Cover Page - USD ($) $ in Billions	12 Months Ended
Cover Page - USD ($) $ in Billions	Dec. 31, 2025	Jan. 31, 2026	Jun. 30, 2025
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2025
Document Transition Report	false
Entity File Number	001-09057
Entity Registrant Name	WEC ENERGY GROUP, INC.
Entity Tax Identification Number	39-1391525
Entity Incorporation, State or Country Code	WI
Entity Address, Address Line One	231 West Michigan Street
Entity Address, Address Line Two	P.O. Box 1331
Entity Address, City or Town	Milwaukee
Entity Address, State or Province	WI
Entity Address, Postal Zip Code	53201
City Area Code	414
Local Phone Number	221-2345
Title of 12(b) Security	Common Stock, $.01 Par Value
Trading Symbol	WEC
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction	false
Entity Shell Company	false
Entity Public Float			$ 33.5
Entity Common Stock, Shares Outstanding		325,531,361
Documents Incorporated by Reference	Portions of WEC Energy Group, Inc.'s Definitive Proxy Statement on Schedule 14A for its Annual Meeting of Shareholders, to be held on May 7, 2026, are incorporated by reference into Part III hereof.
Entity Central Index Key	0000783325
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2025
Document Fiscal Period Focus	FY
Amendment Flag	false

Audit Information	12 Months Ended
Audit Information	Dec. 31, 2025
Audit Information [Abstract]
Auditor Name	DELOITTE & TOUCHE LLP
Auditor Location	Milwaukee, Wisconsin
Auditor Firm ID	34

Consolidated Income Statements - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income Statement [Abstract]
Operating revenues	$ 9,800.1	$ 8,599.9	$ 8,893.0
Operating expenses
Cost of sales	3,265.8	2,656.0	3,191.2
Other operation and maintenance	2,400.8	2,158.0	2,100.5
Impairments related to Illinois segment	130.0	12.1	178.9
Depreciation and amortization	1,478.5	1,354.5	1,264.2
Property and revenue taxes	280.1	266.5	250.2
Total operating expenses	7,555.2	6,447.1	6,985.0
Operating income	2,244.9	2,152.8	1,908.0
Equity in earnings of transmission affiliates	215.8	207.5	177.5
Other income, net	107.9	178.2	177.7
Interest expense	895.1	815.3	727.4
Gain on debt extinguishments	0.0	(23.1)	(0.5)
Other expense	(571.4)	(406.5)	(371.7)
Income before income taxes	1,673.5	1,746.3	1,536.3
Income tax expense	118.0	222.0	204.6
Net income	1,555.5	1,524.3	1,331.7
Preferred stock dividends of subsidiary	1.2	1.2	1.2
Net loss attributed to noncontrolling interests	3.2	4.1	1.2
Net income attributed to common shareholders	$ 1,557.5	$ 1,527.2	$ 1,331.7
EPS
Basic (in dollars per share)	$ 4.84	$ 4.83	$ 4.22
Diluted (in dollars per share)	$ 4.81	$ 4.83	$ 4.22
Weighted average common shares outstanding
Basic (in shares)	321.9	316.2	315.4
Diluted (in shares)	323.8	316.5	315.9

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Statement of Other Comprehensive Income [Abstract]
Net income	$ 1,555.5	$ 1,524.3	$ 1,331.7
Derivatives accounted for as cash flow hedges
Reclassification of realized derivative gains to net income, net of tax	(0.2)	(0.3)	(0.3)
Defined benefit plans
Pension and OPEB adjustments arising during the period, net of tax	0.2	0.1	(0.6)
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax	0.2	0.1	0.0
Defined benefit plans, net	0.4	0.2	(0.6)
Other comprehensive income (loss), net of tax	0.2	(0.1)	(0.9)
Comprehensive income	1,555.7	1,524.2	1,330.8
Preferred stock dividends of subsidiary	1.2	1.2	1.2
Comprehensive loss attributed to noncontrolling interests	3.2	4.1	1.2
Comprehensive income attributed to common shareholders	$ 1,557.7	$ 1,527.1	$ 1,330.8

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Current assets
Cash and cash equivalents	$ 27.6	$ 9.8
Accounts receivable and unbilled revenues, net of reserves of $148.7 and $162.8, respectively	2,062.7	1,669.3
Materials, supplies, and inventories	803.4	813.2
Prepaid taxes	178.8	214.9
Other prepayments	92.4	82.6
Other	119.8	121.9
Current assets	3,284.7	2,911.7
Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $12,411.5 and $11,611.9, respectively	38,278.1	34,645.4
Regulatory assets (December 31, 2025 and December 31, 2024 include $67.5 and $76.5, respectively, related to WEPCo Environmental Trust)	3,156.3	3,339.7
Equity investment in transmission affiliates	2,280.4	2,108.9
Goodwill	3,052.8	3,052.8
Pension and OPEB assets	1,082.4	968.5
Other	383.6	336.2
Long-term assets	48,233.6	44,451.5
Total assets	51,518.3	47,363.2
Current liabilities
Short-term debt	1,924.7	1,116.6
Current portion of long-term debt (December 31, 2025 and December 31, 2024 include $9.3 and $9.2, respectively, related to WEPCo Environmental Trust)	1,519.4	1,729.0
Accounts payable	1,140.1	1,137.1
Other	1,009.2	859.2
Current liabilities	5,593.4	4,841.9
Long-term liabilities
Long-term debt (December 31, 2025 and December 31, 2024 include $67.4 and $76.4, respectively, related to WEPCo Environmental Trust)	18,498.1	17,178.1
Finance lease obligations	372.0	303.3
Deferred income taxes	5,891.7	5,514.7
Deferred revenue, net	314.2	334.6
Regulatory liabilities	4,121.3	3,958.0
Intangible liabilities	580.3	566.8
Environmental remediation liabilities	484.1	445.8
AROs	647.0	580.0
Other	963.4	838.1
Long-term liabilities	31,872.1	29,719.4
Commitments and contingencies (Note 24)
Common shareholders' equity
Common stock – $0.01 par value; 650,000,000 shares authorized; 325,461,519 and 317,680,855 shares outstanding, respectively	3.3	3.2
Additional paid in capital	5,124.4	4,315.8
Retained earnings	8,493.5	8,083.8
Accumulated other comprehensive loss	(7.6)	(7.8)
Common shareholders' equity	13,613.6	12,395.0
Preferred stock of subsidiary	30.4	30.4
Noncontrolling interest	408.8	376.5
Total liabilities and equity	$ 51,518.3	$ 47,363.2

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Statement of Financial Position [Abstract]
Accounts receivable and unbilled revenues, reserves	$ 148.7	$ 162.8
Property, plant, and equipment, accumulated depreciation and amortization	$ 12,411.5	$ 11,611.9
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	650,000,000	650,000,000
Common stock, shares outstanding	325,461,519	317,680,855
Balance sheets
Regulatory assets (December 31, 2025 and December 31, 2024 include $67.5 and $76.5, respectively, related to WEPCo Environmental Trust)	$ 3,156.3	$ 3,339.7
Current portion of long-term debt (December 31, 2025 and December 31, 2024 include $9.3 and $9.2, respectively, related to WEPCo Environmental Trust)	1,519.4	1,729.0
Long-term debt (December 31, 2025 and December 31, 2024 include $67.4 and $76.4, respectively, related to WEPCo Environmental Trust)	18,498.1	17,178.1
WEPCo Environmental Trust
Balance sheets
Regulatory assets (December 31, 2025 and December 31, 2024 include $67.5 and $76.5, respectively, related to WEPCo Environmental Trust)	67.5	76.5
Current portion of long-term debt (December 31, 2025 and December 31, 2024 include $9.3 and $9.2, respectively, related to WEPCo Environmental Trust)	9.3	9.2
Long-term debt (December 31, 2025 and December 31, 2024 include $67.4 and $76.4, respectively, related to WEPCo Environmental Trust)	$ 67.4	$ 76.4

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Operating activities
Net income	$ 1,555.5	$ 1,524.3	$ 1,331.7
Reconciliation to cash provided by operating activities
Depreciation and amortization	1,478.5	1,354.5	1,264.2
Deferred income taxes and ITCs, net	368.5	529.0	219.4
Impairments related to Illinois segment	130.0	12.1	178.9
Contributions and payments related to pension and OPEB plans	(13.7)	(14.5)	(16.7)
Equity income in transmission affiliates, net of distributions	(29.2)	(57.4)	(33.0)
Change in -
Accounts receivable and unbilled revenues, net	(411.8)	(161.5)	340.6
Materials, supplies, and inventories	9.8	(38.0)	41.9
Prepaid taxes	36.1	(41.0)	27.9
Collateral on deposit	(25.4)	84.3	22.1
Other current assets	11.4	(34.4)	8.4
Accounts payable	46.4	99.7	(254.0)
Amounts refundable to customers	43.6	(2.2)	(9.0)
Other current liabilities	86.5	13.8	56.5
Other, net	93.2	(56.9)	(160.5)
Net cash provided by operating activities	3,379.4	3,211.8	3,018.4
Investing activities
Capital expenditures	(4,398.1)	(2,781.1)	(2,492.9)
Acquisition of Hardin III, net of cash acquired of $0.2	(406.1)	0.0	0.0
Acquisition of Delilah I, net of cash acquired of $0.6	0.0	(462.5)	0.0
Acquisition of Maple Flats, net of cash acquired of $0.5	0.0	(431.2)	0.0
Acquisition of West Riverside	0.0	(97.9)	(95.3)
Acquisition of Red Barn	0.0	(2.1)	(143.8)
Acquisition of Whitewater	0.0	0.0	(76.0)
Acquisition of Sapphire Sky, net of cash acquired of $0.3	0.0	0.0	(442.6)
Acquisition of Samson I, net of cash acquired of $5.2	0.0	0.0	(257.3)
Capital contributions to transmission affiliates	(142.4)	(45.5)	(63.7)
Reimbursement for ATC's transmission infrastructure upgrades	39.8	8.1	0.1
Other, net	32.1	9.7	13.3
Net cash used in investing activities	(4,874.7)	(3,802.5)	(3,558.2)
Financing activities
Exercise of stock options	39.1	23.7	6.3
Issuance of common stock, net	761.9	163.4	0.0
Purchase of common stock	(1.3)	(3.2)	(16.6)
Dividends paid on common stock	(1,147.8)	(1,056.2)	(984.2)
Issuance of long-term debt	2,844.5	4,460.9	2,170.0
Retirement of long-term debt	(1,728.9)	(2,138.0)	(1,005.4)
Change in commercial paper	806.9	(902.8)	373.7
Purchase of additional ownership interest in Samson I from noncontrolling interest	0.0	(28.1)	0.0
Payments for debt extinguishment and issuance costs	(39.9)	(45.9)	(14.2)
Other, net	(10.5)	(6.1)	(6.8)
Net cash provided by financing activities	1,524.0	467.7	522.8
Net change in cash, cash equivalents, and restricted cash	28.7	(123.0)	(17.0)
Cash, cash equivalents, and restricted cash at beginning of year	42.2	165.2	182.2
Cash, cash equivalents, and restricted cash at end of year	$ 70.9	$ 42.2	$ 165.2

Consolidated Statement of Cash Flows (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Hardin III
Acquisitions
Cash acquired	$ 0.2
Delilah I
Acquisitions
Cash acquired		$ 0.6
Maple Flats
Acquisitions
Cash acquired		$ 0.5
Sapphire Sky
Acquisitions
Cash acquired			$ 0.3
Samson I
Acquisitions
Cash acquired			$ 5.2

Consolidated Statements of Equity - USD ($) $ in Millions	Total	Total common shareholders' equity	Common stock	Additional paid-in capital	Retained earnings	Accumulated other comprehensive loss	Preferred stock of subsidiary	Noncontrolling interests
Balance at Dec. 31, 2022	$ 11,616.6	$ 11,376.9	$ 3.2	$ 4,115.2	$ 7,265.3	$ (6.8)	$ 30.4	$ 209.3
Equity
Net income attributed to common shareholders	1,331.7	1,331.7	0.0	0.0	1,331.7	0.0	0.0	0.0
Net loss attributed to noncontrolling interests	1.2	0.0	0.0	0.0	0.0	0.0	0.0	1.2
Other comprehensive income (loss)	(0.9)	(0.9)	0.0	0.0	0.0	(0.9)	0.0	0.0
Issuance of common stock, net	0.0
Common stock dividends	(984.2)	(984.2)	0.0	0.0	(984.2)	0.0	0.0	0.0
Exercise of stock options	6.3	6.3	0.0	6.3	0.0	0.0	0.0	0.0
Purchase of common stock	(16.6)	(16.6)	0.0	(16.6)	0.0	0.0	0.0	0.0
Acquisition of noncontrolling interests	114.9	0.0	0.0	0.0	0.0	0.0	0.0	114.9
Distributions to noncontrolling interests	(6.0)	0.0	0.0	0.0	0.0	0.0	0.0	(6.0)
Stock-based compensation and other	10.9	11.0	0.0	11.0	0.0	0.0	0.0	(0.1)
Balance at Dec. 31, 2023	12,071.5	11,724.2	3.2	4,115.9	7,612.8	(7.7)	30.4	316.9
Equity
Net income attributed to common shareholders	1,527.2	1,527.2	0.0	0.0	1,527.2	0.0	0.0	0.0
Net loss attributed to noncontrolling interests	4.1	0.0	0.0	0.0	0.0	0.0	0.0	4.1
Other comprehensive income (loss)	(0.1)	(0.1)	0.0	0.0	0.0	(0.1)	0.0	0.0
Issuance of common stock, net	163.4	163.4	0.0	163.4	0.0	0.0	0.0	0.0
Common stock dividends	(1,056.2)	(1,056.2)	0.0	0.0	(1,056.2)	0.0	0.0	0.0
Exercise of stock options	23.7	23.7	0.0	23.7	0.0	0.0	0.0	0.0
Purchase of common stock	(3.2)	(3.2)	0.0	(3.2)	0.0	0.0	0.0	0.0
Acquisition of noncontrolling interests	99.4	0.0	0.0	0.0	0.0	0.0	0.0	99.4
Purchase of additional ownership interest in Samson I from noncontrolling interest	28.1	(4.3)	0.0	(4.3)	0.0	0.0	0.0	(32.4)
Distributions to noncontrolling interests	(3.3)	0.0	0.0	0.0	0.0	0.0	0.0	(3.3)
Stock-based compensation and other	11.7	11.7	0.0	11.7	0.0	0.0	0.0	0.0
Balance at Dec. 31, 2024	12,801.9	12,395.0	3.2	4,315.8	8,083.8	(7.8)	30.4	376.5
Equity
Net income attributed to common shareholders	1,557.5	1,557.5	0.0	0.0	1,557.5	0.0	0.0	0.0
Net loss attributed to noncontrolling interests	3.2	0.0	0.0	0.0	0.0	0.0	0.0	3.2
Other comprehensive income (loss)	0.2	0.2	0.0	0.0	0.0	0.2	0.0	0.0
Issuance of common stock, net	761.9	761.9	0.1	761.8	0.0	0.0	0.0	0.0
Common stock dividends	(1,147.8)	(1,147.8)	0.0	0.0	(1,147.8)	0.0	0.0	0.0
Exercise of stock options	39.1	39.1	0.0	39.1	0.0	0.0	0.0	0.0
Purchase of common stock	(1.3)	(1.3)	0.0	(1.3)	0.0	0.0	0.0	0.0
Acquisition of noncontrolling interests	45.1	0.0	0.0	0.0	0.0	0.0	0.0	45.1
Distributions to noncontrolling interests	(9.6)	0.0	0.0	0.0	0.0	0.0	0.0	(9.6)
Stock-based compensation and other	9.0	9.0	0.0	9.0	0.0	0.0	0.0	0.0
Balance at Dec. 31, 2025	$ 14,052.8	$ 13,613.6	$ 3.3	$ 5,124.4	$ 8,493.5	$ (7.6)	$ 30.4	$ 408.8

Consolidated Statements of Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Statement of Stockholders' Equity [Abstract]
Dividends per share (in dollars per share)	$ 3.57	$ 3.34	$ 3.12

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2025

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) Nature of Operations—WEC Energy Group serves approximately 1.7 million electric customers and 3.0 million natural gas customers, owns approximately 60% of ATC, and owns majority interests in multiple renewable generating facilities as part of its non-utility energy infrastructure segment.

As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, statements of comprehensive income, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. On our financial statements, we consolidate our majority-owned subsidiaries, which we control, and VIEs, of which we are the primary beneficiary. We reflect noncontrolling interests for the portion of entities that we do not own as a component of consolidated equity separate from the equity attributable to our shareholders. The noncontrolling interests that we reported as equity on our balance sheet as of December 31, 2025 related to the minority interests held by third parties in the renewable generating facilities that are included in our non-utility energy infrastructure segment.

Our financial statements include the accounts of WEC Energy Group, a diversified energy holding company, and the accounts of our subsidiaries in the following reportable segments:

•Wisconsin segment – Consists of WE, WPS, and WG, which are engaged primarily in the generation of electricity and the distribution of electricity and natural gas in Wisconsin; and UMERC, which generates electricity and distributes electricity and natural gas to customers located in the Upper Peninsula of Michigan.

•Illinois segment – Consists of PGL and NSG, which are engaged primarily in the distribution of natural gas in Illinois.

•Other states segment – Consists of MERC and MGU, which are engaged primarily in the distribution of natural gas in Minnesota and Michigan, respectively.

•Electric transmission segment – Consists of our approximate 60% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions, and our approximate 75% ownership interest in ATC Holdco, which invests in transmission-related projects outside of ATC's traditional footprint.

•Non-utility energy infrastructure segment – Consists of We Power, which is principally engaged in the ownership of electric power generating facilities for long-term lease to WE, and Bluewater, which owns underground natural gas storage facilities in Michigan. WECI, which holds our majority interests in multiple renewable generating facilities, is also included in this segment. See Note 2, Acquisitions, for more information on recently acquired WECI renewable generating facilities.

•Corporate and other segment – Consists of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Wisvest, WECC, and WBS.

Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method. We use the cumulative earnings approach for classifying distributions received in the statements of cash flows. Under the cumulative earnings approach, we compare the distributions received to cumulative equity method earnings since inception. Any distributions received up to the amount of cumulative equity earnings are considered a return on investment and classified in operating activities. Any excess distributions are considered a return of investment and classified in investing activities.

Our financial statements also reflect our proportionate interests in certain jointly owned utility facilities. See Note 8, Jointly-Owned Utility Facilities, for more information.

(b) Basis of Presentation—We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates.

(c) Cash and Cash Equivalents—Cash and cash equivalents include marketable debt securities with an original maturity of three months or less.

(d) Operating Revenues—The following discussion includes our significant accounting policies related to operating revenues. For additional required disclosures on disaggregation of operating revenues, see Note 4, Operating Revenues.

Revenues from Contracts with Customers

Electric Utility Operating Revenues

Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our Wisconsin residential and commercial and industrial customers and the majority of our Michigan residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. In our Michigan service territory, a limited number of residential and commercial and industrial customers can purchase the commodity from a third party. In this case, the delivery of the electricity represents our sole performance obligation.

The transaction price of the performance obligations for residential and commercial and industrial customers is valued using the rates, charges, terms, and conditions of service included in the tariffs of our regulated electric utilities, which have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month. Our retail electric rates in Wisconsin include base amounts for fuel and purchased power costs, which also impact our revenues. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under- or over-collections of actual fuel and purchased power costs beyond a 2% price variance from the costs included in the rates charged to customers. Our electric utilities monitor the deferral of under-collected costs to ensure that it does not cause them to earn a greater ROE than authorized by the PSCW. In contrast, the rates of our Michigan retail electric customers include recovery of fuel and purchased power costs on a one-for-one basis. In addition, the Wisconsin residential tariffs of WE and WPS include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates.

Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have our utilities provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric utilities and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis.

The transaction price of the performance obligations for wholesale customers is valued using the rates, charges, terms, and conditions of service, which have been approved by the FERC. These wholesale rates include recovery of fuel and purchased power costs from customers on a one-for-one basis. For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility's costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual current-year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services.

We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales, and net sales in a single hour are recorded as resale revenues on our income statements. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets.

For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days.

Natural Gas Utility Operating Revenues

We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under the tariffs of our regulated utilities. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In certain of our service territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer.

The transaction price of the performance obligations for our natural gas customers is valued using the rates, charges, terms, and conditions of service included in the tariffs of our regulated utilities, which have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month.

The tariffs of our natural gas utilities include various rate mechanisms that allow them to recover or refund changes in prudently incurred costs from rate case-approved amounts. The rates for all of our natural gas utilities include one-for-one recovery mechanisms for natural gas commodity costs. Under normal circumstances, we defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year.

In addition, the rates of PGL and NSG, and the residential tariffs of WE, WPS, and WG, include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. The rates of PGL and NSG include riders for cost recovery of both environmental cleanup costs and energy conservation and management program costs. Finally, through the end of 2023 and effective again starting January 1, 2025, the rates of MGU include a rider to recover costs incurred to replace or modify natural gas facilities.

Consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days.

Other Natural Gas Operating Revenues

We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment. Bluewater owns underground natural gas storage facilities in southeastern Michigan and provides natural gas storage and hub services to customers. Bluewater has entered into long-term service agreements for natural gas storage services with WE, WPS, and WG, and also provides limited service to unaffiliated customers. We recognize revenues using a time-based output method through a monthly fixed service fee. Typical storage contract rates consist of firm storage reservation charges and firm injection and withdrawal charges. All amounts associated with the service agreements with WE, WPS, and WG have been eliminated at the consolidated level.

Other Non-Utility Operating Revenues

Wind and solar generation revenues from WECI's ownership interests in renewable generation facilities continued to grow in 2025. See Note 2, Acquisitions, for more information on recent acquisitions. Most of these renewable generation facilities have offtake agreements with unaffiliated third parties for all of the energy to be produced by the facility, some of which are bundled with

capacity and RECs. We consider bundled energy, capacity, and RECs within these offtake agreements to be distinct performance obligations as each are often transacted separately in the marketplace.

When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Revenue from the sale of this renewable energy is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of the renewable generation facility and conveys the ability to call on the renewable generation facility to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis. The performance obligation for RECs is recognized at a point-in-time; however, the timing of revenue recognition is the same, as the generation of renewable energy and the recognition of REC revenues generally occur concurrently.

Non-utility operating revenues are also derived from servicing appliances for customers at MERC. These contracts customarily have a duration of one year or less and consist of a single performance obligation satisfied over time. We use a time-based output method to recognize revenues monthly for the service fee.

Consistent with the timing of when we recognize revenue, customer billings for the renewable generation and servicing revenues generally occur on a monthly basis, with payments typically due in full within 30 days.

As part of the construction of the We Power electric generating units, we capitalized interest during construction, which is included in property, plant, and equipment. As allowed by the PSCW, we collected these carrying costs from WE's utility customers during construction. The equity portion of these carrying costs was recorded as a contract liability, which is presented as deferred revenue, net on our balance sheets. We continually amortize the deferred carrying costs to revenues over the related lease term that We Power has with WE. During 2025, 2024, and 2023, we recorded $24.6 million, $24.3 million, and $23.5 million, respectively, of revenues related to these deferred carrying costs.

Other Operating Revenues

Bespoke Resources Current Return

We recognize revenues monthly associated with carrying costs, including financing costs, during the construction period of bespoke resources assigned to WE's very large utility customers under payment and cancellation agreements. These amounts are not considered revenues from contracts with customers as electricity is not yet being provided by WE. Consistent with the timing of when we recognize revenue, customer billings for the bespoke resources that are subject to current return (as opposed to AFUDC) occur on a monthly basis, with payments typically due in full within 45 days.

Alternative Revenues

Alternative revenues are created from programs authorized by regulators that allow our utilities to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. Alternative revenue programs allow compensation for the effects of weather abnormalities, other external factors, or demand side management initiatives. Alternative revenue programs can also provide incentive awards if the utility achieves certain objectives and in other limited circumstances. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers.

Below is a summary of the alternative revenue programs at our utilities:

•The rates of PGL, NSG, and MERC include decoupling mechanisms. These mechanisms differ by state and allow the utilities to recover or refund the differences between actual and authorized margins for certain customer classes.

•MERC’s rates include a conservation improvement program rider, which includes a financial incentive for meeting energy savings goals.

•WE and WPS provide wholesale electric service to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual

cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.

(e) Credit Losses—The following discussion includes our significant accounting policies related to credit losses. For additional required disclosures on credit losses, see Note 5, Credit Losses.

Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are primarily generated from the sale of electricity and natural gas by our regulated utility operations. Credit losses associated with our utility operations are analyzed at the reportable segment level as we believe contract terms, political and economic risks, and the regulatory environment are similar at this level as our reportable segments are generally based on the geographic location of the underlying utility operations.

We have an accounts receivable and unbilled revenue balance associated with our non-utility energy infrastructure segment, related to the sale of electricity from our majority-owned renewable generating facilities through agreements with several large high credit quality counterparties.

We evaluate the collectability of our accounts receivable and unbilled revenue balances considering a combination of factors. For some of our larger customers and also in circumstances where we become aware of a specific customer's inability to meet its financial obligations to us, we record a specific allowance for credit losses against amounts due in order to reduce the net recognized receivable to the amount we reasonably believe will be collected. For all other customers, we use the accounts receivable aging method to calculate an allowance for credit losses. Using this method, we classify accounts receivable into different aging buckets and calculate a reserve percentage for each aging bucket based upon historical loss rates. The calculated reserve percentages are updated on at least an annual basis, in order to ensure recent macroeconomic, political, and regulatory trends are captured in the calculation, to the extent possible. Risks identified that we do not believe are reflected in the calculated reserve percentages, are assessed on a quarterly basis to determine whether further adjustments are required.

We monitor our ongoing credit exposure through active review of counterparty accounts receivable balances against contract terms and due dates. Our activities include timely account reconciliation, dispute resolution and payment confirmation. To the extent possible, we work with customers with past due balances to negotiate payment plans, but will disconnect customers for non-payment as allowed by our regulators, if necessary, and employ collection agencies and legal counsel to pursue recovery of defaulted receivables. For our larger customers, detailed credit review procedures may be performed in advance of any sales being made. We sometimes require letters of credit, parental guarantees, prepayments or other forms of credit assurance from our larger customers, including VLCs, to mitigate credit risk.

(f) Materials, Supplies, and Inventories—Our inventories as of December 31 consisted of:


(in millions)	2025		2024
Materials and supplies	$	416.4	$	412.5
Natural gas in storage	292.5		300.2
Fossil fuel	94.5		100.5
Total	$	803.4	$	813.2

PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. Inventories stated on a LIFO basis represented approximately 17% and 18% of total inventories at December 31, 2025 and 2024, respectively. The estimated replacement cost of natural gas in inventory at December 31, 2025 and 2024, exceeded the LIFO cost by $94.9 million and $77.9 million, respectively. In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per Dth of $3.36 at December 31, 2025, and $3.10 at December 31, 2024.

Substantially all other materials and supplies, natural gas in storage, and fossil fuel inventories are recorded using the weighted-average cost method of accounting.

(g) Regulatory Assets and Liabilities—The economic effects of regulation can result in regulated companies recording costs and revenues that are allowed in the ratemaking process in a period different from the period they would have been recognized by a nonregulated company. When this occurs, regulatory assets and liabilities are recorded on the balance sheet. Regulatory assets represent deferred costs probable of recovery from customers that would have otherwise been charged to expense. Regulatory

liabilities represent amounts that are expected to be refunded to customers in future rates or future costs already collected from customers in rates.

The recovery or refund of regulatory assets and liabilities is based on specific periods determined by our regulators or occurs over the normal operating period of the related assets and liabilities. If a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery, and the reduction is charged to expense in the current period. See Note 6, Regulatory Assets and Liabilities, for more information.

(h) Property, Plant, and Equipment—We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to other operation and maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.

We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the applicable regulators. Annual utility composite depreciation rates are shown below:


Annual Utility Composite Depreciation Rates	2025	2024	2023
WE	3.07%	3.03%	3.03%
WPS	3.01%	2.92%	2.93%
WG	2.45%	2.61%	2.61%
PGL	3.34%	3.36%	3.13%
NSG	2.49%	2.49%	2.46%
MERC	2.62%	2.60%	2.60%
MGU	2.87%	2.87%	2.73%
UMERC	3.20%	3.01%	2.97%

We depreciate our We Power assets over the estimated useful life of the various property components. The components have useful lives of between 10 to 45 years for PWGS 1 and PWGS 2 and 10 to 55 years for ER 1 and ER 2.

We depreciate our WECI assets over the estimated useful life of the property, with wind and solar generating facilities being depreciated over 30 and 35 years, respectively.

We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 3 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement.

Third parties reimburse the utilities for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs are recorded as a reduction to property, plant, and equipment.

See Note 7, Property, Plant, and Equipment, for more information.

(i) Allowance for Funds Used During Construction—AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC-Debt) used during plant construction, and a return on shareholders' capital (AFUDC-Equity) used for construction purposes. AFUDC-Debt is recorded as a reduction of interest expense, and AFUDC-Equity is recorded in other income, net.

The majority of AFUDC is recorded at WE, WPS, WG, UMERC, and WBS. Approximately 50% of WE's, WPS's, WG's, UMERC's, and WBS's retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. AFUDC rates are determined by their respective state commissions, each with specific requirements. Average AFUDC rates are shown below:


	2025
	Average AFUDC Retail Rate	Average AFUDC Wholesale Rate
WE	8.65%	7.51%
WPS	7.82%	6.62%
WG	8.54%	N/A
UMERC	6.40%	N/A
WBS	7.82%	N/A

Our regulated utilities and WBS recorded the following AFUDC for the years ended December 31:


(in millions)	2025		2024		2023
AFUDC-Debt
WE	$	29.8	$	14.6	$	13.0
WPS	4.7		3.6		2.9
UMERC	3.4		0.4		—
WG	0.5		0.5		3.4
WBS	0.2		0.1		0.1
Other	0.4		0.2		0.1
Total AFUDC-Debt	$	39.0	$	19.4	$	19.5

AFUDC-Equity
WE	$	78.9	$	46.0	$	41.0
WPS	12.2		9.2		7.6
UMERC	6.3		1.0		—
WG	1.2		2.9		9.8
WBS	0.5		0.3		0.4
Other	0.7		0.4		0.3
Total AFUDC-Equity	$	99.8	$	59.8	$	59.1

See Note 16, Income Taxes, for more information on how AFUDC-Equity is treated for tax purposes and the related impact on total WEC Energy Group income tax expense.

(j) Cloud Computing Hosting Arrangements that are Service Contracts—We have entered into several cloud computing arrangements that are hosted service contracts as part of projects related to the continuous transformation of technology. These projects include, among other things, a centralized repository for data to improve analytics, reporting, work and asset management, targeted enterprise resource planning systems, human resources management, employee scheduling, geospatial information, training, information technology service management, and customer contact systems. We present prepaid hosting fees that are service contracts in either prepayments or other long-term assets on our balance sheets and amortize them as the hosting services are received. Amortization expense, as well as the fees associated with the hosting arrangements, is recorded in other operation and maintenance expense on our income statements.

At December 31, 2025 and 2024, we had $27.0 million and $17.0 million, respectively, of capitalized implementation costs related to cloud computing arrangements that are hosted service contracts. We amortize the implementation costs on a straight-line basis over the cloud computing service arrangement term once the component of the hosted service is ready for its intended use. Accumulated amortization at December 31, 2025 and 2024, was $5.8 million and $4.1 million, respectively. Amortization expense for the years ended December 31, 2025, 2024, and 2023 was not significant. The presentation of the implementation costs, along with the related accumulated amortization, follows the prepaid hosting fees.

(k) Asset Impairment—Goodwill and other intangible assets with indefinite lives are subject to an annual impairment test. Interim impairment tests are performed when impairment indicators are present. During the third quarter of each year, we perform an annual impairment test for all of our reporting units that carried a goodwill balance. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit's net assets exceeds the reporting unit's fair

value. An impairment loss is recorded as the excess of the carrying amount of the goodwill over its fair value. For our indefinite-lived intangible assets, an impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds its fair value. An impairment loss is measured as the excess of the carrying amount of the intangible asset over its fair value. No impairment losses were recorded for our indefinite-lived intangible assets during the years ended December 31, 2025, 2024, and 2023. See Note 10, Goodwill and Intangibles, for more information.

We periodically assess the recoverability of certain long-lived assets when factors indicate the carrying value of such assets may be impaired or such assets are planned to be sold. Long-lived assets that would be subject to an impairment assessment generally include any assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future, as well as assets within nonregulated operations that are proposed to be sold or are currently generating operating losses. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds its fair value. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset over its fair value.

We also periodically assess the recoverability of our non-utility long-lived assets, which includes reviewing current activities, changes in the conditions of our renewable generating facilities, and market conditions in which they operate to determine the existence of any indicators requiring an impairment analysis. Indicators of potential impairment for a non-utility long-lived asset group, generally an individual renewable generation project, include adverse changes in the financial condition of a customer to our offtake agreements, a significant decline in the forecasted operating revenues and earnings of our renewable generation projects, and deterioration in the performance of our renewable generation projects.

We assess the likelihood of a disallowance of part of the cost of recently completed plant by considering factors such as applicable regulatory environment changes, our own recent rate orders, as well as recent rate orders of other regulated entities in similar jurisdictions. When it becomes probable that part of the cost of recently completed plant will be disallowed for rate-making purposes, we assess whether a reasonable estimate of the amount of the disallowance can be made. The estimated amount of the probable disallowance will then be deducted from the reported cost of the plant and recognized as an impairment loss.

When it becomes probable that a generating unit will be retired before the end of its useful life, we assess whether the generating unit meets the criteria for abandonment accounting. Generating units that are considered probable of abandonment are expected to cease operations in the near term, significantly before the end of their original estimated useful lives. If a generating unit meets the applicable criteria to be considered probable of abandonment, and the unit has been abandoned, we assess the likelihood of recovery of the remaining net book value of that generating unit at the end of each reporting period. If it becomes probable that regulators will disallow full recovery as well as a return on the remaining net book value of a generating unit that is either abandoned or probable of being abandoned, an impairment loss may be required. An impairment loss would be recorded if the remaining net book value of the generating unit is greater than the present value of the amount expected to be recovered from ratepayers, using an incremental borrowing rate. See Note 6, Regulatory Assets and Liabilities, and Note 7, Property, Plant, and Equipment, for more information.

We periodically assess the recoverability of equity method investments when factors indicate the carrying amount of such assets may be impaired. Equity method investments are assessed for impairment by comparing the fair values of these investments to their carrying amounts if a fair value assessment was completed or by reviewing for the presence of impairment indicators. If an impairment exists, and it is determined to be other-than-temporary, an impairment loss is recognized equal to the amount by which the carrying amount exceeds the investment's fair value.

We recorded the following impairment losses on our income statements in the following segments during the years ended December 31:


(in millions)	2025			2024			2023
Illinois	$	130.0	(1)	$	12.1	(2)	$	178.9	(3)
Non-utility energy infrastructure (4)	15.9			—			—
Total impairment losses	$	145.9		$	12.1		$	178.9

(1) Represents a probable disallowance of certain capital costs at PGL under the QIP rider. See Note 26, Regulatory Environment, for more information.

(2) Represents a disallowance of certain previously incurred capital costs at PGL resulting from an ICC order received in August 2024 related to the 2016 annual prudency review of the QIP rider. See Note 26, Regulatory Environment, for more information.

(3) Represents a disallowance of certain previously incurred capital costs resulting from PGL's and NSG's November 2023 rate orders from the ICC. See Note 26, Regulatory Environment, for more information.

(4) Represents impairment losses related to storm damage at certain of WECI's renewable generation facilities.

(l) Asset Retirement Obligations—We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. An ARO liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The ARO liabilities are accreted each period using the credit-adjusted risk-free interest rates associated with the expected settlement dates of the AROs. These rates are determined when the obligations are incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated capitalized retirement costs. For our regulated entities, we recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. See Note 9, Asset Retirement Obligations, for more information.

(m) Finite-Lived Intangible Asset and Liabilities—Our finite-lived intangible asset and liabilities include revenue contracts, consisting of PPAs and a proxy revenue swap, in addition to interconnection agreements, which resulted from the acquisitions of renewable generation facilities by WECI in our non-utility energy infrastructure segment. Intangible asset and liabilities are amortized on a straight-line basis over their estimated useful lives, which is the term of the related agreement. Amortization of the revenue intangible asset and liabilities are recorded within operating revenues in the income statements. Amortization of the interconnection agreement intangible liabilities is recorded within other operation and maintenance in the income statements. The straight-line method of amortization is used because it best reflects the pattern in which the economic benefits of the intangibles are consumed or otherwise used. The amounts and useful lives assigned to the intangible asset and liabilities assumed impact the amount and timing of future amortization. See Note 10, Goodwill and Intangibles, for more information.

(n) Stock-Based Compensation—In accordance with the Omnibus Stock Incentive Plan, we provide long-term incentives through our equity interests to our non-employee directors, officers, and other key employees. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in common stock, cash, or a combination thereof. In addition to those shares of common stock that were subject to awards outstanding as of May 6, 2021, when the plan was last approved by shareholders, 9.0 million shares were reserved for issuance under the plan.

We recognize stock-based compensation expense on a straight-line basis over the requisite service period. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period. We account for forfeitures as they occur.

Stock Options

We grant non-qualified stock options that generally vest on a cliff-basis after three years. The exercise price of a stock option under the plan cannot be less than 100% of our common stock's fair market value on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of our common stock on the date of the grant. Options vest immediately upon retirement, death, or disability; however, they may not be exercised within six months of the grant date except in connection with certain termination of employment events following a change in control. Options expire no later than 10 years from the date of the grant.

Our stock options are classified as equity awards. The fair value of our stock options was calculated using a binomial option-pricing model. The following table shows the estimated weighted-average fair value per stock option granted along with the weighted-average assumptions used in the valuation models:


	2025			2024			2023
Stock options granted	231,024			294,990			257,780

Estimated weighted-average fair value per stock option	$	18.23		$	16.19		$	19.58

Assumptions used to value the options:
Risk-free interest rate	4.2% – 4.6%			3.9% – 5.4%			3.8% – 4.8%
Dividend yield	4.1		%	3.8		%	3.2		%
Expected volatility	22.0		%	22.0		%	22.0		%
Expected life (years)	8.3			8.4			8.3

The risk-free interest rate was based on the United States Treasury interest rate with a term consistent with the expected life of the stock options. The dividend yield was based on our dividend rate at the time of the grant and historical stock prices. Expected volatility and expected life assumptions were based on our historical experience.

Restricted Shares

Restricted shares granted to employees generally have a vesting period of three years with one-third of the award vesting on each anniversary of the grant date. Restricted shares granted to non-employee directors fully vest after one year.

Our restricted shares are classified as equity awards.

Performance Units

Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. All grants of performance units are settled in cash and are accounted for as liability awards accordingly. Performance units accrue forfeitable dividend equivalents in the form of additional performance units. The fair value of the performance units reflects our estimate of the final expected value of the awards, which is based on our stock price and performance achievement under the terms of the award. Stock-based compensation costs are generally recorded over the performance period, which is three years.

Pursuant to the terms of the WEC Energy Group Performance Unit Plan, the Compensation Committee selected multiple performance measures that will be weighted to determine the ultimate payout of the performance unit awards. The ultimate number of units that will be paid out will be based on our total shareholder return compared to the total shareholder return of a peer group of companies over three years (55%), and our performance against the weighted average authorized ROE of all of our utility subsidiaries (45%). In addition, the Compensation Committee selected the level of our stock price to earnings ratio compared to our peer companies as a performance measure that can increase the payout by up to 25%. In no event can the performance unit payout be greater than 200% of the target award.

See Note 11, Common Equity, for more information on our stock-based compensation plans.

(o) Earnings Per Share—We compute basic EPS by dividing our net income attributed to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted EPS is computed in a similar manner, but includes the exercise, settlement, and/or conversion of all potentially dilutive securities. Our potentially dilutive securities include stock options, forward equity sales contracts, and shares issuable upon the conversion of our convertible debt instruments.

The dilutive impacts from our in-the-money stock options and forward equity sales contract are calculated using the treasury stock method. The calculation of diluted EPS for the year ended December 31, 2025 excluded 58,533 shares issuable under our forward equity sales contract as their effect was anti-dilutive. The calculation of diluted EPS for the years ended December 31, 2024 and 2023 excluded 66,870 and 1,716,286 stock options, respectively, that had an anti-dilutive effect. No stock options had an anti-dilutive effect for the year ended December 31, 2025, and we did not have any forward equity sales contracts prior to 2025.

Potentially dilutive common shares issuable upon conversion of our convertible debt instruments are calculated using the if-converted method. For the year ended December 31, 2025, there were no shares of our common stock related to the potential conversion of the 2028 Notes (issued in June 2025) included in our diluted EPS calculation as the impact was anti-dilutive. For the year ended December 31, 2024, there were no shares of our common stock related to the potential conversion of the 2027 Notes and 2029 Notes (both issued in 2024) included in our diluted EPS calculation as the impact was anti-dilutive.

See Note 11, Common Equity, for more information on the computation of our basic and diluted EPS.

(p) Leases—We recognize a right of use asset and lease liability for operating and finance leases with a term of greater than one year. As a policy election, we account for each lease component separately from the nonlease components of a contract.

We are currently party to several easement agreements that allow us access to land we do not own for the purpose of constructing and maintaining certain electric power and natural gas equipment. The majority of payments we make related to easements relate to our renewable generating facilities. We have not classified our easements as leases because we view the entire parcel of land specified in our easement agreements to be the identified asset, not just that portion of the parcel that contains our easement. As such, we have concluded that we do not control the use of an identified asset related to our easement agreements, nor do we obtain substantially all of the economic benefits associated with these shared-use assets.

See Note 15, Leases, for more information.

(q) Income Taxes—In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments require additional disclosures, primarily related to income taxes paid and the rate reconciliation table. The amendments require disclosures on specific categories in the rate reconciliation table, as well as additional information for reconciling items that meet a quantitative threshold. For income taxes paid, additional disclosures are required to disaggregate federal, state, and foreign income taxes paid, with additional disclosures for income taxes paid that meet a quantitative threshold. We adopted ASU No. 2023-09 on January 1, 2025, on a retroactive basis, with the required disclosures first included in our 2025 Annual Report on Form 10-K.

We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense.

ITCs are deferred and amortized over the life of the assets. PTCs are recognized in the period in which such credits are generated. The amount of the credit is based upon power production from our qualifying generation facilities. We file a consolidated federal income tax return. Accordingly, we allocate federal current tax expense, benefits, and credits to our subsidiaries based on their separate tax computations and our ability to monetize all credits on our consolidated federal return.

We recognize interest and penalties accrued, related to unrecognized tax benefits, in income tax expense in our income statements.

The IRA contains a tax credit transferability provision that allows us to sell PTCs and ITCs produced after December 31, 2022, to third parties. Under this transferability provision, we entered into agreements to sell the majority of the PTCs and ITCs we generated in 2023, 2024, and 2025 to third parties. See Note 16, Income Taxes, for more information on the PTCs we sold. We have also entered into an agreement to sell the majority of PTCs that we expect to generate in 2026 to third parties. We elect to account for tax credits transferred under the scope of ASC 740. We include the discount from the sale of tax credits as a component of income tax expense. We also include any expected proceeds from the sale of tax credits in the evaluation of the realizability of deferred tax assets related to PTCs and ITCs. The sale of tax credits is presented in the operating activities section of the statements of cash flows consistent with the presentation of cash taxes paid.

In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized for tax purposes. We adopted the safe harbor method of accounting for certain of our utilities on our 2023 tax return

and adopted the safe harbor method of accounting for our remaining utilities on our 2024 tax return, which increased our deferred tax liabilities.

See Note 16, Income Taxes, for more information.

(r) Fair Value Measurements—Fair value is 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).

Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

When possible, we base the valuations of our assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives, such as FTRs and TCRs, are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. FTRs and TCRs are valued using auction prices from the applicable RTO.

See Note 17, Fair Value Measurements, for more information.

(s) Derivative Instruments—We use derivatives as part of our risk management program to manage the risks associated with the price volatility of interest rates, purchased power, generation, and natural gas costs for the benefit of our customers and shareholders. Our approach is non-speculative and designed to mitigate risk. Regulated hedging programs are approved by our state regulators.

We record derivative instruments on our balance sheets as assets or liabilities measured at fair value unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities.

We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows.

Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets, and cash collateral received is reflected in other current liabilities. See Note 18, Derivative Instruments, for more information.

(t) Guarantees—We follow the guidance of the Guarantees Topic of the FASB ASC, which requires, under certain circumstances, that the guarantor recognize a liability for the fair value of the obligation undertaken in issuing the guarantee at its inception. See Note 19, Guarantees, for more information.

(u) Employee Benefits—The costs of pension and OPEB plans are expensed over the periods during which employees render service. These costs are distributed among our subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for the utilities' net periodic benefit cost calculated under GAAP. See Note 20, Employee Benefits, for more information.

(v) Customer Deposits and Credit Balances—When utility customers apply for new service, they may be required to provide a deposit for the service. Customer deposits are recorded within other current liabilities on our balance sheets.

Utility customers can elect to be on a budget plan. Under this type of plan, a monthly installment amount is calculated based on estimated annual usage. During the year, the monthly installment amount is reviewed by comparing it to actual usage. If necessary, an adjustment is made to the monthly amount. Annually, the budget plan is reconciled to actual annual usage. Payments in excess of actual customer usage are recorded within other current liabilities on our balance sheets.

(w) Environmental Remediation Costs—We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including CCR landfills and manufactured gas plant sites. See Note 9, Asset Retirement Obligations, for more information regarding CCR landfills and Note 24, Commitments and Contingencies, for more information regarding manufactured gas plant sites.

We record environmental remediation liabilities when site assessments indicate remediation is probable, and we can reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potentially responsible parties or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation.

Our utilities have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the applicable state regulatory commission's approval.

We review our estimated costs of remediation annually for our manufactured gas plant sites and CCR landfills. We adjust the liabilities and related regulatory assets, as appropriate, to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year.

(x) Customer Concentrations of Credit Risk—The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Although we have a comprehensive credit evaluation process and contractual protections, it is possible that one or more counterparties could fail to perform their obligations, and we could recognize financial losses as a result. Credit risk exposure at WE, WPS, WG, PGL, and NSG is mitigated by their recovery mechanisms for uncollectible expense discussed in Note 1(d), Operating Revenues. There were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2025.

As a result, for the majority of our utility companies, we did not have any significant concentrations of credit risk at December 31, 2025. However, WE has contracts with a small number of customers to provide power to large-scale data centers to support AI and other technology capabilities. This concentration of business with a small number of customers in an industry based on emerging technologies presents several risks. WE is incurring significant costs to construct bespoke resources to serve these customers. Although WE requires these customers to enter into payment and cancellation agreements, WE may still experience significant losses or delayed recovery of these costs. Changes in industry practice or advances in these technologies could reduce the demand for electricity to power data centers, which would reduce our forecasted revenues. Significant capital spend to build out required infrastructure or a downturn in business could weaken their financial condition, liquidity and/or creditworthiness, including their ability to satisfy their reimbursement obligations to us.

Acquisitions

12 Months Ended

Dec. 31, 2025

Asset Acquisition [Abstract]

Asset Acquisition [Text Block]

ACQUISITIONS

In accordance with Topic 805: Clarifying the Definition of a Business (ASU 2017-01), transactions are evaluated and are accounted for as acquisitions of assets or businesses, and transaction costs are capitalized in asset acquisitions. It was determined that all of the below acquisitions met the criteria of asset acquisitions. The purchase price of certain acquisitions below includes intangibles recorded as long-term assets and long-term liabilities related to PPAs. See Note 10, Goodwill and Intangibles, for more information.

Acquisition of a Solar Generation Facility in Ohio

Upon commercial operation in February 2025, WECI completed the acquisition of a 90% ownership interest in Hardin III, a 250 MW solar generating facility located in Hardin County, Ohio for $406.1 million. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years from the date of commercial operation. Hardin III qualifies for PTCs and is included in the non-utility energy infrastructure segment.

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition.


(in millions)
Net property, plant, and equipment	$	526.5
Other current assets	0.2
Other current liabilities	(0.4)
Other long-term liabilities	(75.1)
Noncontrolling interest	(45.1)
Total purchase price	$	406.1

Acquisitions of Solar Generation Facilities in Texas

Upon commercial operation in December 2024, WECI completed the acquisition of a 90% ownership interest in Delilah I, a 300 MW solar generating facility in Lamar, Franklin, Hopkins, and Red River counties in Texas. Delilah I was acquired for $462.5 million, which included transaction costs and was net of cash acquired. The project has offtake agreements for all of the energy to be produced by the facility for a period of 15 years from the date of commercial operation. Delilah I qualifies for PTCs and is included in the non-utility energy infrastructure segment.

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition.


(in millions)
Other current assets	$	0.1
Net property, plant, and equipment	579.8
Other long-term assets	12.4
Other long-term liabilities	(78.3)
Noncontrolling interest	(51.5)
Total purchase price	$	462.5

In February 2023, WECI completed the acquisition of an 80% ownership interest in Samson I, a commercially operational 250 MW solar generating facility in Lamar, Franklin, Hopkins, and Red River counties in Texas. Samson I was acquired for $257.3 million, which included transaction costs and was net of cash acquired. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years from the date of commercial operation in May 2022. Samson I qualifies for PTCs and is included in the non-utility energy infrastructure segment. In January 2024, WECI acquired an additional 10% ownership interest in Samson I for $28.1 million.

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the original acquisition.


(in millions)
Accounts receivable	$	0.5
Other current assets	0.7
Net property, plant, and equipment	497.2
Other long-term assets	12.3
Accounts payable	(0.5)
Other current liabilities	(0.8)
Other long-term liabilities	(186.4)
Noncontrolling interest	(65.7)
Total purchase price	$	257.3

Acquisitions of Electric Generation Facilities in Illinois

Upon commercial operation in November 2024, WECI completed the acquisition of a 90% ownership interest in Maple Flats, a 250 MW solar generating facility in Clay County, Illinois. Maple Flats was acquired for $431.2 million, which included transaction costs and was net of cash acquired. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years from the date of commercial operation. Maple Flats qualifies for PTCs and is included in the non-utility energy infrastructure segment.

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition.


(in millions)
Net property, plant, and equipment	$	469.5
Other long-term assets	44.5
Other long-term liabilities	(34.9)
Noncontrolling interest	(47.9)
Total purchase price	$	431.2

In February 2023, upon achievement of commercial operation, WECI completed the acquisition of a 90% ownership interest in Sapphire Sky, a 250 MW wind generating facility in McLean County, Illinois, for a total investment of $442.6 million, which includes transaction costs and is net of cash acquired. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 12 years from the date of commercial operation. Sapphire Sky qualifies for PTCs and is included in the non-utility energy infrastructure segment.

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition.


(in millions)
Accounts receivable	$	0.8
Net property, plant, and equipment	642.6
Other long-term assets	1.4
Accounts payable	(1.0)
Other long-term liabilities	(152.0)
Noncontrolling interest	(49.2)
Total purchase price	$	442.6

Acquisitions of Electric Generation Facilities in Wisconsin

In December 2025, WE and WPS, along with an unaffiliated utility, signed an agreement to acquire Whitetail, a wind-powered electric generation project with a total capacity of 67.2 MW. This project will be located in Grant County, Wisconsin and WE will own 80% and WPS will own 10%. WE's share of the purchase price is expected to be approximately $178 million and WPS's share of the purchase price is expected to be approximately $22 million. The project is expected to close in late 2027 and it is expected to qualify for PTCs.

In May 2024, WE completed the acquisition of an additional 100 MWs of West Riverside's nameplate capacity for $97.9 million. West Riverside is a commercially operational dual fueled combined cycle generation facility in Beloit, Wisconsin. In June 2023, WE completed the first acquisition of 100 MWs for $95.3 million. After the second acquisition, WE owns 200 MWs, or 27.5%, of West Riverside at a total cost of $193.2 million.

In April 2023, WPS, along with an unaffiliated utility, completed the acquisition of Red Barn, a commercially operational utility-scale wind-powered electric generating facility. The project is located in Grant County, Wisconsin and WPS owns 82 MWs of this project. WPS's share of the cost of this project was $145.9 million. Red Barn qualifies for PTCs.

In January 2023, WE and WPS completed the acquisition of Whitewater, a commercially operational 236.5 MW dual fueled (natural gas and low sulfur fuel oil) combined cycle electric generation facility in Whitewater, Wisconsin, for $76.0 million.

Dispositions	12 Months Ended
Dispositions	Dec. 31, 2025
Discontinued Operations and Disposal Groups [Abstract]
DISPOSITIONS	DISPOSITION Wisconsin Segment Sale of Certain Real Estate by Wisconsin Electric Power Company In June 2023, we sold approximately 192 acres of real estate at WE's former Pleasant Prairie power plant site that was no longer being utilized in its operations, for $23.0 million, which is net of closing costs. As a result of the sale, a pre-tax gain in the amount of $22.2 million was recorded within other operation and maintenance expense on our income statement. The book value of the real estate included in the sale was not material and, therefore, was not presented as held for sale.

Operating Revenues

12 Months Ended

Dec. 31, 2025

Revenue from Contract with Customer [Abstract]

OPERATING REVENUES

For more information about our significant accounting policies related to operating revenues, see Note 1(d), Operating Revenues.

Disaggregation of Operating Revenues

The following tables present our operating revenues disaggregated by revenue source. We do not have any revenues associated with our electric transmission segment, which includes investments accounted for using the equity method. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors. For our segments, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations has different expectations of service, energy and demand requirements, and can be impacted differently by regulatory activities within their jurisdictions.


(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations			WEC Energy Group Consolidated
Year ended December 31, 2025
Electric	$	5,529.6	$	—	$	—	$	5,529.6	$	—	$	—	$	—		$	5,529.6
Natural gas	1,741.6		1,717.6		508.1		3,967.3		47.0		—		(44.5)			3,969.8
Total regulated revenues	7,271.2		1,717.6		508.1		9,496.9		47.0		—		(44.5)			9,499.4
Other non-utility revenues	—		—		21.8		21.8		243.6		—		(9.2)			256.2
Total revenues from contracts with customers	7,271.2		1,717.6		529.9		9,518.7		290.6		—		(53.7)			9,755.6
Other operating revenues	24.3		(34.0)		(2.4)		(12.1)		479.6		—		(423.0)		(1)	44.5
Total operating revenues	$	7,295.5	$	1,683.6	$	527.5	$	9,506.6	$	770.2	$	—	$	(476.7)		$	9,800.1


(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations			WEC Energy Group Consolidated
Year ended December 31, 2024
Electric	$	4,908.4	$	—	$	—	$	4,908.4	$	—	$	—	$	—		$	4,908.4
Natural gas	1,402.4		1,499.6		419.7		3,321.7		48.4		—		(46.0)			3,324.1
Total regulated revenues	6,310.8		1,499.6		419.7		8,230.1		48.4		—		(46.0)			8,232.5
Other non-utility revenues	—		—		20.4		20.4		223.9		—		(9.1)			235.2
Total revenues from contracts with customers	6,310.8		1,499.6		440.1		8,250.5		272.3		—		(55.1)			8,467.7
Other operating revenues	19.7		102.8		9.7		132.2		419.0		—		(419.0)		(1)	132.2
Total operating revenues	$	6,330.5	$	1,602.4	$	449.8	$	8,382.7	$	691.3	$	—	$	(474.1)		$	8,599.9


(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations			WEC Energy Group Consolidated
Year Ended December 31, 2023
Electric	$	4,994.6	$	—	$	—	$	4,994.6	$	—	$	—	$	—		$	4,994.6
Natural gas	1,606.7		1,480.5		493.7		3,580.9		61.9		—		(60.2)			3,582.6
Total regulated revenues	6,601.3		1,480.5		493.7		8,575.5		61.9		—		(60.2)			8,577.2
Other non-utility revenues	—		—		19.6		19.6		197.5		0.1		(9.1)			208.1
Total revenues from contracts with customers	6,601.3		1,480.5		513.3		8,595.1		259.4		0.1		(69.3)			8,785.3
Other operating revenues	24.6		77.3		5.8		107.7		407.1		—		(407.1)		(1)	107.7
Total operating revenues	$	6,625.9	$	1,557.8	$	519.1	$	8,702.8	$	666.5	$	0.1	$	(476.4)		$	8,893.0

(1) Amounts eliminated represent lease revenues related to certain plants that We Power leases to WE to supply electricity to its customers. Lease payments are billed from We Power to WE and then recovered in WE's rates as authorized by the PSCW and the FERC. WE operates the plants and is authorized by the PSCW and Wisconsin state law to fully recover prudently incurred operating and maintenance costs in electric rates.

Revenues from Contracts with Customers

Electric Utility Operating Revenues

The following table disaggregates electric utility operating revenues into customer class:


	Year Ended December 31
(in millions)	2025		2024		2023
Residential	$	2,249.6	$	1,996.3	$	1,992.3
Small commercial and industrial	1,763.6		1,613.0		1,641.1
Large commercial and industrial	1,057.8		942.6		978.4
Other	30.9		30.2		30.5
Total retail revenues	5,101.9		4,582.1		4,642.3
Wholesale	107.6		102.6		120.4
Resale	267.6		176.7		195.4
Steam	28.4		22.4		25.2
Other utility revenues	24.1		24.6		11.3
Total electric utility operating revenues	$	5,529.6	$	4,908.4	$	4,994.6

Natural Gas Utility Operating Revenues

The following tables disaggregate natural gas utility operating revenues into customer class:


(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Year ended December 31, 2025
Residential	$	1,100.2	$	1,174.9	$	316.5	$	2,591.6
Commercial and industrial	563.9		320.0		164.4		1,048.3
Total retail revenues	1,664.1		1,494.9		480.9		3,639.9
Transportation	105.1		291.8		38.8		435.7
Other utility revenues (1) (2)	(27.6)		(69.1)		(11.6)		(108.3)
Total natural gas utility operating revenues	$	1,741.6	$	1,717.6	$	508.1	$	3,967.3


(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Year ended December 31, 2024
Residential	$	893.1	$	945.5	$	250.5	$	2,089.1
Commercial and industrial	416.8		274.5		123.9		815.2
Total retail revenues	1,309.9		1,220.0		374.4		2,904.3
Transportation	96.8		272.2		33.6		402.6
Other utility revenues (1)	(4.3)		7.4		11.7		14.8
Total natural gas utility operating revenues	$	1,402.4	$	1,499.6	$	419.7	$	3,321.7


(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Year Ended December 31, 2023
Residential	$	1,012.0	$	966.0	$	324.4	$	2,302.4
Commercial and industrial	506.7		267.1		175.3		949.1
Total retail revenues	1,518.7		1,233.1		499.7		3,251.5
Transportation	93.0		231.9		32.5		357.4
Other utility revenues (1)	(5.0)		15.5		(38.5)		(28.0)
Total natural gas utility operating revenues	$	1,606.7	$	1,480.5	$	493.7	$	3,580.9

(1) Includes the revenues subject to the purchased gas recovery mechanisms of our utilities, which fluctuate by segment based on actual natural gas costs incurred at our utilities, compared with the recovery of natural gas costs that were anticipated in rates.

(2) For our Illinois segment, includes a $75.0 million reduction in revenues recorded in the fourth quarter of 2025 for future billing credits to customers, based on the terms of a proposed settlement in February 2026 to resolve open QIP and UEA proceedings.

Other Non-Utility Operating Revenues

Other non-utility operating revenues consist primarily of the following:


	Year Ended December 31
(in millions)	2025		2024		2023
Renewable generation revenues	$	209.8	$	190.5	$	164.9
We Power revenues	24.6		24.3		23.5
Appliance service revenues	21.8		20.4		19.6

Other	—		—		0.1
Total other non-utility operating revenues	$	256.2	$	235.2	$	208.1

Other Operating Revenues

Other operating revenues consist primarily of the following:


	Year Ended December 31
(in millions)	2025		2024		2023
Late payment charges	$	48.1	$	48.5	$	56.5
Bespoke resources current return (1)	4.1		—		—
Alternative revenues (2)	(67.7)		79.8		47.0
Other	60.0		3.9		4.2
Total other operating revenues	$	44.5	$	132.2	$	107.7

(1) Bespoke resources current return consists of carrying costs earned during the construction of bespoke resources assigned to WE's VLCs. See Note 1(d), Operating Revenues, for more information.

(2) Alternative revenues consist of amounts to be recovered or refunded to customers subject to decoupling mechanisms, wholesale true-ups, and conservation improvement rider true-ups. Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. For more information about our alternative revenues, see Note 1(d), Operating Revenues.

- Definition

The entire disclosure of revenue from contract with customer to transfer good or service and to transfer nonfinancial asset. Includes, but is not limited to, disaggregation of revenue, credit loss recognized from contract with customer, judgment and change in judgment related to contract with customer, and asset recognized from cost incurred to obtain or fulfill contract with customer. Excludes insurance and lease contracts.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 7
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-7

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 9
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-9

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 10
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-10

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 15
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-15

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (b)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-13

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Name Accounting Standards Codification
-Topic 606
-Publisher FASB
-URI https://asc.fasb.org/606/tableOfContent

+ Details

Credit Losses

12 Months Ended

Dec. 31, 2025

Credit Loss [Abstract]

CREDIT LOSSES

We have included tables below that show our gross third-party receivable balances and the related allowance for credit losses at December 31, 2025 and 2024, by reportable segment.


(in millions)	Wisconsin			Illinois			Other States			Total Utility Operations			Non-Utility Energy Infrastructure			Corporate and Other			WEC Energy Group Consolidated
December 31, 2025
Accounts receivable and unbilled revenues	$	1,368.8		$	654.8		$	130.2		$	2,153.8		$	50.3		$	7.3		$	2,211.4
Allowance for credit losses	61.7			82.3			4.7			148.7			—			—			148.7
Accounts receivable and unbilled revenues, net (1)	$	1,307.1		$	572.5		$	125.5		$	2,005.1		$	50.3		$	7.3		$	2,062.7

Total accounts receivable, net – past due greater than 90 days (1)	$	46.4		$	36.8		$	6.6		$	89.8		$	—		$	—		$	89.8
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	94.6		%	100.0		%	—		%	89.9		%	—		%	—		%	89.9		%


(in millions)	Wisconsin			Illinois			Other States			Total Utility Operations			Non-Utility Energy Infrastructure			Corporate and Other			WEC Energy Group Consolidated
December 31, 2024
Accounts receivable and unbilled revenues	$	1,149.9		$	535.6		$	100.6		$	1,786.1		$	40.0		$	6.0		$	1,832.1
Allowance for credit losses	73.6			83.9			5.3			162.8			—			—			162.8
Accounts receivable and unbilled revenues, net (1)	$	1,076.3		$	451.7		$	95.3		$	1,623.3		$	40.0		$	6.0		$	1,669.3

Total accounts receivable, net – past due greater than 90 days (1)	$	51.8		$	30.1		$	2.5		$	84.4		$	—		$	—		$	84.4
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	93.8		%	100.0		%	—		%	93.2		%	—		%	—		%	93.2		%

(1) Our exposure to credit losses for certain regulated utility customers is mitigated by regulatory mechanisms we have in place. Specifically, rates related to all of the customers in our Illinois segment, as well as the residential rates of WE, WPS, and WG in our Wisconsin segment, include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between the actual provision for credit losses and the amounts recovered in rates. As a result, at December 31, 2025, $1,290.2 million, or 62.5%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. See Note 26, Regulatory Environment, for more information on PGL and NSG's UEA rider for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and amounts recovered in rates.

A rollforward of the allowance for credit losses by reportable segment for the years ended December 31, 2025, 2024, and 2023, is included below:


(in millions)	Wisconsin		Illinois		Other States		WEC Energy Group Consolidated
Balance at January 1, 2025	$	73.6	$	83.9	$	5.3	$	162.8
Provision for credit losses	85.0		55.8		2.0		142.8
Provision for credit losses deferred for future recovery or refund	4.9		(28.7)		—		(23.8)
Write-offs charged against the allowance	(151.4)		(81.2)		(8.4)		(241.0)
Recoveries of amounts previously written off	49.6		52.5		5.8		107.9
Balance at December 31, 2025	$	61.7	$	82.3	$	4.7	$	148.7

On a consolidated basis, there was a $14.1 million decrease in the allowance for credit losses during the year ended December 31, 2025. This decrease is largely driven by customer write-offs in Wisconsin in addition to a decrease in past due account balances in Wisconsin that we believe was related to a continued focus on collection efforts and lower energy bills in the spring and summer months, enabling customers to pay down their arrears.


(in millions)	Wisconsin		Illinois		Other States		WEC Energy Group Consolidated
Balance at January 1, 2024	$	77.4	$	109.7	$	6.4	$	193.5
Provision for credit losses	52.1		52.3		0.5		104.9
Provision for credit losses deferred for future recovery or refund	43.8		(8.0)		—		35.8
Write-offs charged against the allowance	(141.8)		(95.0)		(6.6)		(243.4)
Recoveries of amounts previously written off	42.1		24.9		5.0		72.0
Balance at December 31, 2024	$	73.6	$	83.9	$	5.3	$	162.8

On a consolidated basis, there was a $30.7 million decrease in the allowance for credit losses during the year ended December 31, 2024, largely driven by customer write-offs. We also believe that the lower energy costs that customers were seeing, which were driven by warmer than normal weather conditions during most of 2024 and low average natural gas prices, contributed to a reduction in past due accounts receivable balances and a related decrease in the allowance for credit losses.


(in millions)	Wisconsin		Illinois		Other States		WEC Energy Group Consolidated
Balance at January 1, 2023	$	82.0	$	111.0	$	6.3	$	199.3
Provision for credit losses	40.9		26.3		4.8		72.0
Provision for credit losses deferred for future recovery or refund	52.5		35.8		—		88.3
Write-offs charged against the allowance	(131.6)		(85.4)		(6.6)		(223.6)
Recoveries of amounts previously written off	33.6		22.0		1.9		57.5
Balance at December 31, 2023	$	77.4	$	109.7	$	6.4	$	193.5

On a consolidated basis, there was a $5.8 million decrease in the allowance for credit losses during the year ended December 31, 2023, primarily related to lower customer energy costs (driven by the warmer weather during the fourth quarter of 2023 when compared to the same quarter in 2022 and lower natural gas prices), which contributed to a reduction in past due accounts receivable balances and a related decrease in the allowance for credit losses. Customer write-offs also contributed to the decrease in the allowance for credit losses.

- Definition

The entire disclosure for credit loss on financial instrument measured at amortized cost basis, net investment in lease, off-balance sheet credit exposure, and available-for-sale debt security.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 310
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 42
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481962/310-10-50-42

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 310
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 44
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481962/310-10-50-44

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 326
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479319/326-20-50-5

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 326
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479319/326-20-50-21

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 326
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 4
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479106/326-30-50-4

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 326
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 11
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479319/326-20-50-11

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 326
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 7
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479106/326-30-50-7

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 326
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 8
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479319/326-20-50-8

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 326
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 20
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479319/326-20-50-20

+ Details

Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2025

Regulatory Assets and Liabilities Disclosure [Abstract]

REGULATORY ASSETS AND LIABILITIES

The following regulatory assets were reflected on our balance sheets as of December 31:


(in millions)	2025		2024		See Note
Regulatory assets (1) (2)
Plant retirement related items (3)	$	768.6	$	810.5
Environmental remediation costs (4)	566.0		570.1		24
Pension and OPEB costs (5)	564.5		684.9		20, 26
Income tax related items	493.4		438.5		16
AROs	185.1		166.7		1(l), 9
Uncollectible expense	123.9		151.5		5
SSR (6)	92.6		102.9
Securitization	67.5		76.5		23
Derivatives	57.7		38.2		1(s)
Decoupling	43.8		110.0		1(d)
Bluewater (7)	37.7		57.7
Finance and operating leases	36.0		22.0		15
Electric transmission costs (8)	30.7		0.4
Energy efficiency programs (9)	11.6		26.5
Other, net	94.5		122.3
Total regulatory assets	$	3,173.6	$	3,378.7

Balance sheet presentation
Other current assets	$	17.3	$	39.0
Regulatory assets	3,156.3		3,339.7
Total regulatory assets	$	3,173.6	$	3,378.7

(1) Based on prior and current rate treatment, we believe it is probable that our utilities will continue to recover from customers the regulatory assets in this table. In accordance with GAAP, our regulatory assets do not include the allowance for ROE that is capitalized for regulatory purposes. This allowance was $20.9 million and $26.7 million at December 31, 2025 and 2024, respectively.

(2) As of December 31, 2025, we had $183.1 million of regulatory assets not earning a return, $1.3 million of regulatory assets earning a return based on short-term interest rates, $106.1 million of regulatory assets earning a return based on long-term interest rates, and $5.5 million of regulatory assets earning a return based on the applicable utility's ROE. The regulatory assets not earning a return primarily relate to certain environmental remediation costs, decoupling mechanisms, electric transmission costs, unamortized loss on reacquired debt, and uncollectible expense. The other regulatory assets in the table either earn a return at the applicable utility's weighted average cost of capital or the cash has not yet been expended, in which case the regulatory assets are offset by liabilities.

(3) Primarily represents the net book value of power plants we have both abandoned and retired. For all of these plants, we have approval to collect a return of their remaining net book value. We also have approval to collect a return on all but $100 million of their remaining net book value. For information on the securitization of this $100 million, see Note 23, Variable Interest Entities. These regulatory assets are amortized on a straight-line basis, using the composite depreciation rates approved before the plants were retired, and the amortization is included in depreciation and amortization in the income statement.

(4) As of December 31, 2025, we had made cash expenditures of $81.9 million related to these environmental remediation costs. The remaining $484.1 million represents our estimated future cash expenditures.

(5) Primarily represents the unrecognized future pension and OPEB costs related to our defined benefit pension and OPEB plans. We are authorized recovery of these regulatory assets over the average remaining service life of each plan.

(6) This regulatory asset relates to WE's 2014 announcement to retire the PIPP. Despite WE's intent to retire the PIPP, MISO designated the PIPP as a SSR, which meant the PIPP's operation was necessary for reliability, and the plant could not be shut down until new generation or transmission facilities were built. In December 2014, the PSCW authorized escrow accounting for WE's SSR revenues because of the fluctuations in the actual revenues WE received under the PIPP SSR agreements. The rate order WE received from the PSCW in December 2019 authorized recovery of this SSR regulatory asset over a 15-year period that began on January 1, 2020.

(7) Primarily relates to costs associated with the long-term service agreements our Wisconsin utilities have with Bluewater for natural gas storage services. The PSCW has approved escrow accounting for these costs. As a result, our Wisconsin utilities defer as a regulatory asset or liability the difference between actual storage costs and those included in rates until recovery or refund is authorized in a future rate proceeding.

(8) In accordance with the PSCW's approval of escrow accounting for ATC and MISO network transmission expenses for our Wisconsin electric utilities, WE and WPS defer as a regulatory asset or liability the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding.

(9) Represents amounts recoverable from customers related to programs at the utilities designed to meet energy efficiency standards.

The following regulatory liabilities were reflected on our balance sheets as of December 31:


(in millions)	2025		2024		See Note
Regulatory liabilities
Income tax related items	$	1,802.4	$	1,825.4	16
Removal costs (1)	1,584.7		1,458.2
Pension and OPEB benefits (2)	301.5		308.5		20, 26
Proposed settlement related to QIP and UEA riders	125.0		—		26
Energy costs refundable through rate adjustments	119.2		160.8		1(d)
Uncollectible expense	73.1		47.2		5
Earnings sharing mechanisms	35.8		7.1		26
Derivatives	27.4		36.9		1(s)
MERC property tax tracker (3)	23.1		19.3
Revenue requirements of renewable generation facilities (4)	14.5		44.2
Other, net	103.5		95.7
Total regulatory liabilities	$	4,210.2	$	4,003.3

Balance sheet presentation
Other current liabilities	$	88.9	$	45.3
Regulatory liabilities	4,121.3		3,958.0
Total regulatory liabilities	$	4,210.2	$	4,003.3

(1) Represents amounts collected from customers to cover the future cost of property, plant, and equipment removals that are not legally required. Legal obligations related to the removal of property, plant, and equipment are recorded as AROs. See Note 9, Asset Retirement Obligations, for more information on our legal obligations.

(2) Primarily represents the unrecognized future pension and OPEB benefits related to our defined benefit pension and OPEB plans. We will amortize these regulatory liabilities into net periodic benefit cost over the average remaining service life of each plan.

(3) MERC defers as a regulatory asset or liability the difference between actual property tax expense and the amount included in rates until

recovery or refund is authorized in a future rate proceeding.

(4) These amounts represent the deferral of the incremental revenue requirement impact from the delayed in-service date of certain renewable generation facilities constructed by our electric utilities.

Oak Creek Power Plant Units 5-6

In May 2024, OCPP Units 5 and 6 were retired. Due to the retirement of these units and the determination that recovery was probable, their net book value of $68.3 million at December 31, 2025 was classified as a regulatory asset. In addition, a $45.0 million cost of removal reserve related to the units continued to be classified as a regulatory liability at December 31, 2025. Not included in these amounts was $6.3 million of deferred tax liabilities previously recorded for the retired units. Effective with its rate order issued by the PSCW in December 2022, WE received approval to collect a return of and on the entire net book value of OCPP Units 5 and 6 and, as a result, will continue to amortize the regulatory asset on a straight-line basis, using the composite depreciation rates approved by the PSCW before the units were retired. The amortization is included in depreciation and amortization on the income statement. WE also has FERC approval to continue to collect the net book value of OCPP Units 5 and 6 using the approved composite depreciation rates, in addition to a return on the remaining net book value.

Property, Plant, and Equipment

12 Months Ended

Dec. 31, 2025

Property, Plant and Equipment [Abstract]

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT, AND EQUIPMENT

Property, plant, and equipment consisted of the following at December 31:


(in millions)	2025		2024
Electric – generation	$	7,998.3	$	6,685.0
Electric – distribution	10,048.9		9,298.9
Natural gas – distribution, storage, and transmission	16,175.0		15,673.0
Property, plant, and equipment to be retired, net	621.7		906.3
Other	2,431.2		2,410.8
Less: Accumulated depreciation	10,180.2		9,401.0
Net	27,094.9		25,573.0
CWIP	3,364.4		1,653.6
Net utility and non-utility property, plant, and equipment	30,459.3		27,226.6

We Power generation	3,250.7		3,284.3
Renewable generation	5,252.4		4,720.8
Natural gas storage	299.6		298.6
Net non-utility energy infrastructure	8,802.7		8,303.7
Corporate services	167.6		172.3
Other	11.3		14.1
Less: Accumulated depreciation	1,559.1		1,393.9
Net	7,422.5		7,096.2
CWIP	60.8		41.3
Net other property, plant, and equipment	7,483.3		7,137.5

Property under finance leases	351.8		291.3
Less: Accumulated amortization	16.3		10.0
Net leased facilities	335.5		281.3

Total property, plant, and equipment	$	38,278.1	$	34,645.4

Severance Liability for Plant Retirements

We have severance liabilities related to past and future plant retirements recorded in other current and other long-term liabilities on our balance sheets. Activity related to these severance liabilities for the years ended December 31 was as follows:


(in millions)	2025		2024			2023
Severance liability at January 1	$	13.4	$	17.8		$	16.2
Severance expense	—		(3.9)		(1)	1.6
Severance payments	(0.7)		(0.5)			—

Total severance liability at December 31	$	12.7	$	13.4		$	17.8

(1) The severance accrual was lowered in 2024 due to workforce realignment efforts.

Wisconsin Segment Plant to be Retired

Oak Creek Power Plant Units 7 and 8

As a result of a PSCW approval in December 2022 for the acquisition and construction of Darien, the retirement of OCPP Units 7 and 8 became probable. Subsequently, we have received PSCW approval for several other renewable and other projects and have also acquired additional projects. On June 25, 2025, we announced plans to extend the lives of OCPP Units 7 and 8, and expect to have the units available to meet high energy demand periods through the end of 2026. These units were originally scheduled to be retired at the end of 2025. The total net book value of WE's ownership share of OCPP Units 7 and 8 was $621.7 million at December 31, 2025, which does not include deferred taxes. This amount was classified as plant to be retired within property, plant, and equipment

on our balance sheet. These units are included in rate base, and WE continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

Columbia Energy Center Units 1 and 2

As a result of a MISO ruling received in June 2021, retirement of the jointly-owned Columbia Units 1 and 2 became probable. Through June 30, 2025, Columbia Units 1 and 2 were expected to be retired by the end of 2029 and, therefore, met the criteria to be considered probable of abandonment.

In conjunction with our new capital plan, we and the other co-owners currently plan to continue coal operations at Columbia Units 1 and 2 through at least 2029, and continue to evaluate the conversion of both units to natural gas. As a result, we and the other co-owners concluded that Columbia Units 1 and 2 (net book value of WPS's ownership share of Columbia Units 1 and 2 was $236.8 million at December 31, 2025, which does not include deferred taxes) no longer meet the criteria necessary to be considered probable of abandonment.

At December 31, 2025, these units continue to be included in rate base, and WPS continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

Samson Solar Energy LLC and Delilah Solar Energy LLC – Storm Damage

During several storms that occurred in 2023 and 2024, certain sections of our Samson I solar facility incurred damage. We had previously recognized an impairment loss of $2.8 million related to damage from these storms, and recorded an offsetting $2.8 million receivable for future insurance recoveries. However, in the second quarter of 2025, we determined it was no longer probable that we would receive insurance proceeds sufficient to recover our losses associated with the 2023 and 2024 storms. As a result, the insurance receivable balance was written off, resulting in the recognition of the $2.8 million impairment loss within other operation and maintenance expense on our income statement.

In addition, in March 2025, both our Samson I and Delilah I solar facilities experienced damage from a storm. In the second quarter of 2025, we recognized an impairment loss within other operation and maintenance expense on our income statement in the amount of $8.8 million, related to damage incurred associated with the March 2025 storm. The impairment loss associated with the March 2025 storm was increased from $8.8 million to $12.0 million in the third quarter of 2025 as a result of ongoing damage assessment.

The Peoples Gas Light and Coke Company and North Shore Gas Company Impairments

In the fourth quarter of 2025, PGL recorded a $130.0 million impairment to property, plant, and equipment related to the terms of a proposed settlement that would resolve its open QIP proceedings.

In August 2024, the ICC issued a final order on PGL's 2016 QIP annual reconciliation, which included a disallowance of certain capital costs. As a result, we recorded a $12.1 million impairment to property, plant, and equipment in 2024.

In November 2023, the ICC issued written rate orders that disallowed $177.2 million of previously incurred capital costs related to the construction and improvement of PGL’s service centers and $1.7 million of capital costs related to NSG's construction of a gas infrastructure project. As a result of these disallowances, we recorded a $178.9 million non-cash impairment to property, plant, and equipment in 2023.

See Note 26, Regulatory Environment, for more information.

Jointly Owned Utility Facilities

12 Months Ended

Dec. 31, 2025

Jointly Owned Utility Plant, Net Ownership Amount [Abstract]

JOINTLY-OWNED UTILITY FACILITIES

Our electric utilities hold joint ownership interests in certain electric generating facilities. We are entitled to our share of generating capability and output of each facility equal to our respective ownership interest. We have supplied our own financing for all jointly owned projects. We pay our ownership share of additional construction costs, fuel inventory purchases, and operating expenses, unless specific agreements have been executed to limit our maximum exposure to additional costs. We record our proportionate share of significant jointly owned electric generating facilities as property, plant, and equipment on the balance sheets. In addition, our proportionate share of direct expenses for the joint operation of these plants is recorded within operating expenses in the income statements.

Information related to jointly owned utility facilities in-service at December 31, 2025 was as follows:


Company	Jointly-Owned Utility Facilities	Ownership		Share of Capacity (MW)	In-Service /Acquisition Date	Operating Owner	Property, Plant, and Equipment		Accumulated Depreciation		CWIP
(in millions, except for percentages and MW)
We Power (1)	ER 1 & ER 2 (2)	83.34	%	1,083.4	2010 & 2011	WE	$	2,489.4	$	(542.0)	$	4.6
WPS	Weston Unit 4 (2)	70.0	%	379.8	2008	WPS	600.6		(242.7)		4.5
WPS	Columbia Units 1 & 2 (2)	27.5	%	306.2	1975 & 1978	WPL	439.1		(201.6)		5.0
WPS	Forward Wind (3)	44.6	%	61.5	2008	WPS	120.3		(63.3)		13.9
WPS	Two Creeks (4)	66.7	%	100.0	2020	WPS	135.7		(22.9)		—
WPS	Badger Hollow I (4)	66.7	%	100.0	2021	WPS	146.0		(19.0)		—
WPS	Red Barn (3)	90.0	%	82.4	2023	WPS	150.7		(12.8)		—
WE	West Riverside (2) (5)	27.5	%	190.2	2023 & 2024	WPL	223.6		(36.7)		2.2
WE	Badger Hollow II (4)	66.7	%	100.0	2023	WE	179.3		(11.8)		—
WE, WPS	Paris Solar (4)	90.0	%	180.0	2024	WE	359.3		(11.0)		—
WE, WPS	Paris Battery	90.0	%	99.0	2025	WE	236.8		(5.5)		—
WE, WPS	Darien Solar (4)	90.0	%	225.0	2025	WE	460.1		(10.7)		—

(1) We Power leases its ownership interest in ER 1 and ER 2 to WE.

(2) Capacity is based on rated capacity, which is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. Values are primarily based on the net dependable expected capacity ratings for summer 2026 established by tests and may change slightly from year to year. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand.

(3) Capacity for wind generating facilities is based on nameplate capacity, which is the amount of energy a turbine should produce at optimal wind speeds.

(4) Capacity for solar generating facilities is based on nameplate capacity, which is the maximum output that a generator should produce at continuous full power.

(5) WE acquired a 13.8% ownership interest in June 2023 and acquired an additional 13.7% ownership interest in May 2024. See Note 2, Acquisitions, for more information.

Information related to jointly owned utility facilities approved by the PSCW at December 31, 2025 was as follows:


Company	Jointly-Owned Utility Facilities	Ownership		Share of Capacity (MW)	Date of Expected In-Service	CWIP
(in millions, except for percentages and MW)
WE, WPS	Koshkonong Solar	90.0	%	270.0	2026	$	460.6
WE, WPS	Koshkonong Battery	90.0	%	149.0	2027	150.7
WE, WPS	Darien Battery	90.0	%	68.0	2027	68.3
WE, WPS	High Noon Solar	90.0	%	270.0	2027	404.2
WE, WPS	High Noon Battery	90.0	%	149.0	2027	150.8
WE, WPS	Ursa Solar Electric Generation Facility	90.0	%	180.0	2027	57.1
WE, WPS	Saratoga Solar	90.0	%	135.0	2028	39.2
WE, WPS	Saratoga Battery	90.0	%	45.0	2028	53.2
WE, WPS	Badger Hollow Wind Energy Generation Facility	90.0	%	100.0	2027	50.0
WE, WPS	Whitetail	90.0	%	60.0	2027	9.0

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2025

Asset Retirement Obligation Disclosure [Abstract]

ASSET RETIREMENT OBLIGATIONS

Our utilities have recorded AROs primarily for the removal of natural gas distribution mains and service pipes (including asbestos and PCBs); asbestos abatement at certain generation and substation facilities, office buildings, and service centers; the removal and dismantlement of a biomass generation facility; the dismantling of wind and solar generation projects; the removal and dismantlement of a battery storage facility; the disposal of PCB-contaminated transformers; the closure of CCR landfills at certain generation facilities; and the removal of above ground and underground storage tanks. Regulatory assets and liabilities are established by our utilities to record the differences between ongoing expense recognition under the ARO accounting rules and the ratemaking practices for retirement costs authorized by the applicable regulators.

WECI has also recorded AROs for the dismantling of our non-utility renewable generation projects.

The following table shows changes to our AROs during the years ended December 31:


(in millions)	2025		2024			2023
Balance as of January 1	$	580.0	$	374.2		$	479.3
Accretion	26.6		18.8			17.2
Additions	29.6		192.7		(1)	24.0
Revisions to estimated cash flows	23.7		6.4			(133.5)		(2)
Liabilities settled	(12.9)		(12.1)			(12.8)
Balance as of December 31	$	647.0	$	580.0		$	374.2

(1) AROs increased primarily as a result of AROs being recorded related to the new EPA CCR Rule that was enacted in April 2024. See Note 24, Commitments and Contingencies, for more information.

(2) AROs decreased primarily due to revisions made to estimated cash flows for changes in removal cost estimates and settlements dates for mains and services at PGL and NSG.

Goodwill and Intangibles

12 Months Ended

Dec. 31, 2025

Goodwill and Intangible Assets Disclosure [Abstract]

GOODWILL AND INTANGIBLES

Goodwill

Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. The table below shows our goodwill balances by segment at December 31, 2025. We had no changes to the carrying amount of goodwill during the years ended December 31, 2025 and 2024.


(in millions)	Wisconsin		Illinois		Other States		Non-Utility Energy Infrastructure		Total
Goodwill (1)	$	2,104.3	$	758.7	$	183.2	$	6.6	$	3,052.8

(1) We had no accumulated impairment losses related to our goodwill as of December 31, 2025.

During the third quarter of 2025, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of July 1, 2025. No impairments resulted from these tests.

Other Indefinite-Lived Intangible Assets

At December 31, 2025 and 2024, we had $44.4 million and $29.3 million, respectively, of other indefinite-lived intangible assets included in other long-term assets on our balance sheets. These assets consist of $24.1 million of spectrum frequencies, which enable our utilities to transmit data and voice communications over a wavelength dedicated to us throughout our service territories. We also have $5.2 million of other indefinite-lived intangible assets, consisting of a MGU trade name from a previous acquisition. In October 2025, we entered into an option agreement for exclusive rights to purchase land for future generation development in Wisconsin. We made the first annual option payment and incurred costs of $15.1 million during 2025, with a right to exercise our option on or before December 31, 2030.

Finite-Lived Intangible Asset

At December 31, 2025 and 2024, we had a finite-lived intangible asset with a gross carrying amount of $18.8 million and $13.0 million, respectively, related to a PPA for Maple Flats acquired by WECI in November 2024. The PPA will be amortized over a useful life of 15 years and expires in 2039. At December 31, 2025 and 2024, accumulated amortization related to the intangible asset was not material. This finite-lived intangible asset is included in other long-term assets on our balance sheet. Amortization expense related to the intangible asset was not material for the year ended December 31, 2025 and 2024. Amortization expense to be recorded as a decrease to operating revenues is expected to be $1.3 million in each of the next five years. See Note 2, Acquisitions, for more information on the acquisition of Maple Flats.

Intangible Liabilities

The intangible liabilities below were all obtained through acquisitions by WECI.


	December 31, 2025						December 31, 2024
(in millions)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
PPAs (1)	$	751.2	$	(176.5)	$	574.7	$	679.6	$	(119.3)	$	560.3
Proxy revenue swap (2)	7.2		(4.9)		2.3		7.2		(4.2)		3.0
Interconnection agreements (3)	4.7		(1.4)		3.3		4.7		(1.2)		3.5
Total intangible liabilities	$	763.1	$	(182.8)	$	580.3	$	691.5	$	(124.7)	$	566.8

(1) Represents PPAs related to the acquisition of Blooming Grove, Tatanka Ridge, Jayhawk, Thunderhead, Samson I, Sapphire Sky, Delilah I, and Hardin III expiring between 2030 and 2040. The weighted-average remaining useful life of the PPAs is 10 years. See Note 2, Acquisitions, for more information on recent WECI acquisitions.

(2) Represents an agreement with a counterparty to swap the market revenue of Upstream's wind generation for fixed quarterly payments over 10 years, which expires in 2029. The remaining useful life of the proxy revenue swap is three years.

(3) Represents interconnection agreements related to the acquisitions of Tatanka Ridge and Bishop Hill III, expiring in 2040 and 2041, respectively. These agreements relate to payments for connecting our facilities to the infrastructure of another utility to facilitate the movement of power onto the electric grid. The weighted-average remaining useful life of the interconnection agreements is 15 years.

Amortization related to these intangible liabilities for the years ended December 31, 2025, 2024, and 2023 was $58.1 million, $53.7 million, and $50.6 million, respectively. Amortization for the next five years is estimated to be:


	For the Years Ending December 31
(in millions)	2026		2027		2028		2029		2030
Amortization to be recorded as an increase to operating revenues	$	59.9	$	59.9	$	59.9	$	59.9	$	59.9
Amortization to be recorded as a decrease to other operation and maintenance	0.2		0.2		0.2		0.2		0.2

Common Equity

12 Months Ended

Dec. 31, 2025

Stockholders' Equity Note [Abstract]

COMMON EQUITY

Stock-Based Compensation

The following table summarizes our pre-tax stock-based compensation expense and the related tax benefit recognized in income for the years ended December 31:


(in millions)	2025		2024		2023
Stock options	$	4.1	$	4.9	$	5.3
Restricted stock	6.2		7.6		6.6
Performance units	37.9		26.8		(2.2)		(1)
Stock-based compensation expense	$	48.2	$	39.3	$	9.7
Related tax benefit	$	13.2	$	10.8	$	2.7

(1) The reduction in expense was due to a decrease in the fair value of the outstanding performance units.

Stock-based compensation costs capitalized during 2025, 2024, and 2023 were not significant.

Stock Options

The following is a summary of our stock option activity during 2025:


Stock Options	Number of Options	Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Life (in years)	Aggregate Intrinsic Value (in millions)
Outstanding as of January 1, 2025	2,916,902	$	82.32
Granted	231,024	94.55
Exercised	(575,758)	67.92
Forfeited	(1,351)	91.11
Expired	(1,330)	52.90
Outstanding as of December 31, 2025	2,569,487	86.65		5.3	$	48.3
Exercisable as of December 31, 2025	1,937,953	85.29		4.4	$	39.1

The aggregate intrinsic value of outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they exercised all of their options on December 31, 2025. This is calculated as the difference between our closing stock price on December 31, 2025, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the years ended December 31, 2025, 2024, and 2023 was $22.8 million, $11.2 million, and $5.2 million, respectively. The tax benefit from option exercises for the same years was approximately $6.3 million, $3.1 million, and $1.4 million, respectively. These amounts do not account for the compensation limitations under Internal Revenue Code Section 162(m).

As of December 31, 2025, approximately $1.4 million of unrecognized compensation cost related to unvested and outstanding stock options was expected to be recognized over the next 1.7 years on a weighted-average basis.

During the first quarter of 2026, the Compensation Committee awarded 269,085 non-qualified stock options with a weighted-average exercise price of $106.09 and a weighted-average grant date fair value of $21.20 per option to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

Restricted Shares

The following restricted stock activity occurred during 2025:


Restricted Shares	Number of Shares	Weighted-Average Grant Date Fair Value
Outstanding and unvested as of January 1, 2025	105,242	$	87.61
Granted	79,170	94.55
Released	(58,725)	88.48
Forfeited	(6,774)	90.88
Outstanding and unvested as of December 31, 2025	118,913	91.61

The intrinsic value of restricted stock released was $5.7 million, $8.6 million, and $5.8 million for the years ended December 31, 2025, 2024, and 2023, respectively. The tax benefit from released restricted shares for the same years was $1.6 million, $2.4 million, and $1.6 million, respectively. These amounts do not account for the compensation limitations under Internal Revenue Code Section 162(m).

As of December 31, 2025, approximately $4.9 million of unrecognized compensation cost related to unvested and outstanding restricted stock was expected to be recognized over the next 1.7 years on a weighted-average basis.

During the first quarter of 2026, the Compensation Committee awarded 75,222 restricted shares to certain of our directors, officers, and other key employees under its normal schedule of awarding long-term incentive compensation. The grant date fair value of these awards was $106.09 per share.

Performance Units

During 2025, 2024, and 2023, the Compensation Committee awarded 185,945; 205,051; and 157,035 performance units, respectively, to officers and other key employees under the WEC Energy Group Performance Unit Plan.

Performance units with an intrinsic value of $15.4 million, $2.4 million, and $10.2 million were settled during 2025, 2024, and 2023, respectively. The tax benefit from the distribution of performance units for the same years was $3.8 million, $0.6 million, and $2.6 million, respectively.

At December 31, 2025, we had 502,733 performance units outstanding, including dividend equivalents. A liability of $57.1 million was recorded on our balance sheet at December 31, 2025 related to these outstanding units. As of December 31, 2025, approximately $31.3 million of unrecognized compensation cost related to unvested and outstanding performance units was expected to be recognized over the next 1.7 years on a weighted-average basis.

During the first quarter of 2026, we settled performance units with an intrinsic value of $25.2 million. The tax benefit from the distribution of these awards was $5.7 million. This amount and the tax benefits disclosed above do not account for the compensation limitations under Internal Revenue Code Section 162(m). In January 2026, the Compensation Committee also awarded 182,146 performance units to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

Restrictions

Our ability as a holding company to pay common stock dividends primarily depends on the availability of funds received from our utility subsidiaries, We Power, Bluewater, ATC Holding, and WECI. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans, or advances. All of our utility subsidiaries, with the exception of UMERC and MGU, are prohibited from loaning funds to us, either directly or indirectly.

In accordance with their most recent rate orders, WE, WPS, and WG may not pay common dividends above the test year forecasted amounts reflected in their respective rate cases, if it would cause their average common equity ratio, on a financial basis, to fall below their authorized level of 53.0%. A return of capital in excess of the test year amount can be paid by each company at the end of the year provided that their respective average common equity ratios do not fall below the authorized level.

WE may not pay common dividends to us under WE's Restated Articles of Incorporation if any dividends on its outstanding preferred stock have not been paid. In addition, pursuant to the terms of WE's 3.60% Serial Preferred Stock, WE's ability to declare common dividends would be limited to 75% or 50% of net income during a 12-month period if its common stock equity to total capitalization, as defined in the preferred stock designation, is less than 25% and 20%, respectively.

NSG's long-term debt obligations contain provisions and covenants restricting the payment of cash dividends and the purchase or redemption of its capital stock.

The long-term debt obligations of UMERC, Bluewater Gas Storage, and ATC Holding contain a provision requiring them to maintain a total funded debt to capitalization ratio of 65% or less.

The long-term debt obligations of WECI Wind Holding I, WECI Wind Holding II, and WECI Energy Holding III contain various conditions that must be met prior to them making any cash distributions. Included in these provisions is a requirement to maintain a debt service coverage ratio of 1.2 or greater prior to the distribution.

WEC Energy Group has the option to defer interest payments on its 2024A Junior Notes, 2024B Junior Notes, and 2025 Junior Notes, from time to time, for one or more periods of up to 10 consecutive years per period. During any period in which it defers interest payments, it may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, its common stock.

See Note 13, Short-Term Debt and Lines of Credit, for discussion of certain financial covenants related to short-term debt obligations.

As of December 31, 2025, restricted net assets of our consolidated subsidiaries totaled approximately $14 billion. Our equity in undistributed earnings of investees accounted for by the equity method was approximately $615 million.

We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.

Common Stock

As of January 1, 2024, we began issuing new shares of common stock to fulfill our obligations under various stock-based employee benefit and compensation plans and to provide shares to participants in our dividend reinvestment and stock purchase plan. During 2023, we instructed our independent agents to purchase shares on the open market to fulfill obligations under these plans. As such, no new shares of common stock were issued during the year ended December 31, 2023.

In August 2024, we entered into an EDA, under which we could offer and sell, from time to time, shares of our common stock having an aggregate sales price of up to $1.5 billion through an at-the-market offering program, which included an equity forward sales component. This EDA was terminated on October 31, 2025. Prior to its termination, we issued 7,610,457 shares of common stock under this EDA and received proceeds of $797.3 million, which was net of $9.2 million of commissions and other fees. We did not enter into any forward sales agreements under the August 2024 EDA.

In connection with our termination of the August 2024 EDA, we entered into a new EDA on October 31, 2025, under which we may offer and sell, from time to time, shares of our common stock having an aggregate sales price of up to $3.0 billion through an at-the-market offering program, which also includes an equity forward sales component and a collared forward sales component. We may offer and sell our common shares through the sales agents party to the EDA during the term of the agreement. The October 2025 EDA will terminate upon the earliest of (i) the sale of all common stock subject to the EDA, (ii) termination of the EDA pursuant to its terms, or (iii) October 31, 2028. Actual sales of common stock under the EDA will depend on a variety of factors, including market conditions, the trading price of our common stock, capital needs, and our determination of the appropriate sources of funding. As of December 31, 2025, we had not issued any shares of common stock under the October 2025 EDA.

In November 2025, we entered into a forward sales contract pursuant to our October 2025 EDA. Pursuant to the terms of the contract, 58,533 shares were sold with an initial forward price of $110.7748 per share. The initial forward price is subject to adjustment on a daily basis based on a floating interest rate factor and will decrease by other fixed amounts as specified in the contract. No amounts are recorded on our balance sheet with respect to this contract until actual settlement occurs. The contract requires us to, at our election on or before June 30, 2027, either (i) physically settle the transaction by issuing shares of our stock in exchange for net cash proceeds at the then-applicable forward sales price or (ii) net settle the transaction through the delivery or receipt of cash or shares in accordance with the contract provisions. As of December 31, 2025, no shares were settled under this contract. At December 31, 2025, we could have settled this forward sales contract with physical delivery of 58,533 shares of common stock to the counterparties in exchange for cash proceeds of $6.5 million. The forward sales contract could have alternatively been settled with delivery of approximately $0.3 million of cash or approximately 3,084 shares of common stock to us, if we had elected to net cash or net share settle, respectively, at December 31, 2025.

Any shares offered and sold under our EDAs were done pursuant to our registration statement on Form S-3 filed with the SEC on August 5, 2024 and the related prospectus supplements.

We had the following changes to our outstanding common stock during the years ended December 31, 2025 and 2024:


	2025	2024
Common stock shares outstanding at beginning of period	317,680,855	315,434,531
Shares issued:
At-the-market offering program	6,579,783	1,030,674
Stock-based compensation	609,995	455,474
401(k)	247,889	336,800
Stock investment plan	342,997	423,376
Common stock shares outstanding at end of period	325,461,519	317,680,855

The following is a summary of shares purchased to fulfill exercised stock options and restricted stock awards during the years ended December 31:


(in millions, except share amounts)	2025		2024		2023
Shares purchased	13,795		23,292		182,795
Cost of shares purchased	$	1.3	$	3.2	$	16.6

During the year ended December 31, 2025, our Board of Directors declared common stock dividends which are summarized below:

Date Declared

Date Payable

Per Share

Period

January 16, 2025

March 1, 2025

$0.8925

First quarter

April 17, 2025

June 1, 2025

$0.8925

Second quarter

July 17, 2025

September 1, 2025

$0.8925

Third quarter

October 16, 2025

December 1, 2025

$0.8925

Fourth quarter

On January 22, 2026, our Board of Directors declared a quarterly cash dividend of $0.9525 per share, which equates to an annual dividend of $3.81 per share. The dividend is payable on March 1, 2026, to shareholders of record on February 13, 2026.

Earnings Per Share

The following table shows the computation of our basic and diluted EPS for the years ended December 31:


(in millions, except per share amounts)	2025		2024		2023
Numerator:
Net income attributed to common shareholders	$	1,557.5	$	1,527.2	$	1,331.7

Denominator:
Weighted average basic shares outstanding	321.9		316.2		315.4
Dilutive effect of stock-based compensation awards	0.6		0.3		0.5
Dilutive effect of convertible senior notes	1.3		—		—
Weighted average diluted shares	323.8		316.5		315.9

Basic EPS	$	4.84	$	4.83	$	4.22
Diluted EPS	$	4.81	$	4.83	$	4.22

Preferred Stock

12 Months Ended

Dec. 31, 2025

Class of Stock Disclosures [Abstract]

PREFERRED STOCK

The following table shows preferred stock authorized and outstanding at December 31, 2025 and 2024:


(in millions, except share and per share amounts)	Shares Authorized	Shares Outstanding	Redemption Price Per Share		Total
WEC Energy Group
$0.01 par value Preferred Stock	15,000,000	—	—		$	—

WE
$100 par value, Six Per Cent. Preferred Stock	45,000	44,498	—		4.4
$100 par value, Serial Preferred Stock 3.60% Series	2,286,500	260,000	$	101	26.0
$25 par value, Serial Preferred Stock	5,000,000	—	—		—

WPS
$100 par value, Preferred Stock	1,000,000	—	—		—

PGL
$100 par value, Cumulative Preferred Stock	430,000	—	—		—

NSG
$100 par value, Cumulative Preferred Stock	160,000	—	—		—
Total					$	30.4

Short-Term Debt and Lines of Credit

12 Months Ended

Dec. 31, 2025

Short-Term Debt [Abstract]

SHORT-TERM DEBT AND LINES OF CREDIT

The following table shows our short-term borrowings and their corresponding weighted-average interest rates as of December 31:


(in millions, except percentages)	2025			2024
Commercial paper
Amount outstanding at December 31	$	1,921.3		$	1,114.4
Average interest rate on amounts outstanding at December 31	3.89		%	4.63		%



Operating expense loans
Amount outstanding at December 31 (1)	$	3.4		$	2.2

(1) Coyote Ridge, Tatanka Ridge, Samson I, and Jayhawk have entered into operating expense loans. In accordance with their limited liability company operating agreements, they received loans from the holders of their noncontrolling interests in proportion to their ownership interests.

Our average amount of commercial paper borrowings based on daily outstanding balances during 2025, was $1,124.2 million with a weighted-average interest rate during the period of 4.43%.

WEC Energy Group, WE, PGL, WPS, and WG have entered into bank back-up credit facilities to maintain short-term credit liquidity which, among other terms, require them to maintain, subject to certain exclusions, a total funded debt to capitalization ratio of 70.0%, 65.0%, 65.0%, 65.0%, and 65.0% or less, respectively. As of December 31, 2025, all companies were in compliance with their respective ratio.

The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing programs, including remaining available capacity under these facilities as of December 31:


(in millions)	Maturity	2025
Revolving credit facility (WEC Energy Group) (1) (2) (3)	August 2030	$	1,700.0
Revolving credit facility (WE) (1) (2)	August 2030	800.0
Revolving credit facility (PGL) (1) (2)	August 2030	600.0
Revolving credit facility (WPS) (1) (2)	August 2030	450.0
Revolving credit facility (WG) (1) (4)	August 2030	350.0
Total short-term credit capacity		$	3,900.0

Less:
Letters of credit issued inside credit facilities		$	2.3
Commercial paper outstanding		1,921.3
Available capacity under existing facilities		$	1,976.4

(1) These revolving credit facilities have a renewal provision for two extensions, subject to lender approval. Each extension is for a period of one year.

(2) In August 2025, the capacity of the credit facilities for each of WEC Energy Group, WE, PGL, and WPS was increased to $1,700.0 million, $800.0 million, $600.0 million, and $450.0 million, respectively, and the maturity for each facility was extended to August 2030.

(3) In August 2025, WEC Energy Group terminated its $200.0 million bilateral credit facility.

(4) In August 2025, WG extended the maturity of its credit facility to August 2030.

The bank back-up credit facilities contain customary covenants, including certain limitations on the respective companies' ability to sell assets. The credit facilities also contain customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, Employee Retirement Income Security Act of 1974 defaults, and change of control. In addition, pursuant to the terms of WEC Energy Group's credit agreement, we must ensure that certain of our subsidiaries comply with several of the covenants contained therein.

Long-Term Debt

12 Months Ended

Dec. 31, 2025

Debt Disclosure [Abstract]

LONG-TERM DEBT

The following table is a summary of our long-term debt outstanding as of December 31:


	2025					2024
(in millions)	Maturity Date	Weighted Average Interest Rate		Balance		Weighted Average Interest Rate		Balance
WEC Energy Group Senior Notes (unsecured)	2026-2033	3.96	%	$	6,325.0	4.13	%	$	6,045.0
WEC Energy Group Junior Notes (unsecured) (1) (2)	2055-2056	6.24	%	1,350.0		6.72	%	750.0
WE Debentures (unsecured)	2028-2095	4.55	%	4,485.0		4.55	%	3,935.0
WEPCo Environmental Trust (secured, nonrecourse) (5) (10)	2026-2035	1.58	%	78.8		1.58	%	88.0
WPS Senior Notes (unsecured)	2028-2051	3.99	%	1,975.0		4.17	%	2,275.0
WG Debentures (unsecured)	2028-2046	4.34	%	940.0		3.92	%	840.0
PGL First and Refunding Mortgage Bonds (secured) (3)	2027-2047	3.56	%	1,995.0		3.56	%	1,995.0
NSG First Mortgage Bonds (secured) (4)	2027-2043	3.81	%	177.0		3.81	%	177.0
MERC Senior Notes (unsecured)	2027-2047	3.64	%	210.0		3.04	%	210.0
MGU Senior Notes (unsecured)	2027-2047	4.38	%	190.0		3.45	%	175.0
UMERC Senior Notes (unsecured)	2029-2035	4.23	%	280.0		3.26	%	160.0
Bluewater Gas Storage Senior Notes (unsecured) (5)	2026-2047	4.07	%	128.0		4.07	%	131.9
ATC Holding Senior Notes (unsecured)	2028-2030	4.02	%	390.0		4.05	%	475.0
We Power Subsidiaries Notes (secured, nonrecourse) (5) (6)	2026-2041	5.71	%	769.9		5.67	%	814.3
WECC Notes (unsecured)	2028	6.94	%	50.0		6.94	%	50.0
WECI Wind Holding I Senior Notes (secured, nonrecourse) (5) (7)	2026-2032	2.75	%	202.1		2.75	%	246.4
WECI Wind Holding II Senior Notes (secured, nonrecourse) (5) (8)	2026-2031	6.38	%	147.9		6.38	%	167.6
WECI Energy Holding III Senior Notes (secured, nonrecourse) (5) (9)	2026-2039	5.73	%	446.2		5.73	%	488.7
Total				20,139.9				19,023.9
Jayhawk acquisition				7.5				7.5
Unamortized debt issuance costs				(110.4)				(103.2)
Unamortized discount, net and other				(19.5)				(21.1)
Total long-term debt, including current portion				20,017.5				18,907.1
Current portion of long-term debt				(1,519.4)				(1,729.0)
Total long-term debt				$	18,498.1			$	17,178.1

(1) In November 2025, we issued our 2025 Junior Notes. Our 2025 Junior Notes are fixed-to-fixed reset rate junior subordinated notes. The rate for our 2025 Junior Notes was 5.625% as of December 31, 2025. The rate for our 2025 Junior Notes will reset on May 15, 2031; provided the reset rate will not be less than 5.625%.

(2) In December 2024, we issued our 2024A Junior Notes and 2024B Junior Notes. Our 2024A Junior Notes and 2024B Junior Notes are fixed-to-fixed reset rate junior subordinated notes. The rate for our 2024A Junior Notes was 6.69% as of December 31, 2025. The rate for our 2024A Junior Notes will reset on June 15, 2030. The rate for our 2024B Junior Notes was 6.74% as of December 31, 2025. The rate for our 2024B Junior Notes will reset on June 15, 2035.

(3) PGL's First Mortgage Bonds are subject to the terms and conditions of PGL's First Mortgage Indenture dated January 2, 1926, as supplemented. Under the terms of the Indenture, substantially all property owned by PGL is pledged as collateral for these outstanding debt securities.

PGL has used certain First Mortgage Bonds to secure tax exempt interest rates. The Illinois Finance Authority has issued Tax Exempt Bonds, and the proceeds from the sale of these bonds were loaned to PGL. In return, PGL issued $100 million of collateralized First Mortgage Bonds.

(4) NSG's First Mortgage Bonds are subject to the terms and conditions of NSG's First Mortgage Indenture dated April 1, 1955, as supplemented. Under the terms of the Indenture, substantially all property owned by NSG is pledged as collateral for these outstanding debt securities.

(5) The long-term debt of Bluewater, WECI Wind Holding I, WECI Wind Holding II, WECI Energy Holding III, WEPCo Environmental Trust, and We Power's subsidiaries requires periodic principal payments.

(6) We Power's subsidiaries' senior notes are secured by a collateral assignment of the leases between We Power's subsidiaries and WE related to PWGS and ERGS, as applicable.

(7) WECI Wind Holding I's Senior Notes are secured by a first priority security interest in the ownership interest of its subsidiaries, as well as a pledge of equity in WECI Wind Holding I.

(8) WECI Wind Holding II's Senior Notes are secured by a first priority security interest in the ownership interest of its subsidiaries, as well as a pledge of equity in WECI Wind Holding II.

(9) WECI Energy Holding III's Senior Notes are secured by a first priority security interest in the ownership interest of its subsidiaries, as well as a pledge of equity in WECI Energy Holding III.

(10) WEPCo Environmental Trust’s ETBs are secured by a pledge of and lien on environmental control property, which includes the right to impose, collect and receive a non-bypassable environmental control charge paid by all of WE's retail electric distribution customers, the right to obtain true-up adjustments of the environmental control charges, and all revenues or other proceeds arising from those rights and interests. See Note 23, Variable Interest Entities, for more information.

We amortize debt premiums, discounts, and debt issuance costs over the life of the debt and we include the costs in interest expense.

In December 2024, the DOE issued to WE a conditional commitment for a federal loan guarantee for up to $2.5 billion of borrowings that would be used by WE to fund a portion of the costs to construct certain utility-scale renewable generation projects. The conditional commitment was issued pursuant to provisions of the IRA. Under the conditional commitment, the guaranteed borrowings would be senior, unsecured borrowings of WE made through the Federal Financing Bank and reduce WE's issuance of senior, unsecured obligations in the capital markets. Final approval and issuance of a loan guarantee by the DOE is subject to numerous conditions, including negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and the satisfaction of other conditions. While we continue to work with the DOE, there can be no assurance that the DOE will issue the loan guarantee for WE.

WEC Energy Group, Inc.

In June 2025, the remaining $120.0 million outstanding of our 3.55% Senior Notes, due June 15, 2025, matured, and principal and accrued interest were paid with proceeds received from issuing commercial paper.

In September 2025, our $500.0 million of 5.00% Senior Notes due September 27, 2025, matured, and principal and accrued interest were paid with proceeds received from issuing commercial paper.

In November 2025, we issued $600.0 million of 5.625% 2025 Junior Notes due May 15, 2056, and used the net proceeds to repay short-term debt and for other general corporate purposes.

In January 2026, our $1,000.0 million of 4.75% Senior Notes due January 9, 2026, matured, and principal and accrued interest were paid with proceeds received from issuing commercial paper.

Convertible Senior Notes

2028 Notes

In June 2025, we issued $900.0 million of 2028 Notes. The 2028 Notes are senior unsecured obligations and bear interest at an annual rate of 3.375%, payable semiannually beginning on December 1, 2025. Proceeds from the offering were used to repay short-term debt and for other general corporate purposes.

The 2028 Notes will mature on June 1, 2028, unless earlier converted or repurchased in accordance with their terms. No sinking fund is provided for the 2028 Notes. Upon the occurrence of a fundamental change, as defined in the related indenture, holders may require us to repurchase for cash all or any portion of their 2028 Notes. We may not redeem the 2028 Notes prior to their maturity date. Any fundamental change repurchases of the 2028 Notes will be at a price equal to 100% of the principal amount, plus accrued and unpaid interest.

Holders may convert all or any portion of their notes at their option at any time prior to the close of business on the business day immediately preceding March 1, 2028, only under the following circumstances:

•During any calendar quarter commencing after the calendar quarter ending on September 30, 2025, (and only during such calendar quarter), if the last reported sale price of our common stock for at least 20 trading days (whether or not consecutive) during a period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price of such series of notes on each applicable trading day;

•During the five consecutive business day period immediately after any ten consecutive trading day period (measurement period) in which the trading price per $1,000 principal amount of notes, as determined following a request by a holder or holders, for each trading day of the measurement period was less than 98% of the product of the last reported sale price of our common stock and the conversion rate of such series of notes on each such trading day; or

•Upon the occurrence of specified corporate events, as defined in the related indenture.

Holders may convert all or any portion of their notes at any time, regardless of the foregoing circumstances, on or after March 1, 2028, until the close of business on the second scheduled trading day immediately preceding the maturity date.

Upon conversion, we will pay cash up to the aggregate principal amount of the notes to be converted and pay or deliver cash, shares of our common stock, or a combination of cash and shares of our common stock, at our election, in respect of the remainder, if any, of our conversion obligation in excess of the aggregate principal amount of the notes being converted.

The initial conversion rate for the 2028 Notes is 7.7901 shares of common stock per $1,000 principal amount, which is equivalent to an initial conversion price of approximately $128.37 per share of our common stock. The conversion rate is subject to adjustment upon the occurrence of certain specified events, as defined in the related indenture, but will not be adjusted for any accrued and unpaid interest. In addition, upon the occurrence of a make-whole fundamental change, as defined in the related indenture, we will, in certain circumstances, increase the conversion rate by a number of additional shares of common stock for conversions in connection with the make-whole fundamental change.

2027 Notes and 2029 Notes

In the second quarter of 2024, we issued $862.5 million of 2027 Notes and $862.5 million of 2029 Notes. The 2027 Notes and 2029 Notes are senior unsecured obligations and bear interest at an annual rate of 4.375%, payable semiannually beginning on December 1, 2024. Proceeds from the offerings were used to repay short-term debt and for general corporate purposes.

The 2027 Notes will mature on June 1, 2027, and the 2029 Notes will mature on June 1, 2029, unless earlier converted or repurchased in accordance with their terms, or in the case of the 2029 Notes, redeemed by us. No sinking fund is provided for either series of the notes. Upon the occurrence of a fundamental change, as defined in the related indenture, holders may require us to repurchase for cash all or any portion of their 2027 or 2029 Notes. We may not redeem the 2027 Notes prior to their maturity date. We may redeem for cash all or part of the 2029 Notes, at our option, on or after June 1, 2027 and on or before the 41st scheduled trading day immediately preceding their maturity date, if the last reported sale price per share of our common stock has been at least 130% of the conversion price of the 2029 Notes then in effect for at least 20 trading days (whether or not consecutive) during any 30 consecutive trading day period. Any redemptions or fundamental change repurchases of the 2027 Notes or 2029 Notes will be at a price equal to 100% of the principal amount, plus accrued and unpaid interest.

Holders may convert all or any portion of their notes at their option at any time prior to the close of business on the business day immediately preceding March 1, 2027, in the case of the 2027 Notes, and March 1, 2029, in the case of the 2029 Notes, only under the following circumstances:

•During any calendar quarter commencing after the calendar quarter ending on September 30, 2024 (and only during such calendar quarter), if the last reported sale price of our common stock for at least 20 trading days (whether or not consecutive) during a period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price of such series of notes on each applicable trading day;

•During the five consecutive business day period immediately after any ten consecutive trading day period (measurement period) in which the trading price per $1,000 principal amount of notes of such series for each trading day of the measurement period

was less than 98% of the product of the last reported sale price of our common stock and the conversion rate of such series of notes on each such trading day;

•Upon the occurrence of specified corporate events, as defined in the related indenture;

•In the case of the 2029 Notes only, if we call any of the 2029 Notes for redemption, at any time prior to the close of business on the second scheduled trading day prior to the redemption date, but only with respect to the 2029 Notes called (or deemed called) for redemption.

Holders may convert all or any portion of their notes at any time, regardless of the foregoing circumstances, on or after March 1, 2027, in the case of the 2027 Notes, or March 1, 2029, in the case of the 2029 Notes, until the close of business on the second scheduled trading day immediately preceding the maturity date of such series of notes.

Upon conversion, we will pay cash up to the aggregate principal amount of the notes to be converted and pay or deliver cash, shares of our common stock, or a combination of cash and shares of our common stock, at our election, in respect of the remainder, if any, of our conversion obligation in excess of the aggregate principal amount of the notes being converted.

The initial conversion rate for both the 2027 Notes and 2029 Notes is 10.1243 shares of common stock per $1,000 principal amount, which is equivalent to an initial conversion price of approximately $98.77 per share of our common stock. The conversion rate is subject to adjustment upon the occurrence of certain specified events, as defined in the related indenture, but will not be adjusted for accrued and unpaid interest. In addition, upon the occurrence of a make-whole fundamental change, as defined in the related indenture, we will, in certain circumstances, increase the conversion rate by a number of additional shares of common stock for conversions in connection with the make-whole fundamental change.

As of December 31, 2025, the conditions allowing holders to convert their notes were not met. In accordance with the guidance in ASC Subtopic 470-20, Debt – Debt with Conversion and Other Options, the 2027 Notes, 2028 Notes, and 2029 Notes were accounted for in their entirety as a liability on our balance sheet. The following is a summary of our convertible debt instruments as of December 31, 2025:


(in millions)	Principal Amount		Unamortized Debt Issuance Costs		Net Carrying Amount		Fair Value Amount (1)
2027 Notes	$	862.5	$	(4.7)	$	857.8	$	977.8
2028 Notes	900.0		(8.5)		891.5		912.6
2029 Notes	862.5		(6.8)		855.7		1,011.7

(1) The fair values are categorized in Level 2 of the fair value hierarchy. See Note 1(r), Fair Value Measurements, for more information on the levels of the fair value hierarchy.

The following table provides a summary of the interest expense recorded for each of the 2027 Notes, 2028 Notes, and 2029 Notes for the year ended December 31:


(in millions)	2025		2024
2027 Notes
Contractual interest expense	$	37.7	$	22.3
Amortization of debt issuance costs	3.3		1.9
Total interest expense – 2027 Notes	41.0		24.2

2028 Notes
Contractual interest expense	$	17.0	$	—
Amortization of debt issuance costs	1.8		—
Total interest expense – 2028 Notes	18.8		—

2029 Notes
Contractual interest expense	37.7		22.3
Amortization of debt issuance costs	2.0		1.2
Total interest expense – 2029 Notes	$	39.7	$	23.5

Wisconsin Electric Power Company

In June 2025, WE's $250.0 million of 3.10% Debentures, due June 1, 2025, matured, and outstanding principal and accrued interest were paid with proceeds received from issuing commercial paper.

In September 2025, WE issued $500.0 million of 4.15% Debentures, due October 15, 2030, and used the net proceeds to repay short-term debt and for other general corporate purposes.

In December 2025, WE issued $300.0 million of 3.95% Debentures, due March 1, 2029, and used the net proceeds to repay short-term debt and for other general corporate purposes.

Wisconsin Public Service Corporation

In November 2025, WPS's $300.0 million of 5.35% Senior Notes, due November 10, 2025, matured, and outstanding principal and accrued interest were paid with proceeds received from issuing commercial paper.

In January 2026, WPS issued $300.0 million of 4.25% Senior Notes, due January 15, 2031, and used the net proceeds to repay short-term debt and for other general corporate purposes.

Wisconsin Gas LLC

In September 2025, WG issued $175.0 million of 4.70% Debentures, due October 1, 2030, and $125.0 million of 5.39% Debentures, due October 1, 2035, and used the net proceeds to repay $200.0 million of WG's 3.53% Debentures that matured on September 30, 2025, and to repay short-term debt and for other general limited liability company purposes.

Minnesota Energy Resources Corporation

In April 2025, MERC issued $50.0 million of 5.20% Senior Notes, due May 1, 2030, and used the net proceeds to repay MERC's $50.0 million of 2.69% Senior Notes that matured on May 1, 2025.

Michigan Gas Utilities Corporation

In April 2025, MGU issued $75.0 million of 5.20% Senior Notes, due May 1, 2030, and used the net proceeds to repay MGU's $60.0 million of 2.69% Senior Notes that matured on May 1, 2025 and intercompany short-term debt to its parent, Integrys.

Upper Michigan Energy Resources Corporation

In August 2025, UMERC issued $80.0 million of 5.31% Senior Notes, due August 14, 2030, and $40.0 million of 5.93% Senior Notes, due August 14, 2035, and used the net proceeds to repay intercompany short-term debt to its parent, WEC Energy Group, and for other general corporate purposes.

ATC Holding LLC

In December 2025, ATC's $85.0 million of 4.18% Debentures, due December 20, 2025, matured, and outstanding principal and accrued interest were paid with a contribution received from WEC Energy Group.

Maturities of Long-Term Debt Outstanding

The following table shows the long-term debt securities maturing within one year of December 31, 2025:


(in millions)	Interest Rate	Maturity Date (1)	Principal Amount
WEC Energy Group Senior Notes (unsecured)	4.75%	January	$	1,000.0
WEC Energy Group Senior Notes (unsecured)	5.60%	September	350.0
WEPCo Environmental Trust (secured, nonrecourse)	1.58%	Semi-annually	9.3
Bluewater Gas Storage Senior Notes (unsecured)	3.76%	Semi-annually	3.1
Bluewater Gas Storage Senior Notes (unsecured)	5.41%	Semi-annually	1.0
We Power Subsidiaries Notes – PWGS (secured, nonrecourse)	4.91%	Monthly	8.9
We Power Subsidiaries Notes – ERGS (secured, nonrecourse)	5.209%	Semi-annually	17.1
We Power Subsidiaries Notes – ERGS (secured, nonrecourse)	4.673%	Semi-annually	12.8
We Power Subsidiaries Notes – PWGS (secured, nonrecourse)	6.00%	Monthly	7.9
WECI Wind Holding I Senior Notes (secured, nonrecourse)	2.75%	Semi-annually	45.1
WECI Wind Holding II Senior Notes (secured, nonrecourse)	6.38%	Semi-annually	22.6
WECI Energy Holding III Senior Notes (secured, nonrecourse)	5.73%	Semi-annually	41.6
Total			$	1,519.4

(1) Maturity dates listed as semi-annually and monthly are associated with debt that requires periodic principal payments.

The following table shows the future maturities of our long-term debt outstanding as of December 31, 2025:


(in millions)	Payments
2026	$	1,519.4
2027	2,137.3
2028	3,203.2
2029	2,943.4
2030	1,691.9
Thereafter	8,644.7
Total	$	20,139.9

Certain long-term debt obligations contain financial and other covenants related to payment of principal and interest when due, maintaining certain total funded debt to capitalization ratios, and various other obligations. Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations.

Leases

12 Months Ended

Dec. 31, 2025

Leases [Abstract]

LEASES

In accordance with ASC Subtopic 980-842, Regulated Operations – Leases (Subtopic 980-842), the timing of expense recognition associated with our leases is modified to conform to the rate treatment. The difference between the lease expense that is allowed for rate-making purposes and the unadjusted lease expense calculated under Topic 842 is deferred as a regulatory asset on our balance sheets. For our finance leases, amortization of the right-of-use asset is modified so that the total of the imputed interest and amortization costs equals the lease expense that is allowed for rate-making purposes in accordance with Subtopic 980-842.

Obligations Under Operating Leases

We have recorded right of use assets and lease liabilities primarily associated with the following operating leases:

•Leases of office space, primarily related to several floors we are leasing in the Aon Center office building in Chicago, Illinois, through April 2039.

•Land we are leasing related to our Rothschild biomass plant through June 2051.

•Rail cars we are leasing to transport coal to various generating facilities through June 2027.

•Land we are leasing related to our utility and non-utility solar generation projects through May 2075.

The operating leases generally require us to pay property taxes, insurance premiums, and operating and maintenance costs associated with the leased property. Certain of our leases contain options for early termination or to renew past the initial term, as

set forth in the lease agreements. These options are included in our calculation of the lease obligations if it is reasonably certain that they will be exercised.

Obligations Under Finance Leases

Land Leases – Utility Solar Generation

We have various land leases related to our investments in utility solar generation. Each lease has an initial term and one or more optional extensions. We expect the optional extensions to be exercised, and, as a result, all of the land leases are being amortized over an extended term which can range from 40 to 50 years. Once a solar project achieves commercial operation, the lease liability is remeasured to reflect the final total acres being leased. Our payments related to these leases are being recovered through rates.

Land Leases – Non-Utility Energy Infrastructure Solar Generation

We have various land leases related to our investments in non-utility solar generation. Each lease has an initial term and one or more optional extensions. We expect the optional extensions to be exercised, and, as a result, all of the land leases are being amortized over an extended term of approximately 50 years.

Amounts Recognized in the Financial Statements and Other Information

The components of lease expense and supplemental cash flow information related to our leases for the years ended December 31 are as follows:


(in millions)	2025			2024			2023
Finance lease expense
Amortization of right of use assets (1)	$	1.1		$	0.2		$	—
Interest on lease liabilities (2)	6.9			1.8			0.8
Operating lease expense (3)	7.8			5.2			4.7
Short-term lease expense (3)	0.2			0.6			1.2
Total lease expense	$	16.0		$	7.8		$	6.7

Other information

Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from finance leases	$	6.4		$	1.8		$	0.8
Operating cash flows from operating leases	7.5			7.1			6.8
Financing cash flows from finance leases	0.9			—			—

Non-cash activities
Right of use assets obtained in exchange for finance lease liabilities (4)	$	63.8		$	153.2		$	32.8
Right of use assets obtained in exchange for operating lease liabilities	43.5			2.6			18.3

Weighted-average remaining lease term – finance leases	49.6 years			50.2 years			49.4 years
Weighted-average remaining lease term – operating leases	35.8 years			25.1 years			22.4 years

Weighted-average discount rate – finance lease (5)	6.0		%	5.9		%	5.3		%
Weighted average discount rate – operating leases (5)	6.3		%	5.9		%	5.8		%

(1) Amortization of right of use assets was included as a component of depreciation and amortization expense.

(2) Interest on lease liabilities was included as a component of interest expense.

(3) Operating and short-term lease expense were included as a component of other operation and maintenance expense.

(4) Amounts are net of any reductions to right of use assets and finance lease liabilities resulting from remeasurements.

(5) Because our leases do not provide an implicit rate of return, we used an estimate of the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments.

The following table summarizes our finance and operating lease right of use assets and obligations at December 31:


(in millions)	2025		2024		Balance Sheet Location
Right of use assets
Operating lease right of use assets, net	$	69.5	$	32.1	Other long-term assets
Finance lease right of use assets, net
Land leases – utility solar generation	$	291.5	$	235.8
Land leases –non-utility energy infrastructure solar generation	42.3		43.5
Other	1.7		2.0
Total finance lease right of use assets, net (1)	$	335.5	$	281.3	Property, plant, and equipment, net

Lease obligations
Current operating lease liabilities	$	3.1	$	4.3	Other current liabilities
Long-term operating lease liabilities	$	73.0	$	37.5	Other long-term liabilities
Current finance lease liabilities
Other	$	0.2	$	0.2	Other current liabilities
Long-term finance lease liabilities
Land leases – utility solar generation	$	327.3	$	257.9
Land leases –non-utility energy infrastructure solar generation	43.3		43.8
Other	1.4		1.6
Total long-term finance lease liabilities	$	372.0	$	303.3	Finance lease obligations

(1) Amounts are net of accumulated amortization of $16.3 million and $10.0 million at December 31, 2025 and 2024, respectively.

Future minimum lease payments under our operating and finance leases and the present value of our net minimum lease payments as of December 31, 2025, were as follows:


(in millions)	Total Operating Leases		Land Leases - Utility Solar Generation		Land Leases - Non-Utility Energy Infrastructure Solar Generation		Other		Total Finance Leases
2026	$	7.0	$	9.5	$	2.2	$	0.3	$	12.0
2027	6.3		13.8		2.3		0.3		16.4
2028	5.2		15.9		2.3		0.1		18.3
2029	5.2		16.2		2.3		0.1		18.6
2030	5.0		16.6		2.4		0.1		19.1
Thereafter	208.2		1,221.0		156.6		2.5		1,380.1
Total minimum lease payments	236.9		1,293.0		168.1		3.4		1,464.5
Less: Interest	(160.8)		(965.7)		(124.8)		(1.8)		(1,092.3)
Present value of minimum lease payments	76.1		327.3		43.3		1.6		372.2
Less: Short-term lease liabilities	(3.1)		—		—		(0.2)		(0.2)
Long-term lease liabilities	$	73.0	$	327.3	$	43.3	$	1.4	$	372.0

As of February 20, 2026, we have not entered into any material leases that have not yet commenced.

Income Taxes

12 Months Ended

Dec. 31, 2025

Income Tax Disclosure [Abstract]

Income Tax Disclosure

INCOME TAXES

We adopted the new disclosure provisions of ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, effective January 1, 2025. See Note 1(q), Income Taxes, for more information on the adoption of this ASU.

Income Tax Expense

The following table is a summary of the components of income tax expense for the years ended December 31:


(in millions)	2025		2024		2023
Current tax expense (benefit)
Federal	$	(242.5)	$	(178.5)	$	(36.7)
State	(8.0)		(128.5)		21.9
Deferred tax expense, net
Federal	240.9		386.2		130.1
State	135.6		152.5		99.8

ITCs, net	(8.0)		(9.7)		(10.5)
Total income tax expense	$	118.0	$	222.0	$	204.6

Statutory Rate Reconciliation

The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following:


	2025				2024				2023
(in millions)	Amount		Effective Tax Rate		Amount		Effective Tax Rate		Amount		Effective Tax Rate
Income before income taxes	$	1,673.5			$	1,746.3			$	1,536.3
US federal statutory income tax rate	$	351.9	21.0	%	$	367.3	21.0	%	$	322.6	21.0	%
State and local income taxes net of federal tax effect (1)	101.2		6.0	%	108.0		6.2	%	94.3		6.1	%
Tax credits
PTCs, net (2)	(261.3)		(15.6)	%	(200.1)		(11.5)	%	(168.2)		(10.9)	%
Other	(8.2)		(0.5)	%	(10.0)		(0.6)	%	(10.9)		(0.7)	%
Nontaxable or nondeductible items
AFUDC-Equity (3)	(21.0)		(1.3)	%	(12.6)		(0.7)	%	(12.4)		(0.8)	%
Other	11.0		0.7	%	4.0		0.2	%	4.4		0.2	%
Changes in unrecognized tax benefits	(2.0)		(0.1)	%	(0.4)		—	%	(1.8)		(0.1)	%
Other adjustments
Federal excess deferred tax amortization (4)	(43.0)		(2.6)	%	(36.7)		(2.1)	%	(37.6)		(2.4)	%
Other, net	(10.6)		(0.5)	%	2.5		0.2	%	14.2		0.9	%
Total income tax expense	$	118.0	7.1	%	$	222.0	12.7	%	$	204.6	13.3	%

(1) State taxes in Wisconsin made up the majority of the tax effect in this category.

(2) PTCs are an inflation adjusted US federal income tax credit for each kilowatt hour of electricity generated by certain renewable energy projects.

(3) AFUDC-Equity represents the cost of capital (i.e. ROE) that is added to the construction cost of an asset while it is being built. The tax benefit for regulated utilities from AFUDC-Equity is a regulatory gross-up to allow the recovery of income taxes on the equity portion of construction costs, even though it is not a tax deductible expense.

(4) The Tax Legislation required our regulated utilities to remeasure their deferred income taxes and we began to amortize the resulting excess deferred income taxes beginning in 2018, in accordance with normalization requirements. The decrease in income tax expense related to the amortization of the deferred tax benefits is offset by a decrease in revenue as the benefits are returned to customers, resulting in no impact on net income.

Deferred Income Tax Assets and Liabilities

The components of deferred income taxes as of December 31 were as follows:


(in millions)	2025		2024
Deferred tax assets
Tax gross up – regulatory items	$	416.9	$	420.1
Future tax benefits	240.9		165.4
Deferred revenues	76.8		76.0
Other	206.1		167.9
Total deferred tax assets	940.7		829.4
Valuation allowance	(1.1)		(1.1)
Net deferred tax assets	$	939.6	$	828.3

Deferred tax liabilities
Property-related	$	5,041.5	$	4,545.2
Investment in affiliates	1,143.6		1,103.9
Employee benefits and compensation	229.2		231.4
Deferred costs – plant retirements	178.0		194.3
Other	239.0		268.2
Total deferred tax liabilities	6,831.3		6,343.0
Deferred tax liability, net	$	5,891.7	$	5,514.7

Consistent with ratemaking treatment, deferred taxes related to our regulated utilities in the table above are offset for temporary differences that have related regulatory assets and liabilities.

The components of net deferred tax assets associated with federal and state tax benefit carryforwards as of December 31, 2025 and 2024 are summarized in the tables below:


2025 (in millions)	Gross Value		Deferred Tax Effect		Valuation Allowance		Earliest Year of Expiration
Future tax benefits as of December 31, 2025
Federal tax credit	$	—	$	206.5	$	—	2042
State net operating loss	685.6		34.1		(1.1)		2032
Other state benefits	—		0.3		—		2029
Balance as of December 31, 2025	$	685.6	$	240.9	$	(1.1)


2024 (in millions)	Gross Value		Deferred Tax Effect		Valuation Allowance		Earliest Year of Expiration
Future tax benefits as of December 31, 2024
Federal tax credit	$	—	$	157.9	$	—	2042
State net operating loss	107.5		7.2		(1.1)		2032
Other state benefits	—		0.3		—		2028
Balance as of December 31, 2024	$	107.5	$	165.4	$	(1.1)

Unrecognized Tax Benefits

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:


(in millions)	2025		2024		2023
Balance as of January 1	$	4.4	$	4.6	$	6.3
Additions for tax positions of prior years	0.1		—		0.2

Reductions for tax positions of prior years	(1.5)		(0.2)		(1.9)



Balance as of December 31	$	3.0	$	4.4	$	4.6

The amount of unrecognized tax benefits as of December 31, 2025 and 2024, excludes deferred tax assets related to uncertainty in income taxes of $0.7 million and $1.0 million, respectively. As of December 31, 2025 and 2024, the net amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations was $2.3 million and $3.4 million, respectively.

Interest accrued related to unrecognized tax benefits is as follows:


(in millions)	2025		2024		2023
Balance as of January 1	$	0.9	$	0.6	$	0.5
Interest expense (income) related to unrecognized tax benefits	(0.6)		0.3		0.1
Balance as of December 31	$	0.3	$	0.9	$	0.6

For the years ended December 31, 2025, 2024, and 2023, we recognized no penalties related to unrecognized tax benefits in our consolidated income statements. At December 31, 2025 and 2024, we had no amounts accrued for penalties related to unrecognized tax benefits.

We file income tax returns in the United States federal jurisdiction and state tax returns based on income in our major state operating jurisdictions of Wisconsin, Illinois, Michigan, and Minnesota. We also file tax returns in other state and local jurisdictions with varying statutes of limitations. As of December 31, 2025, with a few exceptions, we were subject to examination by federal and state or local tax authorities for the 2021 through 2025 tax years in our major operating jurisdictions as follows:


Jurisdiction						Years
Federal						2022–2025
Illinois						2021–2025
Michigan						2021–2025
Minnesota						2021–2025
Wisconsin						2021–2025

Cash Received For Income Taxes, Net

The table below is a summary of income taxes paid (received) by jurisdiction for the years ended December 31:


(in millions)	2025			2024			2023
Federal	$	(256.3)	(1)	$	(265.0)	(2)	$	(75.0)	(3)
State	(25.0)			0.8			16.1
Total income taxes received, net	$	(281.3)		$	(264.2)		$	(58.9)

(1) Includes $256.3 million related to 2025 and 2024 PTCs that were sold to third parties.

(2) Includes $269.1 million related to 2024 and 2023 PTCs that were sold to third parties.

(3) Includes $75.0 million related to 2023 PTCs that were sold to third parties.

Income taxes received or paid (net of refunds) exceeded 5 percent of total income taxes received or paid (net of refunds) in the following jurisdiction:


(in millions)	2025		2024			2023
Wisconsin	$	(25.0)	$	—	(1)	$	12.0

(1) Jurisdiction below the threshold for the period presented.

- Definition

The entire disclosure for income tax.

+ References

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+ Details

Fair Value Measurements

12 Months Ended

Dec. 31, 2025

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:


	December 31, 2025
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	1.5	$	18.3	$	—	$	19.8
FTRs and TCRs	—		—		6.5		6.5
Total derivative assets	$	1.5	$	18.3	$	6.5	$	26.3

Investments held in rabbi trust	$	42.0	$	—	$	—	$	42.0

Derivative liabilities
Natural gas contracts	$	23.3	$	8.4	$	—	$	31.7
FTRs and TCRs	—		—		0.8		0.8
Total derivative liabilities	$	23.3	$	8.4	$	0.8	$	32.5


	December 31, 2024
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	19.6	$	13.7	$	—	$	33.3
FTRs and TCRs	—		—		7.8		7.8
Total derivative assets	$	19.6	$	13.7	$	7.8	$	41.1

Investments held in rabbi trust	$	52.1	$	—	$	—	$	52.1

Derivative liabilities
Natural gas contracts	$	7.1	$	6.8	$	—	$	13.9

The derivative assets and liabilities listed in the tables above include options, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs and TCRs, which are used at our electric utilities and certain of our non-utility wind parks to manage electric transmission congestion costs in the MISO Energy Markets and the Southwest Power Pool, Inc. Integrated Marketplace, respectively.

We hold investments in the Integrys rabbi trust. These investments are used to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans. These investments are included in other long-term assets on our balance sheets. During the years ended December 31, 2025, 2024, and 2023, the net unrealized gains included in earnings related to the investments held at the end of the period were $5.8 million, $9.0 million, and $10.0 million, respectively.

The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy at December 31:


(in millions)	2025		2024		2023
Balance at the beginning of the period	$	7.8	$	7.2	$	7.8
Purchases	23.7		28.7		21.0
Net realized and unrealized losses included in earnings (1)	—		(0.7)		(0.5)
Sales	(1.0)		—		—
Settlements	(24.8)		(27.4)		(21.1)
Balance at the end of the period	$	5.7	$	7.8	$	7.2
Net unrealized gains included in earnings attributable to Level 3 derivatives held at the end of the reporting period (1)	$	0.1	$	—	$	0.5

(1) Amounts relate to FTRs and TCRs included in our non-utility energy infrastructure segment. These net realized and unrealized gains and losses are recorded in operating revenues on our income statements.

Fair Value of Financial Instruments

The following table shows the financial instruments included on our balance sheets that are not recorded at fair value at December 31:


	2025				2024
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock of subsidiary	$	30.4	$	21.2	$	30.4	$	21.2
Long-term debt, including current portion	20,017.5		19,609.1		18,907.1		17,840.8

The fair values of our long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

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+ Details

Derivative Instruments

12 Months Ended

Dec. 31, 2025

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS

Derivative assets and liabilities are included in the other current and other long-term line items on our balance sheets. The following table shows our derivative assets and derivative liabilities. None of the derivatives shown below were designated as hedging instruments.


	December 31, 2025				December 31, 2024
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Current
Natural gas contracts	$	19.7	$	30.0	$	29.2	$	13.9
FTRs and TCRs	6.5		0.8		7.8		—
Total current	26.2		30.8		37.0		13.9

Long-term
Natural gas contracts	0.1		1.7		4.1		—

Total	$	26.3	$	32.5	$	41.1	$	13.9

Realized gains and losses on derivatives used in our regulated utility operations are recorded in cost of sales upon settlement; however, they may be subsequently deferred for future rate recovery or refund as the gains and losses are included in our utilities’ fuel and natural gas cost recovery mechanisms. Realized gains and losses on FTRs and TCRs used in our non-utility operations are recorded in operating revenues on the income statements. Our realized gains and losses and the estimated notional volumes related to these settlements were as follows for the years ended:


	December 31, 2025			December 31, 2024			December 31, 2023
(in millions)	Volumes	Gains (Losses)		Volumes	Gains (Losses)		Volumes	Gains (Losses)
Natural gas contracts	202.4 Dth	$	(19.2)	206.3 Dth	$	(127.8)	198.0 Dth	$	(259.1)
FTRs and TCRs
Regulated utility operations	26.3 MWh	18.9		28.4 MWh	8.3		29.3 MWh	27.4
Non-utility operations	0.7 MWh	(0.1)		1.3 MWh	(0.1)		0.9 MWh	(1.5)
Total		$	(0.4)		$	(119.6)		$	(233.2)

At December 31, 2025 and 2024, we had posted cash collateral of $41.4 million and $16.0 million, respectively. We had also received cash collateral of $4.2 million at December 31, 2024.

The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets:


	December 31, 2025					December 31, 2024
(in millions)	Derivative Assets		Derivative Liabilities			Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	26.3	$	32.5		$	41.1		$	13.9
Gross amount not offset on the balance sheet	(2.0)		(23.8)		(1)	(11.5)		(2)	(7.3)
Net amount	$	24.3	$	8.7		$	29.6		$	6.6

(1) Includes cash collateral posted of $21.8 million.

(2) Includes cash collateral received of $4.2 million.

Cash Flow Hedges

We previously entered into forward interest rate swap agreements to mitigate the interest rate exposure associated with the issuance of long-term debt related to the acquisition of Integrys. These swap agreements were settled in 2015, and we continue to amortize amounts out of accumulated other comprehensive loss into interest expense over the periods in which the interest costs are recognized in earnings. The derivative gains related to these swap agreements reclassified from accumulated other comprehensive loss to interest expense during the years ended December 31, 2025, 2024, and 2023 were not significant. At December 31, 2025, the amount expected to be reclassified from accumulated other comprehensive loss to interest expense over the next twelve months was also not significant.

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

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+ Details

Guarantees

12 Months Ended

Dec. 31, 2025

Guarantees [Abstract]

GUARANTEES

The following table shows our outstanding guarantees:


	Total Amounts Committed at December 31, 2025		Expiration

(in millions)			Less Than 1 Year		1 to 3 Years		Over 3 Years
Standby letters of credit (1)	$	188.2	$	30.7	$	30.2	$	127.3
Surety bonds (2)	46.5		46.4		0.1		—
Other guarantees (3)	9.6		—		—		9.6
Total guarantees	$	244.3	$	77.1	$	30.3	$	136.9

(1) At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets.

(2) Primarily for environmental remediation, workers compensation self-insurance programs, and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets.

(3) Related to workers compensation coverage for which a liability was recorded on our balance sheets.

- Definition

The entire disclosure for each guarantee obligation, or each group of similar guarantee obligations, including (a) the nature of the guarantee, including its term, how it arose, and the events or circumstances that would require the guarantor to perform under the guarantee; (b) the maximum potential amount of future payments (undiscounted) the guarantor could be required to make under the guarantee; (c) the current carrying amount of the liability, if any, for the guarantor's obligations under the guarantee; and (d) the nature of any recourse provisions under the guarantee, and any assets held either as collateral or by third parties, and any relevant related party disclosure. Excludes disclosures about product warranties.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 235
-Name Accounting Standards Codification
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-Publisher FASB
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Reference 10: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

Employee Benefits

12 Months Ended

Dec. 31, 2025

Retirement Benefits [Abstract]

EMPLOYEE BENEFITS

Pension and Other Postretirement Employee Benefits

We and our subsidiaries have defined benefit pension plans that cover substantially all of our employees, as well as several unfunded non-qualified retirement plans. In addition, we and our subsidiaries offer multiple OPEB plans to employees. The benefits for a portion of these plans are funded through irrevocable trusts, as allowed for income tax purposes. We also offer medical, dental, and life insurance benefits to active employees and their dependents. We expense the costs of these benefits as incurred.

Generally, other than those employees who receive a contribution to their 401(k) savings plan as described below, former Wisconsin Energy Corporation employees receive a benefit based on a percentage of their annual salary plus an interest credit. Wisconsin Energy Corporation management employees hired after December 31, 2014, and certain new represented employees hired after May 1, 2017, receive an annual company contribution to their 401(k) savings plan instead of being enrolled in the defined benefit plans.

For former Integrys employees, the defined benefit pension plans are closed to all new hires. In addition, the service accruals for the defined benefit pension plans were frozen for non-union employees as of January 1, 2013. These employees receive an annual company contribution to their 401(k) savings plan, which is calculated based on age, wages, and full years of vesting service as of December 31 each year.

We use a year-end measurement date to measure the funded status of all of our pension and OPEB plans. Due to the regulated nature of our business, we have concluded that substantially all of the unrecognized costs resulting from the recognition of the funded status of our pension and OPEB plans qualify as a regulatory asset.

The following tables provide a reconciliation of the changes in our plans' benefit obligations and fair value of assets:


	Pension Benefits				OPEB Benefits
(in millions)	2025		2024		2025		2024
Change in benefit obligation
Obligation at January 1	$	2,209.2	$	2,352.4	$	460.9	$	448.1
Service cost	20.8		24.2		11.3		10.9
Interest cost	118.6		116.6		25.7		22.7
Participant contributions	—		—		11.5		11.2
Plan amendments	—		—		(0.4)		—
Actuarial (gain) loss	8.2		(99.6)		28.3		6.9
Benefit payments	(193.7)		(184.4)		(46.8)		(41.7)
Federal subsidy on benefits paid	N/A		N/A		1.4		1.4
Transfer	—		—		1.5		1.4
Obligation at December 31	$	2,163.1	$	2,209.2	$	493.4	$	460.9

Change in fair value of plan assets
Fair value at January 1	$	2,624.3	$	2,665.8	$	850.0	$	829.6
Actual return on plan assets	221.6		129.8		87.9		49.5
Employer contributions net of plan transfer	11.8		13.1		1.9		1.4
Participant contributions	—		—		11.5		11.2
Benefit payments	(193.7)		(184.4)		(46.8)		(41.7)
Fair value at December 31	$	2,664.0	$	2,624.3	$	904.5	$	850.0
Funded status at December 31	$	500.9	$	415.1	$	411.1	$	389.1

In 2025, we had actuarial losses related to our pension benefit obligations of $8.2 million and actuarial gains in 2024 of $99.6 million. The primary driver for the actuarial loss was the decrease in discount rate. The primary driver for the actuarial gain was a higher discount rate in 2024. Partially offsetting the gain in 2024, was lower than expected asset returns. The discount rate for our pension benefits was 5.50%, 5.69%, and 5.19% in 2025, 2024, and 2023, respectively.

In 2025 and 2024, we had actuarial losses related to our OPEB benefit obligation of $28.3 million and $6.9 million, respectively, both of which were driven by changes to medical trend assumptions and claims and premium updates. The 2025 loss was also driven by a lower discount rate. Partially offsetting the loss in 2024, was a higher discount rate. The discount rate for our OPEB benefits was 5.54%, 5.71%, and 5.16% in 2025, 2024, and 2023, respectively.

The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows:


	Pension Benefits				OPEB Benefits
(in millions)	2025		2024		2025		2024
Pension and OPEB assets	$	646.3	$	562.4	$	436.1	$	406.1
Other long-term liabilities	145.4		147.3		25.0		17.0
Total net assets	$	500.9	$	415.1	$	411.1	$	389.1

The accumulated benefit obligation for all defined benefit pension plans was $2,112.5 million and $2,156.8 million as of December 31, 2025 and 2024, respectively.

The following table shows information for pension plans with an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31:


(in millions)	2025		2024
Accumulated benefit obligation	$	283.0	$	286.0
Fair value of plan assets	141.7		143.2

The following table shows information for pension plans with a projected benefit obligation in excess of plan assets. Amounts presented are as of December 31:


(in millions)	2025		2024
Projected benefit obligation	$	287.1	$	290.5
Fair value of plan assets	141.7		143.2

The following table shows information for OPEB plans with an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31:


(in millions)	2025		2024
Accumulated benefit obligation	$	205.5	$	194.0
Fair value of plan assets	180.5		177.0

The following table shows the amounts that had not yet been recognized in our net periodic benefit cost (credit) as of December 31:


	Pension Benefits				OPEB Benefits
(in millions)	2025		2024		2025		2024
Pre-tax accumulated other comprehensive income (loss) (1)
Net actuarial loss (gain)	$	11.6	$	12.3	$	(1.0)	$	(1.1)



Net regulatory assets (liabilities) (2)
Net actuarial loss (gain)	$	501.1	$	578.7	$	(146.1)	$	(148.8)
Prior service credits	(2.0)		(2.1)		(8.4)		(15.8)
Total	$	499.1	$	576.6	$	(154.5)	$	(164.6)

(1) Amounts related to the nonregulated entities are included in accumulated other comprehensive loss.

(2) Amounts related to the utilities and WBS are recorded as net regulatory assets or liabilities.

The components of net periodic benefit cost (credit) (including amounts capitalized to our balance sheets) for the years ended December 31 were as follows:


	Pension Benefits						OPEB Benefits
(in millions)	2025		2024		2023		2025		2024		2023
Service cost	$	20.8	$	24.2	$	24.0	$	11.3	$	10.9	$	9.8
Interest cost	118.6		116.6		122.3		25.7		22.7		21.6
Expected return on plan assets	(175.1)		(182.1)		(187.4)		(54.3)		(52.7)		(53.0)
Plan settlement	(1.2)		4.0		1.3		—		—		—

Amortization of prior service cost (credit)	(0.1)		(0.1)		—		(7.8)		(13.5)		(14.8)
Amortization of net actuarial loss (gain)	41.1		59.5		33.0		(8.2)		(7.6)		(12.3)
Net periodic benefit cost (credit)	$	4.1	$	22.1	$	(6.8)	$	(33.3)	$	(40.2)	$	(48.7)

Effective January 1, 2023, the PSCW approved escrow accounting for pension and OPEB costs. As a result, as of December 31, 2025 and 2024, our balance sheet included a $14.7 million regulatory liability and a $24.9 million regulatory asset for pension costs, respectively, and a $0.7 million and a $38.2 million regulatory asset for OPEB costs, respectively.

The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31:


	Pension Benefits		OPEB Benefits
	2025	2024	2025	2024
Discount rate	5.50%	5.69%	5.54%	5.71%
Rate of compensation increase	4.00%	4.00%	N/A	N/A
Interest credit rate	4.83%	4.85%	N/A	N/A
Assumed medical cost trend rate (Pre 65)	N/A	N/A	8.00%	7.00%
Ultimate trend rate (Pre 65)	N/A	N/A	5.00%	5.00%
Year ultimate trend rate is reached (Pre 65)	N/A	N/A	2032	2033
Assumed medical cost trend rate (Post 65)	N/A	N/A	9.92%	6.10%
Ultimate trend rate (Post 65)	N/A	N/A	5.00%	5.00%
Year ultimate trend rate is reached (Post 65)	N/A	N/A	2034	2030

The weighted-average assumptions used to determine the net periodic benefit cost for the plans were as follows for the years ended December 31:


	Pension Benefits
	2025	2024	2023
Discount rate	5.69%	5.18%	5.49%
Expected return on plan assets	6.61%	6.61%	6.62%
Rate of compensation increase	4.00%	4.00%	4.00%
Interest credit rate	4.85%	4.84%	4.62%


	OPEB Benefits
	2025	2024	2023
Discount rate	5.71%	5.16%	5.50%
Expected return on plan assets	6.50%	6.50%	6.50%
Assumed medical cost trend rate (Pre 65)	7.00%	6.25%	6.50%
Ultimate trend rate (Pre 65)	5.00%	5.00%	5.00%
Year ultimate trend rate is reached (Pre 65)	2033	2031	2031
Assumed medical cost trend rate (Post 65)	6.10%	6.39%	6.00%
Ultimate trend rate (Post 65)	5.00%	5.00%	5.00%
Year ultimate trend rate is reached (Post 65)	2030	2030	2031

We consult with our investment advisors on an annual basis to help us forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the trust. For 2026, the expected return on assets assumption is 6.61% for the pension plans and 6.50% for the OPEB plans.

Plan Assets

Current pension trust assets and amounts which are expected to be contributed to the trusts in the future are expected to be adequate to meet pension payment obligations to current and future retirees.

The Investment Trust Policy Committee oversees investment matters related to all of our funded benefit plans. The Committee works with external actuaries and investment consultants on an on-going basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. They are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments.

The target asset allocations are 25% equity investments, 55% fixed income investments, and 20% private equity and real estate investments for both the legacy Wisconsin Energy Corporation and legacy Integrys pension trusts. The legacy Wisconsin Energy Corporation OPEB trust target asset allocations are 45% equity investments, 45% fixed income investments, and 10% real estate

investments. The two largest legacy OPEB trusts for Integrys have the same target asset allocations of 45% equity investments, 45% fixed income investments, and 10% real estate investments. Equity securities include investments in large-cap, mid-cap, and small-cap companies. Fixed income securities include corporate bonds of companies from diversified industries, mortgage and other asset backed securities, commercial paper, and United States Treasuries.

Pension and OPEB plan investments are recorded at fair value. See Note 1(r), Fair Value Measurements, for more information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used.

The following tables provide the fair values of our investments by asset class:


	December 31, 2025
	Pension Plan Assets								OPEB Assets
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Asset Class
Equity securities:
United States equity	$	160.8	$	—	$	—	$	160.8	$	97.3	$	—	$	—	$	97.3
International equity	173.7		—		—		173.7		100.8		—		—		100.8
Fixed income securities: (1)
United States bonds	—		933.5		1.4		934.9		110.6		219.3		0.1		330.0
International bonds	—		63.5		—		63.5		—		7.7		—		7.7
	$	334.5	$	997.0	$	1.4	$	1,332.9	$	308.7	$	227.0	$	0.1	$	535.8
Investments measured at net asset value:
Equity securities							412.6								206.0
Fixed income securities							127.6								55.3
Other							790.9								107.4
Total							$	2,664.0							$	904.5

(1) This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries.


	December 31, 2024
	Pension Plan Assets								OPEB Assets
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Asset Class
Equity securities:
United States equity	$	168.4	$	—	$	—	$	168.4	$	93.8	$	—	$	—	$	93.8
International equity	158.2		—		—		158.2		86.4		—		—		86.4
Fixed income securities: (1)
United States bonds	—		880.1		—		880.1		99.0		205.6		—		304.6
International bonds	—		81.6		—		81.6		—		11.2		—		11.2
	$	326.6	$	961.7	$	—	$	1,288.3	$	279.2	$	216.8	$	—	$	496.0
Investments measured at net asset value:
Equity securities							414.9								190.4
Fixed income securities							126.0								51.8
Other							795.1								111.8
Total							$	2,624.3							$	850.0

(1) This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries.

The following tables set forth a reconciliation of changes in fair values of pension and OPEB plan assets categorized as Level 3 in the fair value hierarchy:


	United States Bonds
(in millions)		Pension		OPEB
Beginning balance at January 1, 2025		$	—	$	—

Purchases		1.4		0.1

Ending balance at December 31, 2025		$	1.4	$	0.1

Cash Flows

We expect to contribute $16.5 million to the pension plans and $2.8 million to the OPEB plans in 2026, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

The following table shows the payments, reflecting expected future service, that we expect to make for pension and OPEB over the next 10 years:


(in millions)	Pension Benefits		OPEB Benefits
2026	$	213.5	$	35.5
2027	203.1		37.6
2028	193.5		38.7
2029	187.5		39.5
2030	182.1		39.8
2031-2035	801.3		197.8

Savings Plans

We sponsor 401(k) savings plans which allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. A percentage of employee contributions are matched by us through a contribution into the employee's savings plan account, up to certain limits. The 401(k) savings plans include an Employee Stock Ownership Plan. Certain employees receive a retirement contribution in lieu of receiving a pension benefit. Total costs incurred under all of these plans were $67.3 million, $61.6 million, and $57.5 million in 2025, 2024, and 2023, respectively.

- Definition

The entire disclosure for retirement benefits.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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-Paragraph 1
-Subparagraph (l)
-Publisher FASB
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+ Details

Investment in Transmission Affiliates

12 Months Ended

Dec. 31, 2025

Equity Method Investments and Joint Ventures [Abstract]

INVESTMENT IN TRANSMISSION AFFILATES

INVESTMENT IN TRANSMISSION AFFILIATES

We own approximately 60% of ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects. We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. ATC's corporate manager has an 11-member board of directors, and ATC Holdco's corporate manager has a four-member board of directors. We have one representative on each board. Each member of the board has only one vote. The following tables provide a reconciliation of the changes in our investments in ATC and ATC Holdco:


	2025
(in millions)	ATC		ATC Holdco		Total
Balance at January 1	$	2,085.1	$	23.8	$	2,108.9
Add: Earnings from equity method investment	209.7		6.1		215.8
Add: Capital contributions	142.4		—		142.4
Less: Distributions	180.2		6.4		186.6
Less: Other	0.1		—		0.1
Balance at December 31	$	2,256.9	$	23.5	$	2,280.4


	2024
(in millions)	ATC		ATC Holdco		Total
Balance at January 1	$	1,980.8	$	25.1	$	2,005.9
Add: Earnings from equity method investment	205.4		2.1		207.5
Add: Capital contributions	45.5		—		45.5
Less: Distributions	146.7		3.4		150.1
Add: Other	0.1		—		0.1
Balance at December 31	$	2,085.1	$	23.8	$	2,108.9


	2023
(in millions)	ATC		ATC Holdco		Total
Balance at January 1	$	1,884.6	$	24.6	$	1,909.2
Add: Earnings from equity method investment	175.1		2.4		177.5
Add: Capital contributions	63.7		—		63.7
Less: Distributions	142.6		1.9		144.5
Balance at December 31	$	1,980.8	$	25.1	$	2,005.9

The ROE allowed by the FERC helps determine how much transmission owners, such as ATC, earn on their transmission assets as well as how much consumers pay for those assets. In November 2013, a complaint was filed arguing the base ROE for MISO transmission owners was too high. The D.C. Circuit Court of Appeals issued an opinion in August 2022 for this ROE complaint that resulted in ATC recording a reserve for potential refunds based on a 9.88% base ROE. In response to this opinion, the FERC issued an order in October 2024 that required ATC to adopt a 9.98% base ROE. Due to the change between the 9.88% base ROE originally reflected in ATC's reserve and the 9.98% base ROE authorized in the October 2024 FERC order, ATC reduced its refund liability, which increased our pre-tax equity earnings by $20.1 million during 2024.

We pay ATC for network transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed by ATC. We are also required to initially fund the construction of transmission infrastructure upgrades needed for new generation projects. ATC owns these transmission assets and reimburses us for these costs when the new generation is placed in service.

The following table summarizes our significant related party transactions with ATC during the years ended December 31:


(in millions)	2025		2024		2023
Charges to ATC for services and construction	$	20.2	$	21.6	$	17.4
Charges from ATC for network transmission services	466.9		413.3		377.5
Refund from ATC related to FERC ROE orders	5.2		—		—

As of December 31, 2025 and 2024, our balance sheets included the following receivables and payables for services provided to or received from ATC:


(in millions)	2025		2024
Accounts receivable for services provided to ATC	$	1.6	$	1.4
Accounts payable for services received from ATC	38.4		34.4
Amounts due from ATC for transmission infrastructure upgrades (1)	32.2		54.5

(1) The transmission infrastructure upgrades were primarily related to the construction of WE's, WPS's, and UMERC's renewable energy projects.

Summarized financial data for ATC is included in the tables below:


	Year Ended December 31
(in millions)	2025		2024		2023
Income statement data
Operating revenues	$	975.0	$	911.3	$	818.9
Operating expenses	472.6		442.4		407.6
Other expense, net	165.8		137.7		131.7
Net income	$	336.6	$	331.2	$	279.6


(in millions)	December 31, 2025		December 31, 2024
Balance sheet data
Current assets	$	137.5	$	126.6
Noncurrent assets	7,590.8		6,792.6
Total assets	$	7,728.3	$	6,919.2

Current liabilities	$	839.8	$	482.4
Long-term debt	3,156.3		3,083.4
Other noncurrent liabilities	638.9		545.0
Members' equity	3,093.3		2,808.4
Total liabilities and members' equity	$	7,728.3	$	6,919.2

Segment Information

12 Months Ended

Dec. 31, 2025

Segment Reporting [Abstract]

SEGMENT INFORMATION

Our President and CEO, who is our CODM, reviews financial information presented on a segment basis for purposes of making operating decisions and assessing performance. The CODM regularly reviews net income attributed to common shareholders to measure segment profitability and to allocate resources, including assets, to our businesses. Net income attributed to common shareholders best measures our segment profitability as it reflects all revenues and costs, including the impact on our tax provision from tax credits generated through investments in renewable generation facilities.

Our CODM allocates resources, such as employees, as well as financial and capital resources, to our segments during the annual review of budgets and the capital plan. Our CODM also reviews and revises the resources throughout the year during the monthly forecasting process in order to make timely decisions that align with our overall corporate strategy. The CODM uses each segment’s net income to evaluate performance by comparing actual results to budgeted and forecasted amounts, as well as the ROE earned for each utility within the various utility segments.

Segments were determined based on a combination of factors, including the regulatory environment of each geographical jurisdiction in which the segment operates, equity investment interests, as well as the revenue streams for the products or services provided to customers through electric, natural gas, and renewable operations. See Note 4, Operating Revenues, for more information on disaggregation of operating revenues, including intercompany eliminations. The accounting policies of the segments are the same as those described in Note 1, Summary of Significant Accounting Policies.

At December 31, 2025, we reported six segments, which are described below. All of our operations are located within the United States.

•The Wisconsin segment includes the electric and natural gas utility operations of WE, WPS, WG, and UMERC.

•The Illinois segment includes the natural gas utility operations of PGL and NSG.

•The other states segment includes the natural gas utility operations of MERC and MGU and the non-utility operations of MERC.

•The electric transmission segment includes our approximate 60% ownership interest in ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects, and our approximate 75% ownership interest in ATC Holdco, which was formed to invest in transmission-related projects outside of ATC's traditional footprint. See Note 21, Investment in Transmission Affiliates, for more information on ATC and ATC Holdco.

•The non-utility energy infrastructure segment includes:

◦We Power, which owns and leases generating facilities to WE,

◦Bluewater, which owns underground natural gas storage facilities in Michigan that provide approximately one-third of the current storage needs for our Wisconsin natural gas utilities, and

◦WECI, which owns majority interests in multiple renewable generating facilities.

See Note 2, Acquisitions, for more information on recent WECI acquisitions.

•The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Wisvest, WECC, and WBS.

The following tables show summarized financial information related to our reportable segments for the years ended December 31, 2025, 2024, and 2023.


	Utility Operations
2025 (in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Electric Transmission		Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations		WEC Energy Group Consolidated
External revenues	$	7,295.5	$	1,683.6	$	527.5	$	9,506.6	$	—	$	293.5	$	—	$	—	$	9,800.1
Intersegment revenues	—		—		—		—		—		476.7		—		(476.7)		—
Fuel and purchased power	1,674.9		—		—		1,674.9		—		—		—		—		1,674.9
Cost of natural gas sold	871.5		508.0		246.3		1,625.8		—		9.6		—		(44.5)		1,590.9
Other operation and maintenance	1,737.9		482.2		104.6		2,324.7		—		95.5		(10.2)		(9.2)		2,400.8
Impairments related to Illinois segment	—		130.0		—		130.0		—		—		—		—		130.0
Depreciation and amortization	1,008.1		259.7		49.8		1,317.6		—		240.2		21.6		(100.9)		1,478.5

Property and revenue taxes	178.7		55.5		26.2		260.4		—		19.6		0.1		—		280.1
Equity in earnings of transmission affiliates	—		—		—		—		215.8		—		—		—		215.8
Other income, net (1)	96.5		8.6		0.4		105.5		—		2.8		30.6		(31.0)		107.9
Interest expense	638.7		88.9		19.2		746.8		19.3		123.1		359.0		(353.1)		895.1

Income tax expense (benefit)	226.2		45.8		21.0		293.0		48.9		(122.9)		(101.0)		—		118.0
Preferred stock dividends of subsidiary	1.2		—		—		1.2		—		—		—		—		1.2
Net loss attributed to noncontrolling interests	—		—		—		—		—		3.2		—		—		3.2
Net income (loss) attributed to common shareholders	$	1,054.8	$	122.1	$	60.8	$	1,237.7	$	147.6	$	411.1	$	(238.9)	$	—	$	1,557.5

Other Segment Disclosures
Capital expenditures and asset acquisitions	$	3,860.1	$	306.1	$	112.5	$	4,278.7	$	—	$	504.7	$	20.8	$	—	$	4,804.2
Equity method investments	17.8		—		—		17.8		2,280.4		—		55.7		—		2,353.9
Total assets (2)	33,984.7		8,167.7		1,733.3		43,885.7		2,282.8		7,762.9		1,227.6		(3,640.7)		51,518.3

(1)Includes amounts that are not material for interest income and other equity earnings from investments other than from transmission affiliates.

(2) Total assets at December 31, 2025 reflect an elimination of $2,594.8 million for all lease activity between We Power and WE.


	Utility Operations
2024 (in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Electric Transmission		Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations		WEC Energy Group Consolidated
External revenues	$	6,330.5	$	1,602.4	$	449.8	$	8,382.7	$	—	$	217.2	$	—	$	—	$	8,599.9
Intersegment revenues	—		—		—		—		—		474.1		—		(474.1)		—
Fuel and purchased power	1,455.7		—		—		1,455.7		—		—		—		—		1,455.7
Cost of natural gas sold	661.9		376.7		198.6		1,237.2		—		9.1		—		(46.0)		1,200.3
Other operation and maintenance	1,547.9		461.5		93.9		2,103.3		—		75.1		(11.3)		(9.1)		2,158.0
Impairments related to Illinois segment	—		12.1		—		12.1		—		—		—		—		12.1
Depreciation and amortization	919.9		255.4		47.0		1,222.3		—		198.4		22.3		(88.5)		1,354.5

Property and revenue taxes	169.6		59.9		21.0		250.5		—		15.7		0.3		—		266.5
Equity in earnings of transmission affiliates	—		—		—		—		207.5		—		—		—		207.5
Other income, net (1)	146.6		7.6		0.3		154.5		—		1.0		54.4		(31.7)		178.2
Interest expense	637.3		94.7		16.4		748.4		19.4		99.7		310.0		(362.2)		815.3
Gain on debt extinguishments	—		—		—		—		—		—		(23.1)		—		(23.1)
Income tax expense (benefit)	220.5		97.6		18.7		336.8		47.1		(82.4)		(79.5)		—		222.0
Preferred stock dividends of subsidiary	1.2		—		—		1.2		—		—		—		—		1.2
Net loss attributed to noncontrolling interests	—		—		—		—		—		4.1		—		—		4.1
Net income (loss) attributed to common shareholders	$	863.1	$	252.1	$	54.5	$	1,169.7	$	141.0	$	380.8	$	(164.3)	$	—	$	1,527.2

Other Segment Disclosures
Capital expenditures and asset acquisitions	$	2,347.1	$	343.0	$	118.3	$	2,808.4	$	—	$	945.8	$	20.6	$	—	$	3,774.8
Equity method investments	15.7		—		—		15.7		2,108.9		—		67.0		—		2,191.6
Total assets (2)	30,622.7		8,168.8		1,646.0		40,437.5		2,126.0		7,316.0		1,037.3		(3,553.6)		47,363.2

(1)Includes amounts that are not material for interest income and other equity earnings from investments other than from transmission affiliates.

(2) Total assets at December 31, 2024 reflect an elimination of $1,525.4 million for all lease activity between We Power and WE.


	Utility Operations
2023 (in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Electric Transmission		Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations		WEC Energy Group Consolidated
External revenues	$	6,625.9	$	1,557.8	$	519.1	$	8,702.8	$	—	$	190.1	$	0.1	$	—	$	8,893.0
Intersegment revenues	—		—		—		—		—		476.4		—		(476.4)		—
Fuel and purchased power	1,615.9		—		—		1,615.9		—		—		—		—		1,615.9
Cost of natural gas sold	894.7		443.0		277.2		1,614.9		—		20.5		—		(60.1)		1,575.3
Other operation and maintenance	1,531.3		397.9		94.5		2,023.7		—		80.1		5.8		(9.1)		2,100.5
Impairments related to Illinois segment	—		178.9		—		178.9		—		—		—		—		178.9
Depreciation and amortization	851.5		237.3		43.3		1,132.1		—		188.7		20.9		(77.5)		1,264.2

Property and revenue taxes	179.2		29.9		24.4		233.5		—		16.5		0.2		—		250.2
Equity in earnings of transmission affiliates	—		—		—		—		177.5		—		—		—		177.5
Other income, net (1)	137.6		6.7		0.6		144.9		—		—		53.3		(20.5)		177.7
Interest expense	601.0		88.9		15.9		705.8		19.4		94.3		258.1		(350.2)		727.4
Gain on debt extinguishments	—		—		—		—		—		—		(0.5)		—		(0.5)
Income tax expense (benefit)	237.4		48.6		16.3		302.3		39.0		(68.4)		(68.3)		—		204.6
Preferred stock dividends of subsidiary	1.2		—		—		1.2		—		—		—		—		1.2
Net loss attributed to noncontrolling interests	—		—		—		—		—		1.2		—		—		1.2
Net income (loss) attributed to common shareholders	$	851.3	$	140.0	$	48.1	$	1,039.4	$	119.1	$	336.0	$	(162.8)	$	—	$	1,331.7

Other Segment Disclosures
Capital expenditures and asset acquisitions	$	2,134.4	$	489.8	$	103.5	$	2,727.7	$	—	$	754.4	$	25.8	$	—	$	3,507.9
Equity method investments	14.4		—		—		14.4		2,005.9		—		61.3		—		2,081.6
Total assets (2)	28,527.3		7,970.2		1,571.5		38,069.0		2,006.0		6,404.7		1,100.1		(3,640.1)		43,939.7

(1) Includes amounts that are not material for interest income and other equity earnings from investments other than from transmission affiliates.

(2) Total assets at December 31, 2023 reflect an elimination of $1,630.6 million for all lease activity between We Power and WE.

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

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-Name Accounting Standards Codification
-Section 50
-Paragraph 40
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-40

Reference 23: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/280/tableOfContent

Reference 24: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 26
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-26

Reference 25: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 41
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-41

+ Details

Variable Interest Entities

12 Months Ended

Dec. 31, 2025

Organization, Consolidation and Presentation of Financial Statements [Abstract]

VARIABLE INTEREST ENTITIES

The primary beneficiary of a VIE must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in VIEs.

We assess our relationships with potential VIEs, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to PPAs, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the

obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance.

WEPCo Environmental Trust Finance I, LLC

In November 2020, the PSCW issued a financing order approving the securitization of $100 million of undepreciated environmental control costs related to WE's retired Pleasant Prairie power plant, the carrying costs accrued on the $100 million during the securitization process, and the related financing fees. The financing order also authorized WE to form WEPCo Environmental Trust, a bankruptcy-remote special purpose entity, for the sole purpose of issuing ETBs to recover the costs approved in the financing order. WEPCo Environmental Trust is a wholly owned subsidiary of WE.

In May 2021, WEPCo Environmental Trust issued ETBs and used the proceeds to acquire environmental control property from WE. The environmental control property is recorded as a regulatory asset on our balance sheets and includes the right to impose, collect, and receive a non-bypassable environmental control charge from WE's retail electric distribution customers until the ETBs are paid in full and all financing costs have been recovered. The ETBs are secured by the environmental control property. Cash collections from the environmental control charge and funds on deposit in trust accounts are the sole sources of funds to satisfy the debt obligation. The bondholders do not have any recourse to WE or any of WE's affiliates.

WE acts as the servicer of the environmental control property on behalf of WEPCo Environmental Trust and is responsible for metering, calculating, billing, and collecting the environmental control charge. As necessary, WE is authorized to implement periodic adjustments of the environmental control charge. The adjustments are designed to ensure the timely payment of principal, interest, and other ongoing financing costs. WE remits all collections of the environmental control charge to WEPCo Environmental Trust's indenture trustee.

WEPCo Environmental Trust is a VIE primarily because its equity capitalization is insufficient to support its operations. As described above, WE has the power to direct the activities that most significantly impact WEPCo Environmental Trust's economic performance. Therefore, WE is considered the primary beneficiary of WEPCo Environmental Trust, and consolidation is required.

The following table summarizes the impact of WEPCo Environmental Trust on our balance sheets:


(in millions)	December 31, 2025		December 31, 2024
Assets
Other current assets (restricted cash)	$	2.0	$	1.5
Regulatory assets	67.5		76.5
Other long-term assets (restricted cash)	0.6		0.6

Liabilities
Current portion of long-term debt	9.3		9.2
Accounts payable	0.1		—
Other current liabilities (accrued interest)	0.1		0.1
Long-term debt	67.4		76.4

Investment in Transmission Affiliates

We own approximately 60% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. We have determined that ATC is a VIE but consolidation is not required since we are not ATC's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC's economic performance. Therefore, we account for ATC as an equity method investment. At December 31, 2025 and 2024, our equity investment in ATC was $2,256.9 million and $2,085.1 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC.

We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. We have determined that ATC Holdco is a VIE but consolidation is not required since we are not ATC Holdco's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC Holdco's economic performance. Therefore, we account for ATC Holdco as an equity

method investment. At December 31, 2025 and 2024, our equity investment in ATC Holdco was $23.5 million and $23.8 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.

See Note 21, Investment in Transmission Affiliates, for more information, including any significant assets and liabilities related to ATC and ATC Holdco recorded on our balance sheets.

Commitments and Contingencies

12 Months Ended

Dec. 31, 2025

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

We and our subsidiaries have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, environmental matters, and enforcement and litigation matters.

Unconditional Purchase Obligations

Our electric utilities have obligations to distribute and sell electricity to their customers, and our natural gas utilities have obligations to distribute and sell natural gas to their customers. The utilities expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time.

The renewable generation facilities that are part of our non-utility energy infrastructure segment have obligations to distribute and sell electricity through long-term offtake agreements with their customers for all of the energy produced. In order to support these sales obligations, these companies enter into easements and other service agreements associated with the generating facilities.

The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2025, including those of our subsidiaries:


				Payments Due By Period
(in millions)	Date Contracts Extend Through	Total Amounts Committed		2026		2027		2028		2029		2030		Later Years
Electric utility:
Nuclear	2033	$	5,045.8	$	681.6	$	730.4	$	782.6	$	838.5	$	898.5	$	1,114.2
Coal supply and transportation	2028	412.1		242.2		127.7		37.0		3.5		1.7		—
Purchased power	2063	335.3		61.6		56.3		52.4		25.6		5.9		133.5
Other	2043	85.5		12.0		12.1		9.6		8.4		8.5		34.9
Natural gas utility:
Supply and transportation	2048	2,921.3		487.0		478.8		426.8		323.6		203.0		1,002.1
Non-utility energy infrastructure:
Purchased power	2055	720.7		55.0		56.3		57.6		50.7		48.4		452.7
Natural gas storage and transportation	2048	4.6		3.9		—		0.1		—		—		0.6
Total		$	9,525.3	$	1,543.3	$	1,461.6	$	1,366.1	$	1,250.3	$	1,166.0	$	2,738.0

Environmental Matters

Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as SO2, NOx, fine particulates, ozone, mercury, and GHGs; water intake and discharges; management of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.

We have continued to pursue a proactive strategy to manage our environmental compliance obligations, including:

•the development of additional sources of renewable electric energy supply, battery storage, and natural gas and LNG storage facilities;

•the addition of improvements for water quality matters such as treatment technologies to meet regulatory discharge limits and improvements to our cooling water intake systems;

•the addition of emission control equipment to existing facilities to comply with ambient air quality standards and federal clean air rules;

•the protection of wetlands and waterways, biodiversity including threatened and endangered species, and cultural resources associated with construction projects;

•the retirement of older coal-fired power plants and conversion to modern, efficient, natural gas generation, super-critical pulverized coal generation, and/or replacement with renewable generation;

•the beneficial use of ash and other products from coal-fired and biomass generating units;

•the remediation of former manufactured gas plant sites;

•the reduction of methane emissions across our natural gas distribution system by upgrading infrastructure; and

•the tracking and reporting of GHG emissions.

Federal Deregulatory Actions

In March 2025, the EPA announced a large-scale deregulatory effort that will likely take multiple years to complete. Of the proposed deregulatory actions, those that would apply to us include actions impacting the Good Neighbor Rule, MATS, the PM2.5 Standard, the GHG Power Plant Rule, the Mandatory Greenhouse Gas Reporting Rule, the ELG, and the CCR Rule. Any EPA actions will require formal rulemaking proceedings and are likely to be subject to legal challenges. We continue to monitor and evaluate these deregulatory actions for potential risks and benefits.

In February 2026, the EPA published a final rule rescinding the 2009 declaration that determined that CO2 and other GHGs endanger public health and welfare. The "endangerment finding" has been the legal underpinning of a host of climate regulations under the CAA. The rule is expected to face litigation.

Air Quality

Cross State Air Pollution Rule – Good Neighbor Rule

In 2023, the EPA issued a final Good Neighbor Rule, which required significant reductions in ozone-forming emissions of NOx from power plants and industrial facilities. In June 2024, the rule was stayed by the Supreme Court with respect to the specific applicant states, pending ongoing judicial review.

In response to the Supreme Court's order, in November 2024, the EPA administratively stayed the effectiveness of the Good Neighbor Rule through an interim final rule which extends a stay to all states to which the rule originally applied, including states in which we operate. The interim final rule also includes provisions to ensure that covered facilities in states with previously established requirements to mitigate interstate air pollution with respect to the 2008 ozone NAAQS will remain subject to equivalent requirements while the Good Neighbor Rule's effectiveness is stayed. Regardless of the outcome, we believe we are well positioned to comply with either standard. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

Mercury and Air Toxics Standards

The EPA issued the MATS rule to limit emissions of mercury, acid gases, and other hazardous air pollutants. In May 2024, the EPA finalized amendments to the MATS rule (the "2024 Amendments") which among other things, lowered the PM limit from 0.03 lb/MMBtu to 0.01 lb/MMBtu. We believe we are well positioned to comply with the requirements of the 2024 Amendments.

In June 2025, the EPA proposed to repeal the 2024 Amendments which would result in a return of the PM limit to 0.03 lb/MMBtu. In December 2025, the EPA submitted a draft of the rule to the OMB for interagency review. Following completion of the OMB review process, the EPA has stated it expects the rule to be finalized in the first quarter of 2026.

National Ambient Air Quality Standards

Ozone

After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, creating a more stringent standard than the 2008 NAAQS. The 2015 ozone standard lowered the 8-hour limit for ground-level ozone. The EPA's initial ozone nonattainment area designation was effective August 2018, and the attainment status is evaluated every 3 years thereafter until attainment is achieved. The Milwaukee, Sheboygan, and Chicago, IL-IN-WI nonattainment areas did not meet the marginal attainment deadline of August 2021, so in April 2022 the EPA proposed "moderate" nonattainment status based on the 2015

standard. In October 2022, the EPA published its final reclassifications from "marginal" to "moderate" for these areas, effective November 2022.

After the most recent evaluation, the EPA issued a final rule in December 2024 that determined that parts of Southeast Wisconsin failed to attain 2015 ozone NAAQS and consequently would be reclassified from "moderate" to "serious", effective January 2025.

In February 2025, the State of Wisconsin filed a petition for review of this reclassification in the United States Court of Appeals for the Seventh Circuit. Wisconsin subsequently moved for a stay of the reclassification, which was granted in September 2025, pending the Court's review. This means that Southeast Wisconsin has returned to "moderate" status while the underlying lawsuit proceeds.

A nonattainment status of "serious" could have a material adverse effect on future permitting activities for our facilities in applicable locations, including additional costs associated with more strenuous emission control requirements or the need to purchase emission reduction credits.

Particulate Matter

All counties within our service territories are currently in attainment with current 2012 NAAQS for PM2.5. In February 2024, the EPA finalized a rule which lowered the primary (health-based) annual PM2.5 NAAQS from 12 µg/m3 to 9 µg/m3 (the "2024 PM2.5 Standard"). In February 2025, the WDNR submitted a State Implementation Plan to the EPA recommending Wisconsin be designated as an attainment area under the 2024 PM2.5 Standard. The EPA has not yet issued its attainment designations and has indicated it may extend the designation period. A designation of nonattainment status could impact future permitting activities for facilities in applicable locations, including the potential need for improved or new air pollution control equipment. With our planned transition from coal-fired plants to natural gas-fired plants and renewable generating facilities, we do not expect the 2024 PM2.5 Standard to have a material impact on our units.

In November 2025, the EPA filed a motion with the D.C. Circuit Court of Appeals to vacate the 2024 PM2.5 Standard. The 2024 PM2.5 Standard remains in effect while the motion is being considered. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

New Source Performance Standards

Nitrogen Oxides

In January 2026, the EPA released a pre-publication version of its final rule regulating NOx for CTs constructed, modified, or reconstructed after December 13, 2024. The final rule, which became effective January 15, 2026 and established NOx emissions standards for several subcategories of new, modified, and reconstructed CTs based on the size, rates of utilization, design efficiency, and fuel type of these turbines. We believe we are well positioned to comply with this rule.

Climate Change

Pursuant to the final GHG Power Plant Rule, there are no applicable GHG emission standards for coal plants until the end of 2031. Thereafter, the applicable standard is dependent upon the unit's retirement date. Numerous parties have challenged the GHG Power Plant Rule through litigation pending in the D.C. Circuit Court of Appeals, and it is being held in abeyance at the request of the parties.

In March 2024, the EPA announced it had removed regulations on existing natural gas CTs from the rule. At that time, the EPA indicated it would work on new rulemaking in phases, focusing on CO2 emissions, as well as NOx and hazardous air pollutants emissions. See New Source Performance Standards - Nitrogen Oxides above for a discussion of the EPA's recent actions addressing NOx.

In June 2025, the EPA issued a proposed rule that contains a primary and an alternative proposal which, depending on which version is finalized, would result in either a broad repeal of GHG emissions standards or a more narrow repeal of the rule's carbon capture and storage requirements. We do not expect either alternative to have any impact on its current capital plan. Any final rule would likely be subject to litigation. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

In April 2024, the EPA issued its final Mandatory Greenhouse Gas Reporting Rule, which includes updates to the global warming potentials to determine CO2 equivalency for threshold reporting and the addition of a new section regarding energy consumption. In its current form, the rule will impact the reporting required for our electric generation facilities, LDCs, and underground natural gas storage facilities. In May 2024, the EPA also issued its final rule to amend reporting requirements for petroleum and natural gas systems. Under the current form of this rule, new leak emission factors and reporting requirements for large release events will impact the reporting required for our LDCs and underground natural gas storage facilities; however, under the Federal Deregulatory Actions discussion above, in September 2025, the EPA released a proposal to amend the GHG Reporting Program to permanently remove program obligations for most source categories, including our generation facilities. The EPA is also proposing to suspend program reporting requirements that would be applicable to our underground storage, LNG, and transmission affiliates until 2034. We continue to monitor the status of these deregulatory actions.

Our capital plan includes the planned retirement of older, fossil-fueled generation, to be replaced with natural gas-fired generation and zero-carbon-emitting renewables. We have retired nearly 2,500 MWs of fossil-fueled generation since the beginning of 2018. We expect to retire approximately 900 MWs of additional coal-fired generation by the end of 2031. In conjunction with our new capital plan, we and the other co-owners of Columbia Units 1 and 2 currently plan to continue coal operations at these units through at least 2029, and continue to evaluate the conversion of both units to natural gas. See Note 7, Property, Plant, and Equipment, for more information related to Columbia Units 1 and 2 and our planned power plant retirements. We have a long-term goal to achieve net carbon-neutral electric generation by the end of 2050. We expect to achieve this goal by continuing to make operating refinements, retiring less efficient generating units, and executing our capital plan. As part of our path toward this goal, we started implementing co-firing with natural gas at the ERGS coal-fired units and at Weston Unit 4 in 2025. We expect to use coal only as a backup fuel by the end of 2030 and to be in a position to eliminate coal as an energy source by the end of 2032.

We also continue to focus on methane emission reductions by improving and upgrading our natural gas distribution systems and using RNG throughout our natural gas utility systems.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

The Clean Water Act Cooling Water Intake Structure Rule requires the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the BTA for minimizing adverse environmental impacts. The rule applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted and received a final BTA determination under the rules governing new facilities.

Other than OCPP Units 7 and 8, we have received final or interim BTA determinations for all generation facilities where applicable. We believe existing technology at OCPP Units 7 and 8 also meets the rule requirements for BTA and anticipate that the units will receive that determination when their Wisconsin Pollutant Discharge Elimination System permit is reissued, which is expected in 2026.

Steam Electric Effluent Limitation Guidelines

The EPA's 2024 Supplemental ELG Rule (the "2024 ELG Rule") established ZLD requirements for bottom ash transport water, flue gas desulfurization, and combustion residual leachate wastewaters at coal-fueled facilities. The 2024 ELG Rule also established a new subcategory, providing an alternative compliance pathway for facility owners that commit to the PCCC at a particular facility by December 31, 2034. In exchange for this commitment, ZLD technologies will not be required and less stringent standards will apply at applicable facilities. The 2024 ELG Rule also allows owners of coal-fired units who opted into a cessation of coal subcategory to operate beyond the end of 2034 if needed for reliability concerns (i.e., energy emergencies and reliability must run agreements) as determined by the United States DOE, a public utility commission, or independent system operator. Based on current electric generation resource planning, in December 2025, we filed Notice of Planned Participations to opt into the PCCC subcategory for certain of our past and current coal-fueled facilities.

In December 2025, the EPA published a final rule, effective March 2, 2026, that extends the deadline for facility owners to opt into a subcategory under the 2024 ELG Rule, allowing them more time to assess potential compliance pathways to continue producing low-cost electricity into the future while meeting wastewater standards.

When the deadline extension rule was proposed, the EPA also solicited public comments related to the economic achievability and technical availability of ZLD technologies. Additional ELG rulemaking is anticipated that may lead to substantive changes to the ZLD technology-based requirements established in the 2024 ELG Rule.

In addition, numerous parties have challenged the 2024 ELG Rule through litigation in SWEPCO v. U.S. EPA pending in the United States Court of Appeals for the Eighth Circuit, which has been held in abeyance since February 2025. The 2024 ELG Rule, as well as the deadline extension rule, remain in effect during the pendency of the legal challenge. The outcome of this case may affect our compliance plans.

Land Quality

Manufactured Gas Plant Remediation

We have identified sites at which our utilities or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Our natural gas utilities are responsible for the environmental remediation of these sites. We are working with the EPA as well as various state jurisdictions, as applicable, in our investigation and remediation planning and efforts. These sites are at various stages of investigation, monitoring, remediation, and closure.

The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites.

We have established the following regulatory assets and reserves for manufactured gas plant sites as of December 31:


(in millions)	2025		2024
Regulatory assets for environmental remediation costs	$	566.0	$	570.1
Reserves for future environmental remediation	484.1		445.8

Coal Combustion Residuals Rule

An EPA rule for CCR that applies to landfills, historic fill sites, and projects where CCR was placed at a power plant site became effective in November 2024. The rule also regulates previously exempt closed landfills.

We anticipate this rule will have an impact on some of our coal ash landfills, requiring additional remediation that is not currently required under the state programs. We expect the cost of additional remediation would be recoverable through future rates.

The rule is being challenged through litigation pending in the D.C. Circuit Court of Appeals. In December 2025, the D.C. Circuit Court of Appeals granted the EPA's motion to extend the ongoing abeyance while the EPA reconsiders certain aspects of the rule. In February 2026, the EPA published a final rule extending certain deadlines and making various corrections to the 2024 CCR rule. The EPA has stated it plans to publish a new final rule by the end of 2026. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

Renewables, Efficiency, and Conservation

Wisconsin Legislation

In 2005, Wisconsin enacted Act 141, which established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources annually. WE and WPS have achieved their required renewable energy percentages of 8.27% and 9.74%, respectively, by constructing various wind and solar facilities, a biomass facility, and by also relying on renewable energy purchases. WE and WPS continue to review their renewable energy portfolios and acquire cost-effective renewables as needed to meet their requirements on an ongoing basis. The PSCW administers the renewable program related to Act 141, and each utility funds the program based on 1.2% of its annual retail operating revenues.

Michigan Legislation

In December 2016, Michigan enacted Act 342, which required 12.5% of the state's electric energy to come from renewables for 2019 and 2020, and energy optimization (efficiency) targets up to 1% annually. The renewable requirement increased to 15.0% for 2021 and beyond. UMERC was in compliance with its requirements under this statute as of December 31, 2025. The legislation continues to allow recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective.

In November 2023, Michigan enacted Acts 229, 231 and 235. The acts require electric providers to file a renewable energy plan every two years and to set renewable energy portfolio targets from now until 2040. The proposed renewable energy targets include 15% through 2029, 50% from 2030 through 2034, and 60% renewable energy by 2035 and thereafter. The bill also sets clean energy standards of 80% from 2035 through 2039 and 100% after 2040. The acts only allow natural gas to count as clean energy if it is accompanied with carbon capture and storage. The new acts also revise the requirement a utility must meet in filing its energy waste reduction plans. They require a utility to file a plan every two years until 2025, then every three years thereafter. In February 2025, we filed an AREP with the MPSC addressing UMERC's compliance with the Act 235 renewable portfolio standards. At the same time, we are working with a coalition of members of the Michigan legislature to seek exemption from Act 235 for our new RICE units. In December 2025, the MPSC issued an order denying UMERC's AREP, requiring UMERC to file a new AREP in October 2026.

Enforcement and Litigation Matters

We and our subsidiaries are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material impact on our financial condition or results of operations.

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2025

Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]

SUPPLEMENTAL CASH FLOW INFORMATION

The following table provides additional information regarding our statements of cash flows:


	Year Ended December 31
(in millions)	2025		2024		2023
Cash paid for interest, net of amount capitalized	$	858.5	$	785.7	$	653.4
Cash received for income taxes, net	(281.3)		(264.2)		(58.9)
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs	232.0		285.7		171.3
Common stock issued for stock-based compensation plans	3.2		6.4		—
Increase in receivables related to property damage insurance proceeds	3.5		2.3		3.5
Increase in receivables for corporate-owned life insurance proceeds	—		5.8		1.4
Liabilities accrued for software licensing agreements	21.1		0.2		—

Cash, Cash Equivalents, and Restricted Cash

The statements of cash flows include our activity related to cash, cash equivalents, and restricted cash. The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets at December 31 to the total of these amounts shown on the statements of cash flows:


(in millions)	2025		2024		2023
Cash and cash equivalents	$	27.6	$	9.8	$	42.9
Restricted cash included in other current assets	9.1		5.3		70.1
Restricted cash included in other long-term assets	34.2		27.1		52.2
Cash, cash equivalents, and restricted cash	$	70.9	$	42.2	$	165.2

Our restricted cash primarily consisted of the following:

•Cash held in the Integrys rabbi trust, which is used to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans.

•Cash on deposit in financial institutions that is restricted to satisfy the requirements of certain debt agreements at WECI Wind Holding I, WECI Wind Holding II, WECI Energy Holding III, and WEPCo Environmental Trust.

•Cash related to WECI's ownership interests in certain renewable generation projects. These projects are required to deposit into an escrow account in order to fund future decommissioning.

Regulatory Environment

12 Months Ended

Dec. 31, 2025

Regulated Operations [Abstract]

REGULATORY ENVIRONMENT

Wisconsin Electric Power Company, Wisconsin Public Service Corporation, and Wisconsin Gas LLC

Very Large Customer and Bespoke Resources Tariffs

In March 2025, WE filed an application with the PSCW requesting approval to implement a VLC Tariff and a Bespoke Resources Tariff. WE subsequently filed testimony in October 2025 slightly modifying the initial proposals. Under these proposed inter-connected tariffs, VLCs (new customers using 500 MWs or more, such as large data centers) will have access to reliable power to meet their needs and will directly pay for the electricity they consume, along with the power plants and distribution facilities built to serve them and operating and transmission costs allocated to their usage. The proposed tariffs are designed so that the costs associated with these VLCs are not subsidized by or shifted to residential or business customers.

The two new tariffs will work in tandem as VLCs will be required to sign a service agreement and subscribe to a portion of one or more "Bespoke Resources," including renewable generation facilities, battery storage, and natural gas generation units. Under these agreements, if a VLC terminates or downsizes its plans, it will still be required to pay for the Bespoke Resources and dedicated distribution facilities that have been built to support its forecasted load, unless the facilities can be repurposed, subject to PSCW approval. Service agreements under the Bespoke Resources Tariff will be effective for the depreciable life of the resource, except for wind or solar resources which will have a term of 20 years. As currently proposed, the ROE (can range from 10.48% to 10.98% as agreed upon with the customer) and equity ratio (57%) will both be fixed for the entire term of the agreement, and the revenue and costs recovered through the tariffs will be excluded from future rate case proceedings and earnings sharing mechanisms.

We expect a decision from the PSCW in the second quarter of 2026. Prior to the PSCW approving the tariffs, for infrastructure investments that have not received regulatory approval, WE requires VLCs to enter into payment and cancellation agreements which obligate the VLC to reimburse WE for all costs associated with projects, including any associated costs incurred by ATC for transmission infrastructure projects, requested by the customer until service agreements are executed under the approved tariffs. Reimbursement is required if, among other things, the VLC terminates the payment and cancellation agreement or reduces its anticipated load, or regulatory approval is not received for the construction of a project.

2025 and 2026 Rates

In April 2024, WE, WPS, and WG filed requests with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable. The primary drivers of the requested increases in electric rates were continued capital investments to transition our generation fleets from coal to renewables and natural gas-fueled generation, increased costs driven by higher inflation and interest rates, and the recovery of regulatory assets previously approved by the PSCW. The requested increases in natural gas rates were driven by the companies' ongoing capital investments in reliability and safety projects, including LNG storage facilities, as well as the impacts from higher inflation and increased interest rates.

In December 2024, the PSCW issued final written orders approving electric, natural gas, and steam base rate increases, effective January 1, 2025 and 2026, as applicable. The final written orders reflected the following:


	WE					WPS					WG
2025 rate increase
Electric (1)	$	144.0	million	/	4.2%	$	55.1	million	/	4.5%	N/A
Gas	$	41.3	million	/	7.1%	$	14.9	million	/	3.8%	$	34.5	million	/	4.2%
Steam	$	1.5	million	/	5.0%	N/A					N/A
2026 rate increase (2)
Electric (1)	$	169.5	million	/	4.5%	$	30.0	million	/	2.3%	N/A
Gas	$	29.8	million	/	4.5%	$	13.5	million	/	3.1%	$	23.5	million	/	2.6%
ROE	9.8%					9.8%					9.8%
Common equity component average on a financial basis	53.0%					53.0%					53.0%

(1) Amounts reflect the impact to our Wisconsin retail electric operations and include the incremental decrease resulting from updated fuel costs.

(2) The 2026 rate increases are incremental to the previously authorized revenue plus the approved rate increases for 2025.

Effective January 1, 2025, WE was required to implement a new earnings sharing mechanism, under which, if WE earns above its authorized ROE: (i) it retains 100.0% of earnings for the first 15 basis points above the authorized ROE; (ii) 50.0% of the next 25 basis points is required to be refunded to ratepayers; and (iii) 100.0% of any remaining excess earnings is required to be refunded to ratepayers.

WPS and WG were required to maintain their then current earnings sharing mechanism. Under this mechanism, if the utility earns above its authorized ROE: (i) the utility retains 100.0% of earnings for the first 15 basis points above the authorized ROE; (ii) 50.0% of the next 60 basis points is required to be refunded to ratepayers; and (iii) 100.0% of any remaining excess earnings is required to be refunded to ratepayers.

2024 Limited Rate Case Re-Opener

In accordance with their rate orders approved by the PSCW in December 2022, WE, WPS, and WG filed requests for limited electric and natural gas rate case re-openers, as applicable, with the PSCW in May 2023. The WE and WPS limited electric rate case re-openers included updated fuel costs and revenue requirements for the generation projects that were previously approved by the PSCW and were placed into service in 2023 or were expected to be placed into service in 2024. WE's limited electric re-opener also included the projected savings from the retirement of the OCPP Units 5 and 6, which were retired in May 2024. WE and WG also filed a request for a limited natural gas rate case re-opener to reflect the additional revenue requirements associated with their previously approved LNG projects. WE's and WG's LNG projects were placed into service in November 2023 and February 2024, respectively.

In December 2023, the PSCW issued final written orders approving electric and natural gas rate increases and decreases, effective January 1, 2024. The final orders reflected the following:


	WE					WPS					WG
2024 incremental rate increases (decreases)
Electric (1)	$	82.2	million	/	2.5%	$	(32.7)	million	/	(2.6)%	N/A
Gas	$	23.9	million	/	4.5%	N/A					$	21.6	million	/	2.8%

(1) Amounts reflect the impact to our Wisconsin retail electric operations and include any incremental increases (WE) or decreases (WPS) resulting from updated fuel costs.

The utilities' ROE and common equity component averages were not addressed in the limited rate case re-openers.

2023 and 2024 Rates

In April 2022, WE, WPS, and WG filed requests with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable. These requests were updated in July 2022 to reflect new developments that impacted the original proposals. The requested increases in electric rates were driven by capital investments in new wind, solar, and battery storage; capital investments

in natural gas generation; reliability investments, including grid hardening projects to bury power lines and strengthen WE's distribution system against severe weather; and changes in wholesale business with other utilities. Many of these investments had already been approved by the PSCW. The requested increases in natural gas rates primarily related to capital investments previously approved by the PSCW, including LNG storage for our natural gas distribution system.

In December 2022, the PSCW issued final written orders approving electric, natural gas, and steam base rate increases, effective January 1, 2023. The final orders reflected the following:


	WE					WPS					WG
2023 base rate increase
Electric	$	283.5	million	/	9.1%	$	120.5	million	/	9.8%	N/A
Gas	$	46.1	million	/	9.6%	$	26.4	million	/	7.1%	$	46.5	million	/	6.4%
Steam	$	7.6	million	/	35.3%	N/A					N/A
ROE	9.8%					9.8%					9.8%
Common equity component average on a financial basis	53.0%					53.0%					53.0%

In addition to the above, the final orders included the following terms:

•The utilities kept their then current earnings sharing mechanisms, under which, if a utility earned above its authorized ROE: (i) the utility retained 100.0% of earnings for the first 15 basis points above the authorized ROE; (ii) 50.0% of the next 60 basis points was refunded to ratepayers; and (iii) 100.0% of any remaining excess earnings was required to be refunded to ratepayers.

•WE and WPS were required to complete an analysis of alternative recovery scenarios for generating units that will be retired prior to the end of their useful life.

•WE and WPS were not allowed to propose any changes to their real time pricing rates for large commercial and industrial electric customers through the end of 2024.

•WE and WPS were required to lower monthly residential and small commercial electric customer fixed charges by $1.00 and $3.33, respectively, from previously authorized rates.

•WE and WPS were required to offer an additional voluntary renewable energy pilot for commercial and industrial customers.

•WE and WPS were required to continue to work with PSCW staff and other interested parties to develop alternative low income assistance programs. WE and WPS also collectively contributed $4.0 million to the Keep Wisconsin Warm Fund.

•WE, WPS, and WG were required to implement escrow accounting treatment for pension and OPEB costs. As a result, they defer as a regulatory asset or liability, the difference between actual pension and OPEB costs and those included in rates until recovery or refund is authorized in a future rate proceeding.

•As discussed above, WE and WPS were authorized to file a limited electric rate case re-opener for 2024, and WE and WG were authorized to file a limited natural gas rate case re-opener for 2024.

The Peoples Gas Light and Coke Company and North Shore Gas Company

2026 Rate Application

In January 2026, PGL and NSG filed requests with the ICC to increase their natural gas base rates. They are requesting rate increases of $201.3 million (20.95%) and $12.7 million (12.2%), respectively. The requested rate increases are primarily driven by capital investments made to strengthen the safety and reliability of each utility’s natural gas distribution system. PGL's rate request includes the estimated revenue requirements associated with its PRP projects. As discussed below, projects completed under PGL's PRP are to meet the ICC's directive to retire all cast and ductile iron pipe that has a diameter under 36 inches by January 1, 2035. PGL's rate request includes the revenue requirements associated with approximately $360 million of capital investments planned under its PRP in 2027. Higher operating costs, driven by inflation, and increases in the cost of capital, also drove the requested rate increases. Both companies are requesting an ROE of 10.10% and a common equity component average of 54.0%.

An ICC decision is anticipated in the fourth quarter of 2026, with new rates expected to be effective by January 1, 2027.

2023 Rate Order

In January 2023, PGL and NSG filed requests with the ICC to increase their natural gas base rates. The requested rate increases were primarily driven by capital investments made to strengthen the safety and reliability of each utility’s natural gas distribution system. PGL was also seeking to recover costs incurred to upgrade its natural gas storage field and operations facilities and to continue improving customer service. PGL did not request an extension of the QIP rider as PGL returned to the traditional rate making process to recover the costs of necessary infrastructure improvements.

In November 2023, the ICC issued final written orders approving base rate increases for PGL and NSG. The written orders were subsequently amended for various technical corrections. The amended written orders approved the following base rate increases:

•A $304.6 million (43.5%) base rate increase for PGL’s natural gas customers, effective December 1, 2023. This amount includes the recovery of costs that were previously being recovered under its QIP rider.

•An $11.0 million (11.6%) base rate increase for NSG’s natural gas customers. The new rates at NSG were not effective until February 1, 2024 as changes were required to NSG's billing system as a result of the final rate order.

The ICC approved an authorized ROE of 9.38% for both PGL and NSG, and set the common equity component average at 50.79% and 52.58% for PGL and NSG, respectively.

As part of its decisions, the ICC, among other things, disallowed $236.2 million of capital costs related to the construction and improvement of PGL’s shops and facilities and $1.7 million of capital costs related to NSG's construction of a gas infrastructure project. In addition, the ICC ordered PGL to pause spending on its projects to upgrade its natural gas delivery system until the ICC had a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level.

In December 2023, PGL and NSG filed an application for rehearing with the ICC requesting reconsideration of various issues in the ICC's November 2023 written orders. The ICC granted PGL and NSG a limited-scope rehearing focused exclusively on the authorized spending for the completion of projects to upgrade PGL's natural gas delivery system that started in 2023 and emergency repairs needed to ensure the safety and reliability of the delivery system. In May 2024, the ICC issued a written order on the rehearing. The order approved $28.5 million of additional spending for emergency work, representing a $1.6 million increase to PGL's annual revenue requirement.

As the ICC did not grant a rehearing on the disallowance of PGL's and NSG's capital costs, we recorded a $178.9 million non-cash impairment of our property, plant, and equipment during the fourth quarter of 2023. This amount included $177.2 million of previously incurred disallowed costs at PGL related to its shops and facilities, and the $1.7 million of capital costs disallowed at NSG. The remaining disallowance of capital costs at PGL related to expected future spend.

In June 2024, PGL and NSG filed a petition with the Illinois Appellate Court for review of the November 2023 and May 2024 orders. The appeal includes the ICC's $237.9 million combined disallowance of capital costs at PGL and NSG discussed above, along with the $116.0 million disallowance of capital investments needed to meet safety and reliability requirements of PGL's natural gas delivery system. Although the ICC ordered PGL to complete safety and reliability work in 2024, it denied the recovery of these costs in the current rates.

In accordance with the November 2023 rate order, the ICC initiated a proceeding in January 2024 to determine the optimal method and a prudent investment level for replacing aging natural gas infrastructure. In February 2025, the ICC issued an order setting expectations for PGL's prospective operations. The ICC directed us to focus on retiring all cast and ductile iron pipe that has a diameter under 36 inches by January 1, 2035. The ICC also indicated that failure to comply with this directive could subject us to civil penalties under Illinois statute. PGL is working to retire this cast and ductile iron pipe through its PRP. Costs incurred under the PRP will be evaluated for prudency by the ICC in future rate cases. In addition, the program will be overseen by a safety monitor hired by the ICC. As discussed above, PGL initiated a general rate case proceeding in January 2026, which we anticipate will provide further regulatory clarity before we significantly increase our spend associated with the PRP.

Illinois Riders

Uncollectible Expense Adjustment Rider

The rates of PGL and NSG include a UEA rider for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. The UEA rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency by the ICC. In May 2023, the ICC issued a written order on PGL's and NSG's 2018 UEA rider reconciliation. The order required a $15.4 million and $0.7 million refund to customers at PGL and NSG, respectively. These amounts were refunded over a period of nine months, which began on September 1, 2023. Upon appeal by PGL and NSG, the Illinois Appellate Court affirmed the ICC order and the related disallowance. The Illinois Supreme Court denied a subsequent petition for review and reversal of the order in March 2025.

As of December 31, 2025, there can be no assurance that all costs incurred under the UEA rider during the open reconciliation years will be deemed recoverable by the ICC. Future disallowances by the ICC could be material. The combined annual costs of PGL and NSG included in the rider, which reflect uncollectible write-offs in excess of what is recovered in base rates, have ranged from $10 million to $40 million. However, see Uncollectible Expense Adjustment and Qualifying Infrastructure Plant Riders Settlement below for information on a proposed settlement that would resolve all open proceedings.

Qualifying Infrastructure Plant Rider

In July 2013, Illinois Public Act 98-0057, The Natural Gas Consumer, Safety & Reliability Act, became law. This law provides natural gas utilities with a cost recovery mechanism that allows collection, through a surcharge on customer bills, of prudently incurred costs to upgrade Illinois natural gas infrastructure. In January 2014, the ICC approved a QIP rider for PGL, which was in effect until December 1, 2023. As discussed above, PGL has returned to the traditional rate-making process for recovery of these costs, and they are now included in PGL's base rates.

Costs previously incurred under PGL's QIP rider are still subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In August 2024, the ICC issued a final order on PGL's 2016 annual reconciliation, which included a disallowance of $14.8 million of certain capital costs. PGL recorded a pre-tax charge to income of $25.3 million during the third quarter of 2024 related to the disallowance and the previously recognized return on and of these investments. The charge was recorded on the income statement as a $12.9 million reduction in revenues for the amounts previously collected from customers, a $12.1 million increase to operating expenses for the impairment of PGL's property, plant, and equipment, and a $0.3 million increase to interest expense related to the amounts due to customers. In October 2024, PGL filed a petition with the Illinois Appellate Court for review of the ICC's August 2024 order; however, in January 2026, PGL filed an unopposed motion to stay the appeal, which was granted by the court.

PGL's QIP reconciliations from 2017 through 2023 are still pending. Future disallowances by the ICC could be material. The aggregate capital costs included in the rider during the open reconciliation years, along with any previously recognized return on these investments, totaled approximately $3.0 billion as of December 31, 2025. However, see Uncollectible Expense Adjustment and Qualifying Infrastructure Plant Riders Settlement below for information on a proposed settlement that would resolve all open proceedings.

Uncollectible Expense Adjustment and Qualifying Infrastructure Plant Riders Settlement

In February 2026, PGL and NSG agreed on the terms of a proposed settlement with the Illinois Attorney General that, if approved by the ICC, would resolve all open proceedings related to the UEA and QIP riders. PGL and NSG agreed to refund $49.0 million and $1.0 million, respectively, to customers as bill credits over a period of three years between 2026 and 2028 to resolve the open UEA proceedings. In order to resolve the open QIP proceedings, PGL agreed to permanently remove $130.0 million of qualified infrastructure investment costs from rate base starting in 2027 and to refund $75.0 million to customers as bill credits over a period of three years between 2026 and 2028. As a result of this agreement, we recorded a $205.0 million charge to income during the fourth quarter of 2025. The charge was recorded as a $130.0 million impairment to PGL's net property, plant, and equipment and a $75.0 million reduction to revenues. The total of the rate base reduction and the obligation to refund amounts to customers through bill credits recorded on our balance sheet at December 31, 2025 is $255.0 million. This includes the $205.0 million charge to income recorded during 2025 and a $50.0 million charge to income recorded in prior years. This proposed settlement is subject to ICC approval following a public review process.

Minnesota Energy Resources Corporation

2023 Rate Order

In November 2022, MERC initiated a rate proceeding with the MPUC to increase its retail natural gas base rates. In December 2022, the MPUC approved MERC's request for interim rates totaling $37.0 million, subject to refund. The interim rates went into effect on January 1, 2023.

In November 2023, the MPUC issued a written order approving a settlement agreement MERC reached with certain intervenors. The settlement agreement reflected a natural gas base rate increase of $28.8 million (7.1%), along with a 9.65% ROE and a common equity component average of 53.0%. The natural gas rate increase was primarily driven by increased capital investments as well as inflationary pressure on operating costs. Under the terms of the settlement agreement, MERC will continue the use of its decoupling mechanism for residential customers, and it will be expanded to include certain small commercial and industrial customers.

Final rates went into effect on March 1, 2024. MERC’s customers were entitled to an $8.9 million refund due to the interim rate increase exceeding the final approved rate increase, which was retroactive to January 1, 2023. These amounts were refunded to customers during the second quarter of 2024.

Michigan Gas Utilities Corporation

2026 Rate Application

On December 19, 2025, MGU provided notification to the MPSC of its intent to file an application requesting an increase to its natural gas rates. The application is expected to be filed in March 2026 and to request new rates be effective January 1, 2027. MGU is currently in the process of evaluating its rate request.

2024 Rate Order

In March 2024, MGU filed a request with the MPSC to increase its retail natural gas base rates. In September 2024, the MPSC issued a final order approving a settlement agreement, which authorized MGU to increase its natural gas base rates by $7.0 million (3.88%). The rate increase was primarily driven by inflationary pressure on capital projects and operating and maintenance costs and the significant increase in interest rates over the past few years. The rate increase reflected a 9.86% ROE and a common equity component average of 50.0%. The new rates became effective January 1, 2025. The order also authorized MGU to defer any expenses incurred to implement the PHMSA's proposed rulemaking titled "Gas Pipeline Leak Detection and Repair."

2023 Rate Order

In March 2023, MGU filed a request with the MPSC to increase its retail natural gas base rates. In August 2023, the MPSC issued a written order approving a comprehensive settlement that resolved all issues in MGU's rate case. The key terms of the settlement agreement included:

•a natural gas base rate increase of $9.9 million (4.7%);

•an ROE of 9.8%;

•a common equity component average of 51.0%; and,

•a continuation of the existing MRP rider, effective January 1, 2025 through 2027, including forecasted increased costs for those projects. MRP costs were recovered in base rates in 2024.

The rate increase was primarily driven by capital investments made to strengthen the safety and reliability of MGU's natural gas distribution system and to provide service to additional customers. Inflationary pressure on operating costs also contributed to the rate increase. The new rates were effective January 1, 2024.

Upper Michigan Energy Resources Corporation

Amended Renewable Energy Plan

In accordance with Michigan Public Act 235, UMERC filed an AREP with the MPSC in February 2025. UMERC's AREP addressed its compliance with the Act 235 renewable portfolio standards and its proposal to recover the projected compliance costs through an incremental renewable energy surcharge. The projected compliance costs included the purchase of Michigan-sourced renewable energy credits and the revenue requirements for UMERC's previously approved investment in Renegade, a 100 MW utility-scale solar-powered electric generating facility, and any other incremental renewable generation resources required to meet the Act 235 renewable portfolio standards. On December 18, 2025, the MPSC issued an order denying UMERC's AREP and requiring UMERC to file a new AREP by October 15, 2026.

Renegade is currently interconnected and delivering power to MISO, and it is expected to achieve commercial operation in the first quarter of 2026. The estimated cost of Renegade is approximately $226 million. As UMERC's proposal to recover the annual revenue requirement of Renegade through a renewable energy surcharge was denied, UMERC will recover a portion of these costs through its power supply cost recovery mechanism, and the MPSC advised UMERC to seek deferral accounting treatment for the remainder. UMERC filed its request for deferral accounting with the MPSC on January 27, 2026.

2024 Rate Order

In May 2024, UMERC filed a request with the MPSC to increase its electric base rates for non-mine customers. In October 2024, the MPSC issued a final order approving a settlement agreement, which authorized UMERC to increase electric base rates for non-mine customers by $6.6 million (8.2%). The new rates became effective January 1, 2025. The rate increase reflected a 9.86% ROE and a common equity component average of 50.0%. The rate increase was primarily driven by the construction of the now in-service RICE generation facilities located in the Upper Peninsula of Michigan and a reduction in sales volumes resulting from the implementation of limited retail choice since UMERC’s predecessor utilities last reset rates. A reduction of operation and maintenance costs partially offset these impacts.

Other Income, Net

12 Months Ended

Dec. 31, 2025

Other Income and Expenses [Abstract]

OTHER INCOME, NET

Total other income, net was as follows for the years ended December 31:


(in millions)	2025		2024		2023
AFUDC-Equity	$	99.8	$	59.8	$	59.1
Gains from investments held in rabbi trust	8.1		11.7		13.7
Interest income	5.9		17.2		3.9
Non-service components of net periodic benefit costs	2.7		83.7		97.7
Earnings (losses) from equity method investments (1)	(10.4)		4.7		(1.1)
Other, net	1.8		1.1		4.4
Other income, net	$	107.9	$	178.2	$	177.7

(1) Amounts do not include equity earnings of transmission affiliates as those earnings are shown as a separate line item on the income statements.

New Accounting Pronouncements	12 Months Ended
New Accounting Pronouncements	Dec. 31, 2025
Accounting Standards Update and Change in Accounting Principle [Abstract]
NEW ACCOUNTING PRONOUNCEMENTS	NEW ACCOUNTING PRONOUNCEMENTS Improvements to Interim Reporting In December 2025, the FASB issued ASU No. 2025-11, Interim Reporting (Topic 270) Narrow-Scope Improvements. The amendments clarify interim disclosure requirements and the applicability of Topic 270. The amendments include a comprehensive list of interim disclosures that are currently required under GAAP. The amendments also include a disclosure principle that requires entities to disclose events since the end of the last annual reporting period that have a material impact on the entity. Finally, the amendments clarify the types of interim reporting and the form and content of interim financial statements in accordance with GAAP. The amendments are effective for interim periods within annual periods beginning after December 15, 2027, with early adoption permitted. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures. Accounting for Government Grants In December 2025, the FASB issued ASU No. 2025-10, Government Grants (Topic 832) Accounting for Government Grants Received by Business Entities. The amendments establish the accounting for a government grant received by a business entity, including guidance for a grant related to an asset and a grant related to income. The amendments also require disclosures, including the nature of the government grant received, the accounting policies used to account for the grant, and significant terms and conditions of the grant. The amendments are effective for annual periods beginning after December 15, 2028, and interim periods within those annual periods, with early adoption permitted. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures. Disaggregation of Income Statement Expenses In November 2024, the FASB issued ASU No. 2024-03, Income Statement-Reporting Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40) Disaggregation of Income Statement Expenses. The amendments require disclosure of certain costs and expenses in the notes to financial statements, which are disaggregated from relevant expense captions on the income statement. The amendments also require additional qualitative disclosures of the amounts remaining in relevant expense captions that are not separately disaggregated quantitatively. Finally, the amendments require disclosure of the total amount of selling expenses and, in annual reporting periods, an entity's definition of selling expenses. The amendments are effective for annual periods beginning after December 15, 2026, and interim periods beginning after December 15, 2027, with early adoption permitted. We plan to adopt these amendments beginning with our fiscal year ending on December 31, 2027, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

- Definition

The entire disclosure for change in accounting principle. Includes, but is not limited to, nature, reason, and method of adopting amendment to accounting standards or other change in accounting principle.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

Schedule I - Condensed Parent Company Financial Statements

12 Months Ended

Dec. 31, 2025

Condensed Financial Information Disclosure [Abstract]

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS

SCHEDULE I

CONDENSED PARENT COMPANY FINANCIAL STATEMENTS

WEC ENERGY GROUP, INC. (PARENT COMPANY ONLY)

A. INCOME STATEMENTS


Year Ended December 31
(in millions)	2025		2024		2023
Operating expenses	$	3.6	$	5.4	$	2.5
Equity earnings of subsidiaries	1,819.2		1,724.2		1,502.5
Other income, net	26.5		32.0		19.6
Interest expense	399.3		333.6		260.8
Gain on debt extinguishments	—		(23.1)		—
Income before income taxes	1,442.8		1,440.3		1,258.8
Income tax benefit	114.7		86.9		72.9
Net income attributed to common shareholders	$	1,557.5	$	1,527.2	$	1,331.7

The accompanying Notes to Condensed Parent Company Financial Statements are an integral part of these financial statements.

B. STATEMENTS OF COMPREHENSIVE INCOME


Year Ended December 31
(in millions)	2025		2024		2023
Net income attributed to common shareholders	$	1,557.5	$	1,527.2	$	1,331.7

Other comprehensive income (loss), net of tax
Derivatives accounted for as cash flow hedges

Reclassification of realized derivative gains to net income, net of tax	(0.2)		(0.3)		(0.3)

Defined benefit plans
Pension and OPEB adjustments arising during the period, net of tax	0.2		—		(0.2)
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax	0.1		0.1		0.1
Defined benefit plans, net	0.3		0.1		(0.1)

Other comprehensive income (loss) from subsidiaries, net of tax	0.1		0.1		(0.5)

Other comprehensive income (loss), net of tax	0.2		(0.1)		(0.9)

Comprehensive income attributed to common shareholders	$	1,557.7	$	1,527.1	$	1,330.8

The accompanying Notes to Condensed Parent Company Financial Statements are an integral part of these financial statements.

C. BALANCE SHEETS


At December 31
(in millions)	2025		2024
Assets
Current assets
Cash and cash equivalents	$	0.1	$	—
Accounts receivable from related parties	3.2		2.7
Notes receivable from related parties	63.0		63.2
Prepaid income taxes	14.9		16.3

Current assets	81.2		82.2

Long-term assets
Investments in subsidiaries	22,222.1		19,809.0
Note receivable from WECI	460.0		300.0
Other	56.0		23.2
Long-term assets	22,738.1		20,132.2
Total assets	$	22,819.3	$	20,214.4

Liabilities and Equity
Current liabilities
Short-term debt	$	702.9	$	382.7
Current portion of long-term debt	1,350.0		620.0
Accounts payable to related parties	5.0		3.1
Notes payable to related parties	778.4		580.9
Other	69.5		69.4
Current liabilities	2,905.8		1,656.1

Long-term liabilities
Long-term debt	6,280.2		6,135.4
Other	19.7		28.0
Long-term liabilities	6,299.9		6,163.4

Common shareholders' equity	13,613.6		12,394.9
Total liabilities and equity	$	22,819.3	$	20,214.4

The accompanying notes to Condensed Parent Company Financial Statements are an integral part of these financial statements.

D. STATEMENTS OF CASH FLOWS


Year Ended December 31
(in millions)	2025		2024		2023
Operating activities
Net income attributed to common shareholders	$	1,557.5	$	1,527.2	$	1,331.7
Reconciliation to cash provided by operating activities
Equity income in subsidiaries, net of distributions	(669.2)		(931.8)		(566.8)
Deferred income taxes, net	(21.5)		(2.1)		(3.8)
Gain on debt extinguishments	—		(23.1)		—
Change in –
Accounts receivable from related parties	(0.5)		—		(2.0)
Prepaid income taxes	1.4		(16.3)		35.4
Other current assets	—		0.2		(0.1)
Accounts payable to related parties	1.9		0.2		0.9
Accrued interest	1.3		(3.6)		42.1
Other current liabilities	(0.8)		(0.6)		(0.7)
Other, net	18.4		15.5		14.4
Net cash provided by operating activities	888.5		565.6		851.1

Investing activities
Capital contributions to subsidiaries	(2,277.7)		(1,273.9)		(1,807.4)
Return of capital from subsidiaries	537.9		846.6		175.2
Short-term notes receivable from related parties, net	0.2		(47.2)		14.9
Issuance of long-term note receivable to WECI	(160.0)		—		—
Other, net	(14.7)		—		—
Net cash used in investing activities	(1,914.3)		(474.5)		(1,617.3)

Financing activities
Exercise of stock options	39.1		23.7		6.3
Issuance of common stock, net	761.9		163.4		—
Purchase of common stock	(1.3)		(3.2)		(16.6)
Dividends paid on common stock	(1,147.8)		(1,056.2)		(984.2)
Issuance of long-term debt	1,500.0		2,475.0		2,050.0
Retirement of long-term debt	(620.0)		(1,473.7)		(700.0)
Change in commercial paper	320.2		(314.3)		297.3
Short-term notes payable to related parties, net	197.5		121.3		127.1
Payments for debt extinguishment and issuance costs	(23.7)		(27.0)		(13.3)
Other, net	—		(0.1)		(0.4)
Net cash provided by (used in) financing activities	1,025.9		(91.1)		766.2

Net change in cash and cash equivalents	0.1		—		—
Cash and cash equivalents at beginning of year	—		—		—
Cash and cash equivalents at end of year	$	0.1	$	—	$	—

The accompanying Notes to Condensed Parent Company Financial Statements are an integral part of these financial statements.

SCHEDULE I

CONDENSED PARENT COMPANY FINANCIAL STATEMENTS

WEC ENERGY GROUP, INC. (PARENT COMPANY ONLY)

E. NOTES TO PARENT COMPANY FINANCIAL STATEMENTS

NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

For Parent Company only presentation, investments in subsidiaries are accounted for using the equity method. We use the cumulative earnings approach for classifying distributions received in the statements of cash flows.

The condensed Parent Company financial statements and notes should be read in conjunction with the consolidated financial statements and notes of WEC Energy Group, Inc. appearing in this Annual Report on Form 10-K.

NOTE 2—CASH DIVIDENDS RECEIVED FROM SUBSIDIARIES

Dividends received from our subsidiaries during the years ended December 31 were as follows:


(in millions)	2025		2024		2023
WE	$	600.0	$	240.0	$	370.0
We Power	175.6		225.3		192.8
WECI (1)	152.5		127.2		93.7
WG	100.0		80.0		171.0
ATC Holding	73.9		104.6		86.8
UMERC	23.0		15.0		21.0
Bluewater	20.0		—		—
WEC Investments, LLC	4.3		—		—
Wispark (2)	0.7		0.3		0.4
Total	$	1,150.0	$	792.4	$	935.7

(1) We also received amounts classified as return of capital of $534.5 million, $843.9 million, and $171.6 million from WECI during the years ended December 31, 2025, 2024, and 2023, respectively.

(2) We also received amounts classified as return of capital of $2.9 million, $2.7 million, and $3.6 million from Wispark during the years ended December 31, 2025, 2024, and 2023, respectively.

NOTE 3—LONG-TERM DEBT

The following table shows the future maturities of our long-term debt outstanding as of December 31, 2025:


(in millions)
2026	$	1,350.0
2027	1,762.5
2028	1,850.0
2029	862.5
2030	300.0
Thereafter	1,550.0
Total	$	7,675.0

WECC is our subsidiary and has $50.0 million of long-term notes outstanding. In a Support Agreement between WECC and us, we agreed to make sufficient liquid asset contributions to WECC to permit WECC to service its debt obligations as they become due.

NOTE 4—FAIR VALUE MEASUREMENTS

The following table shows the financial instruments included on our balance sheets that are not recorded at fair value as of December 31:


	2025				2024
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Long-term notes receivable from WECI	$	460.0	$	464.6	$	300.0	$	300.0
Long-term debt, including current portion	7,630.2		7,922.9		6,755.4		6,776.0

The fair value of our long-term notes receivable and long-term debt are categorized within Level 2 of the fair value hierarchy.

NOTE 5—GUARANTEES

The following table shows our outstanding guarantees on behalf of our subsidiaries:


	Total Amounts Committed at December 31, 2025		Expiration

(in millions)			Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees supporting business operations (1)	$	309.6	$	74.9	$	11.0	$	223.7
Standby letters of credit (2)	140.9		30.7		30.0		80.2
Surety bonds (3)	46.5		46.4		0.1		—
Other guarantees (4)	9.6		—		—		9.6
Total guarantees	$	506.6	$	152.0	$	41.1	$	313.5

(1) Consists of $233.5 million, $39.0 million, $17.0 million, $10.1 million, $6.0 million, and $4.0 million of guarantees to support the business operations of WECI, MERC, MGU, Bluewater, NSG, and UMERC, respectively.

(2) At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets.

(3) Primarily for environmental remediation, workers compensation self-insurance programs, and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets.

(4) Related to workers compensation coverage for which a liability was recorded on our balance sheets.

NOTE 6—SUPPLEMENTAL CASH FLOW INFORMATION


(in millions)	2025		2024		2023
Cash paid for interest	$	382.8	$	324.2	$	209.1
Cash received for income taxes, net	(92.9)		(66.7)		(104.5)
Significant non-cash equity transaction:
Issuance of long-term note receivable to WECI	—		300.0		430.0
Repayment of long-term note receivable to WECI	—		430.0		—

NOTE 7—SHORT-TERM NOTES RECEIVABLE FROM RELATED PARTIES

The following table shows our outstanding short-term notes receivable from related parties as of December 31:


(in millions)	2025		2024
UMERC	$	62.9	$	63.2
Wispark	0.1		—
Total	$	63.0	$	63.2

NOTE 8—SHORT-TERM NOTES PAYABLE TO RELATED PARTIES

The following table shows our outstanding short-term notes payable to related parties as of December 31:


(in millions)	2025		2024
Integrys	$	515.3	$	327.0
WECC	112.0		111.1
WBS	97.3		90.4
Bluewater	53.8		52.4
Total	$	778.4	$	580.9

Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2025

SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

SCHEDULE II

WEC ENERGY GROUP, INC.

VALUATION AND QUALIFYING ACCOUNTS


Allowance for Doubtful Accounts (in millions)	Balance at Beginning of Period		Expense (1)		Deferral		Net Write-offs (2)		Balance at End of Period
December 31, 2025	$	162.8	$	142.8	$	(23.8)	$	(133.1)	$	148.7
December 31, 2024	$	193.5	$	104.9	$	35.8	$	(171.4)	$	162.8
December 31, 2023	199.3		72.0		88.3		(166.1)		193.5

(1) Net of recoveries.

(2) Represents amounts written off to the reserve, net of adjustments to regulatory assets.

Insider Trading Arrangements	3 Months Ended
Insider Trading Arrangements	Dec. 31, 2025
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

Cybersecurity Risk Management and Strategy Disclosure	12 Months Ended
Cybersecurity Risk Management and Strategy Disclosure	Dec. 31, 2025
Cybersecurity Risk Management, Strategy, and Governance [Line Items]
Cybersecurity Risk Management Processes Integrated [Flag]	true
Cybersecurity Risk Management Processes Integrated [Text Block]	Our cybersecurity-related risks are managed through monitoring, defense and response tools, audits and assessments of the program’s effectiveness, industry collaboration, and employee training and awareness. Our cybersecurity risk management program utilizes the cybersecurity framework and maturity models from the National Institute of Standards and Technology and the DOE to continually assess its maturity. This includes regular internal security audits and vulnerability assessments, as well as regular engagement with third-party security experts for external assessments of our security controls, including technical, physical, and social aspects. To better comprehend the scope and magnitude of any active threats to our industry and nation and their potential impact on our IT/OT systems, we communicate with other utility companies, government agencies, and other sectors of the economy concerning cybersecurity incidents. All employees are required to complete training annually regarding information security and acceptable use of corporate electronic resources. Annual role-based cybersecurity training as well as ongoing participation in a corporate phishing campaign program, is also required of employees and contractors. In addition, as part of the cybersecurity program, we have established controls and procedures to assess the adequacy of controls in place at third-party vendors to protect corporate information, including restricted and confidential restricted information we provide to third-party vendors, their employees, or authorized agents. These third-party vendors are also subject to a background investigation prior to being granted physical or electronic access to the company's private property, or physical access to customer premises on behalf of the company. As part of the cybersecurity program, we have adopted a cybersecurity incident response plan (the “Plan”) designed to identify, evaluate, respond to, and resolve cybersecurity incidents impacting IT/OT systems. Pursuant to the terms of the Plan, we have established a CSIRT Steering Committee which includes, among others, the Chief Financial Officer, CAO, and the Enterprise Security Director. The CSIRT Steering Committee is responsible for overseeing and implementing the Plan in the event of a cybersecurity threat or incident and provides updates regarding the status of the response to senior management, including the CEO, who provides updates and reports regarding cybersecurity incidents to the AOC and/or the Board of Directors at regularly scheduled meetings or more frequently, as needed. In response to an identified cybersecurity incident, or as it deems appropriate, the CSIRT Steering Committee will assemble and oversee a CSIRT, comprised of appropriate personnel and subject matter experts depending on the scope and severity of the incident, relevant or impacted business units and entities, and type of information or systems potentially compromised by the cybersecurity incident. When assembled, the CSIRT is responsible for developing and implementing an overall response strategy to contain, control, and remediate the cybersecurity incident, including securing affected systems and/or information, mitigating harmful effects of the incident, preventing further compromises, and communicating information to affected parties, regulatory agencies and law enforcement, as necessary. The CSIRT may seek assistance from or engage external support providers including legal counsel, outside technology or forensic experts, investigation service providers, and others, as appropriate, to assist in the response to the incident, based on its nature and scope. Pursuant to the Plan and at the direction of the CAO, the Enterprise Security Director will conduct a post-incident remediation analysis and report findings to the CSIRT Steering Committee. The Plan is tested and reviewed at least annually.
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag]	true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag]	true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Text Block]	We have been subject to attempted cybersecurity attacks from time to time, and will likely continue to be subject to such attempted attacks; however, these prior attacks have not had a material impact on our system or business operations. For information about cybersecurity risks to our business, see Item 1A. Risk Factors and the risk factor titled "Our operations are subject to risks beyond our control, including but not limited to, cybersecurity intrusions, terrorist or other physical attacks, acts of war, or unauthorized access to personally identifiable information."
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block]	Our Board of Directors is responsible for general oversight of our risk environment and associated management policies and practices. The Board of Directors has delegated to its AOC the responsibility for oversight of our major risk categories and exposures, including with respect to cybersecurity, and management's processes to monitor and control them. The AOC meets regularly throughout the year and receives and reviews various risk management reports about IT/OT cybersecurity, data security, and physical security risks, and discusses these matters with appropriate management and other personnel. The CEO and CAO regularly report to the AOC and the Board of Directors about cybersecurity matters and risks as well as the adequacy and effectiveness of the cybersecurity risk management program.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]	To foster an enterprise-wide approach to risk management, we have established an ERSC chaired by our CEO and comprised of a cross-functional group of senior leaders from across our organization. The ERSC regularly reviews key risk areas and oversees the development and implementation of effective compliance and risk management practices, including the use of internal and external audits. Our Board of Directors and the AOC receive reports regarding the same. Governance of our cybersecurity risk management program is overseen by the ERSC, along with steering committees for information security, operational technology security, third-party vendor security controls, Sarbanes-Oxley security controls, and North American Electric Reliability Corporation Critical Infrastructure Protection compliance.
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]	Our CAO is responsible for enterprise-wide information technology services and cybersecurity system strategy. In this capacity, the CAO oversees the cybersecurity risk management program, which is maintained and implemented by the Enterprise Security Director.The Enterprise Security Director, in collaboration with her team, is responsible for IT/OT cybersecurity, data security, and physical security. The Enterprise Security Director identifies, evaluates, and facilitates mitigation of cyber, data, and physical security risks and reports on cybersecurity matters and risks to the ERSC and the AOC.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block]	Our CAO has 26 years of experience at the company, during which time she has held a number of management and leadership positions, including Chief Information Officer, through which she has developed expertise in our IT/OT cybersecurity, data security, and physical security environment and risk profile.Our Enterprise Security Director has over 28 years of experience in IT/OT cybersecurity, data security and physical security, and is a certified information system security professional. She is also a member of numerous state and national cybersecurity organizations.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag]	true

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2025

Accounting Policies [Abstract]

Nature Of Operations

WEC Energy Group serves approximately 1.7 million electric customers and 3.0 million natural gas customers, owns approximately 60% of ATC, and owns majority interests in multiple renewable generating facilities as part of its non-utility energy infrastructure segment.

Consolidation

As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, statements of comprehensive income, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. On our financial statements, we consolidate our majority-owned subsidiaries, which we control, and VIEs, of which we are the primary beneficiary. We reflect noncontrolling interests for the portion of entities that we do not own as a component of consolidated equity separate from the equity attributable to our shareholders. The noncontrolling interests that we reported as equity on our balance sheet as of December 31, 2025 related to the minority interests held by third parties in the renewable generating facilities that are included in our non-utility energy infrastructure segment.

Segment reporting

Our financial statements include the accounts of WEC Energy Group, a diversified energy holding company, and the accounts of our subsidiaries in the following reportable segments:

•Wisconsin segment – Consists of WE, WPS, and WG, which are engaged primarily in the generation of electricity and the distribution of electricity and natural gas in Wisconsin; and UMERC, which generates electricity and distributes electricity and natural gas to customers located in the Upper Peninsula of Michigan.

•Illinois segment – Consists of PGL and NSG, which are engaged primarily in the distribution of natural gas in Illinois.

•Other states segment – Consists of MERC and MGU, which are engaged primarily in the distribution of natural gas in Minnesota and Michigan, respectively.

•Electric transmission segment – Consists of our approximate 60% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions, and our approximate 75% ownership interest in ATC Holdco, which invests in transmission-related projects outside of ATC's traditional footprint.

•Non-utility energy infrastructure segment – Consists of We Power, which is principally engaged in the ownership of electric power generating facilities for long-term lease to WE, and Bluewater, which owns underground natural gas storage facilities in Michigan. WECI, which holds our majority interests in multiple renewable generating facilities, is also included in this segment. See Note 2, Acquisitions, for more information on recently acquired WECI renewable generating facilities.

•Corporate and other segment – Consists of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Wisvest, WECC, and WBS.

Equity method investments

Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method. We use the cumulative earnings approach for classifying distributions received in the statements of cash flows. Under the cumulative earnings approach, we compare the distributions received to cumulative equity method earnings since inception. Any distributions received up to the amount of cumulative equity earnings are considered a return on investment and classified in operating activities. Any excess distributions are considered a return of investment and classified in investing activities.

Jointly owned facilities

Our financial statements also reflect our proportionate interests in certain jointly owned utility facilities. See Note 8, Jointly-Owned Utility Facilities, for more information.

Basis of presentation

We prepare our financial statements in conformity with GAAP.

Use of estimates

We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates.

Cash and cash equivalents

Cash and cash equivalents include marketable debt securities with an original maturity of three months or less.

Operating revenues

The following discussion includes our significant accounting policies related to operating revenues. For additional required disclosures on disaggregation of operating revenues, see Note 4, Operating Revenues.

Revenues from Contracts with Customers

Electric Utility Operating Revenues

Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our Wisconsin residential and commercial and industrial customers and the majority of our Michigan residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. In our Michigan service territory, a limited number of residential and commercial and industrial customers can purchase the commodity from a third party. In this case, the delivery of the electricity represents our sole performance obligation.

The transaction price of the performance obligations for residential and commercial and industrial customers is valued using the rates, charges, terms, and conditions of service included in the tariffs of our regulated electric utilities, which have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month. Our retail electric rates in Wisconsin include base amounts for fuel and purchased power costs, which also impact our revenues. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under- or over-collections of actual fuel and purchased power costs beyond a 2% price variance from the costs included in the rates charged to customers. Our electric utilities monitor the deferral of under-collected costs to ensure that it does not cause them to earn a greater ROE than authorized by the PSCW. In contrast, the rates of our Michigan retail electric customers include recovery of fuel and purchased power costs on a one-for-one basis. In addition, the Wisconsin residential tariffs of WE and WPS include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates.

Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have our utilities provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric utilities and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis.

The transaction price of the performance obligations for wholesale customers is valued using the rates, charges, terms, and conditions of service, which have been approved by the FERC. These wholesale rates include recovery of fuel and purchased power costs from customers on a one-for-one basis. For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility's costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual current-year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services.

We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales, and net sales in a single hour are recorded as resale revenues on our income statements. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets.

For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days.

Natural Gas Utility Operating Revenues

We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under the tariffs of our regulated utilities. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In certain of our service territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer.

The transaction price of the performance obligations for our natural gas customers is valued using the rates, charges, terms, and conditions of service included in the tariffs of our regulated utilities, which have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month.

The tariffs of our natural gas utilities include various rate mechanisms that allow them to recover or refund changes in prudently incurred costs from rate case-approved amounts. The rates for all of our natural gas utilities include one-for-one recovery mechanisms for natural gas commodity costs. Under normal circumstances, we defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year.

In addition, the rates of PGL and NSG, and the residential tariffs of WE, WPS, and WG, include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. The rates of PGL and NSG include riders for cost recovery of both environmental cleanup costs and energy conservation and management program costs. Finally, through the end of 2023 and effective again starting January 1, 2025, the rates of MGU include a rider to recover costs incurred to replace or modify natural gas facilities.

Consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days.

Other Natural Gas Operating Revenues

We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment. Bluewater owns underground natural gas storage facilities in southeastern Michigan and provides natural gas storage and hub services to customers. Bluewater has entered into long-term service agreements for natural gas storage services with WE, WPS, and WG, and also provides limited service to unaffiliated customers. We recognize revenues using a time-based output method through a monthly fixed service fee. Typical storage contract rates consist of firm storage reservation charges and firm injection and withdrawal charges. All amounts associated with the service agreements with WE, WPS, and WG have been eliminated at the consolidated level.

Other Non-Utility Operating Revenues

Wind and solar generation revenues from WECI's ownership interests in renewable generation facilities continued to grow in 2025. See Note 2, Acquisitions, for more information on recent acquisitions. Most of these renewable generation facilities have offtake agreements with unaffiliated third parties for all of the energy to be produced by the facility, some of which are bundled with

capacity and RECs. We consider bundled energy, capacity, and RECs within these offtake agreements to be distinct performance obligations as each are often transacted separately in the marketplace.

When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Revenue from the sale of this renewable energy is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of the renewable generation facility and conveys the ability to call on the renewable generation facility to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis. The performance obligation for RECs is recognized at a point-in-time; however, the timing of revenue recognition is the same, as the generation of renewable energy and the recognition of REC revenues generally occur concurrently.

Non-utility operating revenues are also derived from servicing appliances for customers at MERC. These contracts customarily have a duration of one year or less and consist of a single performance obligation satisfied over time. We use a time-based output method to recognize revenues monthly for the service fee.

Consistent with the timing of when we recognize revenue, customer billings for the renewable generation and servicing revenues generally occur on a monthly basis, with payments typically due in full within 30 days.

As part of the construction of the We Power electric generating units, we capitalized interest during construction, which is included in property, plant, and equipment. As allowed by the PSCW, we collected these carrying costs from WE's utility customers during construction. The equity portion of these carrying costs was recorded as a contract liability, which is presented as deferred revenue, net on our balance sheets. We continually amortize the deferred carrying costs to revenues over the related lease term that We Power has with WE. During 2025, 2024, and 2023, we recorded $24.6 million, $24.3 million, and $23.5 million, respectively, of revenues related to these deferred carrying costs.

Other Operating Revenues

Bespoke Resources Current Return

We recognize revenues monthly associated with carrying costs, including financing costs, during the construction period of bespoke resources assigned to WE's very large utility customers under payment and cancellation agreements. These amounts are not considered revenues from contracts with customers as electricity is not yet being provided by WE. Consistent with the timing of when we recognize revenue, customer billings for the bespoke resources that are subject to current return (as opposed to AFUDC) occur on a monthly basis, with payments typically due in full within 45 days.

Alternative Revenues

Alternative revenues are created from programs authorized by regulators that allow our utilities to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. Alternative revenue programs allow compensation for the effects of weather abnormalities, other external factors, or demand side management initiatives. Alternative revenue programs can also provide incentive awards if the utility achieves certain objectives and in other limited circumstances. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers.

Below is a summary of the alternative revenue programs at our utilities:

•The rates of PGL, NSG, and MERC include decoupling mechanisms. These mechanisms differ by state and allow the utilities to recover or refund the differences between actual and authorized margins for certain customer classes.

•MERC’s rates include a conservation improvement program rider, which includes a financial incentive for meeting energy savings goals.

•WE and WPS provide wholesale electric service to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual

cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.

Credit losses

The following discussion includes our significant accounting policies related to credit losses. For additional required disclosures on credit losses, see Note 5, Credit Losses.

Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are primarily generated from the sale of electricity and natural gas by our regulated utility operations. Credit losses associated with our utility operations are analyzed at the reportable segment level as we believe contract terms, political and economic risks, and the regulatory environment are similar at this level as our reportable segments are generally based on the geographic location of the underlying utility operations.

We have an accounts receivable and unbilled revenue balance associated with our non-utility energy infrastructure segment, related to the sale of electricity from our majority-owned renewable generating facilities through agreements with several large high credit quality counterparties.

We evaluate the collectability of our accounts receivable and unbilled revenue balances considering a combination of factors. For some of our larger customers and also in circumstances where we become aware of a specific customer's inability to meet its financial obligations to us, we record a specific allowance for credit losses against amounts due in order to reduce the net recognized receivable to the amount we reasonably believe will be collected. For all other customers, we use the accounts receivable aging method to calculate an allowance for credit losses. Using this method, we classify accounts receivable into different aging buckets and calculate a reserve percentage for each aging bucket based upon historical loss rates. The calculated reserve percentages are updated on at least an annual basis, in order to ensure recent macroeconomic, political, and regulatory trends are captured in the calculation, to the extent possible. Risks identified that we do not believe are reflected in the calculated reserve percentages, are assessed on a quarterly basis to determine whether further adjustments are required.

We monitor our ongoing credit exposure through active review of counterparty accounts receivable balances against contract terms and due dates. Our activities include timely account reconciliation, dispute resolution and payment confirmation. To the extent possible, we work with customers with past due balances to negotiate payment plans, but will disconnect customers for non-payment as allowed by our regulators, if necessary, and employ collection agencies and legal counsel to pursue recovery of defaulted receivables. For our larger customers, detailed credit review procedures may be performed in advance of any sales being made. We sometimes require letters of credit, parental guarantees, prepayments or other forms of credit assurance from our larger customers, including VLCs, to mitigate credit risk.

Materials, supplies and inventories

Our inventories as of December 31 consisted of:


(in millions)	2025		2024
Materials and supplies	$	416.4	$	412.5
Natural gas in storage	292.5		300.2
Fossil fuel	94.5		100.5
Total	$	803.4	$	813.2

PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. Inventories stated on a LIFO basis represented approximately 17% and 18% of total inventories at December 31, 2025 and 2024, respectively. The estimated replacement cost of natural gas in inventory at December 31, 2025 and 2024, exceeded the LIFO cost by $94.9 million and $77.9 million, respectively. In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per Dth of $3.36 at December 31, 2025, and $3.10 at December 31, 2024.

Substantially all other materials and supplies, natural gas in storage, and fossil fuel inventories are recorded using the weighted-average cost method of accounting.

Regulatory assets and liabilities

The economic effects of regulation can result in regulated companies recording costs and revenues that are allowed in the ratemaking process in a period different from the period they would have been recognized by a nonregulated company. When this occurs, regulatory assets and liabilities are recorded on the balance sheet. Regulatory assets represent deferred costs probable of recovery from customers that would have otherwise been charged to expense. Regulatory

liabilities represent amounts that are expected to be refunded to customers in future rates or future costs already collected from customers in rates.

The recovery or refund of regulatory assets and liabilities is based on specific periods determined by our regulators or occurs over the normal operating period of the related assets and liabilities. If a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery, and the reduction is charged to expense in the current period. See Note 6, Regulatory Assets and Liabilities, for more information.

Property, plant, and equipment

We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to other operation and maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.

We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the applicable regulators. Annual utility composite depreciation rates are shown below:


Annual Utility Composite Depreciation Rates	2025	2024	2023
WE	3.07%	3.03%	3.03%
WPS	3.01%	2.92%	2.93%
WG	2.45%	2.61%	2.61%
PGL	3.34%	3.36%	3.13%
NSG	2.49%	2.49%	2.46%
MERC	2.62%	2.60%	2.60%
MGU	2.87%	2.87%	2.73%
UMERC	3.20%	3.01%	2.97%

We depreciate our We Power assets over the estimated useful life of the various property components. The components have useful lives of between 10 to 45 years for PWGS 1 and PWGS 2 and 10 to 55 years for ER 1 and ER 2.

We depreciate our WECI assets over the estimated useful life of the property, with wind and solar generating facilities being depreciated over 30 and 35 years, respectively.

We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 3 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement.

Third parties reimburse the utilities for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs are recorded as a reduction to property, plant, and equipment.

See Note 7, Property, Plant, and Equipment, for more information.

AFUDC

AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC-Debt) used during plant construction, and a return on shareholders' capital (AFUDC-Equity) used for construction purposes. AFUDC-Debt is recorded as a reduction of interest expense, and AFUDC-Equity is recorded in other income, net.

The majority of AFUDC is recorded at WE, WPS, WG, UMERC, and WBS. Approximately 50% of WE's, WPS's, WG's, UMERC's, and WBS's retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. AFUDC rates are determined by their respective state commissions, each with specific requirements. Average AFUDC rates are shown below:


	2025
	Average AFUDC Retail Rate	Average AFUDC Wholesale Rate
WE	8.65%	7.51%
WPS	7.82%	6.62%
WG	8.54%	N/A
UMERC	6.40%	N/A
WBS	7.82%	N/A

Our regulated utilities and WBS recorded the following AFUDC for the years ended December 31:


(in millions)	2025		2024		2023
AFUDC-Debt
WE	$	29.8	$	14.6	$	13.0
WPS	4.7		3.6		2.9
UMERC	3.4		0.4		—
WG	0.5		0.5		3.4
WBS	0.2		0.1		0.1
Other	0.4		0.2		0.1
Total AFUDC-Debt	$	39.0	$	19.4	$	19.5

AFUDC-Equity
WE	$	78.9	$	46.0	$	41.0
WPS	12.2		9.2		7.6
UMERC	6.3		1.0		—
WG	1.2		2.9		9.8
WBS	0.5		0.3		0.4
Other	0.7		0.4		0.3
Total AFUDC-Equity	$	99.8	$	59.8	$	59.1

See Note 16, Income Taxes, for more information on how AFUDC-Equity is treated for tax purposes and the related impact on total WEC Energy Group income tax expense.

Cloud computing hosting arrangements that are service contracts

We have entered into several cloud computing arrangements that are hosted service contracts as part of projects related to the continuous transformation of technology. These projects include, among other things, a centralized repository for data to improve analytics, reporting, work and asset management, targeted enterprise resource planning systems, human resources management, employee scheduling, geospatial information, training, information technology service management, and customer contact systems. We present prepaid hosting fees that are service contracts in either prepayments or other long-term assets on our balance sheets and amortize them as the hosting services are received. Amortization expense, as well as the fees associated with the hosting arrangements, is recorded in other operation and maintenance expense on our income statements.

At December 31, 2025 and 2024, we had $27.0 million and $17.0 million, respectively, of capitalized implementation costs related to cloud computing arrangements that are hosted service contracts. We amortize the implementation costs on a straight-line basis over the cloud computing service arrangement term once the component of the hosted service is ready for its intended use. Accumulated amortization at December 31, 2025 and 2024, was $5.8 million and $4.1 million, respectively. Amortization expense for the years ended December 31, 2025, 2024, and 2023 was not significant. The presentation of the implementation costs, along with the related accumulated amortization, follows the prepaid hosting fees.

Impairment of goodwill and other intangible assets

Goodwill and other intangible assets with indefinite lives are subject to an annual impairment test. Interim impairment tests are performed when impairment indicators are present. During the third quarter of each year, we perform an annual impairment test for all of our reporting units that carried a goodwill balance. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit's net assets exceeds the reporting unit's fair

value. An impairment loss is recorded as the excess of the carrying amount of the goodwill over its fair value. For our indefinite-lived intangible assets, an impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds its fair value. An impairment loss is measured as the excess of the carrying amount of the intangible asset over its fair value. No impairment losses were recorded for our indefinite-lived intangible assets during the years ended December 31, 2025, 2024, and 2023. See Note 10, Goodwill and Intangibles, for more information.

Impairment of long-lived assets

We periodically assess the recoverability of certain long-lived assets when factors indicate the carrying value of such assets may be impaired or such assets are planned to be sold. Long-lived assets that would be subject to an impairment assessment generally include any assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future, as well as assets within nonregulated operations that are proposed to be sold or are currently generating operating losses. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds its fair value. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset over its fair value.

We also periodically assess the recoverability of our non-utility long-lived assets, which includes reviewing current activities, changes in the conditions of our renewable generating facilities, and market conditions in which they operate to determine the existence of any indicators requiring an impairment analysis. Indicators of potential impairment for a non-utility long-lived asset group, generally an individual renewable generation project, include adverse changes in the financial condition of a customer to our offtake agreements, a significant decline in the forecasted operating revenues and earnings of our renewable generation projects, and deterioration in the performance of our renewable generation projects.

We assess the likelihood of a disallowance of part of the cost of recently completed plant by considering factors such as applicable regulatory environment changes, our own recent rate orders, as well as recent rate orders of other regulated entities in similar jurisdictions. When it becomes probable that part of the cost of recently completed plant will be disallowed for rate-making purposes, we assess whether a reasonable estimate of the amount of the disallowance can be made. The estimated amount of the probable disallowance will then be deducted from the reported cost of the plant and recognized as an impairment loss.

When it becomes probable that a generating unit will be retired before the end of its useful life, we assess whether the generating unit meets the criteria for abandonment accounting. Generating units that are considered probable of abandonment are expected to cease operations in the near term, significantly before the end of their original estimated useful lives. If a generating unit meets the applicable criteria to be considered probable of abandonment, and the unit has been abandoned, we assess the likelihood of recovery of the remaining net book value of that generating unit at the end of each reporting period. If it becomes probable that regulators will disallow full recovery as well as a return on the remaining net book value of a generating unit that is either abandoned or probable of being abandoned, an impairment loss may be required. An impairment loss would be recorded if the remaining net book value of the generating unit is greater than the present value of the amount expected to be recovered from ratepayers, using an incremental borrowing rate. See Note 6, Regulatory Assets and Liabilities, and Note 7, Property, Plant, and Equipment, for more information.

We recorded the following impairment losses on our income statements in the following segments during the years ended December 31:


(in millions)	2025			2024			2023
Illinois	$	130.0	(1)	$	12.1	(2)	$	178.9	(3)
Non-utility energy infrastructure (4)	15.9			—			—
Total impairment losses	$	145.9		$	12.1		$	178.9

(1) Represents a probable disallowance of certain capital costs at PGL under the QIP rider. See Note 26, Regulatory Environment, for more information.

(2) Represents a disallowance of certain previously incurred capital costs at PGL resulting from an ICC order received in August 2024 related to the 2016 annual prudency review of the QIP rider. See Note 26, Regulatory Environment, for more information.

(3) Represents a disallowance of certain previously incurred capital costs resulting from PGL's and NSG's November 2023 rate orders from the ICC. See Note 26, Regulatory Environment, for more information.

(4) Represents impairment losses related to storm damage at certain of WECI's renewable generation facilities.

Impairment of equity method investments

We periodically assess the recoverability of equity method investments when factors indicate the carrying amount of such assets may be impaired. Equity method investments are assessed for impairment by comparing the fair values of these investments to their carrying amounts if a fair value assessment was completed or by reviewing for the presence of impairment indicators. If an impairment exists, and it is determined to be other-than-temporary, an impairment loss is recognized equal to the amount by which the carrying amount exceeds the investment's fair value.

Asset retirement obligations

We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. An ARO liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The ARO liabilities are accreted each period using the credit-adjusted risk-free interest rates associated with the expected settlement dates of the AROs. These rates are determined when the obligations are incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated capitalized retirement costs. For our regulated entities, we recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. See Note 9, Asset Retirement Obligations, for more information.

Finite-lived intangible assets and liabilities

Our finite-lived intangible asset and liabilities include revenue contracts, consisting of PPAs and a proxy revenue swap, in addition to interconnection agreements, which resulted from the acquisitions of renewable generation facilities by WECI in our non-utility energy infrastructure segment. Intangible asset and liabilities are amortized on a straight-line basis over their estimated useful lives, which is the term of the related agreement. Amortization of the revenue intangible asset and liabilities are recorded within operating revenues in the income statements. Amortization of the interconnection agreement intangible liabilities is recorded within other operation and maintenance in the income statements. The straight-line method of amortization is used because it best reflects the pattern in which the economic benefits of the intangibles are consumed or otherwise used. The amounts and useful lives assigned to the intangible asset and liabilities assumed impact the amount and timing of future amortization. See Note 10, Goodwill and Intangibles, for more information

Stock-based compensation

In accordance with the Omnibus Stock Incentive Plan, we provide long-term incentives through our equity interests to our non-employee directors, officers, and other key employees. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in common stock, cash, or a combination thereof. In addition to those shares of common stock that were subject to awards outstanding as of May 6, 2021, when the plan was last approved by shareholders, 9.0 million shares were reserved for issuance under the plan.

We recognize stock-based compensation expense on a straight-line basis over the requisite service period. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period. We account for forfeitures as they occur.

Stock Options

We grant non-qualified stock options that generally vest on a cliff-basis after three years. The exercise price of a stock option under the plan cannot be less than 100% of our common stock's fair market value on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of our common stock on the date of the grant. Options vest immediately upon retirement, death, or disability; however, they may not be exercised within six months of the grant date except in connection with certain termination of employment events following a change in control. Options expire no later than 10 years from the date of the grant.

Our stock options are classified as equity awards. The fair value of our stock options was calculated using a binomial option-pricing model. The following table shows the estimated weighted-average fair value per stock option granted along with the weighted-average assumptions used in the valuation models:


	2025			2024			2023
Stock options granted	231,024			294,990			257,780

Estimated weighted-average fair value per stock option	$	18.23		$	16.19		$	19.58

Assumptions used to value the options:
Risk-free interest rate	4.2% – 4.6%			3.9% – 5.4%			3.8% – 4.8%
Dividend yield	4.1		%	3.8		%	3.2		%
Expected volatility	22.0		%	22.0		%	22.0		%
Expected life (years)	8.3			8.4			8.3

The risk-free interest rate was based on the United States Treasury interest rate with a term consistent with the expected life of the stock options. The dividend yield was based on our dividend rate at the time of the grant and historical stock prices. Expected volatility and expected life assumptions were based on our historical experience.

Restricted Shares

Restricted shares granted to employees generally have a vesting period of three years with one-third of the award vesting on each anniversary of the grant date. Restricted shares granted to non-employee directors fully vest after one year.

Our restricted shares are classified as equity awards.

Performance Units

Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. All grants of performance units are settled in cash and are accounted for as liability awards accordingly. Performance units accrue forfeitable dividend equivalents in the form of additional performance units. The fair value of the performance units reflects our estimate of the final expected value of the awards, which is based on our stock price and performance achievement under the terms of the award. Stock-based compensation costs are generally recorded over the performance period, which is three years.

Pursuant to the terms of the WEC Energy Group Performance Unit Plan, the Compensation Committee selected multiple performance measures that will be weighted to determine the ultimate payout of the performance unit awards. The ultimate number of units that will be paid out will be based on our total shareholder return compared to the total shareholder return of a peer group of companies over three years (55%), and our performance against the weighted average authorized ROE of all of our utility subsidiaries (45%). In addition, the Compensation Committee selected the level of our stock price to earnings ratio compared to our peer companies as a performance measure that can increase the payout by up to 25%. In no event can the performance unit payout be greater than 200% of the target award.

See Note 11, Common Equity, for more information on our stock-based compensation plans.

Stock-based compensation - forfeitures

We account for forfeitures as they occur.

Earnings per share

We compute basic EPS by dividing our net income attributed to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted EPS is computed in a similar manner, but includes the exercise, settlement, and/or conversion of all potentially dilutive securities. Our potentially dilutive securities include stock options, forward equity sales contracts, and shares issuable upon the conversion of our convertible debt instruments.

The dilutive impacts from our in-the-money stock options and forward equity sales contract are calculated using the treasury stock method. The calculation of diluted EPS for the year ended December 31, 2025 excluded 58,533 shares issuable under our forward equity sales contract as their effect was anti-dilutive. The calculation of diluted EPS for the years ended December 31, 2024 and 2023 excluded 66,870 and 1,716,286 stock options, respectively, that had an anti-dilutive effect. No stock options had an anti-dilutive effect for the year ended December 31, 2025, and we did not have any forward equity sales contracts prior to 2025.

Potentially dilutive common shares issuable upon conversion of our convertible debt instruments are calculated using the if-converted method. For the year ended December 31, 2025, there were no shares of our common stock related to the potential conversion of the 2028 Notes (issued in June 2025) included in our diluted EPS calculation as the impact was anti-dilutive. For the year ended December 31, 2024, there were no shares of our common stock related to the potential conversion of the 2027 Notes and 2029 Notes (both issued in 2024) included in our diluted EPS calculation as the impact was anti-dilutive.

See Note 11, Common Equity, for more information on the computation of our basic and diluted EPS.

Leases

We recognize a right of use asset and lease liability for operating and finance leases with a term of greater than one year. As a policy election, we account for each lease component separately from the nonlease components of a contract.

We are currently party to several easement agreements that allow us access to land we do not own for the purpose of constructing and maintaining certain electric power and natural gas equipment. The majority of payments we make related to easements relate to our renewable generating facilities. We have not classified our easements as leases because we view the entire parcel of land specified in our easement agreements to be the identified asset, not just that portion of the parcel that contains our easement. As such, we have concluded that we do not control the use of an identified asset related to our easement agreements, nor do we obtain substantially all of the economic benefits associated with these shared-use assets.

See Note 15, Leases, for more information.

Income taxes

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments require additional disclosures, primarily related to income taxes paid and the rate reconciliation table. The amendments require disclosures on specific categories in the rate reconciliation table, as well as additional information for reconciling items that meet a quantitative threshold. For income taxes paid, additional disclosures are required to disaggregate federal, state, and foreign income taxes paid, with additional disclosures for income taxes paid that meet a quantitative threshold. We adopted ASU No. 2023-09 on January 1, 2025, on a retroactive basis, with the required disclosures first included in our 2025 Annual Report on Form 10-K.

We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense.

ITCs are deferred and amortized over the life of the assets. PTCs are recognized in the period in which such credits are generated. The amount of the credit is based upon power production from our qualifying generation facilities. We file a consolidated federal income tax return. Accordingly, we allocate federal current tax expense, benefits, and credits to our subsidiaries based on their separate tax computations and our ability to monetize all credits on our consolidated federal return.

We recognize interest and penalties accrued, related to unrecognized tax benefits, in income tax expense in our income statements.

The IRA contains a tax credit transferability provision that allows us to sell PTCs and ITCs produced after December 31, 2022, to third parties. Under this transferability provision, we entered into agreements to sell the majority of the PTCs and ITCs we generated in 2023, 2024, and 2025 to third parties. See Note 16, Income Taxes, for more information on the PTCs we sold. We have also entered into an agreement to sell the majority of PTCs that we expect to generate in 2026 to third parties. We elect to account for tax credits transferred under the scope of ASC 740. We include the discount from the sale of tax credits as a component of income tax expense. We also include any expected proceeds from the sale of tax credits in the evaluation of the realizability of deferred tax assets related to PTCs and ITCs. The sale of tax credits is presented in the operating activities section of the statements of cash flows consistent with the presentation of cash taxes paid.

In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized for tax purposes. We adopted the safe harbor method of accounting for certain of our utilities on our 2023 tax return

and adopted the safe harbor method of accounting for our remaining utilities on our 2024 tax return, which increased our deferred tax liabilities.

See Note 16, Income Taxes, for more information.

Fair value measurements

Fair value is 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).

Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

When possible, we base the valuations of our assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives, such as FTRs and TCRs, are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. FTRs and TCRs are valued using auction prices from the applicable RTO.

See Note 17, Fair Value Measurements, for more information.

Derivative instruments

We use derivatives as part of our risk management program to manage the risks associated with the price volatility of interest rates, purchased power, generation, and natural gas costs for the benefit of our customers and shareholders. Our approach is non-speculative and designed to mitigate risk. Regulated hedging programs are approved by our state regulators.

We record derivative instruments on our balance sheets as assets or liabilities measured at fair value unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities.

We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows.

Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets, and cash collateral received is reflected in other current liabilities. See Note 18, Derivative Instruments, for more information.

Guarantees

We follow the guidance of the Guarantees Topic of the FASB ASC, which requires, under certain circumstances, that the guarantor recognize a liability for the fair value of the obligation undertaken in issuing the guarantee at its inception. See Note 19, Guarantees, for more information.

Employee benefits

The costs of pension and OPEB plans are expensed over the periods during which employees render service. These costs are distributed among our subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for the utilities' net periodic benefit cost calculated under GAAP. See Note 20, Employee Benefits, for more information.

Customer deposits and credit balances

When utility customers apply for new service, they may be required to provide a deposit for the service. Customer deposits are recorded within other current liabilities on our balance sheets.

Utility customers can elect to be on a budget plan. Under this type of plan, a monthly installment amount is calculated based on estimated annual usage. During the year, the monthly installment amount is reviewed by comparing it to actual usage. If necessary, an adjustment is made to the monthly amount. Annually, the budget plan is reconciled to actual annual usage. Payments in excess of actual customer usage are recorded within other current liabilities on our balance sheets.

Environmental remediation costs

We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including CCR landfills and manufactured gas plant sites. See Note 9, Asset Retirement Obligations, for more information regarding CCR landfills and Note 24, Commitments and Contingencies, for more information regarding manufactured gas plant sites.

We record environmental remediation liabilities when site assessments indicate remediation is probable, and we can reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potentially responsible parties or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation.

Our utilities have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the applicable state regulatory commission's approval.

We review our estimated costs of remediation annually for our manufactured gas plant sites and CCR landfills. We adjust the liabilities and related regulatory assets, as appropriate, to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year.

Customer concentration of credit risk

The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Although we have a comprehensive credit evaluation process and contractual protections, it is possible that one or more counterparties could fail to perform their obligations, and we could recognize financial losses as a result. Credit risk exposure at WE, WPS, WG, PGL, and NSG is mitigated by their recovery mechanisms for uncollectible expense discussed in Note 1(d), Operating Revenues. There were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2025.As a result, for the majority of our utility companies, we did not have any significant concentrations of credit risk at December 31, 2025. However, WE has contracts with a small number of customers to provide power to large-scale data centers to support AI and other technology capabilities. This concentration of business with a small number of customers in an industry based on emerging technologies presents several risks. WE is incurring significant costs to construct bespoke resources to serve these customers. Although WE requires these customers to enter into payment and cancellation agreements, WE may still experience significant losses or delayed recovery of these costs. Changes in industry practice or advances in these technologies could reduce the demand for electricity to power data centers, which would reduce our forecasted revenues. Significant capital spend to build out required infrastructure or a downturn in business could weaken their financial condition, liquidity and/or creditworthiness, including their ability to satisfy their reimbursement obligations to us.

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2025

Accounting Policies [Abstract]

Schedule of inventory

Our inventories as of December 31 consisted of:


(in millions)	2025		2024
Materials and supplies	$	416.4	$	412.5
Natural gas in storage	292.5		300.2
Fossil fuel	94.5		100.5
Total	$	803.4	$	813.2

Schedule of annual utility composite depreciation rates

Annual utility composite depreciation rates are shown below:


Annual Utility Composite Depreciation Rates	2025	2024	2023
WE	3.07%	3.03%	3.03%
WPS	3.01%	2.92%	2.93%
WG	2.45%	2.61%	2.61%
PGL	3.34%	3.36%	3.13%
NSG	2.49%	2.49%	2.46%
MERC	2.62%	2.60%	2.60%
MGU	2.87%	2.87%	2.73%
UMERC	3.20%	3.01%	2.97%

Schedule of AFUDC rates and amounts

Average AFUDC rates are shown below:


	2025
	Average AFUDC Retail Rate	Average AFUDC Wholesale Rate
WE	8.65%	7.51%
WPS	7.82%	6.62%
WG	8.54%	N/A
UMERC	6.40%	N/A
WBS	7.82%	N/A

Our regulated utilities and WBS recorded the following AFUDC for the years ended December 31:


(in millions)	2025		2024		2023
AFUDC-Debt
WE	$	29.8	$	14.6	$	13.0
WPS	4.7		3.6		2.9
UMERC	3.4		0.4		—
WG	0.5		0.5		3.4
WBS	0.2		0.1		0.1
Other	0.4		0.2		0.1
Total AFUDC-Debt	$	39.0	$	19.4	$	19.5

AFUDC-Equity
WE	$	78.9	$	46.0	$	41.0
WPS	12.2		9.2		7.6
UMERC	6.3		1.0		—
WG	1.2		2.9		9.8
WBS	0.5		0.3		0.4
Other	0.7		0.4		0.3
Total AFUDC-Equity	$	99.8	$	59.8	$	59.1

Schedule of impairment losses

We recorded the following impairment losses on our income statements in the following segments during the years ended December 31:


(in millions)	2025			2024			2023
Illinois	$	130.0	(1)	$	12.1	(2)	$	178.9	(3)
Non-utility energy infrastructure (4)	15.9			—			—
Total impairment losses	$	145.9		$	12.1		$	178.9

(1) Represents a probable disallowance of certain capital costs at PGL under the QIP rider. See Note 26, Regulatory Environment, for more information.

(2) Represents a disallowance of certain previously incurred capital costs at PGL resulting from an ICC order received in August 2024 related to the 2016 annual prudency review of the QIP rider. See Note 26, Regulatory Environment, for more information.

(3) Represents a disallowance of certain previously incurred capital costs resulting from PGL's and NSG's November 2023 rate orders from the ICC. See Note 26, Regulatory Environment, for more information.

(4) Represents impairment losses related to storm damage at certain of WECI's renewable generation facilities.

Schedule of assumptions used to estimate the fair value of stock options granted

The following table shows the estimated weighted-average fair value per stock option granted along with the weighted-average assumptions used in the valuation models:


	2025			2024			2023
Stock options granted	231,024			294,990			257,780

Estimated weighted-average fair value per stock option	$	18.23		$	16.19		$	19.58

Assumptions used to value the options:
Risk-free interest rate	4.2% – 4.6%			3.9% – 5.4%			3.8% – 4.8%
Dividend yield	4.1		%	3.8		%	3.2		%
Expected volatility	22.0		%	22.0		%	22.0		%
Expected life (years)	8.3			8.4			8.3

Acquisitions (Tables) - WECI

12 Months Ended

Dec. 31, 2025

Hardin III

Asset Acquisition

Allocation of purchase price

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition.


(in millions)
Net property, plant, and equipment	$	526.5
Other current assets	0.2
Other current liabilities	(0.4)
Other long-term liabilities	(75.1)
Noncontrolling interest	(45.1)
Total purchase price	$	406.1

Delilah I

Asset Acquisition

Allocation of purchase price

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition.


(in millions)
Other current assets	$	0.1
Net property, plant, and equipment	579.8
Other long-term assets	12.4
Other long-term liabilities	(78.3)
Noncontrolling interest	(51.5)
Total purchase price	$	462.5

Samson I

Asset Acquisition

Allocation of purchase price

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the original acquisition.


(in millions)
Accounts receivable	$	0.5
Other current assets	0.7
Net property, plant, and equipment	497.2
Other long-term assets	12.3
Accounts payable	(0.5)
Other current liabilities	(0.8)
Other long-term liabilities	(186.4)
Noncontrolling interest	(65.7)
Total purchase price	$	257.3

Maple Flats

Asset Acquisition

Allocation of purchase price

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition.


(in millions)
Net property, plant, and equipment	$	469.5
Other long-term assets	44.5
Other long-term liabilities	(34.9)
Noncontrolling interest	(47.9)
Total purchase price	$	431.2

Sapphire Sky

Asset Acquisition

Allocation of purchase price

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition.


(in millions)
Accounts receivable	$	0.8
Net property, plant, and equipment	642.6
Other long-term assets	1.4
Accounts payable	(1.0)
Other long-term liabilities	(152.0)
Noncontrolling interest	(49.2)
Total purchase price	$	442.6

Operating Revenues (Tables)

12 Months Ended

Dec. 31, 2025

Disaggregation of Operating Revenues

Operating revenues disaggregated by revenue source


(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations			WEC Energy Group Consolidated
Year ended December 31, 2025
Electric	$	5,529.6	$	—	$	—	$	5,529.6	$	—	$	—	$	—		$	5,529.6
Natural gas	1,741.6		1,717.6		508.1		3,967.3		47.0		—		(44.5)			3,969.8
Total regulated revenues	7,271.2		1,717.6		508.1		9,496.9		47.0		—		(44.5)			9,499.4
Other non-utility revenues	—		—		21.8		21.8		243.6		—		(9.2)			256.2
Total revenues from contracts with customers	7,271.2		1,717.6		529.9		9,518.7		290.6		—		(53.7)			9,755.6
Other operating revenues	24.3		(34.0)		(2.4)		(12.1)		479.6		—		(423.0)		(1)	44.5
Total operating revenues	$	7,295.5	$	1,683.6	$	527.5	$	9,506.6	$	770.2	$	—	$	(476.7)		$	9,800.1


(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations			WEC Energy Group Consolidated
Year ended December 31, 2024
Electric	$	4,908.4	$	—	$	—	$	4,908.4	$	—	$	—	$	—		$	4,908.4
Natural gas	1,402.4		1,499.6		419.7		3,321.7		48.4		—		(46.0)			3,324.1
Total regulated revenues	6,310.8		1,499.6		419.7		8,230.1		48.4		—		(46.0)			8,232.5
Other non-utility revenues	—		—		20.4		20.4		223.9		—		(9.1)			235.2
Total revenues from contracts with customers	6,310.8		1,499.6		440.1		8,250.5		272.3		—		(55.1)			8,467.7
Other operating revenues	19.7		102.8		9.7		132.2		419.0		—		(419.0)		(1)	132.2
Total operating revenues	$	6,330.5	$	1,602.4	$	449.8	$	8,382.7	$	691.3	$	—	$	(474.1)		$	8,599.9


(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations			WEC Energy Group Consolidated
Year Ended December 31, 2023
Electric	$	4,994.6	$	—	$	—	$	4,994.6	$	—	$	—	$	—		$	4,994.6
Natural gas	1,606.7		1,480.5		493.7		3,580.9		61.9		—		(60.2)			3,582.6
Total regulated revenues	6,601.3		1,480.5		493.7		8,575.5		61.9		—		(60.2)			8,577.2
Other non-utility revenues	—		—		19.6		19.6		197.5		0.1		(9.1)			208.1
Total revenues from contracts with customers	6,601.3		1,480.5		513.3		8,595.1		259.4		0.1		(69.3)			8,785.3
Other operating revenues	24.6		77.3		5.8		107.7		407.1		—		(407.1)		(1)	107.7
Total operating revenues	$	6,625.9	$	1,557.8	$	519.1	$	8,702.8	$	666.5	$	0.1	$	(476.4)		$	8,893.0

(1) Amounts eliminated represent lease revenues related to certain plants that We Power leases to WE to supply electricity to its customers. Lease payments are billed from We Power to WE and then recovered in WE's rates as authorized by the PSCW and the FERC. WE operates the plants and is authorized by the PSCW and Wisconsin state law to fully recover prudently incurred operating and maintenance costs in electric rates.

Revenues from contracts with customers | Electric

Disaggregation of Operating Revenues

Operating revenues disaggregated by revenue source

The following table disaggregates electric utility operating revenues into customer class:


	Year Ended December 31
(in millions)	2025		2024		2023
Residential	$	2,249.6	$	1,996.3	$	1,992.3
Small commercial and industrial	1,763.6		1,613.0		1,641.1
Large commercial and industrial	1,057.8		942.6		978.4
Other	30.9		30.2		30.5
Total retail revenues	5,101.9		4,582.1		4,642.3
Wholesale	107.6		102.6		120.4
Resale	267.6		176.7		195.4
Steam	28.4		22.4		25.2
Other utility revenues	24.1		24.6		11.3
Total electric utility operating revenues	$	5,529.6	$	4,908.4	$	4,994.6

Revenues from contracts with customers | Natural gas

Disaggregation of Operating Revenues

Operating revenues disaggregated by revenue source

The following tables disaggregate natural gas utility operating revenues into customer class:


(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Year ended December 31, 2025
Residential	$	1,100.2	$	1,174.9	$	316.5	$	2,591.6
Commercial and industrial	563.9		320.0		164.4		1,048.3
Total retail revenues	1,664.1		1,494.9		480.9		3,639.9
Transportation	105.1		291.8		38.8		435.7
Other utility revenues (1) (2)	(27.6)		(69.1)		(11.6)		(108.3)
Total natural gas utility operating revenues	$	1,741.6	$	1,717.6	$	508.1	$	3,967.3


(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Year ended December 31, 2024
Residential	$	893.1	$	945.5	$	250.5	$	2,089.1
Commercial and industrial	416.8		274.5		123.9		815.2
Total retail revenues	1,309.9		1,220.0		374.4		2,904.3
Transportation	96.8		272.2		33.6		402.6
Other utility revenues (1)	(4.3)		7.4		11.7		14.8
Total natural gas utility operating revenues	$	1,402.4	$	1,499.6	$	419.7	$	3,321.7


(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Year Ended December 31, 2023
Residential	$	1,012.0	$	966.0	$	324.4	$	2,302.4
Commercial and industrial	506.7		267.1		175.3		949.1
Total retail revenues	1,518.7		1,233.1		499.7		3,251.5
Transportation	93.0		231.9		32.5		357.4
Other utility revenues (1)	(5.0)		15.5		(38.5)		(28.0)
Total natural gas utility operating revenues	$	1,606.7	$	1,480.5	$	493.7	$	3,580.9

(1) Includes the revenues subject to the purchased gas recovery mechanisms of our utilities, which fluctuate by segment based on actual natural gas costs incurred at our utilities, compared with the recovery of natural gas costs that were anticipated in rates.

(2) For our Illinois segment, includes a $75.0 million reduction in revenues recorded in the fourth quarter of 2025 for future billing credits to customers, based on the terms of a proposed settlement in February 2026 to resolve open QIP and UEA proceedings.

Revenues from contracts with customers | Other non-utility revenues

Disaggregation of Operating Revenues

Operating revenues disaggregated by revenue source

Other non-utility operating revenues consist primarily of the following:


	Year Ended December 31
(in millions)	2025		2024		2023
Renewable generation revenues	$	209.8	$	190.5	$	164.9
We Power revenues	24.6		24.3		23.5
Appliance service revenues	21.8		20.4		19.6

Other	—		—		0.1
Total other non-utility operating revenues	$	256.2	$	235.2	$	208.1

Other operating revenues

Disaggregation of Operating Revenues

Operating revenues disaggregated by revenue source

Other operating revenues consist primarily of the following:


	Year Ended December 31
(in millions)	2025		2024		2023
Late payment charges	$	48.1	$	48.5	$	56.5
Bespoke resources current return (1)	4.1		—		—
Alternative revenues (2)	(67.7)		79.8		47.0
Other	60.0		3.9		4.2
Total other operating revenues	$	44.5	$	132.2	$	107.7

(1) Bespoke resources current return consists of carrying costs earned during the construction of bespoke resources assigned to WE's VLCs. See Note 1(d), Operating Revenues, for more information.

(2) Alternative revenues consist of amounts to be recovered or refunded to customers subject to decoupling mechanisms, wholesale true-ups, and conservation improvement rider true-ups. Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. For more information about our alternative revenues, see Note 1(d), Operating Revenues.

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
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Reference 3: http://www.xbrl.org/2003/role/exampleRef
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Reference 4: http://www.xbrl.org/2003/role/exampleRef
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Reference 5: http://www.xbrl.org/2003/role/exampleRef
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Reference 6: http://www.xbrl.org/2003/role/exampleRef
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Reference 7: http://www.xbrl.org/2003/role/exampleRef
-Topic 606
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Reference 8: http://www.xbrl.org/2003/role/exampleRef
-Topic 606
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Reference 9: http://www.xbrl.org/2003/role/exampleRef
-Topic 606
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+ Details

Credit Losses (Tables)

12 Months Ended

Dec. 31, 2025

Credit Loss [Abstract]

Schedule of gross receivables and related allowances for credit losses

We have included tables below that show our gross third-party receivable balances and the related allowance for credit losses at December 31, 2025 and 2024, by reportable segment.


(in millions)	Wisconsin			Illinois			Other States			Total Utility Operations			Non-Utility Energy Infrastructure			Corporate and Other			WEC Energy Group Consolidated
December 31, 2025
Accounts receivable and unbilled revenues	$	1,368.8		$	654.8		$	130.2		$	2,153.8		$	50.3		$	7.3		$	2,211.4
Allowance for credit losses	61.7			82.3			4.7			148.7			—			—			148.7
Accounts receivable and unbilled revenues, net (1)	$	1,307.1		$	572.5		$	125.5		$	2,005.1		$	50.3		$	7.3		$	2,062.7

Total accounts receivable, net – past due greater than 90 days (1)	$	46.4		$	36.8		$	6.6		$	89.8		$	—		$	—		$	89.8
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	94.6		%	100.0		%	—		%	89.9		%	—		%	—		%	89.9		%


(in millions)	Wisconsin			Illinois			Other States			Total Utility Operations			Non-Utility Energy Infrastructure			Corporate and Other			WEC Energy Group Consolidated
December 31, 2024
Accounts receivable and unbilled revenues	$	1,149.9		$	535.6		$	100.6		$	1,786.1		$	40.0		$	6.0		$	1,832.1
Allowance for credit losses	73.6			83.9			5.3			162.8			—			—			162.8
Accounts receivable and unbilled revenues, net (1)	$	1,076.3		$	451.7		$	95.3		$	1,623.3		$	40.0		$	6.0		$	1,669.3

Total accounts receivable, net – past due greater than 90 days (1)	$	51.8		$	30.1		$	2.5		$	84.4		$	—		$	—		$	84.4
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	93.8		%	100.0		%	—		%	93.2		%	—		%	—		%	93.2		%

(1) Our exposure to credit losses for certain regulated utility customers is mitigated by regulatory mechanisms we have in place. Specifically, rates related to all of the customers in our Illinois segment, as well as the residential rates of WE, WPS, and WG in our Wisconsin segment, include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between the actual provision for credit losses and the amounts recovered in rates. As a result, at December 31, 2025, $1,290.2 million, or 62.5%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. See Note 26, Regulatory Environment, for more information on PGL and NSG's UEA rider for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and amounts recovered in rates.

Rollforward of the allowances for credit losses by reportable segment

A rollforward of the allowance for credit losses by reportable segment for the years ended December 31, 2025, 2024, and 2023, is included below:


(in millions)	Wisconsin		Illinois		Other States		WEC Energy Group Consolidated
Balance at January 1, 2025	$	73.6	$	83.9	$	5.3	$	162.8
Provision for credit losses	85.0		55.8		2.0		142.8
Provision for credit losses deferred for future recovery or refund	4.9		(28.7)		—		(23.8)
Write-offs charged against the allowance	(151.4)		(81.2)		(8.4)		(241.0)
Recoveries of amounts previously written off	49.6		52.5		5.8		107.9
Balance at December 31, 2025	$	61.7	$	82.3	$	4.7	$	148.7

On a consolidated basis, there was a $14.1 million decrease in the allowance for credit losses during the year ended December 31, 2025. This decrease is largely driven by customer write-offs in Wisconsin in addition to a decrease in past due account balances in Wisconsin that we believe was related to a continued focus on collection efforts and lower energy bills in the spring and summer months, enabling customers to pay down their arrears.


(in millions)	Wisconsin		Illinois		Other States		WEC Energy Group Consolidated
Balance at January 1, 2024	$	77.4	$	109.7	$	6.4	$	193.5
Provision for credit losses	52.1		52.3		0.5		104.9
Provision for credit losses deferred for future recovery or refund	43.8		(8.0)		—		35.8
Write-offs charged against the allowance	(141.8)		(95.0)		(6.6)		(243.4)
Recoveries of amounts previously written off	42.1		24.9		5.0		72.0
Balance at December 31, 2024	$	73.6	$	83.9	$	5.3	$	162.8

On a consolidated basis, there was a $30.7 million decrease in the allowance for credit losses during the year ended December 31, 2024, largely driven by customer write-offs. We also believe that the lower energy costs that customers were seeing, which were driven by warmer than normal weather conditions during most of 2024 and low average natural gas prices, contributed to a reduction in past due accounts receivable balances and a related decrease in the allowance for credit losses.


(in millions)	Wisconsin		Illinois		Other States		WEC Energy Group Consolidated
Balance at January 1, 2023	$	82.0	$	111.0	$	6.3	$	199.3
Provision for credit losses	40.9		26.3		4.8		72.0
Provision for credit losses deferred for future recovery or refund	52.5		35.8		—		88.3
Write-offs charged against the allowance	(131.6)		(85.4)		(6.6)		(223.6)
Recoveries of amounts previously written off	33.6		22.0		1.9		57.5
Balance at December 31, 2023	$	77.4	$	109.7	$	6.4	$	193.5

On a consolidated basis, there was a $5.8 million decrease in the allowance for credit losses during the year ended December 31, 2023, primarily related to lower customer energy costs (driven by the warmer weather during the fourth quarter of 2023 when compared to the same quarter in 2022 and lower natural gas prices), which contributed to a reduction in past due accounts receivable balances and a related decrease in the allowance for credit losses. Customer write-offs also contributed to the decrease in the allowance for credit losses.

Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2025

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of regulatory assets

The following regulatory assets were reflected on our balance sheets as of December 31:


(in millions)	2025		2024		See Note
Regulatory assets (1) (2)
Plant retirement related items (3)	$	768.6	$	810.5
Environmental remediation costs (4)	566.0		570.1		24
Pension and OPEB costs (5)	564.5		684.9		20, 26
Income tax related items	493.4		438.5		16
AROs	185.1		166.7		1(l), 9
Uncollectible expense	123.9		151.5		5
SSR (6)	92.6		102.9
Securitization	67.5		76.5		23
Derivatives	57.7		38.2		1(s)
Decoupling	43.8		110.0		1(d)
Bluewater (7)	37.7		57.7
Finance and operating leases	36.0		22.0		15
Electric transmission costs (8)	30.7		0.4
Energy efficiency programs (9)	11.6		26.5
Other, net	94.5		122.3
Total regulatory assets	$	3,173.6	$	3,378.7

Balance sheet presentation
Other current assets	$	17.3	$	39.0
Regulatory assets	3,156.3		3,339.7
Total regulatory assets	$	3,173.6	$	3,378.7