Table of Contents
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As filed with the Securities and Exchange Commission on May 14, 2026
Registration 333-   
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
Form
S-4
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
 
 
PUGET ENERGY, INC.
(Exact name of registrant as specified in its charter)
 
 
 
Washington
 
4911
 
91-1969407
(State or Other Jurisdiction of
Incorporation or Organization)
 
(Primary Standard Industrial
Classification Code Number)
 
(I.R.S. Employer
Identification Number)
355 110th Ave NE
Bellevue, Washington 98004
(425) 454-6363
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
 
 
Lorna Luebbe
Senior Vice President, General Counsel and Chief Sustainability Officer
Puget Energy, Inc.
355 110th Ave NE
Bellevue, Washington 98004
(425) 454-6363
(Name, address, including zip code, and telephone number, including area code, of agent for service)
 
 
Copies to:
Andrew Moore
Perkins Coie LLP
1301 Second Avenue, Suite 4200
Seattle, Washington 98101-3804
(206) 359-8000
 
 
Approximate date of commencement of proposed sale of the securities to the public:
As soon as practicable after this registration statement becomes effective.
If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box. ☐
If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐
If this Form is a
post-effective
amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated
filer, a smaller reporting company, or emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule
12b-2
of the Exchange Act.
 
Large Accelerated Filer   ☐    Accelerated filer   ☐
Non-accelerated filer   ☒    Smaller reporting company   ☐
     Emerging growth company   ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act. ☐
If applicable, place an X in the box to designate the appropriate rule provision relied upon in conducting this transaction:
Exchange Act Rule
13e-4(i)
(Cross-Border
Issuer Tender Offer) ☐
Exchange Act Rule
14d-1(d)
(Cross-Border
Third-Party
Tender Offer) ☐
 
 
 
The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until this registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.
 
 
 


Table of Contents

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities, and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

 

SUBJECT TO COMPLETION, DATED MAY 14, 2026

P R O S P E C T U S

Puget Energy, Inc.

 

LOGO

Offers to exchange

the exchange notes set forth below

registered under the Securities Act of 1933, as amended

for any and all of its corresponding outstanding original notes

that were issued and sold in a transaction exempt from registration

under the Securities Act of 1933, as amended

 

Exchange Notes

  

Original Notes

$450,000,000 7.000% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2056, Series A

(CUSIP No. 745310 AS1)

  

$450,000,000 7.000% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2056, Series A

(CUSIP Nos. 745310 AR3 and U74592 AH6)

$450,000,000 7.250% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2056, Series B

(CUSIP No. 745310 AU6)

  

$450,000,000 7.250% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2056, Series B

(CUSIP Nos. 745310 AT9 and U74592 AJ2)

 

 

Puget Energy, Inc. (“we,” “us,” “our,” “Puget Energy,” or the “Company”), a Washington corporation, hereby offers to exchange, upon the terms and conditions set forth in this prospectus and the accompanying letter of transmittal, (i) up to $450 million in aggregate principal amount of its 7.000% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2056, Series A, which we refer to as the “Series A exchange notes,” for the same principal amount of its outstanding 7.000% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2056, Series A, which we refer to as the “Series A original notes” and (ii) up to $450 million in aggregate principal amount of its 7.250% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2056, Series B, which we refer to as the “Series B exchange notes,” and together with the Series A exchange notes, the “exchange notes” for the same principal amount of its outstanding 7.250% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2056, Series B, which we refer to as the “Series B original notes,” and together with the Series A original notes, the “original notes.” We refer to the original notes and the exchange notes, collectively, as the “Notes,” the Series A exchange notes and Series A original notes, collectively, as the “Series A Notes” and the Series B exchange notes and Series B original notes, collectively, as the “Series B Notes.” The original notes are and the exchange notes will be unsecured junior subordinated obligations and will rank junior in right of payment to all of our senior indebtedness. In addition, the Notes are structurally subordinated to all existing and future indebtedness and other liabilities, including trade payables debt and preferred stock, if any, incurred or issued by our subsidiaries. The terms of the exchange notes are substantially identical to the terms of the original notes, except that the exchange notes will generally be freely transferable and do not contain certain terms with respect to registration rights and liquidated damages. We will issue the exchange notes under the indenture governing the original notes. For a description of the principal terms of the exchange notes, see “Description of Notes.”

Each of the exchange offers will expire at 5:00 p.m. New York City time, on     , 2026, unless we extend the offer(s). At any time prior to the applicable expiration date, you may withdraw your tender of any original notes; otherwise, such tender is irrevocable. We will receive no cash proceeds from the exchange offers.

The exchange notes constitute a new issue of securities for which there is no established trading market. Any original notes not tendered and accepted in the exchange offers will remain outstanding. To the extent original notes are tendered and accepted in the exchange offers, your ability to sell untendered, and tendered but unaccepted, original notes could be adversely affected. Following consummation of the exchange offers, the original notes will continue to be subject to their existing transfer restrictions and we will generally have no further obligations to provide for the registration of the original notes under the Securities Act of 1933, as amended (the “Securities Act”). We cannot guarantee that an active trading market will develop or give assurances as to the liquidity of the trading market for either the original notes or the exchange notes. We do not intend to apply for listing of either the original notes or the exchange notes on any exchange or market.

We are not asking you for a proxy and you are requested not to send us a proxy. You do not have dissenters’ rights of appraisal in connection with the exchange offers. See “The Exchange Offers—Absence of Dissenters’ Rights of Appraisal.”

Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offers must acknowledge that it will deliver a prospectus in connection with any resale of its exchange notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer for a period of 180 days following the consummation of the exchange offers (or until such broker-dealer is no longer required to deliver a prospectus) in connection with resales of exchange notes received in exchange for notes where the notes were acquired by the broker-dealer as a result of market-making activities or other trading activities. See “Plan of Distribution.”

 

 

Investing in the exchange notes involves certain risks. Please read “Risk Factors” beginning on page 11 of this prospectus.

This prospectus and the letter of transmittal are first being mailed to all holders of the original notes on or about     , 2026.

 

 

Neither the Securities and Exchange Commission (the “SEC” or the “Commission”) nor any state securities commission has approved or disapproved of the exchange notes or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

 

The date of this prospectus is     , 2026.

 


Table of Contents

You should rely only on the information provided in this prospectus or any prospectus supplement. We have not authorized anyone else to provide you with information different from that contained in this prospectus. We are offering to exchange original notes for exchange notes only in jurisdictions where such offers are permitted. You should not assume that the information in this prospectus or any prospectus supplement is accurate as of any date other than the date on the front of these documents.

No dealer, salesperson or other person has been authorized to give any information or to make any representations other than those contained in this prospectus in connection with the exchange offers, and, if given or made, such information or representations must not be relied upon as having been authorized by Puget Energy. This prospectus does not constitute an offer of any securities other than those to which it relates or an offer or a solicitation by anyone in any jurisdiction in which such offer or solicitation is not authorized or in which the person making such offer or solicitation is not qualified to do so or to anyone to whom it is unlawful to make such offer or solicitation in such jurisdiction. Neither the delivery of this prospectus nor any sale made hereunder shall under any circumstance create an implication that there has been no change in the affairs of Puget Energy since the date of this prospectus.

TABLE OF CONTENTS

 

     Page  

FORWARD-LOOKING STATEMENTS

     ii  

PROSPECTUS SUMMARY

     1  

RISK FACTORS

     11  

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     26  

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

     68  

QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

     68  

BUSINESS

     72  

PROPERTIES

     97  

LEGAL PROCEEDINGS

     97  

MANAGEMENT

     98  

COMPENSATION DISCUSSION & ANALYSIS

     102  

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     122  

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     124  

PRIVATE PLACEMENT

     126  

THE EXCHANGE OFFERS

     127  

USE OF PROCEEDS

     137  

CAPITALIZATION

     138  

DESCRIPTION OF NOTES

     139  

MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

     156  

PLAN OF DISTRIBUTION

     157  

LEGAL MATTERS

     159  

EXPERTS

     159  

WHERE YOU CAN FIND MORE INFORMATION

     160  

INDEX TO FINANCIAL STATEMENTS

     F-1  

 

i


Table of Contents

FORWARD-LOOKING STATEMENTS

This prospectus and the documents incorporated by reference into this prospectus contain “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. This act provides a “safe harbor” for forward-looking statements to encourage companies to provide prospective information about themselves so long as they identify these as forward-looking and provide meaningful cautionary language identifying important factors that could cause actual results to differ from the projected results. Words or phrases such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “future,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “should,” “will likely result,” or “will continue” or the negative of such terms or similar expressions are intended to identify certain of these forward-looking statements.

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 our expectations, beliefs or projections will be achieved or accomplished.

In addition to other factors and matters discussed elsewhere in this prospectus, some important factors that could cause actual results or outcomes for us and Puget Sound Energy, Inc., our wholly owned subsidiary (“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, regulations, executive orders, tariffs, trade restrictions, or other governmental policies or actions, including those relating to federal grant programs, and incentives, funding, budgeting or efficiency measures (including any actual or potential reduction in the federal workforce), national security, environmental protection, climate change, greenhouse gas or other emissions, discharges/releases 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 and Migratory Bird Treaty 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 (including the eligibility and availability of tax credits, and its effects on construction timelines of certain projects); and PSE’s ability to recover costs in a timely manner arising from such changes;

 

  •  

Inability to realize deferred tax assets and use tax credits 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 can delay projects, 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;

 

ii


Table of Contents
  •  

Financial, legal or other difficulties of other energy companies or suppliers 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 systems failure, blackouts or large curtailments of transmission or distribution 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 and wind conditions, which can impact PSE’s ability to generate electricity from hydroelectric facilities and wind facilities, respectively;

 

  •  

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, Middle East and other international conflicts, recessions, tariffs and trade restrictions, fuel prices, international currency fluctuations, sanctions, corruption, political instability, acts of war and local and national elections;

 

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  •  

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 our or PSE’s credit ratings, which may have an adverse impact on the availability and cost of capital for us 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, we undertake 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. You are also advised to consult Item 1A—”Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2025 and in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2026 and any further disclosures we make on related subjects in our current reports on Form 8-K.

 

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PROSPECTUS SUMMARY

This section contains a general summary of certain of the information contained in this prospectus and does not include all of the information that may be important to you in making your investment decision. You should read this entire prospectus, including the “Risk Factors” section and the financial statements and notes to those statements contained in this prospectus before making an investment decision. See “Where You Can Find More Information.” As used herein, unless otherwise stated or indicated by context, references to “we,” “our,” “us” and “Company” refer to Puget Energy, Inc. References to “PSE” are to Puget Sound Energy, Inc., our wholly owned subsidiary.

Puget Energy, Inc.

Overview

We are an energy services holding company incorporated in the state of Washington in 1999. Substantially all of our operations are conducted through our regulated subsidiary, PSE, a utility company. We also have 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.

We are owned through a holding company structure by Puget Holdings, LLC (“Puget Holdings”). All of our 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”), 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 (collectively, the “Consortium”).

We are the direct parent company of PSE, the oldest and largest electric and natural gas utility headquartered in the state of Washington, primarily engaged in the business of electric transmission, distribution and generation and natural gas distribution. Our 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 our customers.

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 of the state of Washington.

The following table presents the number of PSE customers for electric and natural gas as of December 31, 2025 and 2024:

 

     December 31,            December 31,         
Customer Count by Class    2025      2024      Percent     2025      2024      Percent  
(in thousands)    Electric      Change     Natural Gas      Change  

Residential

     1,109        1,099        0.9 %      823        821        0.2 % 

Commercial

     135        135        —        57        57        —   

Industrial

     3        3        —        3        3        —   

Other

     9        9        —        —         —         —   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Total1

     1,256        1,246        0.8 %      883        881        0.2 % 
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 
 
1 

At December 31, 2025 and 2024, approximately 430,270 and 428,440 customers purchased both electricity and natural gas from PSE, respectively.

 

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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 qualifying 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.

Since substantially all of our operations are conducted through PSE, our primary source of funds for the repayment of our indebtedness is dividends paid by PSE, which is subject to restrictions on its ability to pay dividends, some of which derive from PSE’s credit agreements, state regulations and commitments made to the Washington Commission in connection with the Washington Commission’s order approving our merger with Puget Holdings. See “Risk Factors – Risks Relating to Puget Energy’s Corporate Structure – As a holding company, we depend on PSE’s ability to pay dividends” and Note 5, “Dividend Payment Restrictions” to the audited consolidated financial statements included in this prospectus.

Our executive office is located at 355 110th Ave NE, Bellevue, Washington 98004, and our mailing address is P.O. Box 97034, Bellevue, Washington, 98009-9734. Our telephone number is (425) 454-6363. Our website address is www.pugetenergy.com. Information found on our website is not incorporated into or otherwise part of this prospectus.

Summary of the Exchange Offers

In March 2026, we completed a private offering of the original notes. We received aggregate proceeds, before expenses, commissions and discounts, of $900,000,000 from the sale of the original notes.

In connection with the offering of original notes, we entered into a registration rights agreement with the initial purchasers of the original notes in which we agreed to use best efforts to cause an exchange offer registration statement of which this prospectus is a part to be declared effective by the SEC within 180 days of the issuance of the original notes as part of the exchange offers for the original notes. In the exchange offers, you are entitled to exchange your original notes for exchange notes, with substantially identical terms as the original notes. The exchange notes will be accepted for clearance through The Depository Trust Company (“DTC”), and Clearstream Banking S.A. (“Clearstream”), or Euroclear Bank S.A./ N.V., as operator of the Euroclear System (“Euroclear”), with a new CUSIP and ISIN number and common code. You should read the discussions under the headings “The Exchange Offers,” “Description of Notes,” and “Description of Notes—Book-Entry; Delivery and Form” respectively, for more information about the exchange offers and exchange notes. After the exchange offers are completed, you will no longer be entitled to any exchange or, with limited exceptions, registration rights for your original notes.

 

The Exchange Offers

We are offering to exchange (i) up to $450 million in aggregate principal amount of Series A exchange notes for the same principal

 

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amount of Series A original notes and (ii) up to $450 million in aggregate principal amount of Series B exchange notes for the same principal amount of Series B original notes. Original notes may only be exchanged in a principal amount of $2,000 or an integral multiple of $1,000 in excess thereof.

 

  The terms of the exchange notes are identical in all material respects to those of the original notes, except the exchange notes will not be subject to transfer restrictions and holders of the exchange notes, with limited exceptions, will have no registration rights. Also, the exchange notes will not include provisions contained in the original notes that required payment of liquidated damages in the event we failed to satisfy our registration obligations with respect to the original notes.

 

  Original notes that are not tendered for exchange will continue to be subject to transfer restrictions and, with limited exceptions, will not have registration rights. Therefore, the market for secondary resales of original notes that are not tendered for exchange is likely to be minimal.

 

  We will issue registered exchange notes promptly after the expiration of the exchange offers.

 

  The exchange offers are not subject to any federal or state regulatory requirements or approvals other than securities laws and blue sky laws.

 

Expiration Date

Each of the exchange offers will expire at 5:00 p.m. New York City time, on     , 2026, unless we decide to extend the expiration date of the exchange offer(s). Please read “The Exchange Offers—Extensions, Delay in Acceptance, Termination or Amendment” for more information about extending the expiration date of the exchange offer(s).

 

Withdrawal of Tenders

You may withdraw your tender of original notes at any time prior to the applicable expiration date. We will return to you, without charge, promptly after the expiration or termination of the exchange offers any original notes that you tendered but that were not accepted for exchange.

 

Conditions to the Exchange Offers

We will not be required to accept original notes for exchange if there is a question as to whether the exchange offers would be unlawful.

 

  The exchange offers are not conditioned on any minimum aggregate principal amount of original notes being tendered. Please read “The Exchange Offers—Conditions to the Exchange Offers” for more information about the conditions to the exchange offers.

 

Procedures for Tendering Original Notes

If your original notes are held through DTC and you wish to participate in the exchange offers, you may do so through DTC’s automated tender offer program. If you tender under this program, you will agree to be bound by the letter of transmittal that we are providing with this prospectus as though you had signed the letter of transmittal. By signing or agreeing to be bound by the letter of transmittal, you will represent to us that, among other things:

 

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  •  

you are not our “affiliate,” as defined in Rule 405 under the Securities Act;

 

  •  

you are acquiring the exchange notes in the ordinary course of your business;

 

  •  

you do not intend to participate in the distribution of the original notes or the exchange notes;

 

  •  

if you are not a broker-dealer, you are not engaged in and do not intend to engage in the distribution of the exchange notes; and

 

  •  

if you are a broker-dealer or you are using the exchange offers to participate in the distribution of exchange notes, you agree and acknowledge that you could not, under Commission policy, rely on certain no-action letters, and you must comply with the registration and prospectus delivery requirements in connection with a secondary resale transaction.

 

Special Procedures for Beneficial Owner

If you own a beneficial interest in original notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender the original notes in the exchange offers, please contact the registered holder as soon as possible and instruct the registered holder to tender on your behalf and to comply with our instructions described in this prospectus.

 

Guaranteed Delivery Procedures

You must tender your original notes according to the guaranteed delivery procedures described in “The Exchange Offers—Guaranteed Delivery Procedures” if any of the following apply:

 

  •  

you wish to tender your original notes but they are not immediately available;

 

  •  

you cannot deliver your original notes, the letter of transmittal or any other required documents to the exchange agent prior to the applicable expiration date; or

 

  •  

you cannot comply with the applicable procedures under DTC’s automated tender offer program prior to the applicable expiration date.

 

Resales

Except as indicated in this prospectus, we believe that the exchange notes may be offered for resale, resold and otherwise transferred without compliance with the registration and prospectus delivery requirements of the Securities Act provided that:

 

  •  

you are not our affiliate;

 

  •  

you are acquiring the exchange notes in the ordinary course of your business;

 

  •  

you do not intend to participate in the distribution of the original notes or the exchange notes;

 

  •  

if you are not a broker-dealer, you are not engaged in and do not intend to engage in the distribution of the exchange notes; and

 

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  •  

if you are a broker-dealer or you are using the exchange offers to participate in the distribution of exchange notes, you agree and acknowledge that you could not, under Commission policy, rely on certain no-action letters, and you must comply with the registration and prospectus delivery requirements in connection with a secondary resale transaction.

 

  Our belief is based on existing interpretations of the Securities Act by the SEC staff set forth in several no-action letters to third parties. We do not intend to seek our own no-action letter, and there is no assurance that the SEC staff would make a similar determination with respect to the exchange notes. If this interpretation is inapplicable, and you transfer any exchange notes without delivering a prospectus meeting the requirements of the Securities Act or without an exemption from such requirements, you may incur liability under the Securities Act. We do not assume, or indemnify holders against, such liability.

 

  Each broker-dealer that is issued exchange notes for its own account in exchange for original notes that were acquired by the broker-dealer as a result of market-making activities or other trading activities must acknowledge that it will deliver a prospectus meeting the requirements of the Securities Act in connection with any resale of the exchange notes. See “Plan of Distribution.”

 

United States Federal Income Tax Considerations

The exchange of original notes for exchange notes will not be a taxable exchange for United States federal income tax purposes. Please see “Material United States Federal Income Tax Considerations.”

 

Use of Proceeds

We will not receive any proceeds from the issuance of the exchange notes pursuant to the exchange offers. We will pay certain expenses incident to the exchange offers. See “The Exchange Offers—Transfer Taxes.”

 

Registration Rights

If we fail to complete the exchange offers as required by the registration rights agreement, we may be obligated to pay additional interest to holders of the original notes. Please see “The Exchange Offers” and “Description of Notes” for more information regarding your rights as a holder of the original notes.

The Exchange Agent

We have appointed Computershare Trust Company, National Association as exchange agent for the exchange offers. Please direct questions and requests for assistance, requests for additional copies of this prospectus or of the letter of transmittal and requests for the notice of guaranteed delivery to the exchange agent. As described in more detail under the caption “The Exchange Offers—Procedures for Tendering,” if you are not tendering under DTC’s automated tender offer program, you should send the letter of transmittal and any other required documents to the exchange agent as follows:

 

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Computershare Trust Company, National Association

 

By Mail (Registered or Certified
Mail Recommended), Overnight
Courier or Hand:
   By Facsimile Transmission
(for Eligible Institutions Only):
   Confirm Receipt of Tenders by
Telephone:
Computershare Trust Company, N.A.
1505 Energy Park Drive
St. Paul, MN 55108
Attn: Bondholder Communications
   (877) 407-4679    (800) 344-5128

The Exchange Notes

 

Issuer

Puget Energy, Inc.

 

Notes Offered

$450,000,000 principal amount of 7.000% Fixed-to-Fixed Reset Rate Junior Subordinated Notes, Series A (“Series A exchange notes”), and $450,000,000 principal amount of 7.250% Fixed-to-Fixed Reset Rate Junior Subordinated Notes, Series B (“Series B exchange notes”), to be issued under the indenture dated as of March 27, 2026, between us and Computershare Trust Company, National Association, as trustee (the “trustee”), including as supplemented by the first supplemental indenture thereto establishing the terms of the Notes dated as of March 27, 2026 (collectively, the “indenture”).

 

Maturity Date

The Series A exchange notes will mature on September 15, 2056. The Series B exchange notes will mature on September 15, 2056.

 

Interest Rate

The Series A exchange notes will bear interest (i) from and including the date of the original issuance to, but excluding, September 15, 2031 at an annual rate of 7.000% and (ii) from and including September 15, 2031 during each Series A Interest Reset Period (as defined herein) at an annual rate equal to the Five-Year Treasury Rate (as defined herein) as of the most recent Reset Interest Determination Date (as defined herein), plus 2.961%; provided, that the interest rate during any Series A Interest Reset Period will not reset below 7.000% (which equals the initial interest rate on the Series A exchange notes). The Series B exchange notes will bear interest (i) from and including the date of the original issuance to, but excluding, September 15, 2036 at an annual rate of 7.250% and (ii) from and including September 15, 2036 during each Series B Interest Reset Period (as defined herein) at an annual rate equal to the Five-Year Treasury Rate as of the most recent Reset Interest Determination Date, plus 2.848%; provided, that the interest rate during any Series B Interest Reset Period will not reset below 7.250% (which equals the initial interest rate on the Series B exchange notes).

 

Interest Payment Dates

Subject to our right to defer interest payments as described under “—Option to Defer Interest Payments” below, interest on the exchange notes will be paid semi-annually in arrears on March 15 and September 15 of each year, beginning September 15, 2026.

 

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Optional Redemption

We may redeem the Series A exchange notes at our option before their maturity: (i) in whole or in part on one or more occasions at a price equal to 100% of the principal amount of the Series A exchange notes being redeemed, plus accrued and unpaid interest, on any day in the period commencing on the date falling 90 days prior to the first Series A Reset Date (as defined herein) and ending on and including the first Series A Reset Date and, after the first Series A Reset Date, on any interest payment date for the Series A exchange notes; (ii) in whole, but not in part, at 100% of their principal amount, plus any accrued and unpaid interest thereon, if certain changes in tax laws, regulations or interpretations occur; or (iii) in whole, but not in part, at 102% of their principal amount, plus any accrued and unpaid interest thereon, if a rating agency makes certain changes in the equity credit criteria for securities such as the Series A exchange notes.

 

  We may redeem the Series B exchange notes at our option before their maturity: (i) in whole or in part on one or more occasions at a price equal to 100% of the principal amount of the Series B exchange notes being redeemed, plus accrued and unpaid interest, on any day in the period commencing on the date falling 90 days prior to the first Series B Reset Date (as defined herein) and ending on and including the first Series B Reset Date and, after the first Series B Reset Date, on any interest payment date for the Series B exchange notes; (ii) in whole, but not in part, at 100% of their principal amount, plus any accrued and unpaid interest thereon, if certain changes in tax laws, regulations or interpretations occur; or (iii) in whole, but not in part, at 102% of their principal amount, plus any accrued and unpaid interest thereon, if a rating agency makes certain changes in the equity credit criteria for securities such as the Series B exchange notes.

 

  For a more complete description of the circumstances under and the redemption prices at which the exchange notes may be redeemed, see “Description of Notes—Redemption—Optional Redemption,” “Description of Notes—Redemption—Redemption Upon a Tax Event” and “Description of Notes—Redemption—Redemption Upon a Rating Agency Event,” in this prospectus.

 

Change of Control Event

If a Change of Control Event (as defined herein) occurs and is continuing with respect to the Series A exchange notes or Series B exchange notes, as the case may be, we may redeem such series of exchange notes, in whole but not in part, at our option at a redemption price equal to 101% of their principal amount, plus any accrued and unpaid interest thereon to, but excluding the date of redemption.

 

 

If we do not redeem the eligible series of exchange notes following the occurrence of a Change of Control Event and have not given a redemption notice for any other specified reason, the per annum interest rate on such series of exchange notes will increase by 5% from and including the date on which the applicable notice of a

 

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Change of Control Event is sent to holders. See “Description of Notes—Redemption—Redemption Upon a Change of Control Event.”

 

Option to Defer Interest Payments

So long as no event of default has occurred and is continuing with respect to the applicable series of exchange notes, we have the option to defer interest payments on the applicable exchange notes, from time to time, for one or more periods (each, an “Optional Deferral Period”) of up to 10 consecutive years (each period, commencing on the date that the first such interest payment would otherwise have been made on the applicable series, a “Series A Optional Deferral Period” or a “Series B Optional Deferral Period”). In other words, we may declare at our discretion up to a 10-year interest payment moratorium on the applicable exchange notes and may choose to do that on more than one occasion. We may not defer payments beyond the redemption date or the maturity date of the exchange notes, and we may not begin a new Optional Deferral Period for the applicable exchange notes until we have paid all accrued interest on the applicable exchange notes from any previous Optional Deferral Periods. Any deferred interest will accrue additional interest at a rate equal to the interest rate on the then applicable series of exchange notes to the extent permitted by law. Once all accrued and unpaid interest on the applicable exchange notes has been paid, we can begin a new Optional Deferral Period. We, however, have no current intention of deferring interest payments on the exchange notes. See “Description of Notes—Option to Defer Interest Payments” in this prospectus.

 

Certain Limitations During an Optional Deferral Period

During a Series A Optional Deferral Period or a Series B Optional Deferral Period, we will not: (i) declare or pay any dividends or distributions, or redeem, purchase, acquire or make a liquidation payment, on any shares of capital stock of Puget Energy, Inc.; (ii) make any payment of principal of, or interest or premium, if any, on or repay, purchase or redeem any of our debt securities that rank upon our liquidation on a parity with or junior to the exchange notes; or (iii) make any payments with respect to any guarantee by us of debt securities if such guarantee ranks upon liquidation on a parity with or junior to the exchange notes, subject to certain exceptions. See “Description of Notes—Option to Defer Interest Payments” in this prospectus.

 

Ranking

The exchange notes will be our unsecured junior subordinated obligations and will rank junior in right of payment to all of our Senior Indebtedness (as defined in this prospectus under “Description of Notes—Ranking of the Notes”).

 

 

As of March 31, 2026, we had approximately $2.2 billion of Senior Indebtedness (excluding letter of credit amounts) outstanding. In addition, the exchange notes are structurally subordinated to all existing and future indebtedness and other liabilities, including trade payables debt and preferred stock, if any, incurred or issued by our

 

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subsidiaries. As of March 31, 2026, the total long-term indebtedness of our subsidiaries was approximately $6.5 billion (including securities due within one year); this amount does not include other liabilities.

 

Guarantees

The Notes will not be guaranteed by any of our subsidiaries or other affiliates.

 

Events of Default

See “Description of Notes—Events of Default” in this prospectus.

 

U.S. Federal Income Tax Considerations

By acquiring an interest in an exchange note, each holder and beneficial owner thereof will be deemed to agree to treat the exchange notes as indebtedness of Puget Energy for U.S. federal income tax purposes. We will treat the exchange note in the same manner. For a discussion of certain U.S. federal income tax risks relating to an investment in the exchange notes, see “Risk Factors—If we defer interest payments on either series of the Notes, or in certain other circumstances, there will be U.S. federal income tax consequences to holders of the Notes that are United States persons (as defined in the Code).”

 

Issuer Obligations

The obligations to pay the principal of, premium, if any, and interest on the exchange notes are solely our obligations, and none of Puget Equico LLC (“Puget Equico”) (our direct parent company), the members of the Consortium, or any of our subsidiaries will guarantee or provide any credit support for our obligations on the exchange notes.

 

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Summary Consolidated Financial Information

The following tables summarize our consolidated financial information. We derived the following consolidated income statement, cash flow statement and other financial data for each of the three fiscal years ended December 31, 2025, 2024, and 2023 and the consolidated balance sheet and other data as of December 31, 2025 and 2024 from our audited consolidated financial statements included elsewhere in this prospectus. The results as of and for the three months ended March 31, 2026 are not necessarily indicative of results to be expected for the full fiscal year or any future period. The results as of and for the three months ended March 31, 2026 and 2025 are unaudited. The summary consolidated financial information provided below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Use of Proceeds,” the audited consolidated financial statements, the unaudited consolidated interim financial statements, the related notes, and other financial information, included elsewhere in this prospectus.

 

     Fiscal Year Ended
December 31,
    Three Months Ended
March 31,
 
     2025     2024     2023     2026     2025  
     (dollars in thousands)  

Income statement data:

          

Operating revenue

   $ 5,416,333     $ 4,856,215     $ 4,816,574     $ 1,848,257     $ 1,602,003  

Operating expenses

   $ 4,660,649     $ 4,249,019     $ 4,485,508     $ 1,512,023     $ 1,341,122  

Cash flow statement data:

          

Net cash provided by operating activities

   $ 1,061,103     $ 822,823     $ 1,053,395     $ 398,252     $ 397,022  

Net cash used in investing activities

   ($ 1,767,666 )    $ (1,607,843 )    $ (1,452,518 )    $ (412,139 )    $ (351,150 ) 

Net cash provided by financing activities

   $ 724,715     $ 711,146     $ 444,913     $ 529,591     $ 390,584  

Other financial data:

          

Capital expenditures

   $ (1,771,828 )    $ (1,609,715 )    $ (1,466,565 )    $ (412,214 )    $ (353,582 ) 

 

     December 31,      March 31,  
     2025      2024      2026  
     (dollars in thousands)  

Balance sheet and other data
(at end of period):

        

Cash and cash equivalents

   $ 40,484      $ 101,836      $ 521,709  

Debt

   $ 9,012,532      $ 8,219,319      $ 9,559,345  

Shareholders’ equity

   $ 5,707,347      $ 5,368,205      $ 5,908,686  

 

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RISK FACTORS

You should carefully consider the following risks, as well as the other information contained in this prospectus, before exchanging the Notes. The risks and uncertainties described below are not the only ones facing us. Additional risks and uncertainties not presently known or currently deemed immaterial may also impair our business operations and our ability to service the Notes.

RISKS RELATING TO THE EXCHANGE OFFERS

Because there is no public market for the exchange notes, you may not be able to sell your exchange notes.

The exchange notes will be registered under the Securities Act, but will constitute a new issue of securities with no established trading market. There can be no assurance as to:

 

  •  

The liquidity of any trading market that may develop;

 

  •  

The ability of holders to sell their exchange notes; or

 

  •  

The price at which the holders would be able to sell their exchange notes.

The exchange notes will not be listed on any exchange or market. If a trading market were to develop, the exchange notes might trade at higher or lower prices than their principal amount or purchase price, depending on many factors, including prevailing interest rates, the market for similar securities and our financial performance.

Any market-making activity in the exchange notes will be subject to the limits imposed by the Securities Act and the Securities Exchange Act of 1934, as amended (the “Exchange Act”). There can be no assurance that an active trading market will exist for the exchange notes or that any trading market that does develop will be liquid.

In addition, any original note holder who tenders in the exchange offers for the purpose of participating in a distribution of the exchange notes may be deemed to have received restricted securities and, if so, will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction.

Your original notes will not be accepted for exchange if you fail to follow the exchange offer procedures.

We will issue exchange notes pursuant to the exchange offers only after timely receipt of your original notes, a properly completed and duly executed letter of transmittal and all other required documents. Therefore, if you want to tender your original notes, please allow sufficient time to ensure timely delivery. If we do not receive your original notes, letter of transmittal and other required documents by the applicable expiration date of the exchange offers, we will not accept your original notes for exchange. We are under no duty to give notification of defects or irregularities with respect to the tenders of original notes for exchange. If there are defects or irregularities with respect to your tender of original notes, we may not accept your original notes for exchange.

If you do not exchange your original notes, your original notes will continue to be subject to the existing transfer restrictions and you may be unable to sell your outstanding original notes.

We did not register the original notes and do not intend to do so following the exchange offers. Original notes that are not tendered will therefore continue to be subject to the existing transfer restrictions and may be transferred only in limited circumstances under applicable securities laws. If you do not exchange your original notes, you will lose your right, except in limited circumstances, to have your original notes registered under the federal securities laws. As a result, if you hold original notes after the exchange offers, you may be unable to sell your original notes and the value of the original notes may decline. We have no obligation, except in limited

 

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circumstances, and do not currently intend, to file an additional registration statement to cover the resale of original notes that did not tender in the exchange offers or to re-offer to exchange the exchange notes for original notes following the expiration of the exchange offers.

RISKS RELATING TO PUGET ENERGY’S CORPORATE STRUCTURE

As a holding company, we depend on PSE’s ability to pay dividends.

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

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 earnings before interest, tax, depreciation and amortization (“EBITDA”) to interest expense ratio. The common equity ratio, calculated on a regulatory basis, was 49.0% at March 31, 2026, and the EBITDA to interest expense ratio was 5.4 to 1.0 for the twelve months ended March 31, 2026.

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.

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

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 Revised Code of Washington (“RCW”) 80.28 to require electric and natural gas

 

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utilities to file forward looking Multi-Year Rate Plans (“MYRP”) as part of their general rate case (“GRC”) 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 GRC 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 Purchased Gas Adjustment (“PGA”) mechanism, as discussed in our Annual Report on Form 10-K for the year ended December 31, 2025. 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. Concerns about customer affordability could cause the regulators to approve lesser cost recovery amounts than requested by PSE. 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 based off the normalized rate of return reported to the Washington Commission within the Commission Basis Reports. 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 Power Cost Adjustment (“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, variable hydrological and wind conditions, 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

 

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insufficient energy resources to meet its energy supply needs, transmission availability, 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:

 

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Below normal levels of generation by PSE-owned hydroelectric and wind facilities due to low streamflow conditions or precipitation and snowpack, and variable wind conditions, respectively;

 

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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

 

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Failure of a counterparty to build or 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:

 

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

 

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Volatility in prices for fuel and fuel transportation;

 

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

 

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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;

 

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Labor disputes;

 

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Operator error or safety related stoppages;

 

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

 

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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

 

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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 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. Natural disasters and catastrophic events may also expose PSE to liability for personal injury, loss of life and property damage. While PSE maintains insurance coverage for natural disasters and catastrophic events, such 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.

Wildfires may adversely affect PSE’s business, financial condition and results of operations and expose the Company to liability.

PSE’s service territory spans regions in Washington State that are susceptible to wildfires due to vegetation density, drought conditions, high winds, extreme temperatures, and other climate-related factors. Wildfires may be ignited by, or alleged to have been ignited by PSE’s transmission, distribution or generation infrastructure or by PSE’s or its contractors’ operating or maintenance practices. In such events, PSE could be subject to substantial claims and costs, including fire suppression and clean-up expenses, evacuation and emergency response costs, fines and penalties, and liability for economic and property damage, business interruption, environmental impacts, personal injury, or loss of life, whether based on claims of negligence, trespass, or otherwise. Even where PSE is not ultimately found liable, PSE could incur significant defense and settlement costs, and may be subject to governmental investigations, enforcement actions, and reputational harm.

PSE’s wildfire mitigation and response protocols such as public safety power shutoff (“PSPS”) programs may not be successful or sufficient in preventing wildfires and, if implemented, may themselves give rise to claims. For example, intentional power interruptions taken to reduce wildfire risk (such as PSPS), may lead to customer complaints or claims for lost service, business interruption, data loss, spoilage, or other damages.

The frequency and severity of wildfires may increase due to changing climate conditions, including prolonged drought, heat waves, reduced precipitation, higher wind events, and the spread of pests or diseases that create more dead or dying vegetation. Wildfires may damage or destroy PSE’s infrastructure, impair PSE’s ability to deliver power, or limit PSE’s ability to access facilities for inspection and repair, resulting in extended outages, increased operating and capital costs, and reduced revenues. Restoration and hardening efforts following a wildfire can be time-consuming and costly, and supply chain constraints or labor shortages may exacerbate these impacts.

Wildfires, including those beyond PSE’s service territory, have adversely affected insurance markets and may make insurance coverage for wildfire risk limited, costly, or unavailable on commercially reasonable terms, and PSE’s policies may contain sublimits, exclusions and higher deductibles that could result in material uninsured or underinsured losses. Insurers may reduce coverage or increase premiums over time. PSE may be unable to recover wildfire-related costs in rates or through other regulatory mechanisms, or recovery may be

 

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delayed, contested, or conditioned. If wildfire-related liabilities or costs exceed PSE’s insurance and cost-recovery mechanisms, PSE’s financial condition, results of operations, cash flows, and liquidity could be materially adversely affected.

A significant wildfire event, whether or not caused by PSE’s equipment or operations, could also result in increased scrutiny from regulators and lawmakers, more stringent compliance obligations, and heightened litigation risk. Adverse outcomes or the perceived risk of wildfire exposure absent a specific event could harm PSE’s reputation, hinder PSE’s access to capital markets, negatively affect PSE’s credit ratings and increase its cost of borrowing. The absence of legislation limiting wildfire-related liability or establishing a wildfire relief fund could further pressure PSE’s credit profile, constrain its ability to attract capital on acceptable terms, and impede investments necessary to execute its strategic plan.

The magnitude and timing of wildfire-related costs and liabilities are inherently uncertain and depend on numerous factors, including weather conditions, the effectiveness of mitigation measures, legal standards of liability, insurance availability, and regulatory treatment. As a result, PSE may underestimate the scope, duration, or financial impact of wildfire-related risks.

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, such cost recovery could negatively affect the affordability of our services for customers, it may not be possible to recover the full costs or 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

 

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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 greenhouse gas 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 (including federal actions or inaction that may impact the siting, permitting, and construction of new facilities), 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 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

 

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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 or poor performance 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 suffer, which 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 facility development construction and maintenance, electric transmission and natural gas distribution construction and maintenance, certain billing and metering processes, call center overflow and credit and collections. The lack of skilled workers, unavailability of such vendors, or poor performance associated with vendor work 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 such changes could negatively affect the affordability of our services for customers and/or PSE may not be able to recover all of its costs for such expenditures through electric and natural gas rates in a timely manner.

 

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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 (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 diminish 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.

 

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RISKS RELATING TO OUR AND PSE’S FINANCING

Puget Energy’s and PSE’s businesses are dependent on their ability to successfully access capital.

We rely, and PSE 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 we 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 our 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 us or PSE, may increase our 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 Puget Energy’s and PSE’s debt could adversely affect its liquidity and results of operations.

We and PSE have short-term and long-term debt and may incur additional debt (including secured debt) in the future. We have access to a multi-year $800.0 million revolving credit facility, secured by substantially all of our assets, which has a maturity date of May 14, 2027. No amounts were drawn and outstanding under the facility as of March 31, 2026. Our 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 March 31, 2026, no amounts were drawn and outstanding under the PSE credit facility. In addition, we have issued $2.2 billion in senior secured notes and $900 million in junior subordinated notes, whereas PSE, as of March 31, 2026, had approximately $6.5 billion outstanding under pollution control bonds and senior notes. Our debt level could have important effects on the business, including but not limited to:

 

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

 

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

 

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Limiting our and PSE’s financial flexibility, including our and PSE’s 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 we nor PSE has any rating downgrade provisions in our 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 our and PSE’s facilities, the borrowing spreads over the Secured Overnight Financing Rate (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 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.

 

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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 2026 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 THE NOTES

Our obligations under the Notes will be subordinated to all of our Senior Indebtedness.

Our obligations under the Notes will be subordinated to all of our Senior Indebtedness as defined under “Description of Notes—Ranking of the Notes” in this prospectus. This means that we cannot make any payments on the Notes until all holders of our Senior Indebtedness have been paid in full, or provision has been made for such payment, if the Senior Indebtedness is in default (subject to certain exceptions for grace periods and waivers). As of March 31, 2026, we had approximately $2.2 billion of Senior Indebtedness (excluding letter of credit amounts) outstanding.

We can defer interest payments on a given series of the Notes for one or more periods of up to 10 years. This may affect the market price of the Notes.

We have the option to defer interest payments on the Notes, from time to time, for one or more Optional Deferral Periods of up to 10 consecutive years. At the end of an Optional Deferral Period, if all amounts due are paid, we would be permitted to start a new Optional Deferral Period of up to 10 consecutive years. During any Optional Deferral Period, interest on the Notes would be deferred but would accrue additional interest at a rate equal to the interest rate on the then applicable series of Notes, to the extent permitted by law. See “Description of Notes—Option to Defer Interest Payments” in this prospectus.

If we exercise our right to defer interest payments, the Notes may trade at a price that does not fully reflect the value of accrued but unpaid interest on the Notes or that is otherwise less than the price at which the Notes may have been traded if we had not exercised such right. In addition, as a result of our right to defer interest payments, the market price of the Notes may be more volatile than other securities that do not have these rights.

We are not permitted to pay current interest on the Notes until we have paid all outstanding deferred interest, and this could have the effect of extending interest deferral periods.

During an Optional Deferral Period, we will be prohibited from paying current interest on the applicable Notes until we have paid all accrued and unpaid deferred interest plus any accrued interest thereon. As a result, we may not be able to pay current interest on the applicable Notes if we do not have available funds to pay all accrued and unpaid deferred interest plus any accrued interest thereon.

If we defer interest payments on either series of the Notes, or in certain other circumstances, there will be U.S. federal income tax consequences to holders of the Notes that are United States persons (as defined in the Code).

We believe that the likelihood of our exercising the option to defer interest payments is “remote” within the meaning of the U.S. Treasury Regulations and further expect the Notes to be treated for U.S. federal income tax

 

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purposes as “variable rate debt instruments” (“VRDIs”). For these reasons, and based on applicable Treasury Regulations and the expected pricing terms of the Notes, we expect that the Notes will not be treated as issued with original issue discount (“OID”).

Nevertheless, if the option to defer interest payments on either series of the Notes for one or more Optional Deferral Periods were determined not to be remote, or if we exercised such option, the Notes would be treated as issued with OID at the time of issuance, or as reissued with OID at the relevant later point in time. In such case, if you are a beneficial owner of a Note that is a United States person (as defined in the United States Internal Revenue Code of 1986, as amended (the “Code”)), you will be required to include such OID in taxable income (as ordinary income) as it accrues, using a constant yield method, regardless of your regular method of accounting for U.S. federal income tax purposes and in advance of the receipt of the cash to which such OID is attributable.

If you sell or otherwise dispose of a Note of a given series before the record date for the payment of interest at the end of an Optional Deferral Period, you will not receive such interest. Instead, the accrued interest will be paid to the holder of record on the record date regardless of who the holder of record may have been on any other date during the Optional Deferral Period. Moreover, if you are a beneficial owner of a Note that is a United States person (as defined in the Code), the accrued OID will be added to your adjusted tax basis in the Note but may not be reflected in the amount you realize on the sale or other disposition. To the extent the amount realized on a sale or other taxable disposition of a Note is less than your adjusted tax basis, you will generally recognize a capital loss for U.S. federal income tax purposes. The deductibility of capital losses is subject to limitations.

We encourage holders to consult their own tax advisors regarding the United States federal tax consequences of being a holder of the Notes in light of their particular circumstances, as well as any tax consequences arising under the laws of any state, local or foreign taxing jurisdiction.

The Indenture permits us to incur additional debt.

The indenture governing the Notes does not place any limitation on the amount of debt that may be incurred by us or PSE. We may therefore incur a significant amount of additional debt, including secured debt. PSE may also incur additional debt, which could affect its ability to pay dividends to us. The incurrence of additional debt may have important consequences for holders of the Notes, including making it more difficult for us to satisfy our obligations with respect to the Notes, a loss in the trading value of the Notes, if any, and a risk that the credit rating of the Notes is lowered or withdrawn.

Any lowering of the credit ratings on the Notes would likely reduce their value.

Our credit ratings could be lowered in the future. Any lowering of the credit rating on the junior subordinated notes would likely reduce the value of the Notes offered hereby.

Rating agencies may change their practices for rating the Notes, which change may affect the market price of the Notes. In addition, we may redeem the Notes if a rating agency makes certain changes in the equity credit methodology for securities such as the Notes.

The rating agencies that currently or may in the future publish a rating for us, including Moody’s Investors Service, Inc., S&P Global Ratings and Fitch Ratings, Inc., may, from time to time in the future, change the way they analyze securities with features similar to the Notes. This may include, for example, changes to the relationship between ratings assigned to an issuer’s senior securities and ratings assigned to securities with features similar to the Notes. If the rating agencies change their practices for rating these types of securities in the future, and the ratings of the Notes are subsequently lowered, that could have a negative impact on the trading price of the Notes. In addition, we may redeem the Notes at our option, in whole, but not in part, if a rating agency makes certain changes in the equity credit methodology for securities such as the Notes. See “Description of Notes—Redemption—Redemption Upon a Rating Agency Event” in this prospectus.

 

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Holders of each series of the Notes will have limited rights of acceleration.

Holders of each series of the Notes and the trustee under the indenture may accelerate payment of the principal and interest on each series of Notes only upon the occurrence and continuation of certain events of default. Payment of principal and interest on each series of the Notes may be accelerated upon the occurrence of an event of default under the indenture related to failure to pay interest within 30 days after it is due, failure to pay principal or premium, if any, on each series of the Notes when due, and certain events of bankruptcy, insolvency, receivership or reorganization relating to the Company. Holders of each series of the Notes and the trustee will not have the right to accelerate payment of the principal or interest on each series of the Notes upon the breach of any other covenant in the indenture. See “Description of Notes—Events of Default” in this prospectus.

We may choose to redeem the Notes prior to maturity.

We may at our option redeem either series of the Notes in whole or in part at the times and the applicable redemption prices described in this prospectus. See “Description of Notes—Redemption.” We may choose to redeem your Notes at a time when prevailing interest rates are lower than the interest rate paid on your Notes. If prevailing interest rates are lower at the time of redemption, you may not be able to reinvest the redemption proceeds in a comparable security at an interest rate as high as the effective interest rate of the Notes being redeemed.

Upon the occurrence of a Change of Control Event with respect to the Series A Notes or the Series B Notes, we may redeem such series of Notes, in whole but not in part, at our option at a redemption price equal to 101% of their principal amount, plus any accrued and unpaid interest thereon, to but excluding the date of redemption. If we do not redeem the eligible series of Notes following the occurrence of a Change of Control Event and have not given a redemption notice for any other specified reason, the per annum interest rate on such series of Notes will increase by 5% from and including the date on which the applicable notice of a Change of Control Event is sent to holders. See “Description of Notes—Redemption—Redemption Upon a Change of Control Event.”

While it is not possible for the interest rate on the Series A Notes to decrease below the initial interest rate, the interest rate on the Series A Notes may fluctuate over time.

The interest rate on the Series A Notes from their original issue date to, but excluding, September 15, 2031 will be 7.000% per annum. Beginning on September 15, 2031, the interest rate on the Series A Notes for the Series A Interest Reset Period will equal the Five-Year Treasury Rate as of the most recent Series A Reset Interest Determination Date plus a spread of 2.961%, to be reset on the Series A Reset Date; provided, that the interest rate during any Series A Interest Reset Period will not reset below 7.000% (which equals the initial interest rate on the Series A Notes). Accordingly, while it is not possible for the interest rate on the Series A Notes to decrease below the initial interest rate, the interest rate for a given Series A Interest Reset Period subsequent to the initial Series A Interest Reset Period may decrease as compared to the interest rate for the prior Series A Interest Reset Period. The Company has no control over the factors that may affect U.S. Treasury rates, including geopolitical, economic, financial, political, regulatory, judicial or other conditions or events.

While it is not possible for the interest rate on the Series B Notes to decrease below the initial interest rate, the interest rate on the Series B Notes may fluctuate over time.

The interest rate on the Series B Notes from their original issue date to, but excluding, September 15, 2036 will be 7.250% per annum. Beginning on September 15, 2036, the interest rate on the Series B Notes for the Series B Interest Reset Period will equal the Five-Year Treasury Rate as of the most recent Series B Reset Interest Determination Date plus a spread of 2.848%, to be reset on the Series B Reset Date; provided, that the interest rate during any Series B Interest Reset Period will not reset below 7.250% (which equals the initial interest rate on the Series B Notes). Accordingly, while it is not possible for the interest rate on the Series B

 

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Notes to decrease below the initial interest rate, the interest rate for a given Series B Interest Reset Period subsequent to the initial Series B Interest Reset Period may decrease as compared to the interest rate for the prior Series B Interest Reset Period. The Company has no control over the factors that may affect U.S. Treasury rates, including geopolitical, economic, financial, political, regulatory, judicial or other conditions or events.

Historical United States Treasury rates are not an indication of future United States Treasury rates.

In the past, United States Treasury rates have experienced significant fluctuations. Historical levels, fluctuations and trends of United States Treasury rates are not necessarily indicative of future levels. Any historical upward or downward trend in United States Treasury rates is not an indication that United States Treasury rates are more or less likely to increase or decrease at any time after September 15, 2031, and historical United States Treasury rates are not an indication of future Five-Year Treasury Rates.

Federal and state fraudulent transfer laws may permit a court to void the Notes, subordinate claims in respect of the Notes and require holders to return payments received and, if that occurs, you may not receive any payments on the Notes.

Federal and state fraudulent transfer and conveyance statutes may apply to the issuance of the Notes. Under U.S. federal bankruptcy law and comparable provisions of state fraudulent transfer or conveyance laws, which may vary from state to state, the delivery of the Notes could be voided as a fraudulent transfer or conveyance if (a) we or our direct parent company, Puget Equico, as applicable, issued the Notes with the intent of hindering, delaying or defrauding creditors or (b) we or Puget Equico, as applicable, received less than reasonably equivalent value or fair consideration in return for issuing the Notes and, in the case of (b) only, one of the following is also true at the time thereof:

 

  •  

we or Puget Equico, as applicable, were insolvent or rendered insolvent by reason of the issuance of the Notes;

 

  •  

the issuance of the Notes left us or Puget Equico with an unreasonably small amount of capital to carry on the business;

 

  •  

we or Puget Equico intended to, or believed that we or Puget Equico would, incur debts beyond our or Puget Equico’s ability to pay such debts as they mature; or

 

  •  

we or Puget Equico was a defendant in an action for money damages, or had a judgment for money damages docketed against us or Puget Equico, in either case, after final judgment, the judgment is unsatisfied.

A court would likely find that we or Puget Equico did not receive reasonably equivalent value or fair consideration for the Notes if we or Puget Equico did not substantially benefit directly or indirectly from the issuance of the Notes. As a general matter, value is given for a transfer or an obligation if, in exchange for the transfer or obligation, property is transferred or an antecedent debt is secured or satisfied. A debtor will generally not be considered to have received value in connection with a debt offering if the debtor uses the proceeds of that offering to make a dividend payment or otherwise to retire or redeem equity securities issued by the debtor.

We cannot be certain as to the standards a court would use to determine whether or not we or Puget Equico were solvent at the relevant time. Generally, however, an entity would be considered insolvent if, at the time it incurred indebtedness:

 

  •  

the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all its assets;

 

  •  

the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature; or

 

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  •  

it could not pay its debts as they become due.

If a court were to find that the issuance of the Notes was a fraudulent transfer or conveyance, the court could void the payment obligation under the Notes, or further subordinate the Notes to presently existing and future indebtedness of ours or Puget Equico. In the event of a finding that a fraudulent conveyance occurred, you may not receive any repayment on the Notes.

Further, the voidance of the Notes could result in an event of default with respect to our and our subsidiaries’ other debt that could result in acceleration of such debt.

An active trading market for the Notes may not develop.

There is currently no public market for the Notes and we do not currently plan to list the Notes on any national securities exchange or seek their quotation on any automated dealer quotation system. In addition, the liquidity of any trading market in the Notes, and the market price quoted for the Notes, may be adversely affected by changes in the overall market for such securities and by changes in our financial performance or prospects. A liquid trading market in the Notes may not develop.

 

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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 prospectus. 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 prospectus. 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 prospectus. 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 prospectus 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.

Within this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section, Puget Energy and PSE are collectively referred to as the “Company.”

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 (collectively, the “Consortium”).

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 this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this prospectus.

 

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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 2025, 2024 and 2023:

 

    2025     2024     2023  
(Dollars in Thousands)   Earnings     Average
Common
Equity
    Return on
Equity
    Earnings     Average
Common
Equity
    Return on
Equity
    Earnings     Average
Common
Equity
    Return on
Equity
 

Return on equity

  $ 458,715     $ 5,884,719       7.8 %    $ 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

    —        (20,508 )      *       —        16,460       *       —        70,908       *  

Plus: Impact of average of monthly average (AMA)

    —        66,012       *       —        106,805       *       —        (77,648 )      *  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Return on AMA equity

  $ 458,715     $ 5,930,223       7.7 %    $ 319,358     $ 5,430,603       5.9 %    $ 355,810     $ 4,954,196       7.2 % 
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Authorized regulated return on equity2

        9.8 %          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 2024 and 2022 GRC is 9.8% and 9.4%, respectively, for natural gas and electric effective January 29, 2025 for the 2024 GRC and effective January 1, 2023 for the 2022 GRC.

*

Not meaningful and/or applicable.

 

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The following chart displays the Company’s return on AMA equity compared to its authorized regulated ROE for the year ended December 31, 2025:

 

LOGO

The Company’s 2025 return on AMA equity was 7.7%, which is lower than the 9.8% authorized regulated ROE primarily due to the following:

 

  •  

Advanced Metering Infrastructure (“AMI”) / LNG deferred return recovery resulted in an increase of $17.6 million, or 0.3% to ROE.

 

  •  

Power cost recovery was lower in 2025 than the amount allowed in rates, which was primarily driven by consistently lower power prices throughout the year combined with low hydroelectric supply, which reduced the margin from wholesale sales of surplus power relative to the amount included in rates. Higher power costs resulted in a reduction of $44.0 million, or 0.7% to ROE.

 

  •  

Capital related items contributed to lower than authorized return of $32.7 million, or 0.6% to ROE, due to $36.7 million of lower allowance for funds used during construction (“AFUDC”) resulting primarily from large capital projects placed into service earlier than anticipated, partially offset by lower depreciation and amortization expense of $4.0 million due to delayed plant additions.

 

  •  

Colstrip closure disallowances and refunds as ordered by the Washington Commission specific to disallowed Colstrip capital projects deemed life-extending as well as major maintenance costs that are not recoverable after divestiture of the plant on January 1, 2026, resulting in a reduction of $21.5 million, or 0.4% to ROE.

 

  •  

Below the line expenses which are not recoverable in rates resulted in a reduction of $22.5 million, or 0.4% to ROE.

 

  •  

Other expenses including $8.5 million of regulatory deferred interest expense and $6.4 million of other costs, which in total resulted in a reduction of $14.9 million, or 0.3% to ROE.

 

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

 

LOGO

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 construction work in progress (“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.

 

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Factors and Trends Affecting PSE’s Performance

PSE’s ongoing regulatory requirements and operational needs necessitate the investment of substantial capital in 2026 and will continue to do so in future years. Because PSE intends to seek recovery of such investments through the regulatory process, its financial results depend heavily upon favorable outcomes from that process. The principal business, economic and other factors that affect PSE’s operations and financial performance include:

 

  •  

The rates PSE is allowed to charge for its services;

 

  •  

PSE’s ability to recover power costs that are subject to the Company’s power cost adjustment mechanism that are included in rates, which are based on volume;

 

  •  

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

 

  •  

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

 

  •  

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

 

  •  

PSE’s ability to supply electricity and natural gas, 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;

 

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  •  

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; changes in legislation, regulation and government policies including federal grant programs, trade restrictions and tariffs, and government permitting, authorizations or determinations and government staff reductions may increase the Company’s costs, delay projects, interrupt service, 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 executive orders, administrative orders, tariffs and trade restrictions and budget and efficiency measures, including any actual or potential reduction in the federal workforce, 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 2026 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.

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.

Investor Owned Utilities (“IOUs”) are required to file a forward looking MYRP for two, three, or four years as part of a GRC filed with the Washington Commission. For the initial rate year, the Washington Commission is required 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. While utilities are required to file a MYRP (at least two years in length), the Washington Commission is not required to approve them. To the extent the Washington Commission approves a MYRP, utilities are bound to the first and second year of the MYRP but may file for a new rate plan in years three or four. If a company earns greater than a half percent above its authorized rate of return on a regulated basis, revenues above that level must be deferred for refunds to customers or another determination by the Washington Commission in a subsequent adjudicative proceeding. The Washington Commission must also set performance measurements to assess a natural gas or electric company operating under a MYRP.

General Rate Case Filing

PSE filed a GRC, which included a two year MYRP, with the Washington Commission on February 15, 2024. 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

 

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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.

On February 27, 2026, PSE filed a GRC with the Washington Commission in Docket No. UE-260005 and Docket No. UG-260006. The filing included a three-year MYRP requesting an overall increase in electric and natural gas rates of 15.2% and 14.2% respectively in rate year one (expected to approximate calendar year 2027), 3.7% and 3.2%, respectively in rate year two (expected to approximate calendar year 2028) and 8.7% and 3.6% in rate year three (expected to approximate calendar year 2029). PSE requested a return on equity of 10.8% for all three rate years beginning in 2027 and requested an overall rate of return of 8.1% in rate year one and 8.2% in both rate years two and three.

For additional information, see Note 7, “Regulation and Rates” to the unaudited consolidated interim financial statements included in this prospectus.

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.”

Electric Rates:

 

Electric

 

Schedule

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

Bill discount rate rider

  129D      250880     January 1, 2026     1.2 %    $ 43.5  
     240874     January 1, 2025     0.1       3.5  

Clean energy implementation

  141CEI      240004     January 29, 20251     (0.8 )      (23.6 ) 

Colstrip adjustment rider

  141COL      250733     January 1, 2026     (2.3 )      (82.5 ) 
     240729     January 1, 2025     0.1       4.1  
     230808     January 1, 2024     0.03       0.9  

Conservation service rider

  120      260128     May 1, 2026     0.9       35.3  
     250123     May 1, 2025     1.2       37.7  
     240138     May 1, 2024     0.7       20.7  

Electric CCA

  111      250901     January 1, 2026     (7.2 )      (259.0 ) 
  111 Supp      250321     August 1, 20252     1.9       86.2  

Energy charge credit recovery

  141A      250930     January 1, 2026     0.2       5.8  
     240934     January 1, 2025     0.04       1.2  
     230825     January 1, 2024     (0.1 )      (2.0 ) 

Low income program

  129      250648     October 1, 2025     (0.6 )      (21.7 ) 
     250200     May 1, 2025     3.0       34.8  
     240645     October 1, 2024     (1.1 )      (33.3 ) 
     240194     May 1, 2024     2.7       29.2  

PCA/Power cost adjustment clause - Schedule 95

  95 Supp      250318     January 1, 2026     (1.7 )      (62.3 ) 
  October 1, 20253     2.2       78.5  
  95      250747     January 1, 2026     20.8       748.4  
     240004     January 29, 20251     (5.7 )      (161.6 ) 
  Supplemental      240288     October 1, 20244     0.1       3.8  
  2024 variable power cost update      230805     January 1, 2024     6.1       160.9  

Property tax tracker

  140      260218     May 1, 2026     (0.03 )      (1.4 ) 
     250207     May 1, 2025     0.3       10.3  
     240200     May 1, 2024     (0.7 )      (18.7 ) 

 

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Electric

 

Schedule

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

Rates not subject to refund

  141N      240004     January 29, 20251     (5.6)       (160.9)  
     230320     January 1, 2024     (3.1)       (76.2)  

Rates subject to refund

  141R      240004     January 29, 20251     (5.4)       (152.8)  
     230320     January 1, 2024     4.2       105.6  

Residential and exchange benefit

  194      250664     October 1, 2025     0.5       10.6  

Revenue decoupling adjustment mechanism

  142      260213     May 1, 2026     0.7       29.0  
     250203     May 1, 2025     (0.2 )      (5.5 ) 
     240221     May 1, 2024     (0.3 )      (9.5 ) 

Transportation electrification plan

  141TEP      260206     May 1, 2026     (0.04 )      (1.5 ) 
     250197     May 1, 2025     0.1       4.6  
     240067     March 1, 2024     —        1.2  

Wildfire prevention tracker

  141WFP      240004     January 29, 20251     0.8       22.1  

Federal incentive credit tracker

  95A      260224     May 1, 20265     (1.1)       (35.0)  
 
1.

Approved in the 2024 GRC Final Order in Docket No. UE-240004 as part of base rates effective January 29, 2025.

2.

Represents a rate increase from August 1, 2025 through December 31, 2026.

3.

Rate effective October 1, 2025 ran concurrent with PCA rate through December 31, 2025. New rate will be effective January 1, 2026 through December 31, 2026. These rate impacts are presented annualized based on a 12-month forecast.

4.

The Schedule 95 Supplemental PCA mechanism rates recover 2023 PCA imbalance credit of $22.2 million and a provisional 2024 surcharge of $98.2 million through December 31, 2025.

5.

Rate is proposed for May 1, 2026 to January 31, 2027, not for a full 12 months.

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      250881      January 1, 2026      1.3 %    $ 17.0  
     240875      January 1, 2025      (1.1 )      (13.1 ) 

CCA - greenhouse gas emissions cap & invest

   111      250843      January 1, 2026      5.2       66.5  
     240884      January 1, 2025      (5.4 )      (65.8 ) 
     230968      January 1, 2024      3.0       29.1  

Conservation service rider

   120      260129      May 1, 2026      1.4       18.5  
     250124      May 1, 2025      0.5       5.7  
     240139      May 1, 2024      0.7       6.8  

Distribution pipeline provisional recovery

   141D      230393      May 11, 2024      (0.02 )      (0.2 ) 
     220067      January 1, 2024      (0.01 )      (0.1 ) 

Liquefied natural gas

   141LNG      250744      November 1, 2025      1.4       19.2  
     230393      May 11, 2024      3.1       42.7  

Low income program

   129      250649      October 1, 2025      (1.0 )      (13.1 ) 
     250201      May 1, 2025      3.1       7.8  
     240646      October 1, 2024      (4.5 )      (53.1 ) 
     240195      May 1, 2024      4.6       10.2  

 

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Natural gas

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

Property tax tracker

   140      260219      May 1, 2026     0.1       1.5  
     250208      May 1, 2025     0.4       4.7  
     240201      May 1, 2024     (0.5 )      (5.6 ) 

Purchased gas adjustment

   101, 106      250704      November 1, 2025     (4.1 )      (55.1 ) 
     240708      November 1, 2024     10.6       124.4  

Rates not subject to refund

   141N      240005      January 29, 20251     0.3       3.0  
     230393      May 11, 2024     0.1       1.1  
     230889      January 1, 2024     (2.3 )      (27.6 ) 

Rates subject to refund

   141R      240005      January 29, 20251     (5.8 )      (59.5 ) 
     230889      January 1, 2024     4.0       47.2  

Revenue decoupling adjustment mechanism

   142      260214      May 1, 2026     (1.7 )      (23.8 ) 
     250204      May 1, 2025     0.9       12.0  
     240222      May 1, 2024     2.7       28.0  
 
1.

Approved in the 2024 GRC Final Order in Docket No. UE-240004 as part of base rates effective January 29, 2025.

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 or 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this prospectus.

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 or other regulated 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.

 

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The Washington Department of Ecology (“WDOE”) published final regulations to implement the program on September 29, 2022, which became effective on October 30, 2022. The WDOE also indicated that it will have subsequent rulemakings building off initial rulemaking while program implementation is underway. While the Washington Commission has approved the recovery of electric and natural gas CCA-related costs, which led to increased 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. 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 rates.

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 and municipalities or efforts by citizens organizing to form such entities that want to establish their own government-owned utility, as a result of which PSE may lose a number of customers. PSE’s natural gas customers may also elect to use heating oil, propane or other fuels instead of purchasing and using 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 and/or acquired generation resources to meet their growing energy needs. This capacity will largely be used to fulfill commitments for additional cloud computing, artificial intelligence data centers, reduced 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.

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.

 

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

 

Puget Sound Energy

    
(Dollars in Thousands)    Three Months Ended March 31     Year Ended December 31  
     2026     2025     2025     2024     2023  

Operating income (loss)

   $ 340,532     $ 261,354     $ 754,383     $ 602,120     $ 335,452  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Electric utility revenue

   $ 1,260,579     $ 1,026,948     $ 3,891,177     $ 3,332,695     $ 3,345,867  

Purchased electricity

     (555,515 )      (381,528 )      (1,383,812 )      (1,196,897 )      (1,110,572 ) 

Electric generation fuel

     (24,640 )      (91,624 )      (332,691 )      (336,725 )      (457,287 ) 

Residential exchange

     22,713       27,234       82,213       85,175       77,223  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Utility electric margin (non-GAAP)

   $ 703,137     $ 581,030     $ 2,256,887     $ 1,884,248     $ 1,855,231  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Natural gas operating revenue

   $ 579,821     $ 565,973     $ 1,462,357     $ 1,492,254     $ 1,424,368  

Purchased natural gas

     (231,987 )      (246,515 )      (555,672 )      (679,433 )      (641,371 ) 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Utility natural gas margin (non-GAAP)

   $ 347,834     $ 319,458     $ 906,685     $ 812,821     $ 782,997  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Other revenue

   $ 118     $ 99     $ 24,634     $ 282     $ 16,383  

Unrealized gain (loss) on derivative instruments, net

     —        —        —        33,911       (284,495 ) 

Other operation and maintenance expenses

     (274,821 )      (232,385 )      (922,224 )      (785,088 )      (735,278 ) 

Non-utility expense and other

     (5,626 )      (8,775 )      (40,522 )      (21,664 )      (28,658 ) 

Depreciation and amortization

     (267,833 )      (256,573 )      (1,016,188 )      (918,472 )      (865,969 ) 

Taxes other than income tax expense

     (162,277 )      (141,500 )      (454,889 )      (403,918 )      (404,759 ) 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

   $ 340,532     $ 261,354     $ 754,383     $ 602,120     $ 335,452  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Results of Operations For the Three Months Ended March 31, 2026 and March 31, 2025

Puget Sound Energy

The following discussion should be read in conjunction with the unaudited consolidated interim financial statements and the related notes included elsewhere in this prospectus. The following discussion provides significant items that impacted PSE’s results of operations for the three months ended March 31, 2026 and March 31, 2025.

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.

 

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The following charts display the details of PSE’s electric margin changes for the three months ended March 31, 2026 and 2025:

 

LOGO

 

 
*

Includes decoupling cash collections, ROR excess earnings, and decoupling 24-month revenue reserve.

Three Months Ended March 31, 2026 compared to 2025

Electric Operating Revenue

Electric operating revenues increased $233.6 million from the prior year primarily due to changes in the following key drivers: electric retail sales, sales to other utilities, decoupling revenue and transportation and other revenue. These items are discussed in detail below.

 

  •  

Electric retail sales increased $219.3 million primarily from rate increases resulting in an additional $265.5 million in sales compared to the prior year, partially offset by a decrease in retail electricity usage of 4.7% or $46.2 million. The increase in rates is primarily due to the power cost tariff filing effective January 1, 2026; this rate increase was partially offset by lower Schedule 111 rates due to the pass-back of CCA no-cost allowance values. See “Regulation of PSE Rates and Recovery of PSE Costs” included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this prospectus. The decrease in retail usage was primarily due to a decrease in residential, commercial and industrial usage of 5.4%, 3.3% and 3.9%, respectively, due to a decrease in heating degree days of 10.0% in 2026 as compared to 2025.

 

  •  

Sales to other utilities decreased $43.2 million primarily due to a 20.7% decrease in wholesale sales volume driven by a 52.8% decrease in the average price of electric wholesale sales. Decreased wholesale sales volume was related to decreased supply, resulting from lower volumes of economic generation from PSE’s energy supply assets in 2026 compared to 2025 which was influenced by lower

 

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wholesale power prices and Washington carbon prices that were 34.3% higher in 2026 as compared to 2025. Lower wholesale power prices were largely the result of higher regional energy supply driven by higher Mid-Columbia hydro production.

 

  •  

Decoupling revenue increased $9.1 million which was attributable to $4.8 million and $4.3 million increases in delivery and fixed production cost deferral revenues, respectively. The increased revenue was driven primarily by decreased usage in the three months ended March 31, 2026 compared to the same period in 2025. This resulted in actual decoupling revenues being higher than allowed revenues by a less significant margin in 2026 as compared to 2025.

 

  •  

Transportation and other revenue increased $47.5 million primarily due to the start of a regulatory offset of CCA electric no-cost values of $71.4 million, which were passed back to customers as credits on billed revenue and included within electric retail revenues above, and an increase in transmission revenue of $3.3 million. The increases were partially offset by a decrease of non-core gas sales of $24.7 million driven by an increase in natural gas financial hedging costs plus average costs of non-core gas sold in 2026 that were higher than average non-core gas sales in the same period in 2025, and a decrease of $4.1 million related to deferrals under Schedule 129D. See “Regulation of PSE Rates and Recovery of PSE Costs” included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this prospectus.

Electric Power Costs

Electric power costs increased $111.5 million primarily due to changes in the following key drivers: purchased electricity, electric generation fuel and residential exchange credits. These items are discussed in detail below:

 

  •  

Purchased electricity increased $174.0 million primarily due to a 34.0% increase in wholesale electricity volumes and capacity purchases in 2026 compared to 2025, driven by lower-cost open market purchases as market conditions became more favorable relative to firm contract pricing and internal generation dispatch from PSE energy supply assets.

 

  •  

Electric generation fuel decreased $67.0 million primarily driven by a $52.2 million decrease in natural gas fuel costs resulting from lower natural gas prices and a 95.1% decrease in gas-fired combustion turbine (CT) generation. The decrease in gas-fired CT generation was driven by reduced economic dispatch of PSE’s gas-fired energy supply assets in 2026 compared to 2025, influenced by lower wholesale power prices and Washington carbon prices that were 34.3% higher as discussed above. Additionally, Colstrip fuel expense decreased $15.6 million due to the transfer of PSE’s interest in Colstrip Units 3 and 4 to NorthWestern Energy on January 1, 2026, and thus Colstrip no longer served PSE customers in the three months ended March 31, 2026 compared to the same period in 2025.

 

  •  

Residential exchange credits decreased by $4.5 million due to a 0.5% change in the amount of credits to be passed back to customers effective October 1, 2025 and a decrease in residential usage of 5.4%; see “Regulation of PSE Rates and Recovery of PSE Costs” included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this prospectus.

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 to or collected from customers in future periods.

 

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The following charts display the details of PSE’s natural gas margin changes for the three months ended March 31, 2026 and 2025:

 

LOGO

 
*

Includes decoupling cash collections, ROR excess earnings, and decoupling 24-month revenue reserve.

Three Months Ended March 31, 2026 compared to 2025

Natural Gas Operating Revenue

Natural gas operating revenue increased $13.8 million primarily due to changes in the following key drivers: retail sales, decoupling revenue, and transportation and other revenue. These items are discussed in detail below.

 

  •  

Natural gas retail sales revenue increased $0.9 million primarily due to an increase in rates of $56.9 million partially offset by a decrease in natural gas load of 10.4%, or $56.0 million. The increase in rates is primarily driven by Schedule 111 that includes a charge for CCA natural gas allowance costs and a pass back of CCA auction proceeds, Schedule 129D Bill discount rate rider, Schedule 129 Low income program, Schedule 120 Conservation service rider, Schedule 140 Property tax tracker and a marginal increase in base rates from the 2024 GRC. See “Regulation of PSE Rates and Recovery of PSE Costs” included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this prospectus for natural gas rate changes. The decrease in natural gas load was driven by a decrease in heating degree days of 10.0% in the three months ended March 31, 2026 as compared to 2025.

 

  •  

Decoupling revenue increased $10.9 million primarily due to decreased natural gas usage, as mentioned above. This resulted in actual decoupling revenues being higher than the allowed revenues by a less significant margin in 2026 as compared to 2025.

 

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  •  

Transportation and other revenue increased $5.2 million due to an increase of $9.0 million related to the regulatory offset of CCA auction proceeds, which were passed through to customers as credits on billed revenue included within natural gas retail revenues above. The increase was partially offset by a decrease of $3.9 million related to deferrals under Schedule 129D; for additional information see Management’s Discussion and Analysis, “Regulation of PSE Rates and Recovery of PSE Costs” included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this prospectus.

Natural Gas Energy Costs

 

  •  

Purchased natural gas expense decreased $14.5 million primarily due to a decrease in the PGA rates in November 2025 and a decrease in natural gas usage of 10.4%. For natural gas rate changes and details on the PGA, see “Regulation of PSE Rates and Recovery of PSE Costs” included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this prospectus. The decrease was partially offset by an increase of $25.3 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.

Other Operating Expenses and Other Income (Deductions)

The following chart displays the details of PSE’s operating expenses and other income (deductions) for the three months ended March 31, 2026 and 2025:

 

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Three Months Ended March 31, 2026 compared to 2025

 

  •  

Utility operations and maintenance expense increased $42.4 million primarily due to increases in the following: (i) $22.1 million related to customer service expense, driven by an increase in Schedule 129 Low income program in electric and natural gas rates, (ii) $9.0 million of increased amortization of bad

 

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debt deferral recovery, (iii) $4.5 million related to increased outside service expenses driven by contractor spend across multiple business units and (iv) $3.8 million in general and administrative salaries. The increases were partially offset by a $3.6 million decrease in maintenance expenses specific to steam generation, which was primarily driven by the transfer of PSE’s ownership interest in Colstrip Units 3 and 4 to NorthWestern Energy on January 1, 2026. For regulatory schedule information and rate changes, see “Regulation of PSE Rates and Recovery of PSE Costs” included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this prospectus.

 

  •  

Depreciation and amortization expense increased $11.3 million primarily due to a $9.3 million increase in conservation amortization from an increase in conservation rates effective May 1, 2025, see “Regulation of PSE Rates and Recovery of PSE Costs” included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this prospectus.

 

  •  

Taxes other than income taxes increased $20.8 million primarily due to an increase of $9.9 million and $8.9 million in municipal and state excise taxes, respectively, in 2026 compared to 2025.

Other Income, Interest Expense and Income Tax Expense

 

  •  

Interest expense increased $9.2 million primarily due to an increase of $7.0 million in interest expense due to the September 2025 PSE bond issuance and $3.5 million of AFUDC - debt.

 

  •  

Income tax expense increased $10.0 million primarily driven by an increase in pre-tax book income in 2026 as compared to 2025.

Puget Energy

Primarily, all operations of Puget Energy are conducted through PSE. Puget Energy’s net income (loss) for the three months ended March 31, 2026 and 2025 is as follows:

 

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Three Months Ended March 31, 2026 compared to 2025

Summary Results of Operation

Puget Energy’s net income increased by $55.2 million. This is primarily due to: (i) an increase in PSE’s net income of $60.4 million and (ii) increased tax benefit of $4.3 million. The increases were partially offset by an increase in interest expense of $5.0 million, which was driven by interest expense accrued for Puget Energy’s $600.0 million bond issuance in March 2025.

Results of Operations For the Years Ended December 31, 2025 and December 31, 2024

Puget Sound Energy

The following discussion should be read in conjunction with the audited consolidated financial statements and the related notes included elsewhere in this prospectus. The following discussion provides the significant items that impacted PSE’s results of operations for the years ended December 31, 2025 and December 31, 2024.

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, 2024 to December 31, 2025:

 

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*

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

 

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2024 compared to 2025

Electric Operating Revenue

Electric operating revenues increased $558.5 million from the prior year primarily due to changes in the following key drivers: electric retail sales, sales to other utilities, decoupling revenue, other decoupling revenue and transportation and other revenue. These items are discussed in detail below.

 

  •  

Electric retail sales increased $464.6 million primarily from a rate increase resulting in an additional $459.8 million in sales compared to the prior year and a slight increase in retail electricity usage of 0.2% with an impact of $4.8 million. The increase in rates is primarily due to the tariffs filed pursuant to the 2024 GRC order. See “Regulation of PSE Rates and Recovery of PSE Costs” included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this prospectus for electric rate changes. The increase in retail usage was primarily due to an increase in commercial usage of 0.9%.

 

  •  

Sales to other utilities increased $54.5 million primarily due to an increase in wholesale sales volume of 26.3%; partially offset by a 5.5% decrease in the average price of electric wholesale sales. Increased wholesale sales volume was related to increased supply, driven by additional generation resources in 2025 compared to 2024.

 

  •  

Decoupling revenue increased $28.4 million which was attributable to $17.1 million and $11.2 million increases in delivery and fixed production cost deferral revenues, respectively. This was driven primarily by higher allowed rates versus actual delivery rates in 2025 compared to 2024.

 

  •  

Other decoupling revenue increased $7.0 million due to an increase of $6.6 million in current period amortization of prior year decoupling revenues. This is attributable to an increase in amortization rates, which increases the rate at which deferral revenues are passed back to customers.

 

  •  

Transportation and other revenue increased $4.1 million primarily due to an increase in non-core gas sales of $9.6 million driven by a decrease in natural gas financial hedging costs in 2025 compared to 2024; and an increase of $9.2 million related to deferrals under Schedule 129D partially offset by decreased amortization of unspent low income program funds in Schedule 129 rates, see “Regulation of PSE Rates and Recovery of PSE Costs” included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this prospectus. These increases were partially offset by a decrease of $16.3 million related to the discontinuance of the deferred return on AMI per the 2024 GRC order.

Electric Power Costs

Electric power costs increased $185.8 million primarily due to changes in the following key drivers: purchased electricity, electric generation fuel and residential exchange. These items are discussed in detail below:

 

  •  

Purchased electricity expense increased $186.9 million primarily due to wholesale electricity volume and capacity purchases that increased by 27.4% in 2025 compared to 2024, which was partially offset by a 9.3% decrease in wholesale purchase prices in 2025 compared to 2024. The increase to volumes was also driven by carbon allowance prices, which increased in 2025 resulting from the failed voter referendum to repeal the CCA in late 2024. The carbon allowance price increase made it less economic for PSE to run its owned or controlled combustion turbine (“CT”) generation resources and thus resulted in more purchased electricity.

 

  •  

Electric generation fuel expense decreased $4.0 million primarily driven by a $65.5 million decrease in natural gas fuel costs resulting from lower natural gas prices and decreased gas-fired CT generation of 27.5%. This was partially offset by an increase in natural gas fuel costs of $58.5 million related to a tolling agreement that commenced January 1, 2025 to purchase energy and capacity associated with a 650 MW natural gas-fired electric generating facility and Colstrip fuel expense increased $2.9 million driven by an increase in coal generation of 4.8%.

 

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  •  

Residential exchange credits decreased by $3.0 million due to a 0.5% change in the amount of credits to be passed back to customers effective October 1, 2025 and a decrease in residential usage of 0.3%; see “Regulation of PSE Rates and Recovery of PSE Costs” included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this prospectus.

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, 2024 to December 31, 2025:

 

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*

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

2024 compared to 2025

Natural Gas Operating Revenue

Natural gas operating revenue decreased $29.9 million from the prior year primarily due to changes in the following key drivers: natural gas retail sales, decoupling revenue, other decoupling revenue and transportation

 

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and other revenue. These items are discussed in the following details:

 

  •  

Natural gas retail sales increased $158.0 million due to an increase in rates of $214.4 million partially offset by a decrease in natural gas load of 4.1% or $56.4 million of natural gas sales. The increase in rates is primarily due to the tariffs filed pursuant to the Company’s 2024 GRC effective January 29, 2025 and 2024 PGA filing effective November 1, 2024. This was partially offset by a decrease in rates driven by Schedule 111 that includes a charge for CCA allowance costs and a pass back of CCA auction proceeds. See “Regulation of PSE Rates and Recovery of PSE Costs” included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this prospectus for natural gas rate changes. The decrease in natural gas load was driven by a decrease in heating degree days of 2.9% in the year ended 2025 as compared to 2024.

 

  •  

Decoupling revenue decreased $26.2 million, primarily attributable to higher actual delivery rates versus allowed rates in 2025 compared to 2024.

 

  •  

Other decoupling revenue decreased $18.3 million due to an increase in current period amortization of prior year decoupling revenues compared to the same period in 2024. This is attributable to increased amortization rates, which increases the rate at which prior undercollections are collected from customers.

 

  •  

Transportation and other revenue decreased $143.4 million, primarily due to a decrease in the regulatory offset of CCA auction proceeds of $156.6 million, which were passed back to customers as credits on billed revenue and included within natural gas retail revenues above, and $8.3 million related to the equity return on AMI plant, which began amortizing over a three year period starting on January 28, 2025, per the 2024 GRC. The decreases were partially offset by an increase of $14.9 million related to the bill discount rate rider under Schedule 129D and $5.8 million related to the Company’s deferred return on its investment in the Tacoma LNG Facility.

Natural Gas Energy Costs

Purchased natural gas expense decreased $123.8 million primarily due to a decrease of $186.8 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 and a decrease in natural gas usage of 4.1% as stated in the natural gas retail sales section above. This was partially offset by an increase in the PGA rates in November 2024. For natural gas rate changes and details on the PGA, see “Regulation of PSE Rates and Recovery of PSE Costs” included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this prospectus.

 

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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, 2024 to December 31, 2025:

 

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2024 compared to 2025

Other Operating Revenues

 

  •  

Other Operating revenue increased $24.4 million primarily due to sales of land at PSE’s wholly-owned subsidiary, Puget Western Inc., in the amount of $24.1 million.

Other Operating Expenses

 

  •  

Net unrealized (gain) loss on derivative instruments changed $33.9 million due to the Washington Commission’s approval of 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 further details, see Note 4, “Regulation and Rates” and Note 10, “Accounting for Derivative Instruments and Hedging Activities” to the audited consolidated financial statements included in this prospectus.

 

  •  

Utility Operations and Maintenance expense increased $137.1 million primarily due to increases in the following: (i) $64.7 million related to customer service expense, driven by an increase in Schedule 129 - low income program in electric and natural gas rates, (ii) $17.7 million related to maintenance distribution overhead lines of which $12.0 million is driven by an increased scope in vegetation management, (iii) $11.7 million of customer service expenses driven by increases to call center, training and other customer records and collection expenses, (iv) $11.3 million related to insurance

 

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expense driven by wildfire insurance in Schedule 141WFP, (v) other regulatory tracker items of $11.2 million and (vi) increase of contracted maintenance and rent payments for wind generation of $10.3 million. For regulatory schedule information and rate changes, see “Regulation of PSE Rates and Recovery of PSE Costs” included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this prospectus.

 

  •  

Non-utility and other expenses increased $19.1 million primarily due to $16.2 million of costs associated with sales of land at PSE’s wholly-owned subsidiary, Puget Western Inc. and an increase in the long-term incentive plan of $4.9 million in 2025 as compared to 2024.

 

  •  

Depreciation and amortization expense increased $97.7 million due to increases in the following: (i) $34.5 million in conservation amortization due to increases in conservation rates effective May 1, 2025, see “Regulation of PSE Rates and Recovery of PSE Costs” included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this prospectus, (ii) $28.9 million in electric production depreciation primarily driven by net additions to the Upper Baker Dam and waterway and the addition of the Beaver Creek wind facility, (iii) $24.8 million in electric transmission and distribution plant primarily driven by net additions of transmission poles, substation equipment and underground conduit and conductors, and (iv) $6.7 million in natural gas distribution primarily driven by net additions of plastic mains assets.

 

  •  

Taxes other than income taxes increased $51.0 million primarily due to an increase of $28.2 million and $25.4 million in state excise taxes and municipal taxes, respectively.

Other Income, Interest Expense and Income Tax Expense

 

  •  

Other income/expense increased $11.8 million from net other income of $80.5 million in 2024 to net other income of $92.3 million in 2025, due to an increase of $29.4 million in other income that was partially offset by an increase of $17.6 million in other expense. The change in other income was primarily due to increases in the following: (i) AMI interest income of $24.6 million due to the start of amortization of the equity reserve in 2025, (ii) LNG interest income of $9.0 million and, (iii) Washington Commission AFUDC of $2.8 million; partially offset by taxable interest and dividend income of $8.4 million, which decreased due to less invested funds in 2025 compared to 2024. The increase in other expense was driven by an increase of $12.5 million related to Colstrip major maintenance.

 

  •  

Interest expense increased $25.8 million primarily due to an increase of $27.6 million in interest expense due to the June 2024 and September 2025 PSE bond issuances.

 

  •  

Income tax expense increased $25.6 million primarily driven by an increase in pre-tax book income in 2025 as compared to 2024.

 

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Puget Energy

Substantially all the operations of Puget Energy are conducted through its regulated subsidiary, PSE. Puget Energy’s results of operation for the years ended December 31, 2024 and December 31, 2025, were as follows:

 

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2024 compared to 2025

Summary Results of Operations

Puget Energy’s net income increased by $104.1 million, which is primarily attributable to: (i) an increase in PSE’s net income of $112.6 million, (ii) an increase in other operating revenue and income of $5.0 million driven by short-term interest earned from re-investing proceeds of Puget Energy’s $600.0 million bond issued in March 2025 and (iii) an increase of tax benefit of $2.1 million. These increases were partially offset by an increase of $14.6 million in interest expense, primarily driven by Puget Energy’s $600.0 million bond issuance in March 2025.

Results of Operations For the Years Ended December 31, 2024 and December 31, 2023

Puget Sound Energy

The following discussion should be read in conjunction with the audited consolidated financial statements and the related notes included elsewhere in this document. The following discussion provides the significant items that impacted PSE’s results of operations for the years ended December 31, 2024 and December 31, 2023.

 

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Electric Margin

The following chart displays the changes in PSE’s electric margin for the years ended December 31, 2023 to December 31, 2024:

 

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*

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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this prospectus.

 

  •  

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.

 

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  •  

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 this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this prospectus.

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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this prospectus.

 

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Natural Gas Margin

The following chart displays the changes in PSE’s natural gas margin for the years ended December 31, 2023 to December 31, 2024:

 

LOGO

 
*

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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this prospectus 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.

 

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  •  

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” to the audited consolidated financial statements included in this prospectus 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:

 

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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” to the audited consolidated financial statements included in this prospectus.

 

  •  

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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this prospectus, (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” to the audited consolidated financial statements included in this prospectus.

 

  •  

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.

 

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  •  

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.

Puget Energy

Substantially all the operations of Puget Energy are conducted through its regulated subsidiary, PSE. Puget Energy’s results of operation for the years ended December 31, 2023 and December 31, 2024, were as follows:

 

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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 Puget LNG’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.

 

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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, 2025:

 

     Payments Due Per Period  
(Dollars in Thousands)    Total      2026      2027-2028      2029-2030      Thereafter  

Contractual obligations:

              

Energy purchase obligations1

   $ 15,001,849      $ 1,954,541      $ 2,691,581      $ 1,846,205      $ 8,509,522  

Long-term debt including interest2

     12,222,944        332,341        941,867        709,885        10,238,851  

Short-term debt including interest

     60,000        60,000        —         —         —   

Service contract obligations

     243,940        38,372        81,136        86,064        38,368  

Non-cancelable operating leases3

     600,758        117,569        160,033        74,947        248,209  

PSE finance leases3

     256,775        12,683        25,470        25,841        192,781  

Pension and other benefits funding

     46,198        22,231        8,991        5,217        9,759  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total PSE contractual cash obligations

   $ 28,432,464      $ 2,537,737      $ 3,909,078      $ 2,748,159      $ 19,237,490  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Long-term debt including interest2

   $ 2,782,371      $ 91,903      $ 677,363      $ 795,581      $ 1,217,524  

Short-term debt including interest

     448,287        448,287        —         —         —   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Puget Energy contractual cash obligations

   $ 31,663,122      $ 3,077,927      $ 4,586,441      $ 3,543,740      $ 20,455,014  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
 
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 audited consolidated financial statements included in this prospectus. 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 audited consolidated financial statements included in this prospectus.

During the three months ended March 31, 2026, the Company entered into new Electric Portfolio and Electric Wholesale Market Transaction contracts with estimated payment obligations totaling $94.2 million through 2027.

For additional information regarding PSE’s and Puget Energy’s commercial commitments see Note 8, “Liquidity Facilities and Other Financing Arrangements” and Note 15, “Commitments and Contingencies” to the audited consolidated financial statements and Note 8, “Commitments and Contingencies” to the unaudited consolidated interim financial statements, each included in this prospectus.

Off-Balance Sheet Arrangements

As of March 31, 2026, the Company had no off-balance sheet arrangements that have had 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 10, “Other” to the unaudited consolidated interim financial statements included in this prospectus.

Utility Construction Program

The Company’s construction programs for generating facilities, the electric transmission system, the natural gas and electric distribution systems and the Tacoma LNG facility are designed to meet regulatory requirements, support customer growth and improve energy system reliability. Construction expenditures, excluding equity AFUDC, totaled $412.2 million for the three months ended March 31, 2026.

 

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

 

Capital Expenditure Projections       
(Dollars in Millions)    2026      2027      2028      2029      2030  

Total energy delivery, technology and facilities expenditures

   $ 2,079.0      $ 2,812.0      $ 3,182.0      $ 3,308.0      $ 3,112.0  

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

Three Months Ended March 31, 2026, compared to 2025

 

Puget Sound Energy    Three Months Ended
March 31,
 
(Dollars in Thousands)    2026     2025     Change  

Net income

   $ 246,438     $ 186,014     $ 60,424  

Non-cash items1

     285,419       254,317       31,102  

Changes in cash flow resulting from working capital2

     (119,286 )      (82,600 )      (36,686 ) 

Regulatory assets and liabilities

     59,066       31,154       27,912  

Purchased gas adjustment

     (10,061 )      22,871       (32,932 ) 

GHG emission allowances

     (16,797 )      —        (16,797 ) 

Other non-current assets and liabilities3

     (12,416 )      (4,060 )      (8,356 ) 
  

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

   $ 432,363     $ 407,696     $ 24,667  
  

 

 

   

 

 

   

 

 

 
 
1.

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

2.

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

3.

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

Cash generated from operations for the three months ended March 31, 2026 increased by $24.7 million, which includes a net income increase of $60.4 million. The following are significant factors that impacted PSE’s cash flows from operations:

 

  •  

Cash flows resulting from non-cash items increased $31.1 million primarily due to: (i) a $10.2 million increase due to lower usage of CCA no cost emission allowances compared to values passed back in Schedule 111 for electric, (ii) an increase of $9.3 million in conservation amortization, (iii) a change in equity AFUDC of $6.1 million, (iv) an increase of $5.6 million related to amortization of deferred return on PSE’s share of the Tacoma LNG investment, (v) an increase in deferred taxes of $4.9 million and (vi) an increase in depreciation and amortization of $2.0 million. The increases were partially offset by: (i) a decrease of $5.5 million related to the deferral of energy exchange costs and (ii) $2.4 million of ITC amortization.

 

  •  

Cash flows resulting from changes in working capital decreased $36.7 million primarily due to: (i) an increase in cash outflow of $26.0 million due to the timing of accounts receivable and unbilled revenue collections, as the balance of accounts receivable and unbilled revenue increased $81.2 million in 2026 compared to an increase of $55.2 million in 2025, (ii) accounts payable decreased faster in

 

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2026 compared to 2025, which led to increased cash outflow of $15.7 million, (iii) higher incentive payment and timing of accrued salaries and wages led to an increased cash outflow of $8.1 million, (iv) change in natural gas and fuel inventory led to decreased cash inflow of $7.8 million, (v) timing of payments and accrued interest led to a $7.0 million cash outflow and (vi) increased cash outflow of $5.0 million due to higher inventory of plant material and supplies. The decreases were partially offset by: (i) cash inflow of $24.1 million due to the change in taxes payable, (ii) cash inflow of $3.7 million due to the change in prepayment of insurance and employee benefits and (iii) cash inflow of $2.4 million due to the change in prepayment of purchased electricity.

 

  •  

Cash flows resulting from regulatory assets and liabilities increased $27.9 million primarily due to the recovery of prior year PCA imbalances totaling $42.0 million. The increase was partially offset by $18.1 million cash outflow related to revenue decoupling mechanism, which had cash inflows of $34.2 million in 2026 compared to $52.3 million in 2025.

 

  •  

Cash flows resulting from purchased gas adjustment decreased $32.9 million, primarily due to a $39.5 million decrease in allowed PGA recovery in 2026 compared to 2025 which was partially offset by a $6.6 million decrease in actual natural gas cost.

 

  •  

Cash flow resulting from GHG emission allowances decreased $16.8 million due to purchases made to obtain the Washington emission allowances for GHG emissions associated with the Company’s electric and natural gas business activities in compliance with the CCA.

 

  •  

Other non-current assets and liabilities decreased $8.4 million, which is primarily due to $13.2 million increased cash outflow driven by higher long-term incentive payments in 2026 compared to 2025 and partially offset by $3.2 million cash inflow due to an increase in network upgrade refund liability.

 

Puget Energy    Three Months Ended
March 31,
 
(Dollars in Thousands)    2026     2025     Change  

Net income

   $ (23,606 )    $ (18,458 )    $ (5,148 ) 

Non-cash items1

     (194 )      2,716       (2,910 ) 

Changes in cash flow resulting from working capital2

     (9,695 )      6,063       (15,758 ) 

Other non-current assets and liabilities3

     (616 )      (995 )      379  
  

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

   $ (34,111 )    $ (10,674 )    $ (23,437 ) 
  

 

 

   

 

 

   

 

 

 
 
1.

Non-cash items include depreciation, amortization, deferred income taxes, net unrealized (gain) loss on derivative instruments, AFUDC-equity 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 noncurrent assets and liabilities include funding of pension liability.

Cash generated from operations for the three months ended March 31, 2026, in addition to the changes discussed at PSE above, decreased by $23.4 million compared to the same period in 2025, which includes a net income decrease of $5.1 million.

 

  •  

Changes in cash flow resulting from non-cash items decreased $2.9 million primarily due to a $2.9 million change in deferred taxes.

 

  •  

Changes in cash flow resulting from working capital decreased $15.8 million, largely driven by a $17.2 million interest payment in March 2026. This outflow was partially offset by a $3.3 million cash inflow from changes in interest accruals.

 

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Year Ended December 31, 2025, compared to 2024

 

Puget Sound Energy    Year Ended December 31,  
(Dollars in Thousands)    2025     2024     Change  

Net income

   $ 458,715     $ 346,148     $ 112,567  

Non-cash items1

     993,288       826,834       166,454  

Changes in cash flow resulting from working capital2

     27,870       43,156       (15,286 ) 

Proceeds from sale of transferable tax credits

     91,455       —        91,455  

Regulatory assets and liabilities

     (84,279 )      (89,838 )      5,559  

Purchased gas adjustment

     7,273       (73,426 )      80,699  

GHG emission allowances

     (333,169 )      (154,728 )      (178,441 ) 

Other non-current assets and liabilities3

     (27,719 )      (19,058 )      (8,661 ) 
  

 

 

   

 

 

   

 

 

 

Net cash (used in)/provided by operating activities

   $ 1,133,434     $ 879,088     $ 254,346  
  

 

 

   

 

 

   

 

 

 
 
1.

Non-cash items include depreciation, amortization, deferred income taxes, net unrealized (gain) loss on derivative instruments, AFUDC-equity 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.

Cash generated from operations increased by $254.3 million including an increase in net income of $112.6 million. The following are significant factors that impacted PSE’s cash flows from operations:

 

  •  

Cash flow adjustments resulting from non-cash items increased $166.5 million, primarily due to: (i) an increase in depreciation and amortization of $63.3 million, (ii) increased conservation amortization of $34.5 million, (iii) a $33.9 million change in net unrealized gain on derivative instruments due to the deferral of unrealized gain or loss on derivative instruments, consistent with the approved accounting petition in Docket No. UE-240773, (iv) an increase in deferred taxes of $27.4 million and (v) an increase of $11.8 million related to the amortization of regulatory filing fees. The increases were partially offset by a decrease in equity AFUDC of $3.1 million.

 

  •  

Cash flows resulting from changes in working capital decreased $15.3 million primarily due to: (i) a $19.4 million increase of cash outflow driven by changes in timing of prepayments in 2025 compared to 2024, (ii) an increase in cash outflow of $8.2 million due to the change in accounts receivable in 2025 compared to 2024, (iii) a $6.2 million decrease in cash inflows due to the change in accounts payable in 2025 compared to 2024, and (iv) an increase in cash outflow of $2.7 million driven by increased materials and supplies. The decreases were partially offset by: (i) higher taxes payable resulting in increased cash inflow of $17.5 million and (ii) lower fuel and natural gas inventory, which led to increased cash inflow of $5.3 million.

 

  •  

Cash flows resulting from proceeds from sale of transferable tax credits was $91.5 million in 2025, which related to a partial sale of ITCs generated from the Beaver Creek Wind Project that commenced commercial operations in August 2025.

 

  •  

Cash flows resulting from regulatory assets and liabilities increased $5.6 million primarily due to: (i) $18.9 million cash inflow related to lower storm damage costs, (ii) $18.5 million cash inflow related to PSE’s pilot decarbonization program from the 2022 GRC, (iii) $18.7 million cash inflow driven by incremental deferrals of bad debt expense related to COVID-19, which increased less in 2025 compared to the increase in 2024, (iv) $10.0 million cash inflow related to revenue decoupling mechanism, which had cash outflows of $7.2 million in 2025 compared to $17.2 million in 2024 and (v) $8.9 million cash inflow related to deferral of wildfire insurance expenses in 2025 compared to 2024. The increases were partially offset by $69.7 million increased cash outflow related to power cost adjustment receivable, which was driven by actual power costs continuing to be higher than baseline rates in 2025 compared to 2024.

 

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  •  

Cash flow resulting from purchased gas adjustment increased $80.7 million, which was primarily driven by a $62.1 million increase in allowed PGA recovery in 2025 compared to 2024 and an $18.6 million decrease in actual natural gas cost.

 

  •  

Cash flows resulting from changes in GHG emission allowances decreased $178.4 million due to purchases made to obtain the Washington emission allowances for GHG emissions associated with PSE’s electric and natural gas business activities in compliance with the CCA.

 

  •  

Cash flow resulting from other non-current assets and liabilities decreased $8.7 million primarily due to increased cash outflow of $8.5 million related to more long-term prepayments for hardware, software, applications and other outside services in 2025 compared to 2024.

 

Puget Energy    Year Ended December 31,  
(Dollars in Thousands)    2025     2024     Change  

Net income

   $ (89,347 )    $ (80,893 )    $ (8,454 ) 

Non-cash items1

     12,401       26,651       (14,250 ) 

Changes in cash flow resulting from working capital2

     9,023       593       8,430  

Other non-current assets and liabilities3

     (4,408 )      (2,616 )      (1,792 ) 
  

 

 

   

 

 

   

 

 

 

Net cash (used in)/provided by operating activities

   $ (72,331 )    $ (56,265 )    $ (16,066 ) 
  

 

 

   

 

 

   

 

 

 
 
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.

Cash generated from operations for the year ended December 31, 2025, in addition to the changes discussed at PSE above, decreased by $16.1 million compared to the same period in 2024, which includes a net income decrease of $8.5 million. The remaining change was primarily impacted by the factors explained below:

 

  •  

Changes in cash flow resulting from non-cash items decreased $14.3 million primarily due to higher non-cash inflows of $16.0 million related to changes in deferred taxes.

 

  •  

Changes in cash flow resulting from working capital increased $8.4 million mainly driven by a $7.7 million increase in accrued interest of senior secured notes. On March 13, 2025, Puget Energy issued $600.0 million of senior secured notes at an interest rate of 5.725%. On May 15, 2025, Puget Energy repaid at maturity the $400.0 million 3.65% senior secured notes due May 2025.

Year Ended December 31, 2024, compared to 2023

 

Puget Sound Energy    Year Ended December 31,  
(Dollars in Thousands)    2024     2023     Change  

Net income

   $ 346,148     $ 131,059     $ 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 ) 

GHG emission allowances

     (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.

 

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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.

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.

 

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Puget Energy    Year Ended December 31,  
(Dollars in Thousands)    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

     593       (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.

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 construction programs. Puget Energy and PSE continue to have reasonable access to the capital and credit markets.

In the second quarter of 2025, Moody’s, S&P and Fitch issued annual rating agency reports and affirmed both Puget Energy (Baa3/BBB-/BBB-) and PSE (Baa1/BBB/BBB+) credit ratings and retained stable outlooks from all three agencies. Thus, as of March 31, 2026, both Puget Energy and PSE have stable outlooks from Moody’s, S&P and Fitch. 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.

 

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Puget Sound Energy

Debt Restrictive Covenants

PSE’s future long-term financings and ability to issue additional secured debt may be limited by certain restrictions contained in its electric and natural gas mortgage indentures. Under the most restrictive tests, at March 31, 2026, PSE could issue:

 

  •  

Approximately $4.0 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $5.8 billion of electric bondable property available for issuance; and

 

  •  

Approximately $3.1 billion of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $4.5 billion of natural gas bondable property available for issuance.

Dividend Payment Restrictions

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 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 49.0% at March 31, 2026, and the EBITDA to interest expense was 5.4 to 1.0 for the twelve months ended March 31, 2026.

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.

At March 31, 2026, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

For more information on PSE’s credit facilities, long-term debt, demand promissory note, and shelf registrations see Note 10, “Other” to the unaudited consolidated interim financial statements and Note 7, “Long-Term Debt” and Note 8, “Liquidity Facilities and Other Financing Arrangements” to the audited consolidated financial statements, each included in this prospectus.

Puget Energy

Dividend Payment Restrictions

Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission in 2009. Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than 2.0 to 1.0. Puget Energy’s EBITDA to interest expense was 3.9 to 1.0 for the twelve months ended March 31, 2026.

Puget Energy’s ability to pay dividends is also limited by the terms of its junior subordinated notes, which Puget Energy may, at its option, defer interest payments on the junior subordinated notes on one or more occasions for up to 10 consecutive years, so long as no Event of Default (as defined in the Junior Subordinated Indenture, dated as of March 27, 2026) has occurred and is continuing. In the event that Puget Energy were to exercise such right to defer interest payments on the junior subordinated notes, Puget Energy would not be able to pay cash dividends during the periods in which such payments were deferred.

 

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At March 31, 2026, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

For further information on Puget Energy’s credit facilities, shelf registrations, and long-term debt, see Note 10, “Other” to the unaudited consolidated interim financial statements and Note 7, “Long-Term Debt” and Note 8, “Liquidity Facilities and Other Financing Arrangements” to the audited consolidated financial statements, each included in this prospectus.

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 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 Topic 980, Regulated Operations (ASC 980), 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 1 “Summary of Significant Accounting Policies” and Note 3, “Revenue,” to the audited consolidated financial statements included in this prospectus.

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, 2025, in the amount of $1,708.4 million and $1,851.6 million, respectively, and regulatory assets and liabilities as of December 31, 2024, of $1,416.5 million and $1,855.6 million, respectively. These amounts are amortized through a corresponding liability or asset account, with no impact to earnings. PSE expects to fully

 

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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 information, see Note 1 “Summary of Significant Accounting Policies” and Note 4, “Regulation and Rates,” to the audited consolidated financial statements included in this prospectus.

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. 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 normal purchase normal sale 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, 2025 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 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 the “Quantitative and Qualitative Disclosures about Market Risk” section of this prospectus, Note 10, “Accounting for Derivative Instruments and Hedging Activities” and Note 11, “Fair Value Measurements” to the audited consolidated financial statements included in this prospectus.

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

 

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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 is 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 audited consolidated financial statements included in this prospectus.

Fair Value

ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (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 the “Quantitative and Qualitative Disclosures about Market Risk” section in this report.

Pension and Other Postretirement Benefits

PSE has a qualified defined benefit pension plan covering certain employees of PSE. PSE recognized qualified pension income of $6.4 million and $5.1 million for the years ended December 31, 2025, and 2024, respectively. Of these amounts, approximately 45.9% and 45.8% were included in utility operations and maintenance expense in 2025 and 2024, respectively and the remaining amounts were capitalized. For the years ended December 31, 2025, and 2024, Puget Energy recognized incremental qualified pension income of $4.6 million and $2.7 million, respectively. In 2026, it is expected that PSE and Puget Energy will recognize pension income of $7.5 million and incremental qualified pension income of $2.4 million, respectively.

PSE has a Supplemental Executive Retirement Plan (“SERP”) and other limited postretirement benefit plans, for which expenses for the years ended December 31, 2025 and 2024 were immaterial for both PSE and PE. Further, PSE and PE expect to recognize immaterial expenses in 2026 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,

 

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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 2025, 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, 2025, and 2024, the Company’s qualified pension plan was $266.4 million overfunded and $195.7 million overfunded as measured under GAAP, or 145.1% and 133.9% funded, respectively. As of January 1, 2026, 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, 2026, are expected to be at least $18.0 million, $3.4 million and $0.2 million, respectively.

The discount rate used in accounting for pension and other benefit obligations decreased from 5.80% in 2024 to 5.65% in 2025. The discount rate used in accounting for pension and other benefit expense increased from 5.30% in 2024 to 5.80% in 2025. The rate of return on plan assets for qualified pension benefits was 7.00% in both 2024 and 2025. The rate of return on plan assets for other benefits was 7.00% in both 2024 and 2025.

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

 

Puget Energy and

Puget Sound Energy

   Change in Assumption      Impact on Projected
Benefit Obligation
Increase /(Decrease)
 
(Dollars in Thousands)           Pension Benefits     SERP     Other Benefits  

Increase in discount rate

     50 basis points      $ (27,766 )    $ (536 )    $ (253 ) 

Decrease in discount rate

     50 basis points        30,358       568       272  
Puget Energy    Change in Assumption      Impact on 2025
Pension Expense
Increase /(Decrease)
 
(Dollars in Thousands)           Pension Benefits     SERP     Other Benefits  

Increase in discount rate

     50 basis points      $ (2,284 )    $ 20     $ (26 ) 

Decrease in discount rate

     50 basis points        2,485       (20 )      29  

Increase in return on plan assets

     50 basis points      $ (4,013 )      *     $ (20 ) 

Decrease in return on plan assets

     50 basis points        4,013       *       19  
Puget Sound Energy    Change in Assumption      Impact on 2025
Pension Expense
Increase /(Decrease)
 
(Dollars in Thousands)           Pension Benefits     SERP     Other Benefits  

Increase in discount rate

     50 basis points      $ 22     $ 20     $ (25 ) 

Decrease in discount rate

     50 basis points        (36 )      (20 )      30  

Increase in return on plan assets

     50 basis points      $ (4,013 )      *     $ (20 ) 

Decrease in return on plan assets

     50 basis points        4,013       *       19  
 
*

Calculation not applicable.

 

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Recently Adopted Accounting Pronouncements

For the discussion of recently adopted accounting pronouncements, see Note 2, “New Accounting Pronouncements” to the unaudited consolidated interim financial statements included in this prospectus.

 

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CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Within this “Quantitative and Qualitative Disclosure About Market Risk” section, Puget Energy and PSE are collectively referred to as the “Company.”

The Company is exposed to various forms of market risk, consisting primarily of adverse changes in commodity prices, counterparty credit risk, as well as interest rate risk. PSE actively manages market risk and maintains risk policies and procedures designed to discourage unauthorized risk-taking, reduce commodity price volatility, and manage the various risks inherent to the energy portfolio. There have been no material changes to market risks affecting the Company from those set forth below.

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 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.

 

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

 

Puget Energy and Puget Sound Energy    December 31, 2025      December 31, 2024  
(Dollars in Thousands)    Assets      Liabilities      Assets      Liabilities  

Electric portfolio:

           

Current

   $ 32,045      $ 302,567      $ 29,274      $ 166,632  

Long-term

     9,929        190,767        6,067        152,874  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Electric Portfolio

   $ 41,974      $ 493,334      $ 35,341      $ 319,506  

Natural gas portfolio:

           

Current

     5,403        57,323        3,317        51,811  

Long-term

     1,332        22,764        178        18,614  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Natural Gas Portfolio

   $ 6,735      $ 80,087      $ 3,495      $ 70,425  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total derivatives

   $ 48,709      $ 573,421      $ 38,836      $ 389,931  
  

 

 

    

 

 

    

 

 

    

 

 

 

At December 31, 2025, the Company had total assets of $48.7 million and total liabilities of $573.4 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 gas portfolio 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 $137.2 million.

The change in fair value of the Company’s outstanding energy derivative instruments from December 31, 2024, through December 31, 2025, is summarized in the table below:

 

Puget Energy and Puget Sound Energy       
Energy Derivative Contracts Gain (Loss)       
(Dollars in Thousands)    December 31, 2025  

Fair value of contracts outstanding at December 31, 2024

   $ (351,095 ) 

Contracts realized or otherwise settled during 2025

     292,657  

Change in fair value of derivatives

     (466,274 ) 
  

 

 

 

Fair value of contracts outstanding at December 31, 2025

   $ (524,712 ) 
  

 

 

 

The fair value of the Company’s outstanding derivative instruments at December 31, 2025, based on pricing source and the period during which the instrument will mature, is summarized below:

 

Puget Energy and Puget Sound Energy
Source of Fair Value
   Fair Value of Contracts by Settlement Year  
(Dollars in Thousands)    2026     2027-2028     2029-2030     Thereafter     Total  

Prices provided by external sources1

   $ (242,299 )    $ (71,615 )    $ (4,844 )    $ —      $ (318,758 ) 

Prices based on internal models and valuation methods

     (80,142 )      (39,396 )      (23,456 )      (62,960 )      (205,954 ) 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total fair value

   $ (322,441 )    $ (111,011 )    $ (28,300 )    $ (62,960 )    $ (524,712 ) 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
 
1.

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

 

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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 audited consolidated financial statements included in this prospectus.

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. agreements, which standardize physical power contracts in the electric industry; International Swaps and Derivatives Association agreements, which standardize financial natural gas and electric contracts; and North American Energy Standards Board 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, 2025, PSE held approximately $806.5 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, 2025, approximately 96.5% 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

 

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estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against unrealized gain or loss positions. As of December 31, 2025, 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 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, 2025, PSE had cash posted as collateral of $78.0 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, 2025, $53.1 million was issued under a standby letter of credit with TD Bank in support of natural gas and carbon allowance purchases. In support of purchase power contracts, PSE posted cash collateral of $12.0 million and maintained three standby letters of credit in the amounts of $58.5 million, $13.5 million, and $11.9 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, 2025.

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    December 31, 2025      December 31, 2024  
(Dollars in Thousands)    Carrying Amount      Fair Value      Carrying Amount      Fair Value  

Puget Energy

   $ 8,525,032      $ 8,199,785      $ 7,423,919      $ 6,966,211  

Puget Sound Energy

     6,457,684        6,054,647        5,961,025        5,492,999  

For further details regarding Puget Energy and PSE debt instruments, see Note 7, “Long-Term Debt” and Note 11, “Fair Value Measurements” to the audited consolidated financial statements included in this prospectus.

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, 2025, was a net loss of $3.1 million after-tax and accumulated amortization. This compares to an after-tax loss of $3.4 million in OCI as of December 31, 2024. 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, 2025.

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, 2025, the Company had no outstanding interest rate swap instruments.

 

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BUSINESS

Within this “Business” section, Puget Energy and PSE are collectively referred to as the “Company.”

General

Puget Energy is an energy services holding company incorporated in the state of Washington in 1999. Substantially all of its operations are conducted through its regulated subsidiary, PSE, a utility company. Puget Energy also has a wholly-owned, non-regulated subsidiary, Puget LNG, which was formed in 2016 and has the sole purpose of owning and operating the non-regulated activity of a LNG facility at the Port of Tacoma, Washington.

Puget Energy is owned through a holding company structure by 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 BCIMC, AIMCo, OMERS, PGGM Vermogensbeheer B.V., Macquarie Washington Clean Energy Investment, L.P., and the Ontario Teachers’ Pension Plan Board.

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, 2025 and 2024:

 

     December 31,            December 31,         
Customer Count by Class    2025      2024      Percent     2025      2024      Percent  
(in thousands)    Electric      Change     Natural Gas      Change  

Residential

     1,109        1,099        0.9 %      823        821        0.2 % 

Commercial

     135        135        —        57        57        —   

Industrial

     3        3        —        3        3        —   

Other

     9        9        —        —         —         —   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Total1

     1,256        1,246        0.8 %      883        881        0.2 % 
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 
 
1 

At December 31, 2025 and 2024, approximately 430,270 and 428,440 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

 

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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 qualifying 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 “Regulation and Rates” below and Note 4, “Regulation and Rates” to the audited consolidated financial statements included in this prospectus.

Capital Expenditures

The following tables present PSE’s capital expenditures for the five-year period ended December 31, 2025 and gross utility plant by category and percentages as of December 31, 2025:

 

Utility Plant Additions/Retirements 5-Year Total    2021 - 2025  
(Dollars in Thousands)    Electric      Natural Gas      Common  

Additions

   $ 3,504,577      $ 1,403,204      $ 576,805  

Retirements

     (601,022 )       (115,767 )       (562,628 ) 
  

 

 

    

 

 

    

 

 

 

Net utility plant

   $ 2,903,555      $ 1,287,437      $ 14,177  
  

 

 

    

 

 

    

 

 

 

 

Utility Plant in Service    December 31, 2025  
(Dollars in Thousands)    Electric     Natural Gas     Common  

Distribution

   $ 5,806,142        40.0 %    $ 5,580,193        95.3 %    $ —         —  % 

Generation

     5,269,966        32.4       3,239        0.1       —         —   

Transmission

     2,350,904        16.1       —         —        —         —   

General plant & other

     1,094,417        11.5       273,407        4.6       1,213,483        100.0  
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total (excluding CWIP)

   $ 14,521,429        100.0 %    $ 5,856,839        100.0 %    $ 1,213,483        100.0 % 
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Corporate Location

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

Available Information

The Company’s 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 Exchange Act are available or may be accessed free of charge at the Company’s website, www.pugetenergy.com. The 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. Information included on these websites is not incorporated by reference into this prospectus.

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

 

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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 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    Electric      Natural Gas  

Baseline rates

     Yes        Yes  

Expedited rate filing rider

     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 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.

For further information regarding PSE’s GRC filings, see Note 4, “Regulation and Rates” to the audited consolidated financial statements included in this prospectus.

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.

Climate Commitment Act - Greenhouse Gas Emissions Cap and Invest Adjustment

The Schedule 111 for electric and natural gas, tariff implements a surcharge to recover the costs associated with the overall compliance obligation, and provide benefits through credits to certain customers from the Company’s implementation of Washington State GHG emission cap and invest program as prescribed by the CCA and codified in law within RCW 70A.65.

Conservation Service Rider

The Schedule 120 tariff 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.

 

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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. Consistent with the 2024 GRC, PSE included these costs as part of base rates.

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 qualifying 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 PCA and 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 audited consolidated financial statements included in this prospectus.

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

 

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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 audited consolidated financial statements included in this prospectus.

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.

Power Cost Adjustment Clause

The power cost adjustment clause for Schedule 95 includes a supplemental filing, variable power cost update and/or power cost only rate case (“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 2022 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.

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.

Residential 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 typically 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.

 

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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 for each of the resource options provided by PSE for the annual rates approved from 2020 through 2040. Additionally, 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. Docket No. UE-220066 included a Green Direct Settlement agreement in which Schedule 139 energy charge credit is increased annually, every January by 2.0%.

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 those described in 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.

Natural Gas Rate Filings

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 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 recover the 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 of Financial Condition and Results of Operations—Regulation of PSE Rates and Recovery of PSE Costs” included in this prospectus.

 

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ELECTRIC UTILITY OPERATING STATISTICS

 

Puget Sound Energy    Year Ended December 31,  
     2025      2024      2023  

Generation and purchased power, MWh

        

Company-controlled resources

     12,034,560        14,295,586        14,894,381  

Contracted resources

     16,516,388        11,545,827        11,806,074  

Non-firm energy purchased

     2,084,728        3,054,018        2,910,517  
  

 

 

    

 

 

    

 

 

 

Total generation and purchased power

     30,635,676        28,895,431        29,610,972  

Less: losses and Company use

     (1,002,930 )       (1,049,357 )       (1,113,911 ) 
  

 

 

    

 

 

    

 

 

 

Total energy, MWh

     29,632,746        27,846,074        28,497,061  
  

 

 

    

 

 

    

 

 

 

Electric energy sales, MWh

        

Residential

     11,434,185        11,462,977        11,387,971  

Commercial

     8,649,567        8,570,573        8,637,063  

Industrial

     1,040,902        1,057,368        1,070,933  

Other customers

     76,771        77,822        76,495  
  

 

 

    

 

 

    

 

 

 

Total energy sales to customers

     21,201,425        21,168,740        21,172,462  

Sales to other utilities and marketers

     8,431,321        6,677,334        7,324,599  
  

 

 

    

 

 

    

 

 

 

Total energy sales, MWh

     29,632,746        27,846,074        28,497,061  

Transportation

     2,320,864        2,307,813        2,270,474  
  

 

 

    

 

 

    

 

 

 

Electric energy sales and transportation, MWh

     31,953,610        30,153,887        30,767,535  
  

 

 

    

 

 

    

 

 

 

Electric operating revenue by classes

        

(Dollars in Thousands)

        

Residential

   $ 1,944,566      $ 1,677,599      $ 1,514,149  

Commercial

     1,339,883        1,159,596        1,071,385  

Industrial

     146,595        131,869        123,548  

Other customers

     26,086        23,507        21,199  
  

 

 

    

 

 

    

 

 

 

Total operating revenue from customers

     3,457,130        2,992,571        2,730,281  

Transportation

     26,338        18,723        23,573  

Sales to other utilities and marketers

     335,667        281,186        502,391  

Decoupling revenue

     (11,550 )       (39,900 )       (35,621 ) 

Other decoupling revenue1

     42,496        35,536        16,635  

Miscellaneous operating revenue2

     41,096        44,579        108,608  
  

 

 

    

 

 

    

 

 

 

Total electric operating revenue

   $ 3,891,177      $ 3,332,695      $ 3,345,867  
  

 

 

    

 

 

    

 

 

 

Number of customers served (average):

        

Residential

     1,104,338        1,091,599        1,077,406  

Commercial

     135,433        134,993        134,375  

Industrial

     3,145        3,175        3,187  

Other

     8,414        8,269        8,156  

Transportation

     122        124        109  
  

 

 

    

 

 

    

 

 

 

Total customers

     1,251,452        1,238,160        1,223,233  
  

 

 

    

 

 

    

 

 

 
 
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.

 

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ELECTRIC UTILITY OPERATING STATISTICS (Continued)

 

     Year Ended December 31,  
     2025     2024     2023  

Average kWh used per customer:

      

Residential

     10,354       10,501       10,570  

Commercial

     63,866       63,489       64,276  

Industrial

     330,970       333,029       336,032  

Other

     9,124       9,411       9,379  

Average revenue per customer:

      

Residential

   $ 1,761     $ 1,537     $ 1,405  

Commercial

     9,893       8,590       7,973  

Industrial

     46,612       41,534       38,766  

Other

     3,100       2,843       2,599  

Average retail revenue per kWh sold:

      

Residential

   $ 0.1701     $ 0.1463     $ 0.1330  

Commercial

     0.1549       0.1353       0.1240  

Industrial

     0.1408       0.1247       0.1154  

Other

     0.3398       0.3021       0.2771  
  

 

 

   

 

 

   

 

 

 

Average retail revenue per kWh sold

   $ 0.1631     $ 0.1414     $ 0.1290  
  

 

 

   

 

 

   

 

 

 

Heating degree days

     4,254       4,380       4,313  

Percent of normal - NOAA1 30-year average

     99.4 %      101.0 %      98.1 % 
 
1. 

National Oceanic and Atmospheric Administration (“NOAA”).

Electric Supply

At December 31, 2025, 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 7,983 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, 2025 and 2024:

 

     Peak Power Resources
At December 31,
    Energy Production
At December 31,
 
     2025     2024     2025     2024  
     MW      %     MW      %     MWh      %     MWh      %  

Purchased resources:

                    

Columbia River PUD contracts1

     1,117        14.0 %      915        14.1 %      5,003,323        16.3 %      3,284,849        11.4 % 

Other hydroelectric

     47        0.6       47        0.7       357,317        1.2       358,266        1.2  

Coal

     380        4.8       380        5.8       2,625,032        8.6       3,334,286        11.5  

Other producers

     858        10.7       858        13.2       635,145        2.1       664,630        2.3  

Wind/solar

     996        12.5       888        13.6       3,016,488        9.8       2,898,905        10.0  

Biomass

     17        0.2       17        0.3       129,737        0.4       128,213        0.4  

PURPA qualifying facilities

     202        2.5       80        1.2       816,309        2.7       866,835        3.0  

Short-term wholesale energy purchases

     N/A        —        N/A        —        2,079,915        6.8       3,063,861        10.7  
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total purchased

     3,617        45.3 %      3,185        48.9 %      14,663,266        47.9 %      14,599,845        50.5 % 
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

 

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     Peak Power Resources
At December 31,
    Energy Production
At December 31,
 
     2025     2024     2025     2024  
     MW      %     MW      %     MWh      %     MWh      %  

Company-controlled resources:

                    

Hydroelectric

     263        3.3 %      263        4.0 %      866,387        2.8 %      869,257        3.0 % 

Coal2

     370        4.6       370        5.7       2,300,267        7.5       2,195,159        7.6  

Natural gas/oil3

     2,714        34.0       1,931        29.6       10,867,286        35.5       9,309,858        32.3  

Wind/solar

     1,019        12.9       773        11.8       1,938,470        6.3       1,921,312        6.6  

Other

     —         —        2        —        —         —        —         —   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total company-controlled

     4,366        54.7 %      3,339        51.1 %      15,972,410        52.1 %      14,295,586        49.5 % 
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total resources

     7,983        100.0 %      6,524        100.0 %      30,635,676        100.0 %      28,895,431        100.0 % 
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 
 
1.

Net of 15 MW and 35 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, 2025, and 2024, respectively.

2.

The transfer of PSE’s interest in Colstrip Units 3 and 4 to NorthWestern Energy was completed by January 1, 2026, and thus thereafter Colstrip no longer serves PSE customers.

3.

Includes supply under Company-control related to two tolling agreements with a combined capacity of 783 MW.

Company-Owned Electric Generation Resources

At December 31, 2025, PSE owned the following plants with an aggregate net generating capacity of 3,583 MW:

 

Plant Name

 

Plant Type

 

Net Maximum

Capacity (MW)1

 

Year Installed

Colstrip Units 3 & 4
(25% interest)2

  Coal   370   1984 & 1986

Lower Snake River

  Wind   343   2012

Mint Farm

  Natural gas combined cycle   320   2007; acquired 2008; upgraded 2017

Goldendale

  Natural gas combined cycle   315   2004, acquired 2007, upgraded 2016

Wild Horse

  Wind   271   2006 & 2009

Ferndale

  Natural gas co-generation   253   1994; acquired 2012

Beaver Creek

  Wind   248   2025

Fredonia Units 1 & 2

  Dual-fuel combustion turbines   207   1984

Encogen

  Natural gas co-generation   165   1993; acquired 1999

Hopkins Ridge

  Wind   157   2005 & 2008

Frederickson Units 1 & 2

  Dual-fuel combustion turbines   149   1981

Whitehorn Units 2 & 3

  Dual-fuel combustion turbines   149   1981

Frederickson Unit 1
(49.85% interest)

  Natural gas combined cycle   136   2002; added duct firing 2005

Sumas

  Natural gas co-generation   127   1993; acquired 2008

Fredonia Units 3 & 4

  Dual-fuel combustion turbines   107   2001

 

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Plant Name

 

Plant Type

 

Net Maximum

Capacity (MW)1

 

Year Installed

Lower Baker River

  Hydroelectric   105   1925: reconstructed 1960; upgraded 2001 and 2013

Upper Baker River

  Hydroelectric   104   1959; unit 2 upgraded 1997, upgraded 2021

Snoqualmie Falls3

  Hydroelectric   54   1898 to 1911 & 1957; rebuilt 2013

Crystal Mountain

  Internal combustion   3   1969
   

 

 

Total Net Capacity

    3,583  
   

 

 
 
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 transfer of PSE’s interest in Colstrip Units 3 and 4 to NorthWestern Energy was completed by January 1, 2026, and thus thereafter Colstrip no longer serves PSE customers.

3.

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

For the year ended December 31, 2025, approximately 14.0% of the Company’s energy output was obtained through long-term contracts with three of the Washington PUDs that own hydroelectric projects on the Columbia River.

For the year ended, December 31, 2025, 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 PUD:

       

Rock Island Project

     2051        40.0%       250  

Rocky Reach Project

     2051        40.0       515  

Douglas County PUD:

       

Wells Project

     2029        18.6       156  

Grant County PUD:

       

Priest Rapids Development

     2052        9.9       94  

Wanapum Development

     2052        9.9       102  
       

 

 

 

Total

          1,117  
       

 

 

 

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.

 

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PSE began participating in the Energy Imbalance Market (“EIM”) operated by the California Independent System Operator on October 1, 2016. Participation has resulted in reduced costs for PSE customers of approximately $52.5 million in the year ended December 31, 2025, 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 2025, PSE had 5,721 MW and 1,620 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 UTILITY OPERATING STATISTICS

 

Puget Sound Energy    Year Ended December 31,  
     2025      2024      2023  

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

        

Residential1

   $ 900,996      $ 796,889      $ 868,462  

Commercial firm1

     396,097        344,014        356,650  

Industrial firm

     25,339        24,679        25,472  

Interruptible

     27,133        25,944        37,099  
  

 

 

    

 

 

    

 

 

 

Total retail natural gas sales

     1,349,565        1,191,526        1,287,683  

Transportation services1

     31,666        34,706        29,210  

Decoupling revenue

     7,003        33,232        23,116  

Other decoupling revenue2

     (28,029 )       (9,728 )       (3,405 ) 

Other1

     102,152        242,518        87,764  
  

 

 

    

 

 

    

 

 

 

Total natural gas operating revenue

   $ 1,462,357      $ 1,492,254      $ 1,424,368  
  

 

 

    

 

 

    

 

 

 

Number of customers served (average):

        

Residential

     821,438        819,413        815,454  

Commercial firm

     57,064        57,102        56,934  

Industrial firm

     2,238        2,245        2,260  

Interruptible

     245        260        270  

Transportation

     191        199        200  
  

 

 

    

 

 

    

 

 

 

Total customers

     881,176        879,219        875,118  
  

 

 

    

 

 

    

 

 

 

Natural gas volumes, therms (thousands):

        

Residential

     549,817        573,739        587,635  

Commercial firm

     276,566        285,657        285,197  

 

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NATURAL GAS UTILITY OPERATING STATISTICS (Continued)

 

Puget Sound Energy    Year Ended December 31,  
     2025     2024     2023  

Industrial firm

     19,704       21,061       22,168  

Interruptible

     38,622       41,922       49,275  
  

 

 

   

 

 

   

 

 

 

Total retail natural gas volumes, therms

     884,709       922,379       944,275  

Transportation volumes

     171,410       188,336       192,043  
  

 

 

   

 

 

   

 

 

 

Total volumes

     1,056,119       1,110,715       1,136,318  
  

 

 

   

 

 

   

 

 

 

Average therms used per customer:

      

Residential

     669       700       721  

Commercial firm

     4,847       5,003       5,009  

Industrial firm

     8,804       9,381       9,809  

Interruptible

     157,641       161,238       182,500  

Transportation

     897,435       946,412       960,215  

Average revenue per customer:

      

Residential1

   $ 1,097     $ 973     $ 1,065  

Commercial firm1

     6,941       6,025       6,264  

Industrial firm

     11,322       10,993       11,271  

Interruptible

     110,747       99,785       137,404  

Transportation1

     165,791       174,402       146,050  

Average revenue per therm sold:

      

Residential

   $ 1.639     $ 1.389     $ 1.478  

Commercial firm

     1.432       1.204       1.251  

Industrial firm

     1.286       1.172       1.149  

Interruptible

     0.703       0.619       0.753  
  

 

 

   

 

 

   

 

 

 

Average retail revenue per therm sold1

   $ 1.525     $ 1.292     $ 1.364  
  

 

 

   

 

 

   

 

 

 

Transportation1

   $ 0.185     $ 0.184     $ 0.152  

Heating degree days

     4,254       4,380       4,313  

Percent of normal—NOAA 30-year average

     99.4 %      101.0 %      98.1 % 
 
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), utilizing physical and financial hedges to manage volatility in the cost of natural gas. All of PSE’s natural gas supply is 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.

 

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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. PSE also stores 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 optimizes its resources through off-system sales outside of PSE’s service territory when on-system demand requirements permit and market economics are favorable, with the resulting economics of these transactions 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, 2025 and 2024:

 

     At December 31,  
     2025      2024  

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

     

Jackson Prairie

     82,537        82,036  

Clay Basin

     94,067        91,301  

Tacoma LNG

     5,041        4,900  

Gig Harbor LNG

     86        94  

Plymouth LNG

     571        573  

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, enhance supply reliability, provide operational flexibility, and provide significant cost savings by reducing the amount of annual pipeline capacity required to meet peak-day natural gas requirements. The Jackson Prairie facility is operated and one-third owned by PSE. When combined with capacity contracted from NWP’s stake in Jackson Prairie, PSE holds firm withdrawal capacity of approximately 450,000 Dth per day, and over 9.8 million Dth of storage capacity.

PSE holds 12.9 million Dth of Clay Basin storage capacity and approximately 100,000 Dth per day of firm withdrawal capacity at Mountain West Pipeline’s Clay Basin storage facility under two long-term contracts with remaining terms of two years and has rights to extend such agreements.

LNG Resources

LNG 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. PSE designates this storage capacity 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. In addition, PSE holds 15,000 Dth per 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.

 

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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

The Tacoma LNG facility, operational since February 2022, provides up to approximately 85,000 Dth per day peak-shaving services to PSE’s natural gas customers and 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. The case was transferred to Division III of the Court of Appeals in March 2025. A hearing date has not been set. For additional information, see Note 4, “Regulation and Rates” to the audited consolidated financial statements included in this prospectus.

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”).

PSE holds approximately 520,000 Dth per day of capacity for its natural gas customers on NWP that provides firm year-round delivery to PSE’s service territory. PSE holds approximately 285,000 Dth per day of firm transportation capacity on NWP to supply natural gas to its electric generating facilities. For both natural gas customers and electric generating facilities, PSE holds an additional approximately 480,000 Dth per day of seasonal firm capacity on NWP to provide for delivery of natural gas stored at Jackson Prairie to the natural gas system or generating plants. PSE’s firm transportation and storage capacity contracts with NWP have varying terms that provide PSE with either the unilateral right to extend the contracts or the right of first refusal to extend such contracts under current FERC rules.

To supply both its natural gas customers and electric generating facilities, under various contracts, PSE holds additional firm capacity on several upstream pipeline systems. This includes approximately 220,000 Dth per day on the Westcoast pipeline, 120,000 Dth on each of the NGTL and Foothills pipelines, and 115,000 Dth per day on the GTN pipeline. The terms of these contracts all contain an option for PSE to renew its rights.

Additionally, PSE holds approximately 260,000 Dth per day of firm capacity on CNGC to connect generating facilities to the pipeline grid.

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.

 

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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.

Integrated System Plan, Resource Acquisition and Development

PSE is required under Washington state law and Washington Commission rules to file an integrated system plan (“ISP”) that combines natural gas and electric system planning and clean energy implementation plans. Previously, Washington Administrative Code (“WAC”) 480-100-625 required PSE to file a natural gas integrated resource plan (“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 electric resource adequacy planning consideration is capacity. Based on the cumulative capacity need by year, the capacity (surplus)/shortfalls identified in PSE’s most recent resource adequacy analysis are:

 

     2026      2027      2028      2029      2030  

Projected MW (surplus)/shortfall

     576        659        418        524        1,404  

Due to growing regional concerns pertaining to capacity within the short-term market, PSE no longer relies on firm short-term spot market purchases. PSE’s energy supply actions in 2025 reduced capacity shortfalls in future years as compared to the 2024 projected capacity needs. The elimination of Colstrip Units 3 and 4 from PSE’s energy supply portfolio effective on January 1, 2026, which removed approximately 370 MW of coal generation capacity, the expiration of PSE’s 380 MW coal-transition contract with TransAlta for the Centralia coal plant at the end of 2025, and the expected expiration of PSE’s 300 MW PG&E seasonal exchange contract at the end of 2027 collectively reduce PSE’s generation capacity by 1,050 MW. These reductions are planned to be offset by 1,365 MW from the Gray’s Harbor combined cycle contract for 665 MW and the conversion of the TransAlta Centralia coal generation facility to a combined cycle plant for 700 MW in 2028. These changes result in a projected capacity shortfall of 576 MW in 2026 and is expected to be a shortfall of 1,404 MW by 2030. PSE plans to cover the projected shortfall in 2026 through a series of market purchases and other activities. The projected capacity above reflects the peak capacity value of intermittent energy resources, such as wind and solar, consistent with CETA requirements.

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

 

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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 prospectus, all three grants must complete award negotiations and proceed to a signed award with the DOE in order to receive federal cost sharing funds. 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 the accounting remains unchanged as of the 2024 GRC Final Order in Dockets No. UE-240004 and UG-240005. Decoupling 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 “Risk Factors” included in this prospectus.

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 PSE held a partial ownership of Colstrip, and the transfer of PSE’s interest in Colstrip Units 3 and 4 to NorthWestern Energy was completed by January 1, 2026, and thus thereafter Colstrip no longer serves PSE customers. 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. As of December 31, 2025, the Colstrip plant represented PSE’s most significant source of GHG emissions.

 

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Species Protection

PSE owns and operates 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 prior ownership interest in Colstrip (the transfer of PSE ownership interest in Colstrip Units 3 and 4 to NorthWestern Energy was completed by January 1, 2026, and thus thereafter Colstrip no longer serves PSE customers). 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 continued to meet the requirement through December 31, 2025.

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.

 

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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 eliminated coal from its energy supply portfolio by January 1, 2026, and is planning to achieve net zero carbon emissions for its electric supply for the four-year compliance period beginning January 1, 2030, consistent with CETA requirements. Further, the Company set an aspirational goal to be net zero by 2045 for natural gas sales (which will require future policy, regulatory and/or customer preference changes and technology innovation), and to go beyond direct energy supply by helping other Washington sectors address GHG emissions, such as the transportation sector by upgrading transmission and distribution infrastructure to accommodate more widespread EV adoptions and providing LNG 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.

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 for the four-year compliance period beginning January 1, 2030 through a combination of non-emitting electric generation, renewable generation, and/or alternative compliance options; and (iii) by 2045, supply 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 Washington Commission. PSE’s next CEIP will be combined with its ISP due by April 2027.

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, 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 periodic 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

 

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25,000 metric tons of carbon dioxide equivalent per year. As an electric utility subject to Washington’s CETA, PSE receives emission allowances from WDOE at no cost through 2050 for direct emissions associated with electricity used to serve Washington State load to mitigate the cost burden of the program on electric ratepayers.

As a natural 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 for natural gas ratepayers 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.

Greenhouse Gas Emission Reporting

PSE is required to annually submit 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 Environmental Protection Agency (“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 2024 was 8.86 million metric tons of carbon dioxide equivalents. Approximately 25.9% of total electric supply portfolio GHG emissions (approximately 2.29 million metric tons) were associated with PSE’s 2024 ownership and contractual interests in coal generation. Compared to 2023, total GHG emissions decreased by 5.2%. PSE’s GHG emissions resulting from the combustion of natural gas provided to end-users on PSE’s distribution systems in 2024 were 5.86 million metric tons of carbon dioxide equivalents.

Federal 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 federal 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 federal Inflation Reduction Act (“IRA”) was signed into law. The IRA was intended to lower gasoline and electricity prices, increase energy security, and help consumers to afford

 

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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 as of December 31, 2025 generated ITCs under the IRA related to qualifying projects. See Note 13, “Income Taxes” to the audited consolidated financial statements included in this prospectus.

One Big Beautiful Bill Act

On July 4, 2025, the One Big Beautiful Bill Act (“OBBB”) was signed into law. The OBBB includes a range of tax reforms and modifications to certain provisions included in the Tax Cuts and Jobs Act of 2017. The OBBB also impacts certain provisions included in the Inflation Reduction Act of 2022 by modifying or accelerating various tax incentives, which led the Company to accelerate project activities on some eligible projects in order to retain the ability to earn tax incentives while continuing to evaluate other potential future impacts of the legislation. See Note 6, “Utility Plant” to the audited consolidated financial statements included in this prospectus for more details of development projects.

Federal-Level Greenhouse Gas Emission Requirements

The EPA has issued several rules that govern GHG emissions from both new and existing power plants under Section 111 of the CAA. In 2015, the EPA finalized New Source Performance Standards (“NSPS”) for carbon dioxide (“CO2”) emissions from new and reconstructed power plants that burn fossil fuels under Section 111(b) of the CAA (“2015 NSPS”). A new natural gas-fire combustion turbine (“CT”) that supplies more than its design efficiency or 50 percent, whichever is less, times its potential electric output as net-electric sales on both a 12-operating month and a 3-year rolling average basis, can emit no more than 1,000 lbs. of CO2/MWh, which is achievable with the latest combined cycle technology. New coal-fired steam generating units can emit no more than 1,400 lbs. of CO2/MWh. The 2015 NSPS applies to steam generating units that commenced construction after January 8, 2014, commenced reconstruction after June 18, 2014, or commenced modification after January 8, 2014, but on or before May 23, 2023. It applies to CTs that commenced construction after January 8, 2014, but on or before May 23, 2023, or commenced reconstruction after June 18, 2014, but on or before May 23, 2023.

The EPA finalized another NSPS for CO2 emissions from new and reconstructed fossil fuel-fired CTs on May 9, 2024 (“2024 Rule”), which apply to CTs that commenced construction or reconstruction after May 23, 2023. The standards vary based on the capacity factor (“CF”) of the unit: (1) for low load CTs (CF ≤ 20%), affected sources must comply with a CO2 emission limitation of 120 lb CO2/MMBtu; (2) for intermediate load CTs ( 20% < CF ≤ 40%), affected sources must comply with a CO2 emission limitation of 1,170 lb CO2/MWhg; and (3) for base load CTs (CF > 40%), affected sources must install carbon capture and sequestration (“CCS”) or another technology to meet a CO2 emission limitation of 100 lb CO2/MWhg by January 1, 2032. The 2024 Rule also established limits for GHG emissions from existing fossil fuel-fired steam generating units under Section 111(d) of the CAA, as well as repealed an earlier federal GHG emission rule, the Affordable Clean Energy (“ACE”) Rule. The ACE Rule, in turn, had replaced the federal Clean Power Plan. Litigation over the ACE Rule remains in abeyance in the U.S. Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”).

The 2024 Rule is subject to a pending challenge in the D.C. Circuit that has been held in abeyance since April 2025, due to EPA’s plan to reconsider the 2024 Rule. On June 17, 2025, EPA proposed to repeal all GHG emission standards for the power sector under Section 111, including the 2015 NSPS and the 2024 Rule. According to EPA’s November 2025 status report to the D.C. Circuit in the pending challenge to the 2024 Rule, the Agency was continuing to work on the rulemaking and planned to provide further update to the court on February 23, 2026.

 

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Criteria Air Pollutant Emissions Limits for New, Modified, and Reconstructed Stationary Combustion Turbines

On January 15, 2026, EPA published a final rule revising the NSPS regulating criteria air pollutant emissions from new, modified, and reconstructed stationary CTs subject to 40 C.F.R. Subparts GG or KKKK. The final rule sets a range of NOx emission standards (depending on the type of CT, operating conditions, and fuel combusted) based on combustion controls (i.e., without Selective Catalytic Reduction (“SCR”) for all but one subcategory of new, modified, or reconstructed stationary CT. For that subcategory-new large turbines with high rates of utilization (i.e., 12-calendar-month capacity factors greater than 45 percent)-the standard (5 ppm) is based on the installation of combustion controls with SCR. EPA retained the existing sulfur dioxide (SO2) standards, based on its finding that Best System of Emission Reduction remains the use of pipeline natural gas and distillate fuels. The standards apply to affected sources that began construction, modification, or reconstruction after December 13, 2024, the date of publication of the proposal in the Federal Register.

Regional Haze Rule

In January 2017, the EPA revised the Regional Haze Rule. Among other things, these revisions delayed the second planning period 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, which determined that no additional emissions controls on power plants were necessary to make reasonable progress toward visibility improvement. EPA published its final approval of the Washington SIP revision on September 25, 2025. Montana submitted its SIP revision in August 2022, which required no additional emissions controls to make reasonable progress toward the visibility improvement. EPA published its final approval of the Montana SIP revision on November 28, 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, for which SIPs will be due to EPA on July 31, 2031. In October 2025, EPA followed this with an advanced notice of proposed rulemaking announcing its plans to revise the Regional Haze Rule and requesting public input on potential changes. EPA’s final action will govern the scope of SIPs, including state consideration of potential additional emissions controls on existing power plants to address regional haze.

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 required 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 Asset Retirement and Environmental Obligations.

In 2018, the D.C. Circuit 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

 

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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 for the D.C. Circuit, and the EPA has announced that it will reconsider the rule.

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, 2025, PSE had approximately 3,412 full-time equivalent employees. Approximately 1,053 PSE employees are represented by the International Brotherhood of Electrical Workers (“IBEW”) or The United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada (“UA”). The UA contract was ratified effective October 1, 2025, and will expire September 30, 2029. 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

 

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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:

 

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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.

 

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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.

 

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For additional details on company retirement benefits see Note 12 “Retirement Benefits” (for employees hired prior to January 1, 2014) to the audited consolidated financial statements included in this prospectus and “Compensation Discussion & Analysis” included in this prospectus.

Employee Development

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

 

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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.

 

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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.

 

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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.

 

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  •  

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, which are open to all employees and do not provide exclusive benefits to members based on protected traits. These groups benefit their members and the Company by integrating different perspectives, offering opportunities for professional development, increasing employee retention and recruitment, 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 May 14, 2026, 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

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

J. Martin

   44    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

   58    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

   40    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 May 14, 2026, 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

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

J. Martin

   44    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

   58    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

 

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Name

  

Age

  

Offices

A. August

   47    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

C. Pospisil

   57    Senior Vice President, Chief Development Officer since January 2026; Vice President Business Development and M&A from August 2023 to January 2026; Vice President Head of Wind Development at Terra-Gen, LLC from 2017-2023; Vice President of Development at Terra-Gen, LLC from 2016-2017

M. Steuerwalt

   57    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

M. Vargo

   44    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

   53    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

   40    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

 

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PROPERTIES

The principal electric generating plants and underground natural gas storage facilities owned by PSE are described above under “Business—Electric Supply” and “Business—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.

LEGAL PROCEEDINGS

Contingencies arising out of the Company’s normal course of business existed as of March 31, 2026. Litigation is subject to numerous uncertainties and the Company is unable to predict the ultimate outcome of these matters. For further details, see Note 8, “Commitments and Contingencies” to the unaudited consolidated interim financial statements included in this prospectus.

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, the Company 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.

 

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MANAGEMENT

Board of Directors

As of May 14, 2026, twelve directors constitute Puget Energy’s board of directors and thirteen 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.

Jerry Divoky, age 59, has been a director on the board of both Puget Energy and PSE since June 9, 2025. Mr. Divoky is Senior Managing Director at BCIMC since 2024. Mr. Divoky is responsible for sourcing, executing and managing private direct infrastructure investments globally. Mr. Divoky currently serves on the boards of National Gas Transmission in the U.K, Pacific National Rail in Australia, and Czech Gas in the Czech Republic. Mr. Divoky was selected by BCIMC and pursuant to the terms of the bylaws of the Companies, will serve as an owner director on their respective boards of directors. Mr. Divoky 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.

Christine Gregoire, age 79, 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.

Adam Friedrichsen, age 37, has been a director on the board of both Puget Energy and PSE since August 1, 2025. Mr. Friedrichsen is currently a director at OMERS since 2013 and is responsible for the origination, execution and management of infrastructure investments in North America and Europe. He has served on the board of directors of Kenter-Groendus, a Dutch energy infrastructure solutions company from 2022-2025, Ellevio, a Swedish regulated electric distribution operator from 2023-2024 and Scotia Gas Networks, a UK regulated gas network operator from 2021-2022. Mr. Friedrichsen was selected by OMERS and pursuant to the terms of the bylaws of the Companies, will serve as an owner director on their respective boards of directors. Mr. Friedrichsen 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.

Chris Parker, age 55, 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 since 2018 and Southwater (and subsidiary companies Essbio, Esval and AdV) since March 2025. 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.

 

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Julia Hamm, age 49, 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. Ms. Hamm is also a Partner at the Ad Hoc Group and Advisor at the EQT Group. 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 50, 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 BCIMC, 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 is also a director of Boswell 3 Holdings S.a.r.l. Mr. Hodgkins was selected by BCIMC 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 64, has been a director on the boards of both Puget Energy and PSE since April 17, 2019. Mr. King is a member of the board of directors of Woodway Energy Infrastructure since 2022. He is also an Executive Partner 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 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 58, 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 and Chief Executive Officer and director of El Paso from December 2015 to May 2017. 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.

Paul McMillan, age 71, 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 48, has been a director on the board of PSE since May 5, 2022. Ms. Rakow is currently the Chief Executive Officer of Hawaiian Airlines since October 2025. She previously served as Senior Vice President of Public Affairs & Sustainability from November 2021 to October 2025 and External Relations at Alaska Airlines from September 2017 to February 2021. Ms. Rakow also currently serves on the board of

 

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Hawaiian Airlines, Oneworld Alliance Environmental Sustainability Board, Cascadia Sustainable Aviation accelerator and Hawaii Business Roundtable. 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 49, 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.

Bertrand Valdman, age 63 has been a director on the boards of both Puget Energy and PSE since April 10, 2025. He currently serves as President and CEO of NorthStar Energy since 2018 and President and CEO of Optimum Energy since 2015. Mr. Valdman serves on the board of the Space Needle and is Chair of the Finance Committee since 2023 and served on the board of Anvil Corporation from 2022 to 2025. Mr. Valdman brings over 35 years of experience in the energy industry in various roles, including Executive Vice President, COO and CFO of Puget Sound Energy, and Managing Director of JP Morgan’s investment banking group in New York and Paris.

Steven Zucchet, age 60, 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 with respect to Puget Energy’s and PSE’s executive officers is included under “Business—Information About Our Executive Officers” of this prospectus.

Audit Committee

The Puget Energy and PSE boards of directors have both established an Audit Committee. Directors Paul McMillan, Adam Friedrichsen and Tom King are the members of the Audit Committee of Puget Energy. Directors Paul McMillan, Adam Friedrichsen, Tom King, 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 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.

 

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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. We also follow procedures that apply to purchases and sales of securities of each of Puget Energy and PSE. We believe our insider trading policy and procedures are 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 our Annual Report on Form 10-K for the year ended December 31, 2025.

 

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COMPENSATION DISCUSSION & ANALYSIS

Puget Sound Energy Executive Compensation

Compensation and Leadership Development Committee Interlocks and Insider Participation

The members of the Compensation and Leadership Development Committee (referred to as the “Committee”) of the boards of directors (the “boards”) of Puget Energy and PSE (referred to as the “Company” in this “Compensation Discussion & Analysis” section) are Jerry Divoky, Julia Hamm, Aaron Rubin, Bertrand Valdman and Steven Zucchet. No members of the Committee were officers or employees of the Company or any of its subsidiaries during 2025, 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 2025, 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”);

 

  •  

Lorna Luebbe, Senior Vice President, General Counsel and Chief Sustainability Officer;

 

  •  

Aaron A. August, Senior Vice President, Chief Customer and Transformation Officer; and

 

  •  

Matthew M. Steuerwalt, Senior Vice President External Affairs

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

Compensation Program Objectives

The Company’s executive compensation program has two main objectives:

 

  •  

Support sustained Company performance by attracting, retaining and motivating talented people to run the business.

 

  •  

Align incentive compensation payments with the achievement of short and long-term Company goals.

The Committee is responsible for developing and monitoring an executive compensation program and philosophy that achieves the foregoing objectives. In performing its duties, the Committee obtains information and advice on various aspects of the executive compensation program from its independent executive compensation consultant, Meridian Compensation Partners, LLC (“Meridian”). The Committee recommends to the board for approval both the salary level for our CEO, based on information provided by Meridian and other relevant factors described below, and the salary levels for the other executives, based on recommendations from our CEO. The Committee also recommends to the board for approval the annual and long-term incentive compensation plans for the executives, the setting of performance goals and the determination of target and actual awards under those plans, based on the compensation information provided by Meridian and other relevant factors.

In 2025, 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

 

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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 2025 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.

 

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Role of Market Data

The Company uses market data compiled by Meridian to inform its pay decisions on base salary, target annual incentives and target long-term incentive awards. Market data is obtained from both industry-specific surveys and proxy statements of public companies selected for inclusion in the Company’s custom executive compensation peer group. The market survey data were sourced from a select cut from the Willis Towers Watson 2024 Energy Services Survey, comprised of utility and other companies similar in size and scope of operations to PSE.

The 25 companies in the custom market survey cut for 2025 pay decisions are the same as those used for the 2024 pay decisions except that Cleco was removed due to its relatively smaller size:

 

Custom Survey Peer Group

     
1.   

Allete

     10.     

Evergy

     19.     

TXNM Energy

2.   

Alliant Energy

     11.     

Eversource Energy

     20.     

Portland General Electric

3.   

Ameren

     12.     

Hawaiian Electric Industries

     21.     

PPL

4.   

Atmos Energy

     13.     

NiSource

     22.     

Public Service Enterprise Group

5.   

Avista

     14.     

Northwestern Energy

     23.     

Southwest Gas

6.   

Black Hills

     15.     

Oncor

     24.     

Spire

7.   

CenterPoint

     16.     

OGE Energy

     25.     

WEC Energy Group

8.   

CMS Energy

     17.     

ONE Gas

     
9.   

Entergy

     18.     

Pinnacle West Capital

     

The market survey data from the companies above were supplemented with proxy statement data for select positions in the Company’s executive compensation peer group, which was comprised of 17 companies, all but one of which overlapped with the companies included in the market survey data. At the time of the benchmarking study, the median revenue of the executive compensation peers was $4.9 billion, which was comparable to PSE’s annual revenues of $4.8 billion for 2024. The proxy peer group was reviewed by Meridian to assess the continued relevancy of the companies and is the same as 2024.

 

Proxy Peer Group

           
1.    Alliant Energy      7.      Eversource Energy      13.      TXNM Energy
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

 

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executive’s expertise, level of performance, experience in the role and contribution relative to others in the organization.

Base Salary Adjustments for 2025

The Committee reviewed the base salaries of the Named Executive Officers in early 2025 and recommended base salary adjustments to the board. The board approved the Committee’s salary recommendations as shown in the table below. The adjustments were effective March 1, 2025. Base salaries for 2025 generally remained at the 50th percentile of market among the comparator group.

 

Name

   2024 Base Salary      2025 Base Salary      % Change  

Mary E. Kipp

   $ 1,112,400      $ 1,151,340        3.5 % 

Jamie L. Martin

     550,000        605,000        10.0  

Lorna Luebbe

     571,320        591,316        3.5  

Aaron A. August

     500,480        517,997        3.5  

Matthew M. Steuerwalt

     500,280        517,790        3.5  

2025 Annual Incentive Compensation

All PSE employees, including the Named Executive Officers, are eligible to participate in an annual incentive program 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 2025, 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 2025 were the same as those in 2024 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 all three must be satisfied for the safety measure to be treated as met. The three employee safety targets for 2025 were:

 

  •  

Field safety engagements, building on the 2024 safety goal of using the hazard reporting system. Field employees and their leadership will perform and document in-person field leader engagements. The target is a 95% or higher participation of each supervisor or manager and team completing 12 field engagements per year.

 

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  •  

Emergency preparedness training of all employees using Washington Division of Emergency Management videos and exercises. Three separate courses-Wildfire preparedness, Earthquake awareness, and preparedness for Energy outages. The target completion rate is no less than 95% of employee participation.

 

  •  

Driver safety of employees who use PSE pool or fleet vehicles. The target is a 90% or higher average from the driving performance system installed in company vehicles.

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 2025, 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, SAIDI, the board considered the measure met for incentive purposes based on PSE’s overall strong performance for 2025 and the noteworthy progress achieved at improving reliability and increasing efforts of wildfire risk mitigation. EBITDA finished at 103% of target, so funding was above 100%, as described further below.

2025 Annual Incentive Plan Results

For 2025, achievement of the Company goals under the annual incentive plan was at 103% of target for EBITDA. PSE EBITDA was $1,793 million, and SQI and safety achievement was determined to be 10 out of 10, leading to a funding level for 2025 of 106% for the annual incentive plan for the eligible Named Executive Officers.

Funding levels for 2025 at maximum, target, and threshold are shown in the table below:

Annual Incentive Performance Payout Scale and Actual Performance

 

Performance Measure (Dollars in Millions)

   2025 EBITDA      SQI, SAIDI& Safety*      Funding Level  

Maximum

   $ 1,914        10/10        120 % 

Target

     1,740        10/10        100  

Threshold

     1,566        6/10        55  

2025 Actual Performance

     1,793        10/10        106  
 
*

Combined SQI and Safety results of 6/10 or better and minimum EBITDA of $1,566 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 the CEO in 2025. The adjustments for individual performance are noted in the “Bonus” column of the Summary Compensation table and did not materially change

 

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the amounts resulting from 2025 achievement of the Company goals. The board approved the incentive amounts shown below, which will be paid in March 2026:

 

Name

   Target Incentive
(% of Base Salary)
    2025 Actual
Incentive Paid
     2025 Actual Incentive
(% of Base Salary)
 

Mary E. Kipp

     120 %    $ 1,596,310        138.6 % 

Jamie L. Martin

     65       454,361        75.1  

Lorna Luebbe

     65       444,084        75.1  

Aaron A. August

     65       374,745        72.3  

Matthew M. Steuerwalt

     65       388,865        75.1  

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.

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.

For the 2025-2027 cycle, the long-term incentive program is based on two metrics that are evaluated separately:

 

  •  

Return on Equity (“ROE”) with a 35% weighting; and

 

  •  

Total Return with a 65% weighting.

The 2023-2025 and 2024-2026 LTI Plan payments may range from 0% to 173% of target, depending on performance; while the 2025-2027 LTI Plan payments may range from 0% to 182% of target.

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.

2025-2027 Long-Term Incentive Plan Target Awards

Target LTI Plan awards for the 2025-2027 performance cycle were denominated in dollars, taking into account the executive’s level of responsibility within the Company and the corresponding market data.

 

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Ms. Kipp’s target LTI Plan grant was increased to $4,850,000. Target LTI Plan award amounts for the 2025-2027 performance cycle are shown in the following table:

 

Name

   Target Long Term Incentive ($)  

Mary E. Kipp

   $ 4,850,000  

Jamie L. Martin

     1,500,000  

Lorna Luebbe

     900,000  

Aaron A. August

     600,000  

Matthew M. Steuerwalt

     600,000  

Details of the target grants and expected values at target, threshold and maximum performance levels can be found in the “2025 Grants of Plan-Based Awards” table below.

Long-Term Incentive Plan Performance 2023-2025 Performance Cycle Results and Payouts

The 2023-2025 performance cycle has now ended. Amounts payable as a result of award vesting are shown in the following table:

 

  •  

The three performance measure categories all performed at target level or better. The environmental measure of reducing greenhouse gases was met at target. The Strategic Initiatives measure category had an overall funding of 125%. The Total Return measure finished at the maximum level of funding of 200%. Totaling each plan measure resulted in the payment of the following LTI Plan amounts:

 

Name

   Target Long Term Incentive ($)1      2023-2025
LTIP Paid2
 

Mary E. Kipp

   $ 3,875,000      $ 6,345,313  

Jamie L. Martin2

     900,000        1,473,750  

Lorna Luebbe

     600,000        982,500  

Aaron A. August

     525,000        859,688  

Matthew M. Steuerwalt

     500,000        818,750  
 
1

Target LTI Plan incentive is the dollar target level set in 2023 or upon employee hire.

2

In connection with Ms. Martin’s commencement of employment in 2024, she was eligible to participate in the 2023-2025 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 participated in the executive retirement plan during 2025, which is the Officer Restoration Benefit as part of the Deferred Compensation Plan for Key Employees. Additional information regarding the Officer Restoration Benefit and the Retirement Plan is shown in the “2025 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

 

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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 “2025 Nonqualified Deferred Compensation” table.

Post-Termination Benefits

The Committee periodically reviews existing change in control and severance arrangements of the peer group companies. In 2025, based on this review, the Committee established the Company’s Executive Severance Plan (“Severance Plan”), effective March 1, 2025, to provide executives with severance benefits in the event the Company involuntarily terminates an eligible executive’s employment without cause. Severance is subject to the execution of a release of claims. The Severance Plan has an initial term until December 31, 2027, and thereafter can be extended for additional one-year periods unless terminated at least 60 days prior to expiration of a current term. 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, 2025.

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.

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 2025. 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.

 

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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 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.

Summary Compensation Table

The following information is provided for the year ended December 31, 2025, (and for prior years where applicable) with respect to the Named Executive Officers during 2025. 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, 2025. 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  

Mary E. Kipp,

    2025     $ 1,136,147     $ 131,805     $ —      $ —      $ 7,809,817     $ —      $ 126,522     $ 9,204,291  

President and,

    2024       1,105,714       246,641       —        —        4,933,207       —        113,648       6,399,210  

Chief Executive Officer5

    2023       1,072,507       —        —        —        3,810,798       —        1,687,813       6,571,118  

Jamie L. Martin,

    2025       593,542       37,516       —        —        1,890,595       10,975       29,990       2,562,618  

Chief Financial Officer6

    2024       316,667       440,207       —        —        801,034       8,795       259,253       1,825,956  

 

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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  

Lorna Luebbe, SVP General

    2025       587,150       36,668       —        —        1,389,917       57,451       53,656       2,124,842  

Counsel and Chief

    2024       555,943       17,899       —        —        757,989       435       46,704       1,378,970  

Sustainability Officer7

    2023       493,371       —        —        —        373,044       5,269       32,201       903,885  

Aaron A. August, SVP

    2025       514,347       17,845       —        —        1,216,587       —        47,854       1,796,633  

Chief Customer and

    2024       492,127       281,360       —        —        707,351       —        36,107       1,516,945  

Transformation Officer8

    2023       177,727       390,000       —        —        393,931       —        248,932       1,210,590  

Matthew M. Steuerwalt,

    2025       514,143       32,108       —        —        1,175,507       —        49,073       1,770,831  

SVP External Affairs9

    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 ”2025 Annual Incentive Plan Results” for the Named Executive Officers for whom Bonus amounts are reported for 2025.

2.

For 2025, reflects annual cash incentive compensation paid under the 2025 Goals and Incentive Plan and cash incentive compensation paid under the LTI Plan for the 2023-2025 performance cycle. Cash incentive amounts were paid in early 2026 or deferred at the executive’s election. The 2025 Goals and Incentive Plan and the LTI Plan are described in further detail in the “Compensation Discussion and Analysis,” including the individual amounts paid to each Named Executive Officer in early 2026.

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 2025, updated interest rates relative to those used for 2024 have generally resulted in larger increases in value than in prior years. Information regarding these pension plans is set forth in further detail under “2025 Pension Benefits.” The change in pension value amounts for 2025 are: Ms. Kipp, $0; Ms. Martin, $10,975; Ms. Luebbe, $57,451; Mr. August, $0; and Mr. Steuerwalt, $0.

4.

All Other Compensation for 2025 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. 

Ms. Luebbe has worked at PSE since 2002 and became Senior Vice President General Counsel and Chief Sustainability Officer on December 1, 2022.

8.

Mr. August joined PSE and Puget Energy as Senior Vice President and Chief Customer and Transformation Officer on July 27, 2023.

9.

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  

Mary E. Kipp

   $ 9,370      $ 105,386      $ 11,766  

Jamie L. Martin

     10,000        15,177        4,813  

Lorna Luebbe

     —         44,694        8,962  

Aaron A. August

     1,275        40,167        6,412  

Matthew M. Steuerwalt

     —         37,956        11,117  
 
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.

2.

Includes Company contributions during 2025 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, $29,550; Ms. Martin, $15,177; Ms. Luebbe, $24,450; Mr. August, $29,550; and Mr. Steuerwalt, $29,550. Company contributions to the Deferred Compensation Plan are as follows: Ms. Kipp, $75,836; Ms. Martin, $0; Ms. Luebbe, $20,244; Mr. August, $10,617; and Mr. Steuerwalt, $8,406.

3.

Reflects the value of imputed income for life insurance and Company paid premiums on supplemental disability insurance for all Named Executive Officers.

 

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2025 Grants of Plan-Based Awards

The following table presents information regarding 2025 grants of non-equity annual incentive awards and LTI Plan awards, including, as applicable, the range of potential payouts for the awards.

 

            Estimated Future Payouts under Non-Equity
Incentive Plan Awards
 

Name

   Grant Date      Grant Target Value      Threshold      Target      Maximum  

Mary E. Kipp

              

Annual Incentive1

     1/1/2025         $ 759,884      $ 1,381,608      $ 2,763,216  

LTI Plan 2025-20272

     2/20/2025        4,850,000        2,425,000        4,850,000        9,700,000  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Jamie L. Martin

              

Annual Incentive1

     1/1/2025         $ 216,288      $ 393,250      $ 786,500  

LTI Plan 2025-20272

     2/20/2025        1,500,000        750,000        1,500,000        3,000,000  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Lorna Luebbe

              

Annual Incentive1

     1/1/2025         $ 211,395      $ 384,355      $ 768,711  

LTI Plan 2025-20272

     2/20/2025        900,000        450,000        900,000        1,800,000  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Aaron A. August

              

Annual Incentive1

     1/1/2025         $ 185,184      $ 336,698      $ 673,396  

LTI Plan 2025-20272

     2/20/2025        600,000        300,000        600,000        1,200,000  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Matthew M. Steuerwalt

              

Annual Incentive1

     1/1/2025         $ 185,110      $ 336,564      $ 673,127  

LTI Plan 2025-20272

     2/20/2025        600,000        300,000        600,000        1,200,000  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
 
1.

As described in the “Compensation Discussion and Analysis,” the 2025 Goals and Incentive Plan had dual funding thresholds in 2025 of $1,566.0 million EBITDA and SQI performance of 6/10. Payment would be $0 if either threshold is not met. The threshold estimate assumes $1,566.0 million EBITDA and SQI/Safety measure performance at 6/10. The target estimate assumes $1,740.0 million EBITDA and SQI/Safety measure performance at 10/10. The maximum estimate assumes financial results at funding maximum of $1,914.0 million EBITDA or higher, SQI/Safety measure performance at 10/10 and individual incentive award maximum of 200% of target.

2.

As described in the “Compensation Discussion and Analysis,” LTI Plan grants for the 2025-2027 performance cycle were allocated to two measures. The ROE measure (35% weighting) funds at 50% at threshold, 100% at target and 200% at maximum; the Total Return measure (65% 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 50%, 100%, and 200%, respectively.

 

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2025 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
Benefit1
     Payments
During Last
Fiscal Year
 

Mary E. Kipp2

   Retirement Plan      6.3      $ —       $ —   
   Restoration Benefit      6.3        —         —   

Jamie L. Martin

   Retirement Plan      1.6        19,770        —   
   Restoration Benefit      1.6        —         —   

Lorna Luebbe

   Retirement Plan      23.2        503,468        —   
   Restoration Benefit      23.2        —         —   

Aaron A. August

   Retirement Plan      2.4        —         —   
   Restoration Benefit      2.4        —         —   

Matthew M. Steuerwalt

   Retirement Plan      2.3        —         —   
   Restoration Benefit      2.3        —         —   
 
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, 2025, 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 5.65%, and the post-retirement mortality assumption is based on the 2026 417(e) unisex mortality table. Annuity benefits are converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 4.81%, 5.35%, and 5.69% (the 24-month average of the underlying rates as of September 2025). These assumptions are consistent with the ones used for the Retirement Plan for financial reporting purposes for 2025. 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, 2024, for the benefits earned as of that date using the assumptions used for financial reporting purposes for 2024. These assumptions included assumed cash balance interest credits of 4.0%, a discount assumption of 5.80% and post-retirement mortality assumption based on the 2025 417(e) unisex mortality table. Annuity benefits were 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). Other assumptions used to determine the value as of December 31, 2024, were the same as those used for December 31, 2025.

2.

None of the Named Executive Officers have SERP benefits as that plan was closed prior to their joining PSE, or promotion to officer level. 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, 2025 these 401(k) accounts had values of: Ms. Kipp, $91,773, Mr. August, $25,469 and Mr. Steuerwalt, $20,197. 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, 2025 are: Ms. Kipp, $351,974; Ms. Luebbe, $36,267. Mr. August, $10,963; and Mr. Steuerwalt $8,680. Ms. Martin’s first Officer Restoration account contribution is expected to be made in 2026.

 

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Retirement Plan

Under the Retirement Plan, the Company’s eligible employees hired prior to January 1, 2014 (prior to December 12, 2014, in the case of IBEW-represented employees), including the participating Named Executive Officers, accrue benefits in accordance with a cash balance formula, beginning on the later of their date of hire or March 1, 1997. Under this formula, for each calendar year after 1996, age-weighted pay credits are allocated to a bookkeeping account (a Cash Balance Account) for each participant. The pay credits range from 3% to 8% of eligible compensation. Non-represented and UA-represented employees hired on or after January 1, 2014, and IBEW-represented employees hired on or after December 12, 2014, will receive pay credits equal to 4% (rather than the age-based pay credit described above), which non-represented and IBEW-represented employees may choose to have contributed to the Company’s 401(k) plan, rather than credited under the Retirement Plan. Eligible compensation generally includes base salary and bonuses (other than bonuses paid under the LTI Plan and signing, retention and similar bonuses), up to the limit imposed by the Internal Revenue Code. For 2025, the limit was $350,000. For 2026, the limit is $360,000. 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 2025 and 2026, 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, 2025, 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).

 

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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.

2025 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 2025 and year-end account balances under the Deferred Compensation Plan.

 

Name

   Executive
Contributions
in 20251
     Registrant
Contributions in
20252
     Aggregate
Earnings
in 20253
     Aggregate
Withdrawals/
Distributions
     Aggregate
Balance at December
31, 20254
 

Mary E. Kipp

   $ —       $ 75,836      $ 436,108      $ —       $ 3,935,977  

Jamie L. Martin

     —         —         —         —         —   

Lorna Luebbe

     —         20,244        1,222        —         36,267  

Aaron A. August

     —         10,617        345        —         10,963  

Matthew M. Steuerwalt

     —         8,406        273        —         8,680  
 
1.

The amount in this column reflects elective deferrals by the executive of salary, annual incentive compensation or LTI Plan awards paid in 2025. Deferred salary amounts are: Ms. Kipp, $0; 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 Executive Officers. The amounts are also included in the applicable column of the Summary Compensation Table for 2025.

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 2025.

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 2025, 2024, and 2023.

 

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Name

   Reported for 2025      Reported for 2024      Reported for 2023  

Mary E. Kipp

   $ —       $ 68,111      $ 114,816  

Jamie L. Martin

     —         —         —   

Lorna Luebbe

     —         —         1,132  

Aaron A. August

     —         —         —   

Matthew M. Steuerwalt

     —         —         —   

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 2025 calendar year returns of these tracking funds were:

 

Tracking Fund

   Return  

Vanguard Total Bond Market Index

     7.17 % 

Vanguard 500 Index

     17.83  

Vanguard Money Market Index

     4.22  

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

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

 

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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, based on performance through the 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.

Severance Plan

If the Company involuntarily terminates a Named Executive Officer’s employment without cause (and other than by reason of the executive’s death or disability), the executive will be eligible to receive a lump sum cash payment of the following amounts under the Severance Plan, subject to the executive’s execution (and non-revocation) of a release of claims:

 

  •  

Base salary (multiple of 1.5 for the Chief Executive Officer, 1.25 for the Chief Financial Officer and 1.0 for the other Named Executive Officers);

 

  •  

1.0 times the executive’s annual target incentive bonus for the year of termination, prorated for the number of full months employed during the year of termination; and

 

  •  

Amount equal to 12 times the monthly COBRA premium in effect for the executive on the date of termination.

Each Named Executive Officer is also eligible for 12 months of outplacement services or, in the Company’s discretion, a lump sum payment of $25,000.

 

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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, 2025. 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:

 

    Upon Change in
Control (and awards not
assumed or substituted)
    After Change in Control
Involuntary Termination
w/o Cause or for Good
Reason
    Involuntary
Termination
without cause1
    Retirement     Disability     Death  

Mary E. Kipp

           

Long Term Incentive Plan

  $ 11,127,684     $ 11,127,684     $ —      $ 11,127,684     $ 11,127,684     $ 11,127,684  

Supplemental Life Insurance

    —        —        —        —        —        4,465,896  

Severance Plan

    —        —        1,808,530       —        —        —   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Estimated Incremental Value

  $ 11,127,684     $ 11,127,684     $ 1,808,530     $ 11,127,684     $ 11,127,684     $ 15,593,580  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Jamie L. Martin

           

Long Term Incentive Plan

  $ 2,807,925     $ 2,807,925     $ —      $ —      $ 2,807,925     $ 2,807,925  

Supplemental Life Insurance

    —        —        —        —        —        1,396,500  

Severance Plan

    —        —        818,930       —        —        —   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Estimated Incremental Value

  $ 2,807,925     $ 2,807,925     $ 818,930     $ —      $ 2,807,925     $ 4,204,425  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Lorna Luebbe

           

Long Term Incentive Plan

  $ 1,908,881     $ 1,908,881     $ —      $ 1,908,881     $ 1,908,881     $ 1,908,881  

Supplemental Life Insurance

    —        —        —        —        —        1,360,027  

Severance Plan

    —        —        653,996       —        —        —   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Estimated Incremental Value

  $ 1,908,881     $ 1,908,881     $ 653,996     $ 1,908,881     $ 1,908,881     $ 3,268,908  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Aaron A. August

           

Long Term Incentive Plan

  $ 1,477,275     $ 1,477,275     $ —      $ —      $ 1,477,275     $ 1,477,275  

Supplemental Life Insurance

    —        —        —        —        —        1,191,393  

Severance Plan

    —        —        580,677       —        —        —   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Estimated Incremental Value

  $ 1,477,275     $ 1,477,275     $ 580,677     $ —      $ 1,477,275     $ 2,668,668  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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    Upon Change in
Control (and awards not
assumed or substituted)
    After Change in Control
Involuntary Termination
w/o Cause or for Good
Reason
    Involuntary
Termination
without cause1
    Retirement     Disability     Death  

Matthew M. Steuerwalt

           

Long Term Incentive Plan

  $ 1,436,338     $ 1,436,338     $ —      $ —      $ 1,436,338     $ 1,436,338  

Supplemental Life Insurance

    —        —        —        —        —        1,190,917  

Severance Plan

    —        —        580,470       —        —        —   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Estimated Incremental Value

  $ 1,436,338     $ 1,436,338     $ 580,470     $ —      $ 1,436,338     $ 2,627,255  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
 
1.

Amount reported for each Named Executive Officer is the sum of (i) the applicable base salary multiplier for the Name Executive Officer; (ii) $56,520 of COBRA premiums for Ms. Kipp and $37,680 for the other Named Executive Officers (based on a maximum monthly COBRA premium of $3,140); and (iii) $25,000 in lieu of outplacement services.

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 2025, our last completed fiscal year:

 

  •  

The annual total compensation of our CEO reported in the 2025 Summary Compensation Table, was $9,204,291.

 

  •  

The median of the annual total compensation of all our employees (excluding our CEO) was $169,014.

As a result, for 2025 the ratio of annual total compensation of our Chief Executive Officer to the median of our annual total compensation of all employees was 55:1.

We identified our median employee by examining the total cash compensation we paid during 2025 to all individuals, excluding our CEO, who were employed by us on December 31, 2025, which totaled approximately 3,412 individuals, all located in the United States (as reported in the “Business” section of this prospectus), 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 2025, we calculated annual total compensation for such employee for 2025 using the same methodology we use for our named executive officers as set forth in the 2025 Summary Compensation Table in accordance with the requirements of Item 402 (c)(2)(x) of Regulation S-K. Annual total compensation for 2025 for our median employee included annual salary, annual incentives, and company contributions towards benefits including retirement. Annual total compensation for 2025 for our CEO consists of the amount reported in the “Total” column of our 2025 Summary Compensation Table.

 

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Director Compensation for Fiscal Year 2025

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 2025 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: Jerry Divoky, Adam Friedrichsen, Grant Hodgkins, Chris Parker, Aaron Rubin, and Steven Zucchet.

As described in further detail below, the Company’s non-employee director compensation program in 2025 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 Armstrong2

   $ 211,500      $ —       $ 211,500  

Christine Gregoire

     182,000        —         182,000  

Julia Hamm

     182,800        —         182,800  

Thomas King

     187,800        —         187,800  

Paul McMillan

     202,800        —         202,800  

Diana Rakow

     202,800        —         202,800  

Bertrand Valdman

     —         161,500        161,500  
 
1.

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

2.

Scott Armstrong retired from the boards and as a member of the applicable board committees on which he served effective September 30, 2025.

Non-employee Director Compensation Program

The 2025 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 2025 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 2025, 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

 

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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.

 

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Security Ownership of Directors, Executive Officers and Certain Beneficial Owners

The following table shows the number of shares of common stock beneficially owned as of May 14, 2026, 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 the “Compensation Discussion & Analysis” section of this prospectus owns any of the outstanding shares of common stock of Puget Energy or PSE. 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 May 14, 2026.

Beneficial Ownership Table of Puget Energy and PSE

 

     Number of Beneficially
Owned Shares
 

Name

   Puget Energy     Puget Sound Energy  

Puget Equico LLC and affiliates

     200 1, 2      —   

Puget Energy

     —        85,903,791 3 
 

 

1

Information presented above and in this footnote is based on Amendment No. 2 to Schedule 13D/A filed on February 13, 2009 (the Schedule 13D) by, among others, Puget Equico, Puget Intermediate Holdings Inc. (“Puget Intermediate”), Puget Holdings and together with Puget Intermediate, the “Parent Entities”), 6860141 Canada Inc. as trustee for BCIMC, 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”), OMERS, PGGM Vermogensbeheer B.V. (“PGGM”), BCIMC and PIP2PX, the “Investors.” Puget Equico is a wholly-owned subsidiary of Puget Intermediate. Puget Intermediate is a wholly-owned subsidiary of Puget Holdings and the Investors are the direct or indirect owners of Puget Holdings. The Parent Entities and the Investors are the direct or indirect owners of Puget Equico. Although the Parent Entities and the Investors do not own any shares of Puget Energy directly, Puget Equico, the Parent Entities and the Investors may be deemed to be members of a “group,” within the meaning of Section 13(d)(3) of the Exchange Act. 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 March 31, 2026:

 

  •  

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 BCIMC is 750 Pandora Ave, Victoria, British Columbia, Canada V8W 0E4.

 

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  •  

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.

3 

Pursuant 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.

 

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Transactions with Related Persons

The boards of Puget Energy and PSE 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 Audit 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, Bertrand Valdman 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.

 

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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 prospectus as related-person transactions. Mr. Valdman 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. Valdman, 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 the “Management” section of this prospectus.

 

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PRIVATE PLACEMENT

On March 27, 2026, we issued $450 million in aggregate principal amount of the Series A original notes and $450 million in aggregate principal amount of the Series B original notes to the initial purchasers of those notes and received proceeds that after deducting expenses and commissions represented an aggregate of approximately $887.7 million in net proceeds. We issued the original notes to the initial purchasers in transactions exempt from or not subject to registration under the Securities Act. The initial purchasers then offered and resold the original notes to qualified institutional buyers in compliance with Rule 144A or non-U.S. persons in compliance with Regulation S under the Securities Act.

 

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THE EXCHANGE OFFERS

Purpose of the Exchange Offers

In connection with the sale of the original notes, we entered into a registration rights agreement with the initial purchasers of the original notes. In that agreement, we agreed to file a registration statement relating to an offer to exchange the original notes for the exchange notes. We also agreed to use our best efforts to have the SEC declare the registration statement effective 180 days after the issuance of the Notes. We are offering the exchange notes under this prospectus in exchange offers for the original notes to satisfy our obligations under the registration rights agreement. We refer to our offers to exchange the exchange notes for the original notes as the “exchange offers.”

Resale of Exchange Notes

Based on interpretations of the SEC staff in no-action letters issued to third parties, we believe that each exchange note issued in the exchange offers may be offered for resale, resold and otherwise transferred by you without compliance with the registration and prospectus delivery requirements of the Securities Act if:

 

  •  

you are not our affiliate within the meaning of Rule 405 under the Securities Act;

 

  •  

you are acquiring such exchange notes in the ordinary course of your business;

 

  •  

you do not intend to participate in the distribution of exchange notes; and

 

  •  

you are not a broker-dealer and are not engaged in, and do not intend to engage in, the distribution of the exchange notes.

If you tender your original notes in the exchange offers with the intention of participating in any manner in a distribution of the exchange notes, you:

 

  •  

cannot rely on such interpretations of the SEC staff; and

 

  •  

must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a secondary resale transaction of the exchange notes.

Unless an exemption from registration is otherwise available, the resale by any security holder intending to distribute exchange notes should be covered by an effective registration statement under the Securities Act containing the selling security holder’s information required under the Securities Act. This prospectus may be used for an offer to resell, a resale or other retransfer of exchange notes only as specifically described in this prospectus. Each broker-dealer that receives exchange notes for its own account in exchange for original notes, where that broker-dealer acquired such original notes as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. Please read “Plan of Distribution” for more details regarding the transfer of exchange notes.

Terms of the Exchange Offers

Upon the terms and subject to the conditions described in this prospectus and in the letter of transmittal, we will accept for exchange any original notes properly tendered and not withdrawn prior to the applicable expiration date of the exchange offers. We will issue $1,000 principal amount of exchange notes in exchange for each $1,000 principal amount of original notes surrendered under the exchange offers and accepted by us. Original notes may be tendered only in integral multiples of $1,000, subject to a $2,000 minimum, and untendered original notes may only be in a minimum denomination of $2,000 and integral multiples of $1,000.

The terms of the exchange notes are identical in all material respects to those of the original notes, except the exchange notes will not be subject to transfer restrictions and holders of the exchange notes, with limited exceptions, will have no registration rights. Also, the exchange notes will not include provisions contained in the original notes

 

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that required payment of liquidated damages in the event we failed to satisfy our registration obligations with respect to the original notes. The exchange notes will be issued under and entitled to the benefits of the same indenture that authorized the issuance of the original notes.

The exchange offers are not conditioned on any minimum aggregate principal amount of original notes being tendered for exchange.

As of the date of this prospectus, $900 million principal amount of original notes are outstanding. This prospectus and the letter of transmittal are being sent to all registered holders of the original notes. There will be no fixed record date for determining registered holders of the original notes entitled to participate in the exchange offers.

We intend to conduct the exchange offers in accordance with the provisions of the registration rights agreement, the applicable requirements of the Securities Act and the Exchange Act, and the SEC rules and regulations. Original notes that are not tendered for exchange in the exchange offers:

 

  •  

will remain outstanding,

 

  •  

will continue to accrue interest, and,

 

  •  

will be entitled to the rights and benefits that holders have under the indenture relating to the notes and, under limited circumstances, the registration rights agreement.

We will be deemed to have accepted for exchange properly tendered original notes when we have given oral or written notice of the acceptance to the exchange agent and complied with the applicable provisions of the registration rights agreement. The exchange agent will act as agent for the tendering holders for the purposes of receiving the exchange notes from us. We will issue the exchange notes promptly after the expiration of the exchange offers.

If you tender original notes in the exchange offers, you will not be required to pay brokerage commissions or fees or, subject to the instructions in the letter of transmittal, transfer taxes with respect to the exchange of original notes. We will pay all charges and expenses, other than certain applicable taxes described below, in connection with the exchange offers. It is important that you read “The Exchange Offers—Fees and Expenses” for more details about fees and expenses incurred in the exchange offers.

We will return any original notes that we do not accept for exchange for any reason without expense to the tendering holder promptly after the expiration or termination of the exchange offers.

The exchange offers are not subject to any federal or state regulatory requirements or approvals other than securities laws and blue sky laws.

Expiration Date

Each of the exchange offers will expire at 5:00 p.m., New York City time, on    , 2026, unless at our sole discretion we extend the offer(s).

Extensions, Delay in Acceptance, Termination or Amendment

We expressly reserve the right, at any time or at various times, to extend the period of time during which the relevant exchange offer(s) is open. In the event of an extension of the relevant exchange offer(s), we may delay acceptance for exchange of any applicable original notes by giving oral or written notice of the extension to their holders. During any such extensions, all applicable original notes you have previously tendered will remain subject to the exchange offer for that series, and we may accept them for exchange.

To extend the exchange offer(s), we will notify the exchange agent orally or in writing (if oral, to be promptly confirmed in writing) of any extension. We also will make a public announcement of the extension no later than 9:00 a.m., New York City time, on the next business day after the applicable previously scheduled expiration date.

 

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If any of the conditions described below under “The Exchange Offers—Conditions to the Exchange Offers” have not been satisfied with respect to such exchange offer, we reserve the right, at our sole discretion:

 

  •  

to extend such exchange offer,

 

  •  

to delay accepting for exchange any applicable original notes, or

 

  •  

to terminate such exchange offer.

We will give oral or written notice (if oral, to be promptly confirmed in writing) of such extension, delay or termination to the exchange agent. Subject to the terms of the registration rights agreement, we also reserve the right to amend the terms of the exchange offers in any manner.

Any such extension, delay in acceptance, termination or amendment will be followed as promptly as practicable by oral or written notice thereof to the registered holders of the original notes. If we amend either of the exchange offers in a manner that we determine to constitute a material change, including the waiver of a material condition, we will promptly disclose that amendment by means of a prospectus supplement and we will extend the offer period if necessary so that at least five business days remain in the offer period following notice of the material change.

We will distribute the prospectus supplement to the registered holders of the original notes. Depending on the significance of the amendment and the manner of disclosure to the registered holders, we may extend, pursuant to the terms of the registration rights agreement and the requirements of federal securities law, either of the exchange offers if such exchange offer would otherwise expire during such period.

Without limiting the manner in which we may choose to make public announcements of any extension, delay in acceptance, termination or amendment of any of the exchange offers, we have no obligation to publish, advertise or otherwise communicate any such public announcement, other than by making a timely release to an appropriate news agency.

Conditions to the Exchange Offers

Notwithstanding any other provision of the exchange offers and subject to the terms of the registration rights agreement, we will not be required to accept for exchange, or to issue exchange notes in exchange for, any original notes and may terminate or amend either of the exchange offers, if at any time before the applicable expiration date of either of the exchange offers there is a question as to whether such exchange offer is permitted by applicable law.

In addition, we will not be obligated to accept for exchange the original notes of any holder that has not made to us:

 

  •  

the representations described under “The Exchange Offers—Procedures for Tendering” and “Plan of Distribution,” and

 

  •  

such other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to make available to us an appropriate form for registering the exchange notes under the Securities Act.

We expressly reserve the right to amend or terminate either of the exchange offers notwithstanding the satisfaction of the foregoing, and to reject for exchange any original notes upon the occurrence of any of the conditions to the exchange offers specified above. We will give oral or written notice of any extension, non-acceptance, termination or amendment to the holders of the original notes as promptly as practicable.

 

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These conditions are for our sole benefit, and we may assert them or waive them in whole or in part at any time or at various times at our sole discretion. Our failure at any time to exercise any of these rights will not mean that we have waived our rights. Each right will be deemed an ongoing right that we may assert at any time or at various times. If we waive a condition, we may be required in order to comply with applicable securities laws, to extend the expiration date of the applicable exchange offer(s).

In addition, we will not accept for exchange any original notes tendered, and will not issue exchange notes in exchange for any such original notes, if at such time any stop order has been threatened or is in effect with respect to the registration statement of which this prospectus constitutes a part or the qualification of the indenture relating to the notes under the Trust Indenture Act of 1939.

Absence of Dissenters’ Rights of Appraisal

Holders of the original notes do not have any dissenters’ rights of appraisal in connection with the exchange offers.

Procedures for Tendering

How to Tender Generally

Only a holder of the original notes as determined by our records or those of the trustee or DTC may tender original notes in the exchange offers. To tender in the exchange offers, a holder must either (1) comply with the procedures for physical tender or (2) comply with the automated tender offer program procedures of DTC, described below.

To complete a physical tender, a holder must:

 

  •  

complete, sign and date the letter of transmittal or a facsimile of the letter of transmittal,

 

  •  

have the signature on the letter of transmittal guaranteed if the letter of transmittal so requires,

 

  •  

mail or deliver the letter of transmittal or facsimile to the exchange agent prior to the applicable expiration date, and

 

  •  

deliver the original notes to the exchange agent prior to the applicable expiration date or comply with the guaranteed delivery procedures described below.

To be tendered effectively, the exchange agent must receive any physical delivery of the letter of transmittal and other required documents at its address provided above under “Prospectus Summary—The Exchange Agent” prior to the applicable expiration date.

To complete a tender through DTC’s automated tender offer program, the exchange agent must receive, prior to the applicable expiration date, a timely confirmation of book-entry transfer of such original notes into the exchange agent’s account at DTC according to the procedure for book-entry transfer described below or a properly transmitted agent’s message.

The tender by a holder that is not withdrawn prior to the applicable expiration date and our acceptance of that tender will constitute an agreement between the holder and us in accordance with the terms and subject to the conditions described in this prospectus and in the letter of transmittal.

THE METHOD OF DELIVERY OF ORIGINAL NOTES, THE LETTER OF TRANSMITTAL AND ALL OTHER REQUIRED DOCUMENTS TO THE EXCHANGE AGENT IS AT YOUR ELECTION AND RISK. RATHER THAN MAIL THESE ITEMS, WE RECOMMEND THAT YOU USE AN OVERNIGHT OR HAND DELIVERY SERVICE. IN ALL CASES, YOU SHOULD ALLOW

 

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SUFFICIENT TIME TO ENSURE DELIVERY TO THE EXCHANGE AGENT BEFORE THE APPLICABLE EXPIRATION DATE. YOU SHOULD NOT SEND THE LETTER OF TRANSMITTAL OR ORIGINAL NOTES TO US. YOU MAY REQUEST YOUR BROKER, DEALER, COMMERCIAL BANK, TRUST COMPANY OR OTHER NOMINEE TO EFFECT THE ABOVE TRANSACTIONS FOR YOU.

How to Tender if You Are a Beneficial Owner

If you beneficially own original notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender those notes, you should contact the registered holder as soon as possible and instruct the registered holder to tender on your behalf. If you are a beneficial owner and wish to tender on your own behalf, you must, prior to completing and executing the letter of transmittal and delivering your original notes, either:

 

  •  

make appropriate arrangements to register ownership of the original notes in your name, or

 

  •  

obtain a properly completed bond power from the registered holder of your original notes.

The transfer of registered ownership may take considerable time and may not be completed prior to the applicable expiration date.

Signatures and Signature Guarantees

You must have signatures on a letter of transmittal or a notice of withdrawal described below under “The Exchange Offers—Withdrawal of Tenders” guaranteed by an eligible institution unless the original notes are tendered:

 

  •  

by a registered holder who has not completed the box entitled “Special Issuance Instructions” or

 

  •  

“Special Delivery Instructions” on the letter of transmittal, or

 

  •  

for the account of an eligible institution.

An “eligible institution” is a member firm of a registered national securities exchange, a commercial bank or trust company having an office or correspondent in the United States, or an eligible guarantor institution within the meaning of Rule 17Ad-15 under the Exchange Act, that is a member of one of the recognized signature guarantee programs identified in the letter of transmittal.

When Endorsements or Bond Powers Are Needed

If a person other than the registered holder of any original notes signs the letter of transmittal, the original notes must be endorsed or accompanied by a properly completed bond power. The registered holder must sign the bond power as the registered holder’s name appears on the original notes. An eligible institution must guarantee that signature.

If the letter of transmittal or any original notes or bond powers are signed by trustees, executors, administrators, guardians, attorneys-in-fact, or officers of corporations or others acting in a fiduciary or representative capacity, those persons should so indicate when signing. Unless we waive this requirement, they also must submit evidence satisfactory to us of their authority to deliver the letter of transmittal.

Tendering Through DTC’s Automated Tender Offer Program

The exchange agent and DTC have confirmed that any financial institution that is a participant in DTC’s system may use DTC’s automated tender offer program to tender. Accordingly, participants in the program may, instead of physically completing and signing the letter of transmittal and delivering it to the exchange agent,

 

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transmit their acceptance of either of the exchange offers electronically. They may do so by causing DTC to transfer the original notes to the exchange agent in accordance with its procedures for transfer. DTC will then send an agent’s message to the exchange agent.

An agent’s message is a message transmitted by DTC to and received by the exchange agent and forming part of the book-entry confirmation, stating that:

 

  •  

DTC has received an express acknowledgment from a participant in DTC’s automated tender offer program that is tendering original notes that are the subject of such book-entry confirmation;

 

  •  

the participant has received and agrees to be bound by the terms of the letter of transmittal, or, in the case of an agent’s message relating to guaranteed delivery, the participant has received and agrees to be bound by the applicable notice of guaranteed delivery; and

 

  •  

we may enforce the agreement against such participant.

Determinations Under the Exchange Offers

We will determine at our sole discretion all questions as to the validity, form, eligibility, time of receipt, acceptance of tendered original notes and withdrawal of tendered original notes. Our determination will be final and binding. We reserve the absolute right to reject any original notes not properly tendered or any original notes our acceptance of which, in the opinion of our counsel, might be unlawful. Our interpretation of the terms and conditions of the exchange offers, including the instructions in the letter of transmittal, will be final and binding on all parties.

Unless waived, any defects or irregularities in connection with tenders of original notes must be cured within such time as we determine. Neither we, the exchange agent nor any other person will be under any duty to give notification of defects or irregularities with respect to tenders of original notes, nor will we or those persons incur any liability for failure to give such notification. Tenders of original notes will not be deemed made until such defects or irregularities have been cured or waived. Any original notes received by the exchange agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned to the tendering holder, unless otherwise provided in the letter of transmittal, promptly following the applicable expiration date.

When We Will Issue Exchange Notes

In all cases, we will issue exchange notes for original notes that we have accepted for exchange in the exchange offers only after the exchange agent timely receives:

 

  •  

original notes or a timely book-entry confirmation of transfer of such original notes into the exchange agent’s account at DTC, and

 

  •  

a properly completed and duly executed letter of transmittal and all other required documents or a properly transmitted agent’s message.

Return of Original Notes Not Accepted or Exchanged

If we do not accept any tendered original notes for exchange for any reason described in the terms and conditions of the exchange offers or if original notes are submitted for a greater principal amount than the holder desires to exchange, we will return the unaccepted or non-exchanged original notes without expense to their tendering holder. In the case of original notes tendered by book-entry transfer into the exchange agent’s account at DTC according to the procedures described below, such non-exchanged original notes will be credited to an account maintained with DTC. These actions will occur promptly after the expiration or termination of the exchange offers.

 

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Your Representations to Us

By signing or agreeing to be bound by the letter of transmittal, you will represent to us that, among other things:

 

  •  

you are acquiring the exchange notes in the ordinary course of your business;

 

  •  

you are not engaged in, and do not intend to engage in, and you have no arrangement or understanding with any person to participate in, the distribution of the original notes or the exchange notes within the meaning of the Securities Act;

 

  •  

you are not our affiliate, as defined in Rule 405 under the Securities Act;

 

  •  

if you are not a broker-dealer, you are not engaged in and do not intend to engage in the distribution of the exchange notes; and

 

  •  

if you are a broker-dealer or you are using the exchange offers to participate in the distribution of exchange notes, you agree and acknowledge that you could not under Commission policy, rely on certain no-action letters, and you must comply with the registration and prospectus delivery requirements in connection with a secondary resale transaction.

Book-Entry Transfer

The exchange agent will make a request to establish an account with respect to the original notes at DTC for purposes of the exchange offers promptly after the date of this prospectus. Any financial institution participating in DTC’s system may make book-entry delivery of original notes by causing DTC to transfer such original notes into the exchange agent’s account at DTC in accordance with DTC’s procedures for transfer. If you are unable to deliver confirmation of the book-entry tender of your original notes into the exchange agent’s account at DTC or all other documents required by the letter of transmittal to the exchange agent on or prior to the applicable expiration date, you must tender your original notes according to the guaranteed delivery procedures described below.

Guaranteed Delivery Procedures

If you wish to tender your original notes but they are not immediately available or if you cannot deliver your original notes, the letter of transmittal or any other required documents to the exchange agent, or comply with the applicable procedures under DTC’s automated tender offer program prior to the applicable expiration date, you may tender if:

 

  •  

the tender is made through a member firm of a registered national securities exchange, a commercial bank or trust company having an office or correspondent in the United States, or an eligible guarantor institution;

 

  •  

prior to the applicable expiration date, the exchange agent receives from such member firm of a registered national securities exchange, commercial bank or trust company having an office or correspondent in the United States, or eligible guarantor institution either a properly completed and duly executed notice of guaranteed delivery by facsimile transmission, mail or hand delivery or a properly transmitted agent’s message and notice of guaranteed delivery:

 

  •  

stating your name and address, the registered number(s) of your original notes and the principal amount of original notes tendered;

 

  •  

stating that the tender is being made thereby; and

 

  •  

guaranteeing that, within three New York Stock Exchange trading days after the applicable expiration date, the letter of transmittal or facsimile thereof or agent’s message in lieu thereof, together with the original notes or a book-entry confirmation, and any other documents required by the letter of transmittal will be deposited by the eligible guarantor institution with the exchange agent; and

 

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  •  

the exchange agent receives such properly completed and executed letter of transmittal or facsimile or agent’s message, as well as all tendered original notes in proper form for transfer or a book-entry confirmation, and all other documents required by the letter of transmittal, within three New York Stock Exchange trading days after the applicable expiration date.

Upon request to the exchange agent, the exchange agent will send a notice of guaranteed delivery to you if you wish to tender your original notes according to the guaranteed delivery procedures described above.

Withdrawal of Tenders

Except as otherwise provided in this prospectus, you may withdraw your tender at any time prior to 5:00 p.m., New York City time, on the applicable expiration date.

For a withdrawal to be effective:

 

  •  

the exchange agent must receive a written notice of withdrawal at one of the addresses listed above under “Prospectus Summary—The Exchange Agent,” and

 

  •  

the withdrawing holder must comply with the appropriate procedures of DTC’s automated tender offer program.

Any notice of withdrawal must:

 

  •  

specify the name of the person who tendered the original notes to be withdrawn,

 

  •  

identify the original notes to be withdrawn, including the registration number or numbers and the principal amount of such original notes,

 

  •  

be signed by the person who tendered the original notes in the same manner as the original signature on the letter of transmittal used to deposit those original notes or be accompanied by documents of transfer sufficient to permit the trustee to register the transfer in the name of the person withdrawing the tender, and

 

  •  

specify the name in which such original notes are to be registered, if different from that of the person who tendered the original notes.

If original notes have been tendered under the procedure for book-entry transfer described above, any notice of withdrawal must specify the name and number of the account at DTC to be credited with the withdrawn original notes and otherwise comply with the procedures of DTC.

We will determine all questions as to the validity, form, eligibility and time of receipt of notice of withdrawal, and our determination shall be final and binding on all parties. We will deem any original notes so withdrawn not to have been validly tendered for exchange for purposes of the exchange offers.

Any original notes that have been tendered for exchange but that are not exchanged for any reason will be returned to their holder without cost to the holder, or, in the case of original notes tendered by book-entry transfer into the exchange agent’s account at DTC according to the procedures described above, such original notes will be credited to an account maintained with DTC for the original notes. This return or crediting will take place promptly after withdrawal, rejection of tender or termination of the exchange offers. You may retender properly withdrawn original notes by following one of the procedures described under “The Exchange Offers—Procedures for Tendering” at any time on or prior to 5:00 p.m., New York City time, on the applicable expiration date.

 

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Fees and Expenses

We will bear the expenses of soliciting tenders. The principal solicitation is being made by mail; however, we may make additional solicitation by facsimile, email, telephone or in person by our officers and regular employees and those of our affiliates.

We have not retained any dealer-manager in connection with the exchange offers and will not make any payments to broker-dealers or others soliciting acceptances of the exchange offers. We will, however, pay the exchange agent reasonable and customary fees for its services and reimburse it for its related reasonable out-of- pocket expenses. We may also pay brokerage houses and other custodians, nominees and fiduciaries the reasonable out-of-pocket expenses incurred by them in forwarding copies of this prospectus, letters of transmittal and related documents to the beneficial owners of the original notes and in handling or forwarding tenders for exchange.

We will pay the cash expenses to be incurred in connection with the exchange offers. They include:

 

  •  

SEC registration fees for the exchange notes,

 

  •  

fees and expenses of the exchange agent and the trustee,

 

  •  

accounting and legal fees,

 

  •  

printing costs, and

 

  •  

related fees and expenses.

Transfer Taxes

If you tender your original notes for exchange, you will not be required to pay any transfer taxes. We will pay all transfer taxes, if any, applicable to the exchange of original notes in the exchange offers. The tendering holder will, however, be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if:

 

  •  

certificates representing exchange notes or original notes for principal amounts not tendered or accepted for exchange are to be delivered to, or are to be issued in the name of, any person other than the registered holder of the original notes tendered,

 

  •  

tendered original notes are registered in the name of any person other than the person signing the letter of transmittal, or

 

  •  

a transfer tax is imposed for any reason other than the exchange of original notes for exchange notes in the exchange offers.

If satisfactory evidence of payment of any transfer taxes payable by a tendering holder is not submitted with the letter of transmittal, the amount of the transfer taxes will be billed directly to that tendering holder. The exchange agent will retain possession of exchange notes with a face amount equal to the amount of the transfer taxes due until it receives payment of the taxes.

Accounting Treatment

We will record the exchange notes at the same carrying value as the original notes as reflected in our accounting records on the date of the exchange. Accordingly, we will not recognize any gain or loss for accounting purposes upon completion of the exchange offers.

Consequences of Failure to Exchange

If you do not exchange your original notes for exchange notes in the exchange offers, you will remain subject to the existing restrictions on transfer of the original notes. In general, you may not offer or sell the

 

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original notes unless either they are registered under the Securities Act or the offer or sale is exempt from or not subject to registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement, we do not intend to register resales of the original notes under the Securities Act. We have no obligation to re-offer to exchange the exchange notes for original notes following the expiration of the exchange offers.

The tender of original notes in the exchange offers will reduce the outstanding principal amount of the applicable original notes. Due to the corresponding reduction in liquidity, this may have an adverse effect on, and increase the volatility of, the market price of any original notes that you continue to hold.

Other

Participation in the exchange offers is voluntary, and you should carefully consider whether to accept. You are urged to consult your financial and tax advisors in making your decision on what action to take. In the future, we may at our discretion seek to acquire untendered original notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plan to acquire any original notes that are not tendered in the exchange offers or to file a registration statement to permit resales of any untendered original notes, except as required by the registration rights agreement.

 

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USE OF PROCEEDS

We are making the exchange offers to satisfy our obligations under the original notes, the indenture and the registration rights agreement. We will not receive any cash proceeds from the exchange offers. In consideration of issuing the exchange notes in the exchange offers, we will receive an equal principal amount of original notes. Any original notes that are properly tendered and accepted in the exchange offers will be canceled.

 

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CAPITALIZATION

The following table presents our consolidated cash and cash equivalents and capitalization as of March 31, 2026. This table should be read in conjunction with the information contained in “Use of Proceeds” and our unaudited consolidated interim financial statements and related notes included elsewhere in this prospectus.

 

     As of March 31, 2026  
     Actual      As Adjusted  
     (In millions)  

Cash and equivalents

   $ 522     

Short-term debt, including Puget Energy senior secured credit facility

     140     

PSE long-term debt

     6,458     

Puget Energy long-term debt(1)

     2,961     

Existing senior secured notes

     2,200     

Fair value adjustment of PE long-term debt, debt discount, issuance cost and other

     (139 )    

Series A Notes

     450     

Series B Notes

     450     

Equity

     5,909     

Total capitalization

   $ 15,328      $       
  

 

 

    

 

 

 

 

(1) 

Excludes fair value accounting treatment from our financial statements where our long-term debt is valued at $3.1 billion at March 31, 2026.

 

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DESCRIPTION OF NOTES

The original notes were issued on March 27, 2026 in private offerings under the indenture dated as of the same date, between us and Computershare Trust Company, National Association, as trustee (the “trustee”), including as supplemented by the first supplemental indenture thereto establishing the terms of the Notes dated as of the same date (collectively, the “indenture”).

In the exchange offers, we will issue up to (i) $450 million in aggregate principal amount of Series A exchange notes and (ii) $450 million in aggregate principal amount of Series B exchange notes. The exchange notes will be issued under the indenture. The terms of the exchange notes include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”).

The following description is only a summary of the material provisions of the indenture and the exchange notes, does not purport to be complete and is qualified in its entirety by reference to the provisions of the indenture, including the definitions therein of certain terms used below. Because this is a summary, it may not contain all the information that is important to you. We urge you to read the indenture because it, and not this description, will define your rights as holders of the Notes. You may request copies of the proposed form of the indenture as described under “Where You Can Find More Information.”

In the discussion that follows, “Puget Energy,” “the Company,” “we,” “us” and “our” refer only to Puget Energy, Inc., and any successor obligor on the Notes, and not to PSE or any other subsidiary of ours. References to paying principal on the Notes are to payment at maturity or redemption. We refer to the original notes and the exchange notes, collectively, as the “Notes,” the Series A exchange notes and Series A original notes, collectively, as the “Series A Notes” and the Series B exchange notes and Series B original notes, collectively, as the “Series B Notes.”

General

We will issue the exchange notes under the indenture. Under the indenture, we may issue an unlimited amount of additional subordinated debt securities. The indenture does not limit the aggregate amount of indebtedness we or our subsidiaries may issue, guarantee or incur.

The exchange notes will be issued in denominations of $2,000 and integral multiples of $1,000 in excess thereof.

The exchange notes will not be guaranteed by, or otherwise be obligations of, our direct parent company, any of its direct or indirect subsidiaries other than us, or the members of the Consortium that own our direct parent company, and will not be guaranteed by any of our affiliates.

We may, from time to time, without the consent of the holders of any Notes, reopen either series of Notes and issue additional notes with the same terms (other than the issuance date and price to the public). Any such additional notes, together with those offered hereby, will constitute a single series under the indenture.

Interest and Maturity

The Series A Notes bear interest (i) from and including the date of the original issuance to, but excluding, September 15, 2031 at an annual rate of 7.000% and (ii) from and including September 15, 2031 during each Series A Interest Reset Period at an annual rate equal to the Five-Year Treasury Rate as of the most recent Series A Reset Interest Determination Date, plus 2.961%; provided, that the interest rate during any Series A Interest Reset Period will not reset below 7.000% (which equals the initial interest rate on the Series A Notes). The Series A Notes will mature on September 15, 2056 (the “Series A Maturity Date”). The Series B Notes bear interest

 

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(i) from and including the date of the original issuance to, but excluding, September 15, 2036 at an annual rate of 7.250% and (ii) from and including September 15, 2036 during each Series B Interest Reset Period at an annual rate equal to the Five-Year Treasury Rate as of the most recent Series B Reset Interest Determination Date, plus 2.848%; provided, that the interest rate during any Series B Interest Reset Period will not reset below 7.250% (which equals the initial interest rate on the Series B Notes). The Series B Notes will mature on September 15, 2056 (the “Series B Maturity Date”). Subject to our right to defer interest payments as described below, interest will be payable semi-annually in arrears on March 15 and September 15 of each year beginning on September 15, 2026. The amount of interest payable for any interest accrual period will be computed on the basis of a 360-day year consisting of twelve 30-day months. The amount of interest payable for any period shorter than a full semi-annual period for which interest is computed will be computed on the basis of the number of days in the period using 30-day calendar months.

In this prospectus the term “interest” includes semi-annual interest payments and applicable interest on interest payments accrued but not paid on the applicable interest payment date.

“Business Day” means a day other than (i) a Saturday or Sunday, (ii) a day on which banks in New York, New York are authorized or obligated by law or executive order to remain closed or (iii) a day on which the trustee’s corporate trust office is closed for business.

Unless all of the outstanding Notes have been redeemed, we will appoint a calculation agent (the “Calculation Agent”) with respect to the Notes prior to the applicable Reset Interest Determination Date. We or any of our affiliates may assume the duties of the Calculation Agent. The applicable interest rate for each Interest Reset Period will be determined by the Calculation Agent as of the applicable Reset Interest Determination Date. If we or one of our affiliates is not the Calculation Agent, the Calculation Agent will notify us of the interest rate for the relevant Interest Reset Period promptly upon such determination. We will notify the trustee of such interest rate, promptly upon making or being notified of such determination. The Calculation Agent’s determination of any interest rate and its calculation of the amount of interest for any Interest Reset Period will be conclusive and binding absent manifest error, will be made in the Calculation Agent’s sole discretion and, notwithstanding anything to the contrary in the documentation relating to the Notes, will become effective without consent from any other person or entity. Such determination of any interest rate and calculation of the amount of interest will be on file at our principal offices and will be made available to any holder of the Notes upon request.

“Five-Year Treasury Rate” means, as of any Reset Interest Determination Date, the average of the yields on actively traded United States Treasury securities adjusted to constant maturity, for five-year maturities, for the most recent five Business Days appearing under the caption “Treasury Constant Maturities” in the most recent H.15.

If the Five-Year Treasury Rate cannot be determined pursuant to the method described above, the Calculation Agent, after consulting such sources as it deems comparable to any of the foregoing calculations, or any such source as it deems reasonable from which to estimate the Five-Year Treasury Rate, will determine the Five-Year Treasury Rate in its sole discretion, provided that if the Calculation Agent determines there is an industry-accepted successor Five-Year Treasury Rate, then the Calculation Agent will use such successor rate. If the Calculation Agent has determined a substitute or successor base rate in accordance with the foregoing, the Calculation Agent in its sole discretion may determine the business day convention, the definition of “Business Day” and the Reset Interest Determination Date to be used and any other relevant methodology for calculating such substitute or successor base rate, including any adjustment factor needed to make such substitute or successor base rate comparable to the Five-Year Treasury Rate, in a manner that is consistent with industry-accepted practices for such substitute or successor base rate.

“H.15” means the daily statistical release designated as such, or any successor publication as determined by the Calculation Agent in its sole discretion, published by the Federal Reserve Board, and “most recent H.15”

 

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means the H.15 published closest in time but prior to the close of business on the applicable Reset Interest Determination Date.

“Series A Reset Date” means September 15, 2031 and each date falling on the five-year anniversary of the preceding Series A Reset Date.

“Series B Reset Date” means September 15, 2036 and each date falling on the five-year anniversary of the preceding Series B Reset Date.

“Series A Interest Reset Period” means the period from and including September 15, 2031 to, but not including, the next following Series A Reset Date and thereafter each period from and including each Series A Reset Date to, but not including, the next following Series A Reset Date or the maturity date or date of redemption, as the case may be.

“Series B Interest Reset Period” means the period from and including September 15, 2036 to, but not including, the next following Series B Reset Date and thereafter each period from and including each Series B Reset Date to, but not including, the next following Series B Reset Date or the maturity date or date of redemption, as the case may be.

“Reset Interest Determination Date” means, in respect of any Series A Interest Reset Period or Series B Interest Reset Period, the day falling two Business Days prior to the beginning of the applicable Series A Interest Reset Period or Series B Interest Reset Period.

If an interest payment date, a redemption date or the maturity date of the Notes falls on a day that is not a business day, the payment of interest and principal will be made on the next succeeding business day, and no interest on such payment will accrue for the period from and after the interest payment date, the redemption date or the maturity date, as applicable.

So long as all of the Notes remain in book-entry only form, the record date for each interest payment date will be 15 days prior to the applicable interest payment date. If any of the Notes do not remain in book-entry only form, the record date for each interest payment date will be the fifteenth calendar day immediately preceding the applicable interest payment date whether or not a business day.

Subordination

Each series of Notes will be subordinate and junior in right of payment, to the extent set forth in the indenture, to all Senior Indebtedness as defined below. If:

 

  •  

we make a payment or distribution of any of our assets to creditors upon our dissolution, winding-up, liquidation or reorganization, whether in bankruptcy, insolvency or otherwise;

 

  •  

a default beyond any grace period has occurred and is continuing with respect to the payment of principal, interest or any other monetary amounts due and payable on any Senior Indebtedness; or

 

  •  

the maturity of any Senior Indebtedness has been accelerated because of a default on that Senior Indebtedness,

then the holders of Senior Indebtedness generally will have the right to receive payment, in the case of the first instance, of all amounts due or to become due upon that Senior Indebtedness, and, in the case of the second and third instances, of all amounts due on that Senior Indebtedness, or we will make provision for those payments, before the holders of any Notes have the right to receive any payments of principal or interest on their Notes.

 

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Ranking of the Notes

Our payment obligation under the Notes will be unsecured and will rank junior and be subordinated in right of payment and upon liquidation to all of our Senior Indebtedness. However, the Notes will rank equally in right of payment with any Pari Passu Securities.

“Senior Indebtedness,” when used with respect to the Company, means all of the Company’s obligations, whether presently existing or from time to time hereafter incurred, created, assumed or existing, to pay principal, premium, interest, penalties, fees and any other payment in respect of any of the following:

 

  •  

obligations for borrowed money, including without limitation, such obligations as are evidenced by credit agreements, notes, debentures, bonds or other securities or instruments;

 

  •  

capitalized lease obligations;

 

  •  

our obligation for reimbursement under letters of credit, security purchase facilities, or similar facilities issued for our account;

 

  •  

all obligations of the types referred to in the three preceding bullet points or others which we have assumed, endorsed, guaranteed, contingently agreed to purchase or provide funds for the payment of, or otherwise becomes liable for, under any agreement; or

 

  •  

all renewals, extensions or refundings of obligations of the kinds described in any of the preceding categories.

Any such obligation, indebtedness, renewal, extension or refunding, however, will not be Senior Indebtedness if the instrument creating or evidencing it or the assumption or guarantee of it provides that it is not superior in right of payment to or is equal in right of payment with the Notes. Furthermore, trade accounts payable and accrued liabilities arising in the ordinary course of business will not be Senior Indebtedness. Senior Indebtedness will be entitled to the benefits of the subordination provisions in the indenture irrespective of the amendment, modification or waiver of any term of the Senior Indebtedness.

No payment of the principal (including redemption and sinking fund payments) of, or interest, or premium, if any, on the Notes may be made by us until all holders of Senior Indebtedness have been paid in full (or provision has been made for such payment), if any of the following occurs:

 

  •  

certain events of bankruptcy, insolvency, reorganization, dissolution or winding up of the Company;

 

  •  

any of our Senior Indebtedness is not paid when due (after the expiration of any applicable grace period) and that default continues without waiver; or

 

  •  

any other default has occurred and continues without waiver (after the expiration of any applicable grace period) pursuant to which the holders of our Senior Indebtedness are permitted to accelerate the maturity of such Senior Indebtedness.

Upon any distribution of our assets to creditors in connection with any insolvency, bankruptcy or similar proceeding, all principal of, and premium, if any, and interest due or to become due on all Senior Indebtedness must be paid in full before the holders of the Notes are entitled to receive or retain any payment from such distribution.

“Pari Passu Securities” means:

 

  •  

indebtedness and other securities that, among other things, by their terms ranks equally with the Notes, in right of payment and upon liquidation; and

 

  •  

guarantees of indebtedness or other securities described in the preceding bullet point.

“Pari Passu Securities” also includes our trade accounts payable and accrued liabilities arising in the ordinary course of business.

 

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We are a holding company that derives substantially all of our income from our operating subsidiaries. Our subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts on the Notes or to make any funds available for such payment. Therefore, the Notes will be structurally subordinated to all indebtedness and other liabilities, including trade payables debt and preferred stock, if any, incurred or issued by our subsidiaries. In addition to trade liabilities, our operating subsidiaries incur debt in order to finance their business activities. All of this indebtedness will be effectively senior to the Notes. In addition, each subsidiary’s ability to pay dividends to us depends on statutory, regulatory and/or contractual restrictions that may be applicable to such subsidiary. The indenture does not place any limit on the amount of Senior Indebtedness that we may issue, guarantee or otherwise incur or the amount of liabilities, including debt or preferred stock, that our subsidiaries may issue, guarantee or otherwise incur. We expect that we and our subsidiaries will incur from time to time additional indebtedness and other liabilities that will be senior to the Notes. At March 31, 2026, our Senior Indebtedness (excluding letter of credit amounts), on an unconsolidated basis, totaled approximately $2.2 billion. At March 31, 2026, our subsidiaries had approximately $6.5 billion of long-term indebtedness outstanding (including securities due within one year); this amount does not include other liabilities.

Redemption

Optional Redemption

We may redeem the Series A Notes in whole or in part upon not less than 10 nor more than 60 days’ notice, at a redemption price equal to 100% of the principal amount of the Series A Notes being redeemed plus accrued and unpaid interest to, but excluding, the redemption date (i) on any day in the period commencing on the date falling 90 days prior to the first Series A Reset Date and ending on and including the first Series A Reset Date and (ii) after the first Series A Reset Date, on any interest payment date.

We may redeem the Series B Notes in whole or in part upon not less than 10 nor more than 60 days’ notice, at a redemption price equal to 100% of the principal amount of the Series B Notes being redeemed plus accrued and unpaid interest to, but excluding, the redemption date (i) on any day in the period commencing on the date falling 90 days prior to the first Series B Reset Date and ending on and including the first Series B Reset Date and (ii) after the first Series B Reset Date, on any interest payment date.

Any redemption of the Notes may be conditioned upon the occurrence of one or more conditions precedent. Except in the case of a conditional redemption, as discussed below, once notice of redemption is given, the Notes called for redemption become due and payable on the redemption date at the redemption price stated in the notice. If notice of redemption is given as aforesaid, the Notes so to be redeemed will, on the redemption date (subject, in the case of a conditional redemption, to the satisfaction of all conditions precedent), become due and payable at the redemption price together with any accrued and unpaid interest thereon, and from and after such date (unless we have defaulted in the payment of the redemption price and accrued interest) such Notes shall cease to bear interest. The Company shall provide written notice to the trustee prior to the close of business two Business Days prior to the redemption date if any such redemption has been rescinded or delayed, and upon receipt the trustee shall provide such notice to each holder of the Notes in the same manner in which the notice of redemption was given.

If any Notes called for redemption shall not be paid upon surrender thereof for redemption, the principal shall, until paid, bear interest from the redemption date at the rate then applicable to the Notes. See “—Events of Default” below.

A notice of redemption may be conditional and provide that it is subject to the occurrence of any event described in the notice before the date fixed for the redemption. A notice of conditional redemption will be of no effect unless all conditions to the redemption have occurred before the redemption date or have been waived by us.

 

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The Company may also redeem the Notes of a series (i) in whole, but not in part, if certain changes in tax laws, regulations or interpretations occur, at the redemption price and under the circumstances described below under “—Redemption Upon a Tax Event” and (ii) in whole, but not in part, if a rating agency makes certain changes in the equity credit criteria for securities such as the Notes, at the redemption price and under the circumstances described below under “—Redemption Upon a Rating Agency Event.”

Subject to the foregoing and to applicable law (including, without limitation, United States federal securities laws), the Company or its affiliates may, at any time and from time to time, purchase outstanding Notes by tender, in the open market or by private agreement.

Redemption Upon a Tax Event

We may redeem the applicable series of the Notes, in whole but not in part, upon not less than 10 nor more than 60 days’ notice, following the occurrence of a Tax Event (as defined below), at the redemption price equal to the sum of: (1) 100% of the principal amount of the Notes being redeemed plus (2) accrued and unpaid interest thereon, if any, to the date fixed for redemption (“Tax Event Redemption Date”). In such case, we will deliver a notice of redemption specifying the Tax Event Redemption Date, which shall be no later than 120 days following the Tax Event.

If at the time notice of redemption is given, the redemption moneys are not on deposit with the trustee, then the redemption shall be subject to their receipt on or before the Tax Event Redemption Date and such notice shall be of no effect unless such moneys are so received.

A “Tax Event” happens when we have received an opinion of counsel experienced in tax matters that, as a result of:

 

  •  

any amendment to, clarification of, or change, including any announced prospective change, in the laws or treaties of the United States or any of its political subdivisions or taxing authorities, or any regulations under those laws or treaties;

 

  •  

an administrative action, which means any judicial decision or any official administrative pronouncement, ruling, regulatory procedure, notice or announcement including any notice or announcement of intent to issue or adopt any administrative pronouncement, ruling, regulatory procedure or regulation;

 

  •  

any amendment to, clarification of, or change in the official position or the interpretation of any administrative action or judicial decision or any interpretation or pronouncement that provides for a position with respect to an administrative action or judicial decision that differs from the previously generally accepted position, in each case by any legislative body, court, governmental authority or regulatory body, regardless of the time or manner in which that amendment, clarification or change is introduced or made known; or

 

  •  

a threatened challenge asserted in writing in connection with an audit of us or our subsidiaries, or a threatened challenge asserted in writing against any other taxpayer that has raised capital through the issuance of securities that are substantially similar to the applicable series of Notes,

which amendment, clarification, or change in each case is effective or which administrative action is taken or judicial decision, interpretation or pronouncement is issued, or which threatened challenge is asserted, after the date of this prospectus, there is more than an insubstantial risk that interest payable by us on the applicable series of Notes is not deductible, or within 90 days would not be deductible, in whole or in part, by us for United States federal income tax purposes.

 

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Redemption Upon a Rating Agency Event

The Company may redeem, upon not less than 10 nor more than 60 days’ notice, in whole but not in part, either series of the Notes following the occurrence of a Rating Agency Event (as defined below), at 102% of their principal amount plus any accrued and unpaid interest thereon (including any additional interest) to the redemption date.

“Rating Agency Event” means a change to the methodology or criteria that were employed by an applicable nationally recognized statistical rating organization for purposes of assigning equity credit to securities such as the Notes on the date of original issuance of the Notes, which either (i) shortens the period of time during which equity credit pertaining to the Notes would have been in effect had the current methodology not been changed, or (ii) reduces the amount of equity credit assigned to the Notes as compared with the amount of equity credit that such rating agency had assigned to the Notes as of the date of original issuance thereof.

Redemption Upon a Change of Control Event

Following the occurrence of a Change of Control Event (as defined below) with respect to either or both of the Series A Notes or the Series B Notes, the Company may redeem (a “Change of Control Redemption”) such series of Notes, in whole but not in part, at the Company’s option at a redemption price equal to 101% of their principal amount plus any accrued and unpaid interest thereon to, but excluding the date of redemption (“Change of Control Event Redemption Date”). Unless the Company has previously or concurrently given a redemption notice to holders of all outstanding Notes of such series pursuant to “—Optional Redemption,” “—Redemption Upon a Tax Event” or “—Redemption Upon a Rating Agency Event,” within 30 days following any Change of Control Event in respect of such Notes or, at the Company’s option, prior to any Change of Control Event, but after the public announcement of the related Change of Control, the Company will send a notice to each holder of such Notes describing the transaction or transactions that constitute or may constitute the Change of Control Event and either the Company’s election not to redeem such Notes or the Change of Control Event Redemption Date (which date will be no earlier than 60 days and no later than 90 days from the date such notice is sent), together with such other matters as may be advisable in the Company’s discretion or required by the indenture. The notice shall, if sent prior to the occurrence of the Change of Control Event, state that the Change of Control Redemption is conditioned on the Change of Control Event occurring on or prior to the redemption date specified in the notice. If no Change of Control Redemption is made by the Company within the time periods specified in this paragraph following a Change of Control Event with respect to such series of Notes and the Company has not otherwise given a redemption notice to holders of all outstanding Notes of such series pursuant to “—Optional Redemption,” “—Redemption Upon a Tax Event” or “—Redemption Upon a Rating Agency Event,” the per annum rate of interest payable on such series of Notes will be increased by an additional 5.0 percentage points from and including the date on which the applicable notice of a Change of Control Event is sent to holders.

On and after a Change of Control Event Redemption Date, interest will cease to accrue on such series of Notes called for redemption (unless the Company defaults in the payment of the redemption price and accrued interest). On or before the Change of Control Event Redemption Date, the Company will deposit with the trustee money sufficient to pay the redemption price of and (unless the redemption date shall be an interest payment date) accrued and unpaid interest to the redemption date of such Notes.

The definition of Change of Control below with respect to the Notes differs from the definition of change of control in our senior secured credit facility and our senior secured notes. Depending on the circumstances, it is possible that a change of control may occur for purposes of our senior secured credit facility and our senior secured notes without constituting a Change of Control for purposes of the indenture.

“Affiliate” of any specified person means any other person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified person. For the purposes of this definition, “control,” when used with respect to any specified person, means the power to direct generally the management

 

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and policies of such person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise; and the terms “controlling” and “controlled” have meanings correlative to the foregoing.

“Change of Control” means the occurrence of the following:

 

  •  

any “person” or “group” (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act or any successor provisions to either of the foregoing), other than the Permitted Holders, becomes the “beneficial owners” (as used in Rules 13d-3 and 13d-5 under the Exchange Act, except that a person or group will be deemed to have “beneficial ownership” of all shares that any such person or group has the right to acquire, whether such right is exercisable immediately or only after the passage of time), directly or indirectly, of a majority of the total voting power of our Voting Stock, whether as a result of the issuance of our securities, any merger, consolidation, liquidation or dissolution of us or otherwise;

 

  •  

the sale, transfer, assignment, lease, conveyance or other disposition, directly or indirectly, of all or substantially all the assets of us and our subsidiaries, considered as a whole (other than a disposition of such assets as an entirety or virtually as an entirety to a wholly-owned subsidiary) to any person other than the Permitted Holders occurs, or we merge, consolidate or amalgamate with or into any other person or any other person merges, consolidates or amalgamates with or into us, in any such event pursuant to a transaction in which our outstanding Voting Stock is reclassified into or exchanged for cash, securities or other property, other than any such transaction where (i) our outstanding Voting Stock is reclassified into or exchanged for other Voting Stock of us or for Voting Stock of the surviving corporation and (ii) the holders of our Voting Stock immediately prior to such transaction own, directly or indirectly, a majority of our Voting Stock or the surviving corporation immediately after such transaction;

 

  •  

during any financial quarter, individuals who at the beginning of such financial quarter constituted our board of directors (for so long as our Amended and Restated Bylaws, as amended by the First Amendment to the Amended and Restated Bylaws, dated January 6, 2022 (as amended from time to time, the “Bylaws”) are in effect, together with any replacement or new directors appointed to such board of directors in accordance with the terms of the Bylaws, and to the extent the terms of the Bylaws are no longer in effect, together with any new directors whose election or appointment by such board of directors or whose nomination for election by our shareholders was approved by a vote of a majority of the directors then still in office who were either directors at the beginning of such financial quarter or whose election or nomination for election was previously so approved) cease for any reason to constitute a majority of our board of directors then in office; or

 

  •  

our shareholders approve any plan of liquidation or dissolution of us.

“Change of Control Event” means the occurrence of both a Change of Control and a Rating Event.

“Fitch” means Fitch Ratings, Inc., or any successor thereto.

“Investment Grade” means a rating of BBB- or better by Fitch (or its equivalent under any successor rating categories of Fitch), Baa3 or better by Moody’s (or its equivalent under any successor rating categories of Moody’s) and BBB- or better by S&P (or its equivalent under any successor rating categories of S&P) (or, in each case, if such Rating Agency ceases to rate the Notes for reasons outside of the Company’s control, the equivalent investment grade credit rating from any Rating Agency selected by the Company as a replacement Rating Agency).

“Investors” means (i) the British Columbia Investment Management Corporation, (ii) the Alberta Investment Management Corporation, (iii) the Ontario Municipal Employees Retirement System, (iv), PGGM Vermogensbeheer B.V., (v) Macquarie Washington Clean Energy Investment, L.P., (vi) the Ontario Teachers’ Pension Plan Board and (vii) each of their respective Affiliates (not including, however, any portfolio companies of any of the Investors). For purposes of the preceding sentence, the term “portfolio companies” does not include, without limitation, (i) any investment fund or investment vehicle managed or co-managed by any Investor or by

 

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any of such investment funds’ or investment vehicles’ Affiliates or (ii) any direct or indirect non-operating subsidiary of any Investor.

“Moody’s” means Moody’s Investors Service, Inc., or any successor thereto.

“Permitted Holders” means each of the Investors and members of our management (or of our direct or indirect parent) who are holders of our Voting Stock (or any of its direct or indirect parent companies) on the issue date of the Notes and any “group” (as such term is used in Section 13(d) and 14(d) of the Exchange Act or any successor provision) of which any of the foregoing are members; provided, that, in the case of such group and without giving effect to the existence of such group or any other group, such Investors and members of management, collectively, have beneficial ownership of a majority of the total voting power of our Voting Stock.

“person” means an individual, a corporation, a partnership, a limited liability company, an association, a trust or any other entity, including a government or political subdivision or an agency or instrumentality thereof.

“Rating Agency” means:

 

  •  

each of Fitch, Moody’s and S&P; and

 

  •  

if any of Fitch, Moody’s or S&P ceases to rate the Notes or fails to make a rating of the Notes publicly available, another “nationally recognized statistical rating organization” within the meaning of Section 3(a)(62) of the Exchange Act, selected by the Company as a replacement agency for Fitch, Moody’s or S&P, or any of them, as the case may be.

“Rating Decline Period” means the 30-day period (which 30-day period shall be extended as long as the credit rating on the Notes is under publicly announced consideration for a possible downgrade by any Rating Agency) after the earliest of (a) the occurrence of a Change of Control and (b) the first public notice of the occurrence of such Change of Control.

“Rating Event” means, with respect to the Series A Notes or Series B Notes, the credit rating on such series of Notes is lowered by one or more gradations (including gradations within ratings categories as well as between rating categories but excluding, for the avoidance of doubt, changes in ratings outlook) by each of the Rating Agencies during the Rating Decline Period relating to such Change of Control and each such Rating Agency shall have put forth a public statement to the effect that such downgrade is attributable in whole or in part to such Change of Control. Notwithstanding the foregoing, if the rating of a series of Notes by each of the Rating Agencies is Investment Grade, then a “Rating Event” means a decrease in the ratings of such series of Notes by one or more gradations (including gradations within ratings categories as well as between rating categories but excluding, for the avoidance of doubt, changes in ratings outlook) by each of the Rating Agencies such that the rating of such series of Notes by each of the Rating Agencies falls below Investment Grade during the Rating Decline Period.

“S&P” means S&P Global Ratings, a division of S&P Global, Inc., or any successor thereto.

“Voting Stock” means securities of any class or classes the holders of which are ordinarily, in the absence of contingencies, entitled to vote for corporate directors (or persons performing similar functions).

Option to Defer Interest Payments

So long as no event of default has occurred and is continuing with respect to applicable series of the Notes, we may defer interest payments on a given series of the Notes, from time to time, for one or more Optional Deferral Periods of up to 10 consecutive years per Optional Deferral Period. However, a deferral of interest payments cannot extend beyond the redemption date or maturity date of the Notes. During an Optional Deferral Period, interest will continue to accrue on the Notes, and deferred interest payments will accrue additional interest on a semi-annual basis at a rate equal to the interest rate then applicable to such series of Notes, to the

 

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extent permitted by law. No interest will be due and payable on the Notes until the end of the Optional Deferral Period except upon a redemption of the Notes during the Optional Deferral Period.

We may pay at any time all or any portion of the interest accrued to that point during an Optional Deferral Period. At the end of the Optional Deferral Period or on any redemption date, we will be obligated to pay all accrued and unpaid interest.

Once all accrued and unpaid interest on a given series of the Notes has been paid, we again can defer interest payments on that series of Notes as described above, provided that an Optional Deferral Period cannot extend beyond the maturity date of the Notes.

If we defer interest for a period of 10 consecutive years from the commencement of an Optional Deferral Period, we will be required to pay all accrued and unpaid interest at the conclusion of the 10-year period. If we fail to pay in full all accrued and unpaid interest at the conclusion of the 10-year period, and such failure continues for 30 days, an event of default that gives rise to acceleration of principal and interest on the Notes will occur under the indenture. See “—Events of Default” below.

During a Series A Optional Deferral Period or a Series B Optional Deferral Period, we will not do any of the following (with limited exceptions):

 

  •  

declare or pay any dividend or distribution on Puget Energy, Inc.’s capital stock;

 

  •  

redeem, purchase, acquire or make a liquidation payment with respect to any of Puget Energy, Inc.’s capital stock;

 

  •  

pay any principal, interest (to the extent such interest is deferrable) or premium on, or repay, purchase or redeem any of our debt securities that are equal or junior in right of payment with the Notes; or

 

  •  

make any payments with respect to any guarantee by us of debt securities if such guarantee is equal or junior in right of payment to the Notes.

However, at any time, including during an Optional Deferral Period, the exceptions will permit:

 

  •  

purchases, redemptions or other acquisitions of our capital stock in connection with any employment contract, benefit plan or other similar arrangement with or for the benefit of employees, officers, directors, agents, consultants or a stock purchase, dividend reinvestment or similar plan, or the satisfaction of our obligations pursuant to any contract or security outstanding on the date that the payment of interest is deferred requiring us to purchase, redeem or acquire our capital stock;

 

  •  

any payment, repayment, redemption, purchase, acquisition or declaration of a dividend as a result of any reclassification of our capital stock or the exchange or conversion of all or a portion of one class or series of our capital stock or debt securities for a class or series of our capital stock;

 

  •  

the purchase of fractional interests in shares of our capital stock pursuant to the conversion or exchange provisions of our capital stock or the security being converted or exchanged, or in connection with the settlement of stock purchase contracts;

 

  •  

dividends or distributions paid or made in our capital stock (or rights to acquire our capital stock), or purchases, redemptions or acquisitions of capital stock in connection with the issuance or exchange of capital stock (or of securities convertible into or exchangeable for shares of our capital stock) and distributions in connection with the settlement of stock purchase contracts outstanding on the date that the payment of interest is deferred;

 

  •  

redemptions, exchanges or purchases of, or with respect to, any rights outstanding under a shareholder rights plan or the declaration or payment thereunder of a dividend or distribution of or with respect to rights in the future;

 

  •  

payments on the Notes, any trust preferred securities, subordinated debentures or junior subordinated debentures, or guarantees of the foregoing, in each case that rank equal in right of payment to the

 

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Notes, so long as the amount of payments made on account of such securities or guarantees is paid on all such securities and guarantees then outstanding on a pro rata basis in proportion to the full payment to which each series of such securities and guarantees is then entitled if paid in full; and

 

  •  

for the avoidance of doubt, conversions of convertible capital stock of Puget Energy, Inc. into other capital stock of Puget Energy, Inc. in accordance with the terms of such convertible capital stock (together, for the avoidance of doubt, with cash in lieu of any fractional share).

Reports and Other Information

Whether or not required by the SEC’s rules and regulations, so long as any Notes are outstanding, we will furnish to the trustee and holders of the Notes or cause the trustee to furnish to the holders of the Notes:

 

  (a)

within 90 days of the end of each fiscal year and within 60 days of the end of each fiscal quarter, all annual and quarterly reports that would be required to be filed with the SEC on Forms 10-K and 10-Q if we were required to file such reports; and

 

  (b)

within the time periods specified in the SEC’s rules and regulations that would be applicable if we were subject to such rules and regulations, all current reports that would be required to be filed with the SEC on Form 8-K if we were required to file such reports.

All such reports will be prepared, within the time periods specified above, in all material respects in accordance with all of the rules and regulations applicable to such reports. Each annual report on Form 10-K will include a report on our consolidated financial statements by our independent registered public accounting firm or independent auditors. In addition, we will file a copy of each of the reports referred to in clauses (a) and (b) above with the SEC for public availability within the time periods specified in clauses (a) and (b) above (unless the SEC will not accept such a filing). We agree that we will not take any action for the purpose of causing the SEC not to accept any such filings. If, notwithstanding the foregoing, the SEC will not accept our filings for any reason, we will use our reasonable best efforts to post the reports referred to in the preceding paragraph on our website within the time periods specified above. To the extent such filings are made, the reports will be deemed to be furnished to the trustee and holders of the Notes on the date filed.

In addition, for so long as any Notes remain outstanding, we will furnish to prospective purchasers of Notes, upon their request, the information described above as well as any other information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act for compliance with Rule 144A. Delivery of reports, information and documents to the trustee is for informational purposes only and its receipt of such reports shall not constitute constructive notice of any information contained therein or determinable from information contained therein, including our compliance with any of our covenants under the indenture or the notes (as to which the trustee is entitled to rely exclusively on officers’ certificates). The trustee shall not be obligated to monitor or confirm, on a continuing basis or otherwise, our compliance with the covenants or with respect to any reports or other documents filed with the SEC or EDGAR or any website under the indenture, or participate in any conference calls.

Events of Default

The following are events of default under the indenture with respect to any series of the Notes:

 

  •  

failure to pay for three Business Days the principal of (or premium, if any, on) any Notes when due and payable;

 

  •  

failure to pay for 30 days any interest on any Notes when due and payable;

 

  •  

failure to perform any other requirements in the Notes, or in the indenture, for 90 days after notice; or

 

  •  

certain events of our bankruptcy or insolvency.

 

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However, as discussed below under “—Limitation of Remedies,” neither the trustee nor the holders of the Notes will be entitled to declare the Notes to be due and payable immediately upon the occurrence of an event of default described in the third bullet above.

An event of default for a particular series of notes does not necessarily mean that an event of default has occurred for any other series of notes issued under the indenture.

Limitation on Remedies

If an event of default, other than an event of default described in the third bullet under “—Events of Default” above occurs and is continuing, the trustee or the holders of at least 33% of the principal amount of the applicable affected series of Notes may require us to repay the entire principal of the applicable series of Notes immediately (“Repayment Acceleration”). In most instances, the holders of at least a majority in aggregate principal amount of the applicable series of Notes may rescind a previously triggered Repayment Acceleration. However, if we cause an event of default because we have failed to pay (unaccelerated) principal, premium, if any, or interest, Repayment Acceleration may be rescinded only if we have first cured our default by depositing with the trustee enough money to pay all (unaccelerated) past due amounts and penalties, if any.

Subject to certain exceptions, the trustee must within 90 days after a default occurs that is actually known to the trustee, notify the holders of the applicable Series of Notes of default unless such default has been cured or waived. We are required to file an annual certificate with the trustee, signed by an officer, concerning any default by us under any provisions of the indenture.

Subject to the provisions of the indenture relating to its duties in case of default, the trustee shall be under no obligation to exercise any of its rights or powers under the indenture at the request, order or direction of any holders unless such holders offer the trustee indemnity reasonably satisfactory to it against the losses, costs, expenses and liabilities which might be incurred by it in compliance with such request or direction. Subject to the provisions for indemnification, the holders of a majority in principal amount of the applicable series of Notes may direct the time, method and place of conducting any proceedings for any remedy available to, or exercising any trust or power conferred on, the trustee with respect to such Notes.

A valid extension of the Interest Reset Period by the Company as contemplated in the indenture shall not constitute a default in the payment of interest giving rise to an “Event of Default.” If an event of default listed in the third bullet under “—Events of Default” above occurs and is continuing, the holders of such series of the Notes will not be entitled to vote to make a declaration of acceleration (and the Notes will not be considered outstanding for the purpose of determining whether the required vote, described in the other such bullets has been obtained), and the trustee will not have a right to make such declaration with respect to the Notes. See “Risk Factors—Holders of each series of the Notes will have limited rights of acceleration” above. However, they may exercise the other rights and remedies available under the indenture upon the occurrence of such an event of default.

Modification of Indenture

Under the indenture, our rights and obligations and the rights of the holders of any Notes may be changed. Any change affecting the rights of the holders of any series of Notes requires the consent of the holders of not less than a majority in aggregate principal amount of the outstanding Notes of all series affected by the change, voting as one class. However, we cannot change the terms of payment of principal or interest, or reduce the percentage required for changes or a waiver of default, unless the holder consents. We may issue additional series of Notes and take other action that does not affect the rights of holders of any series by executing supplemental indentures without the consent of any noteholders.

Consolidation, Merger or Sale

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the successor or purchaser (i) is organized and existing under the laws of the United States, any state thereof or the District of Columbia, (ii) expressly assumes the payment of principal, premium, if any, and interest on the Notes, and (iii) deliver an officer’s certificate and opinion of counsel to the trustee as provided in the indenture.

Satisfaction and Discharge

The Notes of any series, or any portion of the principal amount thereof, will be deemed to have been paid for purposes of the indenture and, at our election, our entire indebtedness in respect thereof will be satisfied and discharged, if there shall have been irrevocably deposited with the trustee, in trust:

 

  (a)

cash in an amount which will be sufficient,

 

  (b)

in the case of a deposit made before the maturity of such Notes or portions thereof, government securities, which do not contain provisions permitting the redemption or other prepayment thereof at the option of the issuer thereof, the principal of and the interest on which when due, without any regard to reinvestment thereof, will provide moneys which, together with the money, if any, deposited with or held by the trustee, will be sufficient, or

 

  (c)

a combination of (a) and (b) which will be sufficient,

to pay when due the principal of and premium, if any, and interest, if any, due and to become due on such Notes.

The indenture will be deemed to have been satisfied and discharged when no Notes of any series remain outstanding thereunder and we have paid or caused to be paid all other sums payable by us under the indenture.

Legal Defeasance

We will be discharged from our obligations on the Notes of any series at any time if:

 

  •  

we irrevocably deposit with the trustee sufficient cash or government securities to pay the principal, interest, any premium and any other sums due to the stated maturity date or a redemption date of the Notes of the series, and

 

  •  

we deliver to the trustee an opinion of counsel stating that the federal income tax obligations of noteholders of that series will not change as a result of our performing the action described above.

If this happens, the noteholders of the series will no longer be entitled to the benefits of the indenture except for registration of transfer and exchange of Notes and replacement of lost, stolen or mutilated Notes.

Covenant Defeasance

We will be discharged from our obligations under any restrictive covenant applicable to the Notes of a particular series if we perform both actions described above. See “—Legal Defeasance.” If this happens, any later breach of that particular restrictive covenant will not result in Repayment Acceleration. If we cause an event of default apart from breaching that restrictive covenant, there may not be sufficient money or government obligations on deposit with the trustee to pay all amounts due on the Notes of that series. In that instance, we would remain liable for such amounts.

Notes issued to a trust will not be subject to covenant defeasance.

Agreement of Certain Tax Treatment

We agree, and by acquiring an interest in a Note each holder and beneficial owner of a Note agrees, to treat the Notes as indebtedness for U.S. federal, state and local tax purposes.

 

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Governing Law

The indenture and the original notes are, and the exchange notes will be, governed by the laws of the State of New York.

Book-Entry; Delivery and Form

The original notes are, and the exchange notes will be, issued in the form of one or more global certificates, known as “Global Notes.” The Global Notes will be deposited on the date of the acceptance for exchange of the original notes and the issuance of the exchange notes with, or on behalf of, DTC and registered in the name of Cede & Co., as DTC’s nominee.

Beneficial interests in the Global Notes may not be exchanged for Notes in certificated form except in the limited circumstances described below. See “—Exchange of Global Notes for Certificated Notes.” Except in the limited circumstances described below, owners of beneficial interests in the Global Notes will not be entitled to receive physical delivery of Notes in certificated form. Persons holding interests in the global securities may hold their interests directly through DTC or indirectly through organizations that are participants in DTC (such as Euroclear and Clearstream).

Exchange of Global Notes for Certificated Notes

A Global Note is exchangeable for Notes in registered certificated form (“Certificated Notes”) if:

 

  (a)

DTC (i) notifies the Company that it is unwilling or unable to continue as depositary for the Global Notes or (ii) has ceased to be a clearing agency registered under the Exchange Act, and the Company fails to appoint a successor depositary within 90 days;

 

  (b)

we, in our sole discretion, determine that the Notes shall no longer be represented by such Global Notes; or

 

  (c)

there shall have occurred a Default or Event of Default with respect to the Notes.

In addition, beneficial interests in a Global Note may be exchanged for Certificated Notes upon prior written notice given to the trustee by or on behalf of DTC in accordance with the indenture governing the Notes. In all cases, Certificated Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures) and will bear the applicable restrictive legend unless that legend is not required by applicable law.

Book-Entry Only Issuance

DTC will act as the initial securities depository for the Notes. The Notes offered hereby will be issued only as fully-registered securities registered in the name of Cede & Co., DTC’s nominee, or such other name as may be requested by an authorized representative of DTC. One or more fully-registered global Notes certificates will be issued, representing in the aggregate the total principal amount of Notes, and will be deposited with the trustee on behalf of DTC. Investors may hold interests in the Notes offered hereby through DTC if they are participants in DTC or indirectly through organizations that are participants in DTC, including Euroclear, or Clearstream.

DTC is a limited-purpose trust company organized under the New York Banking Law, a “banking organization” within the meaning of the New York Banking Law, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code and a “clearing agency” registered pursuant to the provisions of Section 17A of the Exchange Act. DTC holds and provides asset servicing for over 3.5 million issues of United States and non-United States equity issues, corporate and municipal debt issues and money market instruments (from over 100 countries) that DTC’s participants (“Direct Participants”) deposit with DTC. DTC also facilitates the post-trade settlement among Direct Participants of sales

 

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and other securities transactions in deposited securities, through electronic computerized book-entry transfers and pledges between Direct Participants’ accounts. This eliminates the need for physical movement of securities certificates. Direct Participants include both United States and non-United States securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. DTC is a wholly-owned subsidiary of The Depository Trust & Clearing Corporation (“DTCC”). DTCC is the holding company for DTC, National Securities Clearing Corporation and Fixed Income Clearing Corporation, all of which are registered clearing agencies. DTCC is owned by the users of its regulated subsidiaries. Access to the DTC system is also available to others such as both United States and non-United States securities brokers and dealers, banks, trust companies and clearing corporations that clear through or maintain a custodial relationship with a Direct Participant, either directly or indirectly (“Indirect Participants”). The DTC rules applicable to its Direct and Indirect Participants are on file with the SEC. More information about DTC can be found at www.dtcc.com. The contents of such website do not constitute part of this prospectus.

Purchases of Notes under the DTC system must be made by or through Direct Participants, which will receive a credit for the Notes on DTC’s records. The ownership interest of each actual purchaser of each Notes (“Beneficial Owner”) is in turn to be recorded on the Direct and Indirect Participants’ records. Beneficial Owners will not receive written confirmation from DTC of their purchases. Beneficial Owners, however, are expected to receive written confirmations providing details of the transactions, as well as periodic statements of their holdings, from the Direct or Indirect Participants through which the Beneficial Owners purchased Notes. Transfers of ownership interests in the Notes are to be accomplished by entries made on the books of Direct and Indirect Participants acting on behalf of Beneficial Owners. Beneficial Owners will not receive certificates representing their ownership interests in Notes, except in the event that use of the book-entry system for the Notes is discontinued.

To facilitate subsequent transfers, all Notes deposited by Direct Participants with DTC are registered in the name of DTC’s nominee, Cede & Co., or such other name as may be requested by an authorized representative of DTC. The deposit of Notes with DTC and their registration in the name of Cede & Co. or such other DTC nominee do not effect any changes in beneficial ownership. DTC has no knowledge of the actual Beneficial Owners of the Notes. DTC’s records reflect only the identity of the Direct Participants to whose accounts such Notes are credited, which may or may not be the Beneficial Owners. The Direct and Indirect Participants will remain responsible for keeping account of their holdings on behalf of their customers.

Conveyance of notices and other communications by DTC to Direct Participants, by Direct Participants to Indirect Participants, and by Direct Participants and Indirect Participants to Beneficial Owners will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time.

Redemption notices will be sent to DTC. If less than all of the Notes are being redeemed, DTC’s practice is to determine by lot the amount of interest of each Direct Participant in such Notes to be redeemed.

Although voting with respect to the Notes is limited, in those cases where a vote is required, neither DTC nor Cede & Co. (nor any other DTC nominee) will consent or vote with respect to the Notes unless authorized by a Direct Participant in accordance with DTC’s procedures. Under its usual procedures, DTC mails an Omnibus Proxy to the Company as soon as possible after the record date. The Omnibus Proxy assigns Cede & Co.’s consenting or voting rights to those Direct Participants to whose accounts the Notes are credited on the record date (identified in a listing attached to the Omnibus Proxy).

Payments on the Notes will be made to Cede & Co., or such other nominee as may be requested by an authorized representative of DTC. DTC’s practice is to credit Direct Participants’ accounts upon DTC’s receipt of funds and corresponding detail information from the Company or the trustee on the relevant payment date in accordance with their respective holdings shown on DTC’s records. Payments by Direct or Indirect Participants to Beneficial Owners will be governed by standing instructions and customary practices, as is the case with securities held for the account of customers registered in “street name,” and will be the responsibility of such

 

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Direct or Indirect Participant and not of DTC or the Company, subject to any statutory or regulatory requirements as may be in effect from time to time. Payment to Cede & Co. (or such other nominee as may be requested by an authorized representative of DTC) is the responsibility of the Company, disbursement of such payments to Direct Participants is the responsibility of DTC, and disbursement of such payments to the Beneficial Owners is the responsibility of Direct and Indirect Participants.

Except as provided herein, a Beneficial Owner of global Notes will not be entitled to receive physical delivery of Notes. Accordingly, each Beneficial Owner must rely on the procedures of DTC to exercise any rights under the Notes. The laws of some jurisdictions require that certain purchasers of securities take physical delivery of securities in definitive form. Such laws may impair the ability to transfer beneficial interests in global Notes.

DTC may discontinue providing its services as securities depository with respect to the Notes at any time by giving reasonable notice to the Company. Under such circumstances, in the event that a successor securities depository is not obtained, Notes certificates will be required to be printed and delivered to the holders of record. Additionally, the Company may decide to discontinue use of the system of book-entry transfers through DTC (or a successor securities depository) with respect to the Notes. The Company understands, however, that under current industry practices, DTC would notify its Direct and Indirect Participants of the Company’s decision, but will only withdraw beneficial interests from global Notes at the request of each Direct or Indirect Participant. In that event, certificates for the Notes will be printed and delivered to the applicable Direct or Indirect Participant.

The information in this section concerning DTC and DTC’s book-entry system has been obtained from sources that the Company believes to be reliable, but neither the Company nor any initial purchaser takes any responsibility for the accuracy thereof. Neither the Company nor any initial purchaser has any responsibility for the performance by DTC or its Direct or Indirect Participants of their respective obligations as described herein or under the rules and procedures governing their respective operations.

Global Clearance and Settlement Procedures

Secondary market trading between Clearstream participants and/or Euroclear participants will occur in the ordinary way in accordance with the applicable rules and operating procedures of Clearstream and Euroclear, as applicable.

Cross-market transfers between persons holding directly or indirectly through DTC on the one hand, and directly or indirectly through Clearstream participants or Euroclear participants on the other, will be effected through DTC in accordance with DTC rules on behalf of the relevant European international clearing system by its United States depositary; however, such cross-market transactions will require delivery of instructions to the relevant European international clearing system by the counterparty in such system in accordance with its rules and procedures and within its established deadlines (European time). The relevant European international clearing system will, if the transaction meets its settlement requirements, deliver instructions to its United States depositary to take action to effect final settlement on its behalf by delivering or receiving securities in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Clearstream participants and Euroclear participants may not deliver instructions directly to their respective United States depositaries.

Because of time-zone differences, credits of Notes received in Clearstream or Euroclear as a result of a transaction with a DTC participant will be made during subsequent securities settlement processing and dated the business day following the DTC settlement date. Such credits or any transactions in such Notes settled during such processing will be reported to the relevant Clearstream participant or Euroclear participant on such business day. Cash received in Clearstream or Euroclear as a result of sales of the Notes by or through a Clearstream participant or a Euroclear participant to a DTC participant will be received with value on the DTC settlement date but will be available in the relevant Clearstream or Euroclear cash account only as of the business day following settlement in DTC.

 

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The information in this section concerning DTC and DTC’s book-entry system, Clearstream and Euroclear has been obtained from sources that we believe to be reliable. Neither we nor the initial purchasers take any responsibility for the accuracy of this information.

 

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MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

The following summary describes the material United States federal income tax consequences relevant to the exchange of original notes for exchange notes pursuant to the exchange offers. The following discussion is based on the provisions of the Code, and related United States Treasury regulations, administrative rulings and judicial decisions now in effect, changes to which subsequent to the date hereof may affect the tax consequences described below, possibly with retroactive effect. This discussion does not describe all the tax consequences that may be relevant to particular holders in light of their particular circumstances or to holders subject to special rules under United States federal income tax law, such as (a) dealers in securities or currencies, (b) financial institutions, (c) investors in partnerships or other pass-through entities or arrangements, (d) tax-exempt organizations or pension plans, (e) insurance companies, (f) real estate investment trusts, (g) regulated investment companies, (h) persons holding notes as a hedge or as part of a straddle, constructive sale, conversion transaction or other risk management transactions, (i) persons subject to special tax accounting rules as a result of any item of gross income with respect to the Notes being taken into account in an applicable financial statement, (j) a United States person (as defined in the Code) whose “functional currency” is not the United States dollar, and (k) certain former citizens or residents of the United States. Furthermore, this discussion does not address other federal tax laws (such as estate and gift tax laws) or any state, local or foreign tax laws.

We encourage holders to consult their own tax advisors regarding the United States federal tax consequences of the exchange offers and being a holder of the Notes in light of their particular circumstances, as well as any tax consequences arising under the laws of any state, local or foreign taxing jurisdiction.

An exchange of original notes for exchange notes pursuant to the exchange offers will not be a taxable event for United States federal income tax purposes. Instead, an exchange note a holder receives will be treated as a continuation of such holder’s investment in the corresponding original note surrendered in the exchange offers. Consequently, holders will not recognize any taxable gain or loss as a result of exchanging original notes for exchange notes pursuant to the exchange offers. The holding period of the exchange notes will include the holding period of the original notes, and the tax basis in the exchange notes will be the same as the tax basis in the original notes immediately before the exchange. The United States federal income tax consequences of holding and disposing of an exchange note will be the same as the United States federal income tax consequences of holding and disposing of an original note.

 

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PLAN OF DISTRIBUTION

Based on interpretations of the SEC staff in no-action letters issued to third parties, we believe that you may resell or otherwise transfer exchange notes issued in the exchange offers without further compliance with the registration and prospectus delivery requirements of the Securities Act if:

 

  •  

you are not our affiliate within the meaning of Rule 405 under the Securities Act;

 

  •  

you are acquiring such exchange notes in the ordinary course of your business;

 

  •  

you do not intend to participate in the distribution of exchange notes; and

 

  •  

you are not a broker-dealer and are not engaged in, and do not intend to engage in, the distribution of the exchange notes.

We believe that you may not transfer exchange notes issued in the exchange offers without further compliance with such requirements or an exemption from such requirements if you are:

 

  •  

our affiliate within the meaning of Rule 405 under the Securities Act, or

 

  •  

a broker-dealer that acquired original notes as a result of market-making or other trading activities.

The information described above concerning interpretations of and positions taken by the SEC staff is not intended to constitute legal advice. Broker-dealers should consult their own legal advisors with respect to these matters.

If you wish to exchange your original notes for exchange notes in the exchange offers, you will be required to make representations to us as described in “The Exchange Offers—Procedures for Tendering” and “The Exchange Offers—Your Representations to Us” of this prospectus and in the letter of transmittal. In addition, if a broker-dealer acquired original notes as a result of market-making activities or other trading activities, it may exchange them for exchange notes; however, such broker-dealer may be deemed to be an “underwriter” within the meaning of the Securities Act and must, therefore, deliver a prospectus meeting the requirements of the Securities Act in connection with any resales of the exchange notes received by such broker-dealer and such broker-dealer will be required to acknowledge the same. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an underwriter within the meaning of the Securities Act. A broker-dealer may use this prospectus, as amended or supplemented, in connection with these resales, and all dealers effecting transactions in the exchange notes may be required to deliver a prospectus, as amended or supplemented for 180 days following consummation of the exchange offers or until such time that the broker-dealer is no longer required to deliver a prospectus in connection with market-making or other trading activities. We will provide copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents during such 180-day (or shorter, if no longer required to deliver a prospectus) period in order to facilitate such resales. We have agreed to pay all expenses incident to the exchange offers (including certain expenses of counsel for the initial purchasers) other than dealers’ and brokers’ discounts, commissions and counsel fees and will indemnify the holders of the exchange notes (including any broker-dealer) against certain liabilities, including liabilities under the Securities Act.

We will not receive any proceeds from any sale of exchange notes by broker-dealers. Exchange notes received by broker-dealers for their own account in the exchange offers may be sold from time to time in one or more transactions:

 

  •  

in the over-the-counter market,

 

  •  

in negotiated transactions,

 

  •  

through the writing of options on the exchange notes, or

 

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  •  

a combination of such methods of resale.

The prices at which these sales occur may be:

 

  •  

at market prices prevailing at the time of resale,

 

  •  

at prices related to such prevailing market prices, or

 

  •  

at negotiated prices.

Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any exchange notes. Any profit on any resale of exchange notes and any commission or concessions received by any such persons may be deemed to be underwriting compensation.

 

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LEGAL MATTERS

Certain legal matters in connection with the exchange of the Notes will be passed upon for us by Perkins Coie LLP, Seattle, Washington.

EXPERTS

The financial statements as of December 31, 2025 and 2024 and for each of the three years in the period ended December 31, 2025 and management’s assessment of the effectiveness of internal control over financial reporting (which is included in Management’s Report on Internal Control over Financial Reporting) as of December 31, 2025 included in this prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

 

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WHERE YOU CAN FIND MORE INFORMATION

We and our subsidiary PSE each file reports and other information with the SEC. Such material may also be accessed electronically by means of the SEC’s website on the Internet at www.sec.gov. Additionally, Puget Energy’s and PSE’s reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available or may be accessed free of charge at the Company’s website, www.pugetenergy.com. Information included on these websites is not incorporated by reference into this prospectus.

We have filed with the SEC a registration statement on Form S-4 relating to the securities covered by this prospectus. This prospectus is a part of the registration statement and does not contain all of the information in the registration statement. Whenever a reference is made in this prospectus to a contract or other document of ours, please be aware that the reference is only a summary and that you should refer to the exhibits that are a part of the registration statement for a copy of the contract or other document. You may review a copy of the registration statement through the SEC’s website.

 

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P1YP1YP1YP1YP1YP1Yhttp://fasb.org/us-gaap/2025#OtherLiabilitiesCurrenthttp://fasb.org/us-gaap/2025#PublicUtilitiesPropertyPlantAndEquipmentNethttp://fasb.org/us-gaap/2025#PublicUtilitiesPropertyPlantAndEquipmentNethttp://fasb.org/us-gaap/2025#OtherLiabilitiesCurrent
INDEX TO FINANCIAL STATEMENTS
 
AUDITED CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2025, 2024 AND 2023:
  
 
Page
 
    
F-2
 
     F-4  
    
F-5
 
    
F-8
 
    
F-9
 
    
F-10
 
    
F-12
 
    
F-13
 
    
F-15
 
    
F-68
 
    
F-72
 
UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS FOR THE THREE MONTHS ENDED MARCH 31, 2026 AND 2025:
  
    
F-73
 
    
F-74
 
    
F-75
 
    
F-77
 
    
F-78
 
    
F-79
 
 
F-1

AUDITED CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2025, 2024 AND 2023
Report of Management and Statement of Responsibility
PUGET ENERGY, INC. AND PUGET SOUND ENERGY, INC.
Puget Energy, Inc. and Puget Sound Energy, Inc. (the Company) management assumes accountability for maintaining compliance with our established financial accounting policies and for reporting our results with objectivity and integrity. The Company believes it is essential for investors and other users of the consolidated financial statements to have confidence that the financial information we provide is timely, complete, relevant and accurate. Management is also responsible to present fairly Puget Energy’s and Puget Sound Energy’s consolidated financial statements, prepared in accordance with GAAP.
Management, with oversight of the Board of Directors, established and maintains a strong ethical climate under the guidance of our 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
 
F-2

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
Mary E. Kipp      Jamie Martin      Stacy Smith
President and Chief Executive Officer      Senior Vice President and Chief Financial Officer     
Controller and Principal
Accounting Officer
February 19, 2026
 
F-3

Management’s Report on Internal Control Over Financial Reporting
Puget Energy’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule
13a-15(f)
under the Securities Exchange Act of 1934). Under the supervision and with the participation of Puget Energy’s President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, Puget Energy’s management assessed the effectiveness of internal control over financial reporting based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, Puget Energy’s management concluded that its internal control over financial reporting was effective as of December 31, 2025.
Puget Energy’s effectiveness of internal control over financial reporting as of December 31, 2025, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
February 19, 2026
 
F-4

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, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 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, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s 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
 
F-5

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 $1,712.1 million of regulatory assets and $1,878.8 million of regulatory liabilities as of December 31, 2025. 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
 
F-6

regulatory liabilities; (ii) testing new and 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
February 19, 2026
We have served as the Company’s or its predecessor’s auditor since 1933.
 
F-7

PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands)
 
     Year Ended December 31,  
     2025     2024     2023  
Operating revenue:
      
Electric
   $ 3,891,177   $ 3,332,695   $ 3,345,867
Natural gas
     1,458,636     1,488,570     1,423,276
Other
     66,520     34,950     47,431
  
 
 
   
 
 
   
 
 
 
Total operating revenue
     5,416,333     4,856,215     4,816,574
  
 
 
   
 
 
   
 
 
 
Operating expenses:
      
Energy costs:
      
Purchased electricity
     1,383,812     1,196,897     1,110,572
Electric generation fuel
     332,691     336,725     457,287
Residential exchange
     (82,213 )      (85,175 )      (77,223 ) 
Purchased natural gas
     555,672     679,433     641,371
Unrealized (gain) loss on derivative instruments, net
     —      (33,911 )      284,495
Utility operations and maintenance
     922,224     785,088     735,278
Non-utility
expense and other
     65,189     46,056     56,515
Depreciation and amortization
     851,328     787,986     751,335
Conservation amortization
     171,605     137,147     121,340
Taxes other than income taxes
     460,341     398,773     404,538
  
 
 
   
 
 
   
 
 
 
Total operating expenses
     4,660,649     4,249,019     4,485,508
  
 
 
   
 
 
   
 
 
 
Operating income (loss)
     755,684     607,196     331,066
Other income (deductions):
      
Other income
     137,488     102,882     66,829
Other expense
     (37,161 )      (19,566 )      (14,765 ) 
Interest charges:
      
AFUDC
     36,426     37,660     24,687
Interest expense
     (468,902 )      (432,194 )      (381,511 ) 
  
 
 
   
 
 
   
 
 
 
Income (loss) before income taxes
     423,535     295,978     26,306
Income tax (benefit) expense
     54,167     30,723     (27,434 ) 
  
 
 
   
 
 
   
 
 
 
Net income (loss)
   $ 369,368   $ 265,255   $ 53,740
  
 
 
   
 
 
   
 
 
 
The accompanying notes are an integral part of the consolidated financial statements.
 
F-8

PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in Thousands)
 
     Year Ended December 31,  
     2025      2024      2023  
Net income (loss)
   $ 369,368    $ 265,255    $ 53,740
  
 
 
    
 
 
    
 
 
 
Other comprehensive income (loss):
        
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $8,683, $9,144 and $8,916, respectively
     32,661      25,629      42,313
  
 
 
    
 
 
    
 
 
 
Other comprehensive income (loss)
     32,661      25,629      42,313
  
 
 
    
 
 
    
 
 
 
Comprehensive income (loss)
   $ 402,029    $ 290,884    $ 96,053
  
 
 
    
 
 
    
 
 
 
The accompanying notes are an integral part of the consolidated financial statements.
 
F-9

PUGET ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
ASSETS
 
     December 31,  
     2025     2024  
Utility plant (at original cost, including construction work in progress of $1,082,208 and $1,577,695, respectively):
    
Electric plant
   $ 13,745,675   $ 12,476,380
Natural gas plant
     5,428,156     5,178,523
Common plant
     1,247,883     1,089,618
Less: Accumulated depreciation and amortization
     (5,555,794 )      (5,101,926 ) 
  
 
 
   
 
 
 
Net utility plant
     14,865,920     13,642,595
  
 
 
   
 
 
 
Other property and investments:
    
Goodwill
     1,656,513     1,656,513
Other property and investments
     289,861     307,813
  
 
 
   
 
 
 
Total other property and investments
     1,946,374     1,964,326
  
 
 
   
 
 
 
Current assets:
    
Cash and cash equivalents
     40,484     101,836
Restricted cash
     118,369     38,865
Accounts receivable, net of allowance for doubtful accounts of $26,452 and $40,436, respectively
     511,163     538,930
Unbilled revenue
     332,087     273,420
Materials and supplies, at average cost
     232,947     201,847
Fuel and natural gas inventory, at average cost
     83,535     88,964
Unrealized gain on derivative instruments
     37,448     32,591
GHG emission allowances
     22,788     43,592
Prepaid expenses and other
     132,669     83,851
Power contract acquisition adjustment gain
     3,565     4,122
  
 
 
   
 
 
 
Total current assets
     1,515,055     1,408,018
  
 
 
   
 
 
 
Other long-term and regulatory assets:
    
Power cost adjustment mechanism
     143,687     61,202
Regulatory assets related to power contracts
     3,705     4,779
Other regulatory assets
     1,564,693     1,355,291
Unrealized gain on derivative instruments
     11,261     6,245
Power contract acquisition adjustment gain
     22,878     26,444
Operating lease
right-of-use
asset
     460,990     181,397
Other
     372,230     310,094
  
 
 
   
 
 
 
Total other long-term and regulatory assets
     2,579,444     1,945,452
  
 
 
   
 
 
 
Total assets
   $ 20,906,793   $ 18,960,391
  
 
 
   
 
 
 
The accompanying notes are an integral part of the consolidated financial statements.
 
F-10

PUGET ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
CAPITALIZATION AND LIABILITIES
 
    December 31,  
    2025     2024  
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     3,816,332
Retained earnings
    1,815,186     1,508,705
Accumulated other comprehensive income (loss), net of tax
    75,829     43,168
 
 
 
   
 
 
 
Total common shareholder’s equity
    5,707,347     5,368,205
 
 
 
   
 
 
 
Long-term debt:
   
First mortgage bonds and senior notes
    6,345,000     5,845,000
Pollution control bonds
    161,860     161,860
Long-term debt
    2,200,000     1,600,000
Debt discount, issuance costs and other
    (181,828 )      (182,941 ) 
 
 
 
   
 
 
 
Total long-term debt
    8,525,032     7,423,919
 
 
 
   
 
 
 
Total capitalization
    14,232,379     12,792,124
 
 
 
   
 
 
 
Current liabilities:
   
Accounts payable
    642,044     549,710
Short-term debt
    487,500     378,400
Current maturities of long-term debt
    —      417,000
Accrued expenses:
   
Taxes
    125,719     105,080
Salaries and wages
    84,248     74,294
Interest
    80,969     66,113
Unrealized loss on derivative instruments
    359,890     218,443
Power contract acquisition adjustment loss
    963     1,074
Operating lease liabilities
    104,240     22,761
Compliance obligation
    22,788     43,592
Other
    84,341     105,605
 
 
 
   
 
 
 
Total current liabilities
    1,992,702     1,982,072
 
 
 
   
 
 
 
Other Long-term and regulatory liabilities:
   
Deferred income taxes
    941,823     997,680
Unamortized investment tax credits
    186,250     — 
Unrealized loss on derivative instruments
    213,531     171,488
Purchased gas adjustment liability
    65,931     58,657
Regulatory liabilities
    1,087,668     1,075,620
Regulatory liability for deferred income taxes
    698,727     721,907
Regulatory liabilities related to power contracts
    26,443     30,566
Power contract acquisition adjustment loss
    2,742     3,705
Operating lease liabilities
    365,359     166,700
Finance lease liabilities
    167,426     96,850
Compliance obligation
    96,490     73,049
Other deferred credits
    829,322     789,973
 
 
 
   
 
 
 
Total long-term and regulatory liabilities
    4,681,712     4,186,195
 
 
 
   
 
 
 
Commitments and contingencies (Note 15)
   
 
 
 
   
 
 
 
Total capitalization and liabilities
  $ 20,906,793   $ 18,960,391
 
 
 
   
 
 
 
The accompanying notes are an integral part of the consolidated financial statements.
 
F-11

PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY
(Dollars in Thousands)
 
    Common Stock    
Additional Paid-in

Capital
    Retained
Earnings
    Accumulated Other
Comprehensive Income (Loss)
    Total Equity  
    Shares     Amount  
Balance at December 31, 2022
    200     $ —      $ 3,523,532   $ 1,465,331   $ (24,774 )    $ 4,964,089
Net income (loss)
    —        —        —        53,740     —        53,740
Common stock dividend paid
    —        —        —        (99,760 )      —        (99,760 ) 
Other comprehensive income (loss)
    —        —        —        —        42,313     42,313
 
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
Balance at December 31, 2023
    200     $ —      $ 3,523,532   $ 1,419,311   $ 17,539   $ 4,960,382
Net income (loss)
    —        —        —        265,255     —        265,255
Common stock dividend paid
    —        —        —        (175,861 )      —        (175,861 ) 
Capital contribution
    —        —        292,800       —        —        292,800
Other comprehensive income (loss)
    —        —        —        —        25,629     25,629
 
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
Balance at December 31, 2024
    200     $ —      $ 3,816,332   $ 1,508,705   $ 43,168   $ 5,368,205
Net income (loss)
    —        —        —        369,368     —        369,368
Common stock dividend paid
    —        —        —        (62,887 )      —        (62,887 ) 
Other comprehensive income (loss)
    —        —        —        —        32,661     32,661
 
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
Balance at December 31, 2025
    200     $ —       $ 3,816,332   $ 1,815,186   $ 75,829   $ 5,707,347
 
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
The accompanying notes are an integral part of the consolidated financial statements.
 
F-12

PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
 
     Year Ended December 31,  
     2025     2024     2023  
Operating Activities:
      
Net Income (Loss)
   $ 369,368   $ 265,255   $ 53,740
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
      
Depreciation and amortization
     851,328     787,986     751,335
Conservation amortization
     171,605     137,147     121,340
Deferred income taxes and tax credits, net
     10,635     (747 )      (94,835 ) 
Net unrealized (gain) loss on derivative instruments
     —      (33,911 )      284,495
AFUDC - equity
     (62,555 )      (59,466 )      (39,012 ) 
Other
non-cash
     34,676     22,476     9,966
Proceeds from sale of transferable tax credits
     91,455     —      — 
Funding of pension liability
     (18,000 )      (18,000 )      (18,000 ) 
Regulatory assets and liabilities
     (84,279 )      (89,838 )      153,069
Purchased gas adjustment
     7,273     (73,426 )      152,763
GHG emission allowances
     (333,169 )      (154,728 )      (129,195 ) 
Other long term assets and liabilities
     (14,127 )      (3,674 )      (16,714 ) 
Change in certain current assets and liabilities:
      
Accounts receivable and unbilled revenue
     (30,900 )      (22,307 )      138,646
Materials and supplies
     (31,100 )      (28,402 )      (41,273 ) 
Fuel and natural gas inventory
     3,725     (1,526 )      6,565
Prepayments and other
     (28,239 )      (8,873 )      (33,402 ) 
Accounts payable
     73,049     79,184     (244,030 ) 
Taxes payable
     20,639     2,453     (13,471 ) 
Other
     29,719     23,220     11,408
  
 
 
   
 
 
   
 
 
 
Net cash provided by (used in) operating activities
     1,061,103     822,823     1,053,395
  
 
 
   
 
 
   
 
 
 
Investing Activities:
      
Construction expenditures - excluding equity AFUDC
     (1,771,828 )      (1,609,715 )      (1,466,565 ) 
Other
     4,162     1,872     14,047
  
 
 
   
 
 
   
 
 
 
Net cash provided by (used in) investing activities
     (1,767,666 )      (1,607,843 )      (1,452,518 ) 
  
 
 
   
 
 
   
 
 
 
Financing Activities:
      
Change in short-term debt, net
     109,100     (219,700 )      122,500
Dividends paid
     (62,887 )      (175,861 )      (99,760 ) 
Capital contribution
     —      292,800     — 
Proceeds from long-term debt and bonds issued
     1,091,725     793,892     396,488
Redemption of bonds and notes
     (417,000 )      —      — 
Seller Financing
     (21,739 )      —   
Other
     25,516     20,015     25,685
  
 
 
   
 
 
   
 
 
 
Net cash provided by (used in) financing activities
     724,715     711,146     444,913
  
 
 
   
 
 
   
 
 
 
Net increase (decrease) in cash, cash equivalents, and restricted cash
     18,152     (73,874 )      45,790
Cash, cash equivalents, and restricted cash at beginning of period
     140,701     214,575     168,785
  
 
 
   
 
 
   
 
 
 
Cash, cash equivalents, and restricted cash at end of period
   $ 158,853   $ 140,701   $ 214,575
  
 
 
   
 
 
   
 
 
 
 
F-13

     Year Ended December 31,  
     2025      2024      2023  
Supplemental cash flow information:
        
Cash payments for interest (net of capitalized interest)
   $ 401,623    $ 376,317    $ 339,677
Cash payments (refunds) for income taxes
     22,496      37,065      71,817
Non-cash
financing and investing activities:
        
Accounts payable for capital expenditures eliminated from cash flow
   $ 130,120    $ 110,311    $ 97,892
Seller financing accrued liabilities for capital expenditures eliminated from cash flow
     11,114      1,700      21,739
Recognition of finance lease eliminated from cash flows
     75,936      1,832      1,245
Capital expenditures due to change in ARO estimate eliminated from cash flow
     3,037      20,255      (2,206 ) 
The accompanying notes are an integral part of the consolidated financial statements.
 
F-14

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 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.
 
F-15

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 3.6%, 3.4%, and 3.4% in 2025, 2024, and 2023, respectively; depreciable natural gas utility plant was 3.2%, 3.2%, and 3.2% in 2025, 2024, and 2023, respectively; and depreciable common utility plant was 6.7%, 6.6% and 6.5% in 2025, 2024, and 2023, 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, 2025, December 31, 2024 and December 31, 2023.
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.
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.
 
F-16

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” below.
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. 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
 
F-17

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 $384.7 million, $329.9 million and $319.1 million for 2025, 2024, and 2023, 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, 2025, and 2024:
 
Puget Energy and
Puget Sound Energy
             
(Dollars in Thousands)    Year Ended December 31,  
Allowance for credit losses:
     2025        2024  
  
 
 
    
 
 
 
Beginning balance
   $ 40,436    $ 38,211
Provision for credit loss expense
1
     31,343      43,573
Receivables
charged-off
     (45,327 )       (41,348 ) 
  
 
 
    
 
 
 
Total ending allowance balance
   $ 26,452    $ 40,436
  
 
 
    
 
 
 
 
1
$21.4 million and $37.1 million of provision related to balances of deferred costs specific to
COVID-19
as of December 31, 2025 and 2024, respectively.
 
F-18

Self-Insurance
PSE is self-insured for storm damage and certain environmental contamination associated with current operations occurring on
PSE-owned
property. In addition, PSE is required to meet a deductible for a portion of the risk associated with comprehensive liability, workers’ compensation claims and catastrophic property losses other than those which are storm related. Under the 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.
Investment tax credits are included in other long-term and regulatory liabilities and are accounted for using the deferral method. Under the deferral method, the benefit of the ITC is amortized over the useful life of the underlying asset as a reduction to deferred income tax expense. For additional information, see Note 13, “Income Taxes” below.
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 record
ed on the b
alance 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.
 
F-19

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, 2025, the fair value of these derivatives were recorded on the Company’s balance sheet as a derivative asset of $48.7 million and a derivative liability of $573.4 million. The difference of $524.7 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” below.
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 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
 
F-20

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 are generally accounted for under a financing model. However, consistent with lease accounting standards, PSE recognizes 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
PSE has certain PPAs in which PSE has variable interests mainly including fixed price contracts for renewable energy. The most significant economic activity for these variable interest entities (VIEs) is typically the operation and maintenance of the facility, which is performed by the seller. Therefore, the Company is not the primary beneficiary of any of these VIEs as it does not control the commercial and operating activities that most significantly impact the economic performance of the entities.
The carrying amount of any assets and liabilities related to these VIEs in the Company’s balance sheets represent amounts due from the PPAs. The Company can recover these costs through the PCA mechanism. The Company has no residual interest in the entities and has not provided or guaranteed any debt or equity support, liquidity arrangements, performance guarantees, or other commitments associated with these contracts. The aggregate contracted capacity from these VIE projects was 813.8 MW and 723.8 MW at December 31, 2025 and 2024. Purchased energy of $91.6 million, $88.9 million and $86.0 million were recognized in purchased electricity on the Company’s consolidated statements of income for the years ended December 31, 2025, December 31, 2024 and December 31, 2023, respectively. Additionally, $14.5 million and $11.6 million were included in accounts payable on the Company’s balance sheets as of December 31, 2025 and December 31, 2024, respectively.
 
 
(2)
New Accounting Pronouncements
Recently Adopted Accounting Guidance
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
was 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, 2025, 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
was effective for the Company in annual periods beginning after December 15, 2024. As of December 31, 2025, the Company’s disclosures are consistent with the amendment.
 
F-21

Accounting Standards Issued but Not Yet Adopted
Interim Reporting
In December 2025, the FASB issued ASU
No. 2025-11,
“Interim Reporting (Topic 270): Narrow-Scope Improvements.” ASU
2025-11
is intended to clarify what disclosures should be provided and clarify when the guidance is applicable. The amendments of ASU
2025-11
should be applied prospectively and are effective for annual and interim periods beginning after December 15, 2027, with early adoption permitted. The Company is currently evaluating the impact of adopting ASU
2025-11
on its consolidated financial statements and related disclosures.
Government Grants
In December 2025, the FASB issued ASU
No. 2025-10,
“Government Grants (Topic 832).” ASU
2025-10
establishes authoritative guidance regarding recognition, measurement and presentation for government grants received by business entities. The amendments of ASU
2025-10
should be applied prospectively and are effective for annual and interim periods beginning after December 15, 2028, with early adoption permitted. The Company is currently evaluating the impact of adopting ASU
2025-10
on its consolidated financial statements and related disclosures.
Derivatives and Hedging and Revenue with Contracts with Customers
In September 2025, the FASB issued ASU
No. 2025-07,
“Derivatives and Hedging (Topic 815) and Revenue from Contract with Customers (Topic 606).” ASU
2025-07
addresses stakeholders’ concerns about (i) the application of derivative accounting to contracts with features based on activities or operations of a party to the contract and (ii) the diversity of accounting for share -based
non-cash
consideration. The amendments of ASU
2025-07
should be applied prospectively and are effective for annual and interim periods beginning after December 15, 2026, with early adoption permitted. The Company is currently evaluating the impact of adopting ASU
2025-07
on its consolidated financial statements and related disclosures.
Intangibles - Goodwill and Other -
Internal-Use
Software
In September 2025, the FASB issued ASU
No. 2025-06,
“Intangibles - Goodwill and Other -
Internal-Use
Software (Subtopic
350-40).”
ASU
2025-06
modernizes the accounting for software costs that are accounted for under Subtopic
350-40.
The amendments of ASU
2025-06
should be applied prospectively and are effective for annual and interim periods beginning after December 15, 2027, with early adoption permitted. The Company is currently evaluating the impact of adopting ASU
2025-06
on its consolidated financial statements and related disclosures.
Measurement of Credit Losses Disclosures
In July 2025, the FASB issued ASU
No. 2025-05,
“Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses for Accounts Receivable and Contract Assets.” ASU
2025-05
provides a practical expedient that allows entities to assume that current conditions as of the balance sheet date do not change for the remaining life of the asset when estimating expected credit losses for current accounts receivable and current contract assets. The amendments of ASU
2025-05
should be applied prospectively and are effective for annual and interim periods beginning after December 15, 2025, with early adoption permitted. The Company is currently evaluating the impact of adopting ASU
2025-05
on its consolidated financial statements and related disclosures.
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
 
F-22

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, 2025, December 31, 2024, and December 31, 2023:
Puget Energy and Puget Sound Energy
 
(Dollars in Thousands)    Year Ended December 31, 2025  
     Electric      Natural Gas      Other      Total  
Revenue from contracts with customers:
           
Retail
           
Residential
   $ 1,944,566    $ 900,996    $ —       $ 2,845,562
Commercial
     1,339,883      422,050      —       1,761,933
Industrial
     146,595      26,569      —       173,164
Other
     19,317      —       —       19,317
Wholesale
     349,197      —       —       349,197
Transmission and transportation
     44,658      31,666      —       76,324
Miscellaneous
1
     32,213      99,560      24,634      156,407
  
 
 
    
 
 
    
 
 
    
 
 
 
Total revenue from contracts with customers
   $ 3,876,429    $ 1,480,841    $ 24,634    $ 5,381,904
  
 
 
    
 
 
    
 
 
    
 
 
 
Total other revenue
2
     14,748      (18,484 )       —       (3,736 ) 
  
 
 
    
 
 
    
 
 
    
 
 
 
Total PSE operating revenue
   $ 3,891,177    $ 1,462,357    $ 24,634    $ 5,378,168
  
 
 
    
 
 
    
 
 
    
 
 
 
Puget LNG operating revenue
   $ —       $ —       $ 41,886    $ 41,886
Intercompany eliminations
     —       (3,721 )       —       (3,721 ) 
  
 
 
    
 
 
    
 
 
    
 
 
 
Total Puget Energy operating revenue
   $ 3,891,177    $ 1,458,636    $ 66,520    $ 5,416,333
  
 
 
    
 
 
    
 
 
    
 
 
 
 
1.
 
Miscellaneous natural gas revenue includes $96.4 million for the regulatory offset of CCA auction proceeds passed back to customers.
2.
 
Total other revenue includes revenues from derivatives and alternative revenue programs that are not considered revenues from contracts with customers.
Puget Energy and Puget Sound Energy
 
(Dollars in Thousands)    Year Ended December 31, 2024  
     Electric      Natural Gas      Other      Total  
Revenue from contracts with customers:
           
Retail
           
Residential
   $ 1,677,599    $ 796,889    $ —       $ 2,474,488
Commercial
     1,159,596      367,988      —       1,527,584
Industrial
     131,869      26,764      —       158,633
Other
     23,601      —       —       23,601
Wholesale
     286,364      —       —       286,364
Transmission and transportation
     33,911      34,558      —       68,469
 
F-23

(Dollars in Thousands)    Year Ended December 31, 2024  
     Electric      Natural Gas      Other      Total  
Revenue from contracts with customers:
           
Miscellaneous
1
     35,274      246,708      282      282,264
  
 
 
    
 
 
    
 
 
    
 
 
 
Total revenue from contracts with customers
   $ 3,348,214    $ 1,472,907    $ 282    $ 4,821,403
  
 
 
    
 
 
    
 
 
    
 
 
 
Total other revenue
2
     (15,519 )       19,347      —       3,828
  
 
 
    
 
 
    
 
 
    
 
 
 
Total PSE operating revenue
   $ 3,332,695    $ 1,492,254    $ 282    $ 4,825,231
  
 
 
    
 
 
    
 
 
    
 
 
 
Puget LNG operating revenue
   $ —       $ —       $ 34,668    $ 34,668
Intercompany eliminations
     —       (3,684 )       —       (3,684 ) 
  
 
 
    
 
 
    
 
 
    
 
 
 
Total Puget Energy operating revenue
   $ 3,332,695    $ 1,488,570    $ 34,950    $ 4,856,215
  
 
 
    
 
 
    
 
 
    
 
 
 
 
1.
 
Miscellaneous natural gas revenue includes $253.0 million for the regulatory offset of CCA auction proceeds passed back to customers.
2.
 
Total other revenue includes revenues from derivatives and alternative revenue programs that are not considered revenues from contracts with customers.
Puget Energy and Puget Sound Energy
 
(Dollars in Thousands)    Year Ended December 31, 2023  
     Electric      Natural Gas      Other      Total  
Revenue from contracts with customers:
           
Retail
           
Residential
   $ 1,514,149      $ 868,462      $ —       $ 2,382,611  
Commercial
     1,071,385        390,333                 1,461,718
Industrial
     123,548        29,461        —       153,009
Other
     21,199        —       —       21,199
Wholesale
     498,251        —       —       498,251
Transmission and transportation
     46,141        28,616        —       74,757
Miscellaneous
1
     25,231        67,164        16,383        108,778
  
 
 
    
 
 
    
 
 
    
 
 
 
Total revenue from contracts with customers
   $ 3,299,904      $ 1,384,036      $ 16,383      $ 4,700,323  
  
 
 
    
 
 
    
 
 
    
 
 
 
Total other revenue
2
     45,963        40,332        —         86,295
  
 
 
    
 
 
    
 
 
    
 
 
 
Total PSE operating revenue
   $ 3,345,867      $ 1,424,368      $ 16,383      $ 4,786,618  
  
 
 
    
 
 
    
 
 
    
 
 
 
Puget LNG operating revenue
   $ —       $ —       $ 31,048      $ 31,048  
Intercompany eliminations
     —         (1,092 )       —         (1,092 ) 
  
 
 
    
 
 
    
 
 
    
 
 
 
Total Puget Energy operating revenue
   $ 3,345,867      $ 1,423,276      $ 47,431      $ 4,816,574  
  
 
 
    
 
 
    
 
 
    
 
 
 
 
1.
 
Miscellaneous natural gas revenue includes $98.4 million for the regulatory offset of CCA auction proceeds passed back to customers.
2.
 
Total other revenue includes revenues from derivatives 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.
 
F-24

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, 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.
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.
Puget LNG
In December 2020, Puget LNG entered into a contract with one customer where Puget LNG is selling LNG over a
10-year
delivery period that began April 1, 2024. The contract requires the customer to purchase a
 
F-25

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:
 
Puget Energy
                    
(Dollars in Thousands)
   2026      2027      2028      2029      2030      Thereafter      Total  
Remaining Performance Obligations
   $ 17,989    $ 19,454    $ 19,454    $ 19,454    $ 19,454    $ 63,227    $ 159,032
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, 2025, and 2024, are included in the following tables:
 
Puget Sound Energy
   Remaining Amortization Period    December 31,  
(Dollars in Thousands)    2025      2024  
PCA unrealized loss
   N/A    $ 451,359    $ 284,166
Environmental remediation
   (a)      179,129      180,245
PCA mechanism
   N/A      143,687      61,202
Storm damage costs electric
   1 to 4 years      126,237      120,431
CCA schedule 111 recovery
   N/A      99,388      — 
Energy conservation costs
   (a)      97,320      75,373
Automated meter reading
   18 years      92,685      98,572
PGA unrealized loss
   N/A      73,352      66,929
Baker Dam licensing operating and maintenance costs
   (b)      59,175      56,201
Deferred Washington Commission AFUDC
   30 years      54,985      55,427
Decoupling deferrals and interest
   Less than 2 years      43,419      51,838
Chelan PUD contract initiation
   5.8 years      41,347      48,435
Washington Commission
COVID-19
   N/A      40,966      37,089
Washington Commission LNG
   N/A      31,269      38,070
Unamortized loss on reacquired debt
   2 to 42 years      27,749      29,680
 
F-26

Puget Sound Energy
   Remaining Amortization Period    December 31,  
(Dollars in Thousands)    2025      2024  
Generation plant major maintenance, less Colstrip
   1 to 9 years      27,278      18,975
Lower Snake River
   11.4 years      26,844      35,429
Deferred lease expense
   (a)      22,542      18,862
Various other regulatory assets
   (a)      69,649      139,569
     
 
 
    
 
 
 
Total PSE regulatory assets
      $ 1,708,380    $ 1,416,493
     
 
 
    
 
 
 
Cost of removal
   (c)    $ (822,090 )     $ (748,095 ) 
Deferred income taxes
(d)
   N/A      (699,225 )       (722,558 ) 
Repurposed production tax credits
   N/A      (103,689 )       (110,746 ) 
PGA liability
   2 years      (65,931 )       (58,657 ) 
Decoupling liability
   Less than 2 years      (48,249 )       (63,890 ) 
CCA natural gas allowance auction proceeds
   N/A      (46,367 )       — 
CCA schedule 111 recovery
   N/A      (28,647 )       (97,694 ) 
Various other regulatory liabilities
   (a)      (37,436 )       (54,002 ) 
     
 
 
    
 
 
 
Total PSE regulatory liabilities
      $ (1,851,634 )     $ (1,855,642 ) 
     
 
 
    
 
 
 
PSE net regulatory assets (liabilities)
      $ (143,254 )     $ (439,149 ) 
     
 
 
    
 
 
 
 
(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)
 
The balance is dependent upon the cost of removal of underlying assets and the life of utility plant.
(d)
 
For additional information, see Note 13, “Income Taxes” below.
 
Puget Energy
   Remaining Amortization Period    December 31,  
(Dollars in Thousands)    2025      2024  
Total PSE regulatory assets
   (a)    $ 1,708,380    $ 1,416,493
Puget Energy acquisition adjustments:
        
Regulatory assets related to power contracts
   2 to 26 years      3,705      4,779
     
 
 
    
 
 
 
Total Puget Energy regulatory assets
      $ 1,712,085    $ 1,421,272
     
 
 
    
 
 
 
Total PSE regulatory liabilities
   (a)    $ (1,851,634 )     $ (1,855,642 ) 
Puget Energy acquisition adjustments:
        
Deferred income taxes
        498      651
Regulatory liabilities related to power contracts
   2 to 26 years      (26,443 )       (30,566 ) 
 
F-27

Puget Energy
   Remaining Amortization Period      December 31,  
(Dollars in Thousands)    2025      2024  
Various other regulatory liabilities
     Varies        (1,190 )       (1,193 ) 
     
 
 
    
 
 
 
Total Puget Energy regulatory liabilities
      $ (1,878,769 )     $ (1,886,750 ) 
     
 
 
    
 
 
 
Puget Energy net regulatory asset (liabilities)
      $ (166,684 )     $ (465,478 ) 
     
 
 
    
 
 
 
 
(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 $822.1 million and $748.1 million in 2025 and 2024, respectively, for the cost of removal of utility plant. These amounts are collected from PSE’s customers through depreciation rates.
General Rate Case Filing
PSE filed a GRC which includes a
two-year
MYRP with the Washington Commission on February 15, 2024. On January 15, 2025, the Washington Commission issued an order on PSE’s 2024 GRC, in Docket Nos.
UE-240004
and
UG-240005,
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. On March 17, 2025, the Washington Commission issued an order denying PSE’s petition for reconsideration. The order also granted and denied certain petitions for reconsideration and clarification by other parties. The order approved PSE’s Targeted Electrification Pilot Phase II.
For further information on the prior rates, which were subject to the 2022 GRC, 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, 2024.
Liquefied Natural Gas Rate Adjustment
On April 24, 2024, the Washington Commission issued Final Order 07 in 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,
 
F-28

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 were 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. The parties agreed to seek direct review of the case by the Washington State Court of Appeals. The case was transferred to Division III of the Court of Appeals in March 2025. Petitioners, Public Counsel and the Puyallup Tribe of Indians filed opening briefs on July 11, 2025. Respondents, PSE and the Washington Commission filed briefs on September 10, 2025. Petitioners’ reply briefs were filed on October 10, 2025. A hearing date has not yet been set.
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” below.
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%. On December 19, 2024, the Washington Commission issued Order 01, requiring PSE to file revised tariff pages, with rates effective January 1, 2025, subject to refund pending final determination. The Washington Commission set the matter for adjudication, with a hearing held on September 3, 2025. On December 19, 2025, the Washington Commission concluded that an adjustment to the provisionally approved rate was necessary decreasing annual revenues by $6.9 million or 0.2% effective January 1, 2026.
On September 30, 2025, PSE filed proposed revisions to rates under the Colstrip Adjustment Rider Schedule 141COL with the Washington Commission in Docket No. 250733 for Colstrip Units 3 and 4 for calendar year 2026. The proposed revisions would decrease PSE’s annual revenues by $82.5 million, or 2.3%, including the $6.9 million mentioned above, due to an expected decrease from the removal of Colstrip plant and elimination of operating costs from rates. The revised tariff filed went into effect on January 1, 2026, by operation of law.
Climate Commitment Act Deferral
In 2023, PSE filed its initial revision to natural gas rates for the recovery of allowance costs and pass back of auction proceeds in Docket
UG-230968.
In this 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 its projected no cost allowances revenues. Subsequent filings were also made to revise the tariff rates for allowance costs and auction proceeds related to subsequent periods. The Washington Commission suspended the tariff sheets and subsequent updates but allowed the rates to go into effect on an interim basis, subject to refund, on January 1, 2024. The Washington Commission rejected all parties’ proposals for gas utility risk sharing of CCA compliance costs but indicated that it will consider whether a utility risk sharing mechanism is necessary in an ongoing rulemaking related to CCA implementation.
The ongoing recovery of allowance costs and pass back of proceeds from the sale of consigned
no-cost
allowances associated with PSE’s natural gas business activities is consistent with the approved accounting petitions in Docket Nos.
UG-220975
and
UG-230471.
As of December 31, 2025, PSE recorded a regulatory liability of $28.6 million, which represents the amounts to date over-collected in customer natural gas rates for CCA obligation costs, net of the expense incurred for the purchase of allowances for GHG emissions associated
 
F-29

with the Company’s natural gas business activities. Additionally, PSE will continue to consign for auction at least the minimum amount of
no-cost
emission allowances allocated for natural gas business activities 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, 2025, PSE recorded a regulatory liability of $46.4 million, which represents the proceeds received from the sale of consigned allowances sold at auction net of proceeds from the sale of consigned natural gas GHG emission allowances passed back through customer rates or used on approved decarbonization projects.
On May 2, 2025, PSE filed a revision to its electric tariff in Docket No.
UE-250321,
which proposed the establishment of a new schedule, Schedule 111 for electric, and will allow PSE to recover the costs associated with its electric compliance obligation. PSE’s proposal covered the recovery of its electric compliance costs incurred, or to be incurred, from January 2023 through December 2025, with a recovery period set for the period of August 1, 2025 through December 2026. On July 24, 2025, the Washington Commission approved the recovery of PSE’s estimated 2023 and 2024 compliance costs and a
pro-rata
portion of the 2025 estimated compliance costs. In Docket
UE-250901,
the Washington Commission approved the recovery of the remaining forecasted 2025 allowance obligation and a
true-up
to known compliance costs for 2023 and 2024, effective January 1, 2026.
The Order within Docket No.
UE-250321
also required PSE to file a proposal for future recovery of CCA costs, which was made in that same docket on October 1, 2025. On December 24, 2025, the Washington Commission approved Order 1 in Docket No.
UE-250747,
which approved the total cost of electric CCA compliance will be recovered through PSE’s power cost mechanism. Additionally, to the extent PSE uses no cost allowances granted by the WDOE for compliance, the benefit of this will be simultaneously passed back to customers through the electric Schedule 111 as approved in Docket No.
UE-250901.
When combined with the adjustment to Schedule 111, noted above, for the recovery of compliance costs, the annual net rate decrease beginning January 1, 2026, is $259.0 million or 7.2%.
As of December 31, 2025, PSE recorded a regulatory asset of $99.4 million, which represents the expense incurred for the purchase of allowances for the GHG emissions associated with the Company’s electric business activities, net of amounts to date collected in customer electric rates for CCA obligation costs.
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.
The following graduated scale used in the PCA mechanism resulted in the following Company and customer shares:
Puget Energy and
Puget Sound Energy
     At December 31, 2025  
(Dollars in Thousands)    Company’s Share      Customers’ Share      Total  
Annual power cost variability    Over     Under     Amount      Over     Under     Amount  
(Over) and under collected up to $17 million
     100 %      100 %    $ 17,000        - %      - %    $ —       $ 17,000  
(Over) and under collected between $17—$40 million
     35       50       11,500        65       50       11,500        23,000  
 
F-30

     At December 31, 2025  
(Dollars in Thousands)    Company’s Share      Customers’ Share      Total  
Annual power cost variability    Over      Under      Amount      Over      Under      Amount  
(Over) or under collected beyond $40 million
     10        10        15,521        90        90        139,693        155,214  
Interest
           —               4,453        4,453  
        
 
 
          
 
 
    
 
 
 
Total (over) / under recovery
         $ 44,021            $ 155,646      $ 199,667  
        
 
 
          
 
 
    
 
 
 
Puget Energy and
Puget Sound Energy
     At December 31, 2024  
(Dollars in Thousands)    Company’s Share      Customers’ Share      Total  
Annual power cost variability    Over     Under     Amount      Over     Under     Amount  
(Over) and under collected up to $17 million
     100 %      100 %    $ 17,000        —  %      —  %    $ —       $ 17,000  
(Over) and under collected between $17—$40 million
     35       50       11,500        65       50       11,500        23,000  
(Over) or under collected beyond $40 million
     10       10       8,328        90       90       74,952        83,280  
Interest
         —             3,872        3,872  
      
 
 
        
 
 
    
 
 
 
Total (over) / under recovery
       $ 36,828          $ 90,324      $ 127,152  
      
 
 
        
 
 
    
 
 
 
PSE filed a tariff requesting an update to the PCA mechanism in 2026 within Docket No.
UE-250747,
which was filed concurrently with the proposed tariff revision for Schedule 111, in Docket No.
UE-250901,
discussed above. The former revision requested an increase of $748.4 million or 20.8% and incorporated updated market prices for natural gas and CCA emissions allowances, along with corrected forced outage rates for PSE’s natural
gas-fired
generators. The Washington Commission approved PSE’s tariff revisions filed, effective January 1, 2026, subject to condition that these tariff revisions will be subject to review and revision in PSE’s next GRC and will be effective until the conclusion of that case or February 28, 2027, whichever occurs first.
On July 8, 2025, PSE filed a tariff revision in Docket No.
UE-250537
requesting that the Washington Commission eliminate the deadband and sharing bands in the PCA mechanism. The tariff revision is set for hearing in April 2026. There are currently motions pending to dismiss PSE’s filing, which have not yet been ruled on by the Washington Commission.
On April 30, 2025, PSE filed the 2024 PCA compliance report in Docket No.
UE-250318.
PSE proposed that the $3.1 million difference between the 2024 forecasted deferred balance of $98.2 million, which was set in rates from October 1, 2024, to December 31, 2025, and the actual 2024 deferred balance of $95.1 million be returned to the PCA tracking account for future disposition. Additionally, PSE requested to recover the forecasted 2025 deferred balance of $80.6 million from October 1, 2025 to December 31, 2026. On September 29, 2025, the Washington Commission approved the report, but required PSE to refund the $3.1 million difference.
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
On October 23, 2025, the Washington Commission approved PSE’s request for PGA rates in Docket No.
UG-250704,
effective November 1, 2025. As part of that filing, PSE requested an annual overall revenue
 
F-31

decrease of $55.1 million, where PGA rates, under Schedule 101, decrease annual revenue by $7.9 million and the tracker rates, under Schedule 106, decrease annual revenue by $47.2 million.
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 a counterparty refund of $28.1 million 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, 2025 and December 31, 2024:
Puget Energy and
Puget Sound Energy
     
(Dollars in Thousands)    Year Ended December 31,  
PGA (liability)/receivable balance and activity    2025      2024  
PGA (liability)/receivable beginning balance
   $ (58,657 )     $ (132,082 ) 
Actual natural gas costs
     397,465      416,067
Allowed PGA recovery
     (399,347 )       (336,170 ) 
Interest
     (5,392 )       (6,472 ) 
  
 
 
    
 
 
 
PGA (liability)/receivable ending balance
   $ (65,931 )     $ (58,657 ) 
  
 
 
    
 
 
 
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, 2025, PSE incurred $46.2 million in weather-related electric transmission and distribution system restoration costs, of which the Company deferred $28.3 million and $6.0 million as regulatory assets related to storms that occurred in 2025 and 2024, respectively. This compares to $74.5 million incurred in weather-related electric transmission and distribution system restoration costs for the year ended December 31, 2024, of which the Company deferred $58.9 million and zero as regulatory assets related to storms that occurred in 2024 and 2023, respectively. Under the 2024 GRC Order in Docket No.
UE-240004,
the storm loss deferral mechanism approved the cumulative annual cost threshold for deferral of storms under the mechanism at $9.4 million in 2025 and $9.6 million in 2026 and the minimum expense exclusion, established in the 2017 GRC, remains in effect. Under the 2017 GRC Order in Docket No.
UE-170033,
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 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
 
F-32

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 Bellingham, Everett, Renton, Seattle, and Tacoma, Washington. As of December 31, 2025, the Company’s share of future remediation costs is estimated to be approximately $122.0 million.
 
 
(5)
Dividend Payment Restrictions
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 48.7% at December 31, 2025, and the EBITDA to interest expense was 5.2 to 1.0 for the twelve months ended December 31, 2025.
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 3.8 to 1.0 for the twelve months ended December 31, 2025.
At December 31, 2025, 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:
 

 
  
 
 
  
Puget Energy
 
  
Puget Sound Energy
 
Utility Plant
  
Estimated Useful
Life
1
 
  
December 31,
 
  
December 31,
 
(Dollars in Thousands)
  
(Years)
 
  
2025
 
  
2024
 
  
2025
 
  
2024
 
Distribution plant
    
7-65
     $ 9,589,563    $ 8,983,586    $ 11,062,733    $ 10,474,294
Production plant
    
12-90
       3,810,312      3,310,663      4,419,413      3,928,187
Transmission plant
    
44-75
       2,245,439      1,908,891      2,350,904      2,015,060
General plant
    
5-75
       902,919      805,960      922,152      826,918
Intangible plant (including capitalized software)
2
    
3-50
       686,587      716,038      677,122      706,576
Plant acquisition adjustment
     N/A        242,827      242,827      282,792      282,792
Underground storage
    
25-60
       52,695      50,047      65,553      63,004
Liquefied natural gas storage
    
25-50
       256,284      256,144      258,049      257,909
 
F-33

           
Puget Energy
   
Puget Sound Energy
 
Utility Plant
  
Estimated Useful
Life
1
    
December 31,
   
December 31,
 
(Dollars in Thousands)
  
(Years)
    
2025
   
2024
   
2025
   
2024
 
Plant held for future use
     N/A        29,438     59,657     29,591     59,809
Recoverable cushion gas
     N/A        8,784     8,784     8,784     8,784
Plant not classified
     N/A        1,355,183     733,184     1,355,183     733,184
Finance leases, net of accumulated amortization
3
     N/A        159,475     91,045     159,475     91,045
Less: accumulated provision for depreciation
        (5,555,794 )      (5,101,926 )      (7,808,039 )      (7,382,662 ) 
     
 
 
   
 
 
   
 
 
   
 
 
 
Subtotal
      $ 13,783,712   $ 12,064,900   $ 13,783,712   $ 12,064,900
Construction work in progress
        1,082,208     1,577,695     1,082,208     1,577,695
     
 
 
   
 
 
   
 
 
   
 
 
 
Net utility plant
      $ 14,865,920   $ 13,642,595   $ 14,865,920   $ 13,642,595
     
 
 
   
 
 
   
 
 
   
 
 
 
 
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, 2025, and 2024, accumulated amortization of finance leases at Puget Energy and PSE was $25.6 million and $18.3 million, respectively.
Jointly owned generating plant service costs are included in utility plant service cost at the Company’s ownership share. The Company provides financing for its ownership interest in the jointly owned utility plants. The following tables indicate the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, 2025. 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.
 
Puget Energy
 
             
Jointly Owned
Generating Plants
(Dollars in Thousands)
   Energy Source
(Fuel)
     Company’s
Ownership Share
    Plant in Service
at Cost
     Construction Work in
Progress
     Accumulated
Depreciation
 
Colstrip Units 3 and 4
1
     Coal        25.00 %    $ 324,187    $ —       $ (320,572 ) 
Frederickson 1
     Natural Gas        49.85       68,006      —       (38,390 ) 
Jackson Prairie
     Natural Gas        33.34       50,546      —       (15,792 ) 
Tacoma LNG
     Natural Gas        various       496,973      4,974      (49,793 ) 
 
1.
 
The transfer of PSE’s interest in Colstrip Units 3 and 4 to NorthWestern Energy was completed by January 1, 2026, and thus thereafter Colstrip no longer serves PSE customers.
 
Puget Sound Energy
 
             
Jointly Owned
Generating Plants
(Dollars in Thousands)
   Energy Source
(Fuel)
     Company’s
Ownership Share
    Plant in Service
at Cost
     Construction Work in
Progress
     Accumulated
Depreciation
 
Colstrip Units 3 and 4
1
     Coal        25.00 %    $ 574,980    $ —       $ (571,365 ) 
Frederickson 1
     Natural Gas        49.85       73,658      —       (44,042 ) 
Jackson Prairie
     Natural Gas        33.34       65,553      —       (30,799 ) 
Tacoma LNG
     Natural Gas        various       246,365      1,146      (24,278 ) 
 
1.
 
The transfer of PSE’s interest in Colstrip Units 3 and 4 to NorthWestern Energy was completed by January 1, 2026, and thus thereafter Colstrip no longer serves PSE customers.
 
F-34

PSE had a 50% ownership interest in Colstrip Units 1 and 2 and until January 1, 2026, a 25% interest in Colstrip Units 3 and 4, which are coal-fired generating units located in Colstrip, Montana. PSE accelerated the depreciation of Colstrip Units 3 and 4 to December 31, 2025 as part of the 2019 GRC. 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 January 1, 2026. Management evaluated the agreement with Northwestern Energy and determined that abandonment accounting criteria was met as of January 1, 2026. Thus, PSE applied abandonment accounting on the transfer date of January 1, 2026; Colstrip Units 3 and 4 were classified as Electric Utility Plant on the Company’s balance sheet as of December 31, 2025.
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 year ended December 31, 2025, the Company reviewed the estimated remediation costs related to the Beaver Creek Wind Project and determined that $21.1 million was warranted for the ARO liability. An $18.8 million ARO liability was warranted as of December 31, 2024.
For the twelve months ended December 31, 2025, the Company reviewed the estimated remediation costs at Colstrip and determined no change was warranted for the Colstrip ARO liability for Colstrip Units
1-4,
compared to $7.9 million for the 12 months ended December 31, 2024. For the twelve months ended December 31, 2025 and 2024, the Company recorded relief of ARO and environmental remediation liability of $16.0 million and $6.0 million, respectively.
In addition, the Company recorded Tacoma LNG facility ARO liability of $4.4 million and $4.2 million for PSE and $4.3 million and $4.1 million for Puget LNG held only at Puget Energy as of December 31, 2025 and December 31, 2024, respectively.
 
Puget Energy and
Puget Sound Energy
   Year Ended December 31,  
(Dollars in Thousands)    2025      2024  
ARO beginning balance
   $ 235,943    $ 207,034
New ARO recognized in the period
     626      18,811
Relief of liability
     (16,296 )       (6,049 ) 
Revisions in estimated cash flows
     2,411      9,471
Accretion expense
     7,145      6,676
  
 
 
    
 
 
 
ARO ending balance
   $ 229,829    $ 235,943
  
 
 
    
 
 
 
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, 2025:
 
  •  
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;
 
F-35

  •  
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 nameplate capacity of 248 MW that commenced commercial operations in August 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 and $45.6 million has been paid as of December 31, 2025. On December 1, 2023, PSE entered into a turbine supply agreement with GE Renewables North America, LLC to purchase 88 wind turbines and $283.5 million has been paid as of December 31, 2025. On January 26, 2024, PSE entered into a balance of plant agreement to complete the design and construction of the project, for which $157.4 million has been paid as of December 31, 2025. As of December 31, 2025, $576.8 million of assets were recorded to the “Utility plant—Electric plant” financial statement line item and $21.1 million of ARO was recorded to the “Other deferred credits” financial statement line item, 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 2027. 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, 2025 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, 2025, $93.5 million was recorded to construction work in progress in conjunction with the Appaloosa solar project.
Lower Snake River Phase II
On December 29, 2025, PSE entered into a turbine supply agreement with GE Renewables North America, LLC to purchase 38 wind turbine generators for a total of $182.7 million, of which $18.3 million has been paid as of December 31, 2025. The turbine generators are expected to be delivered in 2027.
 
F-36

(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, 2025 and 2024:
 
(Dollars in Thousands)           December 31,  
Series    Type    Due      2025      2024  
Puget Sound Energy:
 
7.020%
   Senior Secured Note      2027      $ 300,000    $ 300,000
7.000%
   Senior Secured Note      2029        100,000      100,000
3.900%
   Pollution Control Bond      2031        138,460      138,460
4.000%
   Pollution Control Bond      2031        23,400      23,400
5.330%
   Senior Secured Note      2034        400,000      400,000
5.483%
   Senior Secured Note      2035        250,000      250,000
6.724%
   Senior Secured Note      2036        250,000      250,000
6.274%
   Senior Secured Note      2037        300,000      300,000
5.757%
   Senior Secured Note      2039        350,000      350,000
5.795%
   Senior Secured Note      2040        325,000      325,000
5.764%
   Senior Secured Note      2040        250,000      250,000
4.434%
   Senior Secured Note      2041        250,000      250,000
5.638%
   Senior Secured Note      2041        300,000      300,000
4.300%
   Senior Secured Note      2045        425,000      425,000
4.223%
   Senior Secured Note      2048        600,000      600,000
3.250%
   Senior Secured Note      2049        450,000      450,000
2.893%
   Senior Secured Note      2051        450,000      450,000
4.700%
   Senior Secured Note      2051        45,000      45,000
5.448%
   Senior Secured Note      2053        400,000      400,000
5.685%
   Senior Secured Note      2054        400,000      400,000
5.598%
   Senior Secured Note      2055        500,000      — 
*
   Debt discount, issuance cost and other      *        (49,176 )       (45,835 ) 
        
 
 
    
 
 
 
Total PSE long-term debt
      $ 6,457,684    $ 5,961,025
        
 
 
    
 
 
 
Puget Energy:
 
*
   Fair value adjustment of PSE long-term debt      *      $ (122,820 )     $ (131,326 ) 
2.379%
   Senior Secured Note      2028        500,000      500,000
4.100%
   Senior Secured Note      2030        650,000      650,000
4.224%
   Senior Secured Note      2032        450,000      450,000
5.725%
   Senior Secured Note      2035        600,000      — 
*
   Debt discount, issuance cost and other      *        (9,832 )       (5,780 ) 
        
 
 
    
 
 
 
Total Puget Energy long-term debt
      $ 8,525,032    $ 7,423,919
        
 
 
    
 
 
 
 
*
Not Applicable
.
On November 13, 2025, PSE entered into (a) an Indenture of Mortgage—Electric (Electric Mortgage Indenture), dated as of November 13, 2025, with U.S. Bank Trust Company, National Association, as trustee, and (b) an Indenture of Mortgage—Gas (Gas Mortgage Indenture and, together with the Electric Mortgage Indenture, the New Mortgage Indentures), dated as of November 13, 2025, with U.S. Bank Trust Company, National Association, as trustee, which, upon the Lien Effective Date (as defined below), established first mortgage liens on substantially all of PSE’s present electric utility property and gas utility property, respectively, and certain after-acquired electric utility property and gas utility property, respectively, subject to certain exceptions. The Electric Mortgage Indenture replaces PSE’s First Mortgage, dated as of June 2, 1924, with U.S. Bank National Association (as successor to State Street Bank and Trust Company), as amended and supplemented from time to
 
F-37

time. The Gas Mortgage Indenture replaces PSE’s Indenture of First Mortgage, dated as of April 1, 1957, with The Bank of New York Mellon, N.A. (as successor trustee to Harris Trust and Savings Bank), as amended and supplemented from time to time.
On December 16, 2025 (Lien Effective Date and Substitution Date), PSE (a) entered into first supplemental indentures to the New Mortgage Indentures, pursuant to which the respective liens of the New Mortgage Indentures became effective, (b) entered into the sixth supplemental indenture (Sixth Supplemental Indenture) to that certain Indenture dated as of December 1, 1997, as modified and supplemented from time to time (Senior Note Indenture) between PSE and U.S. Bank Trust Company, National Association, as trustee (Senior Note Trustee), and (c) delivered to the Senior Note Trustee pledged substituted mortgage bonds issued under the New Mortgage Indentures in the same principal amount, and with identical terms to the senior notes then-outstanding under the Senior Note Indenture. The Sixth Supplemental Indenture amends the Senior Note Indenture to make it mandatory for PSE to deliver to the Senior Note Trustee upon the issuance of senior notes thereunder, pledged substituted mortgage bonds, which shall be issued under the New Mortgage Indentures, in the same principal amount, and with identical terms to the senior notes, including interest rate, interest payment dates and stated maturity date and redemption provisions. 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 pledged substituted mortgage bonds.
Puget Energy Long-Term Debt
On March 13, 2025, Puget Energy issued $600.0 million of senior secured notes at an interest rate of 5.725% (Initial 5.725% Notes) in a private offering exempt from registration under the Securities Act. The notes mature on March 15, 2035 and pay interest semi-annually in arrears on March 15 and September 15 of each year, commencing September 15, 2025. Proceeds from the issuance of the Initial 5.725% Notes were used to repay Puget Energy’s $400.0 million 3.650% senior secured notes that matured on May 15, 2025, to pay down a portion of the outstanding balance on the Puget Energy senior secured credit facility and for general corporate purposes.
On May 7, 2025, Puget Energy filed a Form
S-4
Registration Statement, which was declared effective by the SEC on May 30, 2025. On June 2, 2025, Puget Energy launched an exchange offer for holders of the Initial 5.725% Notes to receive registered notes (Registered 5.725% Notes) with substantially identical terms as those of the Initial 5.725% Notes. The exchange offer expired on July 1, 2025, and all Initial 5.725% Notes were exchanged and settled on July 8, 2025 and July 22, 2025 for the Registered 5.725% Notes.
Puget Sound Energy Long-Term Debt
On September 15, 2025, PSE issued $500.0 million of senior secured notes at an interest rate of 5.598%. The notes mature on September 15, 2055 and pay interest semi-annually in arrears on March 15 and September 15 of each year, commencing March 15, 2026. Proceeds from the issuance of the notes were used to fund capital expenditures and for general corporate purposes.
On July 30, 2025, PSE filed an automatic shelf registration statement on Form
S-3
as a “well-known seasoned issuer” as defined in Rule 405 under the Securities Act of 1933, as amended. Under this shelf registration process, an indeterminate aggregate offering price or number of securities may be registered from time to time. The shelf registration statement will expire in July 2028.
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 $400.0 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
 
F-38

each year, commencing on December 15, 2024. Net proceeds from the issuance of the notes were invested in short-term money market funds and were allocated 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:
 
(Dollars in Thousands)    2026      2027      2028      2029      2030      Thereafter      Total  
Maturities of:
                    
PSE
   $ —       $ 300,000    $ —       $ 100,000    $ —       $ 6,106,860    $ 6,506,860
Puget Energy
     —       —       500,000      —       650,000      1,050,000      2,200,000
  
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
 
Total long-term debt
   $ —       $ 300,000    $ 500,000    $ 100,000    $ 650,000    $ 7,156,860    $ 8,706,860
  
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
 
(8) Liquidity Facilities and Other Financing Arrangements
As of December 31, 2025 and 2024, PSE had $60.0 million and $40.0 million in short-term debt outstanding, respectively. Outside of the consolidation of PSE’s short-term debt, Puget Energy had $427.5 million and $338.4 million, in short-term debt, drawn and outstanding under its credit facility as of December 31, 2025 and 2024, respectively. PSE’s weighted-average interest rate on short-term debt, including borrowing rate, commitment fees and the amortization of debt issuance costs, during 2025 and 2024 was 35.3% and 8.5%, respectively. The rate in 2025 was inflated by an increase in commitment fees and less commercial paper issued during the year. As of December 31, 2025, PSE and Puget Energy had several committed credit facilities that are described below.
Puget Sound Energy
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, 2025, 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
 
F-39

of February 19, 2026, 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, 2025, no amount was drawn under PSE’s credit facility and $60.0 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 $210.0 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, 2025, $53.1 million was issued under a standby letter of credit with TD Bank in support of natural gas and carbon allowance purchases. On February 13, 2026, TD Bank increased the standby letter of credit, allowing postings of up to $300.0 million. Additionally, PSE posted cash collateral of $78.0 million to ICE for purchased power trading. In support of purchased power contracts, PSE posted cash collateral of $12.0 million and maintained three standby letters of credit in the amounts of $58.5 million, $13.5 million, and $11.9 million. In support of a funding participant contract, PSE has a $13.4 million standby letter of credit. PSE also maintains a $1.7 million letter of credit in support of a long-term transmission contract.
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, 2025, there was no outstanding balance under the promissory note.
Puget Energy
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 February 19, 2026, 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, 2025, Puget Energy was in compliance with all applicable covenants.
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.
In April 2025, Puget Energy borrowed $139.0 million on its credit facility and contributed the proceeds to PSE as an equity contribution. The equity proceeds were used for general corporate purposes.
 
F-40

In August 2025, Puget Energy borrowed $125.0 million on its credit facility and contributed the proceeds to PSE as an equity
contribution
. The equity proceeds were used for general corporate purposes.
(9) Leases
PSE has operating leases for buildings, real estate for operating facilities, including the Puget LNG facility, land, and vehicles. Finance leases primarily represent buildings and equipment. PSE also has certain power purchase agreements that qualify as leases. The leases have remaining lease terms of less than a year to 44 years. PSE’s ROU assets and lease liabilities include options to extend leases when it is reasonably certain that PSE will exercise that option.
On December 4, 2025, PSE entered into an extension agreement for its lease of its corporate headquarters located in Bellevue, Washington. The agreement extended the lease term through August 31, 2039. The extension remeasurement resulted in an increase of the operating lease ROU asset and operating lease liabilities of $70.3 million.
On October 1, 2025, PSE commenced a tolling agreement to purchase the energy and capacity associated with a 132.5 MW natural gas combined cycle facility. The tolling agreement represents an operating lease to PSE and as of December 31, 2025, PSE recorded $77.8 million in ROU assets and $77.9 million in lease liabilities, included in the Company’s consolidated balance sheets. The ROU asset is included in the operating lease ROU assets line item and liabilities are included in the operating lease liabilities line items under the current liabilities and other long-term and regulatory liabilities sections. Lease costs associated with the tolling agreement are included within purchased electricity on the Company’s consolidated statements of income.
On September 1, 2025, PSE commenced a lease agreement for an operations training facility located in Puyallup, Washington. The lease agreement represents a finance lease to PSE and as of December 31, 2025, PSE recorded $73.5 million in assets and $75.9 million in liabilities, included in the Company’s consolidated balance sheets.
On January 1, 2025, PSE commenced a tolling agreement to purchase the energy and capacity associated with a 650.0 MW natural gas combined cycle facility. The tolling agreement represents an operating lease to PSE and as of December 31, 2025, PSE recorded $139.1 million in ROU assets and $139.1 million in lease liabilities, included in the Company’s consolidated balance sheets. The ROU asset is included in the operating lease ROU assets line item and liabilities are included in the operating lease liabilities line items under the current liabilities and other long-term and regulatory liabilities sections. Costs associated with the tolling agreement, include both fixed and variable components, and are included within purchased electricity on the Company’s consolidated statements of income.
The components of lease cost were as follows:
Puget Energy and
Puget Sound Energy
 
     Year Ended December 31,  
(Dollars in Thousands)    2025             2024  
Finance lease cost:
        
Amortization of
right-of-use
asset
   $ 4,583       $ 3,915
Interest on lease liabilities
     4,217         3,192
  
 
 
       
 
 
 
Total finance lease cost
1
   $ 8,800       $ 7,107
  
 
 
       
 
 
 
Operating lease cost:
        
Purchased power leases:
        
 
F-41

     Year Ended December 31,  
(Dollars in Thousands)    2025             2024  
Operating lease cost
   $ 77,294       $ —   
Variable lease cost
     87,450         — 
  
 
 
       
 
 
 
Total purchased power lease cost
   $ 164,744       $ —   
Other operating lease cost
2
     26,357         24,993
  
 
 
       
 
 
 
Total operating lease cost
3
   $ 191,101    $ 191,102      $ 24,993
  
 
 
       
 
 
 
 
1.
 
Includes $1.3 million and $2.0 million recorded to CWIP via construction support overhead related to finance leases for the years ended December 31, 2025 and December 31, 2024, respectively.
2.
 
Includes $1.8 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, 2025 and December 31, 2024, respectively.
3.
 
Includes $9.5 million and $8.8 million recorded to CWIP via construction support overhead related to operating leases for the years ended December 31, 2025 and December 31, 2024, respectively.
Supplemental cash flow information related to leases was as follows:
Puget Energy and
Puget Sound Energy
 
     Year Ended December 31,  
(Dollars in Thousands)    2025      2024  
Cash paid for amounts included in the measurement of lease liabilities:
     
Operating cash flow for operating leases
1
   $ 181,573    $ 17,038
Investing cash flow for operating leases
     10,855      7,955
Operating cash flow for finance leases
     4,217      3,192
Financing cash flow for finance leases
     3,256      3,915
Non-cash
disclosure upon commencement of new lease
     
Right-of-use
assets obtained in exchange for new operating lease liabilities
   $ 300,002    $ 4,093
Right-of-use
assets obtained in exchange for new finance lease liabilities
     75,145      1,832
Non-cash
disclosure upon modification of existing lease
     
Modification of operating lease
right-of-use
assets
   $ 70,502    $ 1,996
 
1
 
Includes $1.8 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, 2025 and December 31, 2024, respectively.
Supplemental balance sheet information related to leases was as follows:
Puget Energy and
Puget Sound Energy
 
     At December 31,  
(Dollars in Thousands)    2025      2024  
Operating Leases
     
Operating lease
right-of-use
assets - other
   $ 244,055      $ 181,397  
Operating lease
right-of-use
assets - purchased power
     216,935      $ —   
  
 
 
    
 
 
 
Total operating lease
right-of-use
assets
   $ 460,990      $ 181,397  
  
 
 
    
 
 
 
Operating lease liabilities - other, current
   $ 21,830      $ 22,761  
Operating lease liabilities - purchased power, current
     82,410        —   
 
F-42

     At December 31,  
(Dollars in Thousands)    2025     2024  
Operating lease liabilities - other, long-term
     230,686       166,700  
Operating lease liabilities - purchased power, long-term
     134,673       —   
  
 
 
   
 
 
 
Total operating lease liabilities:
   $ 469,599     $ 189,461  
  
 
 
   
 
 
 
Finance Leases
    
Common plant
   $ 124,343     $ 53,594  
Natural gas plant
     209       310  
Electric plant
     34,924       37,141  
  
 
 
   
 
 
 
Total finance lease assets
   $ 159,476     $ 91,045  
  
 
 
   
 
 
 
Other current liabilities
   $ 5,586     $ 3,786  
Finance lease liabilities
     167,426       96,850  
  
 
 
   
 
 
 
Total finance lease liabilities
   $ 173,012     $ 100,636  
  
 
 
   
 
 
 
Weighted Average Remaining Lease Term
    
Operating leases
     12.1 Years       21.2 Years  
Finance leases
     17.7 Years       16.9 Years  
Weighted Average Discount Rate
    
Operating leases
     4.52 %      3.76 % 
Finance leases
     4.47 %      3.10 % 
The following table summarizes the Company’s estimated future minimum lease payments for commenced leases as of December 31,
2025
:
Puget Energy and
Puget Sound Energy
 
(Dollars in Thousands)    Future Minimum Lease Payments  
At December 31,    Operating Leases      Finance Leases  
2026
   $ 117,569    $ 12,683
2027
     117,713      12,637
2028
     42,320      12,833
2029
     36,941      12,805
2030
     38,006      13,036
Thereafter
     248,209      192,781
  
 
 
    
 
 
 
Total lease payments
   $ 600,758    $ 256,775
  
 
 
    
 
 
 
Less imputed interest
     (131,159 )       (83,763 ) 
  
 
 
    
 
 
 
Total net present value
   $ 469,599    $ 173,012
  
 
 
    
 
 
 
Leases Not Yet Commenced
On August 22, 2025, PSE entered into an energy storage system tolling agreement that will be accounted for as a lease upon commencement. The lease is expected to commence in December 2028 and has a term of 20 years. The expected total lease payment consideration will approximate $429.0 million over the lease term.
On January 7, 2025, PSE entered into two battery energy storage services agreements that will be accounted for as leases upon commencement. These leases are expected to commence in May 2027 and each will have a term of 20 years. The expected total lease payment consideration will approximate $45.2 million over the lease terms.
 
F-43

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 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.
(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. Due to regulatory accounting treatment, changes in fair value have no impact on earnings. The Company does not apply cash flow hedge accounting.
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:
Puget Energy and
Puget Sound Energy
 
     Year Ended December 31,  
(Dollars in Thousands)    Volumes (millions)      Assets
1
     Liabilities
²
 
     2025      2024      2025      2024      2025      2024  
Electric portfolio derivatives
3
     *        *      $ 41,974    $ 35,341    $ 493,334    $ 319,506
Natural gas derivatives (MMBtus)
3
     289        269      6,735      3,495      80,087      70,425
  
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
 
Total derivative contracts
         $ 48,709    $ 38,836    $ 573,421    $ 389,931
        
 
 
    
 
 
    
 
 
    
 
 
 
Current
         $ 37,448    $ 32,591    $ 359,890    $ 218,443
Long-term
           11,261      6,245      213,531      171,488
        
 
 
    
 
 
    
 
 
    
 
 
 
Total derivative contracts
         $ 48,709    $ 38,836    $ 573,421    $ 389,931
        
 
 
    
 
 
    
 
 
    
 
 
 
 
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”. 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.
*
Electric portfolio derivatives consist of electric generation fuel of 252.9 million One Million British Thermal Units (“MMBtus”) and purchased electricity of 33.8 million megawatt hours (“MWhs”) at December 31, 2025, and 283.5 million MMBtus and 13.3 million MWhs at December 31, 2024.
 
F-44

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,” below.
The following tables present the potential effect of netting arrangements, including rights of
set-off
associated with the Company’s derivative assets and liabilities:
Puget Energy and
Puget Sound Energy
 
December 31, 2025
 
(Dollars in
Thousands)
   Gross Amount
Recognized in the
Consolidated
Balance Sheet
1
     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
Contracts
    Cash Collateral
Received/Pledged
    Net
Amount
 
Assets:
               
Energy derivative contracts
   $ 48,709    $ —       $ 48,709    $ (44,271 )    $ —      $ 4,438
Liabilities:
               
Energy derivative contracts
   $ 573,421    $ —       $ 573,421    $ (44,271 )    $ (54,521 )    $ 474,628
Puget Energy and
Puget Sound Energy
 
December 31, 2024
 
(Dollars in
Thousands)
   Gross Amount
Recognized
1
     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
Contracts
    Cash Collateral
Received/Pledged
    Net
Amount
 
Assets
               
Energy derivative contracts
   $ 38,836    $ —       $ 38,836    $ (34,329 )    $ —      $ 4,507
Liabilities
               
Energy derivative contracts
   $ 389,931    $ —       $ 389,931    $ (34,329 )    $ (3,593 )    $ 352,009
 
1.
 
All derivative contract deals are executed under ISDA, NAESB, and WSPP master agreements with right of
set-off.
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. Prior to the accounting petition, the Company recognized an unrealized gain of $33.9 million and unrealized loss of $284.5 million related to its derivatives for the year ended December 31, 2024 and 2023, respectively in the ‘Unrealized gain (loss) on derivative instruments, net’ line item on its Consolidated Statements of Income. For further information see Part II, Item 8, Note 10 “Accounting for Derivative Instruments and Hedging Activities” in the Company’s Annual Report on Form
10-K
for the year ended December 31, 2024.
 
F-45

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, 2025, approximately 99.2% 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 0.8% 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, 2025, 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, 2025, PSE had cash posted as collateral of $78.0 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, 2025, PSE had $53.1 million 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, 2025.
 
F-46

The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post:
Puget Energy and
Puget Sound Energy
 
     December 31,  
(Dollars in Thousands)    2025      2024  
Contingent Feature    Fair Value
1

Liability
     Posted
Collateral
     Contingent
Collateral
     Fair Value
1

Liability
     Posted
Collateral
     Contingent
Collateral
 
Credit rating
2
   $ 253,105    $ —       $ 253,105    $ 179,532    $ —       $ 179,532
Requested credit for adequate assurance
     21,927      —       —       37,492      —       — 
Forward value of contract
3
     54,521      77,969      N/A        19,905      12,915      N/A  
  
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
 
Total
   $ 329,553    $ 77,969    $ 253,105    $ 236,929    $ 12,915    $ 179,532
  
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
 
 
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. Inputs used to estimate fair value in
 
F-47

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. Investments in life insurance contracts of $44.8 million both at December 31, 2025 and 2024, 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:
Puget Energy
 
            December 31, 2025      December 31, 2024  
(Dollars in Thousands)    Level      Carrying Value      Fair Value      Carrying Value      Fair Value  
Financial liabilities:
              
Long-term debt (fixed-rate), net of discount
1
     2      $ 8,525,032    $ 8,199,785    $ 7,423,919    $ 6,966,211
Puget Sound Energy
 
            December 31, 2025      December 31, 2024  
(Dollars in Thousands)    Level      Carrying Value      Fair Value      Carrying Value      Fair Value  
Financial liabilities:
              
Long-term debt (fixed-rate), net of discount
2
     2      $ 6,457,684    $ 6,054,647    $ 5,961,025    $ 5,492,999
 
1.
 
The carrying value includes debt issuances costs of $23.2 million and $21.3 million for December 31, 2025, and 2024, respectively, which are not included in fair value.
2.
 
The carrying value includes debt issuances costs of $22.2 million and $22.1 million for December 31, 2025, and 2024, respectively, which are not included in fair value.
 
F-48

Assets and Liabilities Measured at Fair Value on a Recurring Basis
The following tables present the Company’s financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis and the reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy:
Puget Energy and
Puget Sound Energy
 
     Fair Value      Fair Value  
     December 31, 2025      December 31, 2024  
(Dollars in Thousands)    Level 2      Level 3      Total      Level 2      Level 3      Total  
Assets:
 
Electric derivative instruments
   $ 38,930    $ 3,044    $ 41,974    $ 25,236    $ 10,105    $ 35,341
Gas derivative instruments
     2,262      4,473      6,735      1,729      1,766      3,495
  
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
 
Total derivative assets
   $ 41,192    $ 7,517    $ 48,709    $ 26,965    $ 11,871    $ 38,836
  
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
 
Liabilities:
 
Electric derivative instruments
   $ 281,007    $ 212,327    $ 493,334    $ 134,292    $ 185,214    $ 319,506
Gas derivative instruments
     78,945      1,142      80,087      70,050      375      70,425
Compliance obligation
     96,490      —       96,490      73,049      —       73,049
  
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
 
Total derivative liabilities
   $ 456,442    $ 213,469    $ 669,911    $ 277,391    $ 185,589    $ 462,980
  
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
 
Puget Energy and
Puget Sound Energy
 
    Year Ended December 31,  
Level 3 Roll-Forward Net
Asset (Liability)
  2025     2024     2023  
(Dollars in Thousands)   Electric     Natural
Gas
    Total     Electric     Natural
Gas
    Total     Electric     Natural
Gas
    Total  
Balance at beginning of period
  $ (175,110 )    $ 1,391   $ (173,719 )    $ 27,262   $ 3,851   $ 31,113   $ 116,078   $ (127 )    $ 115,951
Changes during period:
                 
Realized and unrealized energy derivatives
                 
Included in earnings
1
    —         —         —         (27,262 )      —         (27,262 )      (56,656 )      —         (56,656 ) 
Included in regulatory assets / liabilities
    (88,308 )      4,517     (83,791 )      (211,129 )      1,284     (209,845 )      —         4,906     4,906
Settlements
2
    54,135     (2,578 )      51,557     34,873     (4,418 )      30,455     (32,377 )      (1,098 )      (33,475 ) 
Transferred into Level 3
    —         —         —         —         —         —         —         —         —    
Transferred out Level 3
    —         —         —         1,146     674     1,820     217     170     387
 
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
Balance at end of period
  $ (209,283 )    $ 3,330   $ (205,953 )    $ (175,110 )    $ 1,391   $ (173,719 )    $ 27,262   $ 3,851   $ 31,113
 
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
 
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 for the year ended December 31, 2023.
2.
 
The Company had no purchases or sales of options during the reported periods.
 
F-49

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, 2025, 2024, and 2023. 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, 2025:
Puget Energy and
Puget Sound Energy
     Fair Value    Range  
(Dollars in
Thousands)
   Assets1      Liabilities
1
     Valuation
Technique
  
Unobservable Input
   Low      High      Weighted  
Electricity
   $ 3,044    $ 212,327    Discounted cash
flow
   Power Prices (per MWh)    $ 18.40    $ 126.87    $ 57.64
Natural Gas
   $ 4,473    $ 1,142    Discounted cash
flow
   Natural Gas Prices (per MMBtu)    $ 1.53    $ 4.46    $ 2.30
 
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, 2025, 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 $48.1 million.
(12) Retirement Benefits
PSE has a defined benefit pension plan (Qualified Pension Benefits) covering a substantial majority of PSE employees. For em
plo
yees 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
 
F-50

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, 2025, and 2024:
 
Puget Energy and
Puget Sound Energy
   Qualified
Pension Benefits
    SERP
Pension Benefits
    Other
Benefits
 
(Dollars in Thousands)    2025     2024     2025     2024     2025     2024  
Change in benefit obligation:
            
Benefit obligation at beginning of period
   $ 576,986   $ 609,103   $ 24,464   $ 26,824   $ 8,248   $ 8,597
Amendments
     —         —         —         —         —         34
Service cost
     17,521     18,616     —         —         202     197
Interest cost
     32,265     31,152     1,226     1,370     411     406
Actuarial loss (gain)
     9,669     (38,952 )      207     (1,752 )      (208 )      (194 ) 
Benefits paid
     (44,745 )      (41,583 )      (4,448 )      (1,978 )      (700 )      (792 ) 
Administrative expense
     (1,330 )      (1,350 )      —         —         —         —    
  
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
Benefit obligation at end of period
1
   $ 590,366   $ 576,986   $ 21,449   $ 24,464   $ 7,953   $ 8,248
  
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
 
1.
 
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.
 
Puget Energy and
Puget Sound Energy
   Qualified
Pension Benefits
    SERP
Pension Benefits
    Other
Benefits
 
(Dollars in Thousands)    2025     2024     2025     2024     2025     2024  
Change in plan assets:
            
Fair value of plan assets at beginning of period
   $ 772,690   $ 746,011   $ —       $ —       $ 4,785   $ 5,085
Actual return on plan assets
     112,032     51,509     —         —         531     313
Employer contribution
     18,000     18,000     4,448     1,978     154     179
Benefits paid
     (44,745 )      (41,583 )      (4,448 )      (1,978 )      (700 )      (792 ) 
Administrative expense
     (1,170 )      (1,247 )      —         —         —         —    
  
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
Fair value of plan assets at end of period
   $ 856,807   $ 772,690   $ —       $ —       $ 4,770   $ 4,785
  
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
Funded status at end of period
   $ 266,441   $ 195,704   $ (21,449 )    $ (24,464 )    $ (3,183 )    $ (3,463 ) 
  
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
 
F-51

Puget Energy and
Puget Sound Energy
   Qualified
Pension Benefits
     SERP
Pension Benefits
    Other
Benefits
 
(Dollars in Thousands)    2025      2024      2025     2024     2025     2024  
Amounts recognized in Consolidated Balance Sheet consist of:
              
Noncurrent assets
   $ 266,441    $ 195,704    $ —       $ —       $ —       $ —    
Current liabilities
     —          —          (3,394 )      (6,759 )      (242 )      (237 ) 
Noncurrent liabilities
     —          —          (18,055 )      (17,705 )      (2,941 )      (3,226 ) 
  
 
 
    
 
 
    
 
 
   
 
 
   
 
 
   
 
 
 
Net assets (liabilities)
   $ 266,441    $ 195,704    $ (21,449 )    $ (24,464 )    $ (3,183 )    $ (3,463 ) 
  
 
 
    
 
 
    
 
 
   
 
 
   
 
 
   
 
 
 
 
Puget Energy and
Puget Sound Energy
   Qualified
Pension Benefits
     SERP
Pension Benefits
     Other
Benefits
 
(Dollars in Thousands)    2025      2024      2025      2024      2025      2024  
Change in plan obligation and plan asset:
                 
Projected benefit obligation
   $ 590,366    $ 576,986    $ 21,449    $ 24,464    $ 7,953    $ 8,248
Accumulated benefit obligation
     584,423      571,306      21,449      24,464      7,790      8,109
Fair value of plan assets
     856,807      772,690      —          —          4,770      4,785
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, 2025, and 2024:
 
Puget Energy
   Qualified
Pension Benefits
    SERP
Pension Benefits
    Other
Benefits
 
(Dollars in Thousands)    2025     2024     2025     2024     2025     2024  
Amounts recognized in Accumulated Other Comprehensive Income consist of:
            
Net loss (gain)
   $ (90,960 )    $ (49,242 )    $ (2,921 )    $ (3,579 )    $ (2,383 )    $ (2,132 ) 
Prior service cost (credit)
     —         —         —         —         276     311
  
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
Total
   $ (90,960 )    $ (49,242 )    $ (2,921 )    $ (3,579 )    $ (2,107 )    $ (1,821 ) 
  
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
 
Puget Sound Energy
   Qualified
Pension Benefits
     SERP
Pension Benefits
    Other
Benefits
 
(Dollars in Thousands)    2025     2024      2025     2024     2025     2024  
Amounts recognized in Accumulated Other Comprehensive Income consist of:
             
Net loss (gain)
   $ (7,182 )    $ 39,183    $ (2,722 )    $ (3,342 )    $ (2,451 )    $ (2,204 ) 
Prior service cost (credit)
     —         —          —         —         276     311
  
 
 
   
 
 
    
 
 
   
 
 
   
 
 
   
 
 
 
Total
   $ (7,182 )    $ 39,183    $ (2,722 )    $ (3,342 )    $ (2,175 )    $ (1,893 ) 
  
 
 
   
 
 
    
 
 
   
 
 
   
 
 
   
 
 
 
The following tables summarize Puget Energy’s and PSE’s net periodic benefit cost for the years ended December 31, 2025, 2024, and 2023.
 
Puget Energy
   Qualified
Pension Benefits
    SERP
Pension Benefits
     Other
Benefits
 
(Dollars in Thousands)    2025     2024     2023     2025      2024      2023      2025     2024     2023  
Components of net periodic benefit cost:
                     
Service cost
   $ 17,521   $ 18,616   $ 18,530   $ —        $ —        $ 143    $ 202   $ 197   $ 184
Interest cost
     32,265     31,152     32,375     1,226      1,370      1,589      411     406     439
Expected return on plan assets
     (56,159 )      (54,896 )      (50,641 )      —          —          —          (275 )      (288 )      (297 ) 
 
F-52

Puget Energy
   Qualified
Pension Benefits
    SERP
Pension Benefits
     Other
Benefits
 
(Dollars in Thousands)    2025     2024     2023     2025     2024     2023      2025     2024     2023  
Amortization of prior service cost (credit)
     —         —         —         —         —         144      35     33     28
Amortization of net loss (gain)
     (4,646 )      (2,684 )      (2,447 )      (199 )      (42 )      —          (213 )      (139 )      (210 ) 
  
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
    
 
 
   
 
 
   
 
 
 
Net periodic benefit cost
   $ (11,019 )    $ (7,812 )    $ (2,183 )    $ 1,027   $ 1,328   $ 1,876    $ 160   $ 209   $ 144
  
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
    
 
 
   
 
 
   
 
 
 
 
Puget Sound Energy
   Qualified
Pension Benefits
    SERP
Pension Benefits
     Other
Benefits
 
(Dollars in Thousands)    2025     2024     2023     2025     2024     2023      2025     2024     2023  
Components of net periodic benefit cost:
                   
Service cost
   $ 17,521   $ 18,616   $ 18,530   $ —       $ —       $ 143    $ 202   $ 197   $ 184
Interest cost
     32,265     31,152     32,375     1,226     1,370     1,589      411     406     439
Expected return on plan assets
     (56,159 )      (54,897 )      (50,641 )      —         —         —          (275 )      (288 )      (297 ) 
Amortization of prior service cost (credit)
     —         —         —         —         —         144      35     33     28
Amortization of net loss (gain)
     —         —         —         (179 )      (22 )      44      (217 )      (139 )      (230 ) 
  
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
    
 
 
   
 
 
   
 
 
 
Net periodic benefit cost
   $ (6,373 )    $ (5,129 )    $ 264   $ 1,047   $ 1,348   $ 1,920    $ 156   $ 209   $ 124
  
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
    
 
 
   
 
 
   
 
 
 
The following tables summarize Puget Energy’s and PSE’s benefit obligations recognized in other comprehensive income (OCI) for the years ended December 31, 2025, and 2024:
 
Puget Energy
   Qualified
Pension Benefits
    SERP
Pension Benefits
    Other
Benefits
 
(Dollars in Thousands)    2025     2024     2025      2024     2025     2024  
Other changes
(pre-tax)
in plan assets and benefit obligations recognized in other comprehensive income:
             
Net loss (gain)
   $ (46,365 )    $ (44,439 )    $ 207    $ (1,751 )    $ (464 )    $ (219 ) 
Amortization of net (loss) gain
     4,646     2,684     199      42     213     139
Settlements, mergers, sales, and closures
     —         —         252      —         —         —    
Prior service cost (credit)
     —         —         —          —         —         34
Amortization of prior service (cost) credit
     —         —         —          —         (35 )      (33 ) 
  
 
 
   
 
 
   
 
 
    
 
 
   
 
 
   
 
 
 
Total change in other comprehensive income for year
   $ (41,719 )    $ (41,755 )    $ 658    $ (1,709 )    $ (286 )    $ (79 ) 
  
 
 
   
 
 
   
 
 
    
 
 
   
 
 
   
 
 
 
 
Puget Sound Energy
   Qualified
Pension Benefit
    SERP
Pension Benefits
    Other
Benefits
 
(Dollars in Thousands)    2025     2024     2025      2024     2025     2024  
Other changes
(pre-tax)
in plan assets and benefit obligations recognized in other comprehensive income:
             
Net loss (gain)
   $ (46,364 )    $ (44,438 )    $ 207    $ (1,751 )    $ (464 )    $ (219 ) 
 
F-53

Puget Sound Energy
   Qualified
Pension Benefit
    SERP
Pension Benefits
    Other
Benefits
 
(Dollars in Thousands)    2025     2024     2025      2024     2025     2024  
Amortization of net (loss) gain
     —         —         179      22     217     139
Settlements, mergers, sales, and closures
     —         —         235      —         —         —    
Prior service cost (credit)
     —         —         —          —         —         34
Amortization of prior service (cost) credit
     —         —         —          —         (35 )      (33 ) 
  
 
 
   
 
 
   
 
 
    
 
 
   
 
 
   
 
 
 
Total change in other comprehensive income for year
   $ (46,364 )    $ (44,438 )    $ 621    $ (1,729 )    $ (282 )    $ (79 ) 
  
 
 
   
 
 
   
 
 
    
 
 
   
 
 
   
 
 
 
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, 2026, are expected to be at least $18.0 million, $3.4 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:
 
     Qualified
Pension Benefits
    SERP
Pension Benefits
    Other
Benefits
 
Benefit Obligation Assumptions:    2025     2024     2023     2025     2024     2023     2025     2024     2023  
Discount rate
     5.65 %      5.80 %      5.30 %      5.65 %      5.80 %      5.30 %      5.65 %      5.80 %      5.30 % 
Rate of compensation increase
     4.50     4.50     4.50     N/A       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
     5.80     5.30     5.60     5.80     5.30     5.60     5.80     5.30     5.60
Return on plan assets
     7.00     7.00     6.75     N/A       N/A       N/A       7.00     7.00     7.00
Rate of compensation increase
     4.50     4.50     4.50     N/A       N/A       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
 
F-54

for pension plans experienced an actuarial loss of $9.7 million in 2025. 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:
 
(Dollars in Thousands)    2026      2027      2028      2029      2030      2031-2035  
Qualified Pension total benefits
   $ 45,300    $ 45,800    $ 46,200    $ 47,200    $ 48,000    $ 245,200
SERP Pension total benefits
     3,394      5,321      2,023      1,586      2,017      6,499
Other Benefits total
     837      826      821      822      792      3,260
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
     22 %      28 %      35 % 
Domestic small/medium cap equity
     —        8     12
Non-U.S.
equity
     10     24     30
Fixed income
     30     40     50
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.
 
F-55

The following table sets forth by level, within the fair value hierarchy, the qualified pension plan as of December 31, 2025 and 2024:
 
    Recurring Fair Value Measures     Recurring Fair Value Measures  
    December 31, 2025     December 31, 2024  
(Dollars in Thousands)   Level 1     Level 2     Other     Total     Level 1     Level 2     Other     Total  
Assets:
               
Common Stock:
               
Domestic
  $ 124,005   $ —       $ —       $ 124,005   $ 117,183   $ 199   $ —       $ 117,382
Foreign
    18,374     —         —         18,374     14,050     —         —         14,050
Government Securities
    117,302     31,928     —         149,230     100,126     13,172     —         113,298
Corporate Securities:
               
Domestic
    —         19,618     —         19,618     —         17,807     —         17,807
Foreign
    —         17,574     —         17,574     —         15,004     —         15,004
Mutual Funds
    79,649     —         —         79,649     75,186     —         —         75,186
Cash and cash equivalents
    6,148     (4,554 )      —         1,594     5,263     (6,323 )      —         (1,060 ) 
Investments measured at NAV:
               
Collective Investment Funds
    —         —         353,714     353,714     —         —         321,937     321,937
Partnership
    —         —         109,157     109,157     —         —         90,308     90,308
Mutual Funds
    —         —         64,401     64,401     —         —         57,187     57,187
Other
    —         —         2,283     2,283     —         —         2,045     2,045
Net (payable) receivable
    —         —         (82,792 )      (82,792 )      —         —         (50,454 )      (50,454 ) 
 
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
Total assets
  $ 345,478   $ 64,566   $ 446,763   $ 856,807   $ 311,808   $ 39,859   $ 421,023   $ 772,690
 
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
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  
     December 31, 2025      December 31, 2024  
(Dollars in Thousands)    Level 1      Level 2      Other      Total      Level 1      Level 2      Other      Total  
Assets:
                       
Mutual fund
   $ —       $ 4,770    $ —       $ 4,770    $ —       $ 4,785    $ —       $ 4,785
Total assets
   $ —       $ 4,770    $ —       $ 4,770    $ —       $ 4,785    $ —       $ 4,785
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.
 
F-56

  •  
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.
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 $33.3 million, $31.7 million and $28.9 million for the years 2025, 2024, and 2023, 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. Company matching will be immediately vested.
 
  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.
 
F-57

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

Puget Energy
  
Year
Ende
d December 31,
 
(Dollars in Thousands)
  
2025
 
  
2024
 
  
2023
 
Charged to operating expenses:
        
Current:
        
Federal
   $ (43,334 )     $ 31,101    $ 66,086
State
     553      364      1,317
Deferred:
        
Federal
     100,502      (875 )       (94,860 ) 
State
     5      133      23
Amortization of deferred ITC
     (3,559 )       —          —    
  
 
 
    
 
 
    
 
 
 
Total income tax expense
   $ 54,167    $ 30,723    $ (27,434 ) 
  
 
 
    
 
 
    
 
 
 
Puget Sound Energy
   Year Ended December 31,  
(Dollars in Thousands)    2025      2024      2023  
Charged to operating expenses:
  
  
  
Current:
  
  
  
Federal
   $ (26,143 )     $ 61,924    $ 112,168
State
     848      889      1,626
Deferred:
        
Federal
     107,060      (10,226 )       (120,397 ) 
State
     —          —          —    
Amortization of deferred ITC
     (3,559 )       —          —    
  
 
 
    
 
 
    
 
 
 
Total income tax expense
   $ 78,206    $ 52,587    $ (6,603 ) 
  
 
 
    
 
 
    
 
 
 
The following reconciliation compares
pre-tax
book income at the federal stat
uto
ry rate of 21.0% to the actual income tax expense in the Consolidated Statements of Income:
 
Puget Energy
   Year Ended December 31,  
(Dollars in Thousands)    2025     2024     2023  
Income taxes at the statutory rate
   $ 88,944       21.0 %    $ 63,256     21.0 %    $ 5,524     21.0 % 
  
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
Increase (decrease) resulting from:
            
State and local income tax, net of federal benefit
1
   $ 458       0.1 %    $ 393     0.1 %    $ 1,070     4.1 % 
Nontaxable or nondeductible items
     4,735       1.1     4,069     1.4     2,747     10.4  
Other:
            
Utility plant differences
2
     (33,844 )      (8.0 )      (35,416 )      (11.8 )      (27,823 )      (105.8 ) 
Excess deferred tax amortization
     —         —         —         —         (8,689 )      (33.0 ) 
Other, net
     (6,126 )      (1.4 )    $ (1,579 )      (0.5 )    $ (263 )      (1.0 ) 
  
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
Total income tax expense
   $ 54,167       12.8 %    $ 30,723     10.2 %    $ (27,434 )      (104.3 )% 
  
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
 
F-58

Puget Sound Energy
  
Year Ended December 31,
 
(Dollars in Thousands)
  
2025
 
 
2024
 
 
2023
 
Income taxes at the statutory rate
  
$
112,754
 
 
21.0
% 
 
$
84,835
 
 
21.0
% 
 
$
26,136
 
 
21.0
% 
  
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
Increase (decrease) resulting from:
  
 
 
 
 
 
State and local income tax, net of federal benefit
1
  
$
678
 
 
0.1
% 
 
$
702
 
 
0.2
% 
 
$
1,291
 
 
1.0
% 
Nontaxable or nondeductible items
  
 
4,735
 
 
0.9
 
 
4,069
 
 
1.0
 
 
2,747
 
 
2.2
 
Other:
  
 
 
 
 
 
Utility plant differences
2
     (33,844 )      (6.3 )      (35,416 )      (8.8 )      (27,823 )      (22.3 ) 
Excess deferred tax amortization
     —         —         —         —         (8,689 )      (7.0 ) 
Other, net
     (6,117 )      (1.1 )      (1,603 )      (0.4 )      (265 )      (0.2 ) 
  
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
Total income tax expense
   $ 78,206     14.6 %    $ 52,587     13.0 %    $ (6,603 )      (5.3 )% 
  
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
 
1.
 
State taxes in California and Oregon made up the majority (greater than 50 percent) of the tax effect in this category.
2.
 
Utility plant differences include the reversal of excess deferred taxes using the average rate assumption method in the amount of $29.5 million, $29.8 million and $27.8 million in 2025, 2024 and 2023, respectively.
The Company’s net deferred tax liability at December 31, 2025, and 2024, is composed of amounts related to the following types of temporary differences:
 
Puget Energy
   At December 31,  
(Dollars in Thousands)    2025      2024  
Utility plant and equipment
   $ 1,757,760    $ 1,768,358
Operating lease liabilities
     134,988      61,109
Other deferred tax liabilities
     478,056      405,208
  
 
 
    
 
 
 
Subtotal deferred tax liabilities
   $ 2,370,804    $ 2,234,675
  
 
 
    
 
 
 
Net operating loss carryforward
   $ (207,047 )     $ (201,562 ) 
Net regulatory liability for income taxes
     (698,727 )       (721,907 ) 
Operating lease ROU assets
     (134,948 )       (60,920 ) 
Other deferred tax assets
     (388,259 )       (252,606 ) 
  
 
 
    
 
 
 
Subtotal deferred tax assets
   $ (1,428,981 )     $ (1,236,995 ) 
  
 
 
    
 
 
 
Total net deferred tax liabilities
   $ 941,823    $ 997,680
  
 
 
    
 
 
 
 
Puget Sound Energy
   At December 31,  
(Dollars in Thousands)    2025      2024  
Utility plant and equipment
   $ 1,751,292    $ 1,763,456
Operating lease liabilities
     134,988      61,109
Other deferred tax liabilities
     396,461      321,859
  
 
 
    
 
 
 
Subtotal deferred tax liabilities
   $ 2,282,741    $ 2,146,424
  
 
 
    
 
 
 
Net regulatory liability for income taxes
     (699,225 )       (722,558 ) 
Operating lease ROU assets
     (134,948 )       (60,920 ) 
Other deferred tax assets
     (379,142 )       (245,454 ) 
  
 
 
    
 
 
 
Subtotal deferred tax assets
   $ (1,213,315 )     $ (1,028,932 ) 
  
 
 
    
 
 
 
Total net deferred tax liabilities
   $ 1,069,426    $ 1,117,492
  
 
 
    
 
 
 
 
F-59

The Company’s income taxes paid (net of refunds) at December 31, 2025, and 2024, is composed of amounts related to the following jurisdictions:
 
Puget Energy
   At December 31,  
(Dollars in Thousands)    2025
1
     2024      2023  
Federal
   $ (69,268 )     $ 37,065    $ 69,678
  
 
 
    
 
 
    
 
 
 
Total income taxes paid
   $ (69,268 )     $ 37,065    $ 69,678
  
 
 
    
 
 
    
 
 
 
 
1.
 
Includes $22.2 million related to federal income taxes paid and federal income tax refunds of $91.5 million related to proceeds from the sale of transferable tax credits.
 
Puget Sound Energy
   At December 31,  
(Dollars in Thousands)    2025
1
     2024      2023  
Federal
   $ (51,630 )     $ 67,888    $ 115,680
  
 
 
    
 
 
    
 
 
 
Total income taxes paid
   $ (51,630 )     $ 67,888    $ 115,680
  
 
 
    
 
 
    
 
 
 
 
1.
 
Includes $39.8 million related to federal income taxes paid and federal income tax refunds of $91.5 million related to proceeds from the sale of transferable tax credits.
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.
In connection with qualifying projects, PSE generated ITCs corresponding to a $186.3 million accumulated deferred ITC regulatory liability, net of $3.6 million in ITC amortization, which was reported within the “Unamortized investment tax credit” financial statement line item on the consolidated balance sheets. During the year, PSE transferred a portion of its ITC from the Beaver Creek wind project for net proceeds of $91.5 million. The proceeds are included in “Proceeds from sale of transferrable tax credits” line on the Statement of Cash Flows. A partial valuation allowance was recorded for the remaining ITC for difference between value of the tax credit and the expected net sales price.
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, 2025 will be realized.
As of December 31, 2025, and 2024, 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 2022 through 2025. The Company classifies interest as interest expense and penalties as other expense in the financial statements.
(14) Litigation
From time to time, the Company is involved in litigation or legislative rulemaking proceedings relating to its operations in the normal course of business. As of December 31, 2025, the Company does not believe that it is involved in any pending proceedings material to the Company’s operations.
 
F-60

(15) Commitments and Contingencies
For the year ended December 31, 2025, approximately 14.0% of the Company’s energy output was obtained at an average cost of approximately $0.051 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:
 
(Dollars in Thousands)    2025      2024      2023  
PUD contract costs
   $ 219,263    $ 211,800    $ 174,385
As of December 31, 2025, the Company purchased portions of the power output of the PUDs’ projects as set forth in the following table:
 
            Company’s Share of  
(Dollars in Thousands)    Contract
Expiration
     2026
Percent of
Output
    2026
Megawatt
Capacity
     Estimated
2026 Total
Costs
     2026 Debt
Service
Costs
    
Interest included in
2026 Debt Service
Costs
     Debt
Outstanding
 
Rock Island and Rocky Reach Projects
     2051        35.0 %      764      $ 172,123    $ 26,126    $ 6,980    $ 150,913
Wells Project
     2032        20.0 %      168        74,216      —       —       — 
Priest Rapids and Wanapum Projects
     2052        9.0 %      179        86,362      721      386      8,533
       
 
 
    
 
 
    
 
 
    
 
 
    
 
 
 
Total
          1,111      $ 332,701    $ 26,847    $ 7,366    $ 159,446
       
 
 
    
 
 
    
 
 
    
 
 
    
 
 
 
Power Purchase Agreements
The Company enters into agreements to purchase power and electric capacity. Renewable energy PPAs include energy from solar, wind, hydro, and biomass sources in which some generation facilities have not yet been constructed. Other PPAs includes
non-renewable
energy sources, demand response contracts, and other wholesale agreements accounted for as derivatives under ASC 815 where the source of the energy is either
non-renewable
energy or unspecified. The contracts for renewable energy, capacity and other contracts expire at various dates through 2054, 2043, and 2030, respectively.
The following table summarizes the Company’s estimated payment obligations for electric portfolio contracts. These contracts have varying terms and may include escalation and termination provisions.
 
(Dollars in Thousands)    2026      2027      2028      2029      2030      Thereafter      Total  
Renewable energy
   $ 488,041    $ 394,573    $ 464,891    $ 439,601    $ 417,400    $ 7,098,946    $ 9,303,452
Capacity
     136,659      135,999      117,565      115,176      97,218      406,693      1,009,310
Other
     616,498      319,321      200,574      169,361      106,393      458,258      1,870,405
  
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
 
Total
   $ 1,241,198    $ 849,893    $ 783,030    $ 724,138    $ 621,011    $ 7,963,897    $ 12,183,167
  
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
 
 
F-61

Total purchased power contracts provided the Company with approximately 18.6 million, 14.6 million and 14.7 million MWhs of firm energy at a cost of approximately $1,196.4 million, $1,006.3 million and $851.6 million for the years 2025, 2024, and 2023, 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 $131.6 million, $125.0 million, and $137.6 million for firm transportation, storage and peaking services for its natural gas customers for the years 2025, 2024, and 2023. The Company incurred demand charges of $77.6 million, $71.1 million, and $60.5 million for firm transportation, storage and peaking services for the natural gas supply for its combustion turbines for the years 2025, 2024, and 2023.
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
(Dollars in Thousands)
   2026      2027      2028      2029      2030      Thereafter      Total  
Natural gas wholesale market transactions
   $ 520,649    $ 424,660    $ 265,083    $ 155,465    $ 76,323    $ —       $ 1,442,180
Firm transportation service
     184,218      182,042      176,006      144,404      123,190      541,516      1,351,376
Firm storage service
     8,476      8,189      2,678      837      837      4,109      25,126
  
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
 
Total
   $ 713,343    $ 614,891    $ 443,767    $ 300,706    $ 200,350    $ 545,625    $ 2,818,682
  
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
 
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
(Dollars in Thousands)
   2026      2027      2028      2029      2030      Thereafter      Total  
Energy production service contracts
   $ 38,372    $ 39,054    $ 42,082    $ 43,159    $ 42,905    $ 38,368    $ 243,940
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.
 
F-62

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 has provided an initial allocation of
no-cost
allowances to electric utilities, including PSE, for operations through 2026. However, qualifying electric utilities have been allowed to submit revised emissions forecasts approved by the Washington Commission to WDOE. PSE has filed revised forecasts for emissions associated with its 2023, 2025 and 2026 operations, all of which were approved by the Washington Commission. The WDOE approved the revised 2023 forecast and made modest adjustments to the 2026 revised forecast. PSE understands that WDOE will consider changes or adjustments to the 2025 forecast in October of 2026, after WDOE has received verified actual emissions for electric operations for calendar year 2025 actual emissions. To the extent WDOE were to determine that an adjustment to the allocation of
no-cost
allowances for PSE electric operations for calendar year 2025 were appropriate or necessary, PSE understands that such adjustment would occur in the form of an increase or decrease to the allocation of
no-cost
allowances for PSE electric operations for calendar year 2027.
The WDOE has provided notice to PSE that it does not intend to make further adjustments to its 2023 and 2024 annual compliance obligation based on its 2023 and 2024 reported covered emissions as previously reported to the WDOE. The WDOE has 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 $119.3 million for allowances for electric operations as of December 31, 2025. Given the potential for future rulemakings and the WDOE’s ability to adjust
no-cost
allowances for electric operations during the compliance period or make changes to rules governing the program, there is estimation uncertainty surrounding the Company’s ability to estimate its compliance obligation for electric operations both on an annual basis and a four-year compliance period, prior to a final WDOE determination. The WDOE has indicated there will be future rulemakings impacting the compliance obligation, including the
true-up
mechanism, which could impact periods within the first compliance period, thus, PSE has recorded its compliance obligation based on its best estimate and is unable to determine a range of possible outcomes at this time.
As existing uncertainties are resolved in future periods, any change in compliance costs incurred to date 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.
Indemnifications
In connection with the sale of approximately 50% of the ITC, PSE provided indemnification against the buyer’s losses related to a failure to satisfy the ITC qualification or transferability requirements under the Internal Revenue Code, but not due to the action or legal tax status of the buyer. As of December 31, 2025, management believes the likelihood is remote that PSE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the consolidated balance sheets with respect to these indemnities.
Other Commitments and Contingencies
On December 8, 2025, PSE entered into a tolling agreement to purchase the energy and capacity associated with a 700.0 MW
yet-to-be
constructed natural gas combined cycle facility. The tolling agreement represents a
 
F-63

lease to PSE and is expected to commence in the fourth quarter of 2028. The expected total capacity payments will approximate $2.1 billion over the lease term ending in December 2044. The agreement is subject to final approval by the counterparty upon the satisfaction of certain conditions including approval by the Washington Commission.
On July 22, 2025, the Company executed two agreements with the same counterparty that would provide the Company with the output of a 400 MW solar PV energy project and the capacity of a 200 MW battery energy storage system, both over a
25-year
term. The total estimated payment obligation during the term of the agreements is approximately $2.1 billion. The agreements contain certain provisions that would allow the counterparty to terminate the agreements within 300 days of the execution date for a nominal fee.
For information regarding PSE’s environmental remediation obligations, see Note 4, “Regulation and Rates,” above.
 
 
(16)
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, 2025, 2024 and 2023, respectively:
 

Puget Energy
 
Changes in AOCI, net of tax
(Dollars in Thousands)
  
Net unrealized gain
(loss) and prior
service cost on
pension plans
 
 
Total
 
Balance at December 31, 2022
   $ (24,774 )    $ (24,774 ) 
  
 
 
   
 
 
 
Other comprehensive income (loss) before reclassifications
     44,277     44,277
Amounts reclassified from accumulated other comprehensive income (loss), net of tax
     (1,964 )      (1,964 ) 
  
 
 
   
 
 
 
Net current-period other comprehensive income (loss)
     42,313     42,313
  
 
 
   
 
 
 
Balance at December 31, 2023
   $ 17,539   $ 17,539
  
 
 
   
 
 
 
Other comprehensive income (loss) before reclassifications
     27,866     27,866
Amounts reclassified from accumulated other comprehensive income (loss), net of tax
     (2,237 )      (2,237 ) 
  
 
 
   
 
 
 
Net current-period other comprehensive income (loss)
     25,629     25,629
  
 
 
   
 
 
 
Balance at December 31, 2024
   $ 43,168   $ 43,168
  
 
 
   
 
 
 
Other comprehensive income (loss) before reclassifications
     36,629     36,629
Amounts reclassified from accumulated other comprehensive income (loss), net of tax
     (3,968 )      (3,968 ) 
  
 
 
   
 
 
 
Net current-period other comprehensive income (loss)
     32,661     32,661
  
 
 
   
 
 
 
Balance at December 31, 2025
   $ 75,829   $ 75,829
  
 
 
   
 
 
 
 

Puget Sound Energy
 
Changes in AOCI, net of tax
(Dollars in Thousands)
  
Net unrealized gain
(loss) and prior
service cost on
pension plans
 
 
Net unrealized
gain (loss) on
treasury
interest rate
swaps
 
 
Total
 
Balance at December 31, 2022
   $ (98,830 )    $ (4,214 )    $ (103,044 ) 
  
 
 
   
 
 
   
 
 
 
Other comprehensive income (loss) before reclassifications
     44,277     —      44,277
  
 
 
   
 
 
   
 
 
 
Amounts reclassified from accumulated other comprehensive income (loss), net of tax
     (12 )      385     373
  
 
 
   
 
 
   
 
 
 
Net current-period other comprehensive income (loss)
     44,265     385     44,650
  
 
 
   
 
 
   
 
 
 
Balance at December 31, 2023
   $ (54,565 )    $ (3,829 )    $ (58,394 ) 
  
 
 
   
 
 
   
 
 
 
 
F-64

Puget Sound Energy
Changes in AOCI, net of tax
(Dollars in Thousands)
   Net unrealized gain
(loss) and prior
service cost on
pension plans
    Net unrealized
gain (loss) on
treasury
interest rate
swaps
    Total  
Other comprehensive income (loss) before reclassifications
     27,862     —      27,862
Amounts reclassified from accumulated other comprehensive income (loss), net of tax
     (101 )      386     285
  
 
 
   
 
 
   
 
 
 
Net current-period other comprehensive income (loss)
     27,761     386     28,147
  
 
 
   
 
 
   
 
 
 
Balance at December 31, 2024
   $ (26,804 )    $ (3,443 )    $ (30,247 ) 
  
 
 
   
 
 
   
 
 
 
Other comprehensive income (loss) before reclassifications
     36,648     —      36,648
Amounts reclassified from accumulated other comprehensive income (loss), net of tax
     (285 )      385     100
  
 
 
   
 
 
   
 
 
 
Net current-period other comprehensive income (loss)
     36,363     385     36,748
  
 
 
   
 
 
   
 
 
 
Balance at December 31, 2025
   $ 9,559   $ (3,058 )    $ 6,501
  
 
 
   
 
 
   
 
 
 
Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2025, 2024 and 2023, respectively, are as follows:
 
Puget Energy
(Dollars in Thousands)
                       
Details about accumulated other comprehensive income (loss)
components
   Affected line item in the
statement where net income
(loss) is presented
   Amount reclassified from
accumulated other comprehensive
income (loss)
 
   2025     2024     2023  
Net unrealized gain (loss) and prior service cost on pension plans:
         
Amortization of prior service cost
   (a)    $ (35 )    $ (33 )    $ (172 ) 
Amortization of net gain (loss)
   (a)      5,058     2,865     2,658
     
 
 
   
 
 
   
 
 
 
   Total before tax      5,023     2,832     2,486
   Tax (expense) or benefit      (1,055 )      (595 )      (522 ) 
     
 
 
   
 
 
   
 
 
 
   Net of tax      3,968     2,237     1,964
     
 
 
   
 
 
   
 
 
 
Total reclassification for the period
   Net of tax    $ 3,968   $ 2,237   $ 1,964
     
 
 
   
 
 
   
 
 
 
 
(a)
These AOCI components are included in the computation of net periodic pension cost, see Note 12, “Retirement Benefits,” above.
 
Puget Sound Energy
(Dollars in Thousands)
                       
Details about accumulated other comprehensive income (loss) components    Affected line item in the
statement where net income
(loss) is presented
   Amount reclassified from
accumulated other comprehensive
income (loss)
 
   2025     2024     2023  
Net unrealized gain (loss) and prior service cost on pension plans:
         
Amortization of prior service cost
   (a)    $ (35 )    $ (33 )    $ (172 ) 
Amortization of net gain (loss)
   (a)      396     161     187
     
 
 
   
 
 
   
 
 
 
   Total before tax      361     128     15
   Tax (expense) or benefit      (76 )      (27 )      (3 ) 
     
 
 
   
 
 
   
 
 
 
   Net of tax      285     101     12
     
 
 
   
 
 
   
 
 
 
 
F-65

Puget Sound Energy
(Dollars in Thousands)
                       
Details about accumulated other comprehensive income (loss) components    Affected line item in the
statement where net income
(loss) is presented
   Amount reclassified from
accumulated other comprehensive
income (loss)
 
   2025     2024     2023  
Net unrealized gain (loss) on treasury interest rate swaps:
         
Interest rate contracts
   Interest expense      (488 )      (487 )      (488 ) 
   Tax (expense) or benefit      103     101     103
     
 
 
   
 
 
   
 
 
 
   Net of tax      (385 )      (386 )      (385 ) 
     
 
 
   
 
 
   
 
 
 
Total reclassification for the period
   Net of tax    $ (100 )    $ (285 )    $ (373 ) 
     
 
 
   
 
 
   
 
 
 
 
(a)
 
These AOCI components are included in the computation of net periodic pension cost, see Note 12, “Retirement Benefits,” above.
 
 
(17)
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” above. 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.
 
Puget Energy
   Year Ended December 31, 2025  
(Dollars in Thousands)    Regulated Utility      Other      Total  
Revenue
   $ 5,378,168    $ 38,165    $ 5,416,333
Depreciation and amortization
     844,583      6,745      851,328
Income tax (benefit) expense
     78,206      (24,039 )       54,167
Non-utility
expense and other
     40,522      24,667      65,189
Interest expense
     346,155      122,747      468,902
Net income (loss)
     458,715      (89,347 )       369,368
Total assets
     18,985,451      1,921,342      20,906,793
Construction expenditures
     1,770,218      1,610      1,771,828
 
Puget Energy
   Year Ended December 31, 2024  
(Dollars in Thousands)    Regulated Utility      Other      Total  
Revenue
   $ 4,825,231    $ 30,984    $ 4,856,215
Depreciation and amortization
     781,325      6,661      787,986
Income tax (benefit) expense
     52,587      (21,864 )       30,723
Non-utility
expense and other
     21,664      24,392      46,056
Interest expense
     321,550      110,644      432,194
Net income (loss)
     346,148      (80,893 )       265,255
Total assets
     17,026,384      1,934,007      18,960,391
Construction expenditures
     1,608,947      768      1,609,715
 
F-66

Puget Energy
   Year Ended December 31, 2023  
(Dollars in Thousands)    Regulated Utility      Other      Total  
Revenue
   $ 4,786,618    $ 29,956    $ 4,816,574
Depreciation and amortization
     744,629      6,706      751,335
Income tax (benefit) expense
     (6,603 )       (20,831 )       (27,434 ) 
Non-utility
expense and other
     28,658      27,857      56,515
Interest expense
     285,148      96,363      381,511
Net income (loss)
     131,059      (77,319 )       53,740
Total assets
     15,771,767      1,960,686      17,732,453
Construction expenditures
     1,465,925      640      1,466,565
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, $3.7 million, and $1.1 million for years ended December 31, 2025, 2024 and 2023, 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.
 
F-67

SCHEDULE I: CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY
PUGET ENERGY, INC.
CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Dollars in Thousands)
 
     Year Ended December 31,  
     2025     2024     2023  
Non-utility
expense and other
   $ (3,302 )    $ (2,883 )    $ (1,466 ) 
Other income (deductions):
      
Equity in earnings of subsidiary
     447,714     334,121     110,719
Interest income
     19,006     18,439     17,863
Interest expense
     (115,125 )      (103,019 )      (88,739 ) 
Income tax benefit (expense)
     21,075     18,597     15,363
  
 
 
   
 
 
   
 
 
 
Net income (loss)
   $ 369,368   $ 265,255   $ 53,740
  
 
 
   
 
 
   
 
 
 
Comprehensive income (loss)
   $ 402,029   $ 290,884   $ 96,053
  
 
 
   
 
 
   
 
 
 
See accompanying notes to the condensed financial statements.
 
F-68

PUGET ENERGY, INC.
CONDENSED BALANCE SHEETS
(Dollars in Thousands)
 
     December 31,  
     2025      2024  
Assets:
     
Investment in subsidiaries
   $ 6,220,409    $ 5,594,854
Other property and investments:
     
Goodwill
     1,656,513        1,656,513  
Current assets:
     
Cash
     1,224        817  
Receivables from affiliates
1
     255,198        256,671  
Prepaid expenses and other
     25        16  
Income tax receivables
     455        521  
  
 
 
    
 
 
 
Total current assets
     256,902      258,025  
  
 
 
    
 
 
 
Long-term assets:
     
Deferred income taxes
     205,296        196,210  
Other
     716        1,891  
  
 
 
    
 
 
 
Total long-term assets
     206,012        198,101  
  
 
 
    
 
 
 
Total assets
   $ 8,339,836    $ 7,707,493
  
 
 
    
 
 
 
Capitalization and liabilities:
     
Common equity
   $ 5,707,347    $ 5,368,205
Long-term debt
     2,187,139      1,590,795  
  
 
 
    
 
 
 
Total capitalization
     7,894,486      6,959,000
  
 
 
    
 
 
 
Current liabilities:
     
Accounts payable to affiliates
1
     183        195  
Short-term debt
     427,500        338,400  
Current maturities of long-term debt
     —         400,000  
Interest
     17,667        9,898  
  
 
 
    
 
 
 
Total current liabilities
     445,350      748,493
  
 
 
    
 
 
 
Commitments and contingencies (Note 16)
     
  
 
 
    
 
 
 
Total capitalization and liabilities
   $ 8,339,836    $ 7,707,493
  
 
 
    
 
 
 
 
1
 
Eliminated in consolidation.
See accompanying notes to the condensed financial statements.
 
F-69

PUGET ENERGY, INC.
CONDENSED STATEMENT OF CASH FLOWS
(Dollars in Thousands)
 
     Year Ended December 31,  
     2025     2024     2023  
Operating activities:
      
Net cash provided by (used in) operating activities
   $ 40,513   $ 96,588   $ 64,506
Investing activities:
      
Investment in subsidiaries
     (264,000 )      (292,800 )      (100,000 ) 
(Increase) decrease in loan to subsidiary
     1,337     (590 )      (9,753 ) 
  
 
 
   
 
 
   
 
 
 
Net cash provided by (used in) investing activities
     (262,663 )      (293,390 )      (109,753 ) 
  
 
 
   
 
 
   
 
 
 
Financing activities:
      
Dividends paid
     (62,887 )      (175,861 )      (99,760 ) 
Capital contribution
     —      292,800     — 
Change in short-term debts, net
     89,100     76,900     142,900
Issuance of long-term debts
     596,100     —      — 
Redemption of long-term debts
     (400,000 )      —      — 
Issue costs and others
     244     2,184     2,175
  
 
 
   
 
 
   
 
 
 
Net cash provided by (used in) by financing activities
     222,557     196,023     45,315
  
 
 
   
 
 
   
 
 
 
Increase (decrease) in cash
     407     (779 )      68
Cash at beginning of year
     817     1,596     1,528
  
 
 
   
 
 
   
 
 
 
Cash at end of year
   $ 1,224   $ 817   $ 1,596
  
 
 
   
 
 
   
 
 
 
See accompanying notes to the condensed financial statements.
 
F-70

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 this prospectus. Puget Energy owns 100% of the common stock of its subsidiaries.
Equity earnings of subsidiary included earnings from PSE and Puget LNG of $450.1 million, $338.1 million and $114.8 million for the years ended December 31, 2025, 2024, and 2023, respectively, and business combination accounting adjustments under ASC 805 recorded at Puget Energy for PSE of $(2.4) million, $(4.0) million and $(4.1) million for the years ended December 31, 2025, 2024, and 2023, 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 audited consolidated financial statements included in this prospectus.
(3) Commitments and Contingencies
For information concerning Puget Energy’s material contingencies and guarantees, see Note 15, “Commitments and Contingencies” to the audited consolidated financial statements included in this prospectus.
 
F-71

SCHEDULE II: VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
 
Puget Energy and
Puget Sound Energy
(Dollars in Thousands)
   Balance at
Beginning of
Period
     Additions
Charged to
Costs and
Expenses
     Deductions      Balance
at End
of Period
 
Year Ended December 31, 2025
           
Accounts deducted from assets on balance sheet:
           
Allowance for doubtful accounts receivable
   $ 40,436    $ 31,343    $ 45,327    $ 26,452
  
 
 
    
 
 
    
 
 
    
 
 
 
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
  
 
 
    
 
 
    
 
 
    
 
 
 
 
F-72

UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS FOR THE THREE MONTHS ENDED MARCH 31, 2026 AND 2025
PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands)
(Unaudited)
 
     Three Months Ended
March 31,
 
     2026     2025  
Operating revenue:
    
Electric
   $ 1,260,579     $ 1,026,948  
Natural gas
     579,150       564,927  
Other
     8,528       10,128  
  
 
 
   
 
 
 
Total operating revenue
     1,848,257       1,602,003  
  
 
 
   
 
 
 
Operating expenses:
    
Energy costs:
    
Purchased electricity
     555,515       381,528  
Electric generation fuel
     24,640       91,624  
Residential exchange
     (22,713 )      (27,234 ) 
Purchased natural gas
     231,987       246,515  
Utility operations and maintenance
     274,821       232,385  
Non-utility
expense and other
     12,753       15,327  
Depreciation & amortization
     212,363       210,376  
Conservation amortization
     57,145       47,880  
Taxes other than income taxes
     165,512       142,721  
  
 
 
   
 
 
 
Total operating expenses
     1,512,023       1,341,122  
  
 
 
   
 
 
 
Operating income (loss)
     336,234       260,881  
Other income (expense):
    
Other income
     29,850       33,264  
Other expense
     (1,074 )      (3,516 ) 
Interest charges:
    
AFUDC
     6,818       10,087  
Interest expense
     (123,267 )      (112,662 ) 
  
 
 
   
 
 
 
Income (loss) before income taxes
     248,561       188,054  
  
 
 
   
 
 
 
Income tax (benefit) expense
     25,729       20,498  
  
 
 
   
 
 
 
Net income (loss)
   $ 222,832     $ 167,556  
  
 
 
   
 
 
 
The accompanying notes are an integral part of the financial statements.
 
F-73

PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in Thousands)
(Unaudited)
 
     Three Months Ended
March 31,
 
     2026     2025  
Net income (loss)
   $ 222,832     $ 167,556  
  
 
 
   
 
 
 
Other comprehensive income (loss):
    
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $(148) and $(269), respectively
     (550 )      (1,014 ) 
  
 
 
   
 
 
 
Other comprehensive income (loss)
     (550 )      (1,014 ) 
  
 
 
   
 
 
 
Comprehensive income (loss)
   $ 222,282     $ 166,542  
  
 
 
   
 
 
 
The accompanying notes are an integral part of the financial statements.
 
F-74

PUGET ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
ASSETS
 
     March 31,
2026
    December 31,
2025
 
Utility plant (at original cost, including construction work in progress of $1,231,934 and $1,082,208 respectively):
    
Electric plant
   $ 13,734,516     $ 13,745,675  
Natural gas plant
     5,482,399       5,428,156  
Common plant
     1,267,848       1,247,883  
Less: Accumulated depreciation and amortization
     (5,434,528 )      (5,555,794 ) 
  
 
 
   
 
 
 
Net utility plant
     15,050,235       14,865,920  
  
 
 
   
 
 
 
Other property and investments:
    
Goodwill
     1,656,513       1,656,513  
Other property and investments
     288,546       289,861  
  
 
 
   
 
 
 
Total other property and investments
     1,945,059       1,946,374  
  
 
 
   
 
 
 
Current assets:
    
Cash and cash equivalents
     521,709       40,484  
Restricted cash
     152,848       118,369  
Accounts receivable, net of allowance for doubtful accounts of $28,870 and $26,452, respectively
     588,555       511,163  
Unbilled revenue
     341,516       332,087  
Materials and supplies, at average cost
     250,809       232,947  
Fuel and natural gas inventory, at average cost
     63,248       83,535  
Unrealized gain on derivative instruments
     47,526       37,448  
GHG emission allowances
     —        22,788  
Prepaid expense and other
     93,272       132,669  
Power contract acquisition adjustment gain
     3,421       3,565  
  
 
 
   
 
 
 
Total current assets
     2,062,904       1,515,055  
  
 
 
   
 
 
 
Other long-term and regulatory assets:
    
Power cost adjustment mechanism
     125,881       143,687  
Regulatory assets related to power contracts
     3,464       3,705  
Other regulatory assets
     1,529,151       1,564,693  
Unrealized gain on derivative instruments
     5,783       11,261  
Power contract acquisition adjustment gain
     22,131       22,878  
Operating lease
right-of-use
asset
     441,277       460,990  
Other
     372,826       372,230  
  
 
 
   
 
 
 
Total other long-term and regulatory assets
     2,500,513       2,579,444  
  
 
 
   
 
 
 
Total assets
   $ 21,558,711     $ 20,906,793  
  
 
 
   
 
 
 
The accompanying notes are an integral part of the financial statements.
 
F-75

PUGET ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
CAPITALIZATION AND LIABILITIES
 
     March 31,
2026
    December 31,
2025
 
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       3,816,332  
Retained earnings
     2,017,075       1,815,186  
Accumulated other comprehensive income (loss), net of tax
     75,279       75,829  
  
 
 
   
 
 
 
Total common shareholder’s equity
     5,908,686       5,707,347  
  
 
 
   
 
 
 
Long-term debt:
    
First mortgage bonds and senior notes
     6,345,000       6,345,000  
Pollution control bonds
     161,860       161,860  
Long-term debt
     3,100,000       2,200,000  
Debt discount issuance costs and other
     (187,515 )      (181,828 ) 
  
 
 
   
 
 
 
Total long-term debt
     9,419,345       8,525,032  
  
 
 
   
 
 
 
Total capitalization
     15,328,031       14,232,379  
  
 
 
   
 
 
 
Current liabilities:
    
Accounts payable
     519,971       642,044  
Short-term debt
     140,000       487,500  
Accrued expenses:
    
Taxes
     193,981       125,719  
Salaries and wages
     50,049       84,248  
Interest
     93,267       80,969  
Unrealized loss on derivative instruments
     326,720       359,890  
Power contract acquisition adjustment loss
     961       963  
Operating lease liabilities
     105,512       104,240  
Compliance obligation
     —        22,788  
Other
     93,484       84,341  
  
 
 
   
 
 
 
Total current liabilities
     1,523,945       1,992,702  
  
 
 
   
 
 
 
Other long-term and regulatory liabilities:
    
Deferred income taxes
     946,764       941,823  
Unamortized investment tax credits
     183,453       186,250  
Unrealized loss on derivative instruments
     254,783       213,531  
Purchased gas adjustment liability
     55,870       65,931  
Regulatory liabilities
     1,075,036       1,087,668  
Regulatory liability for deferred income taxes
     686,796       698,727  
Regulatory liabilities related to power contracts
     25,552       26,443  
Power contract acquisition adjustment loss
     2,503       2,742  
Operating lease liabilities
     343,204       365,359  
Finance lease liabilities
     166,059       167,426  
Compliance obligation
     140,105       96,490  
Other deferred credits
     826,610       829,322  
  
 
 
   
 
 
 
Total long-term and regulatory liabilities
     4,706,735       4,681,712  
  
 
 
   
 
 
 
Commitments and contingencies (Note 8)
    
  
 
 
   
 
 
 
Total capitalization and liabilities
   $ 21,558,711     $ 20,906,793  
  
 
 
   
 
 
 
The accompanying notes are an integral part of the financial statements.
 
F-76

PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY
(Dollars in Thousands)
(Unaudited)
 
     Common Stock      Additional
Paid-in

Capital
           Accumulated
Other
Comprehensive
Income (Loss)
       
     Shares      Amount      Retained
Earnings
    Total
Equity
 
Balance at December 31, 2024
     200      $ —       $ 3,816,332      $ 1,508,705     $ 43,168     $ 5,368,205  
Net income (loss)
     —         —         —         167,556       —        167,556  
Common stock dividend paid
     —         —         —         (19,979 )      —        (19,979 ) 
Other comprehensive income (loss)
     —         —         —         —        (1,014 )      (1,014 ) 
  
 
 
    
 
 
    
 
 
    
 
 
   
 
 
   
 
 
 
Balance at March 31, 2025
     200        —       $ 3,816,332      $ 1,656,282     $ 42,154     $ 5,514,768  
  
 
 
    
 
 
    
 
 
    
 
 
   
 
 
   
 
 
 
Balance at December 31, 2025
     200      $ —       $ 3,816,332      $ 1,815,186     $ 75,829     $ 5,707,347  
  
 
 
    
 
 
    
 
 
    
 
 
   
 
 
   
 
 
 
Net income (loss)
     —         —         —         222,832       —        222,832  
Common stock dividend paid
     —         —         —         (20,943 )      —        (20,943 ) 
Other comprehensive income (loss)
     —         —         —         —        (550 )      (550 ) 
  
 
 
    
 
 
    
 
 
    
 
 
   
 
 
   
 
 
 
Balance at March 31, 2026
     200      $ —       $ 3,816,332      $ 2,017,075     $ 75,279     $ 5,908,686  
  
 
 
    
 
 
    
 
 
    
 
 
   
 
 
   
 
 
 
The accompanying notes are an integral part of the consolidated financial statements.
 
F-77

PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
 
     Three Months Ended
March 31,
 
     2026     2025  
Operating activities:
    
Net Income (loss)
   $ 222,832     $ 167,556  
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
    
Depreciation and amortization
     212,363       210,376  
Conservation amortization
     57,145       47,880  
Deferred income taxes and tax credits, net
     (7,211 )      (9,183 ) 
AFUDC—equity
     (11,269 )      (17,379 ) 
Other
non-cash
     34,197       25,339  
Regulatory assets and liabilities
     59,066       31,154  
Purchased gas adjustment
     (10,061 )      22,871  
GHG emission allowances
     (16,797 )      —   
Other long-term assets and liabilities
     (13,032 )      (5,055 ) 
Change in certain current assets and liabilities:
    
Accounts receivable and unbilled revenue
     (86,821 )      (55,338 ) 
Materials and supplies
     (26,374 )      (21,367 ) 
Fuel and natural gas inventory
     14,959       22,637  
Prepayments and other
     25,640       14,874  
Accounts payable
     (107,415 )      (90,699 ) 
Taxes payable
     68,262       39,674  
Other
     (17,232 )      13,682  
  
 
 
   
 
 
 
Net cash provided by (used in) operating activities
     398,252       397,022  
  
 
 
   
 
 
 
Investing activities:
    
Construction expenditures—excluding equity AFUDC
     (412,214 )      (353,582 ) 
Other
     75       2,432  
  
 
 
   
 
 
 
Net cash provided by (used in) investing activities
     (412,139 )      (351,150 ) 
  
 
 
   
 
 
 
Financing activities:
    
Change in short-term debt, net
     (347,500 )      (188,500 ) 
Dividends paid
     (20,943 )      (19,979 ) 
Proceeds from long-term debt and bonds issued
     891,000       596,100  
Other
     7,034       2,963  
  
 
 
   
 
 
 
Net cash provided by (used in) financing activities
     529,591       390,584  
  
 
 
   
 
 
 
Net increase (decrease) in cash, cash equivalents, and restricted cash
     515,704       436,456  
Cash, cash equivalents, and restricted cash at beginning of period
     158,853       140,701  
  
 
 
   
 
 
 
Cash, cash equivalents, and restricted cash at end of period
   $ 674,557     $ 577,157  
  
 
 
   
 
 
 
Supplemental cash flow information:
    
Cash payments for interest (net of capitalized interest)
   $ 100,325     $ 65,276  
Non-cash
financing and investing activities:
    
Accounts payable for capital expenditures eliminated from cash flows
   $ 97,872     $ 97,494  
The accompanying notes are an integral part of the financial statements.
 
F-78

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
 
 
(1)
Summary of Significant Accounting Policies
Basis of Presentation
Puget Energy is an energy services holding company that owns PSE, which 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, which has the sole purpose of owning and operating the
non-regulated
activity of the Tacoma 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, 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 FASB ASC 805, “Business Combinations” (ASC 805), as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date.
The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company.” The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any ASC 805 purchase accounting adjustments. 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.
Allowance for Credit Losses
The Company measures expected credit losses on trade receivables on a collective basis by receivable type, which includes electric retail receivables, natural 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 for the three months ended March 31, 2026 and 2025:
 
Puget Energy and
Puget Sound Energy
   Three Months Ended March 31,  
(Dollars in Thousands)    2026      2025  
Allowance for credit losses:
     
Beginning balance
   $  26,452      $  40,436  
Provision for credit loss expense
1
     10,905        13,673  
Receivables
charged-off
     (8,487 )       (10,810 ) 
  
 
 
    
 
 
 
Total ending allowance balance
   $ 28,870      $ 43,299  
  
 
 
    
 
 
 
 
1
 
$4.7 million and $9.3 million of provision related to balances of deferred costs specific to
COVID-19
as of March 31, 2026 and 2025, respectively.
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
 
F-79

marine market. 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.
Based on an order by the Washington Commission, approximately 43.0% of common capital and operating costs are allocated to PSE, the regulated portion of the Tacoma LNG facility. The remaining 57.0% of common capital and operating costs of the Tacoma LNG facility is allocated to Puget LNG, the unregulated portion of the Tacoma LNG facility. Per this allocation of costs, $228.2 million and $228.9 million of net
non-utility
plant related to Puget LNG’s portion of the Tacoma LNG facility is reported in the Puget Energy “Other property and investments” line item as of March 31, 2026 and December 31, 2025, respectively. Additionally, $6.4 million and $7.1 million of operating costs are reported in the Puget Energy
“Non-utility
expense and other” financial statement line item for the three months ended March 31, 2026, and March 31, 2025, respectively. Further, $222.5 million and $223.2 million of natural gas plant 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 March 31, 2026 and December 31, 2025, respectively, as PSE is a regulated entity.
Variable Interest Entities
PSE has certain PPAs in which PSE has variable interests mainly including fixed price contracts for renewable energy. The most significant economic activity for these variable interest entities (VIEs) is typically the operation and maintenance of the facility, which is performed by the seller. Therefore, the Company is not the primary beneficiary of any of these VIEs as it does not control the commercial and operating activities that most significantly impact the economic performance of the entities.
The carrying amount of any assets and liabilities related to these VIEs in the Company’s balance sheets represent amounts due from the PPAs. The Company can recover these costs through the PCA mechanism. The Company has no residual interest in the entities and has not provided or guaranteed any debt or equity support, liquidity arrangements, performance guarantees, or other commitments associated with these contracts. The aggregate contracted capacity from these VIE projects were 813.8 MW and 723.8 MW at March 31, 2026 and 2025, respectively. Purchased energy of $25.8 million and $25.0 million was recognized in purchased electricity on the Company’s consolidated statements of income for the three months ended March 31, 2026 and 2025, respectively. Additionally, $9.8 million and $14.5 million was included in accounts payable on the Company’s balance sheets as of March 31, 2026 and December 31, 2025, respectively.
For further information on the Company’s accounting policies, see Note 1, “Summary of Significant Accounting Policies” to the audited consolidated financial statements included in this prospectus.
 
 
(2)
New Accounting Pronouncements
Recently Adopted Accounting Guidance
Interim Reporting
In December 2025, the FASB issued ASU
No. 2025-11,
“Interim Reporting (Topic 270): Narrow-Scope Improvements)”. ASU
2025-11
is intended to clarify what disclosures should be provided and clarify when the guidance is applicable. The amendments of ASU
2025-11
should be applied prospectively and are effective for annual and interim periods beginning after December 15, 2027, with early adoption permitted. As of March 31, 2026, the Company’s disclosures are consistent with the amendment.
Measurement of Credit Losses Disclosures
In July 2025, the FASB issued ASU
No. 2025-05,
“Financial Instruments-Credit Losses (Topic 326) - Measurement of Credit Losses for Accounts Receivable and Contract Assets”. ASU
2025-05
provides a practical expedient that allows entities to assume that current conditions as of the balance sheet date do not
 
F-80

change for the remaining life of the asset when estimating expected credit losses for current accounts receivable and current contract assets. The amendments of ASU
2025-05
should be applied prospectively and are effective for annual and interim periods beginning after December 15, 2025, with early adoption permitted. As of March 31, 2026, the Company’s disclosures are consistent with the amendment.
Accounting Standards Issued but Not Yet Adopted
Government Grants
In December 2025, the FASB issued ASU
No. 2025-10,
“Government Grants (Topic 832)”. ASU
2025-10
establishes authoritative guidance regarding recognition, measurement and presentation for government grants received by business entities. The amendments of ASU
2025-10
should be applied prospectively and are effective for annual and interim periods beginning after December 15, 2028, with early adoption permitted. The Company is currently evaluating the impact of adopting ASU
2025-10
on its consolidated financial statements and related disclosures.
Derivatives and Hedging and Revenue with Contracts with Customers
In September 2025, the FASB issued ASU
No. 2025-07,
“
Derivatives and Hedging (Topic 815) and Revenue from Contract with Customers (Topic 606)
”. ASU
2025-07
addresses stakeholders concerns about i) the application of derivative accounting to contracts with features based on activities or operations of a party to the contract and ii) the diversity of accounting for share -based
non-cash
consideration. The amendments of ASU
2025-07
should be applied prospectively and are effective for annual and interim periods beginning after December 15, 2026, with early adoption permitted. The Company has evaluated the impact of adopting ASU
2025-07
and has concluded that this will not have a substantial impact on the Company’s consolidated financial statements or related disclosures.
Intangibles - Goodwill and Other -
Internal-Use
Software
In September 2025, the FASB issued ASU
No. 2025-06,
“
Intangibles - Goodwill and Other -
Internal-Use
Software (Subtopic
350-40)
”. ASU
2025-06
modernizes the accounting for software costs that are accounted for under Subtopic
350-40.
The amendments of ASU
2025-06
should be applied prospectively and are effective for annual and interim periods beginning after December 15, 2027, with early adoption permitted. The Company is currently evaluating the impact of adopting ASU
2025-06
on its consolidated financial statements and related disclosures.
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.
 
F-81

 
(3)
Revenue
The following tables present disaggregated revenue from contracts with customers, and other revenue by major source for the three months ended March 31, 2026 and March 31, 2025:
 

Puget Energy and
Puget Sound Energy
  
 
 
(Dollars in Thousands)
  
Three Months Ended March 31, 2026
 
Revenue from contracts with customers:
  
Electric
 
  
Natural Gas
 
  
Other
 
  
Total
 
Retail
           
Residential
   $ 707,357      $ 373,797      $ —       $ 1,081,154  
Commercial
     426,942        159,957        —         586,899  
Industrial
     46,046        10,280        —         56,326  
Other
     6,917        —         —         6,917  
Wholesale
     19,310        —         —         19,310  
Transmission and transportation
     14,564        11,973        —         26,537  
Miscellaneous
1
     74,158        44,192        118        118,468  
  
 
 
    
 
 
    
 
 
    
 
 
 
Total revenue from contracts with customers
   $ 1,295,294      $ 600,199      $ 118      $ 1,895,611  
  
 
 
    
 
 
    
 
 
    
 
 
 
Total other revenue
2
     (34,715 )       (20,378 )       —         (55,093 ) 
  
 
 
    
 
 
    
 
 
    
 
 
 
Total PSE operating revenue
   $ 1,260,579      $ 579,821      $ 118      $ 1,840,518  
Puget LNG operating revenue
     —         —         8,410        8,410  
Intercompany eliminations
     —         (671 )       —         (671 ) 
  
 
 
    
 
 
    
 
 
    
 
 
 
Total Puget Energy operating revenue
   $ 1,260,579      $ 579,150      $ 8,528      $ 1,848,257  
  
 
 
    
 
 
    
 
 
    
 
 
 
 
1
Miscellaneous electric and natural gas revenue includes $71.4 million and $46.9 million, respectively, of CCA credits passed back to customers.
2
 
Total other revenue includes revenues from derivatives and alternative revenue programs that are not considered revenues from contracts with customers.
 

Puget Energy and
Puget Sound Energy
  
 
 
(Dollars in Thousands)
  
Three Months Ended March 31, 2025
 
Revenue from contracts with customers:
  
Electric
 
  
Natural Gas
 
  
Other
 
  
Total
 
Retail
           
Residential
   $ 583,762      $ 373,364      $ —       $ 957,126  
Commercial
     341,308        159,481        —         500,789  
Industrial
     36,689        10,322        —         47,011  
Other
     6,242        —         —         6,242  
Wholesale
     71,993        —         —         71,993  
Transmission and transportation
     8,764        9,334        —         18,098  
Miscellaneous
1
     5,622        40,893        99        46,614  
  
 
 
    
 
 
    
 
 
    
 
 
 
Total revenue from contracts with customers
   $ 1,054,380      $ 593,394      $ 99      $ 1,647,873  
  
 
 
    
 
 
    
 
 
    
 
 
 
Total other revenue
2
     (27,432 )       (27,421 )       —         (54,853 ) 
  
 
 
    
 
 
    
 
 
    
 
 
 
Total PSE operating revenue
   $ 1,026,948      $ 565,973      $ 99      $ 1,593,020  
Puget LNG operating revenue
     —         —         10,029        10,029  
Intercompany eliminations
     —         (1,046 )       —         (1,046 ) 
  
 
 
    
 
 
    
 
 
    
 
 
 
Total Puget Energy operating revenue
   $ 1,026,948      $ 564,927      $ 10,128      $ 1,602,003  
  
 
 
    
 
 
    
 
 
    
 
 
 
 
1
Miscellaneous natural gas revenue includes $37.9 million of CCA credits passed back to customers.
 
F-82

2
 
Total other revenue includes revenues from derivatives and alternative revenue programs that are not considered revenues from contracts with customers.
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 which began 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 considerations. 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.
The Company expects to recognize revenue over the following time periods:
 
Puget Energy
      
(Dollars in Thousands)    2026      2027      2028      2029      2030      Thereafter      Total  
Remaining performance obligations
   $ 14,591      $ 19,454      $ 19,454      $ 19,454      $ 19,454      $ 63,227      $ 155,634  
The Company has elected the optional exemption in ASC 606, “Revenues from Contracts with Customers”, 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) fluctuations in 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)
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 Power Cost Adjustment. Therefore, wholesale market transactions and PSE’s related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility in costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy, which extends out three years. PSE’s hedging strategy includes a risk-responsive component for the core natural gas portfolio, which utilizes quantitative risk-based measures with defined objectives to balance both portfolio risk and hedge costs.
PSE’s energy risk portfolio management function monitors and manages these risks using analytical models and tools. In order to manage risks effectively, PSE enters into forward physical electric and natural gas purchase and sale agreements,
fixed-for-floating
swap contracts, and commodity call/put options. Currently, the Company does not apply cash flow hedge accounting and therefore records all
mark-to-market
gains or losses through earnings.
The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program and its credit facilities to meet short-term funding needs. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts.
 
F-83

The following table presents the volumes, fair values and classification of the Company’s derivative instruments recorded on the balance sheets:
 
Puget Energy and
Puget Sound Energy
      
     March 31, 2026      December 31, 2025  
(Dollars in Thousands)    Volumes
(millions)
     Assets
1
     Liabilities
2
     Volumes
(millions)
     Assets
1
     Liabilities
2
 
Electric portfolio derivatives
3
     *      $ 46,733      $ 506,832        *      $ 41,974      $ 493,334  
Natural gas derivatives (MMBtus)
3
     261        6,576        74,671        289        6,735        80,087  
  
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
 
Total derivative contracts
      $ 53,309      $ 581,503         $ 48,709      $ 573,421  
     
 
 
    
 
 
       
 
 
    
 
 
 
Current
      $ 47,526      $ 326,720         $ 37,448      $ 359,890  
Long-term
        5,783        254,783           11,261        213,531  
     
 
 
    
 
 
       
 
 
    
 
 
 
Total derivative contracts
      $ 53,309      $ 581,503         $ 48,709      $ 573,421  
     
 
 
    
 
 
       
 
 
    
 
 
 
 
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.” 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.
*
 
Electric portfolio derivatives consist of electric generation fuel of 243.3 million MMBtu and purchased electricity of 28.4 million MWhs at March 31, 2026, and 252.9 million MMBtus and 33.8 million MWhs at December 31, 2025.
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 agreements, which standardize physical power contracts; ISDA agreements, which standardize financial natural gas and electric contracts; and 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 5, “Fair Value Measurements,” below.
The electric and natural gas derivative contracts above will be included in power costs during the period they are delivered and will be included in the applicable recovery mechanism.
The following tables present the potential effect of netting arrangements, including rights of
set-off
associated with the Company’s derivative assets and liabilities:
 
Puget Energy and
Puget Sound Energy
 
     At March 31, 2026  
     Gross
Amount
Recognized
in the
Statement
of Financial
Position
1
     Gross
Amounts
Offset in
the
Statement
of Financial
Position
     Net of
Amounts
Presented in
the
Statement
of Financial
Position
     Gross Amounts Not
Offset in the Statement of
Financial Position
       
(Dollars in Thousands)    Commodity
Contracts
    Cash
Collateral
Received/
Posted
    Net
Amount
 
Assets:
               
Energy derivative contracts
   $ 53,309      $
—
 
     $ 53,309      $ (47,471 )    $ —      $ 5,838  
Liabilities:
               
Energy derivative contracts
   $ 581,503      $ —       $ 581,503      $ (47,471 )    $ (49,007 )    $ 485,025  
 
F-84

Puget Energy and
Puget Sound Energy
   At December 31, 2025  
     Gross
Amount
Recognized
in the
Statement
of Financial
Position
1
     Gross
Amounts
Offset in the
Statement of
Financial
Position
     Net of
Amounts
Presented in
the
Statement
of Financial
Position
     Gross Amounts Not Offset
in the Statement of
Financial Position
       
(Dollars in Thousands)    Commodity
Contracts
    Cash
Collateral
Received/
Posted
    Net
Amount
 
Assets:
               
Energy derivative contracts
   $ 48,709      $  —       $ 48,709      $ (44,271 )    $ —      $ 4,438  
Liabilities:
               
Energy derivative contracts
   $ 573,421      $ —       $ 573,421      $ (44,271 )    $ (54,521 )    $ 474,629  
 
1
All derivative contract deals are executed under ISDA, NAESB, and WSPP master agreements with right of
set-off.
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 March 31, 2026, approximately 99.3% of the Company’s energy portfolio exposure, is with counterparties that are rated investment grade by rating agencies and 0.7% is 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 the unrealized gain (loss) positions. 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 natural gas exchange (NGX) platform. Execution of contracts on ICE requires the daily posting of margin calls as collateral through a
 
F-85

futures and clearing agent. As of March 31, 2026, PSE had cash posted as collateral of $64.5 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 March 31, 2026, PSE had no cash posted with ICE NGX, and $8.0 million was issued under the standby letter of credit agreement in support of natural gas and carbon allowance purchases. PSE did not trigger any collateral requirements with any of its counterparties nor were any of PSE’s counterparties required to post collateral resulting from credit rating downgrades during the three months ended March 31, 2026.
The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post:
 

Puget Energy and
Puget Sound Energy
  
 
 
(Dollars in Thousands)
  
At March 31, 2026
 
  
At December 31, 2025
 
Contingent Feature
  
Fair Value
1

Liability
 
  
Posted
Collateral
 
  
Contingent
Collateral
 
  
Fair Value
1

Liability
 
  
Posted
Collateral
 
  
Contingent
Collateral
 
Credit rating
2
   $ 269,769      $ —       $ 269,769      $ 253,105      $ —       $ 253,105  
Requested credit for adequate assurance
     17,811        —         —         21,927        —         —   
Forward value of contract
3
     49,068        64,498        N/A        54,521        77,969        N/A  
  
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
 
Total
   $ 336,648      $ 64,498      $ 269,769      $ 329,553      $ 77,969      $ 253,105  
  
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
 
 
1
 
Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes 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.
 
 
(5)
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
 
F-86

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. 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. The Company’s environmental compliance obligation is categorized in Level 2 of the fair value hierarchy and is measured at fair value using a market approach based on quoted prices from an independent pricing service.
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. Investments in life insurance contracts of $44.9 million and $44.8 million at March 31, 2026 and December 31, 2025, respectively, are included in “Other property and investments” on the balance sheet. These investments are carried at cash surrender values, which represent the amount of cash that could be realized under the contracts.
The fair value of the long-term notes was estimated using the discounted cash flow method with the U.S. Treasury yields and the Company’s credit spreads as inputs, interpolating to the maturity date of each issue. The carrying values and estimated fair values were as follows:
 
Puget Energy
          March 31, 2026      December 31, 2025  
(Dollars in Thousands)    Level      Carrying
Value
     Fair
Value
     Carrying
Value
     Fair
Value
 
Liabilities:
              
Long-term debt (fixed-rate), net of discount
1
     2      $ 9,419,345      $ 9,101,774      $ 8,525,032      $ 8,199,785  
Puget Sound Energy
                                  
(Dollars in Thousands)          
 
 
                      
Liabilities:
              
Long-term debt (fixed-rate), net of discount
2
     2      $ 6,458,377      $ 6,005,816      $ 6,457,684      $ 6,054,647  
     
 
 
    
 
 
    
 
 
    
 
 
 
 
1
 
The carrying value includes debt issuances costs of $22.7 million and $23.2 million for March 31, 2026 and December 31, 2025, respectively, which are not included in fair value.
2
 
The carrying value includes debt issuances costs of $21.8 million and $22.2 million for March 31, 2026 and December 31, 2025, respectively, which are not included in fair value.
 
F-87

Assets and Liabilities Measured at Fair Value on a Recurring Basis
The following table presents 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:
 
Puget Energy and
Puget Sound Energy
   Fair Value
At March 31, 2026
     Fair Value
At December 31, 2025
 
(Dollars in Thousands)    Level 2      Level 3      Total      Level 2      Level 3      Total  
Assets:
                 
Electric derivative instruments
   $ 42,571      $ 4,162      $ 46,733      $ 38,930      $ 3,044      $ 41,974  
Natural gas derivative instruments
     3,032        3,544        6,576        2,262        4,473        6,735  
  
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
 
Total assets
   $ 45,603      $ 7,706      $ 53,309      $ 41,192      $ 7,517      $ 48,709  
  
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
 
Liabilities:
                 
Electric derivative instruments
   $ 275,371      $ 231,461      $ 506,832      $ 281,007      $ 212,327      $ 493,334  
Natural gas derivative instruments
     73,574        1,097        74,671        78,945        1,142        80,087  
Compliance obligations
     140,105        —         140,105        96,490        —         96,490  
  
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
 
Total liabilities
   $ 489,050      $ 232,558      $ 721,608      $ 456,442      $ 213,469      $ 669,911  
  
 
 
    
 
 
    
 
 
    
 
 
    
 
 
    
 
 
 
The following tables present the Company’s reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy:
 
Puget Energy and
Puget Sound Energy
   Three Months Ended March 31,  
(Dollars in Thousands)    2026     2025  
Level 3 Roll-Forward Net Asset/(Liability)    Electric     Natural
Gas
    Total     Electric     Natural
Gas
    Total  
Balance at beginning of period
   $ (209,283 )    $ 3,330     $ (205,953 )    $ (175,110 )    $ 1,391     $ (173,719 ) 
Changes during period:
            
Realized and unrealized energy derivatives:
            
Included in regulatory assets / liabilities
     (53,704 )      615       (53,089 )      (58,485 )      617       (57,868 ) 
Settlements
     35,688       (1,498 )      34,190       29,877       (423 )      29,454  
Transferred into Level 3
     —        —        —        —        —        —   
Transferred out of Level 3
     —        —        —        —        —        —   
  
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
Balance at end of period
   $ (227,299 )    $ 2,447     $ (224,852 )    $ (203,718 )    $ 1,585     $ (202,133 ) 
  
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company’s consolidated statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled. Unrealized gains and losses on energy derivatives for Level 3 recurring items are deferred as regulatory assets or liabilities on the Company’s consolidated balance sheet.
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. The weighted average price is calculated as the total market value divided by the total volume of the Company’s Level 3 electric and natural gas commodity contracts, respectively, as of the reporting date.
 
F-88

The following table presents the forward price ranges for the Company’s Level 3 commodity contracts as of March 31, 2026:
 
Puget Energy and
Puget Sound Energy
   Fair Value             Range         
(Dollars in Thousands)    Assets
1
     Liabilities
1
     Valuation
Technique
     Unobservable
Input
     Low      High      Weighted
Average
 
Electric
   $ 4,162      $ 231,461       
Discounted
cash flow
 
 
    
Power prices
(per MWh)
 
 
   $ 10.59      $ 113.26      $ 52.26  
Natural gas
   $ 3,544      $ 1,097       
Discounted
cash flow
 
 
    

Natural gas
prices
(per MMBtu)
 

 
   $ 1.92      $ 4.61      $ 2.44  
 
1
 
The valuation techniques and unobservable inputs are the same for asset and liability positions.
The following table presents the forward price ranges for the Company’s Level 3 commodity contracts as of December 31, 2025:
 
Puget Energy and
Puget Sound Energy
   Fair Value             Range         
(Dollars in Thousands)    Assets
1
     Liabilities
1
     Valuation
Technique
     Unobservable
Input
     Low      High      Weighted
Average
 
Electric
   $ 3,044      $ 212,327       
Discounted
cash flow
 
 
    
Power prices
(per MWh)
 
 
   $ 18.40      $ 126.87      $
57.64
 
Natural gas
   $ 4,473      $ 1,142       
Discounted
cash flow
 
 
    

Natural gas
prices (per
MMBtu)
 
 
 
   $ 1.53      $ 4.46      $ 2.30  
 
1
 
The valuation techniques and unobservable inputs 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. As of March 31, 2026 and December 31, 2025, 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 $41.5 million and $48.1 million, respectively.
 
 
(6)
Retirement Benefits
The following tables summarize the Company’s net periodic benefit cost for the three months ended March 31, 2026 and 2025:
 
Puget Energy
   Qualified
Pension Benefits
    SERP
Pension Benefits
    Other
Benefits
 
     Three Months Ended March 31,  
(Dollars in Thousands)    2026     2025     2026     2025     2026     2025  
Components of net periodic benefit cost:
            
Service cost
   $ 4,419     $ 4,206     $  —      $ —      $ 44     $ 51  
Interest cost
     8,023       8,054       280       306       102       108  
Expected return on plan assets
     (14,314 )      (14,061 )      —        —        (73 )      (73 ) 
Amortization of prior service cost
     —        —        —        —        9       9  
Amortization of net loss (gain)
     (608 )      (1,196 )      (42 )      (50 )      (59 )      (46 ) 
  
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
Net periodic benefit cost
   $ (2,480 )    $ (2,997 )    $ 238     $ 256     $ 23     $ 49  
  
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
 
F-89

Puget Sound Energy
   Qualified
Pension Benefits
    SERP
Pension Benefits
    Other
Benefits
 
     Three Months Ended March 31,  
(Dollars in Thousands)    2026     2025     2026     2025     2026     2025  
Components of net periodic benefit cost:
            
Service cost
   $ 4,419     $ 4,206     $ —      $ —      $ 44     $ 51  
Interest cost
     8,024       8,054       279       306       102       108  
Expected return on plan assets
     (14,314 )      (14,061 )      —        —        (73 )      (73 ) 
Amortization of prior service cost
     —        —        —        —        9       9  
Amortization of net loss (gain)
     —        —        (37 )      (45 )      (60 )      (47 ) 
  
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
Net periodic benefit cost
   $ (1,871 )    $ (1,801 )    $ 242     $ 261     $ 22     $ 48  
  
 
 
   
 
 
   
 
 
   
 
 
   
 
 
   
 
 
 
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, 2026, are expected to be at least $18.0 million, $3.4 million and $0.2 million, respectively. The Company contributed $1.2 million and $2.3 million to fund the SERP during each of the three months ended March 31, 2026 and March 31, 2025, respectively. In addition, the Company contributed an immaterial amount to fund the other post-retirement plans.
For further information, see Note 12, “Retirement Benefits” to the audited consolidated financial statements included in this prospectus.
 
 
(7)
Regulation and Rates
General Rate Case
On February 27, 2026, PSE filed a GRC with the Washington Commission in Docket No.
UE-260005
and Docket No.
UG-260006.
The filing included a three-year MYRP requesting an overall increase in electric and natural gas rates of 15.2% and 14.2% respectively in rate year one (expected to approximate calendar year 2027), 3.7% and 3.2%, respectively in rate year two (expected to approximate calendar year 2028) and 8.7% and 3.6% in rate year three (expected to approximate calendar year 2029). PSE requested a return on equity of 10.8% for all three rate years beginning in 2027 and requested an overall rate of return of 8.1% in rate year one and 8.2% in both rate years two and three.
PSE filed a GRC which includes a
two-year
MYRP with the Washington Commission on February 15, 2024. On January 15, 2025, the Washington Commission issued an order on PSE’s 2024 GRC, in Docket Nos.
UE-240004
and
UG-240005,
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.
Liquefied Natural Gas Rate Adjustment
On April 24, 2024, the Washington Commission issued Final Order 07 in Docket No.
UG-230393,
which determined that PSE acted prudently in developing and constructing the Tacoma LNG Facility and included two primary outcomes. 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. 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 were consolidated. The parties agreed to seek direct review of the case by the
 
F-90

Washington State Court of Appeals. The case was transferred to Division III of the Court of Appeals in March 2025. Petitioners, Public Counsel and the Puyallup Tribe of Indians filed opening briefs on July 11, 2025. Respondents, PSE and the Washington Commission filed briefs on September 10, 2025. Petitioners’ reply briefs were filed on October 10, 2025. A hearing date has not yet been set.
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%. On December 19, 2024, the Washington Commission issued Order 01, requiring PSE to file revised tariff pages, with rates effective January 1, 2025, subject to refund pending final determination. The Washington Commission set the matter for adjudication, with a hearing held on September 3, 2025. On December 19, 2025, the Washington Commission concluded that an adjustment to the provisionally approved rate was necessary, decreasing annual revenues by $6.9 million or 0.2% effective January 1, 2026.
On September 30, 2025, PSE filed proposed revisions to rates under the Colstrip Adjustment Rider Schedule 141COL with the Washington Commission in Docket No. 250733 for Colstrip Units 3 and 4 for calendar year 2026. The proposed revisions would decrease PSE’s annual revenues by $82.5 million, or 2.3%, including the $6.9 million mentioned above, due to an expected decrease from the removal of Colstrip plant and reduction of operating costs. The revised tariff filed went into effect on January 1, 2026 by operation of law.
Climate Commitment Act Deferral
Electric
On May 2, 2025, PSE filed a revision to its electric tariff in Docket No.
UE-250321,
which proposed the establishment of Schedule 111 for electric to allow PSE to recover the costs associated with its electric compliance obligation. PSE’s proposal covered the recovery of its electric compliance costs incurred from January 2023 through December 2025 with a recovery period set for the period of August 1, 2025 through December 2026. On July 24, 2025, the Washington Commission approved the recovery of PSE’s estimated 2023 and 2024 compliance costs and a
pro-rata
portion of the 2025 estimated compliance costs in Schedule 111 for electric. In Docket
UE-250901,
the Washington Commission approved the recovery of the remaining forecasted 2025 allowance obligation and a
true-up
to known compliance costs for 2023 and 2024, effective January 1, 2026.
Order 01 within Docket No.
UE-250321
also required PSE to file a proposal for recovery of 2026 CCA costs, which was made in that same docket on October 1, 2025. On December 24, 2025, the Washington Commission issued Order 01 in Docket No.
UE-250747,
which approved the total cost of electric CCA compliance will be recovered through PSE’s power cost mechanism. Additionally, to the extent PSE uses no cost allowances granted by the WDOE for compliance, the benefit of this will be passed back to customers through the electric Schedule 111 as approved in Docket No.
UE-250901.
When combined with the adjustment to Schedule 111, noted above, for the recovery of compliance costs, the annual net rate decrease beginning January 1, 2026, is $259.0 million or 7.2%.
As of March 31, 2026, PSE recorded a regulatory asset of $52.5 million, which represents the expense incurred for the purchase of allowances for the GHG emissions associated with the Company’s electric business activities for 2023 through 2025, net of amounts to date collected in customer electric rates for CCA obligation costs. Further, PSE recorded a regulatory asset of $61.2 million, which represents the value of no cost allowances passed back to customers that exceeded PSE’s actual usage of no cost allowances in 2026.
 
F-91

Natural Gas
The ongoing recovery of allowance costs and pass back of proceeds from the sale of consigned
no-cost
allowances associated with PSE’s natural gas business activities is consistent with the approved accounting petitions in Docket Nos.
UG-220975
and
UG-230471.
As of March 31, 2026, PSE recorded a regulatory liability of $15.1 million, which represents the amounts to date over-collected in customer natural gas rates for CCA obligation costs, net of the expense incurred for the purchase of allowances for GHG emissions associated with the Company’s natural gas business activities. Additionally, PSE will continue to consign for auction at least the minimum amount of
no-cost
emission allowances allocated for natural gas business activities 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 March 31, 2026, PSE recorded a regulatory liability of $49.0 million, which represents the proceeds received from the sale of consigned allowances sold at auction net of proceeds from the sale of consigned natural gas GHG emission allowances passed back through customer rates or used on approved decarbonization projects.
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.
The following graduated scale used in the PCA mechanism resulted in the following Company and customer shares:
 
Puget Energy and
Puget Sound Energy
   At March 31, 2026  
(Dollars in Thousands)    Company’s Share     Customers’ Share      Total  
Annual Power Cost Variability    Over     Under     Amount     Over     Under     Amount  
(Over) and under collected up to $17 million
     100 %      100 %    $ (7,637 )      —  %      —  %    $  —       $ (7,637 ) 
(Over) and under collected between $17 - $40 million
     35       50       —        65       50       —         —   
(Over) or under collected beyond $40 million
     10       10       —        90       90       —         —   
Interest
         —            53        53  
      
 
 
       
 
 
    
 
 
 
Total (over) / under recovery
       $ (7,637 )        $ 53      $ (7,584 ) 
      
 
 
       
 
 
    
 
 
 
 
Puget Energy and
Puget Sound Energy
   At March 31, 2025  
(Dollars in Thousands)    Company’s Share      Customers’ Share      Total  
Annual Power Cost Variability    Over     Under     Amount      Over     Under     Amount  
(Over) and under collected up to $17 million
     100 %      100 %    $ 17,000        —  %      — %    $ —       $ 17,000  
(Over) and under collected between $17 - $40 million
     35       50       11,500        65       50       11,500        23,000  
(Over) or under collected beyond $40 million
     10       10       3,118        90       90       28,063        31,181  
Interest
         —             247        247  
      
 
 
        
 
 
    
 
 
 
Total (over) / under recovery
       $ 31,618          $ 39,810      $ 71,428  
      
 
 
        
 
 
    
 
 
 
 
F-92

On April 30, 2026, PSE filed the 2025 PCA compliance report in Docket No.
UE-260337.
The actual 2025 PCA imbalance including interest was $155.6 million. In the 2024 PCA Compliance Docket No.
UE-250318,
PSE was allowed to collect on an estimated 2025 imbalance of $97.7 million, which was set in rates from October 1, 2025, to December 31, 2026. PSE has collected $42.0 million and forecasts to collect an additional $56.1 million from April 2026 through December 31, 2026. Accordingly, PSE requested to recover the revised remaining 2025 imbalance of $59.5 million over 12 months starting on January 1, 2027.
PSE filed a tariff requesting an update to the PCA mechanism in 2026 within Docket No.
UE-250747,
which was filed concurrently with the proposed tariff revision for Schedule 111, in Docket No.
UE-250901,
discussed above. The former revision requested an increase of $748.4 million or 20.8% and incorporated updated market prices for natural gas and CCA emissions allowances, along with corrected forced outage rates for PSE’s natural
gas-fired
generators. The Washington Commission approved PSE’s tariff revisions filed, effective January 1, 2026, subject to condition that these tariff revisions will be subject to review and revision in PSE’s next GRC and will not be effective until the conclusion of that case or February 28, 2027, whichever occurs first.
On July 8, 2025, PSE filed a tariff revision in Docket No.
UE-250537
requesting that the Washington Commission eliminate the deadband and sharing bands in the PCA mechanism. On February 23, 2026, the Washington Commission dismissed PSE’s filing and determined that PSE’s request would contradict the power cost review process of the
two-year
rate plan approved in 2025. On February 27, 2026, PSE integrated its request into its GRC filing in Docket No.
UE-260005
for the three-year rate plan beginning in 2027.
Purchased Gas Adjustment Mechanism
On October 23, 2025, the Washington Commission approved PSE’s request for PGA rates in Docket No.
UG-250704,
effective November 1, 2025. As part of that filing, PSE requested an annual overall revenue decrease of $55.1 million, where PGA rates, under Schedule 101, decrease annual revenue by $7.9 million and the tracker rates, under Schedule 106, decrease annual revenue by $47.2 million.
The following table presents the PGA mechanism balances and activity at March 31, 2026 and December 31, 2025:
 
Puget Energy and
Puget Sound Energy
      
(Dollars in Thousands)    At March 31,
2026
     At December 31,
2025
 
PGA (liability)/receivable beginning balance
   $ (65,931)      $ (58,657)  
Actual natural gas costs
     151,480        397,465  
Allowed PGA recovery
     (140,588)        (399,347)  
Interest
     (831)        (5,392)  
  
 
 
    
 
 
 
PGA (liability)/receivable ending balance
   $ (55,870)      $ (65,931)  
  
 
 
    
 
 
 
For further information, such as prior rate filings and accounting petitions, see Note 4, “Regulation and Rates” to the audited consolidated financial statements included in this prospectus.
 
 
(8)
Commitments and Contingencies
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.
 
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The WDOE has provided an initial allocation of
no-cost
allowances to electric utilities, including PSE, for operations through 2026. However, qualifying electric utilities have been allowed to submit revised emissions forecasts approved by the Washington Commission to WDOE. PSE has filed revised forecasts for emissions associated with its 2023, 2025 and 2026 operations, all of which were approved by the Washington Commission. The WDOE approved the revised 2023 forecast and made modest adjustments to the 2026 revised forecast. PSE understands that WDOE will consider changes or adjustments to the 2025 forecast in October 2026, after WDOE has received verified actual emissions for electric operations for calendar year 2025 actual emissions. To the extent WDOE were to determine that an adjustment to the allocation of
no-cost
allowances for PSE electric operations for calendar year 2025 were appropriate or necessary, PSE understands that such adjustment would occur in the form of an increase or decrease to the allocation of
no-cost
allowances for PSE electric operations for calendar year 2027.
Given the potential for future rulemakings and the WDOE’s ability to adjust
no-cost
allowances for electric operations during the compliance period or make changes to rules governing the program, there is estimation uncertainty surrounding the Company’s ability to estimate its compliance obligation for electric operations both on an annual basis and a four-year compliance period, prior to a final WDOE determination. The WDOE has indicated there will be future rulemakings impacting the compliance obligation, including the
true-up
mechanism, which could impact periods within the first compliance period: thus, PSE has recorded its compliance obligation based on its best estimate and is unable to determine a range of possible outcomes at this time.
As uncertainties are resolved in future periods, the Company does not anticipate material impacts to its reported earnings due to the cost-recovery mechanisms that exist. For further information, see Note 4, “Regulation and Rates” to the audited consolidated financial statements included in this prospectus.
Other Commitments and Contingencies
In addition to the contractual obligations and consolidated commercial commitments disclosed in the Company’s Annual Report on Form
10-K
for the year ended December 31, 2025, during the three months ended March 31, 2026, the Company entered into new Electric Portfolio contracts with estimated payment obligations totaling $94.2 
million through 2027. On May 7, 2026, the Company entered into a PPA, which increases the Company’s total estimated payment obligation by approximately
 $165.9 million through 2028.
On July 22, 2025, the Company executed two agreements with the same counterparty that would provide the Company with the output of a 400 MW solar PV energy project and the capacity of a 200 MW battery energy storage system, both over a
25-year
term. The total estimated payment obligation during the term of the agreements is approximately $2.1 billion. The agreements contain certain provisions that would allow the counterparty to terminate the agreements before August 31, 2026 for a nominal fee.
For further information regarding the Company’s commitments and contingencies, see Note 15, “Commitments and Contingencies” to the audited consolidated financial statements included in this prospectus.
 
 
(9)
Leases
PSE has operating leases for buildings, real estate for operating facilities and the Puget LNG facility, land, and vehicles. Finance leases primarily represent buildings and equipment. PSE also has certain power purchase agreements that qualify as leases. The leases have remaining lease terms of less than a year to 43 years. PSE’s ROU assets and lease liabilities include options to extend leases when it is reasonably certain that PSE will exercise that option.
 
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Supplemental balance sheet information related to leases was as follows:
 
Puget Energy and
Puget Sound Energy
      
(Dollars in Thousands)    At March 31,
2026
     At December 31,
2025
 
Operating Leases
     
Operating lease
right-of-use
assets - other
   $ 244,704      $ 244,055  
Operating lease
right-of-use
assets - purchased power
     196,573        216,935  
  
 
 
    
 
 
 
Total operating lease
right-of-use
assets
   $ 441,277      $ 460,990  
  
 
 
    
 
 
 
Operating lease liabilities - other, current
   $ 22,029      $ 21,830  
Operating lease liabilities - purchased power, current
     83,483        82,410  
Operating lease liabilities - other, long-term
     230,298        230,686  
Operating lease liabilities - purchased power, long-term
     112,906        134,673  
  
 
 
    
 
 
 
Total operating lease liabilities:
   $ 448,716      $ 469,599  
  
 
 
    
 
 
 
Finance Leases
     
Common plant
   $ 122,558      $ 124,343  
Natural gas plant
     164        209  
Electric plant
     34,369        34,924  
  
 
 
    
 
 
 
Total finance lease assets
   $ 157,091      $ 159,476  
  
 
 
    
 
 
 
Other current liabilities
   $ 5,654      $ 5,586  
Finance lease liabilities
     166,059        167,426  
  
 
 
    
 
 
 
Total finance lease liabilities
   $ 171,713      $ 173,012  
  
 
 
    
 
 
 
 
 
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Other
Long-Term Debt
On March 27, 2026, Puget Energy issued $450.0 million aggregate principal amount of 7.000%
Fixed-to-Fixed
Reset Rate Junior Subordinated Notes due 2056, Series A (the “Series A Notes”) and $450.0 million aggregate principal amount of 7.250%
Fixed-to-Fixed
Reset Rate Junior Subordinated Notes due 2056, Series B (the “Series B Notes” and together with the Series A Notes, the “Notes”) pursuant to a Junior Subordinated Indenture, dated as of March 27, 2026 (the “Base Indenture”), as supplemented by the First Supplemental Indenture dated as of March 27, 2026 (together with the Base Indenture, the “Junior Subordinated Indenture”). Interest on the Notes accrues from March 27, 2026 and is payable semi-annually in arrears on March 15 and September 15 of each year, beginning on September 15, 2026. The Notes mature on September 15, 2056. The Series A Notes bear interest (i) from and including March 27, 2026 to, but excluding, September 15, 2031 at an annual rate of 7.000% and (ii) from and including September 15, 2031, during each Series A Interest Reset Period (as defined in the Junior Subordinated Indenture) at an annual rate equal to the average of the yields on actively traded United States Treasury securities adjusted to constant maturity, for five-year maturities, for the most recent five business days as of the most recent determination date (the “Five-Year Treasury Rate”), plus 2.961%; provided, that the interest rate during any Series A Interest Reset Period will not reset below 7.000% (which equals the initial interest rate on the Series A Notes). The Series B Notes bear interest (i) from and including March 27, 2026 to, but excluding, September 15, 2036 at an annual rate of 7.250% and (ii) from and including September 15, 2036, during each Series B Interest Reset Period (as defined in the Junior Subordinated Indenture) at an annual rate equal to the Five-Year Treasury Rate as of the most recent determination date, plus 2.848%; provided, that the interest rate during any Series B Interest Reset Period will not reset below 7.250%
 
F-95

(which equals the initial interest rate on the Series B Notes). So long as no Event of Default (as defined in the Junior Subordinated Indenture) with respect to the Notes has occurred and is continuing, Puget Energy may, at its option, defer interest payments on the Notes on one or more occasions for up to 10 consecutive years. In the event that Puget Energy were to exercise such right to defer interest on the Notes, Puget Energy would not be able to pay cash dividends during the periods in which such payments were deferred. Proceeds from the issuance of the Notes were used to pay down the outstanding balance on the Puget Energy senior secured credit facility and for general corporate purposes.
The Notes are Puget Energy’s unsecured junior subordinated obligations and rank junior in right of payment to all of Puget Energy’s Senior Indebtedness (as defined in the Junior Subordinated Indenture). The Notes rank equally in right of payment with all of Puget Energy’s existing and future junior indebtedness.
Liquidity Facilities and Other Financing Arrangements
As of March 31, 2026, no amount was drawn and outstanding under Puget Energy’s credit facility.
As of March 31, 2026, there was $140.0 million outstanding under the commercial paper program at PSE and no amount was drawn under PSE’s credit facility. 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 $300.0 million as a condition of transacting on the ICE NGX platform as well as participating in the Washington state carbon allowance auctions. As of March 31, 2026, $8.0 million was issued under the standby letter of credit with TD Bank in support of natural gas purchases and carbon allowance purchases. Additionally, PSE posted cash collateral of $64.5 million to Intercontinental Exchange for purchased power trading. Additionally, PSE secured rights to $70.4 million of GHG emission allowances under the CCA, which did not clear until April 1, 2026 and thus was included in restricted cash. In support of purchase power contracts, PSE posted no cash collateral and maintained two standby letters of credit in the amounts of $60.0 million and $11.9 million. In support of a funding participant contract, PSE has a $13.4 million standby letter of credit.
For further information on the Company’s long-term and short-term debt, credit facilities and other financing arrangements, see Note 7, “Long-Term Debt” and Note 8, “Liquidity Facilities and Other Financing Arrangements” to the audited consolidated financial statements included in this prospectus.
Utility Plant
Beaver Creek 2
On March 30, 2026, PSE entered into a turbine supply agreement with GE Renewables North America, LLC to purchase 21 wind turbine generators for a total of $80.1 million. The wind turbine generators are expected to be delivered in 2028.
Battle Butte Solar Project
On November 14, 2025, PSE executed a membership interest purchase agreement to acquire development rights for a utility-scale solar project located in Stillwater County, Montana. On February 20, 2026, PSE entered into a purchase agreement for photovoltaic modules with an aggregate capacity of 178 MW direct current for this project. The total commitment under the module purchase agreement is approximately $60.0 million. As of March 31, 2026, an immaterial amount was recorded in Utility plant—Electric plant, including CWIP, related to this project.
Beaver Creek Wind Project
Beaver Creek is a utility-scale wind project located in Stillwater County, Montana, with nameplate capacity of 248 MW that commenced commercial operations in August 2025. As of March 31, 2026, a $183.5 million net ITC was recorded with a corresponding accumulated deferred ITC to the “Unamortized investment tax credit” financial statement line item, which will be passed back to customers over the life of the project.
 
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On April 15, 2026 and April 16, 2026, PSE transferred the remaining portion of its ITC from the Beaver Creek wind project for net proceeds of $51.7 million and $46.3 million, respectively. PSE does not anticipate any additional tax credit transfers in 2026.
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 2027. 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 March 31, 2026 and the remaining balance is expected to be paid during the remainder of 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 March 31, 2026, $110.4 million was recorded in Utility plant - Electric plant, including CWIP, related to this project.
Colstrip
Effective January 1, 2026, PSE transferred its 25% interest in Colstrip Units 3 and 4 to NorthWestern Energy. Consistent with the 2019 GRC, PSE accelerated the depreciation of Colstrip Units 3 and 4 to December 31, 2025. Additional costs not covered through repurposed PTCs and hydro-related treasury grants as directed in the 2017 GRC are being recovered through a separate Colstrip tariff as part of the 2022 GRC. On January 1, 2026, PSE applied abandonment accounting specific to Colstrip Units 3 and 4 assets that existed as of December 31, 2025, which were not material.
Separately, PSE maintains a 50% ownership interest in the retired Colstrip Units 1 and 2, which have been shut down and out of service since December 31, 2019.
For further information on the Company’s utility plant, including resource acquisition projects, see Note 6, “Utility Plant” to the audited consolidated financial statements included in this prospectus.
 
 
(11)
Segment Information
Puget Energy operates one reportable segment, PSE, referred to as the regulated utility segment. 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” above. 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.
 
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The following tables present financial information about the regulated utility segment and reconciliation to Puget Energy consolidated financial statements:
 
Puget Energy
   Three Months Ended March 31, 2026  
(Dollars in Thousands)    Regulated
Utility
     Other      Total  
Revenue
   $ 1,840,518      $ 7,739      $ 1,848,257  
Depreciation and amortization
     210,688        1,675        212,363  
Income tax (benefit) expense
     37,853        (12,124 )       25,729  
Non-utility
expense and other
     5,626        7,127        12,753  
Interest expense
     90,884        32,383        123,267  
Net income
     246,438        (23,606 )       222,832  
Total assets
     19,141,327        2,417,384        21,558,711  
Construction expenditures
     (412,198 )       (16 )       (412,214 ) 
 
Puget Energy
   Three Months Ended March 31, 2025  
(Dollars in Thousands)    Regulated
Utility
     Other      Total  
Revenue
   $ 1,593,020      $ 8,983      $ 1,602,003  
Depreciation and amortization
     208,693        1,683        210,376  
Income tax (benefit) expense
     27,815        (7,317 )       20,498  
Non-utility
expense and other
     8,775        6,552        15,327  
Interest expense
     84,920        27,742        112,662  
Net income
     186,014        (18,458 )       167,556  
Total assets
     17,382,024        2,330,456        19,712,480  
Construction expenditures
     (353,435 )       (147 )       (353,582 ) 
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 $0.7 million and $1.0 million for the three months ended March 31, 2026 and 2025, respectively. These revenues are eliminated in Puget Energy’s Consolidated Statements of Income. Puget LNG is charged tariff rates that are approved by the Washington Commission.
 
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Table of Contents
 
 

 

LOGO

Puget Energy, Inc.

Offers to exchange

the exchange notes set forth below

registered under the Securities Act of 1933, as amended

for any and all of its corresponding outstanding original notes

that were issued and sold in a transaction exempt from registration

under the Securities Act of 1933, as amended

 

Exchange Notes

 

Original Notes

$450,000,000 7.000% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2056, Series A (CUSIP No. 745310 AS1)   $450,000,000 7.000% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2056, Series A (CUSIP Nos. 745310 AR3 and U74592 AH6)
$450,000,000 7.250% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2056, Series B (CUSIP No. 745310 AU6)   $450,000,000 7.250% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2056, Series B (CUSIP Nos. 745310 AT9 and U74592 AJ2)

 

 

PROSPECTUS

 

 

 

   , 2026

 

 
 


Table of Contents

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 20. Indemnification of Directors and Officers

Sections 23B.08.500 through 23B.08.603 of the Washington Business Corporation Act (the “WBCA”) authorize a court to award, or a corporation to grant, indemnification to directors and officers on terms sufficiently broad to permit indemnification under certain circumstances for liabilities arising under the Securities Act of 1933, as amended (the “Securities Act”). Article 8 of Puget Energy’s amended articles of incorporation and Article VII of Puget Energy’s Amended and Restated Bylaws, as amended by the First Amendment to the Amended and Restated Bylaws, dated January 6, 2022, provide for indemnification of Puget Energy’s directors and officers to the maximum extent permitted by Washington law, except for (i) acts or omissions of such person finally adjudged to be intentional misconduct or a knowing violation of law by the person, (ii) conduct finally adjudged to be in violation of Section 23B.08.310 of the WBCA, or (iii) any transaction with respect to which it was finally adjudged that the person received a benefit in money, property, or services to which such person was not legally entitled.

Section 23B.08.320 of the WBCA authorizes a corporation to eliminate or limit a director’s personal liability to the corporation or its shareholders for monetary damages for conduct as a director, except in certain circumstances involving intentional misconduct, knowing violations of law or illegal corporate loans or distributions, or any transaction from which the director personally receives a benefit in money, property or services to which the director is not legally entitled. Article 9 of Puget Energy’s amended articles of incorporation contains provisions implementing, to the fullest extent permitted by Washington law, such limitations on a director’s liability to Puget Energy and its shareholders.

Officers and directors of Puget Energy are covered by insurance (with certain exceptions and certain limitations) that indemnifies them against losses and liabilities arising from certain alleged “wrongful acts,” including alleged errors or misstatements, or certain other alleged wrongful acts or omissions constituting neglect or breach of duty.

Item 21. Exhibits and Financial Statement Schedules

(a) Exhibits

 

Exhibit

Number

  

Description

  3.1    Amended Articles of Incorporation of Puget Energy, Inc. (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 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).
  4.1    Indenture dated December 6, 2010 (incorporated herein by reference to Exhibit 4.1 to Puget Energy’s Current Report on Form 8-K, filed December 7, 2010, Commission File No. 1-16305).
  4.2    Fifth Supplemental Indenture dated May 19, 2020 relating to Puget Energy’s 4.100% 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).
  4.3    Sixth Supplemental Indenture dated June 14, 2021 relating to Puget Energy’s 2.379% Senior Secured Notes due 2028 (incorporated herein by reference to Exhibit 4.1 to Puget Energy’s Current Report on Form 8-K filed June 21, 2021, Commission File No. 1-16305).

 

II-1


Table of Contents

Exhibit

Number

  

Description

  4.4    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).
  4.5    Eighth Supplemental Indenture dated March 13, 2025 relating to Puget Energy’s 5.725% Senior Secured Notes due 2035 (incorporated herein by reference to Exhibit 4.1 to Puget Energy’s Current Report on Form 8-K filed March 13, 2025, Commission File No. 1-16305).
  4.6    Junior Subordinated Indenture dated as of March 27, 2026 between Puget Energy, Inc. and Computershare Trust Company, National Association, as Trustee (incorporated herein by reference to Exhibit 4.1 to Puget Energy’s Current Report on Form 8-K filed March 27, 2026, Commission File No. 1-16305).
  4.7    First Supplemental Indenture dated as of March 27, 2026 between Puget Energy, Inc. and Computershare Trust Company, National Association, as Trustee relating to Puget Energy’s Series A Notes and Series B Notes (incorporated herein by reference to Exhibit 4.2 to Puget Energy’s Current Report on Form 8-K filed March 27, 2026, Commission File No. 1-16305).
  4.8    Registration Rights Agreement, dated as of March 27, 2026, among Puget Energy, Inc., Barclays Capital Inc., J.P. Morgan Securities LLC, Mizuho Securities USA LLC, and Wells Fargo Securities, LLC, as representatives of the several initial purchasers party thereto (incorporated herein by reference to Exhibit 4.3 to Puget Energy’s Current Report on Form 8-K filed March 27, 2026, Commission File No. 1-16305).
  4.9*    Form of Puget Energy, Inc. Series A Exchange Note.
  4.10*    Form of Puget Energy, Inc. Series B Exchange Note.
  5.1*    Opinion of Perkins Coie LLP as to legality of the Exchange Notes issued by Puget Energy, Inc.
 10.1**    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 Annual Report on Form 10-K for the fiscal year ended December 31, 2015, Commission File No. 1-16305).
 10.2    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 herein 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).
 10.3    Amendment No. 1 to Second Amended and Restated Credit Agreement dated March 6, 2024 among Puget Energy Inc., as Borrower, JPMorgan Chase Bank N.A., as Administrative Agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.39 to Puget Energy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2025, Commission File No. 1-16305).
 10.4    Amendment No. 2 to Second Amended and Restated Credit Agreement, dated July 28, 2025, among Puget Energy Inc., as Borrower, JPMorgan Chase Bank N.A., as Administrative Agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.41 to Puget Energy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2025, Commission File No. 1-16305).
 21.1    List of Subsidiaries of Registrant (incorporated herein by reference to Exhibit 21.1 to Puget Energy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2025, Commission File No. 1-16305).
 22.1    Issuers of Guaranteed Securities and Affiliates Whose Securities Collateralize Securities of the Registrant (incorporated herein by reference to Exhibit 22.1 to Puget Energy’s Quarterly Report on Form 10-Q for the period ended March 31, 2026, Commission File No. 1-16305).

 

II-2


Table of Contents

Exhibit

Number

  

Description

 23.1*    Consent of Independent Registered Public Accounting Firm.
 23.2*    Consent of Perkins Coie LLP (included in Exhibit 5.1).
 24.1*    Power of Attorney (contained on the signature pages hereto).
 25.1*    Form T-1 Statement of Eligibility of Computershare Trust Company, National Association to act as Trustee under the Indenture relating to Puget Energy’s Series A Notes and Series B Notes.
 99.1*    Form Letter of Transmittal.
 99.2*    Form of Notice of Guaranteed Delivery.
 99.3*    Form of Letter to DTC Participants.
 99.4*    Form of Letter to Clients.
101.INS*    Inline XBRL Instance.
101.SCH*    Inline XBRL Taxonomy Extension Schema.
101.CAL*    Inline XBRL Taxonomy Extension Calculation.
101.DEF*    Inline XBRL Taxonomy Extension Definition.
101.LAB*    Inline XBRL Taxonomy Extension Label.
101.PRE*    Inline XBRL Taxonomy Extension Presentation.
107*    Filing Fee Table.

 

*

Filed herewith.

**

Management contract, compensatory plan or arrangement.

(b) Financial Statement Schedules.

See the Index to Financial Statements included on page F-1 for a list of the financial statements schedules included in this registration statement.

Item 22. Undertakings

The undersigned registrant hereby undertakes:

 

  (1)

To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

 

  (i)

to include any prospectus required by Section 10(a)(3) of the Securities Act;

 

  (ii)

to reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20 percent change in the maximum aggregate offering price set forth in the “Calculation of Filing Fee Tables” or “Calculation of Registration Fee” table, as applicable, in the effective registration statement; and

 

  (iii)

to include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

 

II-3


Table of Contents
  (2)

That, for the purpose of determining any liability under the Securities Act, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

  (3)

To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

 

  (4)

That, for the purpose of determining liability under the Securities Act to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

 

  (5)

That, for the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities, the undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

 

  (i)

Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

 

  (ii)

Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

 

  (iii)

The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

 

  (iv)

Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

 

  (6)

The undersigned registrant hereby undertakes that, for purposes of determining any liability under the Securities Act, each filing of the registrant’s annual report pursuant to Section 13(a) or 15(d) of the Exchange Act (and, where applicable, each filing of an employee benefit plan’s annual report pursuant to section 15(d) of the Exchange Act) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

  (7)

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrants pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

 

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  (8)

To respond to requests for information that is incorporated by reference into the prospectus pursuant to Item 4, 10(b), 11, or 13 of this Form, within one business day of receipt of such request, and to send the incorporated documents by first class mail or other equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request.

 

  (9)

To supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective.

 

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SIGNATURES

Pursuant to the requirements of the Securities Act, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Bellevue, State of Washington, on May 14, 2026.

 

PUGET ENERGY, INC.

By:   /s/ Jamie Martin

Name:

 

Jamie Martin

Title:

 

Senior Vice President and Chief Financial Officer

POWER OF ATTORNEY

Each person whose individual signature appears below hereby authorizes and appoints Mary E. Kipp, Jamie Martin, Stacy Smith, Cara Peterman, and Samuel Osborne, and each of them, with full power of substitution and resubstitution and full power to act without the other, as his or her true and lawful attorney-in-fact and agent to act in his or her name, place and stead and to execute in the name and on behalf of each person, individually and in each capacity stated below, and to file any and all amendments to this registration statement, including any and all post-effective amendments, or any registration statements to be filed in connection with this registration statement pursuant to Rule 462 under the Securities Act, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing, ratifying and confirming all that said attorneys-in-fact and agents or any of them or their or his or her substitute or substitutes may lawfully do or cause to be done by virtue thereof.

Pursuant to the requirements of the Securities Act, this registration statement has been signed by the following persons in the capacities indicated below on May 14, 2026.

 

Signature    Title

/s/ Mary E. Kipp

Mary E. Kipp

  

President, Chief Executive Officer and Director

(Principal Executive Officer)

/s/ Jamie Martin

Jamie Martin

  

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

/s/ Stacy Smith

Stacy Smith

  

Controller and Principal Accounting Officer

(Principal Accounting Officer)

/s/ Jerry Divoky

Jerry Divoky

  

Director

/s/ Adam Friedrichsen

Adam Friedrichsen

  

Director

/s/ Christine Gregoire

Christine Gregoire

  

Director

 

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Signature    Title

/s/ Julia Hamm

Julia Hamm

  

Director

/s/ Grant Hodgkins

Grant Hodgkins

  

Director

/s/ Tom King

Tom King

  

Director

/s/ Paul McMillan

Paul McMillan

  

Director

/s/ Chris Parker

Chris Parker

  

Director

/s/ Aaron Rubin

Aaron Rubin

  

Director

/s/ Bertrand A. Valdman

Bertrand A. Valdman

  

Director

/s/ Steven Zucchet

Steven Zucchet

  

Director

 

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