Cover Page - USD ($) $ in Billions	12 Months Ended
Cover Page - USD ($) $ in Billions	Dec. 31, 2023	Jan. 31, 2024	Jun. 30, 2023
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
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			$ 27.8
Entity Common Stock, Shares Outstanding		315,561,510
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 9, 2024, are incorporated by reference into Part III hereof.
Entity Central Index Key	0000783325
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Amendment Flag	false

Audit Information	12 Months Ended
Audit Information	Dec. 31, 2023
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, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Statement [Abstract]
Operating revenues	$ 8,893.0	$ 9,597.4	$ 8,316.0
Operating expenses
Cost of sales	3,191.2	4,358.9	3,311.0
Other operation and maintenance	2,100.5	1,938.0	2,005.5
Impairment related to ICC disallowances	178.9	0.0	0.0
Depreciation and amortization	1,264.2	1,122.6	1,074.3
Property and revenue taxes	250.2	253.7	210.3
Total operating expenses	6,985.0	7,673.2	6,601.1
Operating income	1,908.0	1,924.2	1,714.9
Equity in earnings of transmission affiliates	177.5	194.7	158.1
Other income, net	177.7	128.8	133.2
Interest expense	726.9	515.1	471.1
Loss on debt extinguishment	0.0	0.0	36.3
Other expense	(371.7)	(191.6)	(216.1)
Income before income taxes	1,536.3	1,732.6	1,498.8
Income tax expense	204.6	322.9	200.3
Net income	1,331.7	1,409.7	1,298.5
Preferred stock dividends of subsidiary	1.2	1.2	1.2
Net (income) loss attributed to noncontrolling interests	1.2	(0.4)	3.0
Net income attributed to common shareholders	$ 1,331.7	$ 1,408.1	$ 1,300.3
Earnings per share
Basic (in dollars per share)	$ 4.22	$ 4.46	$ 4.12
Diluted (in dollars per share)	$ 4.22	$ 4.45	$ 4.11
Weighted average common shares outstanding
Basic (in shares)	315.4	315.4	315.4
Diluted (in shares)	315.9	316.1	316.3

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Other Comprehensive Income [Abstract]
Net income	$ 1,331.7	$ 1,409.7	$ 1,298.5
Derivatives accounted for as cash flow hedges
Net derivative gain, net of tax	0.0	0.0	0.6
Reclassification of realized net derivative (gain) loss to net income, net of tax	(0.3)	(0.3)	0.9
Cash flow hedges, net	(0.3)	(0.3)	1.5
Defined benefit plans
Pension and OPEB adjustments arising during the period, net of tax expense (benefit) of $(0.2), $(1.3), and $0.7, respectively	(0.6)	(3.5)	1.7
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax	0.0	0.2	0.4
Defined benefit plans, net	(0.6)	(3.3)	2.1
Other comprehensive income (loss), net of tax	(0.9)	(3.6)	3.6
Comprehensive income	1,330.8	1,406.1	1,302.1
Preferred stock dividends of subsidiary	1.2	1.2	1.2
Comprehensive (income) loss attributed to noncontrolling interests	1.2	(0.4)	3.0
Comprehensive income attributed to common shareholders	$ 1,330.8	$ 1,404.5	$ 1,303.9

Consolidated Statements of Comprehensive Income (Parentheticals) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Other Comprehensive Income [Abstract]
Tax expense (benefit) on pension and OPEB adjustments arising during the period	$ (0.2)	$ (1.3)	$ 0.7

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Current assets
Cash and cash equivalents	$ 42.9	$ 28.9
Accounts receivable and unbilled revenues, net of reserves of $193.5 and $199.3, respectively	1,503.2	1,818.4
Materials, supplies, and inventories	775.2	807.1
Prepaid Taxes	173.9	201.8
Other prepayments	76.8	69.8
Other	223.7	261.7
Current assets	2,795.7	3,187.7
Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $11,073.1 and $10,383.8, respectively	31,581.5	29,113.8
Regulatory assets (December 31, 2023 and December 31, 2022 include $85.9 and $92.4, respectively, related to WEPCo Environmental Trust)	3,249.8	3,264.6
Equity investment in transmission affiliates	2,005.9	1,909.2
Goodwill	3,052.8	3,052.8
Pension and OPEB assets	870.9	916.7
Other	383.1	427.3
Long-term assets	41,144.0	38,684.4
Total assets	43,939.7	41,872.1
Current liabilities
Short-term debt	2,020.9	1,647.1
Current portion of long-term debt (December 31, 2023 and December 31, 2022 include $9.0 and $8.9, respectively, related to WEPCo Environmental Trust)	1,264.2	881.2
Accounts payable	896.6	1,198.1
Other	933.1	884.6
Current liabilities	5,114.8	4,611.0
Long-term liabilities
Long-term debt (December 31, 2023 and December 31, 2022 include $85.3 and $94.1, respectively, related to WEPCo Environmental Trust)	15,512.8	14,766.2
Deferred income taxes	4,918.5	4,625.6
Deferred revenue, net	356.4	370.7
Regulatory liabilities	3,697.7	3,735.5
Intangible liabilities	594.8	335.4
Environmental remediation liabilities	463.7	499.6
AROs	374.2	479.3
Pension and OPEB obligations	176.0	171.6
Other	659.3	660.6
Long-term liabilities	26,753.4	25,644.5
Commitments and contingencies (Note 24)
Common shareholders' equity
Common stock – $0.01 par value; 325,000,000 shares authorized; 315,434,531 shares outstanding	3.2	3.2
Additional paid in capital	4,115.9	4,115.2
Retained earnings	7,612.8	7,265.3
Accumulated other comprehensive loss	(7.7)	(6.8)
Common shareholders' equity	11,724.2	11,376.9
Preferred stock of subsidiary	30.4	30.4
Noncontrolling interests	316.9	209.3
Total liabilities and equity	$ 43,939.7	$ 41,872.1

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Accounts receivable and unbilled revenues, reserves	$ 193.5	$ 199.3
Property, plant, and equipment, accumulated depreciation and amortization	$ 11,073.1	$ 10,383.8
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	325,000,000	325,000,000
Common stock, shares outstanding	315,434,531	315,434,531
Balance sheets
Regulatory assets (December 31, 2023 and December 31, 2022 include $85.9 and $92.4, respectively, related to WEPCo Environmental Trust)	$ 3,249.8	$ 3,264.6
Current portion of long-term debt (December 31, 2023 and December 31, 2022 include $9.0 and $8.9, respectively, related to WEPCo Environmental Trust)	1,264.2	808.5
Long-term debt (December 31, 2023 and December 31, 2022 include $85.3 and $94.1, respectively, related to WEPCo Environmental Trust)	15,366.9	14,655.7
WEPCo Environmental Trust
Balance sheets
Regulatory assets (December 31, 2023 and December 31, 2022 include $85.9 and $92.4, respectively, related to WEPCo Environmental Trust)	85.9	92.4
Current portion of long-term debt (December 31, 2023 and December 31, 2022 include $9.0 and $8.9, respectively, related to WEPCo Environmental Trust)	9.0	8.9
Long-term debt (December 31, 2023 and December 31, 2022 include $85.3 and $94.1, respectively, related to WEPCo Environmental Trust)	$ 85.3	$ 94.1

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating activities
Net income	$ 1,331.7	$ 1,409.7	$ 1,298.5
Reconciliation to cash provided by operating activities
Depreciation and amortization	1,264.2	1,122.6	1,074.3
Deferred income taxes and ITCs, net	219.4	280.1	151.1
Impairment related to ICC disallowances	178.9	0.0	0.0
Contributions and payments related to pension and OPEB plans	(16.7)	(15.1)	(66.3)
Equity income in transmission affiliates, net of distributions	(33.0)	(74.3)	(25.1)
Net change in transmission regulatory assets and liabilities	19.8	(85.8)	5.7
Net gain on disposition of assets	(23.8)	(66.2)	(6.2)
Change in -
Accounts receivable and unbilled revenues, net	340.6	(342.1)	(249.2)
Materials, supplies, and inventories	41.9	(171.3)	(107.2)
Amounts recoverable from customers	17.4	60.0	(82.3)
Collateral on deposit	22.1	(108.1)	4.6
Other current assets	18.9	(27.7)	17.6
Accounts payable	(254.0)	121.5	126.9
Other current liabilities	47.5	126.9	(17.2)
Other, net	(156.5)	(169.5)	(92.5)
Net cash provided by operating activities	3,018.4	2,060.7	2,032.7
Investing Activities
Capital expenditures	(2,492.9)	(2,314.9)	(2,252.8)
Acquisition of Whitewater	(76.0)	0.0	0.0
Acquisition of Sapphire Sky, net of cash acquired of $0.3	(442.6)	0.0	0.0
Acquisition of Samson I, net of cash acquired of $5.2	(257.3)	0.0	0.0
Acquisition of Red Barn	(143.8)	0.0	0.0
Acquisition of West Riverside	(95.3)	0.0	0.0
Acquisition of Thunderhead, net of cash acquired of $0.5	0.0	(382.0)	0.0
Acquisition of Jayhawk	0.0	0.0	(119.9)
Capital contributions to transmission affiliates	(63.7)	(45.5)	0.0
Proceeds from the sale of assets	32.8	69.0	21.9
Proceeds from the sale of investments held in rabbi trust	10.4	15.4	18.7
Payments for ATC's construction costs that will be reimbursed	(19.8)	(24.8)	(7.0)
Reimbursement for ATC's construction costs	0.1	10.2	0.0
Insurance proceeds received for property damage	2.5	41.6	0.0
Other, net	(12.6)	(11.4)	27.3
Net cash used in investing activities	(3,558.2)	(2,642.4)	(2,311.8)
Financing Activities
Exercise of stock options	6.3	33.6	15.7
Purchase of common stock	(16.6)	(69.2)	(33.1)
Dividends paid on common stock	(984.2)	(917.9)	(854.8)
Issuance of long-term debt	2,170.0	1,999.3	2,383.8
Retirement of long-term debt	(1,005.4)	(92.1)	(1,260.4)
Repayment of short-term loan	(0.8)	0.0	(340.0)
Change in commercial paper	373.7	(252.6)	459.2
Payments for debt extinguishment and issuance costs	(14.2)	(15.6)	(67.2)
Other, net	(6.0)	(9.1)	(9.2)
Net cash provided by financing activities	522.8	676.4	294.0
Net change in cash, cash equivalents, and restricted cash	(17.0)	94.7	14.9
Cash, cash equivalents, and restricted cash at beginning of year	182.2	87.5	72.6
Cash, cash equivalents, and restricted cash at end of year	$ 165.2	$ 182.2	$ 87.5

Consolidated Statement of Cash Flows (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Sapphire Sky
Acquisitions
Cash and restricted cash acquired	$ 0.3
Samson I
Acquisitions
Cash and restricted cash acquired	$ 5.2
Thunderhead
Acquisitions
Cash and restricted cash acquired		$ 0.5

Consolidated Statements of Equity - USD ($) $ in Millions	Total	Total common shareholders' equity	Common stock	Additional paid-in capital	Retained earnings	Accumulated other comprehensive income (loss)	Preferred stock of subsidiary	Noncontrolling interests
Balance at Dec. 31, 2020	$ 10,662.5	$ 10,469.7	$ 3.2	$ 4,143.7	$ 6,329.6	$ (6.8)	$ 30.4	$ 162.4
Equity
Net income attributed to common shareholders	1,300.3	1,300.3	0.0	0.0	1,300.3	0.0	0.0	0.0
Net income (loss) attributed to noncontrolling interests	(3.0)	0.0	0.0	0.0	0.0	0.0	0.0	(3.0)
Other comprehensive income (loss)	3.6	3.6	0.0	0.0	0.0	3.6	0.0	0.0
Common stock dividends	(854.8)	(854.8)	0.0	0.0	(854.8)	0.0	0.0	0.0
Exercise of stock options	15.7	15.7	0.0	15.7	0.0	0.0	0.0	0.0
Purchase of common stock	(33.1)	(33.1)	0.0	(33.1)	0.0	0.0	0.0	0.0
Acquisition of noncontrolling interests	6.3	0.0	0.0	0.0	0.0	0.0	0.0	6.3
Capital contributions from noncontrolling interest	7.6	0.0	0.0	0.0	0.0	0.0	0.0	7.6
Distributions to noncontrolling interests	(4.1)	0.0	0.0	0.0	0.0	0.0	0.0	(4.1)
Stock-based compensation and other	12.3	11.8	0.0	11.8	0.0	0.0	0.0	0.5
Balance at Dec. 31, 2021	11,113.3	10,913.2	3.2	4,138.1	6,775.1	(3.2)	30.4	169.7
Equity
Net income attributed to common shareholders	1,408.1	1,408.1	0.0	0.0	1,408.1	0.0	0.0	0.0
Net income (loss) attributed to noncontrolling interests	0.4	0.0	0.0	0.0	0.0	0.0	0.0	0.4
Other comprehensive income (loss)	(3.6)	(3.6)	0.0	0.0	0.0	(3.6)	0.0	0.0
Common stock dividends	(917.9)	(917.9)	0.0	0.0	(917.9)	0.0	0.0	0.0
Exercise of stock options	33.6	33.6	0.0	33.6	0.0	0.0	0.0	0.0
Purchase of common stock	(69.2)	(69.2)	0.0	(69.2)	0.0	0.0	0.0	0.0
Acquisition of noncontrolling interests	42.5	0.0	0.0	0.0	0.0	0.0	0.0	42.5
Capital contributions from noncontrolling interest	1.1	0.0	0.0	0.0	0.0	0.0	0.0	1.1
Distributions to noncontrolling interests	(4.3)	0.0	0.0	0.0	0.0	0.0	0.0	(4.3)
Stock-based compensation and other	12.6	12.7	0.0	12.7	0.0	0.0	0.0	(0.1)
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 income (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
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

Consolidated Statements of Equity (Parenthetical) - $ / shares					12 Months Ended
	Oct. 19, 2023	Jul. 20, 2023	Apr. 20, 2023	Jan. 19, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Stockholders' Equity [Abstract]
Dividends per share (in dollars per share)	$ 0.78	$ 0.78	$ 0.78	$ 0.78	$ 3.12	$ 2.91	$ 2.71

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2023

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, 2023 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. However, as a result of the extreme weather in the Midwest in February 2021, the cost of gas purchased for our natural gas customers was temporarily driven significantly higher than our normal winter weather expectations, and we were not allowed to recover all of the additional costs. See Note 26, Regulatory Environment, for more information on the recovery of these high natural gas costs.

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, PGL's rates included a rider for pass through of income tax expense changes resulting from the Tax Legislation and a cost recovery mechanism for SMP costs. Similarly, 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 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 2023. 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 2023, 2022, and 2021, we recorded $23.5 million, $23.4 million, and $23.3 million, respectively, of revenues related to these deferred carrying costs.

Other Operating Revenues

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 to mitigate credit risk.

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


(in millions)	2023		2022
Natural gas in storage	$	327.8	$	446.3
Materials and supplies	320.0		257.0
Fossil fuel	127.4		103.8
Total	$	775.2	$	807.1

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 13% of total inventories at December 31, 2023 and 2022, respectively. The estimated replacement cost of natural gas in inventory at December 31, 2023 and 2022, exceeded the LIFO cost by $12.2 million and $98.3 million, respectively. In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per Dth of $2.13 at December 31, 2023, and $3.41 at December 31, 2022.

Substantially all other natural gas in storage, materials and supplies, 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 regulatory 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	2023	2022	2021
WE	3.03%	3.06%	3.09%
WPS	2.93%	2.67%	2.66%
WG	2.61%	2.47%	2.44%
PGL	3.13%	3.13%	3.12%
NSG	2.46%	2.43%	2.52%
MERC	2.60%	2.56%	2.58%
MGU	2.73%	2.75%	2.70%
UMERC	2.97%	3.01%	2.94%

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. The AFUDC calculation for WBS uses the WPS AFUDC retail rate, while our utilities' AFUDC rates are determined by their respective state commissions, each with specific requirements. Average AFUDC rates are shown below:


	2023
	Average AFUDC Retail Rate	Average AFUDC Wholesale Rate
WE	8.45%	6.70%
WPS	7.46%	4.60%
WG	7.94%	N/A
UMERC	6.28%	N/A
WBS	7.46%	N/A

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


(in millions)	2023		2022		2021
AFUDC-Debt
WE	$	13.0	$	6.9	$	2.9
WPS	2.9		2.3		3.5
WG	3.4		1.4		0.2
UMERC	—		0.1		0.1
WBS	0.1		0.1		0.1
Other	0.1		0.2		—
Total AFUDC-Debt	$	19.5	$	11.0	$	6.8

AFUDC-Equity
WE	$	41.0	$	18.8	$	7.9
WPS	7.6		5.8		9.0
WG	9.8		3.9		0.6
UMERC	—		0.1		0.1
WBS	0.4		0.3		0.2
Other	0.3		0.5		0.2
Total AFUDC-Equity	$	59.1	$	29.4	$	18.0

(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 and asset management, targeted enterprise resource planning systems, human resources management, employee scheduling, geospatial information, 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, 2023 and 2022, we had $11.3 million and $4.7 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, 2023 and 2022, was $2.8 million and $1.5 million, respectively. Amortization expense for the years ended December 31, 2023, 2022, and 2021 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 assets over its fair value. No impairment losses were recorded for our indefinite-lived intangible assets during the years ended December 31, 2023, 2022, and 2021. 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 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. In the fourth quarter of 2023, we recorded a non-cash impairment loss of $178.9 million related to the 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.

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.

(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) Intangible Liabilities—Our finite-lived intangible 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 liabilities are amortized on a straight-line basis over their estimated useful lives, which is the term of the agreements. Amortization of the revenue contract intangible liabilities is 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 intangible liabilities assumed impact the amount and timing of future amortization.

(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, rather than estimating potential future forfeitures and recording them over the vesting period.

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:


	2023			2022			2021
Stock options granted	257,780			437,269			530,612

Estimated weighted-average fair value per stock option	$	19.58		$	14.71		$	13.20

Assumptions used to value the options:
Risk-free interest rate	3.8% – 4.8%			0.2% – 1.6%			0.1% – 0.9%
Dividend yield	3.2		%	3.2		%	2.9		%
Expected volatility	22.0		%	21.0		%	21.0		%
Expected life (years)	8.3			8.7			8.7

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 certain officers and all 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.

The ultimate number of units that will be awarded is dependent on our total shareholder return (stock price appreciation plus dividends) as compared to the total shareholder return of a peer group of companies over three years, as well as other performance metrics, as may be determined by the Compensation Committee. Under the terms of awards granted prior to 2023, participants may earn between 0% and 175% of the performance unit award based on our total shareholder return. Pursuant to the plan terms governing these awards, these percentages can be adjusted upwards or downwards by up to 10% based on our performance against additional performance measures, if any, adopted by the Compensation Committee.

The WEC Energy Group Performance Unit Plan was amended and restated, effective January 1, 2023. In accordance with the amended plan, the Compensation Committee selected multiple performance measures that will be weighted to determine the ultimate payout for the awards granted in 2023 and 2024. The ultimate number of units awarded 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 earnings per share by dividing our net income attributed to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per share is computed in a similar manner, but includes the exercise and/or conversion of all potentially dilutive securities, as calculated using the treasury stock method. Such dilutive securities include in-the-money stock options. The calculation of diluted earnings per share for the years ended December 31, 2023, 2022, and 2021 excluded 1,716,286; 653,323; and 769,030 stock options, respectively, that had an anti-dilutive effect.

(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—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 produced after December 31, 2022, to third parties. In September 2023, under this transferability provision, we entered into an agreement to sell substantially all of our 2023 PTCs to a third party. 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 will also include any expected proceeds from the sale of tax credits in the evaluation of the realizability of deferred tax assets related to PTCs. 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 are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

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. 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. 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. As a result, we did not have any significant concentrations of credit risk at December 31, 2023. In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2023.

Acquisitions

12 Months Ended

Dec. 31, 2023

Asset Acquisition [Abstract]

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 liabilities related to PPAs. See Note 10, Goodwill and Intangibles, for more information.

Acquisitions of Electric Generation Facilities in Wisconsin

In June 2023, WE completed the acquisition of 100 MWs of West Riverside's nameplate capacity, in the first of two potential option exercises. West Riverside is a commercially operational dual fueled combined cycle generation facility in Beloit, Wisconsin. Prior to acquisition, WPS received approval to transfer its ownership interest rights to WE. WE's investment was $95.3 million. In addition, WPS filed a request with the PSCW in September 2023 to exercise a second option to acquire an additional 100 MWs of West Riverside's nameplate capacity. As it did with the first option, in October 2023, WPS filed for approval to assign its ownership interest pursuant to this second option to WE. If these approvals are obtained, WE's incremental share of this investment is expected to be approximately $100 million, with the transaction expected to close in 2024.

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 $143.8 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.

Acquisition of a Solar Generation Facility in Texas

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 County, Texas, for $257.3 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 15 years from the date of commercial operation. 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

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

In October 2022, WECI signed an agreement to acquire an 80% ownership interest in Maple Flats, a 250 MW solar generating facility under construction in Clay County, Illinois, for approximately $360 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. The transaction is subject to FERC approval and commercial operation is expected to begin during the second half of 2024, at which time the transaction is expected to close. Maple Flats is expected to qualify for PTCs and will be included in the non-utility energy infrastructure segment.

Acquisition of a Wind Generation Facility in Nebraska

In September 2022, WECI completed the acquisition of a 90% ownership interest in Thunderhead, a 300 MW wind generating facility in Antelope and Wheeler counties in Nebraska. The purchase price was $382.0 million, which includes transaction costs and is net of cash acquired. Thunderhead achieved commercial operation in November 2022. 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. Thunderhead 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	$	0.2
Other prepayments	0.3
Net property, plant, and equipment	692.3
Other long-term assets	5.1
Other current liabilities	(0.2)
Other long-term liabilities	(273.2)
Noncontrolling interest	(42.5)
Total purchase price	$	382.0

Acquisition of a Wind Generation Facility in Kansas

In February 2021, WECI completed the acquisition of a 90% ownership interest in Jayhawk, a 190 MW wind generating facility in Bourbon and Crawford counties, Kansas, for $119.9 million, which included transaction costs. This project became commercially operational in December 2021. Subsequent to the acquisition, WECI incurred an additional $161.3 million of capital expenditures as of December 31, 2022 for the project for a total investment of $281.2 million. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 10 years from the date of commercial operation. Jayhawk qualifies for PTCs. WECI is entitled to 99% of the tax benefits related to this facility for the first 10 years of commercial operation, after which it will be entitled to tax benefits equal to its ownership interest. Jayhawk 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	$	145.3
Other long-term liabilities	(11.8)
Long-term debt	(7.3)
Noncontrolling interest	(6.3)
Total purchase price	$	119.9

Dispositions	12 Months Ended
Dispositions	Dec. 31, 2023
Discontinued Operations and Disposal Groups [Abstract]
DISPOSITIONS	DISPOSITIONS 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. Illinois Segment Sale of Certain Real Estate by The Peoples Gas Light and Coke Company In May 2022, we sold approximately 11 acres of real estate owned by PGL that was no longer being utilized in its operations, for $55.1 million, which is net of closing costs. The real estate was located in Chicago, Illinois. As a result of the sale, a pre-tax gain in the amount of $54.5 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, 2023

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, 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


(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, 2022
Electric	$	4,956.2	$	—	$	—	$	4,956.2	$	—	$	—	$	—		$	4,956.2
Natural gas	1,980.7		1,883.7		601.8		4,466.2		54.3		—		(51.8)			4,468.7
Total regulated revenues	6,936.9		1,883.7		601.8		9,422.4		54.3		—		(51.8)			9,424.9
Other non-utility revenues	—		—		18.7		18.7		133.6		—		(9.1)			143.2
Total revenues from contracts with customers	6,936.9		1,883.7		620.5		9,441.1		187.9		—		(60.9)			9,568.1
Other operating revenues	23.6		7.2		(2.0)		28.8		402.1		0.5		(402.1)		(1)	29.3
Total operating revenues	$	6,960.5	$	1,890.9	$	618.5	$	9,469.9	$	590.0	$	0.5	$	(463.0)		$	9,597.4


(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, 2021
Electric	$	4,516.6	$	—	$	—	$	4,516.6	$	—	$	—	$	—		$	4,516.6
Natural gas	1,490.3		1,630.3		494.0		3,614.6		46.8		—		(43.8)			3,617.6
Total regulated revenues	6,006.9		1,630.3		494.0		8,131.2		46.8		—		(43.8)			8,134.2
Other non-utility revenues	—		—		17.8		17.8		92.8		—		(9.1)			101.5
Total revenues from contracts with customers	6,006.9		1,630.3		511.8		8,149.0		139.6		—		(52.9)			8,235.7
Other operating revenues	30.1		42.5		7.2		79.8		399.9		0.5		(399.9)		(1)	80.3
Total operating revenues	$	6,037.0	$	1,672.8	$	519.0	$	8,228.8	$	539.5	$	0.5	$	(452.8)		$	8,316.0

(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)	2023		2022		2021
Residential	$	1,992.3	$	1,879.1	$	1,768.0
Small commercial and industrial	1,641.1		1,530.4		1,415.7
Large commercial and industrial	978.4		1,042.2		931.9
Other	30.5		29.9		29.3
Total retail revenues	4,642.3		4,481.6		4,144.9
Wholesale	120.4		153.9		157.7
Resale	195.4		256.7		161.9
Steam	25.2		28.4		28.7
Other utility revenues	11.3		35.6		23.4
Total electric utility operating revenues	$	4,994.6	$	4,956.2	$	4,516.6

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, 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


(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Year ended December 31, 2022
Residential	$	1,234.0	$	1,297.4	$	391.3	$	2,922.7
Commercial and industrial	672.7		408.8		218.7		1,300.2
Total retail revenues	1,906.7		1,706.2		610.0		4,222.9
Transportation	81.8		259.8		34.5		376.1
Other utility revenues (1) (2)	(7.8)		(82.3)		(42.7)		(132.8)
Total natural gas utility operating revenues	$	1,980.7	$	1,883.7	$	601.8	$	4,466.2


(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Year Ended December 31, 2021
Residential	$	928.9	$	1,017.9	$	241.2	$	2,188.0
Commercial and industrial	472.1		302.1		129.9		904.1
Total retail revenues	1,401.0		1,320.0		371.1		3,092.1
Transportation	80.0		231.2		31.8		343.0
Other utility revenues (1) (3)	9.3		79.1		91.1		179.5
Total natural gas utility operating revenues	$	1,490.3	$	1,630.3	$	494.0	$	3,614.6

(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) During 2022, we continued to recover natural gas costs we under-collected from our customers in 2021 related to the extreme weather experienced in February 2021, as well as higher natural gas costs incurred at the majority of our segments during 2022. As these amounts are billed to customers, they are reflected in retail revenues with an offsetting decrease in other utility revenues.

(3) During 2021, in addition to costs related to the extreme weather event experienced in February 2021, we incurred higher natural gas costs as a result of an increase in the price of natural gas.

See Note 26, Regulatory Environment, for more information.

Other Non-Utility Operating Revenues

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


	Year Ended December 31
(in millions)	2023		2022		2021
Renewable generation revenues	$	164.9	$	101.0	$	60.3
We Power revenues	23.5		23.4		23.3
Appliance service revenues	19.6		18.7		17.8

Other	0.1		0.1		0.1
Total other non-utility operating revenues	$	208.1	$	143.2	$	101.5

Other Operating Revenues

Other operating revenues consist primarily of the following:


	Year Ended December 31
(in millions)	2023		2022		2021
Late payment charges	$	56.5	$	55.6	$	54.9
Alternative revenues (1)	47.0		(30.3)		21.2
Other	4.2		4.0		4.2
Total other operating revenues	$	107.7	$	29.3	$	80.3

(1) Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to decoupling mechanisms, wholesale true-ups, and conservation improvement rider true-ups.

- 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 9
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-9

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

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
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-Name Accounting Standards Codification
-Section 50
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-URI https://asc.fasb.org//1943274/2147479806/606-10-50-15

Reference 4: 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 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
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-Section 50
-Paragraph 12
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Reference 6: 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 7: 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 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
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-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (e)
-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 13
-Subparagraph (b)(2)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-13

Reference 10: 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, 2023

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, 2023 and 2022, 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, 2023
Accounts receivable and unbilled revenues	$	1,078.0		$	481.5		$	94.9		$	1,654.4		$	33.9		$	8.4		$	1,696.7
Allowance for credit losses	77.4			109.7			6.4			193.5			—			—			193.5
Accounts receivable and unbilled revenues, net (1)	$	1,000.6		$	371.8		$	88.5		$	1,460.9		$	33.9		$	8.4		$	1,503.2

Total accounts receivable, net – past due greater than 90 days (1)	$	51.7		$	45.0		$	2.1		$	98.8		$	—		$	—		$	98.8
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	93.6		%	100.0		%	—		%	94.5		%	—		%	—		%	94.5		%


(in millions)	Wisconsin			Illinois			Other States			Total Utility Operations			Non-Utility Energy Infrastructure			Corporate and Other			WEC Energy Group Consolidated
December 31, 2022
Accounts receivable and unbilled revenues	$	1,199.4		$	624.2		$	164.4		$	1,988.0		$	25.4		$	4.3		$	2,017.7
Allowance for credit losses	82.0			111.0			6.3			199.3			—			—			199.3
Accounts receivable and unbilled revenues, net (1)	$	1,117.4		$	513.2		$	158.1		$	1,788.7		$	25.4		$	4.3		$	1,818.4

Total accounts receivable, net – past due greater than 90 days (1)	$	51.9		$	52.9		$	1.9		$	106.7		$	—		$	—		$	106.7
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	97.0		%	100.0		%	—		%	96.8		%	—		%	—		%	96.8		%

(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, 2023, $914.6 million, or 60.8%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses.

A rollforward of the allowance for credit losses by reportable segment for the years ended December 31, 2023, 2022, and 2021, is included below:


(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. After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance.


(in millions)	Wisconsin		Illinois		Other States		WEC Energy Group Consolidated
Balance at January 1, 2022	$	84.0	$	105.5	$	8.8	$	198.3
Provision for credit losses	50.5		33.0		2.6		86.1
Provision for credit losses deferred for future recovery or refund	29.7		33.2		—		62.9
Write-offs charged against the allowance	(117.0)		(82.6)		(6.4)		(206.0)
Recoveries of amounts previously written off	34.8		21.9		1.3		58.0
Balance at December 31, 2022	$	82.0	$	111.0	$	6.3	$	199.3

On a consolidated basis, there was a $1.0 million increase in the allowance for credit losses during the year ended December 31, 2022. We believe that the high energy costs that customers were seeing, which were driven by high natural gas prices, contributed to higher past due accounts receivable balances and a related increase in the allowance for credit losses. The increase was substantially offset by customer write-offs related to collection practices returning to pre-pandemic levels, including the restoration of our ability to disconnect customers.


(in millions)	Wisconsin		Illinois		Other States		WEC Energy Group Consolidated
Balance at January 1, 2021	$	102.1	$	111.6	$	6.4	$	220.1
Provision for credit losses	46.4		25.6		3.7		75.7
Provision for credit losses deferred for future recovery or refund	(16.6)		3.5		—		(13.1)
Write-offs charged against the allowance	(74.8)		(52.5)		(2.5)		(129.8)
Recoveries of amounts previously written off	26.9		17.3		1.2		45.4
Balance at December 31, 2021	$	84.0	$	105.5	$	8.8	$	198.3

The allowance for credit losses decreased during the year ended December 31, 2021, primarily related to normal collection practices resuming in April 2021 for our Wisconsin utilities and in June 2021 for our Illinois utilities. Across all of our reportable segments, higher year-over-year natural gas prices drove an increase in gross accounts receivable balances, partially offsetting the decrease in the allowance for credit losses attributed to collection efforts.

- 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, 2023

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)	2023		2022		See Note
Regulatory assets (1) (2)
Pension and OPEB costs (3)	$	731.7	$	714.3	20, 26
Plant retirement related items	646.2		688.6
Environmental remediation costs (4)	596.8		610.7		24
Income tax related items	449.9		461.9		16
AROs	162.0		169.7		1(l), 9
Derivatives	130.3		133.8		1(s)
Uncollectible expense	127.7		69.3		5
SSR (5)	113.2		123.5
Securitization	85.9		92.4		23
Bluewater (6)	45.3		20.9
Energy efficiency programs (7)	33.9		33.9
Energy costs recoverable through rate adjustments	3.2		26.9		1(d)
MERC extraordinary natural gas costs (8)	0.8		35.1		26
Other, net	147.8		125.9
Total regulatory assets	$	3,274.7	$	3,306.9

Balance sheet presentation
Other current assets	$	24.9	$	42.3
Regulatory assets	3,249.8		3,264.6
Total regulatory assets	$	3,274.7	$	3,306.9

(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 $26.7 million and $27.3 million at December 31, 2023 and 2022, respectively.

(2) As of December 31, 2023, we had $254.6 million of regulatory assets not earning a return, $5.4 million of regulatory assets earning a return based on short-term interest rates, $129.7 million of regulatory assets earning a return based on long-term interest rates, and $2.5 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, uncollectible expense, our invested capital tax rider, decoupling mechanisms, unamortized loss on reacquired debt, and rate case costs. 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 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.

(4) As of December 31, 2023, we had made cash expenditures of $133.1 million related to these environmental remediation costs. The remaining $463.7 million represents our estimated future cash expenditures.

(5) 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.

(6) 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.

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

(8) Represents the extraordinary natural gas costs MERC incurred during February 2021 that were substantially recovered over 27 months, beginning in September 2021. See Note 26, Regulatory Environment, for more information on our recovery efforts associated with these costs.

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


(in millions)	2023		2022		See Note
Regulatory liabilities
Income tax related items	$	1,901.8	$	1,956.6	16
Removal costs (1)	1,329.9		1,260.9
Pension and OPEB benefits (2)	299.2		340.5		20, 26
Energy costs refundable through rate adjustments	72.4		53.4		1(d)
Electric transmission costs (3)	30.3		0.4
Uncollectible expense	21.2		24.0		5
Derivatives	19.2		76.7		1(s)
Energy efficiency programs (4)	17.2		10.4
Decoupling	—		20.2		1(d)
Other, net	54.0		48.8
Total regulatory liabilities	$	3,745.2	$	3,791.9

Balance sheet presentation
Other current liabilities	$	47.5	$	56.4
Regulatory liabilities	3,697.7		3,735.5
Total regulatory liabilities	$	3,745.2	$	3,791.9

(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) 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.

(4) Represents amounts refundable to customers related to programs at the utilities designed to meet energy efficiency standards.

Pleasant Prairie Power Plant

The Pleasant Prairie power plant was retired on April 10, 2018. The net book value of this plant was $542.4 million at December 31, 2023, representing book value less cost of removal and accumulated depreciation. In addition, previously deferred unprotected tax benefits from the Tax Legislation related to the unrecovered balance of this plant were $16.4 million as of December 31, 2023. The net amount of $526.0 million was classified as a regulatory asset on our balance sheet at December 31, 2023 due to the retirement of the plant. This regulatory asset does not include certain other previously recorded deferred tax liabilities of $147.8 million related to the retired Pleasant Prairie power plant. Pursuant to its rate order issued by the PSCW in December 2019, WE will continue to amortize this regulatory asset on a straight-line basis through 2039, using the composite depreciation rates approved by the PSCW before this plant was retired. The amortization is included in depreciation and amortization in the income statement. WE also has FERC approval to continue to collect the net book value of the Pleasant Prairie power plant using the approved composite depreciation rates, in addition to a return on the remaining net book value.

WE received approval from the PSCW in December 2019 to collect a full return of the net book value of the Pleasant Prairie power plant and a return on all but $100 million of the net book value. During May 2021, WE securitized the remaining $100 million of the Pleasant Prairie power plant's book value, the carrying costs accrued on the $100 million during the securitization process, and the related financing fees, in accordance with a written order issued by the PSCW in November 2020. See Note 23, Variable Interest Entities, for more information on this securitization.

Presque Isle Power Plant

Pursuant to MISO's April 2018 approval of the retirement of the PIPP, these units were retired on March 31, 2019. The net book value of the PIPP was $152.9 million at December 31, 2023, representing book value less cost of removal and accumulated depreciation. In addition, previously deferred unprotected tax benefits from the Tax Legislation related to the unrecovered balance

of these units were $4.8 million as of December 31, 2023. The net amount of $148.1 million was classified as a regulatory asset on our balance sheet at December 31, 2023 as a result of the retirement of the plant. This regulatory asset does not include certain other previously recorded deferred tax liabilities of $41.5 million related to the retired PIPP. After the retirement of the PIPP, a portion of the regulatory asset and related cost of removal reserve was transferred to UMERC for recovery from its retail customers. Effective with its rate order issued by the PSCW in December 2019, WE received approval to collect a return of and on its share of the net book value of the PIPP and, as a result, will continue to amortize the regulatory assets on a straight-line basis through 2037, using the composite depreciation rates approved by the PSCW before the units were retired. UMERC will also continue to amortize the regulatory assets on a straight-line basis using the composite depreciation rates approved by the PSCW before the units were retired. This amortization is included in depreciation and amortization in the income statement. UMERC will address the accounting and regulatory treatment related to the retirement of the PIPP with the MPSC in conjunction with a future rate case. WE also has FERC approval to continue to collect the net book value of the PIPP using the approved composite depreciation rates, in addition to a return on the net book value.

Pulliam Power Plant

In connection with a MISO ruling, WPS retired Pulliam Units 7 and 8 on October 21, 2018. The net book value of the Pulliam units was $33.0 million at December 31, 2023, representing book value less cost of removal and accumulated depreciation. This amount was classified as a regulatory asset on our balance sheet at December 31, 2023 as a result of the retirement of the plant. Effective with its rate order issued by the PSCW in December 2019, WPS received approval to collect a return of and on the entire net book value of the Pulliam units and, as a result, will continue to amortize this regulatory asset on a straight-line basis through 2031, using the composite depreciation rates approved by the PSCW before these generating units were retired. The amortization is included in depreciation and amortization in the income statement. WPS also has FERC approval to continue to collect the net book value of the Pulliam power plant using the approved composite depreciation rates, in addition to a return on the remaining net book value.

Edgewater Unit 4

The Edgewater 4 generating unit was retired on September 28, 2018. The net book value of the generating unit was $2.1 million at December 31, 2023, representing book value less cost of removal and accumulated depreciation. This amount was classified as a regulatory asset on our balance sheet at December 31, 2023 as a result of the retirement of the plant. Effective with its rate order issued by the PSCW in December 2019, WPS received approval to collect a return of and on the entire net book value of the Edgewater 4 generating unit and, as a result, will continue to amortize this regulatory asset on a straight-line basis through 2026, using the composite depreciation rates approved by the PSCW before this generating unit was retired. The amortization is included in depreciation and amortization in the income statement. WPS also has FERC approval to continue to collect the net book value of the Edgewater 4 generating unit 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, 2023

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)	2023		2022
Electric – generation	$	6,190.4	$	5,480.5
Electric – distribution	8,688.0		8,233.3
Natural gas – distribution, storage, and transmission	14,851.3		14,203.3
Property, plant, and equipment to be retired, net	1,043.5		1,085.6
Other	2,350.0		2,302.7
Less: Accumulated depreciation	8,907.9		8,416.2
Net	24,215.3		22,889.2
CWIP	1,118.3		972.1
Net utility and non-utility property, plant, and equipment	25,333.6		23,861.3

We Power generation	3,295.9		3,237.1
Renewable generation	3,667.7		2,537.1
Natural gas storage	291.6		292.2
Net non-utility energy infrastructure	7,255.2		6,066.4
Corporate services	169.8		163.0
Other	14.3		23.8
Less: Accumulated depreciation	1,227.5		1,082.3
Net	6,211.8		5,170.9
CWIP	36.1		81.6
Net other property, plant, and equipment	6,247.9		5,252.5

Total property, plant, and equipment	$	31,581.5	$	29,113.8

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)	2023		2022		2021
Severance liability at January 1	$	16.2	$	4.9	$	0.7
Severance expense	1.6		11.3		4.6
Severance payments	—		—		(0.4)

Total severance liability at December 31	$	17.8	$	16.2	$	4.9

Wisconsin Segment Plant to be Retired

Oak Creek Power Plant Units 5-8

As a result of a PSCW approval in December 2022 for the acquisition and construction of Darien, the retirement of OCPP Units 5-8 became probable. In early 2023, we received additional approvals for electric generation facilities, including Koshkonong and 100 MWs of West Riverside. See Note 2, Acquisitions, for more information on the West Riverside acquisition, which was completed in June 2023. OCPP Units 5 and 6 are expected to be retired by May 2024, while OCPP Units 7 and 8 are expected to be retired by late 2025. The total net book value of WE's ownership share of OCPP Units 5-8 was $783.7 million at December 31, 2023, 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 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. Columbia Units 1 and 2 are expected to be retired by June 2026. The total net book value of WPS's ownership share of Columbia

Units 1 and 2 was $259.8 million at December 31, 2023, 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 WPS continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

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

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 of our property, plant, and equipment in 2023. We anticipate appealing the ICC’s disallowance of these capital costs to the Illinois circuit court. See Note 26, Regulatory Environment, for more information.

Samson I Solar Energy Center LLC – Storm Damage

During wind storms in March and June 2023, certain sections of our Samson I solar facility incurred damage. As of December 31, 2023, we recognized an impairment of $2.3 million related to storm damage, which was offset by a $2.3 million receivable for future insurance recoveries. Although we may experience differences between periods in the timing of cash flows, we do not currently expect a significant impact to our long-term cash flows from this event.

Public Service Building and Steam Tunnel Assets

During a significant rain event in May 2020, an underground steam tunnel in downtown Milwaukee flooded and steam vented into WE’s PSB. The damage to the building and adjacent steam tunnel assets from the flooding and steam was extensive and required significant repairs and restorations. As of December 31, 2023, WE had incurred $95.3 million of costs related to these repairs and restorations. In June 2021, we received approval from the PSCW to restore the PSB and adjacent steam tunnel assets and to defer the project costs, net of insurance proceeds, as a component of rate base. As a result, we do not currently expect a significant impact to our future results of operations.

Jointly Owned Utility Facilities

12 Months Ended

Dec. 31, 2023

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 at December 31, 2023 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	%	1,082.1	2010 & 2011	WE	$	2,487.4	$	(520.0)	$	6.2
WPS	Weston Unit 4 (2)	70.0	%	384.8	2008	WPS	613.3		(227.3)		0.5
WPS	Columbia Energy Center Units 1 and 2 (2) (5)	27.5	%	312.3	1975 & 1978	WPL	433.1		(173.8)		3.5
WPS	Forward Wind (3)	44.6	%	61.5	2008	WPS	119.3		(56.8)		—
WPS	Two Creeks (4)	66.7	%	100.0	2020	WPS	136.9		(14.1)		—
WPS	Badger Hollow I (4)	66.7	%	100.0	2021	WPS	146.2		(9.7)		0.1
WPS	Red Barn (3)	90.0	%	82.4	2023	WPS	150.0		(3.2)		—
WE	West Riverside (2) (6)	13.8	%	84.9	2023	WE	108.7		(11.3)		0.9
WE	Badger Hollow II (4)	66.7	%	100.0	2023	WE	170.1		(0.3)		0.1

(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 2024 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) These units are expected to be retired by June 2026. See Note 7, Property, Plant, and Equipment, for more information.

(6 WE acquired its ownership interest in June 2023. In September 2023, WPS filed a request with the PSCW to exercise a second option to acquire an additional 100 MWs of West Riverside's nameplate capacity. WPS subsequently filed for approval to assign its ownership interest pursuant to this second option to WE. See Note 2, Acquisitions, for more information.

WE and WPS, along with an unaffiliated utility, received PSCW approval to construct Koshkonong, a utility-scale solar-powered electric generating facility. The project will be located in Dane County, Wisconsin and once fully constructed, WE and WPS will collectively own 90%, or 270 MWs of solar generation of this project. Commercial operation of the solar facility is targeted for 2026. Our CWIP balance for Koshkonong was not significant as of December 31, 2023.

WE and WPS, along with an unaffiliated utility, received PSCW approval to construct Paris, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Kenosha County, Wisconsin and once fully constructed, WE and WPS will collectively own 90%, or 180 MWs of solar generation and 99 MWs of battery storage of this project. Commercial operation of the solar facility is targeted for 2024 and construction of the battery storage is expected to be completed in 2025. Our CWIP balance for Paris was $334.3 million as of December 31, 2023.

WE and WPS, along with an unaffiliated utility, received PSCW approval to construct Darien, a utility-scale solar-powered electric generating facility. The project will be located in Rock and Walworth counties, Wisconsin and once constructed, WE and WPS will collectively own 90%, or 225 MWs of solar generation of this project. Commercial operation of the solar facility is targeted for 2024. Our CWIP balance for Darien was $220.4 million as of December 31, 2023.

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2023

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 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)	2023			2022			2021
Balance as of January 1	$	479.3		$	462.0		$	513.5
Accretion	17.2			16.1			21.2
Additions	24.0		(1)	12.8		(3)	31.0		(4)
Revisions to estimated cash flows	(133.5)		(2)	2.2			(84.9)		(5)
Liabilities settled	(12.8)			(13.8)			(18.8)
Balance as of December 31	$	374.2		$	479.3		$	462.0

(1) AROs increased primarily as a result of AROs being recorded for the legal requirement to dismantle, at retirement, the Red Barn wind-powered generation project, the Badger Hollow II solar generation project, and the Sapphire Sky and Samson I non-utility renewable generation projects.

(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.

(3) AROs increased primarily as a result of an ARO being recorded for the legal requirement to dismantle, at retirement, the Thunderhead non-utility wind generation project.

(4) AROs increased as a result of AROs being recorded for the legal requirement to dismantle, at retirement, the Badger Hollow I solar generation project and the Tatanka Ridge and Jayhawk non-utility renewable generation projects.

(5) AROs decreased due to revisions made to estimated cash flows primarily for changes in the cost to retire natural gas distribution lines at PGL and NSG. Partially offsetting this decrease were revisions made to removal estimates for wind generation projects at WE and WPS and for fly ash landfills and ash ponds at WPS.

Goodwill and Intangibles

12 Months Ended

Dec. 31, 2023

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, 2023. We had no changes to the carrying amount of goodwill during the years ended December 31, 2023 and 2022.


(in millions)	Wisconsin		Illinois		Other States		Non-Utility Energy Infrastructure		Total
Goodwill balance (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, 2023.

During the third quarter of 2023, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of July 1, 2023. No impairments resulted from these tests.

Intangible Assets

At December 31, 2023 and 2022, we had $29.3 million and $24.9 million, respectively, of indefinite-lived intangible assets, largely consisting of spectrum frequencies. During 2023, we purchased additional spectrum frequencies for $4.4 million. The spectrum frequencies enable the 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. These indefinite-lived intangible assets are included in other long-term assets on our balance sheets.

Intangible Liabilities

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


	December 31, 2023						December 31, 2022
(in millions)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
PPAs (1)	$	653.9	$	(66.6)	$	587.3	$	343.9	$	(16.9)	$	327.0
Proxy revenue swap (2)	7.2		(3.5)		3.7		7.2		(2.8)		4.4
Interconnection agreements (3)	4.7		(0.9)		3.8		4.7		(0.7)		4.0
Total intangible liabilities	$	665.8	$	(71.0)	$	594.8	$	355.8	$	(20.4)	$	335.4

(1) Represents PPAs related to the acquisition of Blooming Grove, Tatanka Ridge, Jayhawk, Thunderhead, Samson I, and Sapphire Sky expiring between 2030 and 2037. The weighted-average remaining useful life of the PPAs is 11 years. See Note 2, Acquisitions, for more information on the acquisitions of Samson I and Sapphire Sky in 2023.

(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 five 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 17 years.

Amortization related to these intangible liabilities for the years ended December 31, 2023, 2022, and 2021 was $50.6 million, $11.3 million, and $7.5 million, respectively. Amortization for the next five years is estimated to be:


	For the Years Ending December 31
(in millions)	2024		2025		2026		2027		2028
Amortization to be recorded as an increase to operating revenues	$	53.4	$	53.4	$	53.4	$	53.4	$	53.4
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, 2023

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)	2023			2022		2021
Stock options	$	5.3		$	6.5	$	6.5
Restricted stock	6.6			7.0		6.1
Performance units	(2.2)		(1)	21.3		3.1
Stock-based compensation expense	$	9.7		$	34.8	$	15.7
Related tax benefit	$	2.7		$	9.6	$	4.3

(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 2023, 2022, and 2021 were not significant.

Stock Options

The following is a summary of our stock option activity during 2023:


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, 2023	2,909,939	$	77.03
Granted	257,780	93.69
Exercised	(129,743)	48.44
Forfeited	(17,053)	93.34
Expired	(5,172)	91.49
Outstanding as of December 31, 2023	3,015,751	79.57		5.7	$	28.7
Exercisable as of December 31, 2023	2,052,968	73.03		4.6	$	28.7

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, 2023. This is calculated as the difference between our closing stock price on December 31, 2023, 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, 2023, 2022, and 2021 was $5.2 million, $29.2 million, and $12.9 million, respectively. The actual tax benefit from option exercises for the same years was approximately $1.4 million, $8.0 million, and $3.5 million, respectively.

As of December 31, 2023, approximately $1.7 million of unrecognized compensation cost related to unvested and outstanding stock options was expected to be recognized over the next 1.5 years on a weighted-average basis.

During the first quarter of 2024, the Compensation Committee awarded 283,869 non-qualified stock options with a weighted-average exercise price of $85.05 and a weighted-average grant date fair value of $16.20 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 2023:


Restricted Shares	Number of Shares	Weighted-Average Grant Date Fair Value
Outstanding and unvested as of January 1, 2023	89,885	$	94.73
Granted	75,453	93.69
Released	(61,782)	94.75
Forfeited	(3,158)	94.08
Outstanding and unvested as of December 31, 2023	100,398	93.95

The intrinsic value of restricted stock released was $5.8 million, $7.5 million, and $6.5 million for the years ended December 31, 2023, 2022, and 2021, respectively. The actual tax benefit from released restricted shares for the same years was $1.6 million, $2.1 million, and $1.8 million, respectively.

As of December 31, 2023, approximately $2.9 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 2024, the Compensation Committee awarded 105,778 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 $85.05 per share.

Performance Units

During 2023, 2022, and 2021, the Compensation Committee awarded 157,035; 171,492; and 152,382 performance units, respectively, to officers and other key employees under the WEC Energy Group Performance Unit Plan.

Performance units with an intrinsic value of $10.2 million, $20.2 million, and $27.7 million were settled during 2023, 2022, and 2021, respectively. The actual tax benefit from the distribution of performance units for the same years was $2.6 million, $5.1 million, and $6.8 million, respectively.

At December 31, 2023, we had 412,448 performance units outstanding, including dividend equivalents. A liability of $10.0 million was recorded on our balance sheet at December 31, 2023 related to these outstanding units. As of December 31, 2023, approximately $12.8 million of unrecognized compensation cost related to unvested and outstanding performance units was expected to be recognized over the next 1.9 years on a weighted-average basis.

During the first quarter of 2024, we settled performance units with an intrinsic value of $1.0 million. The actual tax benefit from the distribution of these awards was $0.2 million. In January 2024, the Compensation Committee also awarded 196,256 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.

WECI Wind Holding I's and WECI Wind Holding II's long-term debt obligations 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 for the 12-month period prior to the distribution.

WEC Energy Group has the option to defer interest payments on its 2007 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, 2023, restricted net assets of our consolidated subsidiaries totaled approximately $11.4 billion. Our equity in undistributed earnings of investees accounted for by the equity method was approximately $525 million.

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

Share Purchases

During the years ended December 31, 2023, 2022, and 2021, we instructed our independent agents to purchase shares on the open market to fulfill obligations under various stock-based employee benefit and compensations plans and to provide shares to participants in our dividend reinvestment and stock purchase plan. As a result, no new shares of common stock were issued during these years. As of January 1, 2024, we began issuing new shares of common stock to fulfill our obligations under these plans.

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)	2023		2022		2021
Shares purchased	0.2		0.7		0.4
Cost of shares purchased	$	16.6	$	69.2	$	33.1

Common Stock Dividends

During the year ended December 31, 2023, our Board of Directors declared common stock dividends which are summarized below:

Date Declared

Date Payable

Per Share

Period

January 19, 2023

March 1, 2023

$0.78

First quarter

April 20, 2023

June 1, 2023

$0.78

Second quarter

July 20, 2023

September 1, 2023

$0.78

Third quarter

October 19, 2023

December 1, 2023

$0.78

Fourth quarter

On January 18, 2024, our Board of Directors declared a quarterly cash dividend of $0.835 per share, which equates to an annual dividend of $3.34 per share. The dividend is payable on March 1, 2024, to shareholders of record on February 14, 2024. In addition, the Board of Directors affirmed our dividend policy that continues to target a dividend payout ratio of 65-70% of earnings.

Preferred Stock

12 Months Ended

Dec. 31, 2023

Class of Stock Disclosures [Abstract]

PREFERRED STOCK

The following table shows preferred stock authorized and outstanding at December 31, 2023 and 2022:


(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, 2023

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)	2023			2022
Commercial paper
Amount outstanding at December 31	$	2,017.2		$	1,643.5
Average interest rate on amounts outstanding at December 31	5.49		%	4.64		%



Operating expense loans
Amount outstanding at December 31 (1)	$	3.7		$	3.6

(1) Coyote Ridge, Tatanka Ridge, 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 2023, was $1,196.8 million with a weighted-average interest rate during the period of 5.29%.

WEC Energy Group, WE, WPS, WG, and PGL 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, 2023, 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	2023
Revolving credit facility (WEC Energy Group) (1)	September 2026	$	1,500.0
Revolving credit facility (WEC Energy Group)	October 2024	200.0
Revolving credit facility (WE) (1)	September 2026	500.0
Revolving credit facility (WPS) (1)	September 2026	400.0
Revolving credit facility (WG) (1)	September 2026	350.0
Revolving credit facility (PGL) (1)	September 2026	350.0
Total short-term credit capacity		$	3,300.0

Less:
Letters of credit issued inside credit facilities		$	2.3
Commercial paper outstanding		2,017.2
Available capacity under existing facilities		$	1,280.5

(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.

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, 2023

Debt Disclosure [Abstract]

LONG-TERM DEBT

The following table is a summary of our long-term debt outstanding (excluding finance leases) as of December 31:


	2023					2022
(in millions)	Maturity Date	Weighted Average Interest Rate		Balance		Weighted Average Interest Rate		Balance
WEC Energy Group Senior Notes (unsecured) (1)	2024-2033	3.68	%	$	5,320.0	2.44	%	$	3,970.0
WEC Energy Group Junior Notes (unsecured) (1) (2)	2067	7.75	%	500.0		6.72	%	500.0
WE Debentures (unsecured)	2024-2095	4.22	%	3,285.0		4.22	%	3,285.0
WEPCo Environmental Trust (secured, nonrecourse) (5) (9)	2024-2035	1.58	%	97.0		1.58	%	105.9
WPS Senior Notes (unsecured)	2025-2051	4.11	%	1,975.0		4.11	%	1,975.0
WG Debentures (unsecured)	2024-2046	3.35	%	790.0		3.35	%	790.0
Integrys Junior Notes (unsecured)	2073	—	%	—		6.00	%	221.4
PGL First and Refunding Mortgage Bonds (secured) (3)	2024-2047	3.53	%	2,070.0		3.41	%	1,970.0
NSG First Mortgage Bonds (secured) (4)	2027-2043	3.81	%	177.0		3.56	%	157.0
MERC Senior Notes (unsecured)	2025-2047	3.04	%	210.0		3.04	%	210.0
MGU Senior Notes (unsecured)	2025-2047	3.18	%	150.0		3.18	%	150.0
UMERC Senior Notes (unsecured)	2029	3.26	%	160.0		3.26	%	160.0
Bluewater Gas Storage Senior Notes (unsecured) (5)	2024-2047	3.76	%	109.8		3.76	%	112.6
ATC Holding Senior Notes (unsecured)	2025-2030	4.05	%	475.0		4.05	%	475.0
We Power Subsidiaries Notes (secured, nonrecourse) (5) (6)	2024-2041	5.65	%	856.4		5.62	%	896.5
WECC Notes (unsecured)	2028	6.94	%	50.0		6.94	%	50.0
WECI Wind Holding I Senior Notes (secured, nonrecourse) (5) (7)	2024-2032	2.75	%	307.7		2.75	%	332.1
WECI Wind Holding II Senior Notes (secured, nonrecourse) (5) (8)	2024-2031	6.38	%	191.4		6.38	%	199.3
Total				16,724.3				15,559.8
Integrys acquisition fair value adjustment				—				1.2
Jayhawk acquisition				7.5				7.3
Unamortized debt issuance costs				(80.2)				(81.8)
Unamortized discount, net and other				(20.5)				(22.3)
Total long-term debt, including current portion (10)				16,631.1				15,464.2
Current portion of long-term debt				(1,264.2)				(808.5)
Total long-term debt				$	15,366.9			$	14,655.7

(1) In connection with our outstanding 2007 Junior Notes, we executed an RCC, which we amended on June 29, 2015, for the benefit of persons that buy, hold, or sell a specified series of our long-term indebtedness (covered debt). Our 6.20% Senior Notes due April 1, 2033 have been designated as the covered debt under the RCC. The RCC provides that we may not redeem, defease, or purchase, and that our subsidiaries may not purchase, any 2007 Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, we have received a specified amount of proceeds from the sale of qualifying securities. The terms of the RCC have been previously satisfied.

(2) Variable interest rates reset quarterly. The rates were 7.75% and 6.72% as of December 31, 2023 and 2022, respectively.

(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, 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) 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.

(10) The amount of long-term debt on our balance sheets includes finance lease obligations of $145.9 million and $183.2 million at December 31, 2023 and 2022, respectively.

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

In March 2022, President Biden signed into law the Adjustable Interest Rate (LIBOR) Act. This Act established a uniform process, on a nationwide basis, for replacing LIBOR in certain contracts that did not provide a clearly defined or practicable replacement benchmark rate. Under the LIBOR Act, the Federal Reserve Board was required to determine an appropriate benchmark replacement based on SOFR, with applicable credit spread adjustments. In December 2022, the Federal Reserve Board adopted the final rule to implement the LIBOR Act and established the SOFR-based benchmark replacements. No contract modifications were required for qualifying contracts under the LIBOR Act as the benchmark replacement automatically overrode the existing contract language and became the applicable benchmark after June 30, 2023.

For our $500 million of 2007 Junior Notes, starting August 15, 2023, the benchmark replacement rate is the applicable tenor of three-month CME Term SOFR, as administered by the CME Group Benchmark Administration, and includes a credit spread adjustment of 0.26161% per annum. In accordance with the LIBOR Act, no contract modifications were required for our 2007 Junior Notes as the references to LIBOR were replaced by operation of law.

WEC Energy Group, Inc.

In January 2023, we issued $650.0 million of 4.75% Senior Notes due January 9, 2026, and $450.0 million of 4.75% Senior Notes due January 15, 2028, and used the net proceeds to repay short-term debt and for other corporate purposes.

In April 2023, we issued an additional $350.0 million of our 4.75% Senior Notes due January 9, 2026, and used the net proceeds to repay short-term debt and for other corporate purposes.

In September 2023, we issued $600.0 million of 5.60% Senior Notes due September 12, 2026, and used the net proceeds to repay short-term debt and for other corporate purposes. Subsequently, we repaid the outstanding principal and accrued interest on our $700.0 million of 0.55% Senior Notes that matured on September 15, 2023.

In January and February, 2024, pursuant to a tender offer, we purchased $122.1 million aggregate principal amount of the $500.0 million outstanding of our 2007 Junior Notes for $115.2 million with proceeds from issuing commercial paper. We recorded a $6.9 million gain related to the early settlement.

Integrys Holding, Inc.

In March 2023, Integrys repurchased $18.9 million of the $221.4 million outstanding of its 6.00% 2013 Junior Notes, prior to maturity for $18.6 million. Integrys recognized an insignificant gain on the early extinguishment of debt due to the debt being repurchased at a discount.

On August 1, 2023, Integrys redeemed the remaining $202.5 million outstanding of its 6.00% 2013 Junior Notes, prior to maturity at par value.

The Peoples Gas Light and Coke Company

In November 2023, PGL issued $100.0 million of 5.82% First and Refunding Mortgage Bonds, Series NNN due April 1, 2029, and used the net proceeds for general corporate purposes, including capital expenditures and the refinancing of short-term debt.

North Shore Gas Company

In November 2023, NSG issued $20.0 million of 5.82% First Mortgage Bonds, Series T due April 1, 2029, and used the net proceeds for general corporate purposes, including capital expenditures and the refinancing of short-term debt.

Maturities of Long-Term Debt Outstanding

The following table shows the long-term debt securities (excluding finance leases) maturing within one year of December 31, 2023:


(in millions)	Interest Rate	Maturity Date (1)	Principal Amount
WEC Energy Group Senior Notes (unsecured)	0.80%	March	$	600.0
WG Debentures (unsecured)	2.38%	November	150.0
PGL Bonds (secured)	2.64%	November	75.0
WE Debentures (unsecured)	2.05%	December	300.0
WEPCo Environmental Trust (secured, nonrecourse)	1.58%	Semi-annually	9.0
Bluewater Gas Storage Senior Notes (unsecured)	3.76%	Semi-annually	2.9
We Power Subsidiaries Notes – PWGS (secured, nonrecourse)	4.91%	Monthly	8.0
We Power Subsidiaries Notes – ERGS (secured, nonrecourse)	5.209%	Semi-annually	15.5
We Power Subsidiaries Notes – ERGS (secured, nonrecourse)	4.673%	Semi-annually	11.7
We Power Subsidiaries Notes – PWGS (secured, nonrecourse)	6.00%	Monthly	7.0
WECI Wind Holding I Senior Notes (secured, nonrecourse)	2.75%	Semi-annually	61.3
WECI Wind Holding II Senior Notes (secured, nonrecourse)	6.38%	Semi-annually	23.8
Total			$	1,264.2

(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 (excluding obligations under finance leases) as of December 31, 2023:


(in millions)	Payments
2024	$	1,264.2
2025	1,685.5
2026	1,726.8
2027	1,230.7
2028	2,307.2
Thereafter	8,509.9
Total	$	16,724.3

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, 2023

Leases [Abstract]

LEASES

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 2029.

•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 2073.

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

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

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 of approximately 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.

Power Purchase Commitment

In 1997, WE entered into a 25-year PPA with LSP-Whitewater Limited Partnership. The contract, for 236.5 MWs of firm capacity from a natural gas-fired cogeneration facility, included zero minimum energy requirements. The PPA expired on May 31, 2022; however, in November 2021, WE entered into a tolling agreement with LSP-Whitewater Limited Partnership that commenced on June 1, 2022. Concurrent with the execution of the tolling agreement, WE and WPS entered into an asset purchase agreement to acquire the natural gas-fired cogeneration facility and the acquisition closed effective January 1, 2023. See Note 2, Acquisitions, for more information. Both the PPA and the tolling agreement were accounted for as a finance lease prior to the acquisition.

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)	2023			2022			2021
Finance lease expense
Amortization of right of use assets (1)	$	—		$	6.0		$	8.1
Interest on lease liabilities (2)	0.8			0.9			1.6
Operating lease expense (3)	4.7			6.1			3.4
Short-term lease expense (3)	1.2			0.9			0.2
Total lease expense	$	6.7		$	13.9		$	13.3

Other information

Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from finance leases	$	0.8		$	0.9		$	1.6
Operating cash flows from operating leases	6.8			5.7			5.3
Financing cash flows from finance leases	—			6.0			8.1

Non-cash activities:
Right of use assets obtained in exchange for finance lease liabilities (4)	$	32.8		$	57.6		$	73.6
Right of use assets obtained in exchange for operating lease liabilities	18.3			—			0.5

Weighted-average remaining lease term – finance leases	49.4 years			30.0 years			20.5 years
Weighted-average remaining lease term – operating leases	22.4 years			12.0 years			12.5 years

Weighted-average discount rate – finance lease (5)	5.3		%	3.9		%	2.4		%
Weighted average discount rate – operating leases (5)	5.8		%	3.4		%	3.4		%

(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 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)	2023		2022		Balance Sheet Location
Right of use assets
Operating lease right of use assets, net	$	32.0	$	15.7	Other long-term assets

Finance lease right of use assets, net
Power purchase commitment (1)	$	—	$	71.8
Land leases – utility solar generation	132.7		102.4
Other	1.1		1.1
Total finance lease right of use assets, net (2)	$	133.8	$	175.3	Property, plant, and equipment, net

Lease obligations
Current operating lease liabilities	$	4.7	$	4.0	Other current liabilities

Long-term operating lease liabilities	$	38.8	$	25.4	Other long-term liabilities

Current finance lease liabilities
Power purchase commitment (1)	$	—	$	72.7	Current portion of long-term debt

Long-term finance lease liabilities
Land leases – utility solar generation	$	144.8	$	109.3
Other	1.1		1.2
Total long-term finance lease liabilities	$	145.9	$	110.5	Long-term debt

(1) Effective January 1, 2023, WE and WPS closed on the acquisition of Whitewater. See discussion above for more information.

(2) Amounts are net of accumulated amortization of $6.1 million and $146.3 million at December 31, 2023 and 2022, 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, 2023, were as follows:


(in millions)	Total Operating Leases		Land Leases - Utility Solar Generation		Other		Total Finance Leases
2024	$	6.4	$	4.7	$	0.1	$	4.8
2025	5.6		6.0		0.1		6.1
2026	5.8		6.1		0.1		6.2
2027	5.7		6.2		0.1		6.3
2028	5.5		6.4		0.1		6.5
Thereafter	71.0		465.8		2.5		468.3
Total minimum lease payments	100.0		495.2		3.0		498.2
Less: Interest	(56.5)		(350.4)		(1.9)		(352.3)
Present value of minimum lease payments	43.5		144.8		1.1		145.9
Less: Short-term lease liabilities	(4.7)		—		—		—
Long-term lease liabilities	$	38.8	$	144.8	$	1.1	$	145.9

As of February 22, 2024, we have not entered into any material leases that have not yet commenced.

Income Taxes

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

Income Tax Disclosure

INCOME TAXES

Income Tax Expense

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


(in millions)	2023		2022		2021
Current tax expense (benefit)	$	(14.8)	$	50.2	$	93.9
Deferred income taxes, net	229.9		278.5		111.0
ITCs	(10.5)		(5.8)		(4.6)
Total income tax expense	$	204.6	$	322.9	$	200.3

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:


	2023				2022				2021
			Effective				Effective				Effective
(in millions)	Amount		Tax Rate		Amount		Tax Rate		Amount		Tax Rate
Statutory federal income tax	$	322.6	21.0	%	$	363.5	21.0	%	$	315.1	21.0	%
State income taxes net of federal tax benefit	94.3		6.1	%	109.7		6.3	%	96.1		6.4	%
PTCs, net	(168.2)		(10.9)	%	(107.6)		(6.2)	%	(81.3)		(5.4)	%
Federal excess deferred tax amortization (1)	(37.6)		(2.4)	%	(36.9)		(2.1)	%	(37.3)		(2.5)	%
AFUDC-Equity	(12.4)		(0.8)	%	(6.2)		(0.4)	%	(3.8)		(0.3)	%

Federal excess deferred tax amortization – Wisconsin unprotected (2)	(0.8)		(0.1)	%	(0.8)		—	%	(77.9)		(5.2)	%
Other, net	6.7		0.4	%	1.2		—	%	(10.6)		(0.6)	%
Total income tax expense	$	204.6	13.3	%	$	322.9	18.6	%	$	200.3	13.4	%

(1) The Tax Legislation required our regulated utilities to remeasure their deferred income taxes and we began to amortize the resulting excess protected 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.

(2) In accordance with the rate order received from the PSCW in December 2019, our Wisconsin utilities amortized these unprotected deferred tax benefits over periods ranging from two years to four years, to reduce near-term rate impacts to their customers. 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.

See Note 26, Regulatory Environment, for more information about the impact of the Tax Legislation and the Wisconsin rate orders.

Deferred Income Tax Assets and Liabilities

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


(in millions)	2023		2022
Deferred tax assets
Tax gross up – regulatory items	$	438.6	$	459.0
Future tax benefits	160.7		187.7
Deferred revenues	84.7		86.8
Other	168.3		190.2
Total deferred tax assets	852.3		923.7
Valuation allowance	(5.0)		(1.2)
Net deferred tax assets	$	847.3	$	922.5

Deferred tax liabilities
Property-related	$	4,198.0	$	4,072.5
Investment in affiliates	915.1		839.7
Employee benefits and compensation	227.2		219.5
Deferred costs – plant retirements	199.6		212.8
Other	225.9		203.6
Total deferred tax liabilities	5,765.8		5,548.1
Deferred tax liability, net	$	4,918.5	$	4,625.6

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, 2023 and 2022 are summarized in the tables below:


2023 (in millions)	Gross Value		Deferred Tax Effect		Valuation Allowance		Earliest Year of Expiration
Future tax benefits as of December 31, 2023
Federal tax credit	$	—	$	153.0	$	—	2042
State net operating loss	62.6		3.8		(1.1)		2032
Other state benefits	—		3.9		(3.9)		2024
Balance as of December 31, 2023	$	62.6	$	160.7	$	(5.0)


2022 (in millions)	Gross Value		Deferred Tax Effect		Valuation Allowance		Earliest Year of Expiration
Future tax benefits as of December 31, 2022
Federal tax credit	$	—	$	176.4	$	—	2041
State net operating loss	72.6		4.5		(1.2)		2032
Other state benefits	—		6.8		—		2023
Balance as of December 31, 2022	$	72.6	$	187.7	$	(1.2)

Unrecognized Tax Benefits

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


(in millions)	2023		2022		2021
Balance as of January 1	$	6.3	$	6.8	$	11.9
Additions for tax positions of prior years	0.2		0.3		—
Additions based on tax positions related to the current year	—		0.4		1.6
Reductions for tax positions of prior years	(1.9)		(1.2)		(6.7)



Balance as of December 31	$	4.6	$	6.3	$	6.8

The amount of unrecognized tax benefits as of December 31, 2023 and 2022, excludes deferred tax assets related to uncertainty in income taxes of $1.1 million and $1.3 million, respectively. As of December 31, 2023 and 2022, the net amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations was $3.6 million and $5.1 million, respectively.

Interest accrued related to unrecognized tax benefits is as follows:


(in millions)	2023		2022		2021
Balance as of January 1	$	0.5	$	0.1	$	0.5
Interest expense (income) related to unrecognized tax benefits	0.1		0.4		(0.4)
Balance as of December 31	$	0.6	$	0.5	$	0.1

For the years ended December 31, 2023, 2022, and 2021, we recognized no penalties related to unrecognized tax benefits in our consolidated income statements. At December 31, 2023 and 2022, we had no amounts accrued for penalties related to unrecognized tax benefits.

Although analysis of our unrecognized tax benefits is ongoing, the potential estimated decrease in the total amounts of unrecognized tax benefits within the next 12 months is approximately $0.6 million associated with statutes of limitations on certain tax years. We do not anticipate any significant increases in the total amounts of unrecognized tax benefits within the next 12 months.

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, 2023, with a few exceptions, we were subject to examination by federal and state or local tax authorities for the 2019 through 2023 tax years in our major operating jurisdictions as follows:


Jurisdiction						Years
Federal						2020–2023
Illinois						2019–2023
Michigan						2019–2023
Minnesota						2019–2023
Wisconsin						2019–2023

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480990/946-20-50-13

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(h)(2))
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480678/235-10-S99-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org//740/tableOfContent

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 14
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482685/740-10-50-14

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482685/740-10-50-21

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 270
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
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-URI https://asc.fasb.org//1943274/2147482526/740-270-50-1

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 17
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482685/740-10-50-17

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SAB TOPIC 6.I.5.Q1)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479360/740-10-S99-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Subparagraph (SAB Topic 11.C)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479360/740-10-S99-2

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482603/740-30-50-2

+ Details

Fair Value Measurements

12 Months Ended

Dec. 31, 2023

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, 2023
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	2.2	$	8.3	$	—	$	10.5
FTRs and TCRs	—		—		7.2		7.2
Coal contracts	—		0.3		—		0.3
Total derivative assets	$	2.2	$	8.6	$	7.2	$	18.0

Investments held in rabbi trust	$	51.7	$	—	$	—	$	51.7

Derivative liabilities
Natural gas contracts	$	70.1	$	16.0	$	—	$	86.1
Coal contracts	—		20.3		—		20.3
Total derivative liabilities	$	70.1	$	36.3	$	—	$	106.4


	December 31, 2022
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	16.3	$	16.2	$	—	$	32.5
FTRs	—		—		7.8		7.8
Coal contracts	—		34.5		—		34.5
Total derivative assets	$	16.3	$	50.7	$	7.8	$	74.8

Investments held in rabbi trust	$	50.9	$	—	$	—	$	50.9

Derivative liabilities
Natural gas contracts	$	81.4	$	15.2	$	—	$	96.6

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 SPP 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, 2023 and 2021, the net unrealized gains included in earnings related to the investments held at the end of the period were $10.0 million and $16.0 million, respectively. For the year ended December 31, 2022, we recorded $12.7 million of net unrealized losses in earnings related to the investments held at the end of the period.

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


(in millions)	2023		2022		2021
Balance at the beginning of the period	$	7.8	$	2.4	$	2.4
Purchases	21.0		23.7		6.1
Realized and unrealized net gains (losses) included in earnings (1)	(0.5)		0.5		—
Settlements	(21.1)		(18.8)		(6.1)
Balance at the end of the period	$	7.2	$	7.8	$	2.4
Unrealized net gains (losses) included in earnings attributable to Level 3 derivatives held at the end of the reporting period (1)	$	0.5	$	(0.4)	$	—

(1) Amounts relate to FTRs and TCRs included in our non-utility energy infrastructure segment. These realized and unrealized net 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:


	2023				2022
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock of subsidiary	$	30.4	$	21.4	$	30.4	$	22.7
Long-term debt, including current portion (1)	16,631.1		15,564.3		15,464.2		13,921.3

(1) The carrying amount of long-term debt excludes finance lease obligations of $145.9 million and $183.2 million at December 31, 2023 and 2022, respectively.

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.

+ References + Details

Derivative Instruments

12 Months Ended

Dec. 31, 2023

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, 2023				December 31, 2022
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Current
Natural gas contracts	$	10.4	$	78.1	$	32.5	$	88.2
FTRs and TCRs	7.2		—		7.8		—
Coal contracts	0.3		10.9		18.9		—
Total current	17.9		89.0		59.2		88.2

Long-term
Natural gas contracts	0.1		8.0		—		8.4
Coal contracts	—		9.4		15.6		—
Total long-term	0.1		17.4		15.6		8.4
Total	$	18.0	$	106.4	$	74.8	$	96.6

Realized gains and losses on derivatives used in our regulatory 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 estimated notional sales volumes and realized gains and losses were as follows for the years ended:


	December 31, 2023			December 31, 2022			December 31, 2021
(in millions)	Volumes	Gains (Losses)		Volumes	Gains		Volumes	Gains
Natural gas contracts	198.0 Dth	$	(259.1)	183.3 Dth	$	299.5	197.6 Dth	$	136.5

FTRs and TCRs	30.2 MWh	25.9		27.2 MWh	11.8		28.2 MWh	17.7
Total		$	(233.2)		$	311.3		$	154.2

At December 31, 2023 and 2022, we had posted cash collateral of $100.3 million and $122.4 million, respectively.

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


	December 31, 2023					December 31, 2022
(in millions)	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
Gross amount recognized on the balance sheet	$	18.0	$	106.4		$	74.8	$	96.6
Gross amount not offset on the balance sheet	(3.1)		(71.0)		(1)	(17.5)		(82.5)		(2)
Net amount	$	14.9	$	35.4		$	57.3	$	14.1

(1) Includes cash collateral posted of $67.9 million.

(2) Includes cash collateral posted of $65.0 million.

Cash Flow Hedges

Until their expiration on November 15, 2021, we had two interest rate swaps with a combined notional value of $250.0 million to hedge the variable interest rate risk associated with our 2007 Junior Notes. The swaps provided a fixed interest rate of 4.9765% on $250.0 million of the $500.0 million of outstanding 2007 Junior Notes. As these swaps qualified for cash flow hedge accounting treatment, the related gains and losses were deferred in accumulated other comprehensive loss and were amortized to interest expense as interest was accrued on the 2007 Junior Notes.

We also 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 and losses related to these swap agreements recognized in other comprehensive income and reclassified from accumulated other comprehensive loss to interest expense during the years ended December 31, 2023, 2022, and 2021 were not significant. At December 31, 2023, the amount expected to be reclassified from accumulated other comprehensive loss to interest expense over the next twelve months was also not significant.

Guarantees

12 Months Ended

Dec. 31, 2023

Guarantees [Abstract]

GUARANTEES

The following table shows our outstanding guarantees:


	Total Amounts Committed at December 31, 2023		Expiration

(in millions)			Less Than 1 Year		1 to 3 Years		Over 3 Years
Standby letters of credit (1)	$	122.4	$	24.7	$	—	$	97.7
Surety bonds (2)	33.6		33.6		—		—
Other guarantees (3)	11.6		—		—		11.6
Total guarantees	$	167.6	$	58.3	$	—	$	109.3

(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 + Details

Employee Benefits

12 Months Ended

Dec. 31, 2023

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, former Wisconsin Energy Corporation employees who started with the company after 1995 receive a benefit based on a percentage of their annual salary plus an interest credit, while employees who started before 1996 receive a benefit based upon years of service and final average salary. 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)	2023		2022		2023		2022
Change in benefit obligation
Obligation at January 1	$	2,315.9	$	3,136.6	$	402.3	$	530.2
Service cost	24.0		50.8		9.8		14.3
Interest cost	122.3		91.8		21.6		15.4
Participant contributions	—		—		11.8		12.5
Plan amendments	—		—		—		0.2
Actuarial (gain) loss	81.9		(682.3)		45.9		(127.9)
Benefit payments	(191.7)		(281.0)		(46.0)		(45.7)
Federal subsidy on benefits paid	N/A		N/A		1.5		1.4
Transfer	—		—		1.2		1.9
Obligation at December 31	$	2,352.4	$	2,315.9	$	448.1	$	402.3

Change in fair value of plan assets
Fair value at January 1	$	2,628.0	$	3,328.9	$	835.3	$	1,000.2
Actual return on plan assets	214.9		(431.3)		76.4		(135.4)
Employer contributions net of plan transfer (1)	14.6		11.4		(47.9)		3.7
Participant contributions	—		—		11.8		12.5
Benefit payments	(191.7)		(281.0)		(46.0)		(45.7)
Fair value at December 31	$	2,665.8	$	2,628.0	$	829.6	$	835.3
Funded status at December 31	$	313.4	$	312.1	$	381.5	$	433.0

(1) Employer contribution includes a $50.0 million transfer out of the WEC Energy Group Retiree Welfare Plan, in 2023, associated with the overfunded position of this plan.

In 2023, we had actuarial losses related to our pension benefit obligations of $81.9 million and actuarial gains in 2022 of $682.3 million. The primary driver for the actuarial loss was a lower discount rate in 2023. Partially offsetting the loss in 2023, was higher than expected asset returns. The discount rate for our pension benefits was 5.19%, 5.49%, and 2.96% in 2023, 2022, and 2021, respectively.

In 2023, we had actuarial losses related to our OPEB benefit obligation of $45.9 million and actuarial gains in 2022 of $127.9 million. The primary driver for the actuarial loss was changes to medical trend assumptions and a lower discount rate in 2023. Partially offsetting the loss in 2023, was higher than expected asset returns. The discount rate for our OPEB benefits was 5.16%, 5.50%, and 2.92% in 2023, 2022, and 2021, 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)	2023		2022		2023		2022
Pension and OPEB assets	$	475.2	$	470.6	$	395.7	$	446.1
Pension and OPEB obligations	161.8		158.5		14.2		13.1
Total net assets	$	313.4	$	312.1	$	381.5	$	433.0

The accumulated benefit obligation for all defined benefit pension plans was $2,279.6 million and $2,250.6 million as of December 31, 2023 and 2022, 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)	2023		2022
Accumulated benefit obligation	$	300.7	$	185.7
Fair value of plan assets	147.3		32.8

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)	2023		2022
Projected benefit obligation	$	306.7	$	191.3
Fair value of plan assets	147.3		32.8

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)	2023		2022
Accumulated benefit obligation	$	21.0	$	20.6
Fair value of plan assets	6.9		7.4

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)	2023		2022		2023		2022
Pre-tax accumulated other comprehensive income (loss) (1)
Net actuarial loss (gain)	$	12.7	$	12.2	$	(1.2)	$	(1.6)
Prior service credits	—		—		—		—
Total	$	12.7	$	12.2	$	(1.2)	$	(1.6)

Net regulatory assets (liabilities) (2)
Net actuarial loss (gain)	$	688.9	$	669.2	$	(166.3)	$	(200.8)
Prior service credits	(2.2)		(2.1)		(29.3)		(44.2)
Total	$	686.7	$	667.1	$	(195.6)	$	(245.0)

(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)	2023		2022		2021		2023		2022		2021
Service cost	$	24.0	$	50.8	$	54.3	$	9.8	$	14.3	$	15.7
Interest cost	122.3		91.8		87.5		21.6		15.4		14.5
Expected return on plan assets	(187.4)		(208.0)		(200.9)		(53.0)		(68.9)		(66.0)
Plan settlement	1.3		6.2		3.9		—		—		—
Plan curtailment	—		—		—		—		—		(6.4)
Amortization of prior service cost (credit)	—		1.6		1.6		(14.8)		(15.9)		(15.9)
Amortization of net actuarial loss (gain)	33.0		75.3		109.4		(12.3)		(24.7)		(24.4)
Net periodic benefit cost (credit)	$	(6.8)	$	17.7	$	55.8	$	(48.7)	$	(79.8)	$	(82.5)

Effective January 1, 2023, the PSCW approved escrow accounting for pension and OPEB costs. As a result, as of December 31, 2023, we recorded a $6.0 million regulatory asset for pension costs and a $14.8 million regulatory asset for OPEB costs. The above table does not reflect any adjustments for the creation of these regulatory assets.

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
	2023	2022	2023	2022
Discount rate	5.19%	5.49%	5.16%	5.50%
Rate of compensation increase	4.00%	4.00%	N/A	N/A
Interest credit rate	4.84%	4.61%	N/A	N/A
Assumed medical cost trend rate (Pre 65)	N/A	N/A	6.25%	6.50%
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	2031	2031
Assumed medical cost trend rate (Post 65)	N/A	N/A	6.39%	6.00%
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	2030	2031

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
	2023	2022	2021
Discount rate	5.49%	3.18%	2.71%
Expected return on plan assets	6.62%	6.88%	6.88%
Rate of compensation increase	4.00%	4.00%	4.00%
Interest credit rate	4.62%	3.78%	3.71%


	OPEB Benefits
	2023	2022	2021
Discount rate	5.50%	2.92%	2.66%
Expected return on plan assets	6.50%	7.00%	7.00%
Assumed medical cost trend rate (Pre 65)	6.50%	5.70%	5.85%
Ultimate trend rate (Pre 65)	5.00%	5.00%	5.00%
Year ultimate trend rate is reached (Pre 65)	2031	2028	2028
Assumed medical cost trend rate (Post 65)	6.00%	5.67%	5.80%
Ultimate trend rate (Post 65)	5.00%	5.00%	5.00%
Year ultimate trend rate is reached (Post 65)	2031	2028	2028

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 2024, the expected return on assets assumption is 6.62% 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 legacy Wisconsin Energy Corporation pension trust target asset allocations are 25% equity investments, 55% fixed income investments, and 20% private equity and real estate investments. The legacy Integrys pension trust target asset allocations are 25% equity investments, 55% fixed income investments, and 20% private equity and real estate investments. 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, 2023
	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	$	179.3	$	—	$	—	$	179.3	$	91.8	$	—	$	—	$	91.8
International equity	174.0		—		—		174.0		84.6		—		—		84.6
Fixed income securities: (1)
United States bonds	—		906.6		—		906.6		91.5		203.2		—		294.7
International bonds	—		88.0		—		88.0		—		11.9		—		11.9
	353.3		994.6		—		1,347.9		267.9		215.1		—		483.0
Investments measured at net asset value:
Equity securities							407.4								182.1
Fixed income securities							124.2								47.7
Other							786.3								116.8
Total							$	2,665.8							$	829.6

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


	December 31, 2022
	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	$	231.5	$	—	$	—	$	231.5	$	92.5	$	—	$	—	$	92.5
International equity	202.2		—		—		202.2		83.9		—		—		83.9
Fixed income securities: (1)
United States bonds	—		838.7		—		838.7		129.8		145.3		—		275.1
International bonds	—		95.0		—		95.0		—		13.2		—		13.2
	433.7		933.7		—		1,367.4		306.2		158.5		—		464.7
Investments measured at net asset value:
Equity securities							466.0								186.6
Fixed income securities							101.0								65.5
Other							693.6								118.5
Total							$	2,628.0							$	835.3

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

Cash Flows

We expect to contribute $13.1 million to the pension plans and $2.2 million to the OPEB plans in 2024, 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
2024	$	207.0	$	34.3
2025	199.6		34.4
2026	202.2		34.9
2027	193.9		35.4
2028	188.8		35.5
2029-2033	847.4		175.3

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 an employer retirement contribution, in which amounts are contributed to the employee's savings plan account based on the employee's wages, age, and years of service. Total costs incurred under all of these plans were $57.5 million, $54.4 million, and $51.8 million in 2023, 2022, and 2021, respectively.

- Definition

The entire disclosure for retirement benefits.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 70
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480794/715-70-50-1

Reference 2: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 17
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480482/715-20-55-17

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(iv)(03)
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-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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-Paragraph 1
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-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
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-Paragraph 1
-Subparagraph (q)
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Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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-Paragraph 1
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-Name Accounting Standards Codification
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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-Section 50
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
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Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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-Section 50
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Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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Reference 12: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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-URI https://asc.fasb.org//1943274/2147480126/715-20-S99-2

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
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-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480266/715-60-50-3

+ Details

Investment in Transmission Affiliates

12 Months Ended

Dec. 31, 2023

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 a ten-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:


	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


	2022
(in millions)	ATC		ATC Holdco		Total
Balance at January 1	$	1,766.9	$	22.5	$	1,789.4
Add: Earnings from equity method investment	192.6		2.1		194.7
Add: Capital contributions	45.5		—		45.5
Less: Distributions	120.4		—		120.4

Balance at December 31	$	1,884.6	$	24.6	$	1,909.2


	2021
(in millions)	ATC		ATC Holdco		Total
Balance at January 1	$	1,733.5	$	30.8	$	1,764.3
Add: Earnings (loss) from equity method investment	166.4		(8.3)		158.1

Less: Distributions	133.0		—		133.0
Balance at December 31	$	1,766.9	$	22.5	$	1,789.4

In November 2019 and May 2020, the FERC issued orders that addressed complaints related to ATC's allowed ROE. Due to the various petitions related to the complaint filed in February 2015, our financials at December 31, 2021 and 2020, included a $39.1 million liability for potential future refunds that ATC may have been required to provide. In August 2022, a decision issued by

the D.C. Circuit Court of Appeals affirmed the FERC’s previous orders related to the February 2015 complaint. Therefore, during the third quarter of 2022, we reversed the liability that was previously recorded, which increased our equity earnings from ATC.

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)	2023		2022		2021
Charges to ATC for services and construction	$	17.4	$	18.9	$	22.9
Charges from ATC for network transmission services	377.5		363.7		361.0
Net refund (payment) from (to) ATC related to FERC ROE orders	—		(0.1)		7.3

As of December 31, 2023 and 2022, our balance sheets included the following receivables and payables for services provided to or received from ATC:


(in millions)	2023		2022
Accounts receivable for services provided to ATC	$	1.6	$	1.2
Accounts payable for services received from ATC	49.9		30.4
Amounts due from ATC for transmission infrastructure upgrades (1)	46.1		26.6

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

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


	Year Ended December 31
(in millions)	2023		2022		2021
Income statement data
Operating revenues	$	818.9	$	751.2	$	754.8
Operating expenses	407.6		381.5		376.2
Other expense, net	131.7		123.0		113.9
Net income	$	279.6	$	246.7	$	264.7


(in millions)	December 31, 2023		December 31, 2022
Balance sheet data
Current assets	$	115.2	$	89.6
Noncurrent assets	6,337.0		5,997.8
Total assets	$	6,452.2	$	6,087.4

Current liabilities	$	495.9	$	511.9
Long-term debt	2,736.0		2,613.0
Other noncurrent liabilities	585.2		485.8
Members' equity	2,635.1		2,476.7
Total liabilities and members' equity	$	6,452.2	$	6,087.4

Segment Information

12 Months Ended

Dec. 31, 2023

Segment Reporting [Abstract]

SEGMENT INFORMATION

We use net income attributed to common shareholders to measure segment profitability and to allocate resources to our businesses. At December 31, 2023, we reported six segments, which are described below.

•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.

•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.

All of our operations and assets are located within the United States. The following tables show summarized financial information related to our reportable segments for the years ended December 31, 2023, 2022, and 2021.


	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)		—
Other operation and maintenance	1,531.3		397.9		94.5		2,023.7		—		80.1		5.8		(9.1)		2,100.5
Impairment related to ICC disallowances	—		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

Equity in earnings of transmission affiliates	—		—		—		—		177.5		—		—		—		177.5
Interest expense	601.0		88.9		15.9		705.8		19.4		94.3		257.6		(350.2)		726.9
Income tax expense (benefit)	237.4		48.6		16.3		302.3		39.0		(68.4)		(68.3)		—		204.6
Net income (loss)	852.5		140.0		48.1		1,040.6		119.1		334.8		(162.8)		—		1,331.7
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
Capital expenditures and asset acquisitions	2,134.4		489.8		103.5		2,727.7		—		754.4		25.8		—		3,507.9
Total assets (1)	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) Total assets at December 31, 2023 reflect an elimination of $1,630.6 million for all lease activity between We Power and WE.


	Utility Operations
2022 (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	$	6,960.5	$	1,890.9	$	618.5	$	9,469.9	$	—	$	127.0	$	0.5	$	—	$	9,597.4
Intersegment revenues	—		—		—		—		—		463.0		—		(463.0)		—
Other operation and maintenance	1,351.3		459.2		98.5		1,909.0		—		51.0		(12.9)		(9.1)		1,938.0
Depreciation and amortization	754.7		230.9		40.9		1,026.5		—		139.2		25.0		(68.1)		1,122.6

Equity in earnings of transmission affiliates	—		—		—		—		194.7		—		—		—		194.7
Interest expense	555.9		73.8		13.9		643.6		19.4		68.9		119.4		(336.2)		515.1

Income tax expense (benefit)	247.5		83.1		13.1		343.7		45.8		(20.9)		(45.7)		—		322.9
Net income (loss)	759.6		226.9		39.7		1,026.2		129.5		324.8		(70.8)		—		1,409.7
Net income (loss) attributed to common shareholders	758.4		226.9		39.7		1,025.0		129.5		324.4		(70.8)		—		1,408.1
Capital expenditures and asset acquisitions	1,610.8		484.9		101.1		2,196.8		—		483.8		16.3		—		2,696.9
Total assets (1)	27,384.0		8,101.0		1,639.6		37,124.6		1,909.4		5,320.6		774.0		(3,256.5)		41,872.1

(1) Total assets at December 31, 2022 reflect an elimination of $1,632.9 million for all lease activity between We Power and WE.


	Utility Operations
2021 (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	$	6,037.0	$	1,672.8	$	519.0	$	8,228.8	$	—	$	86.7	$	0.5	$	—	$	8,316.0
Intersegment revenues	—		—		—		—		—		452.8		—		(452.8)		—
Other operation and maintenance	1,455.2		433.5		90.4		1,979.1		—		43.1		(7.5)		(9.2)		2,005.5
Depreciation and amortization	726.9		218.1		38.1		983.1		—		125.3		25.9		(60.0)		1,074.3

Equity in earnings of transmission affiliates	—		—		—		—		158.1		—		—		—		158.1
Interest expense	555.6		66.6		6.2		628.4		19.4		71.0		92.8		(340.5)		471.1
Loss on debt extinguishment	—		—		—		—		—		—		36.3		—		36.3
Income tax expense (benefit)	119.9		79.3		11.5		210.7		32.3		3.1		(45.8)		—		200.3
Net income (loss)	707.7		223.0		35.8		966.5		106.3		276.2		(50.5)		—		1,298.5
Net income (loss) attributed to common shareholders	706.5		223.0		35.8		965.3		106.3		279.2		(50.5)		—		1,300.3
Capital expenditures and asset acquisitions	1,389.7		533.7		95.9		2,019.3		—		335.3		18.1		—		2,372.7
Total assets (1)	25,687.9		7,853.4		1,506.1		35,047.4		1,792.7		4,627.7		785.3		(3,264.6)		38,988.5

(1) Total assets at December 31, 2021 reflect an elimination of $1,729.9 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

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 22
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-22

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 15
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-15

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 31
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-31

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 42
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-42

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (f)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 40
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-40

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org//280/tableOfContent

Reference 9: 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 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 34
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-34

Reference 11: 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

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-21

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-21

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

+ Details

Variable Interest Entities

12 Months Ended

Dec. 31, 2023

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 sheet:


(in millions)	December 31, 2023		December 31, 2022
Assets
Other current assets (restricted cash)	$	0.8	$	3.0
Regulatory assets	85.9		92.4
Other long-term assets (restricted cash)	0.6		0.6

Liabilities
Current portion of long-term debt	9.0		8.9
Other current liabilities (accrued interest)	0.1		0.1
Long-term debt	85.3		94.1

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, 2023 and 2022, our equity

investment in ATC was $1,980.8 million and $1,884.6 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, 2023 and 2022, our equity investment in ATC Holdco was $25.1 million and $24.6 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.

Power Purchase Commitment

On May 31, 2022, WE's PPA with LSP-Whitewater Limited Partnership that represented a variable interest expired. This agreement was for 236.5 MWs of firm capacity from a natural gas-fired cogeneration facility, and we accounted for it as a finance lease.

In November 2021, WE entered into a tolling agreement with LSP-Whitewater Limited Partnership that commenced on June 1, 2022, upon the expiration of the PPA. Concurrent with the execution of the tolling agreement, WE and WPS also entered into an agreement to purchase the natural gas-fired cogeneration facility. This asset purchase agreement was approved by the PSCW in December 2022, and the acquisition closed effective January 1, 2023. See Note 2, Acquisitions, for more information on the acquisition of this facility. The tolling agreement represented a variable interest until the facility was acquired since its terms were substantially similar to the terms of the PPA. Based on the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, we were not the primary beneficiary of the entity. We did not hold an equity or debt interest in the entity, and there was no residual guarantee associated with the tolling agreement. Similar to the PPA, we accounted for the tolling agreement as a finance lease.

Commitments and Contingencies

12 Months Ended

Dec. 31, 2023

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 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, 2023, including those of our subsidiaries:


				Payments Due By Period
(in millions)	Date Contracts Extend Through	Total Amounts Committed		2024		2025		2026		2027		2028		Later Years
Electric utility:
Nuclear	2033	$	6,280.6	$	600.3	$	634.5	$	681.6	$	730.4	$	782.6	$	2,851.2
Coal supply and transportation	2026	549.0		358.3		164.6		26.1		—		—		—
Purchased power	2063	333.5		56.7		56.4		57.5		52.1		48.4		62.4
Other	2043	100.6		13.9		13.3		12.9		11.6		10.2		38.7
Natural gas utility:
Supply and transportation	2048	1,777.2		381.2		274.9		214.8		197.4		155.7		553.2
Non-utility energy infrastructure:
Purchased power	2050	611.8		34.4		34.8		35.9		36.7		34.8		435.2
Natural gas storage and transportation	2048	4.8		4.0		—		—		—		0.1		0.7
Total		$	9,657.5	$	1,448.8	$	1,178.5	$	1,028.8	$	1,028.2	$	1,031.8	$	3,941.4

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, 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 reporting of GHG emissions to comply with federal clean air rules.

Air Quality

Cross State Air Pollution Rule – Good Neighbor Plan

In March 2023, the EPA issued its final Good Neighbor Plan, which became effective in August 2023 and requires significant reductions in ozone-forming emissions of NOx from power plants and industrial facilities. After review of the final rule, we believe that we are well positioned to meet the requirements.

Our RICE units in the Upper Peninsula of Michigan and Wisconsin are not currently subject to the final rule as each unit is less than 25 MWs. To the extent we use RICE engines for natural gas distribution operations, those engines not part of an LDC are subject to the emission limits and operational requirements of the rule beginning in 2026. The EPA has exempted LDCs from the final rule.

Mercury and Air Toxics Standards

In 2012, the EPA issued the MATS to limit emissions of mercury, acid gases, and other hazardous air pollutants. In April 2023, the EPA issued the pre-publication version of a proposed rule to strengthen and update MATS to reflect recent developments in control technologies and performance of coal and oil-fired units. The EPA proposed three revisions including a proposal to lower the PM limit from 0.03 lb/MMBtu to 0.01 lb/MMBtu. The EPA also sought comments on an even lower limit of 0.006 lb/MMBtu. Adoption of either of these lower limits could have an adverse effect on our operations.

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. In November 2022, the EPA's 2022 CASAC Ozone Review Panel issued a draft report supporting the reconsideration of the 2015 standard. The EPA staff initially issued a draft Policy Assessment in March 2023 that supported the reconsideration, however, in August 2023 it announced that it is instead restarting its ozone standard evaluation. The EPA has indicated it plans to release its Integrated Review Plan in fall 2024. This new review is anticipated to take 3 to 5 years to complete.

In February 2022, revisions to the Wisconsin Administrative Code to adopt the 2015 standard were finalized. The amended regulations incorporated by reference the federal air pollution monitoring requirements related to the standard. The WDNR submitted the rule updates as a SIP revision to the EPA, which the EPA approved in February 2023.

In April 2022, the EPA proposed to find that the Milwaukee, Sheboygan, and Chicago, IL-IN-WI nonattainment areas did not meet the marginal attainment deadline of August 2021 and should be adjusted to "moderate" nonattainment status for the 2015 standard. In October 2022, the EPA published its final reclassifications from "marginal" to "moderate" for these areas, effective November 7, 2022. Accordingly, the WDNR submitted a SIP revision to the EPA in December 2022 to address the moderate nonattainment status.

In October 2023, the EPA found that 11 states, including Wisconsin, failed to submit timely SIP revisions to address nonattainment areas classified as "moderate" for the 2015 standard. This action triggered a 24-month deadline for states to get their SIP approved or the EPA will issue a federal implementation plan. Additionally, offset sanctions will take effect in 18 months if the SIP is not approved. The offset sanctions impact volatile organic compound and NOx emissions from new or modified sources in the nonattainment areas.

We believe that we are well positioned to meet the requirements associated with the 2015 ozone standard and do not expect to incur significant costs to comply with the associated state and federal rules.

Particulate Matter

In December 2020, the EPA completed its 5-year review of the 2012 annual and 24-hour standards for fine PM and determined that no revisions were necessary to the current annual standard of 12 µg/m3 or the 24-hour standard of 35 µg/m3. All counties within our service territories are in attainment with the current 2012 standards. Under the Biden Administration's policy review, the EPA concluded that the scientific evidence and information from the December 2020 determination supports revising the level of the annual standard for the PM NAAQS to below the current level of 12 µg/m3, while retaining the 24-hour standard. In January 2023, the EPA announced its proposed decision to revise the primary (health-based) annual PM2.5 standard from its current level of 12 µg/m3 to within the range of 9 to 10 µg/m3. The EPA also proposed not to change the current secondary (welfare-based) annual PM2.5 standard, primary and secondary 24-hour PM2.5 standards, and primary and secondary PM10 standards. The EPA did, however, take comments on the full range (between 8 and 11 µg/m3) included in the CASAC's latest report. The EPA finalized the rule on February 7, 2024 and lowered the primary annual PM2.5 level to 9 µg/m3, which could cause some nonattainment areas that may affect permitting at our facilities. The secondary and 24-hour standards remain unchanged. The EPA will designate areas as attainment and nonattainment with the new standard by early 2026. The WDNR will need to draft and submit a SIP for the EPA's approval.

Climate Change

In May 2023, the EPA proposed GHG performance standards for existing fossil-fired steam generating and gas combustion units and also proposed to repeal the Affordable Clean Energy rule, which had replaced the Clean Power Plan. For coal plants, no standards

would apply under the proposed version of the rule until 2032, and after 2032 the applicable standard would depend on the unit's retirement date. For combined cycle natural gas plants above a 50% capacity factor, the proposed rule is highly dependent on the use of hydrogen as an alternative fuel, and on carbon capture technology. For simple cycle natural gas-fired combustion turbines, the proposed version of the rule does not include applicable limits as long as the capacity factor is less than 20%. Our RICE units in Michigan and the new Weston RICE project are not affected under the rule because each RICE unit is less than 25 MWs. We continue to evaluate the proposed rule to understand the impacts to our operations. A final rule is expected in the second quarter of 2024.

In May 2023, the EPA proposed to revise the NSPS for GHG emissions from new, modified, and reconstructed fossil-fueled power plants. The EPA is proposing two distinct 111(b) rules – one for natural gas-fired stationary combustion turbines and the other for coal-fired units. New stationary combustion turbine units would be divided into three subcategories based on their annual capacity factor – low load, intermediate load, and base load. Our RICE units are not affected by this rule since each unit is below 25 MWs. Our ESG Progress Plan is heavily focused on reducing GHG emissions. The EPA has indicated that it anticipates a final rule in the second quarter of 2024.

The EPA released proposed regulations for the Mandatory Greenhouse Gas Reporting Rule, 40 CFR Part 98, in June 2022. In May 2023, the EPA released a supplementary proposal, which includes updates of the global warming potentials to determine CO2 equivalency for threshold reporting and the addition of a new section regarding energy consumption. The proposed revisions could impact the reporting required for our electric generation facilities, local natural gas distribution companies, and underground natural gas storage facilities. In August 2023, the EPA also issued its proposed updates to amend reporting requirements for petroleum and natural gas systems, with an anticipated final rule to be issued in early 2024. We are currently evaluating the potential impact of the proposed rule, if any, on our operations.

Our ESG Progress Plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables and clean natural gas-fueled generation. We have already retired more than 1,900 MWs of fossil-fueled generation since the beginning of 2018. We expect to retire approximately 1,800 MWs of additional fossil-fueled generation by the end of 2031, which includes the planned retirements in 2024-2025 of OCPP Units 5-8, the planned retirement by June 2026 of jointly-owned Columbia Units 1 and 2, and the planned retirement in 2031 of Weston Unit 3. See Note 7, Property, Plant, and Equipment, for more information related to these planned power plant retirements. In May 2021, we announced goals to achieve reductions in carbon emissions from our electric generation fleet by 60% by the end of 2025 and by 80% by the end of 2030, both from a 2005 baseline. We expect to achieve these goals by continuing to make operating refinements, retiring less efficient generating units, and executing our capital plan. Over the longer term, the target for our generation fleet is to be net carbon neutral by 2050.

We also continue to reduce methane emissions by improving our natural gas distribution systems, and have set a target across our natural gas distribution operations to achieve net-zero methane emissions by the end of 2030. We plan to achieve our net-zero goal through an effort that includes both continuous operational improvements and equipment upgrades, as well as the use of RNG throughout our utility systems.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

The EPA issued a final regulation under Section 316(b) of the CWA that became effective in October 2014 and 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.

Pursuant to a WDNR rule, which became effective in June 2020, the requirements of federal Section 316(b) of the CWA were incorporated into the Wisconsin Administrative Code. The WDNR applies this rule when establishing BTA requirements for cooling water intake structures at existing facilities. These BTA requirements are incorporated into WPDES permits for WE and WPS facilities.

We have received a final BTA determination for VAPP. We have received interim BTA determinations for OCPP Units 5-8 and Weston Units 3 and 4. We believe that existing technology installed at the OCPP facility meets the BTA requirements; however, depending on the timing of the permit reissuance, all four generating units at the OCPP may be retired prior to the WDNR making a final BTA decision, anticipated in 2025. In addition, we believe that existing technology installed at the Weston facility will result in a final BTA determination during the WPDES permit reissuance expected in the first quarter of 2024.

The WDNR reissued the WPDES permit for PWGS effective October 2023. This reissued permit includes a conditional BTA determination with conditions for the existing PWGS porous dike (rock breakwater) cooling water intake structure. We do not anticipate compliance with these conditions will result in a material impact on our financial condition or the efficiency of power plant operations.

Steam Electric Effluent Limitation Guidelines

The EPA's ELG rule, effective January 2016 and modified in 2020, revised the treatment technology requirements related to BATW and wet FGD wastewaters at existing coal-fueled facilities and created new requirements for several types of power plant wastewaters. The two new requirements that affect WE and WPS facilities relate to discharge limits for BATW and wet FGD wastewater. Although our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule, certain facility modifications are necessary to meet the ELG rule requirements. Through 2023, compliance costs associated with the ELG rule required $105 million in capital investment. An $8 million BATW modification to OCPP Units 7 and 8 was completed and placed in-service in mid-2021, and in December 2021, the PSCW issued a Certificate of Authority approving the $89 million ERGS FGD wastewater treatment system modification. The BATW modifications, including $8 million of modifications at Weston Unit 3 completed in June 2023, did not require PSCW approval prior to construction. All of these ELG required projects were placed in-service ahead of WPDES permit deadlines.

In March 2023, the EPA issued the proposed "supplemental ELG rule." The rule would replace the existing 2020 ELG rule and, as proposed, would establish stricter limitations on: 1) BATW; 2) FGD wastewater; 3) CCR leachate; and 4) legacy wastewaters. The most significant proposed ELG rule change is a ZLD requirement for FGD wastewater. Under the proposed rule, this new ZLD requirement must be met by a date determined by the permitting authority (the WDNR for WE) that is as soon as possible beginning 60 days following publication of the final rule, but no later than December 31, 2029.

The proposed rule would also create a subcategory for "early adopters" that have already installed a compliant biological treatment system by the date of the proposed rule. Early adopters would not be required to install further FGD wastewater treatment, provided the facility owner also agrees to permanently cease combustion of coal by December 31, 2032. Although the $89 million biological treatment system at ERGS is complete and was placed in service in December 2023 to meet the WPDES permit deadline, the timing of the project's completion did not comply with the deadline proposed by the EPA to qualify for the early adopter status. In addition, we do not believe that the biological treatment system would be compliant with the additional ZLD FGD wastewater treatment requirements as proposed. In May 2023, we submitted written comments to the EPA articulating these concerns, including the cost impact to our customers. The EPA has indicated that it anticipates issuing the final rule in the second quarter of 2024.

If the supplemental ELG rule is finalized as proposed, we anticipate that our coal-fueled facilities, including ER 1 and ER 2 that were built with ELG-compliant dry BA transport systems, will meet the BATW rule provisions.

The EPA also proposed requirements for legacy wastewaters and landfill leachate. We have reviewed the proposed requirements to determine potential costs and actions required for our facilities. We submitted comments to the EPA regarding these proposed requirements.

Waters of the United States

In January 2023, the EPA and the Army Corps (the agencies) together released a final rule effective in March 2023 that established standards for identifying which wetland or surface drainage features qualify as WOTUS based on its pre-2015 definition. The pre-2015 approach involved applying factors established through case law and agency precedents to determine whether a wetland or surface drainage feature is subject to federal jurisdiction.

In May 2023, in Sackett v. EPA, the Supreme Court issued a decision significantly narrowing federal jurisdiction over wetlands to "traditional navigable waters" and wetlands or other waters that have a "continuous surface connection" with a traditional navigable water.

In August 2023, the agencies revised the final rule to conform the definition of WOTUS to the Supreme Court's May 2023 Sackett decision. The conforming rule became effective upon publication in the Federal Register on September 8, 2023.

We anticipate this final rule revision based on the Sackett decision may lead to a decreased number of projects that require Army Corps federal wetland permits. This decision also may affect the administration of some state programs. At this point, our projects

requiring federal permits are moving ahead, but we are monitoring these recent developments to better understand potential future impacts.

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, some of which are in the EPA Superfund Alternative Approach Program. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure.

In addition, we are coordinating the investigation and cleanup of some of these sites subject to the jurisdiction of the EPA under what is called a "multisite" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.

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)	2023		2022
Regulatory assets	$	596.8	$	610.7
Reserves for future environmental remediation	463.7		499.6

Coal Combustion Residuals Rule

The EPA issued a pre-publication proposed rule for CCR in May 2023 that would apply to landfills, historic fill sites, and projects where CCR was placed at a power plant site. As proposed, the rule would regulate previously exempt closed landfills.

We are actively engaged with our trade organizations and provided them information to include in their comments to the EPA. The EPA has indicated that it anticipates issuing a final rule in the second quarter of 2024. As proposed, the rule could have a material adverse impact on our coal ash landfills and require additional remediation that has not been required under the current state programs.

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 parks, solar parks, 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, 2023. 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% for 2035-2039 and 100% after 2040. The bill only allows natural gas to count as clean energy if it is accompanied with carbon capture and storage. The MPSC has indicated that it will complete a study by December 2024 on the unique conditions influencing electric generation, transmission, and demand in the Upper Peninsula of Michigan, which includes the unique role of RICE units placed in service to facilitate the retirement of coal-fired generation in the Upper Peninsula of Michigan. 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.

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.

Consent Decrees

Wisconsin Public Service Corporation – Weston and Pulliam Power Plants

In November 2009, the EPA issued an NOV to WPS, which alleged violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam power plants from 1994 to 2009. WPS entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Eastern District of Wisconsin in March 2013. With the retirement of Pulliam Units 7 and 8 in October 2018, WPS completed the mitigation projects required by the Consent Decree and received a completeness letter from the EPA in October 2018. See Note 6, Regulatory Assets and Liabilities, for more information about the retirement. We are working with the EPA on a closeout process for the Consent Decree and expect that process to begin in 2024.

Joint Ownership Power Plants – Columbia and Edgewater

In December 2009, the EPA issued an NOV to WPL, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including MG&E, WE (former co-owner of an Edgewater unit), and WPS. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. WPS, along with WPL, MG&E, and WE, entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013. As a result of the continued implementation of the Consent Decree related to the jointly owned Columbia and Edgewater plants, the Edgewater 4 generating unit was retired in September 2018. See Note 6, Regulatory Assets and Liabilities, for more information about the retirement. WPL started the process to close out this Consent Decree.

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2023

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

SUPPLEMENTAL CASH FLOW INFORMATION

Non-Cash Transactions


	Year Ended December 31
(in millions)	2023		2022		2021
Cash paid for interest, net of amount capitalized	$	653.4	$	485.2	$	473.8
Cash paid (received) for income taxes, net (1)	(58.9)		52.4		33.8
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs	171.3		197.4		127.8
Increase in receivables related to insurance proceeds	3.5		—		41.7
Liabilities accrued for software licensing agreement	—		7.4		—

(1) Cash received for income taxes in 2023 includes $75 million related to PTCs that were sold to a third party.

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)	2023		2022		2021
Cash and cash equivalents	$	42.9	$	28.9	$	16.3
Restricted cash included in other current assets	70.1		25.6		19.6
Restricted cash included in other long-term assets	52.2		127.7		51.6
Cash, cash equivalents, and restricted cash	$	165.2	$	182.2	$	87.5

Our restricted cash 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, and WEPCo Environmental Trust.

•Cash we received when WECI acquired ownership interests in certain renewable generation projects. This cash is restricted as it can only be used to pay for any remaining costs associated with the construction of the renewable generation facilities.

•Cash used by WE and WPS during January 2023 to purchase a natural gas-fired cogeneration facility located in Whitewater, Wisconsin. This cash was included in other long-term assets at December 31, 2022. See Note 2, Acquisitions, for more information on the purchase of this facility.

Regulatory Environment

12 Months Ended

Dec. 31, 2023

Regulated Operations [Abstract]

REGULATORY ENVIRONMENT

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

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 are 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 are expected to be 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 LNG project was placed into service in November 2023, and WG's LNG project is expected to be placed into service in 2024.

On December 20, 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 September 2022, WE, WPS, and WG entered into settlement agreements with certain intervenors to resolve most of the outstanding issues in each utility's respective rate case; however, the PSCW declined to approve the settlement agreements. 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 will keep their current earnings sharing mechanisms, under which, if a 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 refunded to ratepayers; and (iii) 100.0% of any remaining excess earnings is 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 will not 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 will 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 in 2023 and 2024.

•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.

2022 Rates

In March 2021, WE, WPS, and WG filed an application with the PSCW for the approval of certain accounting treatments that allowed them to maintain their electric, natural gas, and steam base rates through 2022 and forego filing a rate case for one year. In connection with the request, the three utilities also entered into an agreement, dated March 23, 2021, with various stakeholders. Pursuant to the terms of the agreement, the stakeholders fully supported the application. In September 2021, the PSCW issued written orders approving the application.

The final orders reflected the following:

•WE, WPS, and WG amortized, in 2022, certain previously deferred balances to offset approximately half of their forecasted revenue deficiencies.

•WG deferred interest and depreciation expense associated with capital investments since its last rate case that otherwise would have been added to rate base in a 2022 test-year rate case.

•WE, WPS, and WG were able to defer any increases in tax expense due to changes in tax law that occurred in 2021 and/or 2022.

•WE, WPS, and WG maintained their earnings sharing mechanisms for 2022, with modification. The earnings sharing mechanisms were modified to authorize the utility to retain 100.0% of the first 15 basis points of earnings above its then authorized ROE. The earnings sharing mechanisms otherwise remained as previously authorized.

2020 and 2021 Rates

In March 2019, WE, WPS, and WG filed applications with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable, effective January 1, 2020. In August 2019, all three utilities filed applications with the PSCW for approval of settlement agreements entered into with certain intervenors to resolve several outstanding issues in each utility's respective rate case. In December 2019, the PSCW issued written orders that approved the settlement agreements without material modification and addressed the remaining outstanding issues that were not included in the settlement agreements. The new rates were effective January 1, 2020. The final orders reflected the following:


	WE					WPS					WG
2020 Effective rate increase (decrease)
Electric (1) (2)	$	15.3	million	/	0.5%	$	15.8	million	/	1.6%	N/A
Gas (3)	$	10.4	million	/	2.8%	$	4.3	million	/	1.4%	$	(1.5)	million	/	(0.2)%
Steam	$	1.9	million	/	8.6%	N/A					N/A

ROE	10.0%					10.0%					10.2%

Common equity component average on a financial basis	52.5%					52.5%					52.5%

(1) Amounts are net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impact. The WE and WPS rate orders reflected the majority of the unprotected deferred tax benefits from the Tax Legislation being amortized over two years. For WE, approximately $65 million of tax benefits were amortized in each of 2020 and 2021. For WPS, approximately $11 million of tax benefits were amortized in 2020 and approximately $39 million were amortized in 2021. The unprotected deferred tax benefits related to the unrecovered balances of certain of WE's retired plants and its SSR regulatory asset were used to reduce the related regulatory asset. Unprotected deferred tax benefits by their nature are eligible to be returned to customers in a manner and timeline determined to be appropriate by our regulators.

(2) The WPS rate order was net of $21 million of refunds related to its 2018 earnings sharing mechanism. These refunds were made to customers evenly over two years, with half returned in 2020 and the remainder returned in 2021.

(3) The WE amount includes certain deferred tax expense from the Tax Legislation, and the WPS and WG amounts are net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impact. The rate orders for all three gas utilities reflected all of the unprotected deferred tax expense and benefits from the Tax Legislation being amortized evenly over four years. For WE, approximately $5 million of previously deferred tax expense was amortized each year. For WPS and WG, approximately $5 million and $3 million, respectively, of previously deferred tax benefits was amortized each year. Unprotected deferred tax expense and benefits by their nature are eligible to be recovered from or returned to customers in a manner and timeline determined to be appropriate by our regulators.

In accordance with its rate order, WE filed an application with the PSCW in July 2020 requesting a financing order to securitize $100 million of Pleasant Prairie power plant's book value, plus the carrying costs accrued on the $100 million during the securitization process and the related financing fees. In November 2020, the PSCW issued a written order approving the application. The financing order also authorized WE to form a bankruptcy-remote special purpose entity, WEPCo Environmental Trust, for the sole purpose of issuing ETBs to recover the approved costs. In May 2021, WEPCo Environmental Trust issued $118.8 million of

1.578% ETBs due December 15, 2035. See Note 23, Variable Interest Entities, for more information regarding WEPCo Environmental Trust.

The WPS rate order allows WPS to collect the previously deferred revenue requirement for ReACT™ costs above the authorized $275 million level. The total cost of the ReACT™ project was $342 million. This regulatory asset is being collected from customers over eight years.

The PSCW approved all three Wisconsin utilities continuing to have an earnings sharing mechanism through 2021. The earnings sharing mechanism was modified from its previous structure to one that was consistent with other Wisconsin investor-owned utilities. Under this earnings sharing mechanism, if the utility earned above its authorized ROE: (i) the utility retained 100.0% of earnings for the first 25 basis points above the authorized ROE; (ii) 50.0% of the next 50 basis points were required to be refunded to customers; and (iii) 100.0% of any remaining excess earnings were required to be refunded to customers. In addition, the rate orders also required WE, WPS, and WG to maintain residential and small commercial electric and natural gas customer fixed charges at previously authorized rates and to maintain the status quo for WE's and WPS's electric market-based rate programs for large industrial customers through 2021.

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

2023 Rate Order

On January 6, 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 will return to the traditional rate making process to recover the costs of necessary infrastructure improvements.

On November 16, 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. This amount includes the recovery of costs related to PGL’s SMP that were previously being recovered under its QIP rider. PGL's new rates were effective December 1, 2023.

•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 SMP until the ICC has a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level. In accordance with the written order, the ICC initiated the proceeding on January 31, 2024.

On December 15, 2023, PGL and NSG filed an application for rehearing with the ICC requesting reconsideration of various issues in the ICC's November 16, 2023 written orders. On January 3, 2024, the ICC granted PGL and NSG a limited-scope rehearing. The rehearing will be limited to:

•the authorized spending for the completion of SMP projects that started in 2023,

•the authorized spending for emergency repairs needed to ensure the safety and reliability of our delivery system, and

•the timing of changes required to NSG's billing system.

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 in 2023. This amount includes $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. We anticipate appealing the ICC’s disallowance of PGL's and NSG's capital costs to the Illinois circuit court after the rehearing process is complete.

An ICC decision on our limited-scope rehearing is expected in the second quarter of 2024.

Third-Party Transaction Fee Adjustment Rider

In accordance with the Climate and Equitable Jobs Act that was signed into law in Illinois, effective September 15, 2021, Illinois utilities are prohibited from charging customers a fee when they elect to pay for service with a credit card. Utilities are now required to incur these expenses and seek recovery through a rate proceeding or by establishing a recovery mechanism. In December 2021, the ICC approved the use of a TPTFA rider for PGL. The TPTFA rider allowed PGL to recover the costs incurred for these third-party transaction fees prior to them being included in base rates. PGL began recovering costs under the rider on February 1, 2022. Amounts deferred under the rider were being recovered over a period of 12 months and are subject to an annual reconciliation whereby costs are reviewed by the ICC for accuracy and prudency. Effective December 1, 2023, PGL discontinued its use of the TPTFA rider and began recovering costs related to these third-party transaction fees through its base rates. NSG began recovering these costs through its base rates, effective September 15, 2021.

North Shore Gas Company 2021 Rate Order

In October 2020, NSG filed a request with the ICC to increase its natural gas rates. In September 2021, the ICC issued a written order authorizing a rate increase of $4.1 million (4.5%). The rate increase reflected a 9.67% ROE and a common equity component average of 51.58%. The natural gas rate increase was primarily driven by NSG's ongoing significant investment in its distribution system since its last rate review that resulted in revised base rates effective January 28, 2015. The new rates were effective September 15, 2021.

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 March 2023, PGL filed its 2022 reconciliation with the ICC, which, along with the reconciliations from 2016 through 2021, are still pending. Annual costs included in the rider have ranged from $192 million to $348 million.

As of December 31, 2023, there can be no assurance that all costs incurred under PGL's QIP rider during the open reconciliation years, which include 2016 through 2023, will be deemed recoverable by the ICC. Disallowances by the ICC, if any, could be material and have a material adverse impact on our results of operations.

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.

On November 14, 2023, the MPUC issued a written order approving a settlement agreement MERC reached with certain intervenors. The settlement agreement reflects 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 will be effective March 1, 2024.

MERC’s customers are entitled to a refund to the extent the interim rate increase exceeded the final approved rate increase. As of December 31, 2023, MERC had recorded a regulatory liability of $8.5 million for refunds due to customers. These amounts will be refunded to customers during the second quarter of 2024.

Michigan Gas Utilities Corporation

2024 Rate Application

On December 28, 2023, 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 2024 and to request new rates be effective January 1, 2025. MGU is currently in the process of evaluating its rate request.

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 include:

•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 are being 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.

2021 Rate Order

In February 2020, MGU provided notification to the MPSC of its intent to file an application requesting an increase to MGU's natural gas rates to be effective January 1, 2021. However, MGU decided that it would delay its filing of the rate case as a result of the Coronavirus Disease – 2019 pandemic.

In May 2020, MGU filed an application with the MPSC requesting approval to defer $5.0 million of depreciation and interest expense during 2021 related to capital investments made by MGU since its last rate case. In July 2020, the MPSC issued a written order approving MGU's request. The deferral of these costs helped to mitigate the impacts from delaying the filing of the rate case.

In March 2021, MGU filed its request with the MPSC to increase its natural gas rates. In September 2021, the MPSC issued a written order approving a settlement agreement MGU reached with certain intervenors. The order authorized a rate increase of $9.3 million (6.35%) and reflected a 9.85% ROE and a common equity component average of 51.5%. The natural gas rate increase was primarily driven by MGU's significant investment in capital infrastructure since its previous rate review that resulted in revised base rates effective January 1, 2016. The order also allowed MGU to implement a rider for its MRP, which supports recovery of planned capital investment related to pipeline replacements to maintain system safety and reliability between 2023 and 2027, without having to file a rate case. All costs recovered through the rider are subject to a prudence review by the MPSC. The new rates were effective January 1, 2022.

Upper Michigan Energy Resources Corporation

2024 Rate Application

On December 28, 2023, UMERC provided notification to the MPSC of its intent to file an application requesting an increase to its electric rates. The application is expected to be filed in March 2024 and to request new rates be effective January 1, 2025. UMERC is currently in the process of evaluating its rate request.

Recovery of Natural Gas Costs

Due to the cold temperatures, wind, snow, and ice throughout the central part of the country during February 2021, the cost of gas purchased for our natural gas utility customers was temporarily driven significantly higher than our normal winter weather expectations. All of our utilities have regulatory mechanisms in place for recovering all prudently incurred natural gas costs.

In March 2021, WE and WG received approval from the PSCW to recover approximately $54 million and $24 million, respectively, of natural gas costs in excess of the benchmark set in their GCRMs over a period of three months, beginning in April 2021. In March 2021, WPS also filed its revised natural gas rate sheets with the PSCW reflecting approximately $28 million of natural gas costs in excess of the benchmark set in its GCRM. WPS also recovered these excess costs over a period of three months, beginning in April 2021.

PGL and NSG incurred approximately $131 million and $10 million, respectively, of natural gas costs in February 2021 in excess of the amounts included in their rates. These costs were recovered over a period of 12 months, which started on April 1, 2021. PGL's and NSG's natural gas costs were reviewed for prudency by the ICC as part of their annual natural gas cost reconciliation. In January 2023, the ICC issued written orders approving each company's 2021 reconciliation.

In February 2021, MERC incurred approximately $75 million of natural gas costs in excess of the benchmark set in its GCRM. In August 2021, the MPUC issued a written order approving a joint proposal filed by MERC and four other Minnesota utilities to recover their respective excess natural gas costs. In accordance with the order, MERC recovered $10 million of these costs through its annual natural gas true-up process over a period of 12 months, and the remaining $65 million was to be recovered over a period of 27 months, both beginning in September 2021. Recovery of these costs and the issue of prudence was referred to a contested-case proceeding. In October 2022, the MPUC issued a written order approving a settlement agreement entered into by MERC and various parties related to the recovery of the extraordinary natural gas costs incurred in February 2021. Under the settlement agreement, MERC agreed to not seek recovery of $3 million of these costs. MERC substantially recovered the remaining $62 million of extraordinary natural gas costs over the previously approved 27-month recovery period.

Natural gas costs incurred at MGU and UMERC in excess of the amount included in their respective rates were not significant.

Other Income, Net

12 Months Ended

Dec. 31, 2023

Other Income and Expenses [Abstract]

OTHER INCOME, NET

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


(in millions)	2023		2022		2021
Non-service components of net periodic benefit costs	$	97.7	$	104.4	$	72.2
AFUDC-Equity	59.1		29.4		18.0
Gains (losses) from investments held in rabbi trust	13.7		(12.6)		18.6
Earnings (losses) from equity method investments (1)	(1.1)		9.3		19.9
Other, net	8.3		(1.7)		4.5
Other income, net	$	177.7	$	128.8	$	133.2

(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, 2023
Accounting Standards Update and Change in Accounting Principle [Abstract]
NEW ACCOUNTING PRONOUNCEMENTS	NEW ACCOUNTING PRONOUNCEMENTS Improvements to Income Tax Disclosures 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. The amendments are effective for annual periods beginning after December 15, 2024, with early adoption permitted. We plan to adopt these amendments beginning with our fiscal year ending on December 31, 2025, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures. Improvements to Reportable Segment Disclosures In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. The amendments require additional disclosures about reportable segments on an annual and interim basis. The amendments require disclosure of significant segment expenses that are (1) regularly provided to the chief operating decision maker and (2) included in the reported measure of segment profit or loss. The amendments also require disclosure of an amount for other segment items and a description of its composition. The new standard also allows companies to disclose multiple measures of segment profit or loss if those measures are used to assess performance and allocate resources. The amendments are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. We plan to adopt these amendments beginning with our fiscal year ending on December 31, 2024, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures. Reference Rate Reform In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting and in January 2021, the FASB issued ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope. These pronouncements provide temporary optional expedients and exceptions for applying GAAP principles to contract modifications and hedging relationships to ease the financial reporting burdens of the market transition from LIBOR and other interbank offered rates to alternative reference rates. These pronouncements were effective upon issuance on March 12, 2020 through December 31, 2022. In December 2022, the FASB issued ASU No. 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, to extend the temporary accounting rules under Topic 848 from December 31, 2022 to December 31, 2024, after which entities will no longer be permitted to apply the relief in Topic 848. An entity may elect to apply the amendments prospectively from March 12, 2020 through December 31, 2024 by accounting topic. Our $500.0 million 2007 Junior Notes, which were previously subject to a variable rate based on U.S. dollar LIBOR, became subject to a variable rate based on SOFR beginning July 1, 2023. No contract modifications were required as the references to LIBOR were replaced by operation of law. See Note 14, Long-Term Debt, for more information. We do not anticipate this guidance having a significant impact 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

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+ Details

Schedule I - Condensed Parent Company Financial Statements

12 Months Ended

Dec. 31, 2023

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)	2023		2022		2021
Operating expenses (income)	$	2.5	$	(1.6)	$	12.0
Equity earnings of subsidiaries	1,502.5		1,473.0		1,367.0
Other income, net	19.6		2.4		1.7
Interest expense	260.8		109.6		70.2
Loss on debt extinguishment	—		—		23.1
Income before income taxes	1,258.8		1,367.4		1,263.4
Income tax benefit	72.9		40.7		36.9
Net income attributed to common shareholders	$	1,331.7	$	1,408.1	$	1,300.3

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)	2023		2022		2021
Net income attributed to common shareholders	$	1,331.7	$	1,408.1	$	1,300.3

Other comprehensive income (loss), net of tax
Derivatives accounted for as cash flow hedges
Net derivative gain, net of tax	—		—		0.6
Reclassification of realized net derivative (gain) loss to net income, net of tax	(0.3)		(0.3)		0.9
Cash flow hedges, net	(0.3)		(0.3)		1.5

Defined benefit plans
Pension and OPEB adjustments arising during the period, net of tax	(0.2)		(0.8)		0.4
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax	0.1		0.2		0.3
Defined benefit plans, net	(0.1)		(0.6)		0.7

Other comprehensive income (loss) from subsidiaries, net of tax	(0.5)		(2.7)		1.4

Other comprehensive income (loss), net of tax	(0.9)		(3.6)		3.6

Comprehensive income attributed to common shareholders	$	1,330.8	$	1,404.5	$	1,303.9

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)	2023		2022
Assets
Current assets
Accounts receivable from related parties	$	2.7	$	0.7
Notes receivable from related parties	16.0		30.9
Prepaid income taxes	—		35.4
Other	0.2		0.1
Current assets	18.9		67.1

Long-term assets
Investments in subsidiaries	18,307.2		16,533.4
Note receivable from WECI	430.0		—
Other	22.9		24.2
Long-term assets	18,760.1		16,557.6
Total assets	$	18,779.0	$	16,624.7

Liabilities and Equity
Current liabilities
Short-term debt	$	697.0	$	399.7
Current portion of long-term debt	600.0		700.0
Accounts payable to related parties	2.9		2.0
Notes payable to related parties	459.6		332.5
Other	73.2		31.8
Current liabilities	1,832.7		1,466.0

Long-term liabilities
Long-term debt	5,192.8		3,747.2
Other	29.3		34.6
Long-term liabilities	5,222.1		3,781.8

Common shareholders' equity	11,724.2		11,376.9
Total liabilities and equity	$	18,779.0	$	16,624.7

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)	2023		2022		2021
Operating activities
Net income attributed to common shareholders	$	1,331.7	$	1,408.1	$	1,300.3
Reconciliation to cash provided by operating activities
Equity income in subsidiaries, net of distributions	(566.8)		(437.4)		(571.3)
Deferred income taxes, net	(3.8)		11.6		(1.9)
Loss on debt extinguishment	—		—		23.1
Change in –
Accounts receivable from related parties	(2.0)		(0.1)		0.1
Prepaid income taxes	35.4		21.1		(2.1)
Other current assets	(0.1)		—		—
Accounts payable to related parties	0.9		(3.5)		(26.2)
Accrued interest	42.1		15.4		0.4
Other current liabilities	(0.7)		(5.1)		8.2
Other, net	14.4		5.8		(2.5)
Net cash provided by operating activities	851.1		1,015.9		728.1

Investing activities
Capital contributions to subsidiaries	(1,807.4)		(1,099.7)		(734.0)
Return of capital from subsidiaries	175.2		372.9		196.1
Short-term notes receivable from related parties, net	14.9		(1.9)		81.8
Other, net	—		(2.0)		(1.1)
Net cash used in investing activities	(1,617.3)		(730.7)		(457.2)

Financing activities
Exercise of stock options	6.3		33.6		15.7
Purchase of common stock	(16.6)		(69.2)		(33.1)
Dividends paid on common stock	(984.2)		(917.9)		(854.8)
Issuance of long-term debt	2,050.0		900.0		1,100.0
Retirement of long-term debt	(700.0)		—		(300.0)
Repayment of short-term loan	—		—		(340.0)
Change in commercial paper	297.3		(336.4)		255.7
Short-term notes payable to related parties, net	127.1		112.1		(82.6)
Payments for debt extinguishment and issuance costs	(13.3)		(6.7)		(33.9)
Other, net	(0.4)		(1.2)		(1.4)
Net cash provided by (used in) financing activities	766.2		(285.7)		(274.4)

Net change in cash and cash equivalents	—		(0.5)		(3.5)
Cash and cash equivalents at beginning of year	—		0.5		4.0
Cash and cash equivalents at end of year	$	—	$	—	$	0.5

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)	2023		2022		2021
WE	$	370.0	$	630.0	$	360.0
We Power	192.8		158.5		217.9
WG	171.0		60.0		30.0
WECI (1)	93.7		87.7		46.4
ATC Holding (2)	86.8		74.9		106.4
UMERC	21.0		17.0		—
Wispark (3)	0.4		7.5		—
Bluewater	—		—		35.0
Total	$	935.7	$	1,035.6	$	795.7

(1) We also received amounts classified as return of capital of $171.6 million, $363.7 million, and $164.1 million from WECI during the years ended December 31, 2023, 2022, and 2021, respectively.

(2) We also received an amount classified as return of capital of $32.0 million from ATC Holding during the year ended December 31, 2021.

(3) We also received amounts classified as return of capital of $3.6 million and $9.2 million from Wispark during the years ended December 31, 2023 and 2022.

NOTE 3—LONG-TERM DEBT

The following table shows the future maturities of our long-term debt outstanding as of December 31, 2023:


(in millions)
2024	$	600.0
2025	620.0
2026	1,600.0
2027	900.0
2028	950.0
Thereafter	1,150.0
Total	$	5,820.0

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:


	2023				2022
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Long-term notes receivable from WECI	$	430.0	$	425.7	$	—	$	—
Long-term debt, including current portion	5,792.8		5,596.0		4,447.2		4,095.6

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, 2023		Expiration

(in millions)			Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees supporting business operations (1)	$	191.7	$	14.4	$	—	$	177.3
Standby letters of credit (2)	75.1		24.5		—		50.6
Surety bonds (3)	33.6		33.6		—		—
Other guarantees (4)	11.6		—		—		11.6
Total guarantees	$	312.0	$	72.5	$	—	$	239.5

(1) Consists of $177.3 million, $10.2 million, and $4.2 million of guarantees to support the business operations of WECI, Bluewater, 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)	2023		2022		2021
Cash paid for interest	$	209.1	$	88.1	$	70.2
Cash received for income taxes, net	(104.5)		(72.9)		(27.9)
Significant non-cash equity transaction:
Issuance 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)	2023		2022
UMERC	$	15.2	$	27.1
Wispark	0.8		1.1
Bluewater	—		2.7
Total	$	16.0	$	30.9

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)	2023		2022
Integrys	$	257.0	$	115.0
WECC	109.2		106.5
WBS	91.8		111.0
Bluewater	1.6		—
Total	$	459.6	$	332.5

Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2023

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, 2023	$	199.3	$	72.0	$	88.3	$	(166.1)	$	193.5
December 31, 2022	198.3		86.1		62.9		(148.0)		199.3
December 31, 2021	220.1		107.4		(44.8)		(84.4)		198.3

(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, 2023
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

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2023

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, 2023 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. However, as a result of the extreme weather in the Midwest in February 2021, the cost of gas purchased for our natural gas customers was temporarily driven significantly higher than our normal winter weather expectations, and we were not allowed to recover all of the additional costs. See Note 26, Regulatory Environment, for more information on the recovery of these high natural gas costs.

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, PGL's rates included a rider for pass through of income tax expense changes resulting from the Tax Legislation and a cost recovery mechanism for SMP costs. Similarly, 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 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 2023. 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 2023, 2022, and 2021, we recorded $23.5 million, $23.4 million, and $23.3 million, respectively, of revenues related to these deferred carrying costs.

Other Operating Revenues

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 to mitigate credit risk.

Materials, supplies and inventories

Our inventories as of December 31 consisted of:


(in millions)	2023		2022
Natural gas in storage	$	327.8	$	446.3
Materials and supplies	320.0		257.0
Fossil fuel	127.4		103.8
Total	$	775.2	$	807.1

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 13% of total inventories at December 31, 2023 and 2022, respectively. The estimated replacement cost of natural gas in inventory at December 31, 2023 and 2022, exceeded the LIFO cost by $12.2 million and $98.3 million, respectively. In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per Dth of $2.13 at December 31, 2023, and $3.41 at December 31, 2022.

Substantially all other natural gas in storage, materials and supplies, 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 regulatory 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	2023	2022	2021
WE	3.03%	3.06%	3.09%
WPS	2.93%	2.67%	2.66%
WG	2.61%	2.47%	2.44%
PGL	3.13%	3.13%	3.12%
NSG	2.46%	2.43%	2.52%
MERC	2.60%	2.56%	2.58%
MGU	2.73%	2.75%	2.70%
UMERC	2.97%	3.01%	2.94%

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. The AFUDC calculation for WBS uses the WPS AFUDC retail rate, while our utilities' AFUDC rates are determined by their respective state commissions, each with specific requirements. Average AFUDC rates are shown below:


	2023
	Average AFUDC Retail Rate	Average AFUDC Wholesale Rate
WE	8.45%	6.70%
WPS	7.46%	4.60%
WG	7.94%	N/A
UMERC	6.28%	N/A
WBS	7.46%	N/A

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


(in millions)	2023		2022		2021
AFUDC-Debt
WE	$	13.0	$	6.9	$	2.9
WPS	2.9		2.3		3.5
WG	3.4		1.4		0.2
UMERC	—		0.1		0.1
WBS	0.1		0.1		0.1
Other	0.1		0.2		—
Total AFUDC-Debt	$	19.5	$	11.0	$	6.8

AFUDC-Equity
WE	$	41.0	$	18.8	$	7.9
WPS	7.6		5.8		9.0
WG	9.8		3.9		0.6
UMERC	—		0.1		0.1
WBS	0.4		0.3		0.2
Other	0.3		0.5		0.2
Total AFUDC-Equity	$	59.1	$	29.4	$	18.0

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 and asset management, targeted enterprise resource planning systems, human resources management, employee scheduling, geospatial information, 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, 2023 and 2022, we had $11.3 million and $4.7 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, 2023 and 2022, was $2.8 million and $1.5 million, respectively. Amortization expense for the years ended December 31, 2023, 2022, and 2021 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 assets over its fair value. No impairment losses were recorded for our indefinite-lived intangible assets during the years ended December 31, 2023, 2022, and 2021. 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 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. In the fourth quarter of 2023, we recorded a non-cash impairment loss of $178.9 million related to the 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.

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.

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.

Intangible liabilities

Our finite-lived intangible 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 liabilities are amortized on a straight-line basis over their estimated useful lives, which is the term of the agreements. Amortization of the revenue contract intangible liabilities is 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 intangible liabilities assumed impact the amount and timing of future amortization.

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, rather than estimating potential future forfeitures and recording them over the vesting period.

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:


	2023			2022			2021
Stock options granted	257,780			437,269			530,612

Estimated weighted-average fair value per stock option	$	19.58		$	14.71		$	13.20

Assumptions used to value the options:
Risk-free interest rate	3.8% – 4.8%			0.2% – 1.6%			0.1% – 0.9%
Dividend yield	3.2		%	3.2		%	2.9		%
Expected volatility	22.0		%	21.0		%	21.0		%
Expected life (years)	8.3			8.7			8.7

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 certain officers and all 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.

The ultimate number of units that will be awarded is dependent on our total shareholder return (stock price appreciation plus dividends) as compared to the total shareholder return of a peer group of companies over three years, as well as other performance metrics, as may be determined by the Compensation Committee. Under the terms of awards granted prior to 2023, participants may earn between 0% and 175% of the performance unit award based on our total shareholder return. Pursuant to the plan terms governing these awards, these percentages can be adjusted upwards or downwards by up to 10% based on our performance against additional performance measures, if any, adopted by the Compensation Committee.

The WEC Energy Group Performance Unit Plan was amended and restated, effective January 1, 2023. In accordance with the amended plan, the Compensation Committee selected multiple performance measures that will be weighted to determine the ultimate payout for the awards granted in 2023 and 2024. The ultimate number of units awarded 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, rather than estimating potential future forfeitures and recording them over the vesting period.

Earnings per share

We compute basic earnings per share by dividing our net income attributed to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per share is computed in a similar manner, but includes the exercise and/or conversion of all potentially dilutive securities, as calculated using the treasury stock method. Such dilutive securities include in-the-money stock options. The calculation of diluted earnings per share for the years ended December 31, 2023, 2022, and 2021 excluded 1,716,286; 653,323; and 769,030 stock options, respectively, that had an anti-dilutive effect.

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

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 produced after December 31, 2022, to third parties. In September 2023, under this transferability provision, we entered into an agreement to sell substantially all of our 2023 PTCs to a third party. 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 will also include any expected proceeds from the sale of tax credits in the evaluation of the realizability of deferred tax assets related to PTCs. 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 are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

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. 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. 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. As a result, we did not have any significant concentrations of credit risk at December 31, 2023. In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2023

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Schedule of inventory

Our inventories as of December 31 consisted of:


(in millions)	2023		2022
Natural gas in storage	$	327.8	$	446.3
Materials and supplies	320.0		257.0
Fossil fuel	127.4		103.8
Total	$	775.2	$	807.1

Schedule of annual utility composite depreciation rates

Annual utility composite depreciation rates are shown below:


Annual Utility Composite Depreciation Rates	2023	2022	2021
WE	3.03%	3.06%	3.09%
WPS	2.93%	2.67%	2.66%
WG	2.61%	2.47%	2.44%
PGL	3.13%	3.13%	3.12%
NSG	2.46%	2.43%	2.52%
MERC	2.60%	2.56%	2.58%
MGU	2.73%	2.75%	2.70%
UMERC	2.97%	3.01%	2.94%

Schedule of AFUDC rates and amounts

Average AFUDC rates are shown below:


	2023
	Average AFUDC Retail Rate	Average AFUDC Wholesale Rate
WE	8.45%	6.70%
WPS	7.46%	4.60%
WG	7.94%	N/A
UMERC	6.28%	N/A
WBS	7.46%	N/A

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


(in millions)	2023		2022		2021
AFUDC-Debt
WE	$	13.0	$	6.9	$	2.9
WPS	2.9		2.3		3.5
WG	3.4		1.4		0.2
UMERC	—		0.1		0.1
WBS	0.1		0.1		0.1
Other	0.1		0.2		—
Total AFUDC-Debt	$	19.5	$	11.0	$	6.8

AFUDC-Equity
WE	$	41.0	$	18.8	$	7.9
WPS	7.6		5.8		9.0
WG	9.8		3.9		0.6
UMERC	—		0.1		0.1
WBS	0.4		0.3		0.2
Other	0.3		0.5		0.2
Total AFUDC-Equity	$	59.1	$	29.4	$	18.0

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:


	2023			2022			2021
Stock options granted	257,780			437,269			530,612

Estimated weighted-average fair value per stock option	$	19.58		$	14.71		$	13.20

Assumptions used to value the options:
Risk-free interest rate	3.8% – 4.8%			0.2% – 1.6%			0.1% – 0.9%
Dividend yield	3.2		%	3.2		%	2.9		%
Expected volatility	22.0		%	21.0		%	21.0		%
Expected life (years)	8.3			8.7			8.7

Acquisitions (Tables) - WECI

12 Months Ended

Dec. 31, 2023

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

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

Thunderhead

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	$	0.2
Other prepayments	0.3
Net property, plant, and equipment	692.3
Other long-term assets	5.1
Other current liabilities	(0.2)
Other long-term liabilities	(273.2)
Noncontrolling interest	(42.5)
Total purchase price	$	382.0

Jayhawk

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	$	145.3
Other long-term liabilities	(11.8)
Long-term debt	(7.3)
Noncontrolling interest	(6.3)
Total purchase price	$	119.9

Operating Revenues (Tables)

12 Months Ended

Dec. 31, 2023

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, 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


(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, 2022
Electric	$	4,956.2	$	—	$	—	$	4,956.2	$	—	$	—	$	—		$	4,956.2
Natural gas	1,980.7		1,883.7		601.8		4,466.2		54.3		—		(51.8)			4,468.7
Total regulated revenues	6,936.9		1,883.7		601.8		9,422.4		54.3		—		(51.8)			9,424.9
Other non-utility revenues	—		—		18.7		18.7		133.6		—		(9.1)			143.2
Total revenues from contracts with customers	6,936.9		1,883.7		620.5		9,441.1		187.9		—		(60.9)			9,568.1
Other operating revenues	23.6		7.2		(2.0)		28.8		402.1		0.5		(402.1)		(1)	29.3
Total operating revenues	$	6,960.5	$	1,890.9	$	618.5	$	9,469.9	$	590.0	$	0.5	$	(463.0)		$	9,597.4


(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, 2021
Electric	$	4,516.6	$	—	$	—	$	4,516.6	$	—	$	—	$	—		$	4,516.6
Natural gas	1,490.3		1,630.3		494.0		3,614.6		46.8		—		(43.8)			3,617.6
Total regulated revenues	6,006.9		1,630.3		494.0		8,131.2		46.8		—		(43.8)			8,134.2
Other non-utility revenues	—		—		17.8		17.8		92.8		—		(9.1)			101.5
Total revenues from contracts with customers	6,006.9		1,630.3		511.8		8,149.0		139.6		—		(52.9)			8,235.7
Other operating revenues	30.1		42.5		7.2		79.8		399.9		0.5		(399.9)		(1)	80.3
Total operating revenues	$	6,037.0	$	1,672.8	$	519.0	$	8,228.8	$	539.5	$	0.5	$	(452.8)		$	8,316.0

(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)	2023		2022		2021
Residential	$	1,992.3	$	1,879.1	$	1,768.0
Small commercial and industrial	1,641.1		1,530.4		1,415.7
Large commercial and industrial	978.4		1,042.2		931.9
Other	30.5		29.9		29.3
Total retail revenues	4,642.3		4,481.6		4,144.9
Wholesale	120.4		153.9		157.7
Resale	195.4		256.7		161.9
Steam	25.2		28.4		28.7
Other utility revenues	11.3		35.6		23.4
Total electric utility operating revenues	$	4,994.6	$	4,956.2	$	4,516.6

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, 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


(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Year ended December 31, 2022
Residential	$	1,234.0	$	1,297.4	$	391.3	$	2,922.7
Commercial and industrial	672.7		408.8		218.7		1,300.2
Total retail revenues	1,906.7		1,706.2		610.0		4,222.9
Transportation	81.8		259.8		34.5		376.1
Other utility revenues (1) (2)	(7.8)		(82.3)		(42.7)		(132.8)
Total natural gas utility operating revenues	$	1,980.7	$	1,883.7	$	601.8	$	4,466.2


(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Year Ended December 31, 2021
Residential	$	928.9	$	1,017.9	$	241.2	$	2,188.0
Commercial and industrial	472.1		302.1		129.9		904.1
Total retail revenues	1,401.0		1,320.0		371.1		3,092.1
Transportation	80.0		231.2		31.8		343.0
Other utility revenues (1) (3)	9.3		79.1		91.1		179.5
Total natural gas utility operating revenues	$	1,490.3	$	1,630.3	$	494.0	$	3,614.6

(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) During 2022, we continued to recover natural gas costs we under-collected from our customers in 2021 related to the extreme weather experienced in February 2021, as well as higher natural gas costs incurred at the majority of our segments during 2022. As these amounts are billed to customers, they are reflected in retail revenues with an offsetting decrease in other utility revenues.

(3) During 2021, in addition to costs related to the extreme weather event experienced in February 2021, we incurred higher natural gas costs as a result of an increase in the price of natural gas.

See Note 26, Regulatory Environment, for more information.

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)	2023		2022		2021
Renewable generation revenues	$	164.9	$	101.0	$	60.3
We Power revenues	23.5		23.4		23.3
Appliance service revenues	19.6		18.7		17.8

Other	0.1		0.1		0.1
Total other non-utility operating revenues	$	208.1	$	143.2	$	101.5

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)	2023		2022		2021
Late payment charges	$	56.5	$	55.6	$	54.9
Alternative revenues (1)	47.0		(30.3)		21.2
Other	4.2		4.0		4.2
Total other operating revenues	$	107.7	$	29.3	$	80.3

(1) Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to decoupling mechanisms, wholesale true-ups, and conservation improvement rider true-ups.

- 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 + Details

Credit Losses (Tables)

12 Months Ended

Dec. 31, 2023

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, 2023 and 2022, 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, 2023
Accounts receivable and unbilled revenues	$	1,078.0		$	481.5		$	94.9		$	1,654.4		$	33.9		$	8.4		$	1,696.7
Allowance for credit losses	77.4			109.7			6.4			193.5			—			—			193.5
Accounts receivable and unbilled revenues, net (1)	$	1,000.6		$	371.8		$	88.5		$	1,460.9		$	33.9		$	8.4		$	1,503.2

Total accounts receivable, net – past due greater than 90 days (1)	$	51.7		$	45.0		$	2.1		$	98.8		$	—		$	—		$	98.8
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	93.6		%	100.0		%	—		%	94.5		%	—		%	—		%	94.5		%


(in millions)	Wisconsin			Illinois			Other States			Total Utility Operations			Non-Utility Energy Infrastructure			Corporate and Other			WEC Energy Group Consolidated
December 31, 2022
Accounts receivable and unbilled revenues	$	1,199.4		$	624.2		$	164.4		$	1,988.0		$	25.4		$	4.3		$	2,017.7
Allowance for credit losses	82.0			111.0			6.3			199.3			—			—			199.3
Accounts receivable and unbilled revenues, net (1)	$	1,117.4		$	513.2		$	158.1		$	1,788.7		$	25.4		$	4.3		$	1,818.4

Total accounts receivable, net – past due greater than 90 days (1)	$	51.9		$	52.9		$	1.9		$	106.7		$	—		$	—		$	106.7
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	97.0		%	100.0		%	—		%	96.8		%	—		%	—		%	96.8		%

(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, 2023, $914.6 million, or 60.8%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses.

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, 2023, 2022, and 2021, is included below:


(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. After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance.


(in millions)	Wisconsin		Illinois		Other States		WEC Energy Group Consolidated
Balance at January 1, 2022	$	84.0	$	105.5	$	8.8	$	198.3
Provision for credit losses	50.5		33.0		2.6		86.1
Provision for credit losses deferred for future recovery or refund	29.7		33.2		—		62.9
Write-offs charged against the allowance	(117.0)		(82.6)		(6.4)		(206.0)
Recoveries of amounts previously written off	34.8		21.9		1.3		58.0
Balance at December 31, 2022	$	82.0	$	111.0	$	6.3	$	199.3

On a consolidated basis, there was a $1.0 million increase in the allowance for credit losses during the year ended December 31, 2022. We believe that the high energy costs that customers were seeing, which were driven by high natural gas prices, contributed to higher past due accounts receivable balances and a related increase in the allowance for credit losses. The increase was substantially offset by customer write-offs related to collection practices returning to pre-pandemic levels, including the restoration of our ability to disconnect customers.


(in millions)	Wisconsin		Illinois		Other States		WEC Energy Group Consolidated
Balance at January 1, 2021	$	102.1	$	111.6	$	6.4	$	220.1
Provision for credit losses	46.4		25.6		3.7		75.7
Provision for credit losses deferred for future recovery or refund	(16.6)		3.5		—		(13.1)
Write-offs charged against the allowance	(74.8)		(52.5)		(2.5)		(129.8)
Recoveries of amounts previously written off	26.9		17.3		1.2		45.4
Balance at December 31, 2021	$	84.0	$	105.5	$	8.8	$	198.3

The allowance for credit losses decreased during the year ended December 31, 2021, primarily related to normal collection practices resuming in April 2021 for our Wisconsin utilities and in June 2021 for our Illinois utilities. Across all of our reportable segments, higher year-over-year natural gas prices drove an increase in gross accounts receivable balances, partially offsetting the decrease in the allowance for credit losses attributed to collection efforts.

Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2023

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)	2023		2022		See Note
Regulatory assets (1) (2)
Pension and OPEB costs (3)	$	731.7	$	714.3	20, 26
Plant retirement related items	646.2		688.6
Environmental remediation costs (4)	596.8		610.7		24
Income tax related items	449.9		461.9		16
AROs	162.0		169.7		1(l), 9
Derivatives	130.3		133.8		1(s)
Uncollectible expense	127.7		69.3		5
SSR (5)	113.2		123.5
Securitization	85.9		92.4		23
Bluewater (6)	45.3		20.9
Energy efficiency programs (7)	33.9		33.9
Energy costs recoverable through rate adjustments	3.2		26.9		1(d)
MERC extraordinary natural gas costs (8)	0.8		35.1		26
Other, net	147.8		125.9
Total regulatory assets	$	3,274.7	$	3,306.9

Balance sheet presentation
Other current assets	$	24.9	$	42.3
Regulatory assets	3,249.8		3,264.6
Total regulatory assets	$	3,274.7	$	3,306.9