Puget Energy Inc.
11/06/2025 | Press release | Distributed by Public on 11/06/2025 05:03
Quarterly Report for Quarter Ending 09/30/25 (Form 10-Q)
Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis is intended to promote understanding of the results of operations and financial condition, is provided as a supplement to, and should be read in conjunction with the financial statements and related notes thereto included elsewhere in this report on Form 10-Q. This section generally discusses the results of operations and changes in financial condition for the period ended September 30, 2025 compared to 2024. For discussion related to the results of operations and changes in financial condition for the period ended September 30, 2024 compared to 2023 refer to Part I, Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operations in our period ended September 30, 2024, Form 10-Q, which was filed with the United States Securities and Exchange commission (SEC). The discussion contains forward-looking statements that involve risks and uncertainties, such as Puget Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE) objectives, expectations and intentions. Words or phrases such as "anticipates," "believes," "continues," "could," "estimates," "expects," "future," "intends," "may," "might," "plans," "potential," "predicts," "projects," "should," "will likely result," "will continue" and similar expressions are intended to identify certain of these forward-looking statements. However, these words are not the exclusive means of identifying such statements. In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward-looking statements. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. Puget Energy's and PSE's actual results could differ materially from results that may be anticipated by such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed in the section entitled "Forward-Looking Statements" included elsewhere in this report and in the section entitled "Risk Factors" included in Part I, Item 1A in Puget Energy's and PSE's Form 10-K for the period ended December 31, 2024. Except as required by law, neither Puget Energy nor PSE undertakes any obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. Readers are urged to carefully review and consider the various disclosures made in this report and in Puget Energy's and PSE's other reports filed with the SEC that attempt to advise interested parties of the risks and factors that may affect Puget Energy's and PSE's business, prospects and results of operations.
Overview
Puget Energy is an energy services holding company and substantially all of its operations are conducted through its wholly owned subsidiary PSE, a regulated electric and natural gas utility company. PSE is the largest electric and natural gas utility in the state of Washington, primarily engaged in the business of electric transmission, distribution and generation and natural gas distribution. Puget Energy's business strategy is to generate stable cash flows by offering reliable electric and natural gas service in a cost-effective manner through PSE. Puget Energy also has a wholly owned non-regulated subsidiary, Puget LNG, which has the sole purpose of owning and operating the non-regulated activity of the Tacoma liquefied natural gas (LNG) facility. Puget Holdings indirectly owns all of Puget Energy's common stock. Puget Holdings is owned by a consortium of long-term infrastructure investors including the British Columbia Investment Management Corporation (BCIMC), the Alberta Investment Management Corporation (AIMCo), the Ontario Municipal Employees Retirement System (OMERS), PGGM Vermogensbeheer B.V., Macquarie Washington Clean Energy Investment, L.P., and the Ontario Teachers' Pension Plan Board. Puget Energy and PSE are collectively referred to herein as "the Company."
PSE generates revenue and cash flow primarily from the sale of electric and natural gas services to residential and commercial customers within a service territory covering approximately 6,000 square miles, principally in the Puget Sound region of the state of Washington. PSE continually balances its load requirements, generation resources, purchase power agreements and market purchases to meet customer demand. The Company's external financing requirements principally reflect the cash needs of its construction program, its schedule of maturing debt and certain operational needs. PSE requires access to bank and capital markets to meet its financing needs.
Factors and Trends Affecting PSE's Performance
PSE's ongoing regulatory requirements and operational needs necessitate the investment of substantial capital in 2025 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;
•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 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, 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 2025 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.
In 2024, the Washington Governor signed the Washington Decarbonization Act for Large Combination Utilities, introduced as House Bill 1589, which requires PSE to file an integrated system plan that combines natural gas and electric planning into one process and include, among other objectives, planning scenarios that (i) achieve natural gas and electricity emissions reductions and costs associated therewith (including planning scenarios for a range of natural gas decarbonization and associated costs), (ii) achieve two percent of electric load annually with conservation and energy efficiency resources unless the Washington Commission finds that a higher target is cost effective or if it determines the requirement is neither technically nor commercially feasible, (iii) includes low-income electrification programs and (iv) include a 10-year clean energy action plan for implementing CETA at the lowest reasonable cost and at an acceptable resource adequacy standard. The law requires consolidation of multiple existing system plans into an integrated plan. Rulemaking at the Washington Commission has concluded and PSE will submit its first integrated system plan on April 1, 2027 to the Washington Commission. The law also clarifies the application of certain regulatory mechanisms for PSE, including a Certificate of Necessity and usage of CWIP. For additional information on PSE's GRC filings, see Note 7, "Regulation and Rates" in the Combined Notes to Consolidated Financial Statements included in Item 1 of this report.
On March 29, 2024, senate bill 5950 approved Washington State's operating budget, which included $150.0 million for public and private utilities to provide one-time bill rebates for low-and moderate-income residential electric customers. PSE received a total of $45.9 million in 2024 and provided rebates to low-and moderate-income residential electric customers.
Variable Power Cost Filing Update
PSE filed a variable power cost filing update with the Washington Commission on October 1, 2025 in Docket No. 250747, proposing to recover 2026 power costs and to comply with Washington Commission Order 01 in Docket UE-250321. The filing requests a revenue requirement increase of $736.0 million or 20.5%. The proposed tariff revisions have an effective date of January 1, 2026.
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, 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.
For further information, such as prior rate filings, see Part II, Item 8, Note 4, "Regulation and Rates" in the Company's Annual Report on Form 10-K for the year ended December 31, 2024.
Electric Rates
The following table sets forth electric rate adjustments and the expected annual impact of PSE's revenue approved by the Washington Commission since the electric rate adjustments included in the Company's Annual Report included on Form 10-K for the year ended December 31, 2024 and inclusive of filings through the 10-K filing date of February 21, 2025. For further information on the rate schedule descriptions and prior approved filings, see Part I, Item 1, Business, "Regulation and Rates"
and Part II, Item 7, "Regulation of PSE Rates and Recovery of PSE Costs" respectively, in the Company's Annual Report on Form 10-K for the year ended December 31, 2024.
| Electric | Schedule | Docket | Effective Date |
Average Percentage Increase (Decrease) in Rates |
Increase (Decrease) in Revenue (Dollars in Millions) |
||||||||||||
|
Conservation service rider
|
120 | 250123 | May 1, 2025 | 1.2% | $37.7 | ||||||||||||
|
Electric CCA supplemental
|
111E Supp1
|
250321 | August 1, 2025 | 1.9 | 86.2 | ||||||||||||
| Low income program | 129 | 250648 | October 1, 2025 | (0.6) | (21.7) | ||||||||||||
| 250200 | May 1, 2025 | 3.0 | 34.8 | ||||||||||||||
|
PCA supplemental
|
95 Supp2
|
250318 | October 1, 2025 | 2.2 | 78.5 | ||||||||||||
| Property tax tracker | 140 | 250207 | May 1, 2025 | 0.3 | 10.3 | ||||||||||||
|
Residential exchange benefit credit
|
194 | 250664 | October 1, 2025 | 0.5 | 10.6 | ||||||||||||
|
Revenue decoupling adjustment mechanism
|
142 | 250203 | May 1, 2025 | (0.2) | (5.5) | ||||||||||||
| Transportation electrification plan | 141TEP | 250197 | May 1, 2025 | 0.1 | 4.6 | ||||||||||||
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1 Represents a rate increase from August 1, 2025 through December 31, 2026.
2 Rate effective October 1, 2025 runs concurrent with current 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. .
Natural Gas Rates
The following table sets forth natural gas rate adjustments and the expected annual impact of PSE's revenue approved by the Washington Commission since the natural gas rate adjustments included in the Company's Annual Report included on Form 10-K for the year ended December 31, 2024 and inclusive of filings through the 10-K filing date of February 21, 2025. For further information on the rate schedule descriptions and prior approved filings, see Part I, Item 1, Business, "Regulation and Rates" and Part II, Item 7, "Regulation of PSE Rates and Recovery of PSE Costs", respectively, in the Company's Annual Report on Form 10-K for the year ended December 31, 2024.
|
Natural gas
|
Schedule | Docket | Effective Date |
Average Percentage Increase (Decrease) in Rates |
Increase (Decrease) in Revenue (Dollars in Millions) |
||||||||||||
| Conservation service rider | 120 | 250124 | May 1, 2025 | 0.5% | $5.7 | ||||||||||||
|
Liquified natural gas
|
141LNG
|
250744 | November 1, 2025 | 1.4 | 19.2 | ||||||||||||
| Low income program | 129 | 250649 | October 1, 2025 | (1.0) | (13.1) | ||||||||||||
| 250201 | May 1, 2025 | 3.1 | 7.8 | ||||||||||||||
| Property tax tracker | 140 | 250208 | May 1, 2025 | 0.4 | 4.7 | ||||||||||||
|
Purchased gas adjustment
|
101, 106
|
250704 | November 1, 2025 | (4.1) | (55.1) | ||||||||||||
| Revenue decoupling adjustment mechanism | 142 | 250204 | May 1, 2025 | 0.9 | 12.0 | ||||||||||||
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.
Regulatory Compliance Costs and Expenditures
PSE's operations are subject to extensive federal, state and local laws and regulations. These laws and regulations cover electric system reliability, natural gas pipeline system safety and energy market transparency, among other areas. Environmental laws and regulations related to air and water quality, climate change and endangered species protection, waste handling and disposal (including generation by-products such as coal ash), remediation of contaminated sites and the environmental impacts of siting new facilities also impact the Company's operations. PSE must spend significant resources to fulfill requirements set by regulatory agencies, many of which have greatly expanded mandates on measures including resource planning, remediation, monitoring, pollution control equipment and emissions-related abatement and fees.
In 2021, the Washington Legislature adopted the CCA, which establishes a GHG emissions cap-and-invest program that requires covered entities to purchase allowances to cover their GHG emissions with a cap on available allowances beginning on January 1, 2023 that declines annually through 2050. The WDOE published final regulations to implement the program on September 29, 2022, effective October 30, 2022. The WDOE also indicated that it will have subsequent rulemakings building off initial rulemaking while program implementation is underway and progress with Washington carbon goals are evaluated.
As of July 24, 2025, the Washington Commission has approved the recovery of both electric and natural gas CCA-related costs, which increases costs to electric and natural gas customers. Further, the Washington Commission indicated these revenues are subject-to-refund, and thus, there is a risk PSE may not be able to recover all costs. PSE faces continued risks associated with the CCA, including the evolving nature of the CCA rulemaking and related interpretation of the rules, unresolved recovery methodology for the CCA's impact on energy costs and risk sharing mechanisms, company costs, customer rate impacts, and cash, liquidity and credit volatility. For additional information, see Note 7, "Regulation and Rates" in the Combined Notes to Consolidated Financial Statements included in Item 1 of this report.
Compliance with these or other future regulations, such as those pertaining to climate change, could require significant capital expenditures by PSE and may adversely affect PSE's financial position, results of operations, cash flows and liquidity.
Other Challenges and Strategies
Competition
PSE's electric and natural gas utility retail customers generally do not have the ability to choose their electric or natural gas supplier; therefore, PSE's business has historically been recognized as a natural and regulated monopoly. However, PSE faces competition from public utility districts and municipalities or efforts by citizens organizing to form such entities that want to establish their own government-owned utility, as a result of which PSE may lose a number of customers. PSE'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 to meet their growing energy needs, which will largely be used to fulfill commitments for additional cloud computing, artificial intelligence data centers, reduced carbon emissions and increased reliance on renewable energy sources. The increasing competitive pressure may impact the Company's ability to acquire generation and transmission resources and/or increase the cost to acquire such resources.
Results of Operations
Puget Sound Energy
The following discussion should be read in conjunction with the unaudited consolidated financial statements and the related notes included elsewhere in this document and provides significant items that impacted PSE's results of operations for the three months and nine months ended September 30, 2025 and September 30, 2024.
Non-GAAP Financial Measures - Electric and Natural Gas Margins
Financial information is prepared in accordance with GAAP, as well as two other financial measures, electric margin and natural gas margin, that are considered "non-GAAP financial measures." Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that includes adjustments that result in a presentation that is not defined by GAAP. The presentation of electric margin and natural gas margin is intended to supplement an understanding of PSE's operating performance. Electric margin and natural gas margin are used by PSE to determine whether PSE is collecting the appropriate amount of revenue from its customers in order to provide adequate recovery of operating costs, including interest and equity returns. PSE's electric margin and natural gas margin measures may not be comparable to other companies' electric margin and natural gas margin measures. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.
The following table presents operating income and a reconciliation of utility electric and natural gas margins to the most directly comparable GAAP measure, operating income:
| Puget Sound Energy | |||||||||||||||||||||||
| (Dollars in Thousands) |
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Operating income (loss) | $ | 96,240 | $ | (60,293) | $ | 483,032 | $ | 211,688 | |||||||||||||||
| Electric operating revenue | $ | 968,125 | $ | 736,113 | $ | 2,827,428 | $ | 2,434,458 | |||||||||||||||
| Purchased electricity | (354,795) | (250,822) | (1,012,441) | (892,436) | |||||||||||||||||||
| Electric generation fuel | (86,106) | (78,305) | (249,338) | (241,293) | |||||||||||||||||||
| Residential exchange | 17,452 | 17,477 | 62,053 | 61,630 | |||||||||||||||||||
| Electric margin (non-GAAP) | $ | 544,676 | $ | 424,463 | $ | 1,627,702 | $ | 1,362,359 | |||||||||||||||
| Natural gas operating revenue | $ | 177,620 | $ | 184,090 | $ | 1,014,876 | $ | 1,019,434 | |||||||||||||||
| Purchased natural gas | (53,957) | (68,243) | (397,956) | (472,776) | |||||||||||||||||||
| Natural gas margin (non-GAAP) | $ | 123,663 | $ | 115,847 | $ | 616,920 | $ | 546,658 | |||||||||||||||
| Other operating revenue | $ | 48 | $ | 40 | $ | 7,481 | $ | 222 | |||||||||||||||
| Unrealized gain (loss) on derivative instruments, net | - | (108,979) | - | (131,712) | |||||||||||||||||||
| Utility operation and maintenance | (226,024) | (183,915) | (666,366) | (579,697) | |||||||||||||||||||
| Non-utility expense and other | (5,058) | (5,719) | (24,303) | (15,912) | |||||||||||||||||||
| Depreciation and amortization | (247,908) | (225,135) | (748,640) | (676,630) | |||||||||||||||||||
| Taxes other than income taxes | (93,157) | (76,895) | (329,762) | (293,600) | |||||||||||||||||||
| Operating income (loss) | $ | 96,240 | $ | (60,293) | $ | 483,032 | $ | 211,688 | |||||||||||||||
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 charts display the details of PSE's electric margin changes for the three months and nine months ended September 30, 2025 and 2024:
______________
* Includes decoupling cash collections, ROR excess earnings, and decoupling 24-month revenue reserve.
Three Months Ended September 30, 2025 compared to 2024
Electric Operating Revenue
Electric operating revenuesincreased $232.0 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 salesincreased $131.1 million primarily from a rate increase resulting in an additional $125.9 million in sales compared to the prior year and an increase in retail electricity usage of 0.8% with an impact of $5.2 million. The increase in rates is primarily due to the tariffs filed pursuant to the Company's 2024 GRC. See "Regulation of PSE Rates and Recovery of PSE Costs" included in this Item 2 of this report and Part II, Item 7, Management's Discussion and Analysis, "Regulation of PSE Rates and Recovery of PSE Costs" included in the Company's Annual Report on Form 10-K for the year ended December 31, 2024 for electric rate changes. The increase in retail usage was primarily due to an increase in commercial and industrial usage of 1.6% and 2.5%, respectively.
•Sales to other utilitiesincreased $68.8 million primarily due to a 74.9% increase in wholesale sales volume and a 16.0% increase 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. Higher wholesale power prices were largely the result of elevated prices driven by lower Mid-Columbia hydro production.
•Decoupling revenueincreased $21.0 million which was attributable to $15.5 million and $5.5 million increases in delivery and fixed production cost (FPC) deferral revenues, respectively. This was driven primarily by higher allowed rates in the three months ended September 30, 2025 compared to the same period in 2024.
•Transportation and other revenue increased $11.1 million primarily due to increased non-core gas sales of $10.0 million, of which $3.2 million related to a change in net wholesale non-core natural gas sales driven by a decrease in sales volumes and although the average price increased, the total was outpaced by a decrease in the cost of non-core gas sold; and $6.8 million related to a decrease in financial hedging costs in 2025 compared to 2024.
Electric Power Costs
Electric power costsincreased $111.8 million primarily due to changes in the following key drivers: purchased electricity and electric generation fuel. These items are discussed in detail below:
•Purchased electricityincreased $104.0 million primarily due to wholesale electricity volumes and capacity purchases that increased by 40.3% in 2025 compared to 2024 and by slightly increased wholesale purchase prices, which were 0.6% higher in 2025 compared to 2024.
•Electric generation fuelincreased $7.8 million primarily driven by natural gas fuel costs of $14.8 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 $2.0 million driven by an increase in coal generation of 13.3%. These increases were partially offset due to a $9.0 million decrease in natural gas fuel costs resulting from lower natural gas prices and decreased gas-fired combustion turbine (CT) generation of 2.7%.
______________
* Includes decoupling cash collections, ROR excess earnings, and decoupling 24-month revenue reserve.
Nine Months Ended September 30, 2025 compared to 2024
Electric Operating Revenue
Electric operating revenuesincreased $393.0 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 salesincreased $318.1 million primarily from a rate increase resulting in an additional $302.4 million in sales compared to the prior year and a slight increase in retail electricity usage of 0.6% with an impact of $15.7 million. The increase in rates is primarily due to the tariffs filed pursuant to the Company's 2024 GRC. See "Regulation of PSE Rates and Recovery of PSE Costs" included in this Item 2 of this report and Part II, Item 7, Management's Discussion and Analysis, "Regulation of PSE Rates and Recovery of PSE Costs" included in the Company's Annual Report on Form 10-K for the year ended December 31, 2024 for electric rate changes. The increase in retail usage was primarily due to an increase in residential and commercial usage of 0.7% and 0.8%, respectively.
•Sales to other utilitiesincreased $43.6 million primarily due to an increase in wholesale sales volume of 27.3%; partially offset by a 5.9% 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 revenueincreased $16.7 million which was attributable to $10.2 million and $6.5 million increases in delivery and FPC deferral revenues, respectively. This was driven primarily by higher allowed rates and was offset slightly by higher usage in the nine months ended September 30, 2025 compared to the same period in 2024.
•Other decoupling revenueincreased $3.3 million primarily due to an increase of $5.5 million in current period amortization of prior year decoupling revenues compared to the same period in 2024 and partially offset by $2.2 million of 24 months revenue reserve on estimated uncollectable amounts. This is attributable to an increase in amortization rates, which increases rate collecting of the prior year undercollected revenues.
•Transportation and other revenue increased $11.2 million primarily due to increased non-core gas sales of $11.1 million, of which $5.7 million related to an increase in net wholesale non-core natural gas sales driven by an increase in both sales volumes and average price of sales, which outpaced the corresponding increase in the cost of non-core gas sold; and $5.3 million related to a decrease in financial hedging costs in 2025 compared to 2024.
Electric Power Costs
Electric power costsincreased $127.6 million primarily due to changes in the following key drivers: purchased electricity and electric generation fuel. These items are discussed in detail below:
•Purchased electricityincreased $120.0 million primarily due to wholesale electricity volume and capacity purchases that increased by 24.3% in 2025 compared to 2024 which was partially offset by decreased wholesale purchase prices, which were 8.8% lower in 2025 compared to 2024.
•Electric generation fuelincreased $8.0 million primarily driven by natural gas fuel costs of $45.7 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 $4.3 million driven by an increase in coal generation of 10.5%. These increases were partially offset due to a $42.0 million decrease in natural gas fuel costs resulting from lower natural gas prices and decreased gas-fired CT generation of 20.7%.
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.
The following charts display the details of PSE's natural gas margin changes for the three months and nine months ended September 30, 2025 and 2024:
______________
* Includes decoupling cash collections, ROR excess earnings, and decoupling 24-month revenue reserve.
Three Months Ended September 30, 2025 compared to 2024
Natural Gas Operating Revenue
Natural gas operating revenuedecreased $6.5 million primarily due to changes in the following key drivers: retail sales, decoupling revenue, other decoupling revenue and transportation and other revenue. These items are discussed in detail below.
•Natural gas retail sales revenueincreased $24.8 million primarily due to an increase in rates of $38.4 million partially offset by a decrease in natural gas load of 8.2%, or $13.6 million. 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 Part II, Item 7, Management's Discussion and Analysis, "Regulation of PSE Rates and Recovery of PSE Costs" included in the Company's Annual Report on Form 10-K for the year ended December 31, 2024 for natural gas rate changes. The decrease in natural gas load was driven by a decrease in heating degree days of 47.2% in the three months ended September 30, 2025 as compared to 2024.
•Decoupling revenueincreased $1.7 million primarily due to lower natural gas usage, as mentioned above, in 2025 compared to 2024.
•Transportation and other revenuedecreased $32.0 million due to a decrease of $30.8 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.
Natural Gas Energy Costs
•Purchased natural gasexpense decreased $14.3 million primarily due to a decrease of $22.9 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 8.2% 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 Management's Discussion and Analysis, "Regulation of PSE Rates and Recovery of PSE Costs" included in Part II, Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2024.
______________
* Includes decoupling cash collections, ROR excess earnings, and decoupling 24-month revenue reserve.
Nine Months Ended September 30, 2025 compared to 2024
Natural Gas Operating Revenue
Natural gas operating revenuedecreased $4.6 million primarily due to due to changes in the following key drivers: retail sales, decoupling revenue, other decoupling revenue and transportation and other revenue. These items are discussed in detail below.
•Natural gas retail sales revenueincreased $160.4 million primarily due to an increase in rates of $178.6 million partially offset by a decrease in natural gas load of 2.0%, or $18.1 million. 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 Part II, Item 7, Management's Discussion and Analysis, "Regulation of PSE Rates and Recovery of PSE Costs" included in the Company's Annual Report on Form 10-K for the year ended December 31, 2024 for natural gas rate changes. The decrease in natural gas load was driven by a decrease in heating degree days of 1.0% in the nine months ended September 30, 2025 as compared to 2024.
•Decoupling revenuedecreased $21.6 million primarily due to higher baseline delivery rates in 2025 compared to 2024.
•Other decoupling revenuedecreased $15.6 million primarily due to an increase in current period amortization of prior year decoupling revenues compared to the same period in 2024. This is attributable to an increase in amortization rates, which increases the rate at which prior undercollections are recovered from customers.
•Transportation and other revenuedecreased $127.8 million due to a decrease of $142.1 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. The decreases were partially offset by an increase of $11.4 million related to the regulatory offset of bill discounts under Schedule 129D, which are passed back to customers as credits on billed revenue included within natural gas retail revenues above and $6.5 million related to the Company's deferred return on its investment in the Tacoma LNG Facility.
Natural Gas Energy Costs
•Purchased natural gasexpense decreased $74.8 million primarily due to a decrease of $152.1 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 2.0% 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 Management's Discussion and Analysis, "Regulation of PSE Rates and Recovery of PSE Costs" included in Part II, Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2024.
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 and nine months ended September 30, 2025 and 2024:
Three Months Ended September 30, 2025 compared to 2024
•Net unrealized (gain) loss on derivative instruments decreased $109.0 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 additional information, see Note 4, "Accounting for Derivative Instruments and Hedging Activities" and Note 7, "Regulation and Rates" in Item 1 of this report.
•Utility operations and maintenanceexpense increased $42.1 million primarily due to increases in the following: (i) $13.3 million related to maintenance of transmission and distribution overhead lines driven by higher levels of emergent incidents, vegetation management maintenance and wildfire mitigation spent, (ii) $12.4 million related to customer service expense, driven by an increase in Schedule 129 - low income program in electric and natural gas rates, see Management's Discussion and Analysis, "Regulation of PSE Rates and Recovery of PSE Costs" included in Part II, Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2024, (iii) $5.9 million of miscellaneous general expenses driven by increases to call center, training and other customer records and collection expenses, as well as shared services and (iv) $3.4 million related to insurance expense driven by wildfire insurance.
•Depreciation and amortization expenseincreased $22.8 million due to increases in the following: (i) $8.0 million increase 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 Item 2 of this report, (ii) $7.5 million increase in electric production depreciation primarily driven by net additions to the Upper Baker Dam and waterway, addition of Beaver Creek wind facility and software assets and (iii) $6.5 million increase in electric transmission and distribution plant primarily driven by net additions of transmission poles and underground conductors, respectively.
•Taxes other than income taxesincreased $16.3 million primarily due to an increase of $8.6 million and $6.3 million in municipal and state excise taxes, respectively, in 2025 as compared to 2024.
Other Income, Interest Expense and Income Tax Expense
•Interest expense increased $2.6 million primarily due to an increase of $2.1 million in interest expense due to the June 2024 and September 2025 PSE bond issuances.
•Income tax expenseincreased $31.5 million primarily driven by an increase in pre-tax book income in 2025 as compared to 2024.
Nine Months Ended September 30, 2025 compared to 2024
•Net unrealized (gain) loss on derivative instruments decreased $131.7 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 additional information, see Note 4, "Accounting for Derivative Instruments and Hedging Activities" and Note 7, "Regulation and Rates" in Item 1 of this report.
•Utility operations and maintenanceexpense increased $86.7 million primarily due to increases in the following: (i) $41.0 million related to customer service expense, driven by an increase in Schedule 129 - low income program in electric and natural gas rates, see Management's Discussion and Analysis, "Regulation of PSE Rates and Recovery of PSE Costs" included in Part II, Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2024, (ii) $10.7 million related to maintenance distribution overhead lines driven by an increased scope in vegetation management (iii) $8.0 million related to insurance expense driven by wildfire insurance, (iv) $6.1 million of miscellaneous general expenses driven by increases to call center, training and other customer records and collection expenses and $4.1 million related to leak surveys, locates and inspections.
•Non-utility expense and otherincreased $8.3 million primarily due to $5.9 million of costs associated with a sale of land at PSE's wholly-owned subsidiary, Puget Western Inc. in May 2025 and an increase in the long-term incentive plan of $7.6 million in 2025 as compared to 2024; partially offset by an early funding agreement of $5.0 million in 2024.
•Depreciation and amortization expenseincreased $72.0 million due to increases in the following: (i) $24.7 million increase 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 Item 2 of this report, (ii) $20.7 million increase in electric production and electric general plant depreciation primarily driven by net additions to the Upper Baker Dam and waterway, addition of Beaver Creek wind facility and advanced distribution management system computer software assets, (iii) $18.3 million increase in electric transmission and distribution plant primarily driven by net additions of transmission poles and underground conductors, respectively and (iv) $5.2 million increase in natural gas distribution primarily driven by net additions of plastic mains assets.
•Taxes other than income taxesincreased $36.2 million primarily due to an increase of $22.6 million and $20.3 million in state excise taxes and municipal taxes, respectively; partially offset by a $5.0 million decrease in property taxes.
Other Income, Interest Expense and Income Tax Expense
•Other income/expenseincreased $18.5 million from net other income of $56.1 million in 2024 to net other income of $74.6 million in 2025, due to an increase of $25.9 million in other income that was partially offset by an increase of $7.3 million in other expense. The increase in other income was primarily due to an increase of $18.1 million related to advanced metering infrastructure interest income and a $10.5 million increase in equity AFUDC due to an increase in AFUDC rates' partially offset by taxable interest and dividend income of $8.0 million. The increase in other expense was primarily due to an increase of $6.8 million related to Colstrip major maintenance.
•Interest expense increased $15.9 million primarily due to an increase of $18.3 million in interest expense due to the June 2024 and September 2025 PSE bond issuances. This was partially offset by a decrease in other common interest expense of $4.6 million due to less short-term commercial paper borrowing in 2025 as compared to 2024.
•Income tax expenseincreased $41.4 million primarily driven by an increase in pre-tax book income in 2025 as compared to 2024.
Puget Energy
Primarily, all operations of Puget Energy are conducted through PSE. Puget Energy's net income (loss) for the three months and nine months ended September 30, 2025 and 2024 is as follows:
Three Months Ended September 30, 2025 compared to 2024
Summary Results of Operation
Puget Energy's net income increased by $127.4 million. This is primarily due to: (i) an increase in PSE's net income of $122.9 million and (ii) increased tax benefit of $9.2 million. The increases were partially offset by an increase in interest expense of $4.8 million, which was driven by interest expense accrued for Puget Energy's $600.0 million bond issuance in early March 2025.
Nine Months Ended September 30, 2025 compared to 2024
Summary Results of Operation
Puget Energy's net income increased by $238.3 million. This is primarily due to: (i) an increase in PSE's net income of $232.6 million, (ii) an increase in other operating revenue and income of $4.5 million driven by short-term interest earned from re-investing proceeds of Puget Energy's $600.0 million bond issued in early March 2025 and (iii) increased tax benefit of $11.7 million. The increases were partially offset by an increase in interest expense of $9.6 million, which was driven by interest expense accrued for Puget Energy's $600.0 million bond issuance in early March 2025.
Capital Requirements
Contractual Obligations and Commercial Commitments
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, 2024, during the nine months ended September 30, 2025, the Company entered into new Electric Portfolio and Electric Wholesale Market Transaction contracts with estimated payment obligations totaling $1.0 billion through 2054. For further information, see Part II, Item 8, Note 16, "Commitments and Contingencies" in the Company's Annual Report on Form 10-K for the year ended December 31, 2024.
Off-Balance Sheet Arrangements
As of September 30, 2025, 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" in the Combined Notes to Consolidated Financial Statements included in Item 1 of this report.
Utility Construction Program
The Company's construction programs for generating facilities, the electric transmission system, the natural gas and electric distribution systems and the Tacoma LNG facility are designed to meet regulatory requirements, support customer
growth and improve energy system reliability. Construction expenditures, excluding equity AFUDC, totaled $1.2 billion for the nine months ended September 30, 2025. Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:
| Capital Expenditure Projections | |||||||||||||||||
| (Dollars in Millions) | 2025 | 2026 | 2027 | ||||||||||||||
| Total energy delivery, technology and facilities expenditures | $1,676.1 | $1,789.6 | $2,421.1 | ||||||||||||||
The program is subject to change based upon general business, economic and regulatory conditions. Utility construction expenditures and any new generation resource expenditures may be funded from a combination of sources, which may include cash from operations, short-term debt, long-term debt and/or equity. PSE's planned capital expenditures may result in a level of spending that will exceed its cash flow from operations. As a result, execution of PSE's strategy is dependent in part on continued access to capital markets.
Capital Resources
Cash from Operations
| Puget Sound Energy |
Nine Months Ended September 30, |
||||||||||||||||
| (Dollars in Thousands) | 2025 | 2024 | Change | ||||||||||||||
| Net income | $ | 286,296 | $ | 53,715 | $ | 232,581 | |||||||||||
|
Non-cash items1
|
709,374 | 702,250 | 7,124 | ||||||||||||||
|
Changes in cash flow resulting from working capital2
|
79,383 | 154,979 | (75,596) | ||||||||||||||
| Regulatory assets and liabilities | (38,754) | (9,322) | (29,432) | ||||||||||||||
| Purchased gas adjustment | 26,786 | (71,600) | 98,386 | ||||||||||||||
| GHG emission allowances | (140,295) | (83,910) | (56,385) | ||||||||||||||
|
Other non-current assets and liabilities3
|
(9,472) | (40,137) | 30,665 | ||||||||||||||
| Net cash provided by operating activities | $ | 913,318 | $ | 705,975 | $ | 207,343 | |||||||||||
_______________
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.
Nine Months Ended September 30, 2025 compared to 2024
Cash generated from operationsfor the nine months ended September 30, 2025 increased by $207.3 million, which includes a net income increase of $232.6 million. The following are significant factors that impacted PSE's cash flows from operations:
•Cash flows resulting from non-cash itemsincreased $7.1 million primarily due to: (i) an increase in deferred taxes of $64.2 million, (ii) an increase in depreciation and amortization of $47.4 million, (iii) an increase of $24.7 million in conservation amortization, (iv) an increase of $8.6 million related to the amortization of regulatory filing fees, and (v) an increase of $5.1 million related to the deferral of energy exchange costs. The increases were partially offset by: (i) a $131.7 million change in net unrealized loss 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 and (ii) a change in equity AFUDC of $10.5 million.
•Cash flows resulting from changes in working capitaldecreased $75.6 million primarily due to: (i) a decrease in cash inflow of $30.1 million due to the timing of accounts receivable collections, as the balance of accounts receivable decreased $163.7 million in 2025 compared to a decrease of $193.8 million in 2024 (ii) a decrease in cash inflow of $26.1 million in prepayments was primarily driven by the significant difference in the reduction of prepaid electricity assets between the two periods, which led to a less favorable comparison for current year's cash position of $16.9 million, and prepayments made for IT hardware and software of $2.1 million and all other prepayments of $7.1 million, (iii) cash outflow of $13.1 million in material and supplies, which was primarily driven by purchasing network devices and system equipment for the Advanced Metering Infrastructure network, (iv) accounts payable decreased
faster in 2025 compared to 2024, which led to increased cash outflow of $4.4 million, , (v) cash outflow of $5.0 million related to the change in salary and wage payable, (vi) a reduced cash inflow of $3.5 million related to lower transmission services deposits received and (vii) cash outflow of $2.5 million related to annual filing fees paid to the Washington Commission. The decreases were partially offset by: (i) increased cash inflow of $5.9 million due to a decrease in fuel inventory in 2025 compared to 2024, (ii) cash inflow of $3.5 million due to the change in tax payable balance,
•Cash flows resulting from regulatory assets and liabilitiesdecreased $29.4 million primarily due to: (i) $17.8 million cash outflow from incremental deferrals of bad debt expense related to COVID-19 in 2025 compared to 2024, (ii) $10.3 million cash outflow in the PCA due to actual power costs being higher than baseline rates in both periods, but to a larger degree in 2025 compared to 2024, (iii) $5.9 million cash outflow in the Wildfire Tracker that defers both capital and operation and maintenance costs, including insurance premiums attributable to wildfire, which are necessary to implement PSE's Wildfire Mitigation Plan, (iv) $5.1 million of cash outflow from storm damage costs, primarily driven by storm events in the first quarter of 2025, (v) $3.2 million of cash outflow due to an increase in abandonment cost related to Colstrip 3 & 4 and (vi) $3.1 million of cash outflow due to higher deferred costs related to the low income program. The decreases were partially offset by: (i) $13.7 million cash inflow in the deferred costs related to PSE's decarbonization program, which had deferred a total of $15.0 million through 2024 and had begun to amortize the balance in 2025 for two years and (ii) $2.6 million cash inflow in major maintenance.
•Cash flows resulting from purchased gas adjustmentincreased $98.4 million, which was primarily driven by a $76.0 million increase in allowed PGA recovery in 2025 compared to 2024 and a $22.4 million decrease in actual natural gas cost.
•Cash flow resulting from GHG emission allowancesdecreased $56.4 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 liabilitiesincreased $30.7 million, which is primarily due to: (i) $27.2 million increase seen in the low income program, which was mainly driven by higher rates in the first nine months of 2025 compared to 2024 and (ii) $5.4 million cash inflow due to changes in accrual of the Company's long-term incentive plan.
| Puget Energy |
Nine Months Ended September 30, |
||||||||||||||||
| (Dollars in Thousands) | 2025 | 2024 | Change | ||||||||||||||
| Net income | $ | (68,258) | $ | (73,990) | $ | 5,732 | |||||||||||
|
Non-cash items1
|
15,163 | 38,687 | (23,524) | ||||||||||||||
|
Changes in cash flow resulting from working capital2
|
5,348 | 11,255 | (5,907) | ||||||||||||||
|
Other non-current assets and liabilities3
|
(3,331) | (2,027) | (1,304) | ||||||||||||||
| Net cash provided by operating activities | $ | (51,078) | $ | (26,075) | $ | (25,003) | |||||||||||
_______________
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.
Nine Months Ended September 30, 2025 compared to 2024
Cash generated from operationsfor the nine months ended September 30, 2025, in addition to the changes discussed at PSE above, decreased by $25.0 million compared to the same period in 2024, which includes a net income increase of $5.7 million.
•Changes in cash flow resulting from non-cash itemsdecreased $23.5 million primarily due to a $25.6 million change in deferred taxes.
•Changes in cash flow resulting from working capitaldecreased $5.9 million primarily due to changes in interest accrual 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.
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 September 30, 2025, 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.
Puget Sound Energy
Debt Restrictive Covenants
The type and amount of future long-term financings for PSE may be limited by provisions in PSE's electric and natural gas mortgage indentures.
PSE's ability to issue additional secured debt may also be limited by certain restrictions contained in its electric and natural gas mortgage indentures. Under the most restrictive tests at September 30, 2025, PSE could issue:
•Approximately $0.4 billion of additional first mortgage bonds under PSE's electric mortgage indenture based on approximately $0.6 billion of electric bondable property available for issuance, subject to an interest coverage ratio limitation of 2.0 times net earnings available for interest (as defined in the electric utility mortgage), which PSE exceeded at September 30, 2025; and
•Approximately $1.2 billion of additional first mortgage bonds under PSE's natural gas mortgage indenture based on approximately $1.9 billion of natural gas bondable property available for issuance, subject to a combined natural gas and electric interest coverage test of 1.75 times net earnings available for interest and a natural gas interest coverage test of 2.0 times net earnings available for interest (as defined in the natural gas utility mortgage), both of which PSE exceeded at September 30, 2025.
At September 30, 2025, PSE had approximately $10.9 billion in electric and natural gas rate base to support the interest coverage ratio limitation test for net earnings available for interest.
Dividend Payment Restrictions
The payment of dividends by PSE to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE's electric and natural gas mortgage indentures. At September 30, 2025, approximately $2.0 billion of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant.
Pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE's common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission. Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE's corporate credit/issuer rating is investment grade, or, if its credit ratings are below investment grade, PSE's ratio of 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 48.3% at September 30, 2025, and the EBITDA to interest expense ratio was 5.1 to 1.0 for the twelve months ended September 30, 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.
At September 30, 2025, 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 Part I, Item 1, Note 10, "Other" of this report and Part II, Item 8, Note 7, "Long-Term Debt" and Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's Annual Report on Form 10-K for the year ended December 31, 2024.
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 3.7 to 1.0 for the twelve months ended September 30, 2025.
At September 30, 2025, 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 Part I, Item 1, Note 10, "Other" included in this report and Part II, Item 8, Note 7, "Long-Term Debt" and Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's Annual Report on Form 10-K for the year ended December 31, 2024.
Other
New Accounting Pronouncements
For the discussion of new accounting pronouncements, see Note 2, "New Accounting Pronouncements" in the Combined Notes to Consolidated Financial Statements included in Item 1 of this report.
One Big Beautiful Bill Act
On July 4th, 2025, the 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. While the OBBB does not have a material impact on the Company's financial statements for the period ended September 30, 2025, the Company is in the process of evaluating its potential for future impacts.
Washington Clean Energy Transformation Act
In 2019, Washington passed the CETA, which supports Washington's clean energy economy and transitioning to a clean, affordable, and reliable energy future. The CETA requires all electric utilities to (i) eliminate coal-fired generation from their in-state electric supply to customers by December 31, 2025; (ii) be carbon-neutral by January 1, 2030 through a combination of non-emitting electric generation, renewable generation, and/or alternative compliance options; and (iii) makes it the state policy that, by 2045, 100% of electric generation and retail electricity sales will come from renewable or non-emitting resources. CEIP are required every four years from each IOU. The plan must propose interim targets for meeting the 2045 standard between 2030 and 2045 and describe an actionable plan that the IOU intends to pursue to meet the standard. The Washington Commission may approve, reject or recommend alterations to an IOU's plan. The Company intends to seek recovery of any costs associated with CETA through the regulatory process. On December 17, 2021, PSE filed its final CEIP, which proposed a plan for the implementation of CETA for 2022-2025 and associated project costs. On June 6, 2023, the Washington Commission approved PSE's CEIP, subject to conditions. On November 2, 2023, PSE filed a Biennial CEIP Update with the Commission.
Washington Climate Commitment Act
In 2021, the Washington Legislature adopted the CCA, which establishes a GHG emissions cap-and-invest program that requires covered entities, including electric and gas utilities, to purchase allowances to cover their GHG emissions with a cap on available allowances beginning on January 1, 2023, then declining annually through 2050. The WDOE published final
regulations on September 29, 2022, which became effective on October 30, 2022. Allowances can be obtained through quarterly auctions, or bought and sold on a secondary market.
As an electric utility, PSE is required to obtain emission allowances or offset credits for GHG emissions associated with (i) electricity generated in Washington (ii) electricity imported into the state to serve Washington load, and (iii) all PSE facilities with total annual emissions exceeding 25,000 metric tons of carbon dioxide equivalent per year. As an electric utility subject to Washington's CETA, which is discussed below, PSE receives emission allowances from WDOE at no cost through 2050 for direct emissions associated with electricity used to serve Washington State load to eliminate the cost burden of the program on electric ratepayers.
As a 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 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.
Integrated Resource Plans, Resource Acquisition and Development
For further information, see Part I, Item 1 "Integrated Resource Plans, Resource Acquisition and Development" in the Company's Annual Report on Form 10-K for the year ended December 31, 2024.
Environmental Remediation
The Company is subject to federal and state requirements for protection of the environment, including those for the discharge of hazardous materials and remediation of contaminated sites. A potentially responsible party has joint and several liability under existing U.S. environmental laws. In instances where we have been designated a potentially responsible party by the Environmental Protection Agency or state environmental agency, we are potentially liable for the cost of remediating contamination at existing and former work sites. Such sites include former manufactured gas plants and contaminated facilities operated by PSE predecessors, such as Gas Works Park on the shore of Lake Union in Seattle and a long-defunct creosote manufacturer, which had purchased waste products from PSE predecessors (e.g. Quendall Terminals site on Lake Washington in Renton, Washington), respectively. In each case, PSE assesses the environmental remediation obligations related to the contaminated sites based on in-depth studies, which include assessments of the probabilities of recovery from other responsible parties and/or insurance carriers, expert analyses and legal reviews. PSE develops a range of reasonably estimable costs that includes a low and high end of a range for all remediation sites for which we have sufficient information. There are some potential remediation obligations where the costs of remediation cannot be reasonably estimated. Liabilities are recorded based on the best estimate or the low end of a range of reasonably possible costs expected to be incurred to remediate sites. It 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 Part II, Item 8, Note 4, "Regulation and Rates" in the Company's Annual Report on Form 10-K for the year ended December 31, 2024.
Grid Resilience and Innovation Partnerships Program
In 2021, the Infrastructure Investment and Jobs Act was signed into law, which among other investments and programs, established the U.S. Department of Energy's (DOE) Grid Resilience and Innovation Partnerships (GRIP) Program. The GRIP program was established to enhance grid flexibility and improve the resilience of the power system against growing threats of extreme weather and climate change. PSE has been selected for three grant awards under the GRIP program either through individual applications or participating in consortium grant applications: (i) PSE participated in the North Plains Connector grant consortium along with other utilities in the Pacific Northwest region that on August 7, 2024 was selected for a grant of $700.0 million of federal cost sharing; (ii) PSE applied for the Skagit River Valley Transformation for Climate Resiliency project that was selected on October 18, 2024 for a grant of $45.8 million of federal cost sharing; and (iii) PSE partnered in a
coalition with E Source and other Pacific Northwest utilities on the Increasing Energy Resilience via Technology Investment Acceleration project, which was selected on October 18, 2024 for a grant of $77.0 million of federal cost sharing. As of the time of this report, all three grants must complete award negotiations and proceed to a signed award with the DOE in order to receive federal cost sharing funds and, pursuant to recently signed executive orders, the federal government's activities with respect to such awards has been temporarily paused. Thus, at this time, the Company cannot predict the timing or amount of federal cost sharing that may be received.
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