted Average Discount Rate

 Operating leases
 3.76
 %
 3.75
 %

 Finance leases
 3.10
 %
 3.08
 %

 The following table summarizes the Company's estimated future minimum lease payments as of December 31, 2024:

 Future Minimum Lease Payments

 Operating Leases
 Finance Leases

 2025

 $
 24,687
 $
 7,097

 2026

 24,858
 7,140

 2027

 24,469
 7,023

 2028

 21,680
 7,106

 2029

 12,622
 6,964

 153,937
 96,138

 Total lease payments
 $
 262,253
 $
 131,468

 Less imputed interest
 ( 72,792)
 ( 30,832)

 Total net present value
 $
 189,461
 $
 100,636

 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 natural gas combined cycle facility. The tolling agreement represents a lease to PSE and is expected to commence in October 2025. PSE expects the total lease payment consideration will approximate $ 91.0 million over the five year lease term 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 the total lease payment consideration will approximate $ 116.0 million over the 20 year lease term. Construction of the facility will be managed and contracted by the lessor; however, PSE will have involvement in the design of the facility.
 On May 8, 2024, PSE entered into a battery storage tolling agreement that will be accounted for as a lease upon commencement. The lease is expected to commence in August 2027 and has a term of 20 years. The expected total lease payment consideration will approximate $ 744.0 million over the lease term.
 On May 23, 2024, PSE entered into a battery storage tolling agreement that will be accounted for as a lease upon commencement. The lease is expected to commence in September 2027 and has a term of 25 years. The expected total lease payment consideration will approximate $ 856.2 million over the lease term.
 On November 7, 2024, PSE entered into a tolling agreement to purchase the energy and capacity associated with a 650.0 MW natural gas combined cycle facility. The tolling agreement represents a lease to PSE, and commenced January 1, 2025. The expected total lease payment consideration will approximate $ 486.0 million over the three year lease term beginning in January 2025.

 (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

 2024
 2023
 2024
 2023
 2024
 2023

 Electric portfolio derivatives3

 *
 *
 $
 35,341
 $
 93,028
 $
 319,506
 $
 126,939

 Natural gas derivatives (MMBtus)3

 3,495
 16,521
 70,425
 96,898

 Total derivative contracts
 $
 $
 $
 $

 Current
 $
 32,591
 $
 74,225
 $
 218,443
 $
 185,788

 Long-term
 6,245
 35,324
 171,488
 38,049

 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 have been deferred in accordance with ASC 980, "Regulated Operations" in 2024. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of electricity and physical gas purchased to serve customers. In 2023, only fair value adjustments for contracts used to serve natural gas customers were deferred.
 *Electric portfolio derivatives consist of electric generation fuel of 283.5 million One Million British Thermal Units (MMBtus) and purchased electricity of 13.3 million megawatt hours (MWhs) at December 31, 2024, and 315.6 million MMBtus and 2.3 million MWhs at December 31, 2023.

 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
 $
 $
 —
 $
 $
 ( 34,329)
 $
 —
 $
 4,507

 Liabilities:

 Energy derivative contracts
 $
 $
 —
 $
 $
 ( 34,329)
 $
 ( 3,593)
 $
 352,009

 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

 $
 $
 —
 $
 $
 ( 82,206)
 $
 —
 $
 27,343

 Liabilities

 Energy derivative contracts

 $
 $
 —
 $
 $
 ( 82,206)
 $
 ( 84)
 $
 141,547

 __________
 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
 2024
 2023
 2022

 Gas for Power Derivatives:

 Unrealized
 Unrealized gain (loss) on derivative instruments, net
 $
 53,541
 $
 ( 155,774)
 $
 61,761

 Realized
 Electric generation fuel
 ( 85,476)
 47,930
 158,550

 Power Derivatives:

 Unrealized
 Unrealized gain (loss) on derivative instruments, net
 ( 19,630)
 ( 128,721)
 199,416

 Realized
 Purchased electricity
 ( 76,271)
 69,136
 20,917

 Total gain (loss) recognized in income on derivatives
 $
 ( 127,836)
 $
 ( 167,429)
 $
 440,644

 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, 2024, approximately 99.8 % 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 0.2 % 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, 2024, 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 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, 2024, PSE had cash posted as collateral of $ 7.8 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, 2024, PSE had no cash posted with ICE NGX, and $ 6.6 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, 2024.
 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:

 2024
 2023

 Contingent Feature
 Fair Value1
 Liability

 Posted
Collateral
 Contingent
Collateral
 Fair Value1
 Liability

 Posted
Collateral
 Contingent
Collateral

 Credit rating2

 $
 179,532
 $
 —
 $
 179,532
 $
 13,384
 $
 —
 $
 13,384

 Requested credit for adequate assurance
 37,492
 —
 —
 53,427
 —
 —

 Forward value of contract3

 19,905
 12,915
 N/A
 12,429
 N/A

 Total
 $
 236,929
 $
 12,915
 $
 179,532
 $
 66,895
 $
 12,429
 $
 13,384

 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 $ 45.4 million and $ 44.6 million at December 31, 2024, and 2023, 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

 $
 $
 6,966,211
 $
 $
 6,855,503

 Total
 $
 $
 6,966,211
 $
 $
 6,855,503

 Level
 Carrying Value
 Carrying Value

 Financial liabilities:

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

 $
 $
 5,492,999
 $
 $
 5,007,483

 Total
 $
 $
 5,492,999
 $
 $
 5,007,483

 1.The carrying value includes debt issuances costs of $ 21.3 million and $ 21.0 million for December 31, 2024, and 2023, respectively, which are not included in fair value.
 2.The carrying value includes debt issuances costs of $ 22.1 million and $ 21.2 million for December 31, 2024, and 2023, 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

 $
 25,236
 $
 10,105
 $
 35,341
 $
 42,254
 $
 50,774
 $
 93,028

 Gas derivative instruments

 1,729
 1,766
 3,495
 11,647
 4,874
 16,521

 Total derivative assets
 $
 26,965
 $
 11,871
 $
 $
 53,901
 $
 55,648
 $

 Liabilities:

 Electric derivative instruments

 $
 134,292
 $
 185,214
 $
 319,506
 $
 103,427
 $
 23,512
 $
 126,939

 Gas derivative instruments

 70,050
 70,425
 95,875
 1,023
 96,898

 73,049
 —
 73,049
 168,879
 —
 168,879

 Total derivative liabilities
 $
 277,391
 $
 185,589
 $
 462,980
 $
 368,181
 $
 24,535
 $
 392,716

 Level 3 Roll-Forward Net Asset (Liability)
 2024
 2023
 2022

 Total
 Total
 Total

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

 Changes during period:

 Realized and unrealized energy derivatives

 Included in earnings1

 ( 27,262)
 —
 ( 27,262)
 ( 56,656)
 —
 ( 56,656)
 180,533
 —
 180,533

 Included in regulatory assets / liabilities
 ( 211,129)
 1,284
 ( 209,845)
 —
 4,906
 4,906
 —

 Settlements2

 34,873
 ( 4,418)
 30,455
 ( 32,377)
 ( 1,098)
 ( 33,475)
 ( 21,972)
 1,369
 ( 20,603)

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

 Transferred out Level 3
 1,146
 1,820

 Balance at end of period
 $
 ( 175,110)
 $
 1,391
 $
 ( 173,719)
 $
 27,262
 $
 3,851
 $
 31,113
 $
 116,078
 $
 ( 127)
 $
 115,951

 __________________
 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 and $ 147.1 million for the years ended December 31, 2023, and 2022, 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.
 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, 2024, 2023, and 2022. 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, 2024:

 Range

 Assets1

 Liabilities1

 Valuation Technique
 Unobservable Input
 Low
 High
 Weighted

 Electricity
 $
 10,104
 $
 185,214
 Discounted cash flow
 Power Prices (per MWh)
 $
 13.82
 $
 138.94
 $
 64.59

 $
 1,767
 $
 Discounted cash flow
 Natural Gas Prices (per MMBtu)
 $
 2.66
 $
 4.17
 $
 3.66

 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, 2024, 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 $ 57.8 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 2024, 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 $ 31.7 million, $ 28.9 million and $ 25.2 million for the years 2024, 2023, and 2022, 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, 2024, and 2023:

 SERP
 Other

 2024
 2023
 2024
 2023
 2024
 2023

 Change in benefit obligation:

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

 Amendments
 —
 —
 —
 —

 Service cost
 18,616
 18,530
 —

 Interest cost
 31,152
 32,375
 1,370
 1,589

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

 Actuarial loss (gain)
 ( 38,952)
 8,469
 ( 1,752)
 ( 661)
 ( 194)
 ( 52)

 Benefits paid
 ( 41,583)
 ( 38,258)
 ( 1,978)
 ( 3,521)
 ( 792)
 ( 1,067)

 Administrative expense
 ( 1,350)
 ( 1,291)
 —
 —
 —
 —

 Benefit obligation at end of period*
 $
 576,986
 $
 609,103
 $
 24,464
 $
 26,824
 $
 8,248
 $
 8,597

 • The amount is the actuarial present value of the vested benefits to which the employee is currently entitled and is based on the employee's expected date of separation or retirement.

 SERP
 Other

 2024
 2023
 2024
 2023
 2024
 2023

 Change in plan assets:

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

 Actual return on plan assets
 51,509
 109,028
 —
 —

 Employer contribution
 18,000
 18,000
 1,978
 3,521

 Benefits paid
 ( 41,583)
 ( 38,258)
 ( 1,978)
 ( 3,521)
 ( 792)
 ( 1,067)

 Administrative expense
 ( 1,247)
 ( 1,292)
 —
 —
 —
 —

 Fair value of plan assets at end of period
 $
 772,690
 $
 746,011
 $
 —
 $
 —
 $
 4,785
 $
 5,085

 Funded status at end of period
 $
 195,704
 $
 136,908
 $
 ( 24,464)
 $
 ( 26,824)
 $
 ( 3,463)
 $
 ( 3,512)

 SERP
 Other

 2024
 2023
 2024
 2023
 2024
 2023

 Amounts recognized in Consolidated Balance Sheet consist of:

 Noncurrent assets
 $
 195,704
 $
 136,908
 $
 —
 $
 —
 $
 —
 $
 —

 Current liabilities
 —
 —
 ( 6,759)
 ( 1,978)
 ( 237)
 ( 225)

 Noncurrent liabilities
 —
 —
 ( 17,705)
 ( 24,846)
 ( 3,226)
 ( 3,287)

 Net assets (liabilities)
 $
 195,704
 $
 136,908
 $
 ( 24,464)
 $
 ( 26,824)
 $
 ( 3,463)
 $
 ( 3,512)

 SERP
 Other

 2024
 2023
 2024
 2023
 2024
 2023

 Change in plan obligation and plan asset:

 Projected benefit obligation
 $
 576,986
 $
 609,103
 $
 24,464
 $
 26,824
 $
 8,248
 $
 8,597

 Accumulated benefit obligation
 571,306
 601,981
 24,464
 26,824
 8,109
 8,487

 Fair value of plan assets
 772,690
 746,011
 —
 —
 4,785
 5,085

 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, 2024, and 2023:

 SERP
 Other

 2024
 2023
 2024
 2023
 2024
 2023

 Amounts recognized in Accumulated Other Comprehensive Income consist of:

 Net loss (gain)
 $
 ( 49,242)
 $
 ( 16,257)
 $
 ( 3,579)
 $
 ( 1,870)
 $
 ( 2,132)
 $
 ( 2,052)

 Prior service cost (credit)
 —
 —
 —
 —

 Total
 $
 ( 49,242)
 $
 ( 16,257)
 $
 ( 3,579)
 $
 ( 1,870)
 $
 ( 1,821)
 $
 ( 1,742)

 SERP
 Other

 2024
 2023
 2024
 2023
 2024
 2023

 Amounts recognized in Accumulated Other Comprehensive Income consist of:

 Net loss (gain)
 $
 39,183
 $
 74,851
 $
 ( 3,342)
 $
 ( 1,613)
 $
 ( 2,204)
 $
 ( 2,124)

 Prior service cost (credit)
 —
 —
 —
 —

 Total
 $
 39,183
 $
 74,851
 $
 ( 3,342)
 $
 ( 1,613)
 $
 ( 1,893)
 $
 ( 1,814)

 The following tables summarize Puget Energy's and PSE's net periodic benefit cost for the years ended December 31, 2024, 2023, and 2022.

 SERP
 Other

 2024
 2023
 2022
 2024
 2023
 2022
 2024
 2023
 2022

 Components of net periodic benefit cost:

 Service cost
 $
 18,616
 $
 18,530
 $
 26,351
 $
 —
 $
 $
 $
 $
 $

 Interest cost
 31,152
 32,375
 24,263
 1,370
 1,589
 1,253

 Expected return on plan assets
 ( 54,896)
 ( 50,641)
 ( 51,014)
 —
 —
 —
 ( 288)
 ( 297)
 ( 379)

 Amortization of prior service cost (credit)
 —
 —
 —
 —

 Amortization of net loss (gain)
 ( 2,684)
 ( 2,447)
 6,381
 ( 42)
 —
 2,471
 ( 139)
 ( 210)
 ( 29)

 Net periodic benefit cost
 $
 ( 7,812)
 $
 ( 2,183)
 $
 5,981
 $
 1,328
 $
 1,876
 $
 4,570
 $
 $
 $

 SERP
 Other

 2024
 2023
 2022
 2024
 2023
 2022
 2024
 2023
 2022

 Components of net periodic benefit cost:

 Service cost
 $
 18,616
 $
 18,530
 $
 26,351
 $
 —
 $
 $
 $
 $
 $

 Interest cost
 31,152
 32,375
 24,263
 1,370
 1,589
 1,253

 Expected return on plan assets
 ( 54,897)
 ( 50,641)
 ( 51,016)
 —
 —
 —
 ( 288)
 ( 297)
 ( 379)

 Amortization of prior service cost (credit)
 —
 —
 —
 —

 Amortization of net loss (gain)
 —
 —
 15,080
 ( 22)
 2,648
 ( 139)
 ( 230)
 ( 35)

 Net periodic benefit cost
 $
 ( 5,129)
 $
 $
 14,678
 $
 1,348
 $
 1,920
 $
 4,747
 $
 $
 $

 The following tables summarize Puget Energy's and PSE's benefit obligations recognized in other comprehensive income (OCI) for the years ended December 31, 2024, and 2023:

 SERP
 Other

 2024
 2023
 2024
 2023
 2024
 2023

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

 Net loss (gain)
 $
 ( 44,439)
 $
 ( 49,917)
 $
 ( 1,751)
 $
 ( 3,433)
 $
 ( 219)
 $
 ( 298)

 Amortization of net (loss) gain
 2,684
 2,447
 —

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

 Prior service cost (credit)
 —
 —
 —
 —

 Amortization of prior service (cost) credit
 —
 —
 —
 ( 144)
 ( 33)
 ( 28)

 Total change in other comprehensive income for year
 $
 ( 41,755)
 $
 ( 47,470)
 $
 ( 1,709)
 $
 ( 3,722)
 $
 ( 79)
 $
 ( 37)

Pension Benefit
 SERP
 Other

 2024
 2023
 2024
 2023
 2024
 2023

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

 Net loss (gain)
 $
 ( 44,438)
 $
 ( 49,916)
 $
 ( 1,751)
 $
 ( 3,433)
 $
 ( 219)
 $
 ( 298)

 Amortization of net (loss) gain
 —
 —
 ( 44)

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

 Prior service cost (credit)
 —
 —
 —
 —

 Amortization of prior service (cost) credit
 —
 —
 —
 ( 144)
 ( 33)
 ( 28)

 Total change in other comprehensive income for year
 $
 ( 44,438)
 $
 ( 49,916)
 $
 ( 1,729)
 $
 ( 3,766)
 $
 ( 79)
 $
 ( 17)

 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, 2025, are expected to be at least $ 18.0 million, $ 6.8 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:
 2024
 2023
 2022
 2024
 2023
 2022
 2024
 2023
 2022

 Discount rate
 5.80
 %
 5.30
 %
 5.60
 %
 5.80
 %
 5.30
 %
 5.60
 %
 5.80
 %
 5.30
 %
 5.60
 %

 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
 5.30
 5.60
 3.00
 5.30
 5.60
 3.00
 5.30
 5.60
 3.00

 Return on plan assets
 7.00
 6.75
 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 gain of $ 39.0 million in 2024. 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:

 2025
 2026
 2027
 2028
 2029
 2030-2034

 Qualified Pension total benefits
 $
 43,800
 $
 44,700
 $
 45,400
 $
 46,100
 $
 47,100
 $
 242,200

 SERP Pension total benefits
 6,759
 2,263
 4,222
 1,630
 1,559
 7,295

 Other Benefits total
 3,491

 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, 2024, and 2023:

 Recurring Fair Value Measures
 Recurring Fair Value Measures

 Level 1
 Other
 Total
 Level 1
 Other
 Total

 Common Stock:

 Domestic

 $
 117,183
 $
 $
 —
 $
 117,382
 $
 130,288
 $
 $
 —
 $
 130,569

 Foreign

 14,050
 —
 —
 14,050
 13,767
 —
 —
 13,767

 Government Securities
 100,126
 13,172
 —
 113,298
 73,243
 12,709
 —
 85,952

 Corporate Securities:

 Domestic

 —
 17,807
 —
 17,807
 —
 14,787
 —
 14,787

 Foreign

 —
 15,004
 —
 15,004
 —
 8,829
 —
 8,829

 Mutual Funds

 75,186
 —
 —
 75,186
 81,130
 —
 —
 81,130

 Cash and cash equivalents
 5,263
 ( 6,323)
 —
 ( 1,060)
 2,846
 —
 3,082

 Investments measured at NAV:

 Collective Investment Funds
 —
 —
 321,937
 321,937
 —
 —
 297,780
 297,780

 Partnership
 —
 —
 90,308
 90,308
 —
 —
 91,845
 91,845

 Mutual Funds
 —
 —
 57,187
 57,187
 —
 —
 48,116
 48,116

 Other
 —
 —
 2,045
 2,045
 —
 —

 Net (payable) receivable
 —
 —
 ( 50,454)
 ( 50,454)
 —
 —
 ( 29,974)
 ( 29,974)

 $
 311,808
 $
 39,859
 $
 421,023
 $
 772,690
 $
 301,274
 $
 36,842
 $
 407,895
 $
 746,011

 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
 $
 —
 $
 4,785
 $
 —
 $
 4,785
 $
 —
 $
 5,085
 $
 —
 $
 5,085

 $
 —
 $
 4,785
 $
 —
 $
 4,785
 $
 —
 $
 5,085
 $
 —
 $
 5,085

 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 the 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:

 2024
 2023
 2022

 Charged to operating expenses:

 Current:

 Federal
 $
 31,101
 $
 66,086
 $
 41,198

 State
 1,317

 Deferred:

 Federal
 ( 875)
 ( 94,860)
 17,866

 State

 Total income tax expense
 $
 30,723
 $
 ( 27,434)
 $
 59,698

 2024
 2023
 2022

 Charged to operating expenses:

 Current:

 Federal
 $
 61,924
 $
 112,168
 $
 81,597

 State
 1,626

 Deferred:

 Federal
 ( 10,226)
 ( 120,397)
 ( 2,171)

 State
 —
 —
 —

 Total income tax expense
 $
 52,587
 $
 ( 6,603)
 $
 80,295

 The following reconciliation compares pre-tax book income at the federal statutory rate of 21.0% to the actual income tax expense in the Consolidated Statements of Income:

 2024
 2023
 2022

 Income taxes at the statutory rate
 $
 63,256
 21.0
 %
 $
 5,524
 21.0
 %
 $
 99,549
 21.0
 %

 Increase (decrease):

 Utility plant differences1

 $
 ( 29,712)
 ( 9.9)
 %
 $
 ( 23,806)
 ( 90.5)
 %
 $
 ( 23,028)
 ( 4.9)
 %

 AFUDC, net
 ( 5,704)
 ( 1.9)
 ( 4,017)
 ( 15.3)
 ( 3,567)
 ( 0.8)
 %

 Executive compensation
 2,209
 0.7
 1,544
 5.9
 1,821
 0.4
 %

 Treasury grant amortization
 ( 797)
 ( 0.3)
 ( 750)
 ( 2.9)
 ( 5,717)
 ( 1.2)
 %

 Excess deferred tax amortization
 —
 —
 ( 8,689)
 ( 33.0)
 ( 13,722)
 ( 2.9)
 %

 State taxes, net
 0.1
 1,070
 4.1
 0.1
 %

 Other–net
 1,078
 0.4
 1,690
 6.4
 3,857
 0.9
 %

 Total income tax expense
 $
 30,723
 10.1
 %
 $
 ( 27,434)
 ( 104.3)
 %
 $
 59,698
 12.6
 %

 2024
 2023
 2022

 Income taxes at the statutory rate
 $
 84,835
 21.0
 %
 $
 26,136
 21.0
 %
 $
 119,962
 21.0
 %

 Increase (decrease):

 Utility plant differences1

 $
 ( 29,712)
 ( 7.4)
 %
 $
 ( 23,806)
 ( 19.1)
 %
 $
 ( 23,028)
 ( 4.0)
 %

 AFUDC, net
 ( 5,704)
 ( 1.4)
 %
 ( 4,017)
 ( 3.2)
 %
 ( 3,567)
 ( 0.6)
 %

 Excess deferred tax amortization
 —
 —
 %
 ( 8,689)
 ( 7.0)
 %
 ( 13,722)
 ( 2.4)
 %

 State taxes, net
 0.2
 %
 1,291
 1.0
 %
 0.1
 %

 Other–net
 2,466
 0.6
 %
 2,482
 2.0
 %
 ( 39)
 —
 %

 Total income tax expense
 $
 52,587
 13.0
 %
 $
 ( 6,603)
 ( 5.3)
 %
 $
 80,295
 14.1
 %

 1.Utility plant differences include the reversal of excess deferred taxes using the average rate assumption method in the amount of $ 29.8 million, $ 27.8 million and $ 27.2 million in 2024, 2023 and 2022, respectively.

 The Company's net deferred tax liability at December 31, 2024, and 2023, is composed of amounts related to the following types of temporary differences:

 2024
 2023

 Utility plant and equipment
 $
 1,768,358
 $
 1,799,505

 Other deferred tax liabilities
 466,317
 407,842

 Subtotal deferred tax liabilities
 2,234,675
 2,207,347

 Net operating loss carryforward
 ( 201,562)
 ( 210,238)

 Net regulatory liability for income taxes
 ( 721,907)
 ( 760,961)

 Other deferred tax assets
 ( 313,526)
 ( 285,919)

 Subtotal deferred tax assets
 ( 1,236,995)
 ( 1,257,118)

 Total net deferred tax liabilities
 $
 997,680
 $
 950,229

 2024
 2023

 Utility plant and equipment
 $
 1,763,456
 $
 1,796,476

 Other deferred tax liabilities
 382,968
 319,328

 Subtotal deferred tax liabilities
 2,146,424
 2,115,804

 Net regulatory liability for income taxes
 ( 722,558)
 ( 761,621)

 Other deferred tax assets
 ( 306,374)
 ( 275,336)

 Subtotal deferred tax assets
 ( 1,028,932)
 ( 1,036,957)

 Total net deferred tax liabilities
 $
 1,117,492
 $
 1,078,847

 The Company calculates its deferred tax assets and liabilities under ASC 740, "Income Taxes". Deferred tax assets and liabilities are recognized based on temporary differences between the financial statement and tax bases of assets and liabilities using enacted tax rates expected to be in effect when these differences are realized. A valuation allowance is recorded when it is more likely than not that some portion or all of a deferred tax asset will not be realized. The ultimate realization of a deferred tax asset depends on the ability to generate sufficient taxable income of the appropriate character and in the appropriate taxing jurisdictions within the carryforward periods available.
 Puget Energy's net operating loss carryforwards will expire at various dates between 2031 and 2037. Net operating losses generated in 2018 and thereafter have no expiration date. The Company believes that it is more likely than not that its deferred income tax assets as of December 31, 2024 will be realized, thus no material valuation allowance has been recorded.
 As of December 31, 2024, and 2023, 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 2021 through 2024. 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. As of December 31, 2024, the Company does not believe that it is involved in any pending proceedings material to the Company's operations.

 (16) Commitments and Contingencies

 For the year ended December 31, 2024, approximately 10.9 % of the Company's energy output was obtained at an average cost of approximately $ 0.067 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:

 2024
 2023
 2022

 PUD contract costs
 $
 211,800
 $
 174,385
 $
 149,575

 As of December 31, 2024, 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
 2025 Percent of Output
 2025 Megawatt Capacity
 Estimated 2025 Total Costs
 2025 Debt Service Costs
 Interest included in 2025 Debt Service Costs
 Debt Outstanding

 Chelan County PUD1:

 Rock Island Project
 2051
 40.0
 %
 $
 85,641
 $
 20,499
 $
 5,572
 $
 98,638

 Rocky Reach Project
 2051
 40.0
 112,077
 6,166
 1,808
 32,155

 Douglas County PUD2:

 Wells Project
 2032
 18.6
 42,883
 —
 —
 —

 Grant County PUD3:

 Priest Rapids Development
 2052
 9.9
 54,717
 4,112

 Wanapum Development
 2052
 9.9
 54,717
 4,112

 Total
 1,163
 $
 350,035
 $
 27,285
 $
 7,712
 $
 139,017

 1.PSE currently purchases output from Chelan County PUD's Rock Island and Rocky Reach hydroelectric projects under four 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; 3) a contract executed during 2023 to purchase an additional 5 % of output for each from January 1, 2024 through December 31, 2028; and 4) a contract executed during 2024 to purchase an additional 5 % of output that begins on February 1, 2025 and continues through December 31, 2025.
 2.PSE currently purchases output from Douglas County PUD's Wells hydroelectric project under three separate contracts: 1) a contract executed in March 2017 with a variable share output (average 13.1 % in 2025) that began on September 1, 2018 and ends September 30, 2028; 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; and 3) a contract executed in August 2024 for 9.5 % to 18.9 % share of output from January 1, 2026 through December 31, 2032.
 3.PSE currently purchases output from Grant County PUD's Wanapum and Priest Rapids hydroelectric developments under four 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 March 31, 2052; 2) a contract entered in June 2024 for 4.22 % of output from the Annual Auction that begins on January 1, 2025, and continues through December 31, 2025; 3) a contract entered in April 2024 for 0.88 % of output from the Eugene Water and Electric Board Meaningful Priority rights that begins on January 1, 2025, and continues through December 31, 2025; and 4) a contract entered in April 2024 for 4.13 % of output from the Meaningful Priority rights that begins on January 1, 2025, and continues through December 31, 2025. PSE reserves the right to renew the latter contract on an annual basis.

 The following table summarizes the Company's estimated payment obligations for purchases from electric portfolio contracts and electric wholesale market transactions. These contracts have varying terms and may include escalation and termination provisions.

 2025
 2026
 2027
 2028
 2029
 Total

 Columbia River projects
 $
 350,035
 $
 238,243
 $
 226,541
 $
 238,331
 $
 171,203
 $
 3,563,272
 $
 4,787,625

 Electric portfolio contracts

 474,683
 255,973
 258,701
 304,056
 291,040
 3,709,279
 5,293,732

 Electric wholesale market transactions
 226,141
 157,991
 87,434
 57,019
 56,982
 515,240
 1,100,807

 Total
 $
 1,050,859
 $
 652,207
 $
 572,676
 $
 599,406
 $
 519,225
 $
 7,787,791
 $
 11,182,164

 Total purchased power contracts provided the Company with approximately 14.6 million, 14.7 million and 15.3 million MWhs of firm energy at a cost of approximately $ 1,006.3 million, $ 851.6 million and $ 892.7 million for the years 2024, 2023, and 2022, 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 $ 125.0 million, $ 137.6 million, and $ 138.3 million for firm transportation, storage and peaking services for its natural gas customers for the years 2024, 2023, and 2022. The Company incurred demand charges of $ 71.1 million, $ 60.5 million, and $ 53.9 million for firm transportation, storage and peaking services for the natural gas supply for its combustion turbines for the years 2024, 2023, and 2022.
 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
 2025
 2026
 2027
 2028
 2029
 Total

 Natural gas wholesale market transactions
 $
 517,802
 $
 429,749
 $
 277,306
 $
 180,565
 $
 79,714
 $
 —
 $
 1,485,136

 Firm transportation service
 167,274
 165,151
 166,716
 163,261
 144,884
 669,602
 1,476,888

 Firm storage service
 9,350
 8,476
 8,189
 2,678
 4,946
 34,476

 Total
 $
 694,426
 $
 603,376
 $
 452,211
 $
 346,504
 $
 225,435
 $
 674,548
 $
 2,996,500

 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
 2025
 2026
 2027
 2028
 2029
 Total

 Energy production service contracts
 $
 36,920
 $
 40,184
 $
 40,987
 $
 41,823
 $
 42,639
 $
 60,494
 $
 263,047

 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. The WDOE published final regulations to implement the program on September 29, 2022, which became effective on October 30, 2022. The WDOE also indicated that there will be subsequent rulemakings building off initial rulemaking as program implementation proceeds.
 Compliance with the CCA requires covered entities to obtain allowances equal to their emissions and submit to the WDOE annually according to a staggered four-year compliance schedule. For the first three years of each compliance period, covered entities must submit allowances to cover at least 30% of their annual compliance obligation, as determined by the WDOE, no later than November 1st of the following year. For the fourth year of each compliance period, covered entities must submit sufficient allowances to cover 100% of their full four-year compliance obligation, as determined by the WDOE.
 The WDOE provided an initial allocation of no-cost allowances to electric utilities, including PSE, on April 24, 2023. However, qualifying electric utilities were allowed to submit revised emissions forecasts approved by the Washington Commission to WDOE. PSE filed its revised forecast of 2023 emission in Docket No. UE 220797, which was approved by the Washington Commission on July 27, 2023, and approved by the WDOE on September 27, 2023.
 On September 30, 2024, the WDOE provided notice to PSE that its 2023 annual compliance obligation was confirmed based on its 2023 reported covered emissions as previously reported to the WDOE. On October 16, 2024, the WDOE held a meeting with electric utilities, including PSE, regarding CCA compliance issues related to calendar year 2023, at which time WDOE stated that based on current information it will not make further adjustments (or "true up") accounting for allocation methods, forecasts or cost burden associated with calendar year 2023 for any electric utilities, including PSE, except for administrative costs, at the current time. The WDOE also indicated that there will be future meetings with electric utilities on

 how the adjustment (or "true-up") mechanism will work going forward and that the WDOE would provide electric utilities advance notice if any such adjustments were being considered. Based on the determinations made by the WDOE in the aforementioned notices, PSE recorded a compliance obligation of $ 26.2 million for allowances for electric operations as of December 31, 2024. Given the potential for future rulemakings and the WDOE's ability to adjust no-cost allowances during the compliance period, there is estimation uncertainty surrounding the Company's ability to estimate its compliance obligation both on an annual basis and a four-year compliance period, prior to a final WDOE determination.
 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 will be recoverable from customers in future utility rates. As a result, there is no current impact to the Company's consolidated statements of income.

 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, 2024, 2023 and 2022, respectively:

 Net unrealized gain (loss) and prior service cost on pension plans

 Changes in AOCI, net of tax

 Total

 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

 27,866
 27,866

 Amounts reclassified from accumulated other comprehensive income (loss), net of tax
 ( 2,237)
 ( 2,237)

 Balance at December 31, 2024
 $
 43,168
 $
 43,168

 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, 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)

 27,862
 —
 27,862

 Amounts reclassified from accumulated other comprehensive income (loss), net of tax
 ( 101)

 27,761
 28,147

 Balance at December 31, 2024
 $
 ( 26,804)
 $
 ( 3,443)
 $
 ( 30,247)

 Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2024, 2023 and 2022, 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)

 2024
 2023
 2022

 Net unrealized gain (loss) and prior service cost on pension plans:

 Amortization of prior service cost
 (a)
 $
 ( 33)
 $
 ( 172)
 $
 ( 311)

 Amortization of net gain (loss)
 (a)
 2,865
 2,658
 ( 8,824)

 Total before tax
 2,832
 2,486
 ( 9,135)

 Tax (expense) or benefit
 ( 595)
 ( 522)
 1,918

 2,237
 1,964
 ( 7,217)

 Total reclassification for the period
 $
 2,237
 $
 1,964
 $
 ( 7,217)

 __________
 (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 this 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)

 2024
 2023
 2022

 Net unrealized gain (loss) and prior service cost on pension plans:

 Amortization of prior service cost
 (a)
 $
 ( 33)
 $
 ( 172)
 $
 ( 311)

 Amortization of net gain (loss)
 (a)
 ( 17,693)

 Total before tax
 ( 18,004)

 Tax (expense) or benefit
 ( 27)
 ( 3)
 3,781

 ( 14,223)

 Net unrealized gain (loss) on treasury interest rate swaps:

 Interest rate contracts
 ( 487)
 ( 488)
 ( 488)

 Tax (expense) or benefit

 ( 386)
 ( 385)
 ( 386)

 Total reclassification for the period
 $
 ( 285)
 $
 ( 373)
 $
 ( 14,609)

 ____________
 (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 this Item 8 of this report for additional details.

 (18) Segment Information

 Puget Energy operates one reportable segment referred to as the regulated utility segment (PSE). PSE does not contain any additional reportable segments. The regulated utility operation generates, purchases and sells electricity and purchases, transports and sells natural gas. The service territory of PSE covers approximately 6,000 square miles in the state of Washington. Operations in addition to the Regulated Utility reportable segment, described as Other below, include the activities conducted at the holding company level and at Puget LNG, a non-regulated liquefied natural gas facility. The accounting policies of the Regulated Utility operating segment are the same as those described in Note 1, "Summary of

 Significant Accounting Policies" to the consolidated financial statements included in this Item 8 of this report. The chief operating decision maker for both Puget Energy and PSE is the president and chief executive officer.
 The chief operating decision maker assesses performance and decides resource allocation using net income for the Regulated Utility reportable segment. Net income is used by the chief operating decision maker to allocate resources, determine the Company's availability to fund capital expenditures, and assess overall performance. The chief operating decision maker uses net income by comparing actual results to budget to assess Company performance.

 Year Ended December 31, 2024

 Regulated Utility
 Other
 Total

 Revenue
 $
 4,825,231
 $
 30,984
 $
 4,856,215

 781,325
 6,661
 787,986

 Income tax (benefit) expense
 52,587
 ( 21,864)
 30,723

 21,664
 24,392
 46,056

 ( 321,550)
 ( 110,644)
 ( 432,194)

 Net income
 ( 80,893)

 17,026,384
 1,934,007
 18,960,391

 Construction expenditures
 ( 1,608,947)
 ( 768)
 ( 1,609,715)

 Year Ended December 31, 2023

 Regulated Utility
 Other
 Total

 Revenue
 $
 4,786,618
 $
 29,956
 $
 4,816,574

 744,629
 6,706
 751,335

 Income tax (benefit) expense
 ( 6,603)
 ( 20,831)
 ( 27,434)

 28,658
 27,857
 56,515

 ( 285,148)
 ( 96,363)
 ( 381,511)

 Net income
 ( 77,319)

 15,771,767
 1,960,686
 17,732,453

 Construction expenditures
 ( 1,465,925)
 ( 640)
 ( 1,466,565)

 Year Ended December 31, 2022

 Regulated Utility
 Other
 Total

 Revenue
 $
 4,216,173
 $
 4,989
 $
 4,221,162

 Depreciation & Amortization
 657,349
 5,883
 663,232

 Income Tax (Benefit) Expense
 80,295
 ( 20,597)
 59,698

 47,194
 12,610
 59,804

 ( 256,774)
 ( 91,147)
 ( 347,921)

 Net Income
 ( 76,607)

 15,200,242
 1,987,272
 17,187,514

 Construction expenditures
 ( 1,000,810)
 ( 3,903)
 ( 1,004,713)

 There are no significant segment expenses used by the chief operating decision maker to manage the segment's operations that are not included in the Consolidated Statements of Income. PSE recognized revenue from Puget LNG for gas transportation services of $ 3.7 million, $ 1.1 million, and zero for years ended December 31, 2024, 2023 and 2022, respectively. These revenues are eliminated in Puget Energy's Consolidated Statements of Income. Puget LNG is charged tariffed rates that are approved by the Washington Commission.

 SCHEDULE I: CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY

 CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

 2024
 2023
 2022

 $
 ( 2,883)
 $
 ( 1,466)
 $
 ( 1,206)

 Other income (deductions):

 Equity in earnings of subsidiary
 334,121
 110,719
 474,873

 Interest income
 18,439
 17,863
 8,458

 ( 103,019)
 ( 88,739)
 ( 84,051)

 Income tax benefit (expense)
 18,597
 15,363
 16,271

 $
 $
 $

 Comprehensive income (loss)
 $
 290,884
 $
 96,053
 $
 417,003

 See accompanying notes to the condensed financial statements.

 CONDENSED BALANCE SHEETS

 2024
 2023

 Investment in subsidiaries
 $
 5,594,854
 $
 5,096,133

 Other property and investments:

 Goodwill
 1,656,513
 1,656,513

 Current assets:

 Cash
 1,596

 Receivables from affiliates1

 256,671
 256,417

 Prepaid expenses and other

 Income tax receivables

 Total current assets
 258,025
 258,128

 Long-term assets:

 Deferred income taxes
 196,210
 207,192

 Other
 1,891
 2,673

 Total long-term assets
 198,101
 209,865

 $
 7,707,493
 $
 7,220,639

 Capitalization and liabilities:

 Common equity
 $
 5,368,205
 $
 4,960,382

 Long-term debt
 1,590,795
 1,988,609

 Total capitalization
 6,959,000
 6,948,991

 Current liabilities:

 Accounts payable to affiliates1

 Short-term debt
 338,400
 261,500

 Current maturities of long-term debt
 —

 Interest
 9,898
 9,995

 Total current liabilities
 748,493
 271,648

 Commitments and contingencies (Note 16)

 Total capitalization and liabilities
 $
 7,707,493
 $
 7,220,639

 1 Eliminated in consolidation.

 See accompanying notes to the condensed financial statements.

 CONDENSED STATEMENT OF CASH FLOWS

 2024
 2023
 2022

 Operating activities:

 Net cash provided by (used in) operating activities
 $
 96,588
 $
 64,506
 $
 ( 10,197)

 Investing activities:

 Investment in subsidiaries
 ( 292,800)
 ( 100,000)
 ( 50,000)

 (Increase) decrease in loan to subsidiary
 ( 590)
 ( 9,753)
 ( 12,176)

 Net cash provided by (used in) investing activities
 ( 293,390)
 ( 109,753)
 ( 62,176)

 Financing activities:

 Dividends paid
 ( 175,861)
 ( 99,760)
 ( 16,230)

 Investment from Parent
 —
 —

 Change in short-term debts, net
 76,900
 142,900
 84,300

 Issuance of long-term debts
 —
 —
 448,075

 Redemption of long-term debts
 —
 —
 ( 450,000)

 Issue costs and others
 2,184
 2,175
 1,370

 Net cash provided by (used in) by financing activities
 196,023
 45,315
 67,515

 Increase (decrease) in cash
 ( 779)
 ( 4,858)

 Cash at beginning of year
 1,596
 1,528
 6,386

 Cash at end of year
 $
 $
 1,596
 $
 1,528

 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, Puget LNG, which was formed in November 2016, and has the sole purpose of owning, operating and financing the non-regulated activity of the 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 Puget LNG of $ 338.1 million, $ 114.8 million and $ 473.8 million for the years ended December 31, 2024, 2023, and 2022, respectively, and business combination accounting adjustments under ASC 805 recorded at Puget Energy for PSE of $( 4.0) million, $( 4.1) million and $ 1.0 million for the years ended December 31, 2024, 2023, and 2022, 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, 2024

 Accounts deducted from assets on balance sheet:

 Allowance for doubtful accounts receivable
 $
 38,211
 $
 43,573
 $
 41,348
 $
 40,436

 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

 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, 2024, 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, 2024, 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, 2024.
 Puget Energy's effectiveness of internal control over financial reporting as of December 31, 2024, 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, 2024, 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, 2024, 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, 2024.
 PSE's effectiveness of internal control over financial reporting as of December 31, 2024, 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, 2024, 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 February 20, 2025, eleven directors constitute Puget Energy's Board of Directors and twelve directors currently constitute PSE's Board of Directors, as set forth below. The directors are selected in accordance with the bylaws of the Companies, 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 65, has been a director on the board of PSE since June 25, 2015 and on the board of Puget Energy since November 2, 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.

 Christine Gregoire, age 77, 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 54, 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 terms of the bylaws 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 48, 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 bylaws of the Companies.

 Grant Hodgkins, age 49, 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 DE Holdings L.P., a water and wastewater utility and contract energy company based in Vancouver, British Columbia. Mr. Hodgkins was selected by BCI and pursuant to the terms of the bylaws 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 63, 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, a 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 PG&E 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 bylaws of the Companies. 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 57, 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 53, 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 terms of the bylaws of the Companies, Ms. Krause serves as an Owner Director on their respective Board 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 70, 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 bylaws of the Companies, 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 47, 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., where she has served 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 serves on the board of Hawaiian Airlines and the board of the Seattle Metro Chamber. 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 47, 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, and Cleco Corporation. Mr. Rubin was selected by Clean Energy JV Sub 1, LP, and pursuant to the terms of the bylaws of the Companies, serves 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 59, 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 currently serves on the boards 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 Paul McMillan, Tom King and Jenine Krause are the members of the Audit Committee of Puget Energy. Directors Paul McMillan, Tom King, Jenine Krause and Diana Rakow are the members of the Audit Committee of PSE. Each 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 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.

 Insider Trading Policy
 Each of Puget Energy and PSE has adopted an insider trading policy governing the purchase, sale and other dispositions of the applicable Company's securities that applies to all Company personnel, including directors, officers, employees and other covered persons, that we believe is reasonably designed to promote compliance with insider trading laws, rules and regulations. A copy of each of Puget Energy's and PSE's insider trading policy is filed as Exhibit 19.1 to this report.

 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 2024, 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 2024, the Company's Named Executive Officers and titles were:
 • Mary E. Kipp, President and Chief Executive Officer (CEO);
 • Jamie L. Martin, Senior Vice President and Chief Financial Officer (CFO) effective May 20, 2024;
 • Lorna Luebbe, Senior Vice President, General Counsel and Chief Sustainability Officer;
 • Aaron A. August, Senior Vice President, Chief Customer and Transformation Officer;
 • Matthew M Steuerwalt, Senior Vice President External Affairs since September 29, 2023; and
 • Daniel A. Doyle, interim Chief Financial Officer (CFO) until May 19, 2024 and serving as a consultant until December 31, 2024. Mr. Doyle had previously served as Senior Vice President and CFO at the Company from 2011 until his retirement in 2021.

 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 was not an employee and did 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 2024, 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 Committee also 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, 84% of the target 2024 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 2023 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 2024 pay decisions are 24 of the companies used for the 2023 pay decisions and two new companies (indicated by asterisks) as shown below:

 Custom Survey Peer Group

 1.
 Allete

 10.
 Entergy*

 19.
 Pinnacle West Capital

 2.
 Alliant Energy
 11.
 Evergy

 20.
 PNM Resource

 3.
 Ameren
 12.
 Eversource

 21.
 Portland General Electric

 4.
 Atmos Energy
 13.
 Hawaiian Electric Industries, Inc.

 22.
 PPL

 5.
 Avista
 14.
 NiSource

 23.
 Public Service Enterprise Group*

 6.
 Black Hills

 15.
 Northwestern Energy

 24.
 Southwest Gas

 CenterPoint

 16.
 Oncor

 25.
 Spire

 Cleco
 17.
 OGE Energy

 26.
 WEC Energy Group

 9.
 CMS Energy
 18.
 ONE Gas

 * Added to 2024 customer survey peer group. (Note - 2023 peer companies South Jersey Industries and UGI did not participate in 2024 survey.)

 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 $4.4 billion, which was comparable to PSE's annual revenues of $4.7 billion. The proxy peer group was reviewed by Meridian to assess the continued relevancy of the companies and is the same as 2023.

 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

 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 2024
 The Committee reviewed the base salaries of the Named Executive Officers in early 2024 and recommended base salary adjustments to the Board, except for Ms. Martin, whose salary was approved at hire in May 2024 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, 2024. Base salaries for 2024 generally remained at the 50th percentile of market among the comparator group.

 Name

 2023 Base Salary

 2024 Base Salary

 % Change

 $1,080,000
 $1,112,400
 3.0%

 N/A

 550,000
 —

 496,800
 571,320
 15.0

 460,000
 500,480
 8.8

 440,000
 500,420
 13.7

 2024 Annual Incentive Compensation
 All PSE employees, including the Named Executive Officers (other than Mr. Doyle), are eligible to participate in an annual incentive plan also 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 2024, 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 2024 were the same as those in 2023 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, and two of the three must be satisfied for the safety measure to be treated as met. The three employee safety targets for 2024 were:
 • All employees view a monthly PSE Awareness and Prevention — Consistent Safety Message video, featuring safety and health related topics to raise awareness and engage employee and leadership discussion. 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 20% increase of submissions from the 2023 baseline number.
 • The Company DART (Days Away from Work, days of Restricted Work, or Job Transfer) is not to exceed a rate of 0.37.
 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 2024, 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. In 2024, PSE EBITDA totaled $1,494.4 million and the Board approved an adjustment for incentive calculation purposes to $1,520.4 million, resulting in funding at 98.2% of target, as described further below.

 2024 Annual Incentive Plan Results
 For 2024, achievement of the corporate goals under the annual incentive plan was at 98.2% of target for EBITDA. PSE adjusted EBITDA was $1,520.4 million, and SQI and safety achievement was 10 out of 10, met or deemed met, leading to a funding level for 2024 of 96.4% for the annual incentive plan for the eligible Named Executive Officers.
 Funding levels for 2024 at maximum, target, and threshold are shown in the table below:
 Annual Incentive Performance Payout Scale and Actual Performance

 Performance Measure (Dollars in Millions)

 2024 EBITDA*

 SQI, SAIDI& Safety**

 Funding Level

 Maximum
 $
 1,703.0

 10/10

 120%

 Target
 1,549.0

 10/10

 Threshold
 1,394.0

 6/10

 2024 Actual Performance

 1,520.4

 10/10

 96.4

 * 2024 EBITDA adjusted from $1,494.4 million with Board approval to reduce the impact of circumstances beyond the control of participants.
 ** Combined SQI and Safety results of 6/10 or better and minimum EBITDA of $1,394.0 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 55% 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 2024. 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 2024 achievement of the corporate goals. The Board approved the incentive amounts shown below, which will be paid in March 2025:

 Name

 Target Incentive
 (% of Base Salary)

 2024 Actual
 Incentive Paid

 2024 Actual Incentive (% of Base Salary)

 115%

 $
 1,479,848

 133.0%

 Jamie L. Martin*

 65*

 241,241
 43.9

 375,889
 65.8

 344,961
 68.9

 376,171
 75.2

 ______________
 * Ms. Martin's annual incentive is prorated for time worked in 2024 since her hire. Her target annual incentive is 65% of base salary. 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 payment for the 2022-2024 cycle is based on achievement of a Return on Equity (ROE) metric, and 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 cycle is funded based on the three-year average ROE metric. ROE reflects the income earned on our equity investment.
 For the 2023-2025 and the 2024-2026 cycles, the long term incentive program is based on three metric categories 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 2022-2024 LTI Plan payment ultimately paid may range from 0% to 200% of target, depending on performance; while the 2023-2025 and 2024-2026 LTI Plan payments may range from 0% to 173% of target, depending on performance.
 The Committee recommends for Board approval a targeted LTI Plan grant value in dollars for each executive. The targeted LTI Plan grant value is determined by evaluating LTI Plan 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.

 2024-2026 Long-Term Incentive Plan Target Awards
 Consistent with prior years, target LTI Plan awards for the 2024-2026 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 $4,550,000 to align with market pay levels. Target LTI Plan award amounts for the 2024-2026 performance cycle are shown in the following table:

 Name

 Target Long Term Incentive ($)

 $4,550,000

 1,200,000

 Details of the target grants and expected values at target, threshold and maximum performance levels can be found in the "2024 Grants of Plan-Based Awards" table below.

 Long-Term Incentive Plan Performance 2022-2024 Performance Cycle Results and Payouts
 The 2022-2024 performance cycle has now ended. Amounts payable as a result of award vesting are shown in the following table:
 • The threshold EBITDA goal of $3,820.0 million was satisfied for the performance cycle. Performance on the ROE component of the grant finished at 7.1%, which was 86.2% of target, below the plan's threshold for funding. The Committee recommended and the Board approved a payment of 100% 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

 2022-2024
 LTIP Paid2

 $3,700,000
 $3,700,000

 Jamie L. Martin2

 393,750
 393,750

 375,000
 375,000

 ______________
 1 Target LTI Plan incentive is the dollar target level set in 2022 or upon employee hire.
 2 In connection with Ms. Martin's commencement of employment in 2024, she was eligible to participate in the 2022-2024 performance cycle at a target amount that reflected reduced participation during the performance cycle but was intended to incentivize performance following commencement of employment.

 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) and Investment Plan for Employees of Puget Sound Energy, Inc. (401(k) 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 2024. Additional information regarding the Officer Restoration Benefit and the Retirement Plan is shown in the "2024 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 "2024 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, 2024.

 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.
 Mr. Doyle, who previously retired as Senior Vice President and CFO from the Company in 2021, was CFO on a contract basis, beginning September 26, 2023 through May 19, 2024. Mr. Doyle was paid $1,575,000 for his time as interim CFO and as a consultant during 2024, as well as housing expenses.
 In connection with her offer of employment, Ms. Martin was eligible to receive a signing bonus of $150,000 and a relocation payment of $175,000, grossed up for taxes, to assist with moving expenses. Both amounts must be repaid if Ms. Martin resigns or is terminated for cause within 24 months of employment. Subject to continued employment, Ms. Martin was eligible to receive a retention bonus of $250,000 in December 2024 and received it. In addition to participation in the 2022-2024 performance cycle under the LTI Plan, Ms. Martin is also eligible to participate in the 2023-2025 performance cycle based on a target grant value of $900,000 and in the 2024-2026 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 2024. 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 Officer Restoration 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. Section 162(m) of the Internal Revenue Code limits the tax deductibility of compensation paid to certain executive officers, including the Named Executive Officers, to $1 million per person per year. The Company, consistent with past practice, retains the flexibility and the discretion to authorize 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 2024.
 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, 2024, for filing with the SEC.

 Compensation and Leadership
 Development Committee of

 Steven Zucchet, chair,
 Scott Armstrong
 Julia Hamm
 Aaron Rubin

 Summary Compensation Table
 The following information is provided for the year ended December 31, 2024, (and for prior years where applicable) with respect to the Named Executive Officers during 2024. The positions listed below are at Puget Energy and PSE, except that Mr. August and Mr. Steuerwalt are executives of PSE only. Positions listed are those held by the Named Executive Officers as of December 31, 2024 (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

 2024

 $
 1,105,714
 $
 246,641
 $
 —
 $
 —
 $
 4,933,207
 $
 —
 $
 113,648
 $
 6,399,210

 President and,
 2023

 1,072,507
 —
 —
 —
 3,810,798
 —
 1,687,813
 6,571,118

 Chief Executive Officer5

 2022

 991,585
 176,361
 —
 —
 3,505,307
 —
 87,678
 4,760,931

 Jamie L. Martin, Chief Financial Officer (effective 5/20/2024)6

 2024

 316,667
 440,207
 —
 —
 801,034
 8,795
 259,253
 1,825,956

 Dan Doyle, Former CFO

 2024

 —
 —
 —
 —
 —
 —
 1,643,147
 1,643,147

 (until 5/19/2024)7

 2023

 —
 —
 —
 —
 —
 —
 360,265
 360,265

 Lorna Luebbe, SVP General

 2024

 555,943
 17,899
 —
 —
 757,989
 46,704
 1,378,970

 Counsel and Chief Sustainability Officer8

 2023

 493,371
 —
 —
 —
 373,044
 5,269
 32,201
 903,885

 Aaron A. August, SVP

 2024

 492,127
 281,360
 —
 —
 707,351
 —
 36,107
 1,516,945

 Chief Customer and Strategy Officer9

 2023

 177,727
 390,000
 —
 —
 393,931
 —
 248,932
 1,210,590

 Matthew M. Steuerwalt, SVP External Affairs10

 2024

 487,841
 62,695
 —
 —
 688,475
 —
 37,141
 1,276,152

 1.Reflects individual performance above target as described in the "Compensation Discussion and Analysis," section titled "2024 Annual Incentive Plan Results" for Ms. Kipp, Ms. Martin, Ms. Luebbe, Mr. August and Mr. Steuerwalt. For Ms. Martin reflects a signing bonus of $150,000 and a retention bonus of $250,000 in connection with commencement of employment in 2024 and described in the "Compensation Discussion and Analysis" section titled "Other Compensation". For Mr. August reflects a retention bonus of $250,000 paid in 2024 in connection with the terms of his 2023 offer of employment.
 2.For 2024, reflects annual cash incentive compensation paid under the 2024 Goals and Incentive Plan and cash incentive compensation paid under the LTI Plan for the 2022-2024 performance cycle. Cash incentive amounts were paid in early 2025 or deferred at the executive's election. The 2024 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 2025.
 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 2024, updated interest rates relative to those used for 2023 have generally resulted in smaller increases in value than in prior years. Information regarding these pension plans is set forth in further detail under "2024 Pension Benefits." The change in pension value amounts for 2024 are: Ms. Kipp, $0; Ms. Martin, $8,795; Mr. August, $0; Ms. Luebbe, $435; and Mr. Steuerwalt, $0. Mr. Doyle retired from the company in 2021 and is not accruing any additional pension benefits.
 4.All Other Compensation for 2024 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.Ms. Martin joined PSE and Puget Energy as Chief Financial Officer on May 20, 2024.
 7.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 until May 19, 2024 and continued as a consultant until December 31, 2024.
 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. August joined PSE as Senior Vice President and Chief Customer and Transformation Officer on July 27, 2023.
 10.Mr. Steuerwalt joined PSE as Senior Vice President External Affairs on September 29, 2023.

 Detail of All Other Compensation
 Name

 Perquisites and Other
 Personal Benefits1

 Registrant Contributions
 to Defined Contribution
 and Deferred Compensation
 Plans2

 Other3

 $
 —
 $
 101,352
 $
 12,297

 175,000
 10,813
 73,441

 Daniel A Doyle

 —
 —
 1,643,147

 —
 37,329
 9,374

 —
 29,325
 6,782

 —
 29,325
 7,816

 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 Ms. Martin, also includes a relocation payment of $175,000, as described in "Other Compensation" of the "Compensation Discussion and Analysis."
 2.Includes Company contributions during 2024 to PSE's Investment Plan (a tax qualified 401(k) plan) and the Deferred Compensation Plan. Company 401(k) contributions are as follows: Ms. Kipp, $29,325; Ms. Martin, $10,813; Ms. Luebbe, $24,150; Mr. August, $29,325; and Mr. Steuerwalt, $29,325. Company contributions to the Deferred Compensation Plan are as follows: Ms. Kipp, $72,027; Ms. Martin, $0; Ms. Luebbe, $13,179; Mr. August, $0; and Mr. Steuerwalt, $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. Martin, also includes the amount of a tax gross-up on relocation payments of $70,441, as described in the "Compensation Discussion and Analysis," "Other Compensation". For Mr. Doyle includes amounts paid under contract for services and housing expenses.

 2024 Grants of Plan-Based Awards
 The following table presents information regarding 2024 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.

 Estimated Future Payouts under Non-Equity
 Incentive Plan Awards

 Name

 Grant Date

 Grant Target Value

 Threshold

 Target

 Maximum

 1/1/2024

 $
 703,593

 $
 1,279,260

 $
 2,558,520

 LTI Plan 2024-20262

 2/23/2024

 4,550,000

 2,502,500

 4,550,000

 7,848,750

 05/20/2024

 $
 114,698
 $
 208,542
 $
 417,083

 LTI Plan 2022-20243

 05/20/2024

 1,552,000

 LTI Plan 2023-20253

 05/20/2024

 2,070,000

 LTI Plan 2024-20262

 05/20/2024

 1,200,000
 660,000
 1,200,000
 2,070,000

 1/1/2024

 $
 204,247

 $
 371,358

 $
 742,716

 LTI Plan 2024-20262

 2/23/2024

 495,000

 1,550,500

 1/1/2024

 $
 178,922
 $
 325,312
 $
 650,624

 LTI Plan 2024-20262

 2/23/2024

 330,000
 1,035,000

 1/1/2024

 $
 178,850

 $
 325,182

 $
 650,364

 LTI Plan 2023-20252

 2/23/2024

 330,000

 1,035,000

 1.As described in the "Compensation Discussion and Analysis," the 2024 Goals and Incentive Plan had dual funding thresholds in 2024 of $1,394.0 million EBITDA and SQI performance of 6/10. Payment would be $0 if either threshold is not met. The threshold estimate assumes $1,394.0 million EBITDA and SQI/Safety measure performance at 6/10. The target estimate assumes $1,549.0 million EBITDA and SQI/Safety measure performance at 10/10. The maximum estimate assumes financial results at funding maximum of $1,703.0 million EBITDA or higher, SQI/Safety measure performance at 10/10 and individual incentive award maximum of 200% of target. The award for Ms. Martin was pro-rated for time worked in 2024 per the plan.
 2.As described in the "Compensation Discussion and Analysis," LTI Plan grants for the 2024-2026 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 Ms. Martin's commencement of employment, she 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".

 2024 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.

 Name

 Plan Name

 Number of Years
 Credited Service

 Present Value
 of Accumulated
 Benefit 1

 Payments
 During Last
 Fiscal Year

 Mary E. Kipp2

 5.3

 $
 —

 $
 —

 5.3

 —

 —

 0.6

 8,795
 —

 —
 —
 —

 22.2

 446,017

 —

 22.2

 —

 —

 1.4

 —

 —

 1.4

 —

 —

 1.3

 —

 —

 1.3

 —

 —

 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, 2024, 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 5.80%, and the post-retirement mortality assumption is based on the 2025 417(e) unisex mortality table. Annuity benefits are converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 5.07%, 5.33%, and 5.36% (the 24-month average of the underlying rates as of September 2024), except that payments assumed to occur during 2025 use segment rates in effect for 2025 (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 2024. 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, 2023, for the benefits earned as of that date using the assumptions used for financial reporting purposes for 2023. These assumptions included assumed cash balance interest credits of 4.0%, a discount assumption of 5.30% and post-retirement mortality assumption based on the 2024 417(e) unisex mortality table. Annuity benefits were 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). Other assumptions used to determine the value as of December 31, 2023, were the same as those used for December 31, 2024.
 2.None of the Named Executive Officers have SERP benefits as that plan was closed prior to their joining PSE. Ms. Kipp, Mr. August and Mr. Steuerwalt 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, 2024 these 401(k) accounts had values of: Ms. Kipp, $66,567, Mr. August, $7,997 and Mr. Steuerwalt, $4,110. 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 as of December 31, 2024 are: Ms. Kipp, $236,294; Ms. Luebbe, $14,801. Mr. August and Mr. Steuerwalt will have contributions added in 2025 and Ms. Martin's first Officer Restoration account contribution is also expected to be made in 2025.

 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 2024, the limit was $345,000. For 2025, the limit is $350,000. 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 2024 and 2025, 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, 2024, of the Named Executive Officers, only Ms. Martin and Ms. Luebbe participate in the Retirement Plan, and only Ms. Luebbe is vested in their benefits under the Retirement Plan and, hence, would be eligible to commence benefit payments upon termination. Ms. Kipp, Mr. August and Mr. Steuerwalt 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.
 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 Internal Revenue Code limitations, are credited by the Company to an account for each within the Deferred Compensation Plan.

 2024 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 2024 and year-end account balances under the Deferred Compensation Plan.

 Name

 Executive Contributions
 in 20241

 Registrant Contributions in 20242

 Aggregate Earnings
 in 20243

 Aggregate Withdrawals/
 Distributions

 Aggregate Balance at December 31, 20244

 $
 68,111
 $
 156,522
 $
 357,404
 $
 —
 $
 3,424,032

 —
 —
 —
 —
 —

 —
 13,179
 —
 14,801

 —
 —
 —
 —
 —

 —
 —
 —
 —
 —

 1.The amount in this column reflects elective deferrals by the executive of salary, annual incentive compensation or LTI Plan awards paid in 2024. Deferred salary amounts are: Ms. Kipp, $68,111; Ms. Martin, $0; Ms. Luebbe, $0; Mr. August, $0 and Mr. Steuerwalt, $0. Deferred annual incentive compensation and LTI Plan award amounts are $0 for all Named Executives. The amounts are also included in the applicable column of the Summary Compensation Table for 2024.
 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 2024.
 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 2024, 2023, and 2022.

 Name
 Reported for 2024

 Reported for 2023

 Reported for 2022

 $
 68,111

 $
 114,816

 $
 1,016,624

 —
 —
 —

 —
 1,132
 —

 —
 —
 —

 —

 —

 —

 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 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. The tracking funds differ from the investment funds offered in the 401(k) plan. The 2024 calendar year returns of these tracking funds were:

 Vanguard Total Bond Market Index

 1.25
 %

 Vanguard 500 Index

 24.97

 Vanguard Money Market Index

 5.23

 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 65 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, 2024. 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 of December 31, 2024, Mr. Doyle was not an employee, and is 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

 $

 $

 $

 $

 $
 9,225,668

 —

 —

 —

 —

 4,183,320

 $

 $

 $

 $

 $
 13,408,988

 $
 $
 $
 —
 $
 $

 —
 —
 —
 —
 —

 $

 $

 $
 —

 $

 $

 $

 $

 $

 $

 $

 —
 —
 —
 —
 1,314,036

 $

 $

 $

 $

 $
 2,634,136

 $
 $
 $
 —
 $
 $

 —

 —

 —

 —

 1,151,104

 $

 $

 $
 —

 $

 $
 2,288,067

 $
 $
 $
 —
 $
 $

 —
 —
 —
 —
 1,150,644

 $

 $

 $
 —

 $

 $
 2,242,894

 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 2024, our last completed fiscal year:
 • The annual total compensation of our CEO reported in the 2024 Summary Compensation Table, was $6,399,210.
 • The median of the annual total compensation of all our employees (excluding our CEO) was $154,837.

 As a result, for 2024 the ratio of annual total compensation of our Chief Executive Officer to the median of our annual total compensation of all employees was 41.4:1.
 We identified our median employee by examining the total cash compensation we paid during 2024 to all individuals, excluding our CEO, who were employed by us on December 31, 2024, which totaled approximately 3,257 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 2024, we calculated annual total compensation for such employee for 2024 using the same methodology we use for our named executive officers as set forth in the 2024 Summary Compensation Table in accordance with the requirements of Item 402 (c)(2)(x) of Regulation S-K. Annual total compensation for 2024 for our median employee included annual salary, annual incentives, and company contributions

 towards benefits including retirement. Annual total compensation for 2024 for our CEO consists of the amount reported in the "Total" column of our 2024 Summary Compensation Table.

 Director Compensation for Fiscal Year 2024
 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 2024 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 2024 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

 $
 289,200

 $
 —

 $
 289,200

 Christine Gregoire
 184,400
 —
 184,400

 Julia Hamm
 186,800
 —
 186,800

 Thomas King

 191,000

 —

 191,000

 Paul McMillan

 206,000

 —

 206,000

 Diana Rakow

 190,200

 —

 190,200

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

 Non-employee Director Compensation Program
 The 2024 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 2024 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 2024, non-employee directors were paid the following additional cash quarterly retainer fees:
 1.Independent Board Chairman, $25,000;
 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, 2024, by each person or group that we know owns more than 5.0% of Puget Energy's and PSE's common stock. No director, officer or executive officer named in the Summary Compensation Table in Item 11 of Part III of this report owns any of the outstanding shares of common stock of Puget Energy or PSE. Puget Equico LLC (Puget Equico) and its affiliates beneficially own 100.0% of the outstanding common stock of Puget Energy. Puget Energy holds 100.0% of the outstanding common stock of PSE. Percentage of beneficial ownership is based on 200 shares of Puget Energy common stock and 85,903,791 shares of PSE common stock outstanding as of February 20, 2025.

 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), 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 Employees 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 to dispose of such shares of Puget Energy common stock that may be beneficially owned by Puget Equico. However, Puget Equico, the Parent Entities and the Investors expressly disclaims beneficial ownership of such shares of common stock other than those shares held directly by such entity. As of February 20, 2025:
 • 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 the Pledge Agreement dated 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 the 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.

 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 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 bylaws of the Companies. An Independent Director: (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 also 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, 2024, and 2023 were as follows:

 2024
 2023

 PSE
 PSE

 Audit fees1

 $
 3,356
 $
 3,026
 $
 3,138
 $
 2,848

 Audit related fees2

 Other fees3

 Total
 $
 3,596
 $
 3,228
 $
 3,426
 $
 3,136

 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 2024 fees are estimated and include an aggregate amount of $2.4 million billed to Puget Energy and $2.2 million billed to PSE through December 2024.
 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 2024 and 2023, 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, 2024, 2023, and 2022, 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 Annual 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 Annual 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 Annual 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 Quarterly 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 Annual 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 Annual 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 Quarterly 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 Annual 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 Annual Report on Form 10-K for the fiscal year ended December 31, 2005.

 ***

 Commission File No. 1-4393); Exhibit 4.4 to Post-Effective Amendment No. 2 to Puget Sound Energy's Registration Statement on Form S-3, filed February 9, 2009.

 Registration No. 333-132497-01; Exhibit 4.1 to Puget Sound Energy's Current Report on Form 8-K, dated September 13, 2006.

 ***

 Commission File No. 1-4393; Exhibit 4.1 to Puget Sound Energy's Annual 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 Annual Report on Form 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 Quarterly 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

 Ninety-third Supplemental Indenture to Puget Sound Energy's Electric Utility First Mortgage, dated as of April 29, 2014

 *

 4.8

 Ninety-fourth Supplemental Indenture to Puget Sound Energy's Electric Utility First Mortgage, dated as of April 29, 2015

 *

 4.9

 Ninety-fifth Supplemental Indenture to Puget Sound Energy's Electric Utility First Mortgage, dated as of April 25, 2016.

 *

 4.10

 Ninety-sixth Supplemental Indenture to Puget Sound Energy's Electric Utility First Mortgage, dated as of April 27, 2017.

 *

 4.11

 Ninety-seventh Supplemental Indenture to Puget Sound Energy's Electric Utility First Mortgage, dated as of April 27, 2018.

 *

 4.12

 Ninety-eighth Supplemental Indenture to Puget Sound Energy's Electric Utility First Mortgage, dated as of April 30, 2019.

 *

 4.13

 Ninety-ninth Supplemental Indenture to Puget Sound Energy's Electric Utility First Mortgage, dated as of April 30, 2020.

 *

 4.14

 One-hundredth Supplemental Indenture to Puget Sound Energy's Electric Utility First Mortgage, dated as of April 30, 2021.

 *

 4.15

 One-hundred and first Supplemental Indenture to Puget Sound Energy's Electric Utility First Mortgage, dated as of April 28, 2023.

 4.16

 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 Exhibit 4.25 to Puget Sound Energy's Registration Statement on Form S-3ASR, filed March 13, 2009, Registration No. 333-157960).

 4.17

 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.

 ***
 4.18

 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).

 ***
 4.19

 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).

 ***
 4.20

 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).

 *

 4.21

 Thirty-seventh Supplemental Indenture to Puget Sound Energy's Gas Utility First Mortgage, dated as of April 25, 2016.

 *

 4.22

 Thirty-eighth Supplemental Indenture to Puget Sound Energy's Gas Utility First Mortgage, dated as of April 27, 2017.

 *

 4.23

 Thirty-ninth Supplemental Indenture to Puget Sound Energy's Gas Utility First Mortgage, dated as of April 30, 2020.

 *

 4.24

 Fortieth Supplemental Indenture to Puget Sound Energy's Gas Utility First Mortgage, dated as of April 28, 2023.

 *

 4.25

 Forty-first Supplemental Indenture to Puget Sound Energy's Gas Utility First Mortgage, dated as of April 22, 2024.

 4.26

 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).

 4.27

 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).

 4.28

 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).

 4.29

 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).

 4.30

 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).

 4.31

 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).

 4.32

 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).

 4.33

 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).

 4.34

 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).

 4.35

 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).

 4.36

 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).

 4.37

 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).

 4.38

 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).

 4.39

 Sixth Supplemental Indenture dated June 14, 2020 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).

 4.40

 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 Quarterly 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 Quarterly 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 Quarterly 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 Quarterly 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 Quarterly 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 Quarterly 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 Quarterly 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 Quarterly 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 Quarterly 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 Quarterly 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 Quarterly 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 Quarterly 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 Annual 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 Annual 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 Annual 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 (incorporated herein by reference to Exhibit 10.16 to Puget Energy's Annual Report on Form 10-K, filed March 5, 2024, Commission File No. 1-16305).

 ***
 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 Annual 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 Annual 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 Annual 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 Annual 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 Annual 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 Annual 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 Annual 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 Quarterly 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 Quarterly 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 Quarterly 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 Annual 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 Annual 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 Annual 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 (incorporated herein by reference to Exhibit 10.32 to Puget Energy's Annual Report on Form 10-K, filed March 5, 2024, Commission File No. 1-16305).

 **

 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 Annual 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 (incorporated herein by reference to Exhibit 10.34 to Puget Energy's Annual Report on Form 10-K, filed March 5, 2024, Commission File No. 1-16305).

 **

 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 Annual 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).

 *

 10.38

 Amendment No. 1 to Second Amended and Restated Credit Agreement dated May 6, 2024 among Puget Energy Inc., as Borrower, JPMorgan Chase Bank N.A., as Administrative Agent, and the lenders party thereto.

 *

 10.39

 Amendment No. 1 to Amended and Restated Credit Agreement dated May 6, 2024, among Puget Sound Energy, Inc., as Borrower, Mizuho Bank, Ltd., as Administrative Agent, and the lenders party thereto.

 *
 19.1

 Puget Energy, Inc and Puget Sound Energy, Inc. Insider Trading Policy.

 *
 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 – Jamie L. Martin.

 *
 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 – Jamie L. Martin.

 *
 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 – Jamie L. Martin.

 97.1

 Puget Energy, Inc. and Puget Sound Energy, Inc. NYSE Executive Compensation Recoupment Policy (incorporated herein by reference to Exhibit 97.1 to Puget Energy's Annual report on Form 10-K, filed March 5, 2024, Commission File No. 1-16305).

 *

 *
 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/ Jamie Martin

 Senior VP and

 (Jamie Martin)

 Chief Financial Officer

 /s/ Stacy Smith
 Controller and Principal Accounting Officer

 (Stacy Smith)

 /s/ Scott Armstrong

 (Scott Armstrong)

 /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)