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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)

☒			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2026

OR

☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ________________ to ___________________

Commission File Number

Registrant; State of Incorporation; Address; and Telephone Number

IRS Employer Identification No.

001-09057

WEC ENERGY GROUP, INC.

39-1391525

(A Wisconsin Corporation)

231 West Michigan Street

P.O. Box 1331

Milwaukee, WI 53201

c/o Corporate Secretary

(414) 221-2345

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class

Trading Symbol(s)

Name of Each Exchange on Which Registered

Common Stock, $.01 Par Value

WEC

New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 

    Yes ☒    No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

    Yes ☒    No ☐

---

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

    Yes ☐    No ☒

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date (September 30, 2026):

Common Stock, $.01 Par Value, 328,992,329 shares outstanding

---

Table of Contents

WEC ENERGY GROUP, INC.

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended September 30, 2026

TABLE OF CONTENTS

Page

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

1

PART I.

FINANCIAL INFORMATION

4

ITEM 1.

FINANCIAL STATEMENTS (UNAUDITED)

4

Condensed Consolidated Income Statements

4

Condensed Consolidated Statements of Comprehensive Income

5

Condensed Consolidated Balance Sheets

6

Condensed Consolidated Statements of Cash Flows

7

Condensed Consolidated Statements of Equity

8

Notes to Condensed Consolidated Financial Statements

10

Page

Note 1

General Information

10

Note 2

Acquisitions

10

Note 3

Disposition

11

Note 4

Operating Revenues

11

Note 5

Credit Losses

15

Note 6

Regulatory Assets and Liabilities

17

Note 7

Property, Plant, and Equipment

18

Note 8

Common Equity

19

Note 9

Short-Term Debt and Lines of Credit

21

Note 10

Long-Term Debt

22

Note 11

Leases

23

Note 12

Materials, Supplies, and Inventories

24

Note 13

Income Taxes

25

Note 14

Fair Value Measurements

26

Note 15

Derivative Instruments

28

Note 16

Guarantees

30

Note 17

Employee Benefits

30

Note 18

Goodwill and Intangibles

31

Note 19

Investment in Transmission Affiliates

33

Note 20

Segment Information

34

Note 21

Variable Interest Entities

39

Note 22

Commitments and Contingencies

41

Note 23

Supplemental Cash Flow Information

45

Note 24

Regulatory Environment

46

Note 25

Other Income, Net

49

Note 26

New Accounting Pronouncements

50

ITEM 2.

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

51

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

92

ITEM 4.

CONTROLS AND PROCEDURES

92

PART II.

OTHER INFORMATION

93

ITEM 1.

LEGAL PROCEEDINGS

93

ITEM 1A.

RISK FACTORS

93

ITEM 5.

OTHER INFORMATION

93

ITEM 6.

EXHIBITS

94

SIGNATURE

95

09/30/2026 Form 10-Q			i			WEC Energy Group, Inc.

---

Table of Contents

GLOSSARY OF TERMS AND ABBREVIATIONS

The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:

Subsidiaries and Affiliates
ATC						American Transmission Company LLC
ATC Holdco						ATC Holdco LLC
Blooming Grove						Blooming Grove Wind Energy Center LLC
Bluewater						Bluewater Natural Gas Holding, LLC
Delilah I						Delilah Solar Energy LLC
Hardin III						Hardin Solar Energy III Center
Integrys						Integrys Holding, Inc.
Jayhawk						Jayhawk Wind, LLC
MERC						Minnesota Energy Resources Corporation
MGU						Michigan Gas Utilities Corporation
NSG						North Shore Gas Company
PGL						The Peoples Gas Light and Coke Company
Samson I						Samson Solar Energy LLC
Tatanka Ridge						Tatanka Ridge Wind LLC
Thunderhead						Thunderhead Wind Energy LLC
UMERC						Upper Michigan Energy Resources Corporation
WE						Wisconsin Electric Power Company
We Power						W.E. Power, LLC
WEC Energy Group						WEC Energy Group, Inc.
WECI						WEC Infrastructure LLC
WEPCo Environmental Trust						WEPCo Environmental Trust Finance I, LLC
WG						Wisconsin Gas LLC
WPS						Wisconsin Public Service Corporation
Federal and State Regulatory Agencies
CBP						United States Customs and Border Protection Agency
DOC						United States Department of Commerce
EPA						United States Environmental Protection Agency
FERC						Federal Energy Regulatory Commission
ICC						Illinois Commerce Commission
IRS						United States Internal Revenue Service
MPSC						Michigan Public Service Commission
PSCW						Public Service Commission of Wisconsin
SEC						United States Securities and Exchange Commission
USITC						United States International Trade Commission
Accounting Terms
AFUDC						Allowance for Funds Used During Construction
ARO						Asset Retirement Obligation
ASC						Accounting Standards Codification
ASU						Accounting Standards Update
FASB						Financial Accounting Standards Board
GAAP						United States Generally Accepted Accounting Principles
LIFO						Last-In, First-Out
OPEB						Other Postretirement Employee Benefits
VIE						Variable Interest Entity
Environmental Terms
BTA						Best Technology Available
CCR						Coal Combustion Residuals
CO2						Carbon Dioxide
CRL						Combustion Residual Leachate

09/30/2026 Form 10-Q			ii			WEC Energy Group, Inc.

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ELG						Steam Electric Effluent Limitation Guidelines
GHG						Greenhouse Gas
GHG Power Plant Rule						2024 Greenhouse Gas Power Plant Rule
MATS						Mercury and Air Toxics Standards
NAAQS						National Ambient Air Quality Standards
NOx						Nitrogen Oxide
PCCC						Permanent Cessation of Coal Combustion
PM						Particulate Matter
PM2.5						Particulates Less Than 2.5 Micrometers in Diameter
ZLD						Zero Liquid Discharge
Measurements
Bcf						Billion Cubic Feet
Dth						Dekatherm
GW						Gigawatt
lb/MMBtu						Pound Per Million British Thermal Unit
MW						Megawatt
MWh						Megawatt-hours
µg/m3						Micrograms Per Cubic Meter
Other Terms and Abbreviations
2024A Junior Notes						WEC Energy Group, Inc.'s Series 2024A 6.69% Fixed-to-Fixed Reset Rate Junior Subordinated Notes Due June 15, 2055
2024B Junior Notes						WEC Energy Group, Inc.'s Series 2024B 6.69% Fixed-to-Fixed Reset Rate Junior Subordinated Notes Due June 15, 2055
2025 Junior Notes						WEC Energy Group, Inc.'s Series 2025 5.625% Fixed-to-Fixed Reset Rate Junior Subordinated Notes Due May 15, 2056
2027 Notes						WEC Energy Group, Inc.'s 4.375% Convertible Senior Notes Due 2027
2028 Notes						WEC Energy Group, Inc.'s 3.375% Convertible Senior Notes Due 2028
2029 Notes						WEC Energy Group, Inc.'s 4.375% Convertible Senior Notes Due 2029
AD						Antidumping
AI						Artificial Intelligence
AREP						Amended Renewable Energy Plan
Bespoke Resources						All or a portion of generation facilities and PPAs allocated to VLCs
Chicago, IL-IN-WI						Chicago, Illinois, Indiana, and Wisconsin
CODM						Chief Operating Decision Maker
Columbia						Columbia Energy Center
CPCN						Certificate of Public Convenience and Necessity
CT						Combustion Turbine
CVD						Countervailing Duty
D.C. Circuit Court of Appeals						United States Court of Appeals for the District of Columbia Circuit
EDA						Equity Distribution Agreement
EPS						Earnings Per Share
ERGS						Elm Road Generating Station
ETB						Environmental Trust Bond
Exchange Act						Securities Exchange Act of 1934, as amended
FTR						Financial Transmission Right
IRA						Inflation Reduction Act
ITC						Investment Tax Credit
LDC						Local Natural Gas Distribution Company
LNG						Liquefied Natural Gas
MISO						Midcontinent Independent System Operator, Inc.
MISO Energy Markets						MISO Energy and Operating Reserves Markets
OBBBA						One Big Beautiful Bill Act
OCPP						Oak Creek Power Plant
PPA						Power Purchase Agreement
PRP						Pipe Retirement Program

09/30/2026 Form 10-Q			iii			WEC Energy Group, Inc.

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PTC						Production Tax Credit
QIP						Qualifying Infrastructure Plant
REC						Renewable Energy Certificate
Renegade						Renegade Solar Energy Center
RNG						Renewable Natural Gas
ROE						Return on Equity
S&P						Standard & Poor's
Supreme Court						United States Supreme Court
TCR						Transmission Congestion Right
UEA						Uncollectible Expense Adjustment
UFLPA						Uyghur Forced Labor Prevention Act
VLC						Very Large Customer
Weston						Weston Generating Station

09/30/2026 Form 10-Q			iv			WEC Energy Group, Inc.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

In this report, we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act. Readers are cautioned not to place undue reliance on these forward-looking statements. Forward-looking statements may be identified by reference to a future period or periods or by the use of terms such as "anticipates," "believes," "could," "estimates," "expects," "forecasts," "goals," "guidance," "intends," "may," "objectives," "plans," "possible," "potential," "projects," "seeks," "should," "targets," "will," or variations of these terms.

Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of capital projects, sales and customer growth, rate actions and related filings with regulatory authorities, environmental and other regulations, including associated compliance costs, legal proceedings, dividend payout ratios, effective tax rates, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, climate-related matters, our capital plan, liquidity and capital resources, and other matters.

Forward-looking statements are subject to a number of risks and uncertainties that could cause our actual results to differ materially from those expressed or implied in the statements. These risks and uncertainties include those described in risk factors as set forth in our 2025 Annual Report on Form 10-K, and those identified below:

•Factors affecting utility and non-utility energy infrastructure operations such as catastrophic weather-related damage, environmental incidents, unplanned facility outages and repairs and maintenance, electric grid reliability, and electric transmission or natural gas pipeline system constraints;

•Factors affecting the demand for electricity and natural gas, including political or regulatory developments, varying, adverse, or unusually severe weather conditions, changes in economic conditions, including continued economic growth, customer growth and declines, including our ability to develop and/or acquire new generation to meet demand from data centers and other large customers and uncertainty regarding the projected demand from these customers, commodity prices, energy conservation efforts, and continued adoption of distributed generation by customers or co-location of generation near data centers;

•The timing, resolution, and impact of rate cases and negotiations, including recovery of deferred and current costs and the ability to earn a reasonable return on investment, and other regulatory decisions impacting our regulated operations;

•The impact of federal, state, and local legislative and/or regulatory changes, including changes in rate-setting policies or procedures, the results of rate orders, deregulation and restructuring of the electric and/or natural gas utility industries, transmission or distribution system operation, changes to address energy affordability concerns and grid reliability, the approval process for new construction, reliability standards, pipeline integrity and safety standards, allocation of energy assistance, energy efficiency mandates, electrification initiatives and other efforts to reduce the use of natural gas, and tax laws, including those that affect our ability to use PTCs and ITCs, as well as changes in the interpretation and/or enforcement of any laws or regulations by regulatory agencies;

•Federal, state, and local legislative and regulatory changes relating to the environment, including changing environmental regulations impacting generation facilities and renewable energy standards, the enforcement of these laws and regulations, changes in and uncertainty regarding the interpretation of regulations or permit conditions by regulatory agencies, and the recovery of associated remediation and compliance costs;

•Risks related to providing service to data centers and other large-scale customers including project termination, cancellation or delay, failure to receive regulatory approvals of projects or tariffs or other necessary permitting or siting approvals, delays in recovery of contractual reimbursement for project costs, the ability to fully recover our investment on assets developed to serve our large-scale customers, lower than anticipated need for electricity by these customers, public opposition to data centers and failure to garner support at the local, state and federal levels, and new legislation or regulation impacting data centers specifically or large-scale customer cost allocation generally;

•The ability to obtain and retain customers, including wholesale customers, due to increased competition in our electric and natural gas markets from retail choice and alternative electric suppliers, and continued industry consolidation;

•The timely completion of capital projects within budgets and the ability to recover the related costs through rates;

09/30/2026 Form 10-Q			1			WEC Energy Group, Inc.

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•The impact of changing expectations and demands of our customers, regulators, investors, and other stakeholders;

•The risk of delays and shortages, and increased costs of equipment, materials, or other resources that are critical to our business operations and corporate strategy, as a result of changes to United States trade policy (including changes to tariffs on imports, port fees, and other trade policy tools) as well as changes to foreign governments' trade policies impacting United States exports, supply chain disruptions (including from rail congestion), inflation, and other factors;

•The impact of public health crises, including epidemics and pandemics, on our business functions, financial condition, liquidity, and results of operations;

•Risks inherent in electric generation and distribution and natural gas transportation, distribution, and storage activities, including leaks, accidental explosions, mechanical problems, fires, discharges or releases of toxic or hazardous substances or gases, and risks related to the ability to obtain adequate insurance to cover such events;

•Factors affecting the achievement of our CO2 emission reduction goal and related opportunities and actions, including related regulatory decisions, the cost of materials, supplies, and labor, technology advances, significant increases in demand, the feasibility of competing generation projects, reliability, and our ability to execute our capital plan;

•The risks associated with inflation and changing commodity prices, including natural gas and electricity;

•The availability and cost of sources of natural gas and other fossil fuels, purchased power, materials needed to operate environmental controls at our electric generating facilities, or water supply due to high demand, shortages, transportation problems, nonperformance by electric energy or natural gas suppliers under existing power purchase or natural gas supply contracts, or other developments;

•Any impacts on the global economy, including from sanctions, and impacts on supply chains and fuel prices, generally, from increasing tensions between the United States and other countries, such as the war with Iran, or from other new, protracted or escalating regional or international conflicts;

•Changes in credit ratings, interest rates, and our ability to access the capital markets, caused by volatility in the global markets, our capitalization structure, and market perceptions of the utility industry, us, or any of our subsidiaries;

•Costs and effects of litigation, administrative proceedings, investigations, settlements, claims, and inquiries;

•The direct or indirect effect on our business resulting from terrorist or other physical attacks and cybersecurity intrusions, as well as the threat of such incidents, including the failure to maintain the security of personally identifiable information, the associated costs to protect our utility assets, technology systems, and personal information, and the costs to notify affected persons to mitigate their information security concerns and to comply with state notification laws;

•Restrictions imposed by various financing arrangements and regulatory requirements on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans or advances, that could prevent us from paying our common stock dividends, taxes, and other expenses, and meeting our debt obligations;

•The risk of financial loss, including increases in bad debt expense, associated with the inability of our customers, counterparties, and affiliates to meet their obligations;

•Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including data centers and other large-scale customers, participants in the energy trading markets and fuel suppliers and transporters;

•The financial performance of ATC and its corresponding contribution to our earnings;

•The investment performance of our employee benefit plan assets, as well as unanticipated changes in related actuarial assumptions, which could impact future funding requirements;

•Factors affecting the employee workforce, including loss of key personnel, internal restructuring, work stoppages, and collective bargaining agreements and negotiations with union employees;

09/30/2026 Form 10-Q			2			WEC Energy Group, Inc.

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•Advances in technology, and related legislation or regulation supporting the use of that technology, that result in competitive disadvantages and create the potential for impairment of existing assets;

•Risks involved in developing and implementing AI, including data privacy concerns or other legal liability, new or enhanced governmental or regulatory scrutiny or regulations governing the use of AI, the ability to meet expectations or requirements relating to adoption or implementation of AI technology, or other complications related to the use of AI;

•Risks related to our non-utility renewable energy facilities, including unfavorable weather, changes in the financial performance and/or creditworthiness of counterparties to the off-take agreements, changes in demand based on lower prices for alternative energy sources, pricing differentials between the facilities' point of interconnection and our required delivery location, the ability to replace expiring PPAs under acceptable terms, rights to property on which our projects are located but we do not own, the availability of reliable interconnection and electricity grids, the performance and quality of the wind turbine and solar panel components and availability of replacement parts, and exposure to the rules and procedures of the power markets in which these facilities are located;

•The risk associated with the values of goodwill and other long-lived assets, including intangible assets, and equity method investments and their possible impairment;

•Potential business strategies to acquire and dispose of assets or businesses, or portions thereof, which cannot be assured to be completed timely or within budgets, and legislative or regulatory restrictions or caps on non-utility acquisitions, investments or projects, including the State of Wisconsin's public utility holding company law;

•The timing and outcome of any audits, disputes, and other proceedings related to taxes;

•The effect of accounting pronouncements issued periodically by standard-setting bodies; and

•Other considerations disclosed elsewhere herein and in other reports we file with the SEC or in other publicly disseminated written documents.

Except as may be required by law, we expressly disclaim any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

09/30/2026 Form 10-Q			3			WEC Energy Group, Inc.

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited)						Three Months Ended												Nine Months Ended
						September 30												September 30
(in millions, except per share amounts)						2026						2025						2026						2025
Operating revenues						$	2,290.6					$	2,104.0					$	7,786.9					$	7,263.0
Operating expenses
Cost of sales						651.2						608.1						2,597.8						2,344.3
Other operation and maintenance						614.4						605.1						1,840.2						1,809.3
Depreciation and amortization						389.0						373.4						1,153.7						1,102.2
Property and revenue taxes						72.3						67.8						218.7						215.2
Total operating expenses						1,726.9						1,654.4						5,810.4						5,471.0
Operating income						563.7						449.6						1,976.5						1,792.0
Equity in earnings of transmission affiliates						65.8						54.8						187.9						160.3
Other income, net						49.5						23.8						159.2						68.4
Interest expense						241.7						223.6						699.1						667.4
Other expense						(126.4)						(145.0)						(352.0)						(438.7)
Income before income taxes						437.3						304.6						1,624.5						1,353.3
Income tax expense						47.0						34.4						127.1						114.6
Net income						390.3						270.2						1,497.4						1,238.7
Preferred stock dividends of subsidiary						0.3						0.3						0.9						0.9
Net (income) loss attributed to noncontrolling interests						(0.7)						1.4						(3.6)						3.1
Net income attributed to common shareholders						$	389.3					$	271.3					$	1,492.9					$	1,240.9
EPS
Basic						$	1.19					$	0.84					$	4.58					$	3.87
Diluted						$	1.18					$	0.83					$	4.54					$	3.85
Weighted average common shares outstanding
Basic						326.6						323.5						326.0						320.7
Diluted						328.8						325.6						328.7						322.4

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

09/30/2026 Form 10-Q			4			WEC Energy Group, Inc.

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WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)						Three Months Ended												Nine Months Ended
						September 30												September 30
(in millions)						2026						2025						2026						2025
Net income						$	390.3					$	270.2					$	1,497.4					$	1,238.7
Other comprehensive income (loss), net of tax
Derivatives accounted for as cash flow hedges
Reclassification of realized derivative gains to net income, net of tax						—						—						—						(0.2)
Defined benefit plans
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax						0.1						—						0.2						0.1
Other comprehensive income (loss), net of tax						0.1						—						0.2						(0.1)
Comprehensive income						390.4						270.2						1,497.6						1,238.6
Preferred stock dividends of subsidiary						0.3						0.3						0.9						0.9
Comprehensive (income) loss attributed to noncontrolling interests						(0.7)						1.4						(3.6)						3.1
Comprehensive income attributed to common shareholders						$	389.4					$	271.3					$	1,493.1					$	1,240.8

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

09/30/2026 Form 10-Q			5			WEC Energy Group, Inc.

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WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts)						September 30, 2026						December 31, 2025
Assets
Current assets
Cash and cash equivalents						$	58.8					$	27.6
Accounts receivable and unbilled revenues, net of reserves of $139.9 and $148.7, respectively						1,403.8						2,062.7
Materials, supplies, and inventories						865.2						803.4
Prepaid taxes						154.3						178.8
Other prepayments						45.7						92.4
Other						223.3						119.8
Current assets						2,751.1						3,284.7
Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $13,025.9 and $12,411.5, respectively						40,791.3						38,278.1
Regulatory assets (September 30, 2026 and December 31, 2025 include $60.9 and $67.5, respectively, related to WEPCo Environmental Trust)						3,140.7						3,156.3
Equity investment in transmission affiliates						2,497.0						2,280.4
Goodwill						3,052.8						3,052.8
Pension and OPEB assets						1,050.3						1,082.4
Other						614.3						383.6
Long-term assets						51,146.4						48,233.6
Total assets						$	53,897.5					$	51,518.3
Liabilities and Equity
Current liabilities
Short-term debt						$	1,904.3					$	1,924.7
Current portion of long-term debt (September 30, 2026 and December 31, 2025 include $9.4 and $9.3, respectively, related to WEPCo Environmental Trust)						1,134.5						1,519.4
Accounts payable						1,119.2						1,140.1
Other						1,031.5						1,009.2
Current liabilities						5,189.5						5,593.4
Long-term liabilities
Long-term debt (September 30, 2026 and December 31, 2025 include $62.8 and $67.4, respectively, related to WEPCo Environmental Trust)						19,717.2						18,498.1
Finance lease obligations						417.8						372.0
Deferred income taxes						6,341.0						5,891.7
Deferred revenue, net						300.3						314.2
Regulatory liabilities						4,292.2						4,121.3
Intangible liabilities						535.2						580.3
Environmental remediation liabilities						457.9						484.1
AROs						676.0						647.0
Other						960.3						963.4
Long-term liabilities						33,697.9						31,872.1
Commitments and contingencies (Note 22)
Common shareholders' equity
Common stock – $0.01 par value; 650,000,000 shares authorized; 328,992,329 and 325,461,519 shares outstanding, respectively						3.3						3.3
Additional paid in capital						5,523.9						5,124.4
Retained earnings						9,055.6						8,493.5
Accumulated other comprehensive loss						(7.4)						(7.6)
Common shareholders' equity						14,575.4						13,613.6
Preferred stock of subsidiary						30.4						30.4
Noncontrolling interests						404.3						408.8
Total liabilities and equity						$	53,897.5					$	51,518.3

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

09/30/2026 Form 10-Q			6			WEC Energy Group, Inc.

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WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)						Nine Months Ended
						September 30
(in millions)						2026						2025
Operating activities
Net income						$	1,497.4					$	1,238.7
Reconciliation to cash provided by operating activities
Depreciation and amortization						1,153.7						1,102.2
Deferred income taxes and ITCs, net						335.7						296.2
AFUDC-Equity						(139.5)						(63.7)
Contributions and payments related to pension and OPEB plans						(10.5)						(10.3)
Equity income in transmission affiliates, net of distributions						(43.6)						(17.5)
Change in –
Accounts receivable and unbilled revenues, net						587.8						368.0
Materials, supplies, and inventories						(61.8)						(29.4)
Prepaid taxes						24.5						89.4
Other current assets						(14.3)						6.1
Accounts payable						(93.1)						(145.3)
Accrued interest						96.5						88.8
Other current liabilities						(25.4)						7.1
Other, net						105.7						24.5
Net cash provided by operating activities						3,413.1						2,954.8
Investing activities
Capital expenditures, including AFUDC-Debt						(3,318.7)						(3,120.0)
Acquisition of Hardin III, net of cash acquired of $— and $0.2, respectively						(3.0)						(406.1)
Capital contributions to transmission affiliates						(173.0)						(142.4)
Payment for option to acquire projects						(170.8)						—
Proceeds from the sale of assets						23.3						5.1
Proceeds from the sale of investments held in rabbi trust						2.9						16.9
Reimbursement for ATC's transmission infrastructure upgrades						10.4						39.7
Other, net						29.1						36.3
Net cash used in investing activities						(3,599.8)						(3,570.5)
Financing activities
Exercise of stock options						9.9						37.6
Issuance of common stock, net						382.5						746.6
Dividends paid on common stock						(930.8)						(857.4)
Issuance of long-term debt						2,395.6						1,944.6
Retirement of long-term debt						(1,558.5)						(1,285.9)
Change in commercial paper						(21.9)						141.7
Payments for debt issuance costs						(20.8)						(28.9)
Other, net						(9.7)						(7.1)
Net cash provided by financing activities						246.3						691.2
Net change in cash, cash equivalents, and restricted cash						59.6						75.5
Cash, cash equivalents, and restricted cash at beginning of period						70.9						42.2
Cash, cash equivalents, and restricted cash at end of period						$	130.5					$	117.7

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

09/30/2026 Form 10-Q			7			WEC Energy Group, Inc.

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WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited)
						WEC Energy Group Common Shareholders' Equity
(in millions, except per share amounts)						Common Stock						Additional Paid In Capital						Retained Earnings						Accumulated Other Comprehensive Loss						Total Common Shareholders' Equity						Preferred Stock of Subsidiary						Non-controlling Interests						Total Equity
Balance at December 31, 2025						$	3.3					$	5,124.4					$	8,493.5					$	(7.6)					$	13,613.6					$	30.4					$	408.8					$	14,052.8
Net income attributed to common shareholders						—						—						804.4						—						804.4						—						—						804.4
Net income attributed to noncontrolling interests						—						—						—						—						—						—						1.4						1.4
Other comprehensive income						—						—						—						0.1						0.1						—						—						0.1
Issuance of common stock, net						—						12.8						—						—						12.8						—						—						12.8
Common stock dividends of $0.9525 per share						—						—						(310.1)						—						(310.1)						—						—						(310.1)
Exercise of stock options						—						7.4						—						—						7.4						—						—						7.4
Capital contributions from noncontrolling interest						—						—						—						—						—						—						0.8						0.8
Distributions to noncontrolling interests						—						—						—						—						—						—						(3.1)						(3.1)
Stock-based compensation and other						—						2.8						—						—						2.8						—						—						2.8
Balance at March 31, 2026						$	3.3					$	5,147.4					$	8,987.8					$	(7.5)					$	14,131.0					$	30.4					$	407.9					$	14,569.3
Net income attributed to common shareholders						—						—						299.2						—						299.2						—						—						299.2
Net income attributed to noncontrolling interests						—						—						—						—						—						—						1.5						1.5
Issuance of common stock, net						—						11.0						—						—						11.0						—						—						11.0
Common stock dividends of $0.9525 per share						—						—						(310.2)						—						(310.2)						—						—						(310.2)
Exercise of stock options						—						1.7						—						—						1.7						—						—						1.7
Distributions to noncontrolling interests						—						—						—						—						—						—						(2.1)						(2.1)
Stock-based compensation and other						—						2.2						—						—						2.2						—						0.4						2.6
Balance at June 30, 2026						$	3.3					$	5,162.3					$	8,976.8					$	(7.5)					$	14,134.9					$	30.4					$	407.7					$	14,573.0
Net income attributed to common shareholders						—						—						389.3						—						389.3						—						—						389.3
Net income attributed to noncontrolling interests						—						—						—						—						—						—						0.7						0.7
Other comprehensive income						—						—						—						0.1						0.1						—						—						0.1
Issuance of common stock, net						—						358.7						—						—						358.7						—						—						358.7
Common stock dividends of $0.9525 per share						—						—						(310.5)						—						(310.5)						—						—						(310.5)
Exercise of stock options						—						0.8						—						—						0.8						—						—						0.8
Distributions to noncontrolling interests						—						—						—						—						—						—						(4.1)						(4.1)
Stock-based compensation and other						—						2.1						—						—						2.1						—						—						2.1
Balance at September 30, 2026						$	3.3					$	5,523.9					$	9,055.6					$	(7.4)					$	14,575.4					$	30.4					$	404.3					$	15,010.1

09/30/2026 Form 10-Q			8			WEC Energy Group, Inc.

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						WEC Energy Group Common Shareholders' Equity
(in millions, except per share amounts)						Common Stock						Additional Paid In Capital						Retained Earnings						Accumulated Other Comprehensive Loss						Total Common Shareholders' Equity						Preferred Stock of Subsidiary						Non-controlling Interests						Total Equity
Balance at December 31, 2024						$	3.2					$	4,315.8					$	8,083.8					$	(7.8)					$	12,395.0					$	30.4					$	376.5					$	12,801.9
Net income attributed to common shareholders						—						—						724.2						—						724.2						—						—						724.2
Net income attributed to noncontrolling interests						—						—						—						—						—						—						1.0						1.0
Other comprehensive loss						—						—						—						(0.1)						(0.1)						—						—						(0.1)
Issuance of common stock, net						—						117.1						—						—						117.1						—						—						117.1
Common stock dividends of $0.8925 per share						—						—						(283.6)						—						(283.6)						—						—						(283.6)
Exercise of stock options						—						21.2						—						—						21.2						—						—						21.2
Acquisition of noncontrolling interests						—						—						—						—						—						—						45.1						45.1
Distributions to noncontrolling interests						—						—						—						—						—						—						(1.8)						(1.8)
Stock-based compensation and other						—						2.0						—						—						2.0						—						—						2.0
Balance at March 31, 2025						$	3.2					$	4,456.1					$	8,524.4					$	(7.9)					$	12,975.8					$	30.4					$	420.8					$	13,427.0
Net income attributed to common shareholders						—						—						245.4						—						245.4						—						—						245.4
Net loss attributed to noncontrolling interests						—						—						—						—						—						—						(2.7)						(2.7)
Issuance of common stock, net						—						281.7						—						—						281.7						—						—						281.7
Common stock dividends of $0.8925 per share						—						—						(285.1)						—						(285.1)						—						—						(285.1)
Exercise of stock options						—						3.5						—						—						3.5						—						—						3.5
Distributions to noncontrolling interests						—						—						—						—						—						—						(1.5)						(1.5)
Stock-based compensation and other						—						1.8						—						—						1.8						—						—						1.8
Balance at June 30, 2025						$	3.2					$	4,743.1					$	8,484.7					$	(7.9)					$	13,223.1					$	30.4					$	416.6					$	13,670.1
Net income attributed to common shareholders						—						—						271.3						—						271.3						—						—						271.3
Net loss attributed to noncontrolling interests						—						—						—						—						—						—						(1.4)						(1.4)
Issuance of common stock, net						—						347.8						—						—						347.8						—						—						347.8
Common stock dividends of $0.8925 per share						—						—						(288.7)						—						(288.7)						—						—						(288.7)
Exercise of stock options						—						12.9						—						—						12.9						—						—						12.9
Distributions to noncontrolling interests						—						—						—						—						—						—						(3.2)						(3.2)
Stock-based compensation and other						—						2.0						—						—						2.0						—						—						2.0
Balance at September 30, 2025						$	3.2					$	5,105.8					$	8,467.3					$	(7.9)					$	13,568.4					$	30.4					$	412.0					$	14,010.8

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

09/30/2026 Form 10-Q			9			WEC Energy Group, Inc.

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WEC ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

September 30, 2026

NOTE 1—GENERAL INFORMATION

WEC Energy Group serves approximately 1.7 million electric customers and 3.1 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 condensed 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. In this report, when we refer to "the Company," "us," "we," "our," or "ours," we are referring to WEC Energy Group and all of its subsidiaries.

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 sheets related to the minority interests held by third parties in the renewable generating facilities that are included in our non-utility energy infrastructure segment.

We use the equity method to account for investments in companies we do not control but over which we exercise significant influence regarding their operating and financial policies. As a result of our limited voting rights, we account for ATC and ATC Holdco as equity method investments. See Note 19, Investment in Transmission Affiliates, for more information.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2025. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and nine months ended September 30, 2026, are not necessarily indicative of expected results for 2026 due to seasonal variations and other factors.

In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results.

NOTE 2—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 the below acquisitions met the criteria of asset acquisitions. The purchase price of the Hardin III acquisition discussed below includes intangibles recorded as long-term liabilities related to PPAs. See Note 18, Goodwill and Intangibles, for more information.

Pending Acquisitions of Electric Generation Facilities in Wisconsin

WE filed for PSCW approval to purchase a 30% ownership interest in Weston Unit 4, an approximately 500 MW supercritical pulverized coal base-load electric generating facility located in the Villages of Kronenwetter and Rothschild, Wisconsin and the Town of Knowlton, Wisconsin. WPS currently owns a 70% interest in this facility. Pursuant to the asset purchase agreement, WE would purchase the remaining 30% interest currently owned by an unrelated third-party for its book value at the closing date, currently estimated at $150 million. If approved, it is anticipated that the transaction would close in the first half of 2027.

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

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Acquisition of a Solar Generation Facility in Ohio

Upon commercial operation in February 2025, WECI completed the acquisition of a 90% ownership interest in Hardin III, a 250 MW solar generating facility located in Hardin County, Ohio for $409.1 million. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years from the date of commercial operation. Hardin III qualifies for PTCs and is included in the non-utility energy infrastructure segment.

NOTE 3—DISPOSITION

Illinois Segment

Sale of Certain Real Estate by The Peoples Gas Light and Coke Company

In January 2026, we sold approximately 15 acres of real estate owned by PGL that was no longer being utilized in its operations, for $20.9 million, which is net of selling costs. The real estate was located in Chicago, Illinois. As a result of the sale, a pre-tax gain in the amount of $11.9 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.

NOTE 4—OPERATING REVENUES

For more information about our operating revenues, see Note 1(d), Operating Revenues, in our 2025 Annual Report on Form 10-K.

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
Three Months Ended September 30, 2026
Electric						$	1,767.6					$	—					$	—					$	1,767.6					$	—					$	—					$	—					$	1,767.6
Natural gas						155.0						177.9						54.9						387.8						10.0						—						(9.7)						388.1
Total regulated revenues						1,922.6						177.9						54.9						2,155.4						10.0						—						(9.7)						2,155.7
Other non-utility revenues						—						—						5.8						5.8						68.4						—						(1.6)						72.6
Total revenues from contracts with customers						1,922.6						177.9						60.7						2,161.2						78.4						—						(11.3)						2,228.3
Other operating revenues						42.1						5.3						0.2						47.6						122.5						—						(107.8)			(1)			62.3
Total operating revenues						$	1,964.7					$	183.2					$	60.9					$	2,208.8					$	200.9					$	—					$	(119.1)					$	2,290.6

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(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Non-Utility Energy Infrastructure						Corporate and Other						Reconciling Eliminations						WEC Energy Group Consolidated
Three Months Ended September 30, 2025
Electric						$	1,608.6					$	—					$	—					$	1,608.6					$	—					$	—					$	—					$	1,608.6
Natural gas						179.5						185.2						47.9						412.6						10.4						—						(9.7)						413.3
Total regulated revenues						1,788.1						185.2						47.9						2,021.2						10.4						—						(9.7)						2,021.9
Other non-utility revenues						—						—						5.5						5.5						62.5						—						(1.6)						66.4
Total revenues from contracts with customers						1,788.1						185.2						53.4						2,026.7						72.9						—						(11.3)						2,088.3
Other operating revenues						3.5						(1.7)						(0.4)						1.4						120.4						—						(106.1)			(1)			15.7
Total operating revenues						$	1,791.6					$	183.5					$	53.0					$	2,028.1					$	193.3					$	—					$	(117.4)					$	2,104.0

(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Non-Utility Energy Infrastructure						Corporate and Other						Reconciling Eliminations						WEC Energy Group Consolidated
Nine Months Ended September 30, 2026
Electric						$	4,546.8					$	—					$	—					$	4,546.8					$	—					$	—					$	—					$	4,546.8
Natural gas						1,306.0						1,133.3						386.3						2,825.6						33.7						—						(32.8)						2,826.5
Total regulated revenues						5,852.8						1,133.3						386.3						7,372.4						33.7						—						(32.8)						7,373.3
Other non-utility revenues						—						—						16.8						16.8						227.0						—						(7.1)						236.7
Total revenues from contracts with customers						5,852.8						1,133.3						403.1						7,389.2						260.7						—						(39.9)						7,610.0
Other operating revenues						71.7						61.8						(0.6)						132.9						366.5						—						(322.5)			(1)			176.9
Total operating revenues						$	5,924.5					$	1,195.1					$	402.5					$	7,522.1					$	627.2					$	—					$	(362.4)					$	7,786.9

(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Non-Utility Energy Infrastructure						Corporate and Other						Reconciling Eliminations						WEC Energy Group Consolidated
Nine Months Ended September 30, 2025
Electric						$	4,231.7					$	—					$	—					$	4,231.7					$	—					$	—					$	—					$	4,231.7
Natural gas						1,190.7						1,225.0						348.1						2,763.8						35.9						—						(33.7)						2,766.0
Total regulated revenues						5,422.4						1,225.0						348.1						6,995.5						35.9						—						(33.7)						6,997.7
Other non-utility revenues						—						—						16.4						16.4						182.1						—						(7.1)						191.4
Total revenues from contracts with customers						5,422.4						1,225.0						364.5						7,011.9						218.0						—						(40.8)						7,189.1
Other operating revenues						16.3						17.4						(2.1)						31.6						359.0						—						(316.7)			(1)			73.9
Total operating revenues						$	5,438.7					$	1,242.4					$	362.4					$	7,043.5					$	577.0					$	—					$	(357.5)					$	7,263.0

(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.

09/30/2026 Form 10-Q			12			WEC Energy Group, Inc.

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Revenues from Contracts with Customers

Electric Utility Operating Revenues

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

						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2026						2025						2026						2025
Residential						$	712.1					$	658.1					$	1,814.4					$	1,715.0
Small commercial and industrial						531.8						498.8						1,428.7						1,343.2
Large commercial and industrial (1)						363.6						318.8						924.2						814.9
Other						7.2						7.5						22.6						22.9
Total retail revenues						1,614.7						1,483.2						4,189.9						3,896.0
Wholesale						29.1						30.7						86.6						84.2
Resale						111.0						84.3						228.1						212.8
Steam						3.3						2.2						22.5						20.6
Other utility revenues						9.5						8.2						19.7						18.1
Total electric utility operating revenues						$	1,767.6					$	1,608.6					$	4,546.8					$	4,231.7

(1)    Includes the revenues from VLCs.

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
Three Months Ended September 30, 2026
Residential						$	89.7					$	101.3					$	27.0					$	218.0
Commercial and industrial						43.9						31.5						13.6						89.0
Total retail revenues						133.6						132.8						40.6						307.0
Transportation						20.9						42.0						7.0						69.9
Other utility revenues (1)						0.5						3.1						7.3						10.9
Total natural gas utility operating revenues						$	155.0					$	177.9					$	54.9					$	387.8

(in millions)						Wisconsin						Illinois						Other States						Total Natural Gas Utility Operating Revenues
Three Months Ended September 30, 2025
Residential						$	84.4					$	115.9					$	25.8					$	226.1
Commercial and industrial						40.9						32.7						13.8						87.4
Total retail revenues						125.3						148.6						39.6						313.5
Transportation						20.1						43.5						6.8						70.4
Other utility revenues (1)						34.1						(6.9)						1.5						28.7
Total natural gas utility operating revenues						$	179.5					$	185.2					$	47.9					$	412.6

(in millions)						Wisconsin						Illinois						Other States						Total Natural Gas Utility Operating Revenues
Nine Months Ended September 30, 2026
Residential						$	815.2					$	725.4					$	223.6					$	1,764.2
Commercial and industrial						407.4						211.6						118.8						737.8
Total retail revenues						1,222.6						937.0						342.4						2,502.0
Transportation						79.6						186.2						28.5						294.3
Other utility revenues (1)						3.8						10.1						15.4						29.3
Total natural gas utility operating revenues						$	1,306.0					$	1,133.3					$	386.3					$	2,825.6

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(in millions)						Wisconsin						Illinois						Other States						Total Natural Gas Utility Operating Revenues
Nine Months Ended September 30, 2025
Residential						$	733.5					$	725.4					$	214.5					$	1,673.4
Commercial and industrial						369.2						211.6						109.0						689.8
Total retail revenues						1,102.7						937.0						323.5						2,363.2
Transportation						76.0						186.2						27.9						290.1
Other utility revenues (1)						12.0						10.1						(3.3)						18.8
Total natural gas utility operating revenues						$	1,190.7					$	1,133.3					$	348.1					$	2,672.1

(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, compared with the recovery of natural gas costs that were included in rates.

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. All amounts associated with the service agreements with WE, WPS, and WG have been eliminated at the consolidated level.

Other Non-Utility Operating Revenues

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

						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2026						2025						2026						2025
Renewable generation revenues						$	60.6					$	54.7					$	201.3					$	156.6
We Power revenues (1)						6.2						6.2						18.6						18.4
Appliance service revenues						5.8						5.5						16.8						16.4
Total other non-utility operating revenues						$	72.6					$	66.4					$	236.7					$	191.4

(1)As part of the construction of the We Power electric utility 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.

Other Operating Revenues

Other operating revenues consist of the following:

						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2026						2025						2026						2025
Bespoke Resources current return (1)						$	38.3					$	—					$	53.4					$	—
Amortization of revenue intangibles (2)						14.7						14.3						44.0						42.3
Late payment charges						12.3						10.4						43.5						38.1
Alternative revenues (3)						(3.5)						(9.6)						33.5						(9.6)
Other						0.5						0.6						2.5						3.1
Total other operating revenues						$	62.3					$	15.7					$	176.9					$	73.9

(1)    Consists of revenues related to carrying costs recognized during the construction of certain Bespoke Resources assigned to WE's VLCs. Consistent with the timing of when we recognize revenue, customer billings for the Bespoke Resources that are subject to current return (as opposed to AFUDC) occur on a monthly basis. For more information about the Bespoke Resources current return, see Note 1(d), Operating Revenues, in our 2025 Annual Report on Form 10-K.

(2)    We account for our asset acquisitions by recognizing identifiable intangible assets and liabilities assumed at fair value at the acquisition date. Amortization of these intangible assets and liabilities, which relate to PPAs and a proxy revenue swap, is recognized on a straight-line basis over

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the remaining contract term as a decrease or increase to operating revenues, respectively. See Note 18, Goodwill and Intangibles, for more information.

(3)    Alternative revenues consist of amounts to be recovered or refunded to customers subject to decoupling mechanisms, wholesale true-ups, and conservation improvement rider true-ups. Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. For more information about our alternative revenues, see Note 1(d), Operating Revenues, in our 2025 Annual Report on Form 10-K.

NOTE 5—CREDIT LOSSES

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

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

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

We monitor our ongoing credit exposure through active review of counterparty accounts receivable balances against contract terms and due dates. Our activities include timely account reconciliation, dispute resolution and payment confirmation. To the extent possible, we work with customers with past due balances to negotiate payment plans, but will disconnect customers for non-payment as allowed by our regulators, if necessary, and employ collection agencies and legal counsel to pursue recovery of defaulted receivables. For our larger customers, detailed credit review procedures may be performed in advance of any sales being made. We sometimes require letters of credit, parental guarantees, prepayments or other forms of credit assurance from our larger customers, including VLCs, to mitigate credit risk. See Note 24, Regulatory Environment, for more information about the VLC and Bespoke Resources tariffs.

We have included tables below that show our gross third-party receivable balances and the related allowance for credit losses at September 30, 2026 and December 31, 2025, by reportable segment.

(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Non-Utility Energy Infrastructure						Corporate and Other						WEC Energy Group Consolidated
September 30, 2026
Accounts receivable and unbilled revenues						$	1,096.9					$	341.5					$	53.9					$	1,492.3					$	45.2					$	6.2					$	1,543.7
Allowance for credit losses						55.2						80.5						4.2						139.9						—						—						139.9
Accounts receivable and unbilled revenues, net (1)						$	1,041.7					$	261.0					$	49.7					$	1,352.4					$	45.2					$	6.2					$	1,403.8
Total accounts receivable, net – past due greater than 90 days (1)						$	57.6					$	59.9					$	7.3					$	124.8					$	—					$	—					$	124.8
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)						94.0		%				100.0		%				—		%				91.4		%				—		%				—		%				91.4		%

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(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Non-Utility Energy Infrastructure						Corporate and Other						WEC Energy Group Consolidated
December 31, 2025
Accounts receivable and unbilled revenues						$	1,368.8					$	654.8					$	130.2					$	2,153.8					$	50.3					$	7.3					$	2,211.4
Allowance for credit losses						61.7						82.3						4.7						148.7						—						—						148.7
Accounts receivable and unbilled revenues, net (1)						$	1,307.1					$	572.5					$	125.5					$	2,005.1					$	50.3					$	7.3					$	2,062.7
Total accounts receivable, net – past due greater than 90 days (1)						$	46.4					$	36.8					$	6.6					$	89.8					$	—					$	—					$	89.8
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)						94.6		%				100.0		%				—		%				89.9		%				—		%				—		%				89.9		%

(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 September 30, 2026, $842.4 million, or 60.0%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. See Note 24, Regulatory Environment, for more information on PGL and NSG's UEA rider for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and amounts recovered in rates.

A roll-forward of the allowance for credit losses by reportable segment is included below:

Three Months Ended September 30, 2026 (in millions)						Wisconsin						Illinois						Other States						WEC Energy Group Consolidated
Balance at July 1, 2026						$	61.2					$	83.7					$	4.0					$	148.9
Provision for credit losses						51.5						11.7						1.0						64.2
Provision for credit losses deferred for future recovery or refund						(33.6)						(8.2)						—						(41.8)
Write-offs charged against the allowance						(36.1)						(12.9)						(1.2)						(50.2)
Recoveries of amounts previously written off						12.2						6.2						0.4						18.8
Balance at September 30, 2026						$	55.2					$	80.5					$	4.2					$	139.9

Nine Months Ended September 30, 2026 (in millions)						Wisconsin						Illinois						Other States						WEC Energy Group Consolidated
Balance at January 1, 2026						$	61.7					$	82.3					$	4.7					$	148.7
Provision for credit losses						150.8						41.0						1.3						193.1
Provision for credit losses deferred for future recovery or refund						(84.7)						(7.9)						—						(92.6)
Write-offs charged against the allowance						(112.0)						(55.0)						(3.0)						(170.0)
Recoveries of amounts previously written off						39.4						20.1						1.2						60.7
Balance at September 30, 2026						$	55.2					$	80.5					$	4.2					$	139.9

Three Months Ended September 30, 2025 (in millions)						Wisconsin						Illinois						Other States						WEC Energy Group Consolidated
Balance at July 1, 2025						$	52.3					$	84.6					$	5.3					$	142.2
Provision for credit losses						21.8						11.6						(0.6)						32.8
Provision for credit losses deferred for future recovery or refund						(1.0)						(25.1)						—						(26.1)
Write-offs charged against the allowance						(35.7)						(12.2)						(5.0)						(52.9)
Recoveries of amounts previously written off						11.3						17.7						4.5						33.5
Balance at September 30, 2025						$	48.7					$	76.6					$	4.2					$	129.5

09/30/2026 Form 10-Q			16			WEC Energy Group, Inc.

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Nine Months Ended September 30, 2025 (in millions)						Wisconsin						Illinois						Other States						WEC Energy Group Consolidated
Balance at January 1, 2025						$	73.6					$	83.9					$	5.3					$	162.8
Provision for credit losses						59.6						41.3						(0.1)						100.8
Provision for credit losses deferred for future recovery or refund						(14.0)						(39.4)						—						(53.4)
Write-offs charged against the allowance						(108.0)						(53.5)						(6.3)						(167.8)
Recoveries of amounts previously written off						37.5						44.3						5.3						87.1
Balance at September 30, 2025						$	48.7					$	76.6					$	4.2					$	129.5

On a consolidated basis, there was a $8.8 million decrease in the allowance for credit losses at September 30, 2026, compared to January 1, 2026. This decrease was largely driven by customer write-offs in Wisconsin and a decrease in past due accounts in both Wisconsin and Illinois that we believe was related to a continued focus on collection efforts and lower energy bills in the spring and summer months, enabling customers to pay down their arrears.

On a consolidated basis, there was a $33.3 million decrease in the allowance for credit losses at September 30, 2025, compared to January 1, 2025. This decrease was largely driven by customer write-offs in Wisconsin in addition to a decrease in past due account balances in Wisconsin that we believe was related to a continued focus on collection efforts and lower energy bills in the spring and summer months, enabling customers to pay down their arrears. Also, the allowance for credit losses in Illinois decreased based on the lower accounts receivable balance at the end of the period.

NOTE 6—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets and liabilities were reflected on our balance sheets at September 30, 2026 and December 31, 2025. For more information on our regulatory assets and liabilities, see Note 6, Regulatory Assets and Liabilities, in our 2025 Annual Report on Form 10-K.

(in millions)						September 30, 2026						December 31, 2025
Regulatory assets
Plant retirement related items						$	722.1					$	768.6
Income tax related items						549.8						493.4
Environmental remediation costs						538.2						566.0
Pension and OPEB costs						506.5						564.5
AROs						215.0						185.1
Electric transmission costs						100.0						30.7
System support resource						85.0						92.6
Decoupling						78.7						43.8
Derivatives						66.2						57.7
Securitization						60.9						67.5
Uncollectible expense						49.3						123.9
Finance and operating leases						48.6						36.0
Revenue requirements of generation facilities (1)						27.8						4.2
Bluewater						22.2						37.7
Other, net						116.6						101.9
Total regulatory assets						$	3,186.9					$	3,173.6
Balance sheet presentation
Other current assets						$	46.2					$	17.3
Regulatory assets						3,140.7						3,156.3
Total regulatory assets						$	3,186.9					$	3,173.6

(1)These amounts primarily represent the deferral of the incremental revenue requirement of incurred costs resulting from changes to the retirement of certain generation facilities.

09/30/2026 Form 10-Q			17			WEC Energy Group, Inc.

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(in millions)						September 30, 2026						December 31, 2025
Regulatory liabilities
Income tax related items						$	1,770.4					$	1,802.4
Removal costs						1,689.2						1,584.7
Pension and OPEB benefits						296.3						301.5
Energy costs refundable through rate adjustments						147.0						119.2
Settlement related to QIP and UEA riders						125.0						125.0
Uncollectible expense						93.4						73.1
Earnings sharing mechanisms						48.1						35.8
Derivatives						38.5						27.4
MERC property tax tracker						29.2						23.1
We Power escrowed costs (1)						20.1						15.1
Other, net						120.7						102.9
Total regulatory liabilities						$	4,377.9					$	4,210.2
Balance sheet presentation
Other current liabilities						$	85.7					$	88.9
Regulatory liabilities						4,292.2						4,121.3
Total regulatory liabilities						$	4,377.9					$	4,210.2

(1)We defer as a regulatory asset or liability the difference between actual costs associated with the We Power generation units and those included in rates until recovery or refund is authorized in a future rate proceeding.

NOTE 7—PROPERTY, PLANT, AND EQUIPMENT

Wisconsin Segment Plant to be Retired

Oak Creek Power Plant Units 7-8

The retirement of OCPP Units 7 and 8 became probable at the end of 2022, following initial PSCW approvals for replacement generation. On April 1, 2026, we announced plans to extend the operating lives of OCPP Units 7 and 8, and expect to have the units available to meet high energy demand periods through 2027. These units were previously scheduled to be retired at the end of 2026. The decision to postpone the retirement dates for these units is based on two critical factors, reliability and affordability for WE’s customers. This past winter the Midwest power market experienced tightened energy supply and higher energy costs during extreme temperatures. Keeping OCPP Units 7 and 8 available will better position WE to serve customers with safe, reliable and affordable energy on the hottest and coldest days of the year. The extension of these units will serve as a bridge until new dispatchable generation begins to come online, which is expected in late 2027.

The total net book value of OCPP Units 7 and 8 was $595.7 million at September 30, 2026, 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.

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

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

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

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2025 storm was increased from $8.8 million to $12.0 million in the third quarter of 2025 based on finalization of the damage assessment.

In addition, in June 2026, our Delilah I solar facility experienced minor damage from a storm, resulting in the recognition of a $1.7 million impairment loss within other operation and maintenance in the second quarter of 2026. In the third quarter of 2026, we increased the impairment by $1.3 million to $3.0 million based on finalization of the damage assessment.

As a result of storm damage sustained over the past several years, we have undertaken storm hardening efforts at both our Samson I and Delilah I solar facilities, and those efforts remain ongoing.

The Peoples Gas Light and Coke Company Impairment

In the fourth quarter of 2025, PGL recorded a $130.0 million impairment to property, plant, and equipment related to the terms of a proposed settlement that was finalized in May 2026, resolving its open proceedings related to the QIP Rider. See Note 24, Regulatory Environment, for more information.

NOTE 8—COMMON EQUITY

Stock-Based Compensation

During the nine months ended September 30, 2026, the Compensation Committee of our Board of Directors awarded the following stock-based compensation to our directors, officers, and certain other key employees:

Award Type						Number of Awards
Stock options (1)						269,085
Restricted shares (2)						75,222
Performance units						182,146

(1)Stock options awarded had a weighted-average exercise price of $106.09 and a weighted-average grant date fair value of $21.20 per option.

(2)Restricted shares awarded had a weighted-average grant date fair value of $106.09 per share.

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 LLC (which holds our ownership interest in ATC), 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. Our utility subsidiaries, with the exception of UMERC and MGU, are prohibited from loaning funds to us, either directly or indirectly. See Note 11, Common Equity, in our 2025 Annual Report on Form 10-K for additional information on these and other restrictions.

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

Common Stock

We issue new shares of common stock to fulfill our obligations under various stock-based employee benefit and compensation plans and to provide shares to participants in our dividend reinvestment and stock purchase plan.

In August 2024, we entered into an EDA, under which we could offer and sell, from time to time, shares of our common stock having an aggregate sales price of up to $1.5 billion through an at-the-market offering program. In October 2025, we terminated this EDA and entered into a new EDA, under which we may offer and sell, from time to time, shares of our common stock having an aggregate sales price of up to $3.0 billion through an at-the-market offering program. This EDA also includes an equity forward sales component and a collared forward sales component. We may offer and sell our common shares through the sales agents party to the EDA during the term of the agreement. The October 2025 EDA will terminate upon the earliest of (i) the sale of all common stock subject to the EDA, (ii) termination of the EDA pursuant to its terms, or (iii) October 31, 2028. Actual sales of common stock under

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the EDA will depend on a variety of factors, including market conditions, the trading price of our common stock, capital needs, and our determination of the appropriate sources of funding. Any shares offered and sold under our October 2025 EDA will be done pursuant to our registration statement on Form S-3 filed with the SEC on August 5, 2024 and the related prospectus supplements.

We have entered into several forward sales contracts under our October 2025 EDA. The following table presents information related to the common stock sold under our outstanding forward sales contracts at September 30, 2026:

Forward Sale Contract Effective Date						Maturity Date						Shares						Initial Forward Price (1)
First quarter - 2026						September 30, 2027						757,000						$	114.0796
Second quarter - 2026						December 31, 2027						2,607,398						111.4073
Third quarter - 2026						March 31, 2028						3,644,019						106.4837

(1)Amount represents the weighted-average initial forward price of the forward sales contracts that became effective during the quarter. The initial forward price is subject to adjustment on a daily basis based on a floating interest rate factor and will decrease by other fixed amounts as specified in the contract.

No amounts are recorded on our balance sheet with respect to these contracts until actual settlement occurs. The contracts require us, at our election, to either (i) physically settle the transaction by issuing shares of our stock in exchange for net cash proceeds at the then-applicable forward sales price or (ii) net settle the transaction through the delivery or receipt of cash or shares in accordance with the contract provisions. At September 30, 2026, we could have settled our outstanding forward sales contracts as follows:

(Dollars in millions)						Physical Share Settlement						Net Settlement
Forward Sale Contract Effective Date						Cash Proceeds						Cash Proceeds						Shares Received
First quarter - 2026						$	86.3					$	10.0					99,328
Second quarter - 2026						290.5						27.7						275,004
Third quarter - 2026						387.6						20.3						201,862

During the third quarter of 2026, we physically settled various forward sales contracts that were entered into under our October 2025 EDA. As a result of these settlements, we issued 3,027,623 shares of common stock at a weighted-average net price of $114.79 per share. The net proceeds from the issuance were $347.5 million.

We had the following changes to our outstanding common stock during the three and nine months ended September 30, 2026 and 2025:

						Three Months Ended September 30												Nine Months Ended September 30
						2026						2025						2026						2025
Common stock shares outstanding at beginning of period						325,849,383						321,866,395						325,461,519						317,680,855
Shares issued:
At-the-market offering program						3,027,623						3,075,416						3,027,623						6,579,783
Stock-based compensation						10,987						196,997						185,299						587,111
401(k)						18,437						70,200						65,711						185,300
Stock investment plan						85,899						85,244						252,177						261,203
Common stock shares outstanding at end of period						328,992,329						325,294,252						328,992,329						325,294,252

On October 15, 2026, our Board of Directors declared a quarterly cash dividend of $0.9525 per share, payable on December 1, 2026, to shareholders of record on November 13, 2026.

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Earnings Per Share

The following table shows the computation of our basic and diluted EPS for the three and nine months ended September 30, 2026 and 2025:

						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2026						2025						2026						2025
Numerator:
Net income attributed to common shareholders						$	389.3					$	271.3					$	1,492.9					$	1,240.9
Denominator:
Weighted average basic shares outstanding						326.6						323.5						326.0						320.7
Dilutive effect of stock-based compensation awards						0.5						0.5						0.5						0.5
Dilutive effect of convertible senior notes						1.7						1.6						2.1						1.2
Dilutive effect of forward equity sales contracts						—						—						0.1						—
Weighted average diluted shares						328.8						325.6						328.7						322.4
Basic EPS						$	1.19					$	0.84					$	4.58					$	3.87
Diluted EPS						$	1.18					$	0.83					$	4.54					$	3.85

NOTE 9—SHORT-TERM DEBT AND LINES OF CREDIT

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

(in millions, except percentages)						September 30, 2026						December 31, 2025
Commercial paper
Amount outstanding						$	1,899.4					$	1,921.3
Weighted-average interest rate on amounts outstanding						4.16		%				3.89		%
Operating expense loans
Amount outstanding (1)						$	4.9					$	3.4

(1)Coyote Ridge Wind, LLC, Tatanka Ridge, Samson I, Thunderhead, 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 the nine months ended September 30, 2026 was $2,055.8 million with a weighted-average interest rate during the period of 3.97%.

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:

(in millions)						Maturity						September 30, 2026
WEC Energy Group						August 2030						$	1,700.0
WE						August 2030						800.0
PGL						August 2030						600.0
WPS						August 2030						450.0
WG						August 2030						350.0
Total short-term credit capacity												$	3,900.0
Less:
Letters of credit issued inside credit facilities												$	2.3
Commercial paper outstanding												1,899.4
Available capacity under existing agreements												$	1,998.3

09/30/2026 Form 10-Q			21			WEC Energy Group, Inc.

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NOTE 10—LONG-TERM DEBT

WEC Energy Group, Inc.

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

In February 2026, we issued an additional $400.0 million of our 4.75% Senior Notes due January 15, 2028, and used the net proceeds to repay short-term debt and for other general corporate purposes.

In September 2026, our $350.0 million of 5.60% Senior Notes due September 12, 2026, matured, and principal and accrued interest were paid with proceeds received from issuing commercial paper.

Convertible Senior Notes

As of September 30, 2026, the conditions allowing holders to convert their notes were not met. In accordance with the guidance in ASC Subtopic 470-20, Debt – Debt with Conversion and Other Options, the 2027 Notes, 2028 Notes, and 2029 Notes were accounted for in their entirety as a liability on our balance sheet. The following is a summary of our convertible debt instruments as of September 30, 2026:

(in millions)						Principal Amount						Unamortized Debt Issuance Costs						Net Carrying Amount						Fair Value Amount (1)
2027 Notes						$	862.5					$	(2.2)					$	860.3					$	922.6
2028 Notes						900.0						(5.9)						894.1						890.1
2029 Notes						862.5						(5.3)						857.2						955.2

(1)    The fair values are categorized in Level 2 of the fair value hierarchy. See Note 14, Fair Value Measurements, for more information on the levels of the fair value hierarchy.

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

						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2026						2025						2026						2025
2027 Notes
Contractual interest expense						$	9.4					$	9.4					$	28.3					$	28.3
Amortization of debt issuance costs						0.8						0.8						2.5						2.5
Total interest expense – 2027 Notes						10.2						10.2						30.8						30.8
2028 Notes
Contractual interest expense						7.6						7.6						22.8						9.4
Amortization of debt issuance costs						0.8						0.6						2.6						0.9
Total interest expense – 2028 Notes						$	8.4					$	8.2					$	25.4					$	10.3
2029 Notes
Contractual interest expense						9.4						9.4						28.3						28.3
Amortization of debt issuance costs						0.5						0.5						1.5						1.5
Total interest expense – 2029 Notes						$	9.9					$	9.9					$	29.8					$	29.8

Wisconsin Electric Power Company

In March 2026, WE issued $300.0 million of 5.65% Debentures, due March 15, 2056, and used the net proceeds to repay short-term debt and for other general corporate purposes.

In June 2026, WE issued $400.0 million of 4.65% Debentures, due June 15, 2031, and $400.0 million of 5.10% Debentures, due June 15, 2036, and used the net proceeds to repay short-term debt and for other general corporate purposes.

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In August 2026, WE issued an additional $300.0 million of its 5.10% Debentures, due June 15, 2036, and used the net proceeds to repay short-term debt and for other general corporate purposes.

Wisconsin Public Service Corporation

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

In August 2026, WPS issued $300.0 million of 6.05% Senior Notes, due August 15, 2056, and used the net proceeds to repay short-term debt and for other general corporate purposes.

Wisconsin Gas LLC

In October 2026, WG issued $50.0 million of 5.60% Debentures, due November 1, 2031, and $50.0 million of 5.90% Debentures, due November 1, 2036, and used the net proceeds to repay short-term debt and for other general corporate purposes

The Peoples Gas Light and Coke Company

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 $100.0 million of collateralized First Mortgage Bonds. In February 2026, PGL provided notice of its intent to redeem in full all $50.0 million of its First and Refunding Mortgage Bonds, Series VV and all of its $50.0 million First and Refunding Mortgage Bonds, Series ZZ. In addition, notices of redemption for all $50.0 million of the related 3.90% Illinois Finance Authority Gas Supply Refunding Revenue Bonds, Series 2010 due March 1, 2030 and all $50.0 million of the 4.00% Illinois Finance Authority Gas Supply Refunding Revenue Bonds, Series 2013A due February 1, 2033 were issued. In March 2026, all redemptions were made.

NOTE 11—LEASES

Obligations Under Finance Leases

During 2026, WE and WPS, along with an unaffiliated utility, acquired 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. The weighted-average remaining lease term for these land leases was 50.1 years at September 30, 2026. Once a solar project achieves commercial operation, the lease liability will be remeasured to reflect the final total acres being leased.

The right of use assets obtained in exchange for these finance lease liabilities was $43.1 million. Our total obligation under these land-related leases was $43.9 million at September 30, 2026, and was included in finance lease obligations on our balance sheet. Our finance lease right of use asset related to these leases was $42.8 million as of September 30, 2026, and was included in property, plant, and equipment on our balance sheet. Our weighted-average discount rate for these leases was 6.39%. We used an estimate of the fully collateralized incremental borrowing rate based upon information available for similarly rated companies in determining the present value of lease payments.

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Future minimum lease payments and the corresponding present value of our net minimum lease payments under these land-related leases as of September 30, 2026, were as follows:

(in millions)						Finance Leases
Three Months Ended December 31, 2026						$	—
2027						2.3
2028						2.4
2029						2.4
2030						2.4
2031						2.5
Thereafter						164.6
Total minimum lease payments						176.6
Less: Interest						(132.7)
Present value of minimum lease payments						43.9
Less: Short-term lease liabilities						—
Long-term lease liabilities						$	43.9

NOTE 12—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventories consisted of:

(in millions)						September 30, 2026						December 31, 2025
Materials and supplies						$	428.9					$	416.4
Natural gas in storage						357.5						292.5
Fossil fuel						78.8						94.5
Total						$	865.2					$	803.4

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. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. At September 30, 2026, all LIFO layers were replenished, and the LIFO liquidation balance was zero.

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

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NOTE 13—INCOME TAXES

Statutory Rate Reconciliation

The provision for income taxes 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:

						Three Months Ended September 30, 2026												Three Months Ended September 30, 2025
(in millions)						Amount						Effective Tax Rate						Amount						Effective Tax Rate
Income before income taxes						$	437.3											$	304.6
United States federal statutory income tax rate						$	91.6					21.0		%				$	64.3					21.0		%
State and local income taxes net of federal tax effect (1)						25.9						5.9		%				18.5						6.0		%
Tax credits
PTCs, net (2)						(48.1)						(11.1)		%				(33.4)						(10.9)		%
Other						(1.7)						(0.4)		%				(1.3)						(0.4)		%
Nontaxable or nondeductible items
AFUDC-Equity (3)						(6.1)						(1.4)		%				(4.6)						(1.5)		%
Other						1.4						0.4		%				2.3						0.8		%
Changes in unrecognized tax benefits						0.1						—		%				0.1						—		%
Other adjustments
Federal excess deferred tax amortization (4)						(8.2)						(1.9)		%				(6.5)						(2.1)		%
Other, net						(7.9)						(1.8)		%				(5.0)						(1.6)		%
Total income tax expense						$	47.0					10.7		%				$	34.4					11.3		%
						Nine Months Ended September 30, 2026												Nine Months Ended September 30, 2025
(in millions)						Amount						Effective Tax Rate						Amount						Effective Tax Rate
Income before income taxes						$	1,624.5											$	1,353.3
United States federal statutory income tax rate						$	340.2					21.0		%				$	284.7					21.0		%
State and local income taxes net of federal tax effect (1)						93.9						5.8		%				82.2						6.1		%
Tax credits
PTCs, net (2)						(216.6)						(13.4)		%				(194.0)						(14.3)		%
Other						(7.1)						(0.4)		%				(5.9)						(0.4)		%
Nontaxable or nondeductible items
AFUDC-Equity (3)						(33.0)						(2.0)		%				(15.8)						(1.2)		%
Other						9.4						0.6		%				8.0						0.6		%
Changes in unrecognized tax benefits						0.1						—		%				0.2						—		%
Other adjustments
Federal excess deferred tax amortization (4)						(33.5)						(2.1)		%				(32.0)						(2.4)		%
Other, net						(26.3)						(1.7)		%				(12.8)						(0.9)		%
Total income tax expense						$	127.1					7.8		%				$	114.6					8.5		%

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

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

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

(4)    The Tax Cuts and Jobs Act of 2017 required our regulated utilities to remeasure their deferred income taxes and we began to amortize the resulting excess deferred income taxes beginning in 2018, in accordance with normalization requirements. The decrease in income tax expense related to the amortization of the deferred tax benefits is offset by a decrease in revenue as the benefits are returned to customers, resulting in no impact on net income.

09/30/2026 Form 10-Q			25			WEC Energy Group, Inc.

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The IRA contains a tax credit transferability provision that allows us to sell PTCs and ITCs produced after December 31, 2022, to third parties. Under this transferability provision, we entered into agreements to sell substantially all of the PTCs and ITCs we generated in 2025 to third parties. We have also entered into agreements to sell the majority of PTCs that we expect to generate in 2026 and a portion of the PTCs that we expect to generate in 2027 and 2028 to third parties. We elect to account for tax credits transferred under the scope of ASC 740. We include the discount from the sale of tax credits as a component of income tax expense. We also include any expected proceeds from the sale of tax credits in the evaluation of the realizability of deferred tax assets related to PTCs and ITCs. The sale of tax credits is presented in the operating activities section of the statements of cash flows consistent with the presentation of cash taxes paid.

Cash Paid (Received) For Income Taxes, Net

The table below is a summary of income taxes paid (received) by jurisdiction:

						Nine Months Ended September 30
(in millions)						2026						2025
Federal						$	(199.4)		(1)			$	(195.0)		(2)
State						0.2						(25.0)
Total income taxes received, net						$	(199.2)					$	(220.0)

(1)    Amount includes $153.3 million of cash received related to third-party sales of both 2026 and 2025 PTCs, and $81.6 million of cash received related to third-party sales of 2025 ITCs.

(2)    Amount includes $195.0 million of cash received related to third party sales of both 2025 and 2024 PTCs.

The table below is a summary of income taxes received (net of refunds) that exceeded five percent of total income taxes paid or received (net of refunds) by jurisdiction. There was no jurisdiction exceeding the threshold for the nine months ended September 30, 2026.

(in millions)						Nine Months Ended September 30, 2025
Wisconsin						$	(25.0)

NOTE 14—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.

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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 regional transmission organization.

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:

						September 30, 2026
(in millions)						Level 1						Level 2						Level 3						Total
Derivative assets
Natural gas contracts						$	2.3					$	17.2					$	—					$	19.5
FTRs						—						—						14.7						14.7
Total derivative assets						$	2.3					$	17.2					$	14.7					$	34.2
Investments held in rabbi trust						$	44.2					$	—					$	—					$	44.2
Derivative liabilities
Natural gas contracts						$	48.2					$	9.0					$	—					$	57.2

						December 31, 2025
(in millions)						Level 1						Level 2						Level 3						Total
Derivative assets
Natural gas contracts						$	1.5					$	18.3					$	—					$	19.8
FTRs						—						—						6.5						6.5
Total derivative assets						$	1.5					$	18.3					$	6.5					$	26.3
Investments held in rabbi trust						$	42.0					$	—					$	—					$	42.0
Derivative liabilities
Natural gas contracts						$	23.3					$	8.4					$	—					$	31.7
FTRs						—						—						0.8						0.8
Total derivative liabilities						$	23.3					$	8.4					$	0.8					$	32.5

The tables above include derivative assets and liabilities for options, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. Both tables also include FTRs used at our electric utilities to manage electric transmission congestion costs in the MISO Energy Markets. Additionally, the December 31, 2025 table includes FTRs used at certain of our non-utility wind parks to manage electric transmission congestion costs in the MISO Energy Markets, which were all settled during the first six months of 2026.

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. For the three months ended September 30, 2026 and 2025, the net unrealized gains included in earnings related to the investments held at the end of the period were $0.7 million and $3.0 million, respectively. For the nine months ended September 30, 2026 and 2025, the net unrealized gains included in earnings related to the investments held at the end of the period were $4.6 million and $4.9 million, respectively.

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

						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2026						2025						2026						2025
Balance at the beginning of the period						$	24.3					$	19.0					$	5.7					$	7.8
Purchases						0.1						—						28.3						23.7
Net realized and unrealized losses included in earnings (1)						—						(0.1)						—						(0.1)
Sales						(0.2)						—						(0.6)						—
Settlements						(9.5)						(8.3)						(18.7)						(20.8)
Balance at the end of the period						$	14.7					$	10.6					$	14.7					$	10.6
Net unrealized losses included in earnings attributable to Level 3 derivatives held at the end of the reporting period (1)						$	—					$	(0.1)					$	—					$	(0.1)

(1)Amounts relate to FTRs and TCRs included in our non-utility energy infrastructure segment. These net realized and unrealized losses were recorded in operating revenues on our income statements. During the first six months of 2026, all remaining FTRs used in our non-utility operations were settled. Our TCRs were all settled during the year ended December 31, 2025.

Fair Value of Financial Instruments

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

						September 30, 2026												December 31, 2025
(in millions)						Carrying Amount						Fair Value						Carrying Amount						Fair Value
Preferred stock of subsidiary						$	30.4					$	21.1					$	30.4					$	21.2
Long-term debt, including current portion						20,851.7						19,321.4						20,017.5						19,609.1

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

NOTE 15—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 an asset or liability 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.

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On our balance sheets, we classify derivative assets and liabilities as current or long-term based on the maturities of the underlying contracts. 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.

						September 30, 2026												December 31, 2025
(in millions)						Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
Current
Natural gas contracts						$	19.3					$	55.2					$	19.7					$	30.0
FTRs						14.7						—						6.5						0.8
Total current						34.0						55.2						26.2						30.8
Long-term
Natural gas contracts						0.2						2.0						0.1						1.7
Total						$	34.2					$	57.2					$	26.3					$	32.5

Realized gains and losses on derivatives used in our regulated utility operations are recorded in cost of sales upon settlement; however, they may be subsequently deferred for future rate recovery or refund as the gains and losses are included in our utilities’ fuel and natural gas cost recovery mechanisms. Realized gains and losses on FTRs and TCRs used in our non-utility operations were recorded in operating revenues on the income statements. During the first six months of 2026, all remaining FTRs used in our non-utility operations were settled. Our TCRs were all settled during the year ended December 31, 2025. Our realized gains and losses and the estimated notional volumes related to these settlements were as follows:

						Three Months Ended September 30, 2026												Three Months Ended September 30, 2025
(in millions)						Volumes						Gains (Losses)						Volumes						Gains (Losses)
Natural gas contracts						39.5 Dth						$	(23.0)					37.6 Dth						$	(13.6)
FTRs and TCRs
Regulated utility operations						6.6 MWh						19.6						6.8 MWh						6.7
Non-utility operations						— MWh						—						— MWh						(0.1)
Total												$	(3.4)											$	(7.0)
						Nine Months Ended September 30, 2026												Nine Months Ended September 30, 2025
(in millions)						Volumes						Gains (Losses)						Volumes						Gains (Losses)
Natural gas contracts						151.1 Dth						$	(10.2)					146.4 Dth						$	(9.0)
FTRs and TCRs
Regulated utility operations						18.5 MWh						25.6						20.6 MWh						11.4
Non-utility operations						0.1 MWh						0.1						0.6 MWh						—
Total												$	15.5											$	2.4

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At September 30, 2026 and December 31, 2025, we had posted cash collateral of $92.2 million and $41.4 million, respectively. These amounts were recorded on our balance sheets in other current assets. At September 30, 2026, we had also received cash collateral of $2.0 million. This amount was recorded on our balance sheet in other current liabilities.

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

						September 30, 2026												December 31, 2025
(in millions)						Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
Gross amount recognized on the balance sheet						$	34.2					$	57.2					$	26.3					$	32.5
Gross amount not offset on the balance sheet						(4.1)						(50.0)			(1)			(2.0)						(23.8)			(2)
Net amount						$	30.1					$	7.2					$	24.3					$	8.7

(1)Includes cash collateral posted of $45.9 million.

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

Cash Flow Hedges

We previously entered into forward interest rate swap agreements to mitigate the interest rate exposure associated with the issuance of long-term debt related to the acquisition of Integrys. These swap agreements were settled in 2015, and we continue to amortize amounts out of accumulated other comprehensive loss into interest expense over the periods in which the interest costs are recognized in earnings. The derivative gains related to these swap agreements reclassified from accumulated other comprehensive loss to interest expense during the three and nine months ended September 30, 2026 and 2025 were not significant. At September 30, 2026, the amount expected to be reclassified from accumulated other comprehensive loss to interest expense over the next twelve months was also not significant.

NOTE 16—GUARANTEES

The following table shows our outstanding guarantees:

						Total Amounts Committed at September 30, 2026						Expiration
(in millions)												Less Than 1 Year						1 to 3 Years						Over 3 Years
Standby letters of credit (1)						$	179.3					$	21.4					$	30.2					$	127.7
Surety bonds (2)						46.5						23.3						23.2						—
Other guarantees (3)						10.9						—						—						10.9
Total guarantees						$	236.7					$	44.7					$	53.4					$	138.6

(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.

NOTE 17—EMPLOYEE BENEFITS

The following tables show the components of net periodic benefit cost (credit) (including amounts capitalized to our balance sheets) for our benefit plans:

						Pension Benefits
						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2026						2025						2026						2025
Service cost						$	5.6					$	5.2					$	16.8					$	15.7
Interest cost						28.7						29.6						85.9						89.0
Expected return on plan assets						(42.8)						(43.8)						(128.2)						(131.5)
Gain on plan settlement						(1.0)						(0.7)						(1.0)						(0.7)
Amortization of prior service credit						—						—						(0.1)						(0.1)
Amortization of net actuarial loss						10.5						9.0						31.8						32.1
Net periodic benefit cost (credit)						$	1.0					$	(0.7)					$	5.2					$	4.5

09/30/2026 Form 10-Q			30			WEC Energy Group, Inc.

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						OPEB Benefits
						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2026						2025						2026						2025
Service cost						$	3.1					$	2.9					$	9.3					$	8.5
Interest cost						6.6						6.4						19.8						19.2
Expected return on plan assets						(14.5)						(13.6)						(43.4)						(40.7)
Amortization of prior service credit						(1.3)						(1.4)						(3.9)						(6.4)
Amortization of net actuarial gain						(2.2)						(2.2)						(6.3)						(5.9)
Net periodic benefit credit						$	(8.3)					$	(7.9)					$	(24.5)					$	(25.3)

During the nine months ended September 30, 2026, we made contributions and payments of $9.1 million related to our pension plans and $1.4 million related to our OPEB plans. We expect to make contributions and payments of $2.7 million related to our pension plans and $0.9 million related to our OPEB plans during the remainder of 2026, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

Certain of our utility subsidiaries utilize escrow accounting for our current pension and OPEB costs, as approved by the PSCW. As of September 30, 2026 and December 31, 2025, our balance sheets included regulatory liabilities of $26.9 million and $14.7 million, respectively, for pension costs and regulatory assets of $2.8 million and $0.7 million, respectively, for OPEB costs. In accordance with our PSCW rate orders, we amortize the related regulatory assets and liabilities. The above tables do not reflect any adjustments for the creation or amortization of these regulatory assets and liabilities.

NOTE 18—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 September 30, 2026. We had no changes to the carrying amount of goodwill during the nine months ended September 30, 2026.

(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 September 30, 2026.

During the third quarter of 2026, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of July 1, 2026. No impairments resulted from these tests.

Other Indefinite-Lived Intangible Assets

At September 30, 2026 and December 31, 2025, we had $229.7 million and $44.4 million, respectively, of other indefinite-lived intangible assets included in other long-term assets on our balance sheets. In July 2026, WE and WPS entered into an option agreement and made a refundable aggregate payment of $170.8 million for exclusive rights to purchase certain generation projects to be constructed in Wisconsin. In October 2025, we entered into an option agreement for exclusive rights to purchase land for future generation development in Wisconsin. We have made two annual option payments for exclusive rights to purchase the land and incurred total costs of $29.6 million and $15.1 million as of September 30, 2026 and December 31, 2025, respectively, with a right to exercise our option before December 31, 2030. In addition, we have other indefinite-lived intangible assets consisting of $24.1 million of spectrum frequencies, which enable our utilities to transmit data and voice communications over a wavelength dedicated to us throughout our service territories. We also have $5.2 million of other indefinite-lived intangible assets, consisting of a MGU trade name from a previous acquisition.

Finite-Lived Intangible Assets

At September 30, 2026 and December 31, 2025, we had $18.3 million and $17.4 million, respectively, of finite-lived intangible assets included in other long-term assets on our balance sheets. These assets largely consist of a PPA for Maple Flats Solar Energy Center LLC acquired by WECI in November 2024, with a gross carrying amount of $18.8 million. The PPA is being amortized over a useful life

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of 15 years and expires in 2039. At September 30, 2026 and December 31, 2025, accumulated amortization related to the intangible assets was $2.3 million and $1.4 million, respectively. Amortization was not material for the three and nine months ended September 30, 2026 and 2025. Amortization to be recorded as a decrease to operating revenues is expected to be $1.3 million in each of the next five years.

Intangible Liabilities

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

						September 30, 2026																		December 31, 2025
(in millions)						Gross Carrying Amount						Accumulated Amortization						Net Carrying Amount						Gross Carrying Amount						Accumulated Amortization						Net Carrying Amount
PPAs (1)						$	751.2					$	(220.9)					$	530.3					$	751.2					$	(176.5)					$	574.7
Proxy revenue swap (2)						7.2						(5.5)						1.7						7.2						(4.9)						2.3
Interconnection agreements (3)						4.7						(1.5)						3.2						4.7						(1.4)						3.3
Total intangible liabilities						$	763.1					$	(227.9)					$	535.2					$	763.1					$	(182.8)					$	580.3

(1)    Represents PPAs related to the acquisitions of Blooming Grove, Tatanka Ridge, Jayhawk, Thunderhead, Samson I, Sapphire Sky Wind Energy LLC, Delilah I, and Hardin III expiring between 2030 and 2040. The weighted-average remaining useful life of the PPAs is 9 years. See Note 2, Acquisitions, for more information on recent WECI acquisitions.

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

(3)    Represents interconnection agreements related to the acquisitions of Tatanka Ridge and Bishop Hill Energy III LLC, 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 14 years.

Amortization related to these intangible liabilities for the three and nine months ended September 30, 2026, was $15.1 million and $45.1 million, respectively. Amortization related to these intangible liabilities for the three and nine months ended September 30, 2025, was $14.7 million and $43.4 million, respectively. Amortization for the next five years, including amounts recorded through September 30, 2026, is estimated to be:

						For the Years Ending December 31
(in millions)						2026						2027						2028						2029						2030
Amortization to be recorded as an increase to operating revenues						$	59.9					$	59.9					$	59.9					$	59.3					$	59.1
Amortization to be recorded as a decrease to other operation and maintenance						0.2						0.2						0.2						0.2						0.2

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NOTE 19—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. The following tables provide a reconciliation of the changes in our investments in ATC and ATC Holdco:

						Three Months Ended September 30, 2026
(in millions)						ATC						ATC Holdco						Total
Balance at beginning of period						$	2,398.1					$	22.6					$	2,420.7
Add: Earnings from equity method investment						65.5						0.3						65.8
Add: Capital contributions						60.6						—						60.6
Less: Distributions						50.0						—						50.0
Less: Other						0.1						—						0.1
Balance at end of period						$	2,474.1					$	22.9					$	2,497.0
						Three Months Ended September 30, 2025
(in millions)						ATC						ATC Holdco						Total
Balance at beginning of period						$	2,177.5					$	22.6					$	2,200.1
Add: Earnings from equity method investment						54.2						0.6						54.8
Add: Capital contributions						54.6						—						54.6
Less: Distributions						40.7						—						40.7
Balance at end of period						$	2,245.6					$	23.2					$	2,268.8
						Nine Months Ended September 30, 2026
(in millions)						ATC						ATC Holdco						Total
Balance at beginning of period						$	2,256.9					$	23.5					$	2,280.4
Add: Earnings from equity method investment						186.9						1.0						187.9
Add: Capital contributions						173.0						—						173.0
Less: Distributions						142.7						1.6						144.3
Balance at end of period						$	2,474.1					$	22.9					$	2,497.0
						Nine Months Ended September 30, 2025
(in millions)						ATC						ATC Holdco						Total
Balance at beginning of period						$	2,085.1					$	23.8					$	2,108.9
Add: Earnings from equity method investment						154.5						5.8						160.3
Add: Capital contributions						142.4						—						142.4
Less: Distributions						136.4						6.4						142.8
Balance at end of period						$	2,245.6					$	23.2					$	2,268.8

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:

						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2026						2025						2026						2025
Charges to ATC for services and construction						$	5.4					$	4.2					$	18.8					$	13.7
Charges from ATC for network transmission services						129.3						116.8						387.5						350.2
Net refund from ATC related to FERC ROE orders						—						2.1						1.3						3.8

09/30/2026 Form 10-Q			33			WEC Energy Group, Inc.

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Our balance sheets included the following receivables and payables for services provided to or received from ATC:

(in millions)						September 30, 2026						December 31, 2025
Accounts receivable for services provided to ATC						$	1.8					$	1.6
Accounts payable for services received from ATC						43.7						38.4
Amounts due from ATC for transmission infrastructure upgrades (1)						38.0						32.2

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

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

						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2026						2025						2026						2025
Income statement data
Operating revenues						$	280.8					$	245.1					$	820.1					$	721.2
Operating expenses						129.4						116.9						386.4						351.2
Other expense, net						47.3						41.4						135.8						123.2
Net income						$	104.1					$	86.8					$	297.9					$	246.8

(in millions)						September 30, 2026						December 31, 2025
Balance sheet data
Current assets						$	165.8					$	137.5
Noncurrent assets						8,470.0						7,590.8
Total assets						$	8,635.8					$	7,728.3
Current liabilities						$	619.4					$	839.8
Long-term debt						3,798.5						3,156.3
Other noncurrent liabilities						768.5						638.9
Members' equity						3,449.4						3,093.3
Total liabilities and members' equity						$	8,635.8					$	7,728.3

NOTE 20—SEGMENT INFORMATION

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

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

Segments were determined based on a combination of factors, including the regulatory environment of each geographical jurisdiction in which the segment operates, equity investment interests, as well as the revenue streams for the products or services provided to customers through electric, natural gas, and renewable operations. See Note 4, Operating Revenues, for more information on disaggregation of operating revenues, including intercompany eliminations. The accounting policies of the segments are the same as those described in Note 1, Summary of Significant Accounting Policies, in our 2025 Annual Report on Form 10-K.

At September 30, 2026, we reported six segments, which are described below. All of our operations are located within the United States.

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

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

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

•The electric transmission segment includes our approximate 60% ownership interest in ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects, and our approximate 75% ownership interest in ATC Holdco, which was formed to invest in transmission-related projects outside of ATC's traditional footprint. See Note 19, Investment in Transmission Affiliates, for more information on ATC and ATC Holdco.

•The non-utility energy infrastructure segment includes:

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

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

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

See Note 2, Acquisitions, for more information on WECI's acquisition of Hardin III.

•The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the Peoples Energy, LLC holding company, Wispark LLC, Wisvest LLC, Wisconsin Energy Capital Corporation, and WEC Business Services LLC.

09/30/2026 Form 10-Q			35			WEC Energy Group, Inc.

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The following tables show summarized financial information related to our reportable segments for the three and nine months ended September 30, 2026 and 2025:

						Utility Operations
(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Electric Transmission						Non-Utility Energy Infrastructure						Corporate and Other						Reconciling Eliminations						WEC Energy Group Consolidated
Three Months Ended September 30, 2026
External revenues						$	1,964.7					$	183.2					$	60.9					$	2,208.8					$	—					$	81.8					$	—					$	—					$	2,290.6
Intersegment revenues						—						—						—						—						—						119.1						—						(119.1)						—
Fuel and purchased power						559.1						—						—						559.1						—						—						—						—						559.1
Cost of natural gas sold						50.3						27.4						23.3						101.0						—						0.8						—						(9.7)						92.1
Other operation and maintenance						479.3						89.2						24.7						593.2						—						30.9						(8.1)						(1.6)						614.4
Depreciation and amortization						271.8						67.1						13.5						352.4						—						60.4						5.6						(29.4)						389.0
Property and revenue taxes						49.0						11.2						6.8						67.0						—						5.3						—						—						72.3
Equity in earnings of transmission affiliates						—						—						—						—						65.8						—						—						—						65.8
Other income, net (1)						43.6						2.6						0.3						46.5						—						0.7						11.3						(9.0)						49.5
Interest expense						175.0						21.1						4.8						200.9						3.9						30.0						94.3						(87.4)						241.7
Income tax expense (benefit)						61.8						(9.0)						(3.1)						49.7						15.6						(19.3)						1.0						—						47.0
Preferred stock dividends of subsidiary						0.3						—						—						0.3						—						—						—						—						0.3
Net income attributed to noncontrolling interests						—						—						—						—						—						(0.7)						—						—						(0.7)
Net income (loss) attributed to common shareholders						$	361.7					$	(21.2)					$	(8.8)					$	331.7					$	46.3					$	92.8					$	(81.5)					$	—					$	389.3
Other Segment Disclosures
Three Months Ended September 30, 2026
Capital expenditures, including AFUDC-Debt and asset acquisitions						$	1,011.1					$	123.4					$	37.3					$	1,171.8					$	—					$	19.2					$	7.6					$	—					$	1,198.6
Balance at September 30, 2026
Equity method investments						19.7						—						—						19.7						2,497.0						—						56.9						—						2,573.6
Total assets (2)						36,318.6						8,047.2						1,718.3						46,084.1						2,497.0						7,661.1						1,298.8						(3,643.5)						53,897.5

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

(2)    Total assets at September 30, 2026 reflect an elimination of $2,552.4 million for all lease activity between We Power and WE.

09/30/2026 Form 10-Q			36			WEC Energy Group, Inc.

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						Utility Operations
(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Electric Transmission						Non-Utility Energy Infrastructure						Corporate and Other						Reconciling Eliminations						WEC Energy Group Consolidated
Three Months Ended September 30, 2025
External revenues						$	1,791.6					$	183.5					$	53.0					$	2,028.1					$	—					$	75.9					$	—					$	—					$	2,104.0
Intersegment revenues						—						—						—						—						—						117.4						—						(117.4)						—
Fuel and purchased power						502.4						—						—						502.4						—						—						—						—						502.4
Cost of natural gas sold						75.8						21.4						17.5						114.7						—						0.8						—						(9.8)						105.7
Other operation and maintenance						443.7						108.0						23.6						575.3						—						34.6						(3.2)						(1.6)						605.1
Depreciation and amortization						255.7						65.0						12.5						333.2						—						60.6						5.2						(25.6)						373.4
Property and revenue taxes						44.5						11.4						6.6						62.5						—						5.3						—						—						67.8
Equity in earnings of transmission affiliates						—						—						—						—						54.8						—						—						—						54.8
Other income, net (1)						25.0						2.1						0.1						27.2						—						0.8						3.7						(7.9)						23.8
Interest expense						158.9						21.8						5.0						185.7						4.8						30.5						90.9						(88.3)						223.6
Income tax expense (benefit)						54.0						(11.5)						(3.2)						39.3						12.7						(24.2)						6.6						—						34.4
Preferred stock dividends of subsidiary						0.3						—						—						0.3						—						—						—						—						0.3
Net loss attributed to noncontrolling interests						—						—						—						—						—						1.4						—						—						1.4
Net income (loss) attributed to common shareholders						$	281.3					$	(30.5)					$	(8.9)					$	241.9					$	37.3					$	87.9					$	(95.8)					$	—					$	271.3
Other Segment Disclosures
Three Months Ended September 30, 2025
Capital expenditures, including AFUDC-Debt and asset acquisitions						$	1,385.7					$	93.9					$	29.7					$	1,509.3					$	—					$	58.3					$	6.9					$	—					$	1,574.5
Balance at September 30, 2025
Equity method investments						17.3						—						—						17.3						2,268.8						—						55.3						—						2,341.4
Total assets (2)						32,467.2						8,049.4						1,651.7						42,168.3						2,268.8						7,809.9						1,199.4						(3,637.5)						49,808.9

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

(2)    Total assets at September 30, 2025 reflect an elimination of $2,613.4 million for all lease activity between We Power and WE.

09/30/2026 Form 10-Q			37			WEC Energy Group, Inc.

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						Utility Operations
(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Electric Transmission						Non-Utility Energy Infrastructure						Corporate and Other						Reconciling Eliminations						WEC Energy Group Consolidated
Nine Months Ended September 30, 2026
External revenues						$	5,924.5					$	1,195.1					$	402.5					$	7,522.1					$	—					$	264.8					$	—					$	—					$	7,786.9
Intersegment revenues						—						—						—						—						—						362.4						—						(362.4)						—
Fuel and purchased power						1,392.6						—						—						1,392.6						—						—						—						—						1,392.6
Cost of natural gas sold						687.7						335.1						209.2						1,232.0						—						6.0						—						(32.8)						1,205.2
Other operation and maintenance						1,389.4						310.3						78.3						1,778.0						—						79.5						(10.2)						(7.1)						1,840.2
Depreciation and amortization						802.6						199.4						39.7						1,041.7						—						181.8						16.5						(86.3)						1,153.7
Property and revenue taxes						148.8						33.5						20.5						202.8						—						15.8						0.1						—						218.7
Equity in earnings of transmission affiliates						—						—						—						—						187.9						—						—						—						187.9
Other income, net (1)						138.9						6.7						0.6						146.2						—						1.9						36.9						(25.8)						159.2
Interest expense						499.1						63.3						15.0						577.4						11.8						90.6						281.3						(262.0)						699.1
Income tax expense (benefit)						164.3						73.0						10.4						247.7						43.7						(80.3)						(84.0)						—						127.1
Preferred stock dividends of subsidiary						0.9						—						—						0.9						—						—						—						—						0.9
Net income attributed to noncontrolling interests						—						—						—						—						—						(3.6)						—						—						(3.6)
Net income (loss) attributed to common shareholders						$	978.0					$	187.2					$	30.0					$	1,195.2					$	132.4					$	332.1					$	(166.8)					$	—					$	1,492.9
Other Segment Disclosures
Capital expenditures, including AFUDC-Debt and asset acquisitions						$	2,883.2					$	271.9					$	82.1					$	3,237.2					$	—					$	65.8					$	18.7					$	—					$	3,321.7

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

09/30/2026 Form 10-Q			38			WEC Energy Group, Inc.

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						Utility Operations
(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Electric Transmission						Non-Utility Energy Infrastructure						Corporate and Other						Reconciling Eliminations						WEC Energy Group Consolidated
Nine Months Ended September 30, 2025
External revenues						$	5,438.7					$	1,242.4					$	362.4					$	7,043.5					$	—					$	219.5					$	—					$	—					$	7,263.0
Intersegment revenues						—						—						—						—						—						357.5						—						(357.5)						—
Fuel and purchased power						1,284.5						—						—						1,284.5						—						—						—						—						1,284.5
Cost of natural gas sold						582.7						339.1						165.1						1,086.9						—						6.6						—						(33.7)						1,059.8
Other operation and maintenance						1,274.8						367.3						76.2						1,718.3						—						107.6						(9.5)						(7.1)						1,809.3
Depreciation and amortization						749.5						194.2						37.0						980.7						—						179.6						16.2						(74.3)						1,102.2
Property and revenue taxes						135.0						44.6						19.9						199.5						—						15.6						0.1						—						215.2
Equity in earnings of transmission affiliates						—						—						—						—						160.3						—						—						—						160.3
Other income, net (1)						62.4						6.5						0.3						69.2						—						2.2						20.3						(23.3)						68.4
Interest expense						478.6						67.1						14.0						559.7						14.5						92.6						266.3						(265.7)						667.4
Income tax expense (benefit)						171.5						66.4						12.8						250.7						36.0						(98.7)						(73.4)						—						114.6
Preferred stock dividends of subsidiary						0.9						—						—						0.9						—						—						—						—						0.9
Net loss attributed to noncontrolling interests						—						—						—						—						—						3.1						—						—						3.1
Net income (loss) attributed to common shareholders						$	823.6					$	170.2					$	37.7					$	1,031.5					$	109.8					$	279.0					$	(179.4)					$	—					$	1,240.9
Other Segment Disclosures
Capital expenditures, including AFUDC-Debt and asset acquisitions						$	2,716.8					$	219.3					$	84.9					$	3,021.0					$	—					$	490.4					$	14.7					$	—					$	3,526.1

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

NOTE 21—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.

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WEPCo Environmental Trust Finance I, LLC

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

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

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

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

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

(in millions)						September 30, 2026						December 31, 2025
Assets
Other current assets (restricted cash)						$	4.6					$	2.0
Regulatory assets						60.9						67.5
Other long-term assets (restricted cash)						0.6						0.6
Liabilities
Current portion of long-term debt						9.4						9.3
Accounts payable						—						0.1
Other current liabilities (accrued interest)						0.3						0.1
Long-term debt						62.8						67.4

Investment in Transmission Affiliates

We own approximately 60% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. We have determined that ATC is a VIE but consolidation is not required since we are not ATC's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC's economic performance. Therefore, we account for ATC as an equity method investment. At September 30, 2026 and December 31, 2025, our equity investment in ATC was $2,474.1 million and $2,256.9 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 September 30, 2026 and December 31, 2025, our equity investment in ATC Holdco was $22.9 million and $23.5 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.

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See Note 19, Investment in Transmission Affiliates, for more information, including any significant assets and liabilities related to ATC and ATC Holdco recorded on our balance sheets.

NOTE 22—COMMITMENTS AND CONTINGENCIES

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

Unconditional Purchase Obligations

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

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

Our minimum future commitments related to these purchase obligations as of September 30, 2026, including those of our subsidiaries, were approximately $11.0 billion.

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 sulfur dioxide, NOx, PM, ozone, mercury, and GHGs; water intake and discharges; management of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.

Federal Deregulatory Actions

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

In February 2026, the EPA published a final rule rescinding the 2009 declaration that determined that CO2 and other GHGs endanger public health and welfare. The "endangerment finding" has been the legal underpinning of a host of climate regulations under the Clean Air Act. Litigation over the rule has been initiated in the D.C. Circuit Court of Appeals.

Air Quality

Cross State Air Pollution Rule – Good Neighbor Rule

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

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

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to comply with either standard. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

Mercury and Air Toxics Standards

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

In February 2026, the EPA issued a final rule effective April 27, 2026, repealing the 2024 Amendments. The final rule reverts back to the prior PM limit of 0.03 lb/MMBtu and eliminates the requirement of continuous emissions monitoring of PM emissions.

National Ambient Air Quality Standards

Ozone

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

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

In February 2025, the State of Wisconsin filed a petition for review of this reclassification in the United States Court of Appeals for the Seventh Circuit and was granted a stay of the reclassification in September 2025, pending the Court's review. The case is being held in abeyance and Southeast Wisconsin is currently under a "moderate" reclassification status pending a further court order. In August 2026, Clean Wisconsin and Sierra Club filed a motion to intervene and defend the final rule reclassifying the nonattainment area from "moderate" to "serious".

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

Particulate Matter

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

In November 2025, the EPA filed a motion in the litigation pending in the D.C. Circuit Court of Appeals to vacate the 2024 PM2.5 Standard. The court issued an order in June 2026, denying the EPA's motion. The 2024 PM2.5 Standard therefore remains in effect. Previously, in April 2026, the State of Wisconsin signed onto a complaint filed in California that seeks an order directing the EPA to implement the 2024 PM2.5 Standard and make nonattainment designations. In July 2026, the Northern District Court of California ordered the EPA to publish final designations for all areas of the country no later than February 6, 2027. The EPA is appealing the order while continuing to move forward with completing the designations. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

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New Source Performance Standards

Nitrogen Oxides

In January 2026, the EPA released a final rule regulating NOx for CTs constructed, modified, or reconstructed after December 13, 2024. The final rule became effective January 15, 2026, and established NOx emissions standards for several subcategories of new, modified, and reconstructed CTs based on the size, rates of utilization, design efficiency, and fuel type of these turbines. We believe the CTs included in our capital plan will be well positioned to comply with this rule. The existing simple cycle CTs will require more stringent NOx limits if they undergo upgrades.

Climate Change

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

In September 2026, the EPA issued two actions for addressing the 2024 GHG Power Plant Rule. The EPA issued a final rule repealing carbon capture, storage-based standards, and emission guidelines and a proposed supplemental rule that would repeal all GHG standards for the power sector. The final rule becomes effective on November 16, 2026, and the proposed rule has a comment period ending November 2, 2026. The final rule has already been challenged in court, and the proposed supplemental rule is expected to be challenged if finalized. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

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

Our capital plan includes the planned retirement of older, fossil-fueled generation, to be replaced with natural gas-fired generation and zero-carbon-emitting renewables. We have retired nearly 2,500 MWs of fossil-fueled generation since the beginning of 2018. We expect to retire additional coal-fired generation, including OCPP Units 7 and 8. See Note 7, Property, Plant, and Equipment, for more information related to our planned power plant retirements. As part of our capital plan, we and the other co-owners of Columbia Units 1 and 2 currently plan to continue coal operations at these units through at least 2030. We have a long-term goal to achieve net carbon-neutral electric generation by the end of 2050. We expect to achieve this goal by continuing to make operating refinements, retiring less efficient generating units, and executing our capital plan. As part of our path toward this goal, we started implementing co-firing with natural gas at the ERGS coal-fired units and at Weston Unit 4.

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

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

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

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

Steam Electric Effluent Limitation Guidelines

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

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

When the deadline extension rule was proposed, the EPA also solicited public comments related to the economic achievability and technical availability of ZLD technologies. Additional ELG rulemaking is anticipated that may lead to substantive changes to the ZLD technology-based requirements established in the 2024 ELG Rule. Another proposed ELG rule was published in May 2026, to address CRL treatment requirements. As currently written, the proposed rule confirms that CRL from our Company's landfills is not subject to the limitations in the 2024 ELG Rule.

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

Land Quality

Manufactured Gas Plant Remediation

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

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

We have established the following regulatory assets and reserves for manufactured gas plant sites:

(in millions)						September 30, 2026						December 31, 2025
Regulatory assets						$	538.2					$	566.0
Reserves for future environmental remediation						457.9						484.1

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Coal Combustion Residuals Rule

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

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

The rule is being challenged through litigation pending in the D.C. Circuit Court of Appeals. In December 2025, the D.C. Circuit Court of Appeals granted the EPA's motion to extend the ongoing abeyance while the EPA reconsiders certain aspects of the rule. In February 2026, the EPA published a final rule extending certain deadlines and making various corrections to the 2024 CCR rule. In April 2026, the EPA published a rule seeking comments on proposed amendments to the 2024 CCR rule. These amendments include (1) changes to the existing self-implementing regulations; (2) new compliance pathways allowing for site-specific flexibility under a state or federal permit; and (3) changes impacting the definition of CCR beneficial use. The EPA stated its intent is to revise the rule based on public feedback, including technical information submittals, and currently plans to publish a new final rule by early 2027. The EPA stated that it intends to address closure issues in a separate proposed rulemaking, which is also expected in 2027. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

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.

NOTE 23—SUPPLEMENTAL CASH FLOW INFORMATION

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

						Nine Months Ended September 30
(in millions)						2026						2025
Cash paid for interest, net of amount capitalized						$	581.2					$	555.4
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs						338.3						227.6
Common stock issued for stock-based compensation plans						4.2						3.2
Liabilities accrued for software licensing agreements						2.6						20.7
(Decrease) increase in receivables related to property damage insurance proceeds						(0.5)						2.5

Cash, Cash Equivalents, and Restricted Cash

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

(in millions)						September 30, 2026						December 31, 2025
Cash and cash equivalents						$	58.8					$	27.6
Restricted cash included in other current assets						43.9						9.1
Restricted cash included in other long-term assets						27.8						34.2
Cash, cash equivalents, and restricted cash						$	130.5					$	70.9

Our restricted cash primarily consisted of the following:

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

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

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

NOTE 24—REGULATORY ENVIRONMENT

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

2027 and 2028 Rate Cases

On April 1, 2026, WE, WPS, and WG filed requests with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable, effective January 1, 2027 and January 1, 2028. The requests reflected the following:

						WE												WPS												WG
Proposed 2027 rate increase
Electric (2)						$	175.8	million	/			4.7%						$	86.1	million	/			6.3%						N/A
Gas						$	2.1	million	/			0.3%			(3)			$	21.7	million	/			4.9%						$	59.4	million	/			6.8%
Steam						$	0.1	million	/			0.2%						N/A												N/A
Proposed 2028 rate increase (1)
Electric (2)						$	179.5	million	/			4.5%						$	50.8	million	/			3.5%						N/A
Gas						$	33.3	million	/			4.9%			(3)			$	6.9	million	/			1.5%						$	37.2	million	/			4.0%
Steam						$	1.2	million	/			3.8%						N/A												N/A
Proposed ROE						9.9%												9.9%												9.9%
Proposed common equity component average on a financial basis						53.5%												55.0%												53.5%

(1)    The proposed 2028 rate increases are incremental to the currently authorized revenue plus the requested rate increases for 2027.

(2)    Amounts reflect the impact to our Wisconsin retail electric operations and exclude any impacts from updated fuel costs.

(3)    Increase excludes the impact of the costs directly assigned to natural gas electric generation facilities.

The primary driver of the requested increases in electric rates is continued capital investments to transition our generation fleet from coal to renewables and natural gas-fueled generation, as well as the related investments in transmission and distribution assets. These capital investments, which will strengthen reliability and help reduce carbon emissions, have either already been approved by the PSCW or are expected to receive PSCW approval before or during 2028. Increased operation and maintenance costs, driven by higher inflation, was also a significant driver of the rate increases.

The requested increases in natural gas rates are driven by our ongoing capital investments in reliability and safety projects, including the previously approved Oak Creek LNG storage facility and the Rochester lateral, as well as the impact from higher inflation on operation and maintenance costs.

The utilities also proposed retaining their respective current earnings sharing mechanisms. Under WE's current earnings sharing mechanism, if WE earns above its authorized ROE: (i) it retains 100.0% of earnings for the first 15 basis points above the authorized ROE; (ii) 50.0% of the next 25 basis points is required to be refunded to ratepayers; and (iii) 100.0% of any remaining excess earnings is required to be refunded to ratepayers. Under WPS's and WG's current mechanism, if the utility earns above its authorized ROE: (i) the utility retains 100.0% of earnings for the first 15 basis points above the authorized ROE; (ii) 50.0% of the next 60 basis points is required to be refunded to ratepayers; and (iii) 100.0% of any remaining excess earnings is required to be refunded to ratepayers.

A PSCW decision is expected in the fourth quarter of 2026.

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Very Large Customer and Bespoke Resources Tariffs

In March 2025, WE filed an application with the PSCW requesting approval to implement a VLC tariff and a Bespoke Resources tariff. The PSCW issued a final written order approving the tariffs, with modifications (including to the credit support criteria and collateral provisions), in May 2026. Under these inter-connected tariffs, VLCs (customers with new demand exceeding 100 MWs, such as large data centers) will have access to reliable power to meet their needs and will directly pay for the electricity they consume, along with the power plants and distribution facilities built to serve them and operating and transmission costs allocated to their usage. The tariffs are designed so that the costs associated with these VLCs are not subsidized by or shifted to residential or business customers.

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

In June 2026, WE, along with two intervenors, filed a petition for rehearing with the PSCW requesting reconsideration and modification to the credit support criteria and collateral provisions in the May 2026 order. The PSCW did not take action on the petition within the allowed 30-day time period so it was deemed denied by operation of law. A VLC had also filed a petition for review of the VLC tariff's credit support and collateral requirements in the Wisconsin Circuit Court, but subsequently withdrew its petition.

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

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

2026 Rate Application

In January 2026, PGL and NSG filed requests with the ICC to increase their natural gas base rates. Subsequent to the initial filing, PGL and NSG made various concessions, compromises, and adjustments to their capital plans that reduced their initial requests by $57.3 million and $4.0 million, respectively. PGL and NSG are currently requesting rate increases of $144.0 million (14.6%) and $8.7 million (8.4%), respectively. The requested rate increases are primarily driven by capital investments made to strengthen the safety and reliability of each utility’s natural gas distribution system. PGL's rate request includes the estimated revenue requirements associated with its PRP projects. As discussed below, projects completed under PGL's PRP are to meet the ICC's directive to retire all cast and ductile iron pipe that has a diameter under 36 inches by January 1, 2035. PGL's rate request includes the revenue requirements associated with approximately $349 million of capital investments planned under its PRP in 2027. Higher operating costs, driven by inflation, and increases in the cost of capital, also drove the requested rate increases. Both companies are requesting an ROE of 10.10% and a common equity component average of 54.0%.

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

2023 Rate Order

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

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

•A $304.6 million (43.5%) base rate increase for PGL’s natural gas customers. This amount includes the recovery of costs 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 projects to upgrade its natural gas delivery system until the ICC had a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level.

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

In June 2024, PGL and NSG filed a petition with the Illinois Appellate Court for review of the November 2023 and May 2024 orders; however, the Illinois Appellate Court affirmed these orders and the related disallowances in March 2026. PGL and NSG subsequently petitioned the Illinois Supreme Court for review and reversal of these orders, but their request was denied in September 2026.

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

Illinois Riders

Uncollectible Expense Adjustment Rider

The rates of PGL and NSG include a UEA rider for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. The UEA rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency by the ICC.

In May 2026, the ICC issued a final written order approving a settlement agreement PGL and NSG entered into with the Illinois Attorney General and ICC staff that resolved all open proceedings related to the 2019 through 2023 annual reconciliations of the UEA rider. Under the terms of the settlement, PGL and NSG will refund $49.0 million and $1.0 million, respectively, to customers as bill credits over a period of three years between 2026 and 2028. Half of the refunds will be credited to customers in 2026, and 25% will be refunded in each of 2027 and 2028. PGL and NSG will begin refunding amounts in November 2026. As a result of this agreement, we recorded a $50.0 million reduction to revenues during the fourth quarter of 2025.

Qualifying Infrastructure Plant Rider

In July 2013, Illinois Public Act 98-0057, The Natural Gas Consumer, Safety & Reliability Act, became law. This law provided 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

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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 were still subject to an annual reconciliation whereby such costs were reviewed for accuracy and prudency by the ICC. In August 2024, the ICC issued a final order on PGL's 2016 annual reconciliation, which included a disallowance of $14.8 million of certain capital costs. PGL subsequently filed a petition with the Illinois Appellate Court for review of the ICC's August 2024 order; however, in connection with the settlement agreement discussed below, in June 2026, PGL, the ICC, and the Illinois Attorney General filed a joint motion to dismiss the appeal with prejudice, which was granted by the court.

In May 2026, the ICC issued a final written order approving a settlement agreement PGL entered into with the Illinois Attorney General, ICC staff, and the Illinois Citizens Utility Board that resolved all remaining open annual reconciliation proceedings from 2017 through 2023 related to the QIP rider. Under the terms of the settlement, PGL agreed to permanently remove $130.0 million of qualified infrastructure investment costs from rate base starting in 2027 and to refund $75.0 million to customers as bill credits over a period of three years between 2026 and 2028. As a result of this agreement, we recorded a $155.0 million charge to income during the fourth quarter of 2025. The charge was recorded as a $130.0 million impairment to PGL's net property, plant, and equipment and a $25.0 million reduction to revenues. The total of the rate base reduction and the obligation to refund amounts to customers through bill credits recorded on our balance sheet at September 30, 2026 was $205.0 million. This includes the $155.0 million charge to income recorded during the fourth quarter of 2025 and a $50.0 million charge to income recorded in years prior to 2025. PGL will begin refunding amounts to customers in November 2026, with $25.0 million being refunded in each of the three years starting in 2026 through 2028.

Upper Michigan Energy Resources Corporation

Amended Renewable Energy Plan

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

Renegade achieved commercial operation in March 2026. The estimated cost of Renegade is approximately $226 million. As UMERC's proposal to recover the annual revenue requirement of Renegade through a renewable energy surcharge was denied, UMERC subsequently filed a request for deferral accounting treatment. In April 2026, the MPSC issued an order authorizing UMERC to defer all of the costs associated with owning and operating Renegade. The costs will be reviewed for recovery in a future proceeding.

NOTE 25—OTHER INCOME, NET

Total other income, net was as follows for the three and nine months ended September 30:

						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2026						2025						2026						2025
AFUDC-Equity						$	44.7					$	25.1					$	139.5					$	63.7
Interest income						1.7						0.8						5.9						5.1
Gains from investments held in rabbi trust						1.0						3.4						5.7						6.7
Earnings (losses) from equity method investments (1)						0.8						(8.1)						3.4						(11.0)
Other, net						1.3						2.6						4.7						3.9
Other income, net						$	49.5					$	23.8					$	159.2					$	68.4

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

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NOTE 26—NEW ACCOUNTING PRONOUNCEMENTS

Environmental Credits and Environmental Credit Obligations

In May 2026, the FASB issued ASU No. 2026-02, Environmental Credits and Environmental Credit Obligations (Topic 818). The amendments improve the financial accounting for and disclosure of environmental credits and environmental credit obligations. The update provides recognition, measurement, presentation, and disclosure requirements for all entities that generate, purchase, or receive environmental credits or have a regulatory compliance obligation that may be settled with environmental credits. The amendments are effective for annual periods beginning after December 15, 2027, and interim periods within those annual periods. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

Improvements to Interim Reporting

In December 2025, the FASB issued ASU No. 2025-11, Interim Reporting (Topic 270) Narrow-Scope Improvements. The amendments clarify interim disclosure requirements and the applicability of Topic 270. The amendments include a comprehensive list of interim disclosures that are currently required under GAAP. The amendments also include a disclosure principle that requires entities to disclose events since the end of the last annual reporting period that have a material impact on the entity. Finally, the amendments clarify the types of interim reporting and the form and content of interim financial statements in accordance with GAAP. The amendments are effective for interim periods within annual periods beginning after December 15, 2027, with early adoption permitted. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

Accounting for Government Grants

In December 2025, the FASB issued ASU No. 2025-10, Government Grants (Topic 832) Accounting for Government Grants Received by Business Entities. The amendments establish the accounting for a government grant received by a business entity, including guidance for a grant related to an asset and a grant related to income. The amendments also require disclosures, including the nature of the government grant received, the accounting policies used to account for the grant, and significant terms and conditions of the grant. The amendments are effective for annual periods beginning after December 15, 2028, and interim periods within those annual periods, with early adoption permitted. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

Disaggregation of Income Statement Expenses

In November 2024, the FASB issued ASU No. 2024-03, Income Statement-Reporting Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40) Disaggregation of Income Statement Expenses. The amendments require disclosure of certain costs and expenses in the notes to financial statements, which are disaggregated from relevant expense captions on the income statement. The amendments also require additional qualitative disclosures of the amounts remaining in relevant expense captions that are not separately disaggregated quantitatively. Finally, the amendments require disclosure of the total amount of selling expenses and, in annual reporting periods, an entity's definition of selling expenses. The amendments are effective for annual periods beginning after December 15, 2026, and interim periods beginning after December 15, 2027, with early adoption permitted. We plan to adopt these amendments beginning with our fiscal year ending on December 31, 2027, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CORPORATE DEVELOPMENTS

The following discussion should be read in conjunction with the accompanying unaudited financial statements and related notes and our 2025 Annual Report on Form 10-K.

Introduction

We are a diversified holding company with natural gas and electric utility operations (serving customers in Wisconsin, Illinois, Michigan, and Minnesota), an approximately 60% equity ownership interest in ATC (a for-profit electric transmission company regulated by the FERC and certain state regulatory commissions), and non-utility energy infrastructure operations through We Power (which owns generation assets in Wisconsin that it leases to WE), Bluewater (which owns underground natural gas storage facilities in Michigan), and WECI (which holds ownership interests in several renewable generating facilities).

Corporate Strategy

We are working to build and sustain long-term value for our shareholders and customers by supporting economic growth in our region while focusing on the fundamentals of our business: reliability, operating efficiency, financial discipline, environmental stewardship, exceptional customer care, and safety. Our capital plan provides a roadmap for us to achieve this goal. It is a plan premised upon maintaining superior reliability, delivering savings for customers, and growing our investment in the future of energy.

Throughout our strategic planning process, we take into account important developments, risks and opportunities, including new technologies, customer preferences and affordability, energy resiliency efforts, and sustainability.

Supporting Economic Growth Within Our Communities

Economic growth continues in our Wisconsin service territories. Companies are investing in major projects, including data centers and modern manufacturing facilities. We anticipate electric demand growth in the years ahead from these economic developments. Microsoft has announced plans to invest over $20 billion in data centers in southeastern Wisconsin over the next several years, and we expect up to 3.2 GWs of load growth in the Milwaukee-to-Chicago corridor through 2031. The first phase of the project went into service in April 2026. Additionally, Vantage Data Centers is developing a large data center campus in Port Washington that is forecasted to add 1.3 GWs of demand through 2031. This site has the potential to add an incremental 2.2 GWs, for a total of up to 3.5 GWs over time. We are working closely with these large customers to provide power to meet this substantial projected demand. In May 2026, the PSCW approved new VLC and Bespoke Resources tariffs, which specifically address the unique needs of VLCs while protecting our other customers and shareholders. Subsequent to its approval, Microsoft entered into a service agreement to obtain service under the VLC tariff. See Note 24, Regulatory Environment, for more information on the VLC and Bespoke Resources tariffs.

To meet the forecasted electric demand growth in the years ahead, greater capacity will be required to provide affordable, reliable, and clean energy for our communities. In August 2026, we entered into an agreement to extend the PPA for the Point Beach nuclear power plant, which will allow us to continue purchasing approximately 1,000 MWs of capacity for an additional 20 years beyond the current agreement. This new agreement is subject to PSCW approval and if approved, will not take effect until the current PPA expires in 2030 for Unit 1 and 2033 for Unit 2. The forecasted demand growth is also addressed in our capital plan with a range of planned investments in natural gas-fired generation, renewables, and battery storage. We plan on investing approximately $9.4 billion from 2027 to 2031 in efficient natural gas-fired generation and related infrastructure, including:

•3,540 MWs of CTs and reciprocating internal combustion engine natural gas-fueled generation (we plan on constructing a new natural gas lateral pipeline to support the CTs planned at our OCPP site);

•750 MWs of combined cycle gas turbines; and

•200 MWs of combined cycle gas turbine summer upgrades.

We expect to invest approximately $13.7 billion from 2027 to 2031 in regulated renewable energy in Wisconsin. Our plan is to build and own zero-carbon-emitting renewable generation facilities that are anticipated to include the following investments:

•3,100 MWs of utility-scale solar;

•3,450 MWs of battery storage; and

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•600 MWs of wind.

For more details on the projects discussed above, see Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.

Our capital plan also reflects the planned retirement of our older, fossil-fueled generation, which we expect to replace with the natural gas-fired generation and zero-carbon-emitting renewables discussed above. Our long-term goal is to achieve net carbon neutral electric generation by the end of 2050. We expect to achieve this goal by continuing to make operating refinements, retiring less efficient generating units, and executing our capital plan.

As part of our path toward this goal, we have started implementing co-firing with natural gas at the ERGS coal-fired units and at Weston Unit 4. Additionally, we have retired nearly 2,500 MWs of fossil-fueled generation since the beginning of 2018, which includes the retirement of OCPP Units 5 and 6 in May 2024, the 2019 retirement of the Presque Isle Power Plant, and the 2018 retirements of the Pleasant Prairie power plant, the J.P. Pulliam Generating power plant, and the jointly-owned Edgewater Generating Station Unit 4. We expect to retire additional coal-fired generation, including OCPP Units 7 and 8. See Note 7, Property, Plant, and Equipment, for more information related to the planned retirement of OCPP Units 7 and 8. We and the other co-owners of Columbia Units 1 and 2 currently plan to continue coal operations at these units through at least 2030.

When taken together, the retirements and new investments in natural gas generation and renewables should better balance our supply with our demand, while helping to maintain reliable, affordable energy for our customers.

We also continue to focus on methane emission reductions by improving and upgrading our natural gas distribution systems and using RNG throughout our natural gas utility systems. In 2023, we began transporting the output of local dairy farms onto our natural gas distribution systems in Wisconsin. The RNG supplied is replacing higher-emission methane from natural gas that would have entered our pipes. We currently have contracts in place for 2.1 Bcf of RNG.

Reliability

We have made significant reliability-related investments in recent years, and in accordance with our capital plan, expect to continue strengthening and modernizing our generation fleet, as well as our electric and natural gas distribution networks to further improve reliability.

Below are a few of the more significant projects that are proposed, currently underway, or recently completed.

•The PSCW approved WE's request to construct an LNG facility with a storage capacity of two Bcf, which will be located on the OCPP site. In addition, the construction of additional LNG facilities in Wisconsin has been proposed as part of our capital plan and would provide another approximately two Bcf of natural gas supply. The LNG facilities are expected to reduce the likelihood of constraints on our natural gas distribution system during the highest demand days of winter.

•PGL had been working to replace old iron pipes and facilities in Chicago’s natural gas delivery system with modern polyethylene pipes to reinforce the long-term safety and reliability of the system. In November 2023, the ICC ordered PGL to pause spending on these projects until the ICC completed a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level. In February 2025, the ICC issued an order setting expectations for PGL's prospective retirement of its aging natural gas infrastructure. The ICC directed PGL to focus on retiring all cast and ductile iron pipes that have a diameter of less than 36 inches by January 1, 2035. PGL is working to retire this cast and ductile iron pipe through its PRP. For more information, see Note 24, Regulatory Environment, and Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Illinois Proceeding – Replacement of Aging Natural Gas Infrastructure.

•Our capital plan includes investments in battery energy storage systems, which are intended to capture excess power and release it during peak demand or when power is limited due to weather or other unexpected disruptions.

•Our utilities continue to upgrade their electric and natural gas distribution systems to enhance reliability and storm hardening.

We expect to spend approximately $7.6 billion and $5.2 billion on reliability related to natural gas and electric distribution projects, respectively, from 2027 to 2031, with continued investment over the next decade. For more details, see Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.

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Operating Efficiency

We continually look for ways to optimize the operating efficiency of our Company and will continue to do so under our capital plan. For example, we continue to make progress on our advanced metering infrastructure program, replacing aging meter-reading equipment on both our network and customer property. An integrated system of smart meters, communication networks, and data management programs enables two-way communication between our utilities and our customers. This program reduces the manual effort for customer connections and enhances outage management capabilities.

Through our multiyear Energy Delivery Program, we are planning to implement capabilities and standard processes for customer service, natural gas and electric operations, work management, and field operations. This includes improvements to outage management, geographic information systems, and work and asset management systems, as well as the implementation of new capabilities through advanced distribution management systems.

We continue to focus on integrating the resources of all our businesses and improving our business processes to find the best and most efficient processes possible, including evaluating the use of AI tools. We expect these efforts to continue to drive operational efficiency and to put us in a position to effectively support plans for future growth.

Financial Discipline

A strong adherence to financial discipline is essential to meeting our earnings projections and maintaining a strong balance sheet, stable cash flows, a growing dividend, and quality credit ratings. We work to earn allowed rates of return through a focus on cost control and strategic investment.

Our planned investment focus from 2027 to 2031 is in our regulated utilities and our investment in ATC. We expect total capital expenditures for our regulated utility businesses to be approximately $42.2 billion from 2027 to 2031. In addition, we currently forecast that our share of ATC's projected capital expenditures over the next five years will be approximately $5.3 billion. For additional information regarding projects included in our $47.5 billion capital plan, see Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.

We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plants, equipment, and entire business units, that are no longer strategic to operations, are not performing as intended, or have an unacceptable risk profile. See Note 2, Acquisitions, and Note 3, Disposition, for additional information on our recent and pending transactions.

Exceptional Customer Care

Our approach is driven by an intense focus on delivering exceptional customer care every day. We strive to provide the best value for our customers by demonstrating personal responsibility for results, leveraging our capabilities and expertise, and using creative solutions to meet or exceed our customers’ expectations.

A multiyear effort is driving a standardized, seamless approach to digital customer service across our companies. We have moved all utilities to a common platform for all customer-facing self-service options. Using common systems and processes reduces costs, provides greater flexibility and enhances the consistent delivery of exceptional service to customers.

Safety

Safety is one of our core values and a critical component of our culture. We are committed to keeping our employees and the public safe through a comprehensive corporate safety program that focuses on employee engagement and elimination of at-risk behaviors. To further protect public safety, we monitor the integrity of our distribution systems, have emergency response and business continuity plans in place, and provide key safety information to customers, contractors, and first responders.

Under our "Target Zero" mission, we have an ultimate goal of zero incidents, accidents, and injuries. Management and union leadership work together to reinforce the Target Zero culture. We set annual goals for safety results as well as measurable leading indicators, in order to raise awareness of at-risk behaviors and situations and guide injury-prevention activities. All employees are

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encouraged to report unsafe conditions or incidents that could have led to an injury. Injuries and tasks with high levels of risk are assessed, and findings and best practices are shared across our companies.

Our corporate safety program provides a forum for addressing employee concerns, training employees and contractors on current safety standards, and recognizing those who demonstrate a safety focus.

RESULTS OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2026

Consolidated Earnings

The following table compares our consolidated results for the third quarter of 2026 with the third quarter of 2025, including favorable or better, "B", and unfavorable or worse, "W", variances:

						Three Months Ended September 30
(in millions, except per share data)						2026						2025						B (W)
Wisconsin						$	361.7					$	281.3					$	80.4
Illinois						(21.2)						(30.5)						9.3
Other states						(8.8)						(8.9)						0.1
Electric transmission						46.3						37.3						9.0
Non-utility energy infrastructure						92.8						87.9						4.9
Corporate and other						(81.5)						(95.8)						14.3
Net income attributed to common shareholders						$	389.3					$	271.3					$	118.0
Diluted EPS						$	1.18					$	0.83					$	0.35

Earnings increased $118.0 million during the third quarter of 2026, compared with the same quarter in 2025. The $118.0 million increase in earnings was driven by:

•An $80.4 million increase in net income attributed to common shareholders at the Wisconsin segment, driven by higher margins due to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2026, higher retail sales volumes due to warmer summer weather and the impact of our VLCs, and carrying costs earned during the third quarter of 2026 on the construction of certain Bespoke Resources assigned to our VLCs. See Note 26, Regulatory Environment, in our 2025 Annual Report on Form 10-K, for more information on our Wisconsin rate orders. Higher AFUDC-Equity and increases in certain income tax benefits also contributed to the higher earnings. These positive impacts were partially offset by higher operating expenses, primarily due to an increase in regulatory amortizations and other pass through expenses, an increase in transmission expense, and higher depreciation and amortization expense. These increases in operating expenses were partially offset by lower benefit expense.

•A $14.3 million decrease in the net loss attributed to common shareholders at the corporate and other segment, driven by a decrease in an interim income tax expense recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate. Net earnings from our equity method investments in technology and energy-focused investment funds during the third quarter of 2026, compared with net losses during the same quarter in 2025 also contributed to the lower net loss attributed to common shareholders.

•A $9.3 million decrease in the net loss attributed to common shareholders at the Illinois segment, driven by lower benefit expense and an increase in revenues related to higher fixed charges.

•A $9.0 million increase in net income attributed to common shareholders at the electric transmission segment, driven by continued capital investment by ATC.

Non-GAAP Financial Measures

The discussions below address the contribution of each of our utility segments to net income attributed to common shareholders. The discussions include financial information prepared in accordance with GAAP, as well as utility margin, which is not a measure of

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financial performance under GAAP. Utility margin (operating revenues less fuel and purchased power costs and cost of natural gas sold) is a non-GAAP financial measure because it excludes certain operation and maintenance expenses applicable to revenues, as well as depreciation and amortization and property and revenue taxes.

We believe that utility margin provides a useful basis for evaluating utility operations since the majority of prudently incurred fuel and purchased power costs, as well as prudently incurred natural gas costs, are passed through to customers in current rates. As a result, management uses utility margin internally when assessing the operating performance of our utility segments as these measures exclude the majority of revenue fluctuations caused by changes in these expenses. Similarly, the presentation of utility margin herein is intended to provide supplemental information for investors regarding our operating performance.

Our utility margin may not be comparable to similar measures presented by other companies. Furthermore, this measure is not intended to replace gross margin as determined in accordance with GAAP as an indicator of operating performance. Each of our three utility segment discussions below include a table that provides the calculation of both gross margin as determined in accordance with GAAP and utility margin, as well as a reconciliation between the two measures.

Wisconsin Segment Contribution to Net Income Attributed to Common Shareholders

The Wisconsin segment's contribution to net income attributed to common shareholders was $361.7 million during the third quarter of 2026, representing an $80.4 million, or 28.6%, increase over the same quarter in 2025. The increase in earnings was driven by higher margins due to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2026, higher retail sales volumes due to warmer summer weather and the impact of our VLCs, and carrying costs earned during the third quarter of 2026 on the construction of certain Bespoke Resources assigned to our VLCs. See Note 26, Regulatory Environment, in our 2025 Annual Report on Form 10-K, for more information on our Wisconsin rate orders. Higher AFUDC-Equity and increases in certain income tax benefits also contributed to the higher earnings. These positive impacts were partially offset by higher operating expenses, primarily due to an increase in regulatory amortizations and other pass through expenses, an increase in transmission expense, and higher depreciation and amortization expense. These increases in operating expenses were partially offset by lower benefit expense.

						Three Months Ended September 30
(in millions)						2026						2025						B (W)
Operating revenues						$	1,964.7					$	1,791.6					$	173.1
Operating expenses
Cost of sales (1)						609.4						578.2						(31.2)
Other operation and maintenance						479.3						443.7						(35.6)
Depreciation and amortization						271.8						255.7						(16.1)
Property and revenue taxes						49.0						44.5						(4.5)
Operating income						555.2						469.5						85.7
Other income, net						43.6						25.0						18.6
Interest expense						175.0						158.9						(16.1)
Income before income taxes						423.8						335.6						88.2
Income tax expense						61.8						54.0						(7.8)
Preferred stock dividends of subsidiary						0.3						0.3						—
Net income attributed to common shareholders						$	361.7					$	281.3					$	80.4

(1)    Cost of sales includes fuel and purchased power and cost of natural gas sold.

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The following table shows a breakdown of other operation and maintenance:

						Three Months Ended September 30
(in millions)						2026						2025						B (W)
Operation and maintenance not included in line items below						$	189.3					$	214.7					$	25.4
Transmission (1)						163.7						146.2						(17.5)
Regulatory amortizations and other pass through expenses (2)						81.6						51.7						(29.9)
We Power (3)						30.6						31.9						1.3
Earnings sharing mechanisms (4)						14.1						(0.8)						(14.9)
Total other operation and maintenance						$	479.3					$	443.7					$	(35.6)

(1)Represents transmission expense that our electric utilities are authorized to collect in rates. The PSCW has approved escrow accounting for ATC and MISO network transmission expenses for WE and WPS. As a result, 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. During the third quarter of 2026 and 2025, $184.4 million and $157.9 million, respectively, of costs were billed to our electric utilities by transmission providers.

(2)Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on net income.

(3)Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE. During the third quarter of 2026 and 2025, $28.2 million and $29.0 million, respectively, of costs were billed to or incurred by WE related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset or liability.

(4)    Represents operation and maintenance associated with the earnings mechanisms we have in place, both the current year sharing estimate and the amortization of prior year amounts. See Note 26, Regulatory Environment, in our 2025 Annual Report on Form 10-K, for more information.

The following tables provide information on delivered sales volumes by customer class and weather statistics:

						Three Months Ended September 30
Electric Sales Volumes (MWh - in thousands)						2026						2025						B (W)
Customer Class
Residential						3,510.8						3,339.2						171.6
Small commercial and industrial (1)						3,679.5						3,555.8						123.7
Large commercial and industrial (1)						3,640.0						3,239.0						401.0
Other						23.1						25.5						(2.4)
Total retail (1)						10,853.4						10,159.5						693.9
Wholesale						465.1						476.1						(11.0)
Resale						1,481.5						1,667.8						(186.3)
Total sales in MWh (1)						12,800.0						12,303.4						496.6

(1)Includes distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.

						Three Months Ended September 30
Natural Gas Sales Volumes (Therms - in millions)						2026						2025						B (W)
Customer Class
Residential						56.7						58.5						(1.8)
Commercial and industrial						56.7						60.7						(4.0)
Total retail						113.4						119.2						(5.8)
Transportation						283.8						274.2						9.6
Total sales in therms						397.2						393.4						3.8

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						Three Months Ended September 30
Weather (Degree Days) (1)						2026						2025						B (W)
WE and WG
Heating (90 Normal)						69						68						1.5		%
Cooling (530 Normal)						606						574						5.6		%
WPS
Heating (168 Normal)						128						163						(21.5)		%
Cooling (387 Normal)						463						469						(1.3)		%
UMERC
Heating (290 Normal)						200						261						(23.4)		%
Cooling (259 Normal)						331						270						22.6		%

(1)Normal degree days are based on a 20-year moving average of monthly temperature readings from National Oceanic and Atmospheric Administration weather stations within each company's respective service territories.

Gross Margin GAAP and Utility Margin Non-GAAP

The following table summarizes our Wisconsin segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See Non-GAAP Financial Measures above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).

						Three Months Ended September 30
(in millions)						2026						2025						B (W)
Electric revenues						$	1,808.3					$	1,611.0					$	197.3
Natural gas revenues						156.4						180.6						(24.2)
Operating revenues						1,964.7						1,791.6						173.1
Operating expenses
Fuel and purchased power						(559.1)						(502.4)						(56.7)
Cost of natural gas sold						(50.3)						(75.8)						25.5
Other operation and maintenance (1)						(309.0)						(315.5)						6.5
Depreciation and amortization						(271.8)						(255.7)						(16.1)
Property and revenue taxes						(49.0)						(44.5)						(4.5)
Gross margin (GAAP)						725.5						597.7						127.8
Other operation and maintenance (1)						309.0						315.5						(6.5)
Depreciation and amortization						271.8						255.7						16.1
Property and revenue taxes						49.0						44.5						4.5
Utility margin (non-GAAP)						$	1,355.3					$	1,213.4					$	141.9

(1)    Operating and maintenance expenses deemed to be directly attributable to our revenue-producing activities include plant operating and maintenance expenses related to our generating units; costs associated with the We Power generating units; and transmission, distribution and customer service expenses. These expenses are included in the above table to calculate gross margin as defined under GAAP.

Gross margin (GAAP) at the Wisconsin segment increased $127.8 million during the third quarter of 2026, compared with the same quarter in 2025, and utility margin (non-GAAP) increased $141.9 million during the third quarter of 2026, compared with the same quarter in 2025. Both measures were driven by:

•A $54.8 million increase in margins driven by the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2026. See Note 26, Regulatory Environment, in our 2025 Annual Report on Form 10-K, for more information.

•A $47.5 million net increase in margins related to higher electric retail sales volumes, driven by a $24.3 million increase from warmer summer weather. As measured by cooling degree days, the third quarter of 2026 was 5.6% warmer than the same quarter in 2025 in the combined WE and WG service area. In addition, margins related to weather-normalized customer growth increased $23.2 million, driven by the impact of our VLCs.

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•A current return of $38.3 million consisting of carrying costs earned during the construction of certain Bespoke Resources assigned to our VLCs during the third quarter of 2026. See Note 4, Operating Revenues, for more information.

Additionally, the smaller increase in gross margin (GAAP) as compared with the increase in utility margin (non-GAAP), was driven by the following items that are further described in Other Operating Expenses below:

•A $17.5 million increase in transmission expense;

•A $16.1 million increase in depreciation and amortization expense;

•A $9.0 million increase in electric and natural gas distribution expense; and

•A partially offsetting $13.7 million decrease in other operating and maintenance related to our power plants.

Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)

Other operating expenses at the Wisconsin segment increased $56.2 million during the third quarter of 2026, compared with the same quarter in 2025. The significant factors impacting the increase in other operating expenses were:

•A $29.9 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

•A $17.5 million increase in transmission expense as approved by the PSCW in our Wisconsin rate orders, effective January 1, 2026. See the notes under the other operation and maintenance table above for more information.

•A $16.1 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.

•A $14.9 million increase in expense related to the earnings sharing mechanisms in place at our Wisconsin utilities, driven by earnings sharing recorded at WE during the third quarter of 2026. The earnings sharing mechanisms are discussed in the notes under the other operation and maintenance table above.

•A $9.0 million increase in electric and natural gas distribution expenses, driven by higher costs to maintain the distribution systems and an increase in storm costs during the third quarter of 2026, compared with the same quarter in 2025.

These increases were partially offset by the following:

•A $28.2 million decrease in benefit expenses, driven by various employee compensation plans.

•A $13.7 million decrease in other operating and maintenance related to our power plants during the third quarter of 2026, compared with the same quarter in 2025, driven by a reduction in allowed expense for OCPP and Columbia under escrow accounting, as approved by the PSCW in our Wisconsin rate orders.

Other Income, Net

Other income, net at the Wisconsin segment increased $18.6 million during the third quarter of 2026, compared with the same quarter in 2025, driven by a $19.7 million positive impact from higher AFUDC-Equity due to continued capital investment.

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Interest Expense

Interest expense at the Wisconsin segment increased $16.1 million during the third quarter of 2026, compared with the same quarter in 2025. The increase was primarily due to the impact of long-term debt issuances in the fourth quarter of 2025 and 2026. This increase was partially offset by AFUDC-Debt that was $8.8 million higher quarter-over-quarter due to continued capital investment, and the impact of long-term debt maturities in 2025.

Income Tax Expense

Income tax expense at the Wisconsin segment increased $7.8 million during the third quarter of 2026, compared with the same quarter in 2025, driven by higher pre-tax income.

Partially offsetting this increase in income tax expense was:

•A $5.3 million favorable income tax impact associated with certain tax-related regulatory deferrals;

•A $5.4 million increase in PTCs and ITCs; and

•A $3.6 million increase in income tax benefits associated with AFUDC-Equity, driven by continued capital investment.

See Note 13, Income Taxes, for more information.

Illinois Segment Contribution to Net Income Attributed to Common Shareholders

The Illinois segment's net loss attributed to common shareholders was $21.2 million during the third quarter of 2026, representing a $9.3 million, or 30.5%, reduction in the net loss over the same quarter in 2025. The decrease in the net loss was driven by lower benefit expense and an increase in revenues related to higher fixed charges.

Since the majority of PGL and NSG customers use natural gas for heating, net income attributed to common shareholders at the Illinois segment is sensitive to weather and is generally higher during the winter months.

						Three Months Ended September 30
(in millions)						2026						2025						B (W)
Operating revenues						$	183.2					$	183.5					$	(0.3)
Operating expenses
Cost of natural gas sold						27.4						21.4						(6.0)
Other operation and maintenance						89.2						108.0						18.8
Depreciation and amortization						67.1						65.0						(2.1)
Property and revenue taxes						11.2						11.4						0.2
Operating loss						(11.7)						(22.3)						10.6
Other income, net						2.6						2.1						0.5
Interest expense						21.1						21.8						0.7
Loss before income taxes						(30.2)						(42.0)						11.8
Income tax benefit						(9.0)						(11.5)						(2.5)
Net loss attributed to common shareholders						$	(21.2)					$	(30.5)					$	9.3

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The following table shows a breakdown of other operation and maintenance:

						Three Months Ended September 30
(in millions)						2026						2025						B (W)
Operation and maintenance not included in the line items below						$	78.8					$	87.6					$	8.8
Riders (1)						10.3						19.6						9.3
Regulatory amortizations (1)						0.1						0.8						0.7
Total other operation and maintenance						$	89.2					$	108.0					$	18.8

(1)These riders and regulatory amortizations are substantially offset in margins and therefore do not have a significant impact on net income.

The following tables provide information on delivered sales volumes by customer class and weather statistics:

						Three Months Ended September 30
Natural Gas Sales Volumes (Therms - in millions)						2026						2025						B (W)
Customer Class
Residential						43.8						43.3						0.5
Commercial and industrial						20.6						20.8						(0.2)
Total retail						64.4						64.1						0.3
Transportation						84.4						82.4						2.0
Total sales in therms						148.8						146.5						2.3

						Three Months Ended September 30
Weather (Degree Days) (1)						2026						2025						B (W)
Heating (46 Normal)						30						34						(11.8)		%

(1)Normal heating degree days are based on a 12-year moving average of monthly temperature readings from National Oceanic and Atmospheric Administration weather stations throughout our Illinois service territories.

Gross Margin GAAP and Utility Margin Non-GAAP

The following table summarizes our Illinois segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See Non-GAAP Financial Measures above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).

						Three Months Ended September 30
(in millions)						2026						2025												B (W)
Operating revenues						$	183.2					$	183.5											$	(0.3)
Operating expenses
Cost of natural gas sold						(27.4)						(21.4)												(6.0)
Other operation and maintenance (1)						(58.5)						(58.9)												0.4
Depreciation and amortization						(67.1)						(65.0)												(2.1)
Property and revenue taxes						(11.2)						(11.4)												0.2
Gross margin (GAAP)						19.0						26.8												(7.8)
Other operation and maintenance (1)						58.5						58.9												(0.4)
Depreciation and amortization						67.1						65.0												2.1
Property and revenue taxes						11.2						11.4												(0.2)
Utility margin (non-GAAP)						$	155.8					$	162.1											$	(6.3)

(1)    Operating and maintenance expenses deemed to be directly attributable to our revenue-producing activities include distribution and customer service expenses. These expenses are included in the above table to calculate gross margin as defined under GAAP.

Gross margin (GAAP) at the Illinois segment decreased $7.8 million during the third quarter of 2026, compared with the same quarter in 2025, and utility margin (non-GAAP) decreased $6.3 million during the third quarter of 2026, compared with the same quarter in 2025. Both measures were driven by a $9.3 million decrease in revenues associated with certain riders that are offset in

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other operation and maintenance and therefore do not have a significant impact on net income. This decrease in gross margin (GAAP) and utility margin (non-GAAP) was partially offset by a $1.4 million increase in revenues associated with fixed customer charges during the third quarter of 2026, compared with the same quarter in 2025.

Additionally, the larger decrease in gross margin (GAAP) as compared with the decrease in utility margin (non-GAAP), was driven by the following items that are further described in Other Operating Expenses below:

•A $2.1 million increase in depreciation and amortization expense;

•A $1.5 million increase in natural gas distribution and maintenance costs; and

•A partially offsetting $0.6 million decrease in costs at the Manlove Gas Storage Field.

Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)

Other operating expenses at the Illinois segment decreased $7.6 million, net of the $9.3 million impact of the riders referenced above, during the third quarter of 2026, compared with the same quarter in 2025. The significant factors impacting the decrease in other operating expenses were:

•A $9.6 million decrease in benefit expense.

•A $0.6 million decrease in costs at the Manlove Gas Storage Field.

These decreases in operating expenses were partially offset by:

•A $2.1 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.

•A $1.5 million increase in natural gas distribution and maintenance costs, primarily related to maintaining the natural gas infrastructure.

Interest Expense

Interest expense at the Illinois segment decreased $0.7 million during the third quarter of 2026, compared with the same quarter in 2025, driven by the impact of PGL's Series VV and Series ZZ mortgage bonds redemptions in March 2026. See Note 10, Long-Term Debt, for more information.

Income Tax Benefit

The income tax benefit at the Illinois segment decreased $2.5 million during the third quarter of 2026, compared with the same quarter in 2025, driven by a decrease in pre-tax loss.

Other States Segment Contribution to Net Income Attributed to Common Shareholders

The other states segment's net loss attributed to common shareholders was $8.8 million during the third quarter of 2026, representing a $0.1 million, or 1.1%, decrease in the net loss over the same quarter in 2025. The lower net loss was driven by a decrease in benefit expense and an increase in margins related to higher sales volumes. These positive impacts were partially offset by an increase in the provision for credit losses and higher depreciation and amortization expense.

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Since the majority of MERC and MGU customers use natural gas for heating, net income attributed to common shareholders at the other states segment is sensitive to weather and is generally higher during the winter months.

						Three Months Ended September 30
(in millions)						2026						2025						B (W)
Operating revenues						$	60.9					$	53.0					$	7.9
Operating expenses
Cost of natural gas sold						23.3						17.5						(5.8)
Other operation and maintenance						24.7						23.6						(1.1)
Depreciation and amortization						13.5						12.5						(1.0)
Property and revenue taxes						6.8						6.6						(0.2)
Operating loss						(7.4)						(7.2)						(0.2)
Other income, net						0.3						0.1						0.2
Interest expense						4.8						5.0						0.2
Loss before income taxes						(11.9)						(12.1)						0.2
Income tax benefit						(3.1)						(3.2)						(0.1)
Net loss attributed to common shareholders						$	(8.8)					$	(8.9)					$	0.1

The following table shows a breakdown of other operation and maintenance:

						Three Months Ended September 30
(in millions)						2026						2025						B (W)
Operation and maintenance not included in line item below						$	20.2					$	21.4					$	1.2
Regulatory amortizations and other pass through expenses (1)						4.5						2.2						(2.3)
Total other operation and maintenance						$	24.7					$	23.6					$	(1.1)

(1)Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on net income.

The following tables provide information on delivered sales volumes by customer class and weather statistics:

						Three Months Ended September 30
Natural Gas Sales Volumes (Therms - in millions)						2026						2025						B (W)
Customer Class
Residential						17.0						16.8						0.2
Commercial and industrial						13.7						15.4						(1.7)
Total retail						30.7						32.2						(1.5)
Transportation						183.8						159.8						24.0
Total sales in therms						214.5						192.0						22.5

						Three Months Ended September 30
Weather (Degree Days) (1)						2026						2025						B (W)
MERC
Heating (189 Normal)						127						148						(14.2)		%
MGU
Heating (106 Normal)						86						92						(6.5)		%

(1)Normal heating degree days for MERC and MGU are based on a 20-year moving average and 15-year moving average, respectively, of monthly temperature readings from National Oceanic and Atmospheric Administration weather stations throughout their respective service territories.

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Gross Margin GAAP and Utility Margin Non-GAAP

The following table summarizes our other states segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See Non-GAAP Financial Measures above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).

						Three Months Ended September 30
(in millions)						2026						2025						B (W)
Operating revenues						$	60.9					$	53.0					$	7.9
Operating expenses
Cost of natural gas sold						(23.3)						(17.5)						(5.8)
Other operation and maintenance (1)						(15.3)						(15.0)						(0.3)
Depreciation and amortization						(13.5)						(12.5)						(1.0)
Property and revenue taxes						(6.8)						(6.6)						(0.2)
Gross margin (GAAP)						2.0						1.4						0.6
Other operation and maintenance (1)						15.3						15.0						0.3
Depreciation and amortization						13.5						12.5						1.0
Property and revenue taxes						6.8						6.6						0.2
Utility margin (non-GAAP)						$	37.6					$	35.5					$	2.1

(1)    Operating and maintenance expenses deemed to be directly attributable to our revenue-producing activities include distribution and customer service expenses. These expenses are included in the above table to calculate gross margin as defined under GAAP.

Gross margin (GAAP) increased $0.6 million during the third quarter of 2026, compared with the same quarter in 2025, and utility margin (non-GAAP) increased $2.1 million during the third quarter of 2026, compared with the same quarter in 2025. Both measures were driven by:

•A $1.4 million increase in margins related to higher sales volumes during the second quarter of 2026, compared with the same quarter in 2025.

•A $0.8 million positive impact related to MGU's energy optimization program, which provides rebates, incentives, and energy efficiency education to customers.

Additionally, the smaller increase in gross margin (GAAP) as compared to the increase in utility margin (non-GAAP), was driven by a $1.0 million increase in depreciation and amortization expense that is further described in Other Operating Expenses below.

Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)

Other operating expenses at the other states segment increased $2.3 million during the third quarter of 2026, compared with the same quarter in 2025. The significant factors impacting the increase in operating expenses were:

•A $1.7 million increase in the provision for credit losses, primarily driven by the aging of MGU's customer receivables.

•A $1.0 million increase in depreciation and amortization expense related to continued capital investment.

•A $0.8 million increase related to MGU's energy optimization program.

These increases in operating expenses were partially offset by a $1.7 million decrease in benefit expense.

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Interest Expense

Interest expense at the other states segment decreased $0.2 million during the third quarter of 2026, compared with the same quarter in 2025, driven by lower average short-term debt interest rates.

Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders

						Three Months Ended September 30
(in millions)						2026						2025						B (W)
Equity in earnings of transmission affiliates						$	65.8					$	54.8					$	11.0
Interest expense						3.9						4.8						0.9
Income before income taxes						61.9						50.0						11.9
Income tax expense						15.6						12.7						(2.9)
Net income attributed to common shareholders						$	46.3					$	37.3					$	9.0

Equity in Earnings of Transmission Affiliates

Equity in earnings of transmission affiliates increased $11.0 million during the third quarter of 2026, compared with the same quarter in 2025, driven by continued capital investment by ATC.

Interest Expense

Interest expense at the electric transmission segment decreased $0.9 million during the third quarter of 2026, compared with the same quarter in 2025, due to the maturity of long-term debt in December 2025.

Income Tax Expense

Income tax expense at the electric transmission segment increased $2.9 million during the third quarter of 2026, compared with the same quarter in 2025, driven by higher pre-tax income.

Non-Utility Energy Infrastructure Segment Contribution to Net Income Attributed to Common Shareholders

						Three Months Ended September 30
(in millions)						2026						2025						B (W)
Operating income						$	103.5					$	92.0					$	11.5
Other income, net						0.7						0.8						(0.1)
Interest expense						30.0						30.5						0.5
Income before income taxes						74.2						62.3						11.9
Income tax benefit						(19.3)						(24.2)						(4.9)
Net (income) loss attributed to noncontrolling interests						(0.7)						1.4						(2.1)
Net income attributed to common shareholders						$	92.8					$	87.9					$	4.9

Operating Income

Operating income at the non-utility energy infrastructure segment increased $11.5 million during the third quarter of 2026, compared with the same quarter in 2025, driven by the following items at WECI:

•An $8.8 million increase in capacity revenues due to strong capacity pricing.

•A $6.1 million reduction in operation and maintenance expenses due primarily to having fixed-cost full service agreements in place in 2026.

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•A net $3.5 million positive impact related to lower impairment losses recorded at our Thunderhead wind and Samson I and Delilah I solar facilities in the third quarter of 2026 related to damage incurred associated with various storms.

These increases in operating income at WECI were partially offset by a $9.0 million decrease due to performance payments received in the third quarter of 2025.

In addition to the above items at WECI, there was a $2.7 million positive impact from We Power due to continued capital investment.

Interest Expense

Interest expense at the non-utility energy infrastructure segment decreased $0.5 million during the third quarter of 2026, compared with the same quarter in 2025, primarily due to a lower principal balance, as a result of the semi-annual principal payments on long-term debt at WECI's subsidiaries. Partially offsetting the decrease was a $1.3 million increase in interest expense due to WECI's issuance of a $100.0 million long-term intercompany note to WEC Energy Group in April 2026. This intercompany interest expense is offset by higher interest income at our corporate and other segment and is eliminated in consolidation.

Income Tax Benefit

The income tax benefit at the non-utility energy infrastructure segment decreased $4.9 million during the third quarter of 2026, compared with the same quarter in 2025, primarily due to higher pre-tax income.

Corporate and Other Segment Contribution to Net Income Attributed to Common Shareholders

						Three Months Ended September 30
(in millions)						2026						2025						B (W)
Operating income (loss)						$	2.5					$	(2.0)					$	4.5
Other income, net						11.3						3.7						7.6
Interest expense						94.3						90.9						(3.4)
Loss before income taxes						(80.5)						(89.2)						8.7
Income tax expense						1.0						6.6						5.6
Net loss attributed to common shareholders						$	(81.5)					$	(95.8)					$	14.3

Operating Income (Loss)

The corporate and other segment had operating income of $2.5 million during the third quarter of 2026, compared with an operating loss of $2.0 million during the same quarter in 2025. The quarter-over-quarter change was driven by a decrease in benefit expense at WEC Energy Group during the third quarter of 2026.

Other Income, Net

Other income, net at the corporate and other segment increased $7.6 million during the third quarter of 2026, compared with the same quarter in 2025, driven by an $8.9 million increase due to $0.2 million of net earnings from our equity method investments in technology and energy-focused investment funds during the third quarter of 2026, compared with net losses of $8.7 million during the same quarter in 2025. This increase was partially offset by a $2.4 million decrease in the net gains from the investments held in the Integrys rabbi trust. Gains from the investments held in the rabbi trust partially offset increases in benefit costs related to certain deferred compensation, which are primarily included in other operation and maintenance expense in our utility segments. See Note 14, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.

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Interest Expense

Interest expense at the corporate and other segment increased $3.4 million during the third quarter of 2026, compared with the same quarter in 2025, due to higher average short-term debt balances. Partially offsetting the increase was the impact of long-term debt maturities.

Income Tax Expense

Income tax expense at the corporate and other segment decreased $5.6 million during the third quarter of 2026, compared with the same quarter in 2025. This decrease was driven by an $8.8 million decrease in the interim tax expense recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate during the third quarter of 2026, compared with the same quarter in 2025. Partially offsetting this decrease in income tax expense was a lower pre-tax loss.

NINE MONTHS ENDED SEPTEMBER 30, 2026

Consolidated Earnings

The following table compares our consolidated results for the nine months ended September 30, 2026 with the nine months ended September 30, 2025, including favorable or better, "B", and unfavorable or worse, "W", variances:

						Nine Months Ended September 30
(in millions, except per share data)						2026						2025						B (W)
Wisconsin						$	978.0					$	823.6					$	154.4
Illinois						187.2						170.2						17.0
Other states						30.0						37.7						(7.7)
Electric transmission						132.4						109.8						22.6
Non-utility energy infrastructure						332.1						279.0						53.1
Corporate and other						(166.8)						(179.4)						12.6
Net income attributed to common shareholders						$	1,492.9					$	1,240.9					$	252.0
Diluted EPS						$	4.54					$	3.85					$	0.69

Earnings increased $252.0 million during the nine months ended September 30, 2026, compared with the same period in 2025. The significant factors impacting the $252.0 million increase in earnings were:

•A $154.4 million increase in net income attributed to common shareholders at the Wisconsin segment, driven by higher margins due to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2026, carrying costs earned during 2026 on the construction of certain Bespoke Resources assigned to our VLCs, and higher retail sales volumes due to the impact of our VLCs. Higher AFUDC-Equity and increases in certain income tax benefits also contributed to the higher earnings. These positive impacts were partially offset by higher operating expenses, primarily due to an increase in regulatory amortizations and other pass through expenses, higher depreciation and amortization expense, and an increase in transmission expense. These increases in operating expenses were partially offset by lower benefit expense.

•A $53.1 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by higher operating income at WECI, reflecting improved market conditions, lower operating costs, and lower losses from storm damage.

•A $22.6 million increase in net income attributed to common shareholders at the electric transmission segment, driven by continued capital investment by ATC.

•A $17.0 million increase in net income attributed to common shareholders at the Illinois segment, driven by lower operating expenses, primarily due to the positive impact from a gain on the sale of certain real estate at PGL during the nine months ended September 30, 2026 and a decrease in benefit expense. See Note 3, Disposition, for more information on the sale.

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Expected 2026 Annual Effective Tax Rate

We expect our 2026 annual effective tax rate to be between 8.0% and 9.0%. Our effective tax rate calculations are revised every quarter based on the best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.

Non-GAAP Financial Measures

The discussions below address the contribution of each of our utility segments to net income attributed to common shareholders. The discussions include financial information prepared in accordance with GAAP, as well as utility margin, which is not a measure of financial performance under GAAP. Utility margin (operating revenues less fuel and purchased power costs and cost of natural gas sold) is a non-GAAP financial measure because it excludes certain operation and maintenance expenses applicable to revenues, as well as depreciation and amortization and property and revenue taxes.

We believe that utility margin provides a useful basis for evaluating utility operations since the majority of prudently incurred fuel and purchased power costs, as well as prudently incurred natural gas costs, are passed through to customers in current rates. As a result, management uses utility margin internally when assessing the operating performance of our utility segments as these measures exclude the majority of revenue fluctuations caused by changes in these expenses. Similarly, the presentation of utility margin herein is intended to provide supplemental information for investors regarding our operating performance.

Our utility margin may not be comparable to similar measures presented by other companies. Furthermore, this measure is not intended to replace gross margin as determined in accordance with GAAP as an indicator of operating performance. Each of our three utility segment discussions below include a table that provides the calculation of both gross margin as determined in accordance with GAAP and utility margin, as well as a reconciliation between the two measures.

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Wisconsin Segment Contribution to Net Income Attributed to Common Shareholders

The Wisconsin segment's contribution to net income attributed to common shareholders was $978.0 million during the nine months ended September 30, 2026, representing a $154.4 million, or 18.7%, increase over the same period in 2025. The increase in earnings was driven by higher margins due to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2026, carrying costs earned during 2026 on the construction of certain Bespoke Resources assigned to our VLCs, and higher retail sales volumes due to the impact of our VLCs. Higher AFUDC-Equity and increases in certain income tax benefits also contributed to the higher earnings. These positive impacts were partially offset by higher operating expenses, primarily due to an increase in regulatory amortizations and other pass through expenses, higher depreciation and amortization expense, and an increase in transmission expense. These increases in operating expenses were partially offset by lower benefit expense.

						Nine Months Ended September 30
(in millions)						2026						2025						B (W)
Operating revenues						$	5,924.5					$	5,438.7					$	485.8
Operating expenses
Cost of sales (1)						2,080.3						1,867.2						(213.1)
Other operation and maintenance						1,389.4						1,274.8						(114.6)
Depreciation and amortization						802.6						749.5						(53.1)
Property and revenue taxes						148.8						135.0						(13.8)
Operating income						1,503.4						1,412.2						91.2
Other income, net						138.9						62.4						76.5
Interest expense						499.1						478.6						(20.5)
Income before income taxes						1,143.2						996.0						147.2
Income tax expense						164.3						171.5						7.2
Preferred stock dividends of subsidiary						0.9						0.9						—
Net income attributed to common shareholders						$	978.0					$	823.6					$	154.4

(1)    Cost of sales includes fuel and purchased power and cost of natural gas sold.

The following table shows a breakdown of other operation and maintenance:

						Nine Months Ended September 30
(in millions)						2026						2025						B (W)
Operation and maintenance not included in line items below						$	546.6					$	571.7					$	25.1
Transmission (1)						487.9						439.1						(48.8)
Regulatory amortizations and other pass through expenses (2)						249.7						170.5						(79.2)
We Power (3)						92.8						97.0						4.2
Earnings sharing mechanisms (4)						12.4						(3.5)						(15.9)
Total other operation and maintenance						$	1,389.4					$	1,274.8					$	(114.6)

(1)Represents transmission expense that our electric utilities are authorized to collect in rates. The PSCW has approved escrow accounting for ATC and MISO network transmission expenses for WE and WPS. As a result, 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. During the nine months ended September 30, 2026 and 2025, $543.2 million and $466.7 million, respectively, of costs were billed to our electric utilities by transmission providers.

(2)Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on net income.

(3)Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE. During the nine months ended September 30, 2026 and 2025, $93.2 million and $88.9 million, respectively, of costs were billed to or incurred by WE related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset or liability.

(4)    Represents operation and maintenance associated with the earnings mechanisms we have in place, both the current year sharing estimate and the amortization of prior year amounts.

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The following tables provide information on delivered sales volumes by customer class and weather statistics:

						Nine Months Ended September 30
Electric Sales Volumes (MWh - in thousands)						2026						2025						B (W)
Customer Class
Residential						8,849.2						8,700.3						148.9
Small commercial and industrial (1)						10,019.8						9,879.1						140.7
Large commercial and industrial (1)						9,901.1						9,095.6						805.5
Other						77.4						84.2						(6.8)
Total retail (1)						28,847.5						27,759.2						1,088.3
Wholesale						1,300.7						1,342.6						(41.9)
Resale						3,078.5						4,486.4						(1,407.9)
Total sales in MWh (1)						33,226.7						33,588.2						(361.5)

(1)Includes distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.

						Nine Months Ended September 30
Natural Gas Sales Volumes (Therms - in millions)						2026						2025						B (W)
Customer Class
Residential						720.3						761.6						(41.3)
Commercial and industrial						471.2						502.9						(31.7)
Total retail						1,191.5						1,264.5						(73.0)
Transportation						1,014.9						1,005.4						9.5
Total sales in therms						2,206.4						2,269.9						(63.5)

						Nine Months Ended September 30
Weather (Degree Days) (1)						2026						2025						B (W)
WE and WG
Heating (4,184 Normal)						4,028						4,364						(7.7)		%
Cooling (709 Normal)						740						750						(1.3)		%
WPS
Heating (4,679 Normal)						4,602						4,577						0.5		%
Cooling (543 Normal)						578						629						(8.1)		%
UMERC
Heating (5,373 Normal)						5,185						5,341						(2.9)		%
Cooling (346 Normal)						408						372						9.7		%

(1)Normal degree days are based on a 20-year moving average of monthly temperature readings from the National Oceanic and Atmospheric Administration weather stations within each company's respective service territories.

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Gross Margin GAAP and Utility Margin Non-GAAP

The following table summarizes our Wisconsin segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See Non-GAAP Financial Measures above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).

						Nine Months Ended September 30
(in millions)						2026						2025						B (W)
Electric revenues						$	4,611.8					$	4,242.6					$	369.2
Natural gas revenues						1,312.7						1,196.1						116.6
Operating revenues						5,924.5						5,438.7						485.8
Operating expenses
Fuel and purchased power						(1,392.6)						(1,284.5)						(108.1)
Cost of natural gas sold						(687.7)						(582.7)						(105.0)
Other operation and maintenance (1)						(958.6)						(920.2)						(38.4)
Depreciation and amortization						(802.6)						(749.5)						(53.1)
Property and revenue taxes						(148.8)						(135.0)						(13.8)
Gross margin (GAAP)						1,934.2						1,766.8						167.4
Other operation and maintenance (1)						958.6						920.2						38.4
Depreciation and amortization						802.6						749.5						53.1
Property and revenue taxes						148.8						135.0						13.8
Utility margin (non-GAAP)						$	3,844.2					$	3,571.5					$	272.7

(1)    Operating and maintenance expenses deemed to be directly attributable to our revenue-producing activities include plant operating and maintenance expenses related to our generating units; costs associated with the We Power generating units; and transmission, distribution and customer service expenses. These expenses are included in the above table to calculate gross margin as defined under GAAP.

Gross margin (GAAP) at the Wisconsin segment increased $167.4 million during the nine months ended September 30, 2026, compared with the same period in 2025, and utility margin (non-GAAP) increased $272.7 million during the nine months ended September 30, 2026, compared with the same period in 2025. Both measures were driven by:

•A $177.5 million increase in margins driven by the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2026.

•A current return of $53.4 million consisting of carrying costs earned during the construction of certain Bespoke Resources assigned to our VLCs during the nine months ended September 30, 2026.

•A $40.7 million net increase in margins related to higher electric retail sales volumes, including a $45.2 million increase from weather-normalized customer growth, driven by the impact of our VLCs. The margin impact from weather-normalized customer growth was partially offset by a $4.5 million decrease from unfavorable weather. As measured by heating degree days, the nine months ended September 30, 2026 were 7.7% warmer than the same period in 2025 in the combined WE and WG service area. As measured by cooling degree days, the nine months ended September 30, 2026 were 1.3% and 8.1% colder than the same period in 2025 in the combined WE and WG service area and the WPS service area, respectively.

Additionally, the smaller increase in gross margin (GAAP) as compared with the increase in utility margin (non-GAAP), was driven by the following items that are further described in Other Operating Expenses below:

•A $53.1 million increase in depreciation and amortization expense;

•A $48.8 million increase in transmission expense;

•A $13.8 million increase in property and revenues taxes;

•A $3.2 million increase in electric and natural gas distribution expense; and

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•A partially offsetting $12.7 million decrease in other operating and maintenance related to our power plants.

Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)

Other operating expenses at the Wisconsin segment increased $181.5 million during the nine months ended September 30, 2026, compared with the same period in 2025. The significant factors impacting the increase in other operating expenses were:

•A $79.2 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

•A $53.1 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.

•A $48.8 million increase in transmission expense as approved by the PSCW in our Wisconsin rate orders, effective January 1, 2026. See the notes under the other operation and maintenance table above for more information.

•A $15.9 million increase in expense related to the earnings sharing mechanisms in place at our Wisconsin utilities, driven by earnings sharing recorded at WE during the third quarter of 2026. The earnings sharing mechanisms are discussed in the notes under the other operation and maintenance table above

•A $13.8 million increase in property and revenue taxes, driven by higher gross receipt taxes.

•A $3.2 million increase in electric and natural gas distribution expenses, driven by higher costs to maintain the distribution systems during the nine months ended September 30, 2026, compared with the same period in 2025.

These increases in operating expenses were partially offset by:

•A $22.8 million decrease in benefit expense, driven by various employee compensation plans.

•A $12.7 million decrease in other operating and maintenance related to our power plants during the nine months ended September 30, 2026, compared with the same period in 2025, driven by a reduction in allowed expense for OCPP and Columbia under escrow accounting, as approved by the PSCW in our Wisconsin rate orders.

Other Income, Net

Other income, net at the Wisconsin segment increased $76.5 million during the nine months ended September 30, 2026, compared with the same period in 2025, driven by a $76.1 million positive impact from higher AFUDC-Equity due to continued capital investment.

Interest Expense

Interest expense at the Wisconsin segment increased $20.5 million during the nine months ended September 30, 2026, compared with the same period in 2025. The increase was primarily due to the impact of long-term debt issuances in 2025 and 2026. Also contributing to the increase was higher average short-term debt balances. These increases were partially offset by AFUDC-Debt that was $34.2 million higher year-over-year due to continued capital investment, and the impact of long-term debt maturities in 2025.

Income Tax Expense

Income tax expense at the Wisconsin segment decreased $7.2 million during the nine months ended September 30, 2026, compared with the same period in 2025. This decrease was driven by:

•A $17.5 million increase in income tax benefits associated with AFUDC-Equity, driven by continued capital investment;

•A $13.1 million favorable income tax impact associated with certain tax-related regulatory deferrals; and

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•A $13.0 million increase in PTCs and ITCs.

Partially offsetting these favorable income tax variances was higher pre-tax income.

Illinois Segment Contribution to Net Income Attributed to Common Shareholders

The Illinois segment's contribution to net income attributed to common shareholders was $187.2 million during the nine months ended September 30, 2026, representing a $17.0 million, or 10.0%, increase over the same period in 2025. The increase was driven by lower operating expenses, primarily due to the positive impact from a gain on the sale of certain real estate at PGL during the nine months ended September 30, 2026 and a decrease in benefit expense. See Note 3, Disposition, for more information on the sale.

Since the majority of PGL and NSG customers use natural gas for heating, net income attributed to common shareholders at the Illinois segment is sensitive to weather and is generally higher during the winter months.

						Nine Months Ended September 30
(in millions)						2026						2025						B (W)
Operating revenues						$	1,195.1					$	1,242.4					$	(47.3)
Operating expenses
Cost of natural gas sold						335.1						339.1						4.0
Other operation and maintenance						310.3						367.3						57.0
Depreciation and amortization						199.4						194.2						(5.2)
Property and revenue taxes						33.5						44.6						11.1
Operating income						316.8						297.2						19.6
Other income, net						6.7						6.5						0.2
Interest expense						63.3						67.1						3.8
Income before income taxes						260.2						236.6						23.6
Income tax expense						73.0						66.4						(6.6)
Net income attributed to common shareholders						$	187.2					$	170.2					$	17.0

The following table shows a breakdown of other operation and maintenance:

						Nine Months Ended September 30
(in millions)						2026						2025						B (W)
Operation and maintenance not included in the line items below						$	231.9					$	249.4					$	17.5
Riders (1)						77.9						115.8						37.9
Regulatory amortizations (1)						0.5						2.1						1.6
Total other operation and maintenance						$	310.3					$	367.3					$	57.0

(1)These riders and regulatory amortizations are substantially offset in margins and therefore do not have a significant impact on net income.

The following tables provide information on delivered sales volumes by customer class and weather statistics:

						Nine Months Ended September 30
Natural Gas Sales Volumes (Therms - in millions)						2026						2025						B (W)
Customer Class
Residential						552.1						577.5						(25.4)
Commercial and industrial						211.6						215.4						(3.8)
Total retail						763.7						792.9						(29.2)
Transportation						504.1						539.8						(35.7)
Total sales in therms						1,267.8						1,332.7						(64.9)

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						Nine Months Ended September 30
Weather (Degree Days) (1)						2026						2025						B (W)
Heating (3,798 Normal)						3,518						3,774						(6.8)		%

(1)Normal heating degree days are based on a 12-year moving average of monthly temperature readings from National Oceanic and Atmospheric Administration weather stations throughout our Illinois service territories.

Gross Margin GAAP and Utility Margin Non-GAAP

The following table summarizes our Illinois segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See Non-GAAP Financial Measures above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).

						Nine Months Ended September 30
(in millions)						2026						2025						B (W)
Operating revenues						$	1,195.1					$	1,242.4					$	(47.3)
Operating expenses
Cost of natural gas sold						(335.1)						(339.1)						4.0
Other operation and maintenance (1)						(172.9)						(179.9)						7.0
Depreciation and amortization						(199.4)						(194.2)						(5.2)
Property and revenue taxes						(33.5)						(44.6)						11.1
Gross margin (GAAP)						454.2						484.6						(30.4)
Other operation and maintenance (1)						172.9						179.9						(7.0)
Depreciation and amortization						199.4						194.2						5.2
Property and revenue taxes						33.5						44.6						(11.1)
Utility margin (non-GAAP)						$	860.0					$	903.3					$	(43.3)

(1)    Operating and maintenance expenses deemed to be directly attributable to our revenue-producing activities include distribution and customer service expenses. These expenses are included in the above table to calculate gross margin as defined under GAAP.

Gross margin (GAAP) at the Illinois segment decreased $30.4 million during the nine months ended September 30, 2026, compared with the same period in 2025, and utility margin (non-GAAP) decreased $43.3 million during the nine months ended September 30, 2026, compared with the same period in 2025. Both measures were driven by:

•A $37.9 million decrease in revenues associated with certain riders that are offset in other operation and maintenance and therefore do not have a significant impact on net income.

•A $10.9 million decrease in revenues associated with the invested capital tax adjustment rider, which is offset in property and revenue taxes and therefore does not have a significant impact on net income. The invested capital tax adjustment rider is a mechanism that allows us to recover or refund the difference between the cost of invested capital tax incurred and the amount collected through base rates.

These decreases in margins were partially offset by a $1.5 million increase in revenues associated with fixed customer charges during the nine months ended September 30, 2026, compared with the same period in 2025.

Additionally, the smaller decrease in gross margin (GAAP) as compared with the decrease in utility margin (non-GAAP), was driven by the following items that are further described in Other Operating Expenses below:

•An $11.1 million decrease in property and revenue taxes;

•A $3.2 million decrease in natural gas distribution and maintenance costs; and

•A partially offsetting $5.2 million increase in depreciation and amortization expense, primarily related to maintaining the natural gas infrastructure.

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Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)

Other operating expenses at the Illinois segment decreased $25.0 million, net of the $37.9 million impact of the riders referenced in the table above, during the nine months ended September 30, 2026, compared with the same period in 2025. The significant factors impacting the decrease in other operating expenses were:

•An $11.9 million gain related to the sale of certain real estate owned by PGL during the nine months ended September 30, 2026. See Note 3, Disposition, for more information.

•An $11.1 million decrease in property and revenue taxes, driven by the invested capital tax.

•A $6.7 million decrease in benefit expense.

•A $3.2 million decrease in natural gas distribution and maintenance costs, primarily related to maintaining the natural gas infrastructure.

These decreases in operating expenses were partially offset by:

•A $5.2 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.

•A $2.7 million pre-tax gain on the renegotiation of a lease contract during the nine months ended September 30, 2025.

Interest Expense

Interest expense at the Illinois segment decreased $3.8 million during the nine months ended September 30, 2026, compared with the same period in 2025, due the impact of PGL's Series VV and Series ZZ mortgage bonds redemptions in March 2026, and lower average short-term debt interest rates.

Income Tax Expense

Income tax expense at the Illinois segment increased $6.6 million during the nine months ended September 30, 2026, compared with the same period in 2025, driven by an increase in pre-tax income.

Other States Segment Contribution to Net Income Attributed to Common Shareholders

The other states segment's contribution to net income attributed to common shareholders was $30.0 million during the nine months ended September 30, 2026, representing a $7.7 million, or 20.4%, decrease over the same period in 2025. The lower earnings were driven by a decrease in margins related to lower retail sales volumes and higher operating expenses.

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Since the majority of MERC and MGU customers use natural gas for heating, net income attributed to common shareholders at the other states segment is sensitive to weather and is generally higher during the winter months.

						Nine Months Ended September 30
(in millions)						2026						2025						B (W)
Operating revenues						$	402.5					$	362.4					$	40.1
Operating expenses
Cost of natural gas sold						209.2						165.1						(44.1)
Other operation and maintenance						78.3						76.2						(2.1)
Depreciation and amortization						39.7						37.0						(2.7)
Property and revenue taxes						20.5						19.9						(0.6)
Operating income						54.8						64.2						(9.4)
Other income, net						0.6						0.3						0.3
Interest expense						15.0						14.0						(1.0)
Income before income taxes						40.4						50.5						(10.1)
Income tax expense						10.4						12.8						2.4
Net income attributed to common shareholders						$	30.0					$	37.7					$	(7.7)

The following table shows a breakdown of other operation and maintenance:

						Nine Months Ended September 30
(in millions)						2026						2025						B (W)
Operation and maintenance not included in line item below						$	60.0					$	60.7					$	0.7
Regulatory amortizations and other pass through expenses (1)						18.3						15.5						(2.8)
Total other operation and maintenance						$	78.3					$	76.2					$	(2.1)

(1)Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on net income.

The following tables provide information on delivered sales volumes by customer class and weather statistics:

						Nine Months Ended September 30
Natural Gas Sales Volumes (Therms - in millions)						2026						2025						B (W)
Customer Class
Residential						211.3						218.0						(6.7)
Commercial and industrial						137.0						138.6						(1.6)
Total retail						348.3						356.6						(8.3)
Transportation						594.2						550.7						43.5
Total sales in therms						942.5						907.3						35.2

						Nine Months Ended September 30
Weather (Degree Days) (1)						2026						2025						B (W)
MERC
Heating (5,043 Normal)						4,716						4,938						(4.5)		%
MGU
Heating (3,976 Normal)						3,805						3,915						(2.8)		%

(1)Normal heating degree days for MERC and MGU are based on a 20-year moving average and 15-year moving average, respectively, of monthly temperature readings from National Oceanic and Atmospheric Administration weather stations throughout their respective service territories.

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Gross Margin GAAP and Utility Margin Non-GAAP

The following table summarizes our other states segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See Non-GAAP Financial Measures above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).

						Nine Months Ended September 30
(in millions)						2026						2025						B (W)
Operating revenues						$	402.5					$	362.4					$	40.1
Operating expenses
Cost of natural gas sold						(209.2)						(165.1)						(44.1)
Other operation and maintenance (1)						(45.8)						(44.4)						(1.4)
Depreciation and amortization						(39.7)						(37.0)						(2.7)
Property and revenue taxes						(20.5)						(19.9)						(0.6)
Gross margin (GAAP)						87.3						96.0						(8.7)
Other operation and maintenance (1)						45.8						44.4						1.4
Depreciation and amortization						39.7						37.0						2.7
Property and revenue taxes						20.5						19.9						0.6
Utility margin (non-GAAP)						$	193.3					$	197.3					$	(4.0)

(1)    Operating and maintenance expenses deemed to be directly attributable to our revenue-producing activities include distribution and customer service expenses. These expenses are included in the above table to calculate gross margin as defined under GAAP.

Gross margin (GAAP) decreased $8.7 million during the nine months ended September 30, 2026, compared with the same period in 2025, and utility margin (non-GAAP) decreased $4.0 million during the nine months ended September 30, 2026, compared with the same period in 2025. Both measures were driven by:

•A $5.2 million decrease in margins related to lower retail sales volumes, including the unfavorable impact of weather, during the nine months ended September 30, 2026, compared with the same period in 2025.

•A $0.9 million decrease related to MERC CIP revenue, which was offset in operation and maintenance expense. Rebates and programs are available to residential and commercial customers of MERC through the CIP, which is funded by ratepayers using the Conservation Cost Recovery Charge and the Conservation Cost Recovery Adjustment funds that are collected on their monthly billing statements.

Partially offsetting these decreases was a $2.4 million increase related to MGU's energy optimization program.

Additionally, the larger decrease in gross margin (GAAP) as compared to the decrease in utility margin (non-GAAP), was driven by the following items that are further described in Other Operating Expenses below:

•A $2.7 million increase in depreciation and amortization expense; and

•A $1.4 million increase in natural gas operations and customer service expense.

Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)

Other operating expenses at the other states segment increased $5.4 million during the nine months ended September 30, 2026, compared with the same period in 2025. The significant factors impacting the increase in operating expenses were:

•A $2.7 million increase in depreciation and amortization expense related to continued capital investment.

•A $2.4 million increase in revenues related to MGU's energy optimization program.

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•A $1.4 million increase in natural gas operations and customer service expense, driven by increased training costs and additional service maintenance expense.

•A $1.4 million increase in the provision for credit losses, primarily driven by the aging of customer receivables.

These increases in operating expenses were partially offset by:

•A $1.6 million positive impact from a settlement payment MGU received during the second quarter of 2026 related to a 2025 natural gas outage in its service territory.

•A $0.9 million decrease in operation and maintenance expense related to MERC's CIP program, which has an offsetting decrease in margins.

Interest Expense

Interest expense at the other states segment increased $1.0 million during the nine months ended September 30, 2026, compared with the same period in 2025, driven by the impact of MERC and MGU issuing long-term debt in April 2025. This increase was partially offset by MERC and MGU long-term debt maturities in May 2025 and lower average short-term debt interest rates.

Income Tax Expense

Income tax expense at the other states segment decreased $2.4 million during the nine months ended September 30, 2026, compared with the same period in 2025, driven by lower pre-tax income.

Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders

						Nine Months Ended September 30
(in millions)						2026						2025						B (W)
Equity in earnings of transmission affiliates						$	187.9					$	160.3					$	27.6
Interest expense						11.8						14.5						2.7
Income before income taxes						176.1						145.8						30.3
Income tax expense						43.7						36.0						(7.7)
Net income attributed to common shareholders						$	132.4					$	109.8					$	22.6

Equity in Earnings of Transmission Affiliates

Equity in earnings of transmission affiliates increased $27.6 million during the nine months ended September 30, 2026, compared with the same period in 2025. This increase in earnings was primarily due to continued capital investment by ATC, partially offset by a $3.6 million gain recognized in March 2025 related to the sale of an investment at ATC Holdco.

Interest Expense

Interest expense at the electric transmission segment decreased $2.7 million during the nine months ended September 30, 2026, compared with the same period in 2025, due to the impact of a long-term debt maturity in December 2025.

Income Tax Expense

Income tax expense at the electric transmission segment increased $7.7 million during the nine months ended September 30, 2026, compared with the same period in 2025, primarily due to an increase in pre-tax income.

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Non-Utility Energy Infrastructure Segment Contribution to Net Income Attributed to Common Shareholders

						Nine Months Ended September 30
(in millions)						2026						2025						B (W)
Operating income						$	344.1					$	267.6					$	76.5
Other income, net						1.9						2.2						(0.3)
Interest expense						90.6						92.6						2.0
Income before income taxes						255.4						177.2						78.2
Income tax benefit						(80.3)						(98.7)						(18.4)
Net (income) loss attributed to noncontrolling interests						(3.6)						3.1						(6.7)
Net income attributed to common shareholders						$	332.1					$	279.0					$	53.1

Operating Income

Operating income at the non-utility energy infrastructure segment increased $76.5 million during the nine months ended September 30, 2026, compared with the same period in 2025, driven by the following items at WECI:

•An $18.2 million increase in revenue related to lower congestion related costs.

•A $13.9 million increase in capacity revenues due to strong capacity pricing.

•A net $13.5 million positive impact related to lower impairment losses recorded at our Thunderhead wind and Samson I and Delilah I solar facilities during the first nine months of 2026 compared to the same period in 2025, related to damage incurred associated with various storms.

•An $8.4 million reduction in operation and maintenance expenses, primarily due to fixed-cost full service agreements in place in 2026 and lower benefit costs.

•A $5.5 million increase in insurance proceeds related to storms that occurred in 2023 and 2024 at our Samson I solar facility.

•A $5.2 million positive impact related to the receipt of performance payments.

•A $2.5 million increase in PPA revenues due to higher generation at certain sites and lower electricity curtailments.

•A $1.3 million increase due to higher amounts recognized for REC sales in 2026 at Blooming Grove, driven by higher contracted REC prices.

In addition to the above items at WECI, there was a $7.3 million positive impact from We Power due to continued capital investment.

Interest Expense

Interest expense at the non-utility energy infrastructure segment decreased $2.0 million during the nine months ended September 30, 2026, compared with the same period in 2025, driven by a lower principal balance, as a result of the semi-annual principal payments on long-term debt at WECI's subsidiaries. Partially offsetting the decrease was a $3.4 million increase in interest expense due to WECI's issuance of $160.0 million and $100.0 million long-term intercompany notes to WEC Energy Group in February 2025 and April 2026, respectively. This intercompany interest expense is offset by higher interest income at our corporate and other segment and is eliminated in consolidation.

Income Tax Benefit

The income tax benefit at the non-utility energy infrastructure segment decreased $18.4 million during the nine months ended September 30, 2026, compared with the same period in 2025, primarily due to higher pre-tax income.

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Corporate and Other Segment Contribution to Net Income Attributed to Common Shareholders

						Nine Months Ended September 30
(in millions)						2026						2025						B (W)
Operating loss						$	(6.4)					$	(6.8)					$	0.4
Other income, net						36.9						20.3						16.6
Interest expense						281.3						266.3						(15.0)
Loss before income taxes						(250.8)						(252.8)						2.0
Income tax benefit						(84.0)						(73.4)						10.6
Net loss attributed to common shareholders						$	(166.8)					$	(179.4)					$	12.6

Other Income, Net

Other income, net at the corporate and other segment increased $16.6 million during the nine months ended September 30, 2026, compared with the same period in 2025. The significant factors impacting the increase in other income, net were:

•A $13.7 million increase due to $0.9 million of net earnings from our equity method investments in technology and energy-focused investment funds during the nine months ended September 30, 2026, compared with net losses of $12.8 million during the same period in 2025.

•A $3.4 million increase in intercompany interest income from WECI, due to WECI's issuance of $160.0 million and $100.0 million long-term intercompany notes to WEC Energy Group in February 2025 and April 2026, respectively. This intercompany interest income is offset by higher intercompany interest expense at our non-utility energy infrastructure segment and is eliminated in consolidation.

Interest Expense

Interest expense at the corporate and other segment increased $15.0 million during the nine months ended September 30, 2026, compared with the same period in 2025, driven by higher average short-term debt balances. Partially offsetting the increase was the impact of long-term debt maturities.

Income Tax Benefit

The income tax benefit at the corporate and other segment increased $10.6 million during the nine months ended September 30, 2026, compared with the same period in 2025. This increase was driven by a $10.4 million increase in the interim tax benefit recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate during the nine months ended September 30, 2026, compared with the same period in 2025.

LIQUIDITY AND CAPITAL RESOURCES

Overview

We expect to maintain adequate liquidity to meet our cash requirements for the operation of our businesses and implementation of our corporate strategy through the internal generation of cash from operations and access to the capital markets.

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Cash Flows

The following table summarizes our cash flows during the nine months ended September 30:

(in millions)						2026						2025						Change in 2026 Over 2025
Cash provided by (used in):
Operating activities						$	3,413.1					$	2,954.8					$	458.3
Investing activities						(3,599.8)						(3,570.5)						(29.3)
Financing activities						246.3						691.2						(444.9)

Operating Activities

Net cash provided by operating activities increased $458.3 million during the nine months ended September 30, 2026, compared with the same period in 2025, driven by:

•A $445.5 million increase in cash from higher overall collections from customers during the nine months ended September 30, 2026, compared with the same period in 2025. This increase was driven by the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2026, and the impact of the VLCs.

•A $106.8 million increase in cash from lower payments for operating and maintenance expenses. During the nine months ended September 30, 2026, our payments were lower due to the timing of payments for accounts payable, partially offset by higher transmission costs.

These increases in net cash provided by operating activities were partially offset by:

•A $38.1 million increase in cash paid for property and revenue taxes driven by higher gross receipts taxes in Wisconsin, revenue taxes in Illinois, and property taxes for WECI during the nine months ended September 30, 2026, compared with the same period in 2025.

•A $25.8 million decrease in cash from higher payments for interest driven by higher average short-term debt balances during the nine months ended September 30, 2026, compared with the same period in 2025, as well as long-term debt issuances in 2025 and 2026.

•A $20.8 million decrease in cash received from income taxes driven by estimated tax payments that were made in 2026. See Note 13, Income Taxes, for more information.

•A $16.8 million decrease in cash driven by higher amounts of collateral paid to counterparties during the nine months ended September 30, 2026, compared with the same period in 2025.

Investing Activities

Net cash used in investing activities increased $29.3 million during the nine months ended September 30, 2026, compared with the same period in 2025, driven by:

•A $198.7 million increase in cash paid for capital expenditures, including AFUDC-Debt during the nine months ended September 30, 2026, compared with the same period in 2025, which is discussed in more detail below.

•A $170.8 million refundable aggregate payment for exclusive rights to purchase certain generation projects during the nine months ended September 30, 2026. See Note 18, Goodwill and Intangibles, for more information.

•A $30.6 million increase in capital contributions paid to transmission affiliates during the nine months ended September 30, 2026, compared with the same period in 2025. See Note 19, Investment in Transmission Affiliates, for more information.

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•A $29.3 million decrease in cash received from ATC during the nine months ended September 30, 2026, compared with the same period in 2025, for the reimbursement of transmission infrastructure upgrades. See Note 19, Investment in Transmission Affiliates, for more information.

•A $14.0 million decrease in cash received from the sale of investments held in the rabbi trust during the nine months ended September 30, 2026, compared with the same period in 2025.

These increases in net cash used in investing activities were partially offset by:

•The acquisition of a 90% ownership interest in Hardin III in February 2025 for $406.1 million, net of cash acquired of $0.2 million. See Note 2, Acquisitions, for more information.

•An $18.2 million increase in proceeds received from the sale of assets during the nine months ended September 30, 2026, compared with the same period in 2025. See Note 3, Disposition, for more information.

Capital Expenditures

Capital expenditures, including AFUDC-Debt, by segment for the nine months ended September 30 were as follows:

Reportable Segment (in millions)						2026						2025						Change in 2026 Over 2025
Wisconsin						$	2,883.2					$	2,716.8					$	166.4
Illinois						271.9						219.3						52.6
Other states						82.1						84.9						(2.8)
Non-utility energy infrastructure						62.8						84.3						(21.5)
Corporate and other						18.7						14.7						4.0
Total capital expenditures						$	3,318.7					$	3,120.0					$	198.7

The increase in cash paid for capital expenditures at the Wisconsin segment during the nine months ended September 30, 2026, compared with the same period in 2025, was driven by higher payments for the CTs and LNG at WE, electric distribution at WE and WPS, and natural gas distribution at WE. These increases in capital expenditures at the Wisconsin segment were partially offset by lower payments for renewable energy projects at WE, WPS, and at UMERC for Renegade, which achieved commercial operation in March 2026.

The increase in cash paid for capital expenditures at the Illinois segment during the nine months ended September 30, 2026, compared with the same period in 2025, was driven by higher payments related to PGL's upgrade of its natural gas delivery system.

The decrease in cash paid for capital expenditures at the non-utility energy infrastructure segment during the nine months ended September 30, 2026, compared with the same period in 2025, was driven by lower payments for new generator units at Port Washington Generating Station.

See Capital Resources and Requirements – Capital Requirements – Significant Capital Projects for more information.

Financing Activities

Net cash provided by financing activities decreased $444.9 million during the nine months ended September 30, 2026, compared with the same period in 2025, driven by:

•A $364.1 million decrease in cash due to lower issuances of common stock during the nine months ended September 30, 2026, compared with the same period in 2025. See Note 8, Common Equity, for more information.

•A $272.6 million decrease in cash due to higher retirements of long-term debt during the nine months ended September 30, 2026, compared with the same period in 2025.

•A $163.6 million decrease in cash due to $21.9 million of net repayments of commercial paper during the nine months ended September 30, 2026, compared with $141.7 million of net borrowings of commercial paper during the same period in 2025.

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•A $73.4 million decrease in cash due to higher dividends paid on our common stock during the nine months ended September 30, 2026, compared with the same period in 2025. In January 2026, our Board of Directors increased our quarterly dividend by $0.06 per share (6.7%) effective with the March 2026 dividend payment.

•A $27.7 million decrease in cash related to a lower number of stock options exercised during the nine months ended September 30, 2026, compared with the same period in 2025.

These decreases in net cash provided by financing activities were partially offset by a $451.0 million increase in cash due to the issuance of more long-term debt during the nine months ended September 30, 2026, compared with the same period in 2025.

Other Significant Financing Activities

For more information on our other significant financing activities, see Note 8, Common Equity, Note 9, Short-Term Debt and Lines of Credit, and Note 10, Long-Term Debt.

Cash Requirements

We require funds to support and grow our businesses. Our significant cash requirements primarily consist of capital and investment expenditures, payments to retire and pay interest on long-term debt, the payment of common stock dividends to our shareholders, and the funding of our ongoing operations. See the discussion below and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Cash Requirements in our 2025 Annual Report on Form 10-K for additional information regarding our significant cash requirements.

Significant Capital Projects

We have several capital projects and acquisitions that will require significant capital expenditures over the next three years and beyond. All projected capital requirements are subject to periodic review and may vary significantly from estimates, depending on a number of factors. These factors include environmental and regulatory requirements, changes in tax laws and regulations, acquisition and development opportunities, market volatility, economic trends, supply chain disruptions, inflation, and interest rates. Our estimated capital expenditures and acquisitions for the next three years are reflected below. These amounts include anticipated expenditures for environmental compliance and certain remediation issues. For a discussion of certain environmental matters affecting us, see Note 22, Commitments and Contingencies.

(in millions)						2026 (1)						2027						2028
Wisconsin - Non-VLC/Bespoke Resources						$	2,521.7					$	3,001.2					$	2,929.0
Wisconsin - VLC/Bespoke Resources						2,057.0						4,300.0						5,025.0
Illinois						477.9						807.6						813.0
Other states						117.3						123.0						129.9
Non-utility energy infrastructure						90.1						152.6						162.8
Corporate and other						22.0						23.6						18.3
Total						$	5,286.0					$	8,408.0					$	9,078.0

(1)This includes actual capital expenditures incurred through September 30, 2026, as well as estimated capital expenditures for the remainder of the year.

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We are committed to investing in solar, wind, battery storage, and natural gas-fired generation. In addition, our utilities continue to upgrade their electric and natural gas distribution systems to enhance reliability. Below are the anticipated investment amounts for the next three years for generation, LNG, and distribution projects that are proposed or currently underway.

(in millions)						2026 (1)						2027						2028
Generation:
Solar						$	938.4					$	2,176.6					$	1,732.8
Wind						105.1						169.6						295.6
Battery						462.9						604.1						922.2
Thermal						935.6						2,008.6						2,864.6
Other						423.0						661.1						717.8
LNG						189.0						73.0						16.0
Distribution:
Electric distribution						1,032.0						1,023.0						976.0
Gas distribution						1,200.0						1,692.0						1,553.0
Total						$	5,286.0					$	8,408.0					$	9,078.0

(1)This includes actual capital expenditures incurred through September 30, 2026, as well as estimated capital expenditures for the remainder of the year.

The DOC set duties on solar panels and cells imported from four southeast Asian countries as well as from Laos, Indonesia, and India, and began an investigation into cells from Ethiopia. See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – United States Department of Commerce Complaints and Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Uyghur Forced Labor Prevention Act for information on the duties set by the DOC and its current investigation, as well as CBP actions, respectively. The forecasted costs identified above already reflect some of these impacts.

See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Renewable Energy Legislation for potential impacts to our capital projects as a result of the OBBBA.

In accordance with its November 2023 PGL rate order, the ICC initiated a proceeding in January 2024 to determine the optimal method and a prudent investment level for replacing aging natural gas infrastructure. In February 2025, the ICC issued an order setting expectations for PGL's prospective operations. The ICC directed PGL to focus on retiring all cast and ductile iron pipes that have a diameter under 36 inches by January 1, 2035. PGL is working to retire this cast and ductile iron pipe through its PRP. Annual investment for pipe replacement is expected to ramp up to approach $500 million in 2028. For more information on regulatory proceedings related to this matter, see Note 24, Regulatory Environment, and Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Illinois Proceeding – Replacement of Aging Natural Gas Infrastructure.

We expect to provide total capital contributions to ATC (not included in the above table) of approximately $820 million from 2026 through 2028. We do not expect to make any contributions to ATC Holdco during that period. Our portion of the investment in MISO Tranche 1 and Tranche 2.1 is estimated to be approximately $500 million and $700 million, respectively, between 2027 and 2031, a portion of which will be funded by ATC's cash from operations. Tranche 1 is part of MISO's Long Range Transmission Planning initiative to upgrade the grid so that it can reliably accommodate for the shift in generation to lower-carbon resources. Tranche 2.1 is the second phase of long range transmission planning and builds on the foundation of Tranche 1.

Long-Term Debt

See Note 10, Long-Term Debt, for information regarding the changes in our outstanding long-term debt during the nine months ended September 30, 2026.

Common Stock Dividends

Our current quarterly dividend rate is $0.9525 per share, which equates to an annual dividend of $3.81 per share. For information related to our most recent common stock dividend declared, see Note 8, Common Equity.

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Other Significant Cash Requirements

See Note 22, Commitments and Contingencies, for information regarding our minimum future commitments related to purchase obligations for the procurement of fuel, power, and natural gas supply, as well as the related storage and transportation. There were no material changes to our other significant commitments outside the ordinary course of business during the nine months ended September 30, 2026.

Off-Balance Sheet Arrangements

We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit that support construction projects, commodity contracts, and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see Note 9, Short-Term Debt and Lines of Credit, Note 16, Guarantees, and Note 21, Variable Interest Entities.

Sources of Cash

Liquidity

We anticipate meeting our short-term and long-term cash requirements to operate our businesses and implement our corporate strategy through internal generation of cash from operations and access to the capital markets, and common equity. Accessing the capital markets allows us to obtain external short-term borrowings, including commercial paper and term loans, and issue intermediate or long-term debt securities, as well as other types of securities. We also issue common equity through a combination of our employee benefit plans and stock purchase and dividend reinvestment plan, as well as through an at-the-market program. Cash generated from operations is primarily driven by sales of electricity and natural gas to our utility customers, reduced by costs of operations. Our access to the capital markets is critical to our overall strategic plan and allows us to supplement cash flows from operations with external borrowings to manage seasonal variations, working capital needs, commodity price fluctuations, unplanned expenses, and unanticipated events. Subject to market conditions and other factors, we may repurchase our debt securities through open market purchases, privately negotiated transactions and/or other types of transactions.

WEC Energy Group, WE, WPS, WG, and PGL maintain bank back-up credit facilities, which provide liquidity support for each company's obligations with respect to commercial paper and for general corporate purposes. We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations.

The amount, type, and timing of any financings for the remainder of 2026, as well as in subsequent years, will be contingent on investment opportunities and our cash requirements and will depend upon prevailing market conditions, regulatory approvals for certain subsidiaries, and other factors. Our regulated utilities plan to maintain capital structures consistent with those approved by their respective regulators. For more information on our utilities' approved capital structures, see Item 1. Business – E. Regulation in our 2025 Annual Report on Form 10-K.

The issuance of securities by our utility companies is subject to the approval of the applicable state commissions or FERC. Additionally, with respect to the public offering of securities, we, WE, and WPS file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as well as the securities registered under the 1933 Act, are closely monitored and appropriate filings are made to ensure flexibility in the capital markets.

At September 30, 2026, our current liabilities exceeded our current assets by $2,438.4 million. We do not expect this to have an impact on our liquidity, as we currently believe that our available capacity under our existing revolving credit facilities, cash generated from ongoing operations, and access to the capital markets are adequate to meet our short-term and long-term cash requirements.

See Note 8, Common Equity, Note 9, Short-Term Debt and Lines of Credit, and Note 10, Long-Term Debt, for more information about our common stock activity, credit facilities, commercial paper, and debt securities.

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Investments in Outside Trusts

We maintain investments in outside trusts to fund the obligation to provide pension and certain OPEB benefits to current and future retirees. These trusts have investments consisting of fixed income and equity securities that are subject to the volatility of the stock market and interest rates. For more information, see Investments in Outside Trusts in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Sources of Cash in our 2025 Annual Report on Form 10-K.

Capitalization Structure

The following table shows our capitalization structure as of September 30, 2026, as well as an adjusted capitalization structure that we believe is consistent with how a majority of the rating agencies currently view our Junior Notes:

(in millions)						Actual						Adjusted
Common shareholders' equity						$	14,575.4					$	15,250.4
Preferred stock of subsidiary						30.4						30.4
Long-term debt (including current portion)						20,851.7						20,176.7
Short-term debt						1,904.3						1,904.3
Total capitalization						$	37,361.8					$	37,361.8
Total debt						$	22,756.0					$	22,081.0
Ratio of debt to total capitalization						60.9		%				59.1		%

Included in long-term debt on our balance sheet as of September 30, 2026, was $600.0 million principal amount of WEC Energy Group's 2025 Junior Notes due 2056 and $750.0 million principal amount of WEC Energy Group's 2024 Junior Notes (2024A Junior Notes and 2024B Junior Notes, collectively) due 2055. The adjusted presentation attributes $675.0 million of the Junior Notes to common shareholders' equity and $675.0 million to long-term debt.

The adjusted presentation of our consolidated capitalization structure is included as a complement to our capitalization structure presented in accordance with GAAP. Management evaluates and manages our capitalization structure, including our total debt to total capitalization ratio, using the GAAP calculation as adjusted to reflect the treatment of the 2025 Junior Notes and 2024 Junior Notes by the majority of rating agencies. Therefore, we believe the non-GAAP adjusted presentation reflecting this treatment is useful and relevant to investors in understanding how management and the rating agencies evaluate our capitalization structure.

Debt Covenants

Certain of our short-term and long-term debt agreements contain financial covenants that we must satisfy, including debt to capitalization ratios and debt service coverage ratios. At September 30, 2026, we were in compliance with all such covenants related to outstanding short-term and long-term debt. We expect to be in compliance with all such debt covenants for the foreseeable future. See Note 11, Common Equity, Note 13, Short-Term Debt and Lines of Credit, and Note 14, Long-Term Debt, in our 2025 Annual Report on Form 10-K, for more information regarding our debt covenants.

Credit Rating Risk

Cash collateral postings and prepayments made with external parties, including postings related to exchange-traded contracts, and cash collateral posted by external parties were immaterial as of September 30, 2026. From time to time, we may enter into commodity contracts that could require collateral or a termination payment in the event of a credit rating change to below BBB- at S&P Global Ratings, a division of S&P Global Inc., and/or Baa3 at Moody’s Investors Service, Inc. If WE had a sub-investment grade credit rating at September 30, 2026, it could have been required to post $109 million of additional collateral or other assurances pursuant to the terms of a PPA. We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.

In addition, access to capital markets at a reasonable cost is determined in large part by credit quality. Any credit ratings downgrade could impact our ability to access capital markets.

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Subject to other factors affecting the credit markets as a whole, we believe our current ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, these security ratings reflect the views of the rating agency only. An explanation of the significance of these ratings may be obtained from the rating agency. Such ratings are not a recommendation to buy, sell, or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency.

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity, and capital resources. This discussion should be read together with the information in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources in our 2025 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, competitive markets, environmental and regulatory matters, critical accounting policies and estimates, and other matters.

Regulatory, Legislative, and Legal Matters

Regulatory Recovery

Our utilities account for their regulated operations in accordance with accounting guidance under the Regulated Operations Topic of the FASB ASC. Regulated entities are allowed to defer certain costs that would otherwise be charged to expense if the regulated entity believes the recovery of those costs is probable. We record regulatory assets pursuant to generic and/or specific orders issued by our regulators. Recovery of the deferred costs in future rates is subject to the review and approval by those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of the deferred costs, including those referenced below, is not approved by our regulators, the costs would be charged to income in the current period. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities. See Note 6, Regulatory Assets and Liabilities, for more information on our regulatory assets and liabilities. See Note 24, Regulatory Environment, in this report, and Note 26, Regulatory Environment, in our 2025 Annual Report on Form 10-K for more information regarding recent and pending rate proceedings, orders, and investigations involving our utilities.

Illinois Riders

Uncollectible Expense Adjustment Rider

The rates of PGL and NSG include a UEA rider for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. The UEA rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency by the ICC.

In May 2026, the ICC issued a final written order approving a settlement agreement PGL and NSG entered into with the Illinois Attorney General and ICC staff that resolved all open proceedings related to the 2019 through 2023 annual reconciliations of the UEA rider. Under the terms of the settlement, PGL and NSG will refund $49.0 million and $1.0 million, respectively, to customers as bill credits over a period of three years between 2026 and 2028. Half of the refunds will be credited to customers in 2026, and 25% will be refunded in each of 2027 and 2028. PGL and NSG will begin refunding amounts in November 2026. As a result of this agreement, we recorded a $50.0 million reduction to revenues during the fourth quarter of 2025.

Qualifying Infrastructure Plant Rider

In January 2014, the ICC approved PGL's use of the QIP rider as a recovery mechanism for costs incurred related to investments in QIP. This rider, which was in effect until December 1, 2023, was subject to an annual reconciliation whereby costs were reviewed for accuracy and prudency.

In August 2024, the ICC issued a final order on PGL's 2016 annual reconciliation, which included a disallowance of $14.8 million of certain capital costs. PGL subsequently filed a petition with the Illinois Appellate Court for review of the ICC's August 2024 order; however, in connection with the settlement agreement discussed below, in June 2026, PGL, the ICC, and the Illinois Attorney General filed a joint motion to dismiss the appeal with prejudice, which was granted by the court.

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In May 2026, the ICC issued a final written order approving a settlement agreement PGL entered into with the Illinois Attorney General, ICC staff, and the Illinois Citizens Utility Board that resolved all remaining open annual reconciliation proceedings from 2017 through 2023 related to the QIP rider. Under the terms of the settlement, PGL agreed to permanently remove $130.0 million of qualified infrastructure investment costs from rate base starting in 2027 and to refund $75.0 million to customers as bill credits over a period of three years between 2026 and 2028. As a result of this agreement, we recorded a $155.0 million charge to income during the fourth quarter of 2025. The charge was recorded as a $130.0 million impairment to PGL's net property, plant, and equipment and a $25.0 million reduction to revenues. The total of the rate base reduction and the obligation to refund amounts to customers through bill credits recorded on our balance sheet at September 30, 2026 was $205.0 million. This includes the $155.0 million charge to income recorded during the fourth quarter of 2025 and a $50.0 million charge to income recorded in years prior to 2025. PGL will begin refunding amounts to customers in November 2026, with $25.0 million being refunded in each of the three years starting in 2026 through 2028.

Illinois Proceeding - Replacement of Aging Natural Gas Infrastructure

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

See Note 24, Regulatory Environment, for more information regarding the 2026 rate case filing and November 2023 ICC rate order.

Very Large Customer and Bespoke Resources Collateral Requirements

We have incurred significant costs to construct generation, transmission and distribution assets that will be used to provide energy and capacity to Oracle America Cloud Services LLC ("OACS"), which will be taking service under the approved VLC and Bespoke Resources tariffs. Following a credit rating downgrade of OACS’s parent, our contracts required additional collateral to secure our credit exposure. OACS and its parent have provided the collateral required in conjunction with the credit rating downgrade. The amount of collateral required will increase as additional project costs are incurred, and we fully expect OACS and its parent to provide the additional required amounts. See Note 24, Regulatory Environment, for more information on the VLC and Bespoke Resources tariffs.

Uyghur Forced Labor Prevention Act

In June 2022, the CBP implemented the UFLPA, which establishes a rebuttable presumption that certain silica-based products wholly or partially manufactured in the Xinjiang Uyghur Autonomous Region of China, such as polysilicon included in the manufacturing of solar panels, are prohibited from entering the United States. While our suppliers have been able to provide the CBP sufficient documentation to meet the UFLPA compliance requirements, and we expect the same will be true for subsequent projects, we cannot currently predict what, if any, long-term impact the UFLPA will have on the overall supply of solar panels into the United States and whether we will experience any further impacts to the timing and cost of solar projects included in our long-term capital plan.

In 2025, and again in July 2026, the Department of Homeland Security expanded the UFLPA Entity List to include additional Chinese businesses across various industries, including several solar supply chain providers. We continue to work with our contractors and developers to avoid doing business with these companies and remain in compliance with the UFLPA.

United States Department of Commerce Complaints

Starting in June 2024, the DOC began applying duties to certain imports of solar cells from Malaysia, Vietnam, Thailand and Cambodia, with the potential for enhanced duties in certain circumstances, based on final findings by both the DOC and the USITC in their AD/CVD investigations that Chinese manufacturers were shifting products to those four Southeast Asian countries to avoid tariffs on products imported from China.

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In April 2025, based upon an investigation in response to a new petition, the DOC reached affirmative findings that some Chinese companies had moved their solar operations to avoid penalties imposed in the first investigation, increasing tariff rates, in some cases significantly. These increased rates became effective and enforceable in May 2025 upon the USITC’s final affirmative determination.

In September 2026 the DOC set AD/CVD duties on imports of solar cells and panels from India, Indonesia and Laos based on findings that producers in those countries are benefiting from illegal subsidies and selling solar products below cost in the United States. The USITC is expected to make a final determination this fall. If the USITC votes affirmatively, final rates will then be issued and take effect. Further, the DOC recently began an investigation into solar panels from Ethiopia and a petition was filed requesting investigation into solar panels from South Korea, both based on similar claims that solar panels from those countries are being made with Chinese-made components in violation of AD/CVD laws.

As a result of the duties that have been imposed to date, the cost and availability of solar panels in the United States has been impacted and the United States solar industry overall has experienced higher costs of materials as well as delays. Some of these impacts have already been reflected in the estimated cost and in-service dates for certain of our solar projects; however, we are continuing to monitor the tariffs and investigations for any additional potential impact on our solar projects.

Bulk-Power System Executive Order

On August 26, 2026, President Trump issued Executive Order 14421, declaring a national emergency to protect the United States bulk-power system from security threats associated with foreign-supplied electric equipment and technology. The order authorizes the United States Secretary of Energy to restrict, evaluate, and mitigate transactions involving the installation of foreign-sourced bulk-power system components that pose certain security threats initiated after the order and to establish a framework for identifying and monitoring the same foreign-sourced components already in the domestic power infrastructure prior to this order. This order covers facilities and control systems necessary for operating an interconnected transmission network and electric generation facilities but excludes local distribution. The Executive Order requires the United States Department of Energy to publish rules or regulations implementing this order no later than 120 days from August 26, 2026, or December 24, 2026. We are currently evaluating the potential operational and financial implications of this order.

Renewable Energy Legislation

Infrastructure Investment and Jobs Act

In November 2021, the Infrastructure Investment and Jobs Act was signed into law and provides for approximately $1.2 trillion of federal spending through 2026, including approximately $85 billion for investments in power, utilities, and renewables infrastructure across the United States. Funding from this Act supports the work we are doing to reduce GHG emissions and to strengthen and protect the energy grid. In January 2025, disbursement of funds was paused until agency heads could determine whether grants, loans, contracts, and other disbursements were consistent with the administration's energy policy. The pause disrupted, and continues to disrupt, funding, temporarily or permanently, for infrastructure projects already in progress, caused project delays and cancellations, and impacted payment obligations for downstream contractors and suppliers.

Inflation Reduction Act

In August 2022, the IRA was signed into law and provides for $258 billion in energy-related provisions over a 10-year period. The IRA has helped reduce our cost of investing in projects that support our commitment to reduce emissions and provide affordable, reliable, and clean energy for our communities. We and our customers have benefited from the IRA’s provisions to extend tax benefits for renewable technologies, increase or restore higher rates for PTCs, claim PTCs for solar projects, expand qualified ITC facilities to include standalone energy storage, and allow companies to transfer tax credits generated from renewable projects.

Under the IRA transferability option, we entered into agreements to sell the majority of the PTCs that we expect to generate in 2026 and a portion of the PTCs that we expect to generate in 2027 and 2028 to third parties. See Note 13, Income Taxes, for more information about these sales. The IRA also implements a 15% corporate alternative minimum tax and a 1% excise tax on stock repurchases. Although significant regulatory guidance is expected on the tax provisions in the IRA, we currently believe the provisions on alternative minimum tax and stock repurchases will not have a material impact on us.

09/30/2026 Form 10-Q			88			WEC Energy Group, Inc.

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One Big Beautiful Bill Act

In July 2025, the OBBBA was signed into law, enacting significant modifications to clean-energy tax credits previously provided under the IRA. The OBBBA provides companies the ability to earn solar and wind tax credits at current credit rates if construction of projects began by July 4, 2026, and the projects are placed in-service within four years after beginning construction. However, wind and solar projects that begin construction more than one year after enactment of the OBBBA must be placed in service by December 31, 2027 to qualify for PTCs and ITCs. In addition, wind and solar projects that began construction after December 31, 2025 must also satisfy prohibited foreign entity material assistance requirements, as defined through proposed guidance by the United States Treasury Department in February 2026. The incentives can also be denied for taxpayers that exceed certain thresholds of equity or debt held by specified foreign entities. The phase out of PTCs and ITCs does not apply to energy storage, hydroelectric facilities, nuclear, or any other zero emission technology. The OBBBA preserves the ability to transfer tax credits, with the exception of transfers to a prohibited foreign entity. In August 2025, the United States Treasury Department implemented new beginning-of-construction safe harbor rules that became effective in September 2025. However, in June 2026, a federal court vacated the revised beginning-of-construction safe harbor rules and remanded the issue back to the IRS for reconsideration. Therefore, uncertainty remains. We will continue to monitor additional information as it becomes available. The capital plan for 2027 through 2031 reflects the impacts of OBBBA, including the revised beginning-of-construction rules.

American Transmission Company LLC's Ozaukee County Distribution Interconnection Project

In September 2025, ATC filed an application for a CPCN with the PSCW to construct the Ozaukee County Distribution Interconnection Project. This proposed project is an important part of our plan to serve the data center under construction in Port Washington, Wisconsin, and includes the construction of new transmission lines, rebuilding and upgrading existing lines, and the construction of up to five new electrical substations. The PSCW deemed this CPCN application complete in December 2025. However, on September 10, 2026, based upon numerous revisions, modifications, and additional documents filed by ATC, the PSCW issued an order stating the current state of the CPCN application was unreasonably complicated and rescinded its previous completeness determination. As requested by the PSCW, ATC refiled its application for a CPCN to construct the Ozaukee County Distribution Interconnection Project on September 14, 2026. We are monitoring this project and all related PSCW actions for any potential impacts on our capital plan and earnings.

American Transmission Company LLC Allowed Return on Equity Complaint

For transmission owners such as ATC, the ROE allowed by the FERC helps determine how much can be earned on their transmission assets as well as how much consumers pay for those assets. In November 2013, a group of MISO industrial customers filed a complaint with the FERC requesting a decrease in the base ROE used by MISO transmission owners, including ATC, from 12.2% to 9.15%. Due to this complaint, the FERC and the D.C. Circuit Court of Appeals have issued the following orders and opinions. The base ROEs listed below do not include the 50 basis point ROE incentive currently provided for membership in a transmission organization.

•Significant FERC Orders Issued Prior to August 2022 D.C. Circuit Court of Appeals Opinion

◦In November 2019, the FERC issued an order that expanded its base ROE methodology and reduced the base ROE for MISO transmission owners to 9.88% for the period covered by the complaint, November 12, 2013 through February 11, 2015 and September 28, 2016 going forward. Then, in May 2020, the FERC made additional revisions to its base ROE methodology and issued an order that increased the base ROE for all MISO transmission owners to 10.02% for the period covered by the complaint.

•August 2022 D.C. Circuit Court of Appeals Opinion

◦In August 2022, the D.C. Circuit Court of Appeals ruled the FERC failed to adequately explain why it made additional revisions to its base ROE methodology in its May 2020 Order. Due to this ruling, the D.C. Circuit Court of Appeals vacated the FERC’s previous orders and remanded the issue of determining an appropriate base ROE for MISO transmission owners back to the FERC for additional proceedings.

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•Significant Orders and Opinions Issued After August 2022 D.C. Circuit Court of Appeals Opinion

◦In response to the August 2022 D.C. Circuit Court of Appeals Opinion, the FERC adjusted its base ROE methodology to remove the impacts of the May 2020 Order. As a result of this methodology change, orders were issued by the FERC in October 2024 and March 2025 that required MISO transmission owners to adopt a 9.98% base ROE for the period covered by the complaint. In June 2026, the D.C. Circuit Court of Appeals affirmed the FERC’s October 2024 and March 2025 orders, which had no impact on our financial statements.

Environmental Matters

See Note 22, Commitments and Contingencies, for a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change.

Market Risks and Other Significant Risks

We are exposed to market and other significant risks as a result of the nature of our businesses and the environments in which those businesses operate. These risks include, but are not limited to, the risks described below. In addition, the war with Iran and increasing tensions between the United States and other countries, as well as other new, protracted or escalating regional and international conflicts have had, and are expected to have a continuing, impact on the global economy, supply chains, and fuel prices. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in our 2025 Annual Report on Form 10-K for a discussion of market and other significant risks applicable to us.

Changes to United States Trade Policy (Tariff Activity)

The United States continues to implement changes to its international trade policy including changes to tariffs, port fees and other policies relating to exports from and imports into the United States. In response to these changes, foreign governments also continue to adjust their trade policies, including the imposition of additional tariffs. There remains significant uncertainty as to the ultimate scope, duration and impact of the United States and foreign trade policies. In certain cases, both the United States and foreign trade policy changes have resulted in increased cost of materials and disrupted supply chains, which may impact our ability to repair or maintain our infrastructure; the timing, cost or completion of our infrastructure projects; and/or our ability to execute our capital plan. In addition, these changes, including their potential impact on economic conditions, could lead to reduced energy demand by our customers. Consequently, these policy changes could have a material adverse effect on our business, results of operations and financial condition.

We have received refunds of certain tariffs paid in connection with our capital projects and continue to pursue additional refunds, including requiring our contractors and vendors to seek refunds, as applicable, of tariffs paid under the International Emergency Economic Powers Act and other tariff provisions.

Inflation and Supply Chain Disruptions

We continue to monitor the impact of inflation and supply chain disruptions. We monitor the costs of medical plans, fuel, transmission access, construction costs, regulatory and environmental compliance costs, and other costs in order to minimize inflationary effects in future years, to the extent possible, through pricing strategies, productivity improvements, and cost reductions. We monitor the global supply chain, and related disruptions, so that we are able to procure the materials and other resources necessary to both maintain our energy services in a safe and reliable manner and to grow our infrastructure in accordance with our capital plan. For additional information concerning risks related to inflation and supply chain disruptions, see the four risk factors below that are disclosed in Part I of our 2025 Annual Report on Form 10-K.

•Item 1A. Risk Factors – Risks Related to the Operation of Our Business – Public health crises, including epidemics and pandemics, could adversely affect our business functions, financial condition, liquidity, and results of operations.

•Item 1A. Risk Factors – Risks Related to the Operation of Our Business – Our operations and corporate strategy may be adversely affected by supply chain disruptions, inflation, and tariffs.

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•Item 1A. Risk Factors – Risks Related to the Operation of Our Business – We are actively involved with multiple significant capital projects, which are subject to a number of risks and uncertainties that could adversely affect project costs and completion of construction projects.

•Item 1A. Risk Factors – Risks Related to Economic and Market Volatility – The fluctuation in demand for certain commodities and their respective prices could negatively impact our operations.

For additional information concerning risk factors, including market risks, see the Cautionary Statement Regarding Forward-Looking Information at the beginning of this report.

Critical Accounting Policies and Estimates

We have reviewed our critical accounting policies and considered whether any new critical accounting estimates or other significant changes to our accounting policies require additional disclosures. We have found that the disclosures made in our 2025 Annual Report on Form 10-K are still current and that there have been no significant changes, except as follows:

Goodwill

We completed our annual goodwill impairment tests for all of our reporting units that carried a goodwill balance as of July 1, 2026. No impairments were recorded as a result of these tests. For all of our reporting units, the fair values calculated in step one of the test were greater than their carrying values. The fair values for the reporting units were calculated using a combination of the income approach and the market approach.

For the income approach, we used internal forecasts to project cash flows. Any forecast contains a degree of uncertainty, and changes in these cash flows could significantly increase or decrease the calculated fair value of a reporting unit. For our reporting units that are regulated, a fair recovery of and return on costs prudently incurred to serve customers is assumed. An unfavorable outcome in a rate case could cause the fair values of our reporting units to decrease.

Key assumptions used in the income approach include ROEs, the long-term growth rates used to determine terminal values at the end of the discrete forecast period, and the discount rates. The discount rate is applied to estimated future cash flows and is one of the most significant assumptions used to determine fair value under the income approach. As interest rates rise, the calculated fair values will decrease. The discount rate is based on the weighted-average cost of capital for each reporting unit, taking into account both the after-tax cost of debt and cost of equity. The terminal year ROE for each utility is driven by its current allowed ROE. The terminal growth rate is based primarily on a combination of historical and forecasted statistics for real gross domestic product and personal income for each utility service area.

For the market approach, we used a higher weighting for the guideline public company method than the guideline merged and acquired company method due to a low number of mergers and acquisitions in recent years. The guideline public company method uses financial metrics from similar publicly traded companies to determine fair value. The guideline merged and acquired company method calculates fair value by analyzing the actual prices paid for recent mergers and acquisitions in the industry. We applied multiples derived from these two methods to the appropriate operating metrics for our reporting units to determine fair value.

The underlying assumptions and estimates used in the impairment tests were made as of a point in time. Subsequent changes in these assumptions and estimates could change the results of the tests.

For all of our reporting units that carried a goodwill balance at July 1, 2026, the fair value exceeded its carrying value by over 50%. Based on these results, our reporting units are not at risk of failing step one of the goodwill impairment test.

See Note 18, Goodwill and Intangibles, for more information.

09/30/2026 Form 10-Q			91			WEC Energy Group, Inc.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes related to market risk from the disclosures presented in our 2025 Annual Report on Form 10-K. In addition to the Form 10-K disclosures, see Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in Item 2 of Part I of this report, as well as Note 14, Fair Value Measurements, Note 15, Derivative Instruments, and Note 16, Guarantees, in this report for information concerning our market risk exposures.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based upon such evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of such period, our disclosure controls and procedures are effective: (i) in recording, processing, summarizing, and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act; and (ii) to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the third quarter of 2026 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

09/30/2026 Form 10-Q			92			WEC Energy Group, Inc.

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Table of Contents

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The following should be read in conjunction with Item 3. Legal Proceedings in Part I of our 2025 Annual Report on Form 10-K. See Note 22, Commitments and Contingencies, and Note 24, Regulatory Environment, in this report for additional information on material legal proceedings and matters related to us and our subsidiaries.

In addition to those legal proceedings discussed in Note 22, Commitments and Contingencies, and Note 24, Regulatory Environment, we currently, and from time to time, are subject to claims and suits arising in the ordinary course of business. Although the results of these additional legal proceedings cannot be predicted with certainty, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material impact on our financial statements.

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors disclosed in Item 1A. Risk Factors in Part I of our 2025 Annual Report on Form 10-K.

ITEM 5. OTHER INFORMATION

During the three months ended September 30, 2026, none of our directors or officers (as defined in Rule 16a-1 under the Exchange Act) adopted or terminated any contract, instruction, or written plan for the purchase or sale of our securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any "non-Rule 10b5-1 trading arrangement" (as defined in Item 408 of Regulation S-K).

09/30/2026 Form 10-Q			93			WEC Energy Group, Inc.

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ITEM 6. EXHIBITS
The following exhibits are filed or furnished with or incorporated by reference in the report with respect to WEC Energy Group, Inc. (File No. 001-09057). An asterisk (*) indicates that the exhibit has previously been filed with the SEC and is incorporated herein by reference. A double asterisk (**) indicates that portions of the exhibit have been redacted because such portions are not material and are private or confidential.
Number						Exhibit
4						Instruments Defining the Rights of Security Holders, Including Indentures
						4.1*			Eighteenth Supplemental Indenture, dated as of August 13, 2026, between WPS and U.S. Bank Trust Company, National Association (as successor to Firstar Bank Milwaukee, N.A., National Association), as Trustee. (Exhibit 4.1 to WPS's Form 8-K filed August 13, 2026) (File No. 1-3016.)
10						Material Contracts
						10.1**			Point Beach PPA between Nextera Energy Point Beach, LLC and WE, dated as of August 14, 2026.
31						Rule 13a-14(a) / 15d-14(a) Certifications
						31.1			Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
						31.2			Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32						Section 1350 Certifications
						32.1			Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
						32.2			Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101						Interactive Data Files
						101.INS			Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
						101.SCH			Inline XBRL Taxonomy Extension Schema
						101.CAL			Inline XBRL Taxonomy Extension Calculation Linkbase
						101.DEF			Inline XBRL Taxonomy Extension Definition Linkbase
						101.LAB			Inline XBRL Taxonomy Extension Label Linkbase
						101.PRE			Inline XBRL Taxonomy Extension Presentation Linkbase
104						Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

09/30/2026 Form 10-Q			94			WEC Energy Group, Inc.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

						WEC ENERGY GROUP, INC.
						(Registrant)
						/s/ CAROLINE M. GARCIA
Date:			October 30, 2026			Caroline M. Garcia
						Vice President and Controller
						(Duly Authorized Officer and Chief Accounting Officer)

09/30/2026 Form 10-Q			95			WEC Energy Group, Inc.

Exhibit 10.1

Portions of this Exhibit have been omitted.

Omitted portions are not material and are private or confidential.

Execution Version

POINT BEACH NUCLEAR PLANT

POWER PURCHASE AGREEMENT

BETWEEN

NEXTERA ENERGY POINT BEACH, LLC

AND

WISCONSIN ELECTRIC POWER COMPANY

DATED AS OF AUGUST 14, 2026

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POWER PURCHASE AGREEMENT

TABLE OF CONTENTS

ARTICLE I: DEFINITIONS												2
			1.1.			Defined Terms						2
			1.2.						Rules of Interpretation			16
			1.3.			Accounting Terms						17
			1.4.						Legal Representation			17
ARTICLE II: PURCHASE OF CAPACITY, ENERGY, ANCILLARY SERVICES,
			AND ENVIRONMENTAL ATTRIBUTES									17
			2.1.			Capacity Sale and Purchase						17
			2.2.			Energy Sale and Purchase						18
			2.3.			Ancillary Services and Environmental Attributes						18
			2.4.			Replacement Energy						19
			2.5.			Financial Transmission Rights						20
			2.6.			Title and Risk of Loss						20
			2.7.						Delivery Point			20
			2.8.						Capacity Accreditation			21
			2.9.						Uprates			21
			2.10.			[Reserved]						22
			2.11.			Reactive Power						22
			2.12.			Station Service						22
			2.13.			CT and Solar Field Capacity						23
ARTICLE III: PAYMENTS												23
			3.1.			Purchase Payments						23
			3.2.			Peak Adjustment Payment						23
ARTICLE IV: SCHEDULING												24
			4.1.						Scheduling			24
			4.2.						Failure to Schedule			24
ARTICLE V: MAINTENANCE AND OPERATION												25
			5.1.			Scheduled Maintenance						25
			5.2.						Derate Notices			26
			5.3.						Operation			26
ARTICLE VI: METERING												29
			6.1.						Metering			29
ARTICLE VII: BILLING AND PAYMENT												30
			7.1.			Billing and Payment						30
ARTICLE VIII: PERFORMANCE SECURITY												31
			8.1.						Seller Performance Security			31
			8.2.			Buyer Performance Security						31
			8.3.			Draws; Replenishments; Return						32

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			8.4.						Reporting			32
ARTICLE IX: FORCE MAJEURE												33
			9.1.						Conditions of Excuse for Seller			33
			9.2.			Conditions of Excuse for Buyer						33
			9.3.			Burden of Proof						33
			9.4.			Payment and Security Obligations Not Excused						34
			9.5.			Time Limits						34
			9.6.			Deadline Extended						34
ARTICLE X: EVENTS OF DEFAULT; REMEDIES												34
			10.1.			List of Events of Default						34
			10.2.			Remedies						36
			10.3.			Rights of Specific Performance						37
			10.4.			Limitation of Liability						37
			10.5.			Disclaimer of Warranties						38
ARTICLE XI: REPRESENTATIONS, WARRANTIES AND COVENANTS												38
			11.1.			Representations and Warranties of Buyer						38
			11.2.			Representations and Warranties of Seller						39
			11.3.			Covenants of Seller						40
			11.4.			Covenants of Parties Relating to Regulatory Matters						40
			11.5.			Buyer Approval						41
ARTICLE XII: INDEMNITY												41
			12.1.			Indemnification By Seller						41
			12.2.			Indemnification by Buyer						41
			12.3.			Joint Negligence						42
			12.4.			Responsibility for Employees						42
			12.5.			Notice and Participation						42
			12.6.			Payment of Indemnification Claims						43
			12.7.			Survival of Obligation						43
ARTICLE XIII: TERM												43
			13.1.			Term and Conditions Precedent						43
			13.2.			Termination						44
			13.3.			Effect of Termination						44
ARTICLE XIV: ADMINISTRATIVE COMMITTEE												45
			14.1.			Purpose						45
			14.2.			Meetings						45
			14.3.			Functions						45
			14.4.			Expenses						46
ARTICLE XV: NOTICES												46
			15.1.			Notices in Writing						46
			15.2.			Date of Notification						47

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			15.3.			Oral Notice in Emergency						47
ARTICLE XVI: CONFIDENTIALITY												47
			16.1.			Confidentiality						47
			16.2.			Survival of Confidentiality						48
ARTICLE XVII: INSURANCE												48
			17.1.			Coverage and Amounts of Seller						48
			17.2.			Insurance Certificates						50
			17.3.			Coverage For Full Term						50
ARTICLE XVIII: ASSIGNMENT												50
			18.1.			Binding Effect						50
			18.2.			Assignment						50
			18.3.			Permitted Transfer						50
ARTICLE XIX: DISPUTE RESOLUTION												52
			19.1.			General Provisions						52
			19.2.			Negotiation						52
			19.3.			Binding Upon Parties						53
			19.4.			Continued Performance						53
ARTICLE XX: COMPLIANCE WITH LAWS; TAXES												53
			20.1.			Compliance with Laws						53
			20.2.			Mobile-Sierra						53
			20.3.			Taxes and Other Charges						54
ARTICLE XXI: CHANGE IN LAW												54
			21.1.			Change in Law						54
			21.2.			Environmental Attributes						55
			21.3.			MISO Changes						55
ARTICLE XXII: MISCELLANEOUS												55
			22.1.			Recording Telephone Conversations						55
			22.2.			Governing Law						56
			22.3.			Entire Agreement; Amendment						57
			22.4.			No Implied Waiver						57
			22.5.			Severability						57
			22.6.			No Exclusivity/Dedication of Assets						57
			22.7.			Expenses						57
			22.8.			Counterparts						58
			22.9.			Survival						58
			22.10.			Individual Responsibility						58
			22.11.			No Duty To Third Parties						58
			22.12.			Forward Contract						58
			22.13.			Press Releases						59

iii

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Exhibits

Exhibit A

Delivered Energy Charges

Exhibit B

Capacity and Capacity Testing Procedures

Exhibit C

Delivered Energy Charge Shaping Factor

Exhibit D

Diagram of Metering Devices

Exhibit E

Form of Seller’s Guaranty

Exhibit F

Form of Letter of Credit

Exhibit G

Peak Adjustment Payment

Exhibit H

Scheduling Provisions

Exhibit I

MISO Business Practice Manual

Exhibit J

Replacement Energy Provisions

Exhibit K

Performance Tests

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POWER PURCHASE AGREEMENT

This POWER PURCHASE AGREEMENT is made and entered into as of August 14, 2026 (the “Execution Date”), by and between NEXTERA ENERGY POINT BEACH, LLC, a Wisconsin limited liability company (“Seller”), and WISCONSIN ELECTRIC POWER COMPANY, a Wisconsin corporation (“Buyer”) (hereinafter the parties hereto are sometimes referred to collectively as the “Parties,” or individually as a “Party” and shall become effective as of the Unit 1 Commencement Date (as defined herein) (the “Effective Date”) (except that Article IX, Sections 11.1 and 11.2, 11.4, 11.5, 13.2(a), 13.2(b), Article XIX, Section 21.1, Article XVI, Article XVIII, Article XXII, and defined terms relevant to the foregoing, shall become effective as of the Execution Date).

W I T N E S S E T H:

WHEREAS, Buyer is a public utility which operates a system for generation and distribution of electric power in the States of Wisconsin and Michigan;

WHEREAS, as of the Execution Date, Seller wholly owns the Point Beach Nuclear Plant, a nuclear-powered electric generating facility consisting of two generating units and facilities, equipment, supplies and improvements (including the CT) located in Two Rivers, Wisconsin, NRC Operating License Nos. Unit 1 – DPR 24 and Unit 2 – DPR 27 (such licenses, the “NRC Operating Licenses,” and the Point Beach Nuclear Plant and the assets its comprises, “Point Beach”), and certain facilities and other assets associated therewith and ancillary thereto, in accordance with the NRC Licenses;

WHEREAS, Seller and Buyer are currently parties to that certain Power Purchase Agreement, dated as of December 19, 2006 (as amended, modified, supplemented or otherwise varied from time to time, the “Existing PPA”), pursuant to which Buyer acquires capacity, energy and all associated ancillary services of Point Beach from Seller throughout the current terms set forth in the NRC Operating Licenses (namely, through October 5, 2030, for Unit 1 and March 8, 2033 for Unit 2);

WHEREAS, under the Existing PPA, sales by Seller to Buyer of capacity, energy, and all associated ancillary services of Unit 1 at Point Beach terminate as of October 5, 2030, and sales by Seller to Buyer of capacity, energy, and ancillary services of Unit 2 at Point Beach terminate as of March 8, 2033;

WHEREAS, Seller has been granted further twenty (20) year renewals of the NRC Operating Licenses;

WHEREAS, in connection with such renewals of the NRC Operating Licenses, Buyer desires to purchase, and Seller desires to sell, under this Agreement rights related to eighty-six percent (86%) of the Capacity, Energy, and all associated Ancillary Services and Environmental Attributes (as such terms are defined herein) produced by (i) Unit 1 following the Unit 1 Commencement Date; and (ii) Unit 2 following the Unit 2 Commencement Date, respectively, on the terms, and subject to the conditions, set forth below; and

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WHEREAS, WPPI Energy, a Wisconsin municipal electric company, is entitled to purchase rights relating to the Capacity, Energy, and all associated Ancillary Services and Environmental Attributes (as such terms are defined herein) produced by Unit 1 and Unit 2 not purchased by Buyer hereunder.

NOW, THEREFORE, in consideration of the recitals and the mutual promises, covenants and agreements contained herein and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereto hereby agree as follows:

ARTICLE I: DEFINITIONS

1.1. Defined Terms

As used in this Agreement, the following terms shall have the following meanings:

“Accredited Capacity” means capacity as measured by applicable MISO rules (including those with respect to “Installed Capacity,” as defined by MISO), including the following to the extent applicable, capacity that (a) meets the resource adequacy requirements in Module E of the MISO Tariff (“Module E”) for Buyer’s Network Load, a portion of which may include capacity that satisfies the requirement for a Capacity Resource for Buyer’s Network Load and (b) is measured in accordance with the MISO Business Practice Manual.

“Acknowledgement” or “Acknowledged” means Buyer shall deliver to Seller an electronic acknowledgement within twenty-four (24) hours of receipt by Buyer of Seller’s Stable Energy Notice or Ramp Notice. For the avoidance of doubt, (i) the affected Unit shall be deemed to have achieved a Stable Level at the start of the Hour Ending (HE) clock-hour within which a Stable Energy Notice was delivered by Seller to Buyer regardless of whether an Acknowledgement was delivered to Seller by Buyer, and (ii) Buyer will be deemed to have Acknowledged a Stable Energy Notice or Ramp Notice if such notice is properly delivered pursuant to this Agreement and Buyer fails to deliver an Acknowledgement thereof to Seller within twenty-four (24) hours of receipt of such notice.

“Administrative Committee” has the meaning set forth in Article XIV: .

“Affiliate” has the meaning set forth in Rule 12b-2 under the Securities Exchange Act of 1934.

“Agreement” means this Power Purchase Agreement entered into by Seller and Buyer, including all Attachments, Exhibits, and Schedules hereto.

“Ancillary Services” means those services that during the Term are necessary to support the transmission of electric capacity and energy, or support the generation or transmission of Energy from the Facilities, as applicable, while maintaining reliable operation of the transmission system, associated with or otherwise corresponding to the Capacity of the Facilities, as applicable, and/or output of Energy at such time, which Ancillary Services shall include Reactive Power and frequency response service. Seller shall not have to incur any incremental costs in connection with the delivery of Ancillary Services to Buyer in

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excess of the amount available in the Seller Contingency Tranche; Buyer shall pay all such incremental costs.

“Associate” means, with respect to any Party, any officer, director, trustee, fiduciary, employee, agent, representative, contractor or subcontractor of such Party and any shareholder, partner, member or other owner of such Party.

“ATC” means the American Transmission Company LLC.

“Authorization” means any license, permit, approval, consent, filing, waiver, exemption, variance, clearance, entitlement, allowance, franchise or other authorization, whether corporate, governmental, regulatory or otherwise.

“Balancing Authority Function” means the operating authority that maintains the load resource balancing and reliability for the balancing authority area in which the Facilities

are located and includes Local Balancing Authorities as defined in the MISO Tariff.

“Billing Cycle” means each calendar month during the Term and any partial calendar month at the beginning or end of the Term.

“Business Day” means any day other than Saturday, Sunday, or any NERC holiday or any other day on which banking institutions in the State of Wisconsin or the State of Florida are authorized by Law or by the order, direction, or decree of any Governing Authority to be closed.

“Buyer” has the meaning set forth in the Preamble.

“Buyer Approval” has the meaning set forth in Section 11.5.

“Buyer Approval Date” has the meaning set forth in Section 11.5.

“Buyer Performance Security” means any performance security that may be required to be posted by Buyer pursuant to Section 8.2.

“Buyer’s Capacity Amount” means, for any given time, Buyer’s Product Share of Capacity of the Facilities, as further set forth and described in Section 2.1 and Exhibit B.

“Buyer’s Guarantor” means a Person that, at the time of the execution and delivery of any guaranty issued pursuant to Section 8.2, is a direct or indirect owner of Buyer and (a) has an Investment Grade Credit Rating and a consolidated Net Worth of at least five hundred million dollars ($500,000,000.00); or (b) is reasonably acceptable to Seller as having a verifiable creditworthiness and Net Worth sufficient to secure Buyer’s Guarantor’s obligations under any guaranty issued pursuant to Section 8.2.

“Buyer’s Guaranty” has the meaning set forth in Section 8.2.

“Buyer’s Product Share” means eighty-six percent (86%).

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“Calendar Year” means a twelve-month period beginning January 1 and ending December 31.

“Capacity” means, on or as of any date of determination with respect to any of the Facilities, such Facility’s capability to generate a specific amount of electrical energy at a given point in time, which capability shall be measured by Performance Tests in accordance with this Agreement and set forth from time to time in Exhibit B.

“Capacity Resource” has the meaning set forth in the MISO Tariff.

“Change in Control” means any one or more of the following events that occurs with respect to Seller, or with respect to any Person which is a direct or indirect owner of a majority of the ownership interests in Seller: (i) a transfer of a majority of the ownership interests in Seller or such Person; (ii) a change in the general partner of any such Person; (iii) any consolidation or merger of Seller or any such Person in which Seller or such Person, as the case may be, is not the continuing or surviving entity, other than a consolidation or merger of a Person in which the holders of such Person's ownership interests immediately before the consolidation or merger shall, upon consummation of the consolidation or merger, own at least 50% of the equity of the surviving entity; or (iv) any other event or circumstance in which "control" (as defined in Rule 12b-2 under the Securities Exchange Act of 1934) of Seller or of any such Person is transferred to another Person.

“Change in Law” has the meaning set forth in Section 21.1.

“Claims” means all third-party claims or actions, threatened or filed and, whether groundless, false, fraudulent or otherwise, that directly or indirectly relate to the subject matter of an indemnity, and the resulting losses, damages, expenses, reasonable attorneys’ fees and court costs.

“Communications Protocol” has the meaning set forth in Section 5.3(b)(i).

“Confidential Information” means all confidential information concerning the business, strategies, operations, financial affairs, trade secrets, intellectual property, organizational and personnel matters, policies, procedures and other proprietary non-public matters related to the Parties or Point Beach, including the terms and conditions of this Agreement, or any WEPCO Power Purchase Agreement.

“CPNode” means the commercial pricing nodes established by the Transmission Provider for both Unit 1 and Unit 2 (as of the Effective Date, such nodes are WEC.PTBHGBl (for Unit 1) and WEC.PTBHGB2 (for Unit 2)); provided, that if this Agreement only applies to one Unit, then the CPNode shall be the applicable commercial pricing node for such Unit.

“Credit Rating” means, with respect to an entity, the rating assigned to such entity’s unsecured, senior long-term debt obligations (not supported by third party credit enhancements) by Moody’s or S&P or, in the event such rating is not assigned, then the issuer rating assigned by S&P or Moody’s with respect to such entity.

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“CT” means the existing No. 2 fuel oil-fired combustion turbine generator located at the Facilities site.

“Defaulting Party” has the meaning set forth in Section 10.1.

“Delivered Energy” means, for any period of time, the sum of the Net Energy Output plus Replacement Energy delivered to the Delivery Point and confirmed by Buyer in accordance with the scheduling provisions in Exhibit H, part (b)(iii).

“Delivered Energy Charge” has the meaning set forth in Section 3.1(a).

“Delivered Energy Payment” has the meaning set forth in Section 3.1(a).

“Delivery Period” means the period commencing on the earlier of: (i) the commencement date of the Delivery Period – Unit 1, and (ii) the commencement date of the Delivery Period – Unit 2; and continuing through the later of: (x) the Unit 1 Termination Date, and (y) the Unit 2 Termination Date.

“Delivery Period – Unit 1” means the period commencing on 0000 hours EST on the Unit 1 Commencement Date and ending on 2400 hours EST on the Unit 1 Termination Date.

“Delivery Period – Unit 2” means the period commencing on 0000 hours EST on the Unit 2 Commencement Date and ending on 2400 hours EST on the Unit 2 Termination Date.

“Delivery Point” has the meaning set forth in Section 2.7.

“Derate” means, with respect to a given Unit, an event or condition which causes the Net Energy Output of such Unit to be less than [ ] of the associated Buyer’s Capacity Amount, or causes the MISO FinSched to be less than [ ] of the associated Buyer’s Capacity Amount attributable to such Unit, unless such event or condition resulting in a reduction in the MISO FinSched was agreed to by Buyer, excluding any ramp up or ramp down of the Facilities associated with Seller’s nuclear fuel management procedures scheduled in accordance with Section 5.1.

“Derate Notice” has the meaning set forth in Section 5.2.

“Designated Network Resource” or “DNR” means a resource deliverable to the Buyer’s Network Load designated as a “Network Resource” as defined under the applicable MISO Tariff and related documents. The term DNR shall apply to the Facilities and to the resource selected by Seller, and accepted by MISO as a WEPCO Designated Network Resource.

“Dispatch Authority Function” means the Buyer’s Power Operations group in its Power Generation department or such other group or department of Buyer as Buyer may designate by written notice to Seller from time to time.

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“Dispute” means any controversy, claim or dispute of whatsoever nature, arising out of or relating to this Agreement or the making, validity, execution, performance, discharge, termination, or breach hereof.

“Dispute Resolution Procedures” means the dispute resolution procedures for Disputes set forth in Article XIX: .

“Early Termination Date” has the meaning set forth in Section 10.2.

“Effective Date” has the meaning set forth in the Preamble.

“Electric Reliability Organization” or “ERO” has the meaning set forth in 18 C.F.R. § 39.1.

“Energy” means electric energy expressed in MWh.

“Environmental Attributes” means those attributes (such as RECs) that may be available under applicable or future Law relating to avoided NOx, SOx, CO2, or other greenhouse gas emissions. Environmental Attributes do not include any Tax attributes including, without limitation, the PTC or any other state, local and/or federal production tax credit (including the PTC and the Nuclear PTC), tax deduction, and/or investment tax credit (including the ITC) specific to the production of renewable or other low-intensity carbon energy and/or investments in renewable or other low-intensity carbon energy facilities, or certain other tax incentives existing now or in the future associated with the construction, ownership or operation of the Facilities. While Buyer will receive Environmental Attributes to the extent provided by this Agreement, Buyer will pay all incremental costs, if any, with respect to issuance of the Environmental Attributes in excess of the amount available in the Seller Contingency Tranche.

“EST” or “Eastern Standard Time” means, with respect to any particular time in question, Eastern Standard Time.

“Event of Default” has the meaning set forth in Section 10.1.

“Execution Date” has the meaning set forth in the Preamble.

“Existing PPA” has the meaning set forth in the Recitals.

“Facilities” means Point Beach (including Unit 1 and Unit 2) but excluding (a) any Uprate not accepted by Buyer pursuant to the Existing PPA or Section 2.9 and (b) the CT, the Solar Field, and any other new ancillary generation facilities added; provided, that, (i) after the Unit 1 Termination Date (if prior to the Unit 2 Termination Date), the term “Facilities” shall exclude Unit 1 for the remainder of the Term of this Agreement, and (ii) after the Unit 2 Termination Date (if prior to the Unit 1 Termination Date), the term “Facilities” shall exclude Unit 2 for the remainder of the Term of this Agreement.

“FASB” means the Financial Accounting Standards Board.

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“FERC” means the Federal Energy Regulatory Commission.

“Financial Bilateral Transaction” has the meaning ascribed to such term by the Transmission Provider in the applicable MISO Tariff or related documents, as such relevant meaning or relevant term may be modified from time to time.

“Force Majeure” means any cause or occurrence beyond the reasonable control of and without the fault or negligence of the affected Party which causes such Party to be unable to, or otherwise materially impairs its ability to, perform its obligations hereunder and which by the exercise of reasonable foresight such Party could not have been reasonably expected to avoid and could not have been prevented or avoided by such Party through the exercise of reasonable diligence. Subject to the foregoing, such causes or occurrences may include any acts of God; acts of the public enemy; wars; blockades; insurrections; riots; epidemics; landslides; lightning; earthquakes; fires; storms; floods; washouts; civil disturbances; strikes, lockouts, work stoppages or other labor actions that affect the U.S. electric generation or utility industry as a whole, including operation of the Facilities; shutdowns or reductions in the Facilities’ output or capabilities required, caused by, or related to directives, orders or requirements of the NRC or any other Governing Authority that affect the U.S. nuclear generation industry as a whole; Seller’s inability to obtain fuel supply for the Facilities; a Change in Law and any other cause, whether of the kind herein enumerated or otherwise, which, despite all reasonable efforts of such Party to prevent or mitigate its effects, prevents or delays the performance of a Party, or prevents the obtaining of the benefits of performance by the other Party, and is not within the control of the Party claiming excuse. The following acts, events or causes shall in no event constitute an event of Force Majeure: (i) any lack of profitability to a Party or any losses incurred by a Party or any other financial consideration of a Party; (ii) unavailability of funds or financing; (iii) an event caused by conditions of national or local economics or markets; (iv) any failure of equipment which is not itself directly caused by an event which would otherwise independently constitute a Force Majeure; (v) strikes, lockouts, work stoppages or other labor actions that affect the operation of the Facilities but do not affect the U.S. electric generation or utility industry as a whole; (vi) changes in market conditions that affect the cost or availability of equipment, materials, supplies or services, including the cost of power from resources other than the Facilities, but this exclusion (vi) shall not be deemed to include change in market conditions with respect to the fuel supply for the Facilities; (vii) failures of third parties, unless such failures are caused by an event which would otherwise constitute a Force Majeure event hereunder, if experienced by a Party and the Party claiming Force Majeure is relying on such third party in order to discharge any of such Party’s duties or obligations hereunder; (viii) climatic temperature and humidity conditions; and (ix) shutdowns or reductions in the Facilities’ output or capabilities required, caused by, or related to, directives, orders or requirements of the NRC or any other Governing Authority that do not apply to the U.S. nuclear electric generation industry as a whole. The curtailment, unavailability or interruption of transmission service shall not constitute a Force Majeure event unless MISO directs the curtailment or interruption of transmission service overall, or substantially all, of the transmission system owned and/or controlled by the Transmission Owner in the State of Wisconsin.

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“GAAP” means generally accepted accounting principles in the United States, as in effect from time to time, consistently applied, except as to consistency for mandated changes imposed by appropriate accountancy administrative bodies (including the FASB) or regulatory authorities.

“Generation Offer” has the meaning ascribed to such term by MISO in the applicable MISO Tariff or related documents, as such relevant meaning or relevant term may be modified from time to time.

“Governing Authority” means the federal government of the United States, and any state, county or local government, and any regulatory department, body, political subdivision, commission, bureau, administration, agency, instrumentality, ministry, court, judicial or administrative body, taxing authority, or other authority of any of the foregoing (including, without limitation, any corporation or other entity owned or controlled by any of the foregoing), PSCW, MISO, ERO, NRC, any other regional reliability council, the Transmission Provider and any other regional transmission organization, in each case having jurisdiction over any or all of the Parties, the Facilities or the Transmission Provider’s transmission system, whether acting under express or delegated authority.

“Gross Receipts Tax” means the tax imposed by the State of Wisconsin pursuant to Sections 76.28 and 76.29 of the Wisconsin Statutes as amended.

“Gross Receipts Tax Payment” has the meaning set forth in Section 20.3(d).

“Indemnified Party” has the meaning set forth in Section 12.5.

“Indemnifying Party” has the meaning set forth in Section 12.5.

“Insufficient Credit Status” means, as to Buyer or Seller, or if Buyer is providing collateral in the form of a guaranty, the Buyer’s Guarantor, or if Seller is providing collateral in the form of a guaranty, Seller’s Guarantor, that: (a) such Person does not have a Credit Rating or such Person’s Credit Rating is not Investment Grade or is determined by either Moody’s or S&P to not be Investment Grade; or (b) the maturity of any indebtedness of such Person which in the aggregate exceeds one hundred million dollars ($100,000,000) or five percent (5%) of the shareholders’ equity of such Person, whichever is less, is accelerated by the holder or holders thereof as a result of a default thereunder, or such holders have the right to accelerate such indebtedness (without regard to any requirements relating to notice, the passage of time or both) as a result of a payment default or a default with respect to a failure by Buyer or Seller (or Buyer’s Guarantor or Seller’s Guarantor), as applicable, to comply with a financial covenant.

“Interconnection Agreement” means the Generation Transmission Interconnection Agreement by and among Seller, ATC, and MISO dated as of July 12, 2010, as amended and restated on October 10, 2011, and as further revised on November 6, 2018.

“Investment Grade” means a Credit Rating of at least BBB- by S&P and Baa3 by Moody’s; provided, that if an entity is rated by only S&P or Moody’s, as applicable, then such Credit Rating shall be at least the rating stated above by S&P or Moody’s, as

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applicable. In the event that a Credit Rating from one of S&P or Moody’s is at or above Investment Grade and the Credit Rating from the other rating agency is below Investment Grade with respect to a Person or its obligations, then such Person and its obligations shall not be considered to have an Investment Grade Credit Rating.

“ITC” means the investment tax credit established pursuant to Section 48 or Section 48E of the Internal Revenue Code, as such law may be amended or superseded.

“Law” means any federal, state and local laws, statutes, regulations, rules, codes, orders, judgments, decrees or ordinances enacted, adopted, issued or promulgated by any Governing Authority, including any Authorizations issued to a Party or by which a Party or the Facilities may be bound (including any of the foregoing pertaining to electrical, building, zoning, environmental and occupational safety and health requirements) or any published directive, guideline, requirement or other governmental restriction which has the force of law or any determination by, or interpretation of, any of the foregoing by any Governing Authority, binding on a given Person in a relevant jurisdiction.

“Letter of Credit” means an irrevocable standby letter of credit, substantially in the form attached hereto as Exhibit F and which (i) is issued by a U.S. commercial bank or the U.S. branch of a foreign bank with total assets of at least ten billion dollars ($10,000,000,000) having a Credit Rating of A- or higher by S&P or A3 or higher by Moody’s; and (ii) permits presentation for drawing at a bank located in Milwaukee, Wisconsin.

“LMP” means the “Locational Marginal Price” at the relevant CPNode for the relevant hour(s) and day(s) for the MISO Day-Ahead Market or MISO Real-Time Market, as applicable, as posted by MISO.

“Maintenance Schedule” has the meaning set forth in Section 5.1(a).

“Medical Isotopes Project” means any project pursuant to which medical isotopes are or are intended to be produced by inserting target material into a nuclear reactor at Point Beach, including all work, equipment, assets, materials, third party business interests, and other revenue that is primarily related to any such project.

“Metering Devices” has the meaning set forth in Section 6.1(a).

“MISO” means the Midcontinent Independent System Operator, Inc.

“MISO Business Practices Manual” means the applicable MISO Business Practices Manual as published by MISO and updated from time to time.

“MISO Day-Ahead Market” means the Day-Ahead Energy and Operating Reserve Market as defined in the applicable MISO Tariff, or successor term referring to MISO’s centralized forward market for sales and purchases of energy and related products.

“MISO FinSched” means a Financial Bilateral Transaction for a given Operating Day that is subsequently settled in the MISO Day Ahead Market with a source point and delivery point at the CPNode and the sink point at WEC.S.

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“MISO FinSched Energy” means the quantity of MWh Scheduled on MISO FinScheds for a given Operating Day.

“MISO Market” means the MISO Real-Time Market or the MISO Day-Ahead Market.

“MISO Market Time” means Eastern Standard Time or as otherwise set forth in the MISO Tariff.

“MISO Real-Time Market” means the Real-Time Energy and Operating Reserve Market as defined in the applicable MISO Tariff, or successor term referring to MISO’s centralized market for energy sales and purchases during an Operating Day.

“MISO Tariff” means the “Open Access Transmission, Energy and Operating Reserve Markets Tariff for the Midwest Independent System Operator, Inc.” or any successor tariff adopted by MISO, or tariff of a successor to MISO, and any related procedures or rules published by MISO, including the “Business Practice Manual” related thereto.

“Module E” has the meaning set forth in the definition of Accredited Capacity.

“Moody’s” means Moody’s Investor Services, Inc.

“MW” means a megawatt.

“MWh” means megawatt-hours.

“NEER” or “NextEra” means NextEra Energy Resources, LLC.

“NEIL” means Nuclear Electric Insurance Limited.

“NEPB” means NextEra Energy Point Beach, LLC.

“NERC” means the North American Electric Reliability Council.

“Net Energy Output” means, for any hour during a Billing Cycle and with respect to the applicable Unit, (a) if the applicable Unit is operating, total Energy output of the applicable Unit as measured at the Delivery Point (in MWh), which shall be net of Station Service Load calculated at the applicable Metering Devices, multiplied by a fraction, the numerator of which is the Capacity of the applicable Unit and the denominator of which is the sum of (i) the Capacity of the applicable Unit and (ii) the Capacity of any Uprate with respect to the applicable Unit not accepted by Buyer pursuant to the Existing PPA or Section 2.9 (provided that Net Energy Output can in no event be less than zero), or (b) if the applicable Unit is not operating, zero MWh with respect to such Unit.

“Net Energy Output – Unit 1” means the Net Energy Output produced by Unit 1.

“Net Energy Output – Unit 2” means the Net Energy Output produced by Unit 2.

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“Net Worth” means the dollar value calculated by subtracting liabilities from total assets (excluding goodwill and other intangible assets described in FASB Statement 142) as such terms are determined in accordance with GAAP.

“Network Load” has the meaning set forth in the MISO Tariff.

“Non-Defaulting Party” has the meaning set forth in Section 10.1.

“Notice Time” means the time no later than two (2) hours prior to the deadline for submission to MISO of Generation Offers for the next Operating Day.

“NRC” means the United States Nuclear Regulatory Commission.

“NRC Operating Licenses” has the meaning set forth in the Recitals.

“Nuclear PTC” means the production tax credit established pursuant to Section 45J or 45U of the Internal Revenue Code, as such law may be amended or superseded.

“Off-Peak” means all hours that are not On-Peak hours.

“On-Peak” means the hours from 0700 EST through and including the hour ending 2200 EST, Monday through Friday, excluding NERC holidays.

“Operating Contact” has the meaning set forth in Section 14.1.

“Operating Day” has the meaning ascribed to such term by MISO in the applicable MISO Tariff or related documents, as such relevant meaning or relevant term may be modified from time to time.

“Party” has the meaning set forth in the Preamble.

“Peak Adjustment Payment” has the meaning set forth in Section 3.2.

“Peak Period” means the month of June, July, and August in each year of the Delivery Period during the Term, as further described in Exhibit G.

“Performance Test” has the meaning set forth in Section 5.3(d)(ii).

“Permitted Transfer” has the meaning set forth in Section 18.3.

“Person” means any individual, partnership, limited liability company, joint venture, corporation, trust, unincorporated organization, association, or governmental entity or any political subdivision, department or agency thereof.

“Planned Resource Credits” has the meaning given to it in the MISO Tariff.

“Point Beach” has the meaning given such term in the Recitals.

“PPAs” means the Existing PPA and this Agreement, taken collectively.

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“Prime Rate” means, for any period, the rate per annum expressed as a daily percentage, in effect on the first day of such period, as published from time to time in the money rates section of The Wall Street Journal representing the base rate on corporate loans posted by at least seventy-five percent (75%) of the nation’s thirty (30) largest banks. If for any reason such rate is not available, “Prime Rate” means the rate per annum which JPMorgan Chase Bank announces in New York from time-to-time as its prime or base lending rate for corporate customers.

“Products” means (i) Buyer’s Product Share of the Capacity of the Facilities, as further described in Section 2.1, (ii) Buyer’s Product Share of the Net Energy Output of the Facilities, (iii) the Environmental Attributes attributable to and generated as a result of Buyer’s Product Share of the Capacity of the Facilities and Net Energy Output of the Facilities, and (iv) the Ancillary Services associated with Buyer’s Product Share of the Capacity of the Facilities and Net Energy Output.

“Prudent Utility Practice” means any applicable practices, methods and acts engaged in or approved by a significant portion of (a) as to Seller, the nuclear power electric generating industry in the United States of America, or (b) as to Buyer, the electric utility industry in the United States of America, during the relevant time period, or the practices, methods and acts which, in the exercise of reasonable judgment by a prudent nuclear operator (or prudent utility operator, if applicable to Buyer) in light of the facts known or which should reasonably have been known at the time the decision was made, could have been expected to accomplish the desired result consistent with good business practices, reliability, safety, expedition and the requirements of any Governing Authority having jurisdiction. “Prudent Utility Practice” is not intended to be limited to the optimum practice, method or act to the exclusion of all others, but rather to the acceptable practices, methods or acts generally accepted (a) as to Seller, by the nuclear power electric generating industry in the United States of America or (b) as to Buyer, by the electric utility industry in the United States of America.

“PSCW” means the Public Service Commission of Wisconsin.

“PSCW Approval” has the meaning set forth in Section 11.4.

“PTC” means the production tax credit established pursuant to Section 45 or Section 45Y of the Internal Revenue Code, as such law may be amended or superseded.

“Qualified Operator” means an operator of nuclear generation facilities that has, or provides Seller’s Performance Security from a Person that has, an Investment Grade Credit Rating, is nationally recognized, and demonstrates to the Buyer’s reasonable satisfaction that it has sufficient experience to successfully operate Point Beach.

“Ramp Down Notice” means confirmation of the commencement of a Ramp Down Period provided in writing by Seller to Buyer transmitted electronically within twenty-four (24) hours of such commencement and receipt Acknowledged by Buyer.

“Ramp Down Period” means the period of time during which the Energy production of a Unit is being decreased in association with a Derate.

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“Ramp Notice” means either a Ramp Down Notice or Ramp Up Notice.

“Ramp Period” means each of a Ramp Down Period and a Ramp Up Period.

“Ramp Up Notice” means confirmation of the commencement of a Ramp Up Period provided in writing by Seller to Buyer transmitted electronically within twenty-four (24) hours of such commencement and receipt Acknowledged by Buyer.

“Ramp Up Period” means the period of time during which the Energy production of a Unit is being increased in association with a Derate.

“Reactive Power” means the reactive power capability of the Facilities as set forth in the Interconnection Agreement.

“Replacement Energy” means, at any time, Energy supplied to Buyer by Seller from any resource other than the Facilities to fulfill, in part or in whole, Seller’s obligation hereunder to deliver Energy which, when combined with the Net Energy Output of the Facilities, shall not exceed the aggregate amount of Energy associated with the Facilities’ Capacity as calculated in Exhibit B.

“Replacement Energy Notice” has the meaning set forth in Exhibit J.

“Replacement Energy Period” has the meaning set forth in Exhibit J.

“Representatives” means, with respect to any Person, such Person’s directors, officers, employees, advisors, consultants, partners, agents or representatives.

“Revenue Sufficiency Guarantee” has the meaning set forth in the MISO Tariff.

“S&P” means Standard & Poor’s Ratings Group (A Division of The McGraw-Hill Companies).

“SCADA” means supervisory, control and data acquisition technology and equipment.

“Schedule”, “Scheduled” or “Scheduling” means the actions of Seller, Buyer and/or their designated representatives, of notifying, requesting and confirming to each other and to any third party the quantity and type of Energy to be delivered on any Operating Day (a) submitted to MISO by Seller as Seller’s Generation Offer from the Facilities for a relevant Operating Day during the Term pursuant to this Agreement, or (b) submitted to MISO by Seller and accepted by Buyer as a Financial Bilateral Transaction for a relevant Operating Day during the Term pursuant to this Agreement.

“Scheduled Maintenance Outage” has the meaning set forth in Section 5.1(a).

“Scheduling Window” has the meaning set forth in Exhibit H.

“Seller” has the meaning set forth in the Preamble.

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“Seller Contingency Tranche” shall mean the one million dollars ($1,000,000) that Seller will absorb in the first instance for the collective specified additional costs regarding Ancillary Services, Environmental Attributes, and, to the extent provided in Section 2.11(b), Reactive Power before such additional costs are allocated in the manner set forth in the relevant provisions of this Agreement, it being agreed and understood that Seller shall have no obligation to replenish any funds withdrawn from this Seller Contingency Tranche.

“Seller Performance Security” means the performance security required to be posted by Seller pursuant to Section 8.1.

“Seller’s Guarantor” means a Person that, at the time of the execution and delivery of the Seller’s Guaranty, is a direct or indirect owner of Seller and (a) has an Investment Grade Credit Rating and a consolidated Net Worth of at least one billion dollars ($1,000,000,000.00); or (b) is reasonably acceptable to Buyer as having a verifiable creditworthiness and Net Worth sufficient to secure Seller’s Guarantor’s obligations under the Seller’s Guaranty.

“Seller’s Guaranty” has the meaning set forth in Section 8.1.

“Senior Executives” has the meaning set forth in Section 19.2.

“Shaping Factor” means the Delivered Energy Charge Shaping Factor set forth for the applicable period in Exhibit C.

“Short Derate” has the meaning set forth in Exhibit J.

“Solar Field” means the assets (tangible and intangible) and business of the solar photovoltaic energy project located at Point Beach.

“Station Service Load” means all electric service requirements used in connection with the operation and maintenance of the Facilities and any improvements thereto, including auxiliary, stand-by, supplemental, back-up maintenance and interruptible power.

“Subsequent Derate Notice” has the meaning set forth in Exhibit J.

“Target Capacity Factor” means [ ].

“Tax” means (i) any tax (including but not limited to franchise tax), charge, fee, levy or other assessment imposed by any Governing Authority and based on or measured with respect to net income or profits, including any interest, penalties or additions attributable or imposed with respect thereto, and (ii) any other tax, charge, levy, fee or other assessment imposed by any Governing Authority, including any transfer, gross receipts, sales, use, service, occupation, ad valorem, property, payroll, personal property, excise, severance, premium, stamp, documentary, license, registration, social security, employment, unemployment, disability, environmental (including but not limited to taxes under Section 59A of the Internal Revenue Code of 1986), add-on, value added, withholding (whether payable directly or by withholding and whether or not requiring the filing of a tax return

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therefor), commercial rent and occupancy tax, and (iii) any estimated tax, deficiency assessment, interest, penalties and additions to tax or additional amounts in connection with any of the foregoing, imposed by any Governing Authority; provided, that “Tax” does not include any Gross Receipts Tax.

“Term” means the period from and after the Effective Date to and including the date and time of the later of (i) the Unit 1 Termination Date or (ii) the Unit 2 Termination Date, it being agreed and understood that, as provided in the Preamble, certain Articles and Sections of this Agreement are operative as of the Execution Date forward through the end of the Term.

“Transmission Owner” means ATC.

“Transmission Provider” means MISO with respect to its function as the regional transmission organization and/or with respect to its function as market operator of the MISO Market, as applicable; in the event either of such functions is performed by a separate entity, “Transmission Provider” shall refer to such entity as and where applicable in this Agreement.

“Unit” means Unit 1 or Unit 2, and “Units” means Unit 1 and Unit 2, collectively

“Unit 1” means Point Beach Nuclear Plant Unit 1 and related facilities in existence as of the Effective Date.

“Unit 1 Commencement Date” means October 6, 2030.

“Unit 1 Termination Date” means the earlier of (i) 2400 hours EST on October 5, 2050, (ii) effective date of termination of this Agreement in relation to Unit 1 only pursuant to Section 13.2, or (iii) any Early Termination Date pursuant to Section 10.2.

“Unit 2” means Point Beach Nuclear Plant Unit 2 and related facilities in existence as of the Effective Date.

“Unit 2 Commencement Date” means March 9, 2033.

“Unit 2 Termination Date” means the earlier of (i) 2400 hours EST on March 8, 2053, (ii) effective date of termination of this Agreement in relation to Unit 2 only pursuant to Section 13.2, or (iii) any Early Termination Date pursuant to Section 10.2.

“Unscheduled Outage” means any Derate of the Facilities other than a Scheduled Maintenance Outage.

“Uprate” means, with respect to each Unit, an increase in the maximum thermal power level at which such Unit may operate under its NRC license as such license may be amended after the date hereof.

“VAR” or “VARs” means Volt-Amps-Reactive, a measure of reactive power.

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“Weekly Schedule” has the meaning set forth in Section 2.4(a)(i).

“WEPCO” means Wisconsin Electric Power Company, a utility subsidiary of Wisconsin Energy Corporation.

“WEPCO Power Purchase Agreements” means, individually or collectively as the context may require, (i) the Existing PPA, (ii) this Agreement, and (iii) any other power purchase agreement between WEPCO, as buyer, and NEPB, as seller.

“Worker’s Compensation Laws” means all Laws relating to employment-related accidents and diseases and the benefits, insurance and other compensation required in relation thereto.

“ZRCs” are Zonal Resource Credits as defined in the MISO Tariff, and shall include any replacements thereto adopted in the MISO Tariff including any zonal credits.

1.2. Rules of Interpretation

In this Agreement and in any Appendices, Exhibits or Schedules attached hereto, except to the extent that the context requires otherwise:

(a)The Table of Contents and the headings of the Articles and Sections herein have been inserted as a matter of convenience for reference only and shall not control or affect the meaning or construction of any of the terms or provisions hereof;

(b)The singular includes the plural and the masculine includes the feminine and neuter unless the context requires otherwise;

(c)Except as otherwise expressly provided, references to any document, agreement or Law, including this Agreement, shall be deemed to include references to (i) all appendices, exhibits, and schedules attached thereto and (ii) such document, agreement or Law as amended, modified, supplemented, replaced or restated from time to time in accordance with its terms (if applicable) and (where applicable) subject to compliance with the requirements set forth therein;

(d)The Exhibits hereto are incorporated herein by this reference and are intended to be a part of this Agreement; provided, however, that in the event of a conflict between the terms of an Exhibit and the terms of the remainder of this Agreement, the terms of the remainder of the Agreement shall take precedence;

(e)References to “Articles,” “Sections,” “Clauses,” “Paragraphs,” “Appendices,” “Exhibits,” or “Schedules,” are to articles, sections, clauses, paragraphs, appendices, exhibits or schedules of this Agreement;

(f)All references to a particular Person shall include a reference to such Person’s successors and permitted assigns;

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(g)The words “herein,” “hereof” and “hereunder” shall refer to this Agreement as a whole and not to any particular section or subsection of this Agreement; the words “include,” “includes” or “including” shall mean “including, but not limited to;”

(h)The term “day” shall mean a calendar day commencing at 0000 EST and whenever an event is to be performed or a payment is to be made by a particular date and the date in question falls on a day that is not a Business Day, the event shall be performed or the payment shall be made on the next succeeding Business Day; the term “week” shall mean a seven consecutive day period; the term “month” shall mean a calendar month; provided, that when a period measured in months commences on a date other than the first day of a month, the period shall run from the date on which it starts to the corresponding date in the next month and, as appropriate, to succeeding months thereafter; and the term “year” shall mean a Calendar Year; and

(i)All monetary references contained herein refer to U.S. dollars.

1.3. Accounting Terms

All accounting terms used herein shall be construed in accordance with GAAP unless the context or use requires a different interpretation.

1.4. Legal Representation

This Agreement was negotiated and prepared by both Parties with the advice of counsel to the extent deemed necessary by each Party; the Parties have agreed to the wording of this Agreement; and none of the provisions hereof shall be construed against one Party on the ground that such Party is the author or drafter of this Agreement or any part hereof.

ARTICLE II: PURCHASE OF CAPACITY, ENERGY,

ANCILLARY SERVICES, AND ENVIRONMENTAL ATTRIBUTES

2.1. Capacity Sale and Purchase

Subject to the terms and conditions of this Agreement, Seller agrees to sell and supply to Buyer, and Buyer agrees to accept and purchase from Seller, in each month during the Delivery Period the sum of the product of Buyer’s Product Share multiplied by the Capacity of Unit 1 applicable to such month as determined by MISO (in connection with the definition of Accredited Capacity) plus (b) the product of Buyer’s Product Share multiplied by the Capacity of Unit 2 applicable to such month as determined by MISO (in connection with the definition of Accredited Capacity).

Furthermore, except as otherwise specifically provided for herein, Seller shall not sell or commit to sell Buyer’s Product Share of the Capacity of the respective Facilities during the Term to any party other than Buyer.

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2.2. Energy Sale and Purchase

(a)Subject to the terms and conditions of this Agreement, for the duration of the Term, Seller shall sell and deliver to Buyer at the Delivery Point, and Buyer shall accept and purchase, an amount of Energy equal to the sum of (i) Net Energy Output – Unit 1 multiplied by Buyer’s Product Share, (ii) Net Energy Output – Unit 2 multiplied by Buyer’s Product Share, and (iii) all Replacement Energy that Seller delivers to Buyer pursuant to the terms of this Agreement. The amount of all Energy sold to Buyer as Scheduled by Seller and purchased by Buyer from Seller as confirmed by Buyer in accordance with Exhibit H, for any period of time, shall be the aggregate amount of Delivered Energy for such period of time. Furthermore, except as otherwise specifically provided for herein, Seller shall not sell or commit to sell the Buyer’s Product Share of Energy produced by the Facilities during the Term to any party other than Buyer.

(b)The Parties acknowledge and agree that any increases in Capacity, Energy, Ancillary Services, or Environmental Attributes from the Facilities, whether due to changes in ambient conditions or otherwise (other than that attributable to Uprates not accepted by Buyer in accordance with the Existing PPA or Section 2.9(a) or (b)), are included in the Products.

2.3. Ancillary Services and Environmental Attributes

(a)The sale of Capacity and Energy hereunder from the Facilities to Buyer shall include the Ancillary Services and Environmental Attributes associated with such Capacity and Energy from the Facilities. Seller agrees to provide and/or execute any documents or agreements necessary to transfer to Buyer any revenue and any other benefits and rights received from third parties by Seller in providing such Ancillary Services and Environmental Attributes, with the costs of the documentation and related agreements involved in the creation of such Ancillary Services and Environmental Attributes being absorbed by the Seller Contingency Tranche to the extent that funds are available therein, and thereafter paid by Buyer. For all periods during which such documents and agreements are not in effect, Seller agrees to credit to Buyer such revenues as provided in Section 3.1 until such time as an agreement is executed. Further, to the extent permitted by Law, Seller hereby assigns and delegates to Buyer all rights and obligations Seller may have to reach agreement with the Transmission Provider or Transmission Owner, as applicable, as to the appropriate entitlement of revenues for Ancillary Services provided by the Facilities under the applicable MISO Tariff and/or under the Interconnection Agreement, as applicable.

(b)To the extent that Seller’s unexcused failure to deliver Buyer’s Product Share of Ancillary Services to Buyer results in any increased cost, damage or penalty incurred by Buyer, Seller shall reimburse Buyer for any such increased cost, damage or penalty within ten (10) Business Days of invoice receipt therefor. Any invoice submitted by Buyer to Seller pursuant to this Section 2.3(b) shall include a written statement explaining in reasonable detail the calculation of the amount

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owed by Seller. The amount of such cost, damages or penalty to be reimbursed shall not exceed an amount equal to the increased costs or penalties actually incurred by Buyer. Notwithstanding the preceding sentence, in the event that during the Term there exists a market for the purchase and sale of Ancillary Services, then (i) if Seller fails to provide an Ancillary Service required to be delivered hereunder from the Facilities, Seller shall use commercially reasonable efforts to provide Buyer with a replacement for such Ancillary Service and (ii) if Seller is unsuccessful in satisfying its obligation under clause (i), Seller shall reimburse Buyer for the market-clearing price for such undelivered Ancillary Service.

(c)Notwithstanding the foregoing, in no event shall Seller be required to reduce its Net Energy Output for the purpose of providing Ancillary Services to Buyer.

2.4. Replacement Energy

(a)Replacement Energy. Subject to the provisions of this Agreement (including Exhibit J, which provisions are controlling with respect to the matters specifically covered thereby, with the intent of such provisions being to implement and aid in the interpretation of the provisions of this Section 2.4), Seller may provide Buyer with Replacement Energy as set forth below in this Section 2.4(a) during a Scheduled Maintenance Outage or an Unscheduled Outage, but only to the extent of any associated Derate. Seller may provide Replacement Energy from any source.

(i)Unscheduled Outage Replacement Energy Notices

If the event or condition constituting the Derate is an Unscheduled Outage, Seller shall provide, via email, a Replacement Energy Notice (as such term is defined in Exhibit J) of Seller’s election in accordance with Section 2.4(a)(iii) below (to provide or not to provide Replacement Energy) as soon as practicable but no later than the Notice Time on the day following the day the Derate commenced. Seller’s election shall be effective based on a “Weekly Schedule,” which means seven (7) consecutive days beginning at 0000 MISO Market Time on any day of the week following the appropriate Notice Time and ending at 2359 MISO Market Time on the seventh (7th) day. Seller shall provide Buyer notice of its intent to continue or discontinue its Replacement Energy election no later than two (2) Business Days prior to the commencement of the applicable Weekly Schedule.

(ii)Scheduled Maintenance Replacement Energy Notices

If the event or condition constituting the Derate is a Scheduled Maintenance Outage, Seller shall provide via email a Replacement Energy Notice of Seller’s election in accordance with Section 2.4(a)(iii) below to provide or not to provide Replacement Energy no later than two (2) Business Days prior to the scheduled commencement of such Scheduled Maintenance

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Outage. Seller’s election shall be effective based on a Weekly Schedule. Seller shall provide Buyer notice of its intent to continue or discontinue its Replacement Energy election no later than two (2) Business Days prior to the commencement of the applicable Weekly Schedule.

(iii)Replacement Energy Scheduling

Any Replacement Energy Scheduled hereunder shall be Scheduled in accordance with Article IV: , subject to the following: Replacement Energy may only be Scheduled and delivered on a continuous basis in either (A) a single, fixed quantity or (B) a quantity varied to reflect expected changes in the Net Energy Output (e.g., changes in output or ramp rates or expected resolution of outages with respect to the Facilities) such that the aggregate of such Replacement Energy and the Net Energy Output will result in a single, fixed quantity.

(b)Replacement Capacity

(i)No replacement Capacity shall be provided pursuant to this Agreement.

2.5. Financial Transmission Rights

Buyer shall be entitled to all financial transmission rights and all other rights and benefits with and from MISO associated with the Capacity, Energy and Ancillary Services being purchased from the Facilities. To the extent that Seller has the right to such financial transmission rights, Seller shall cooperate in good faith with Buyer to ensure that such financial transmission rights and other rights and benefits are effectively assigned and transferred to Buyer at no additional cost to Buyer. Further, Seller hereby assigns and delegates to Buyer all rights and obligations Seller may have to request auction revenue rights or financial transmission rights under the MISO Tariff in connection with the Product being sold to Buyer hereunder.

2.6. Title and Risk of Loss

Title to and risk of loss related to the Capacity, Energy, Ancillary Services, and Environmental Attributes being purchased hereunder shall transfer from Seller to Buyer at the Delivery Point. Seller warrants that it will deliver to Buyer such Capacity, Energy, Ancillary Services, and Environmental Attributes free and clear of all liens, security interests, claims and encumbrances or any interest therein or thereto by any Person.

2.7. Delivery Point

The “Delivery Point” for Energy (including Replacement Energy) delivered pursuant to this Agreement is the CPNode.

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2.8. Capacity Accreditation

Seller shall take, at its sole cost and expense, all reasonable actions required to cause Buyer’s Product Share of the Capacity to be Accredited Capacity, including the satisfaction of all applicable requirements to establish and maintain the DNR status (as defined under the applicable MISO Tariff and acceptable to the applicable regional reliability council and the Transmission Provider, as applicable), and including Capacity Resource status in relation to Buyer’s Network Load of the Facilities.

2.9. Uprates

(a)With respect to future Uprates, Buyer shall have a right of first offer with respect to the Capacity, Energy, Ancillary Services, and Environmental Attributes related to any such Uprate. Seller shall provide Buyer notice to Buyer as to Buyer’s right to provide Seller with a written offer setting forth the terms upon which Buyer will agree to purchase the Capacity, Energy, Ancillary Services, and Environmental Attributes associated with the portion of such Uprate that will be owned by Seller. No later than one hundred eighty (180) days after Buyer’s receipt of notice from Seller, Buyer may submit such offer to purchase if it desires to acquire the Capacity, Energy, Ancillary Services, and Environmental Attributes associated with the portion of such Uprate. Within thirty (30) days of Seller’s receipt of an offer from Buyer pursuant to this Section 2.9(a), Seller, in its discretion, may choose, whether it wishes to sell all or any portion of such Capacity, Energy, Ancillary Services, and Environmental Attributes of any such Uprate upon such terms as set forth in Buyer’s offer. Should Seller accept Buyer’s offer, the Parties shall, upon the effective date of the Uprate, to the extent required, adjust Buyer’s Capacity Amount to account for the Capacity of such Uprate, as determined pursuant to Performance Tests and otherwise with respect to Section 5.3(d)(ii), and the offered amount with respect to such Uprate that Buyer has agreed to acquire, to take effect, together with any adjustment to pricing terms hereunder based on the pricing for Energy, Ancillary Services, and Environmental Attributes relative to such Uprate, upon the completion of such Uprate. The Energy related to an Uprate shall not be included as Delivered Energy until the transmission upgrades, if any, required for such Uprate have been completed in accordance with the applicable transmission studies performed by ATC and/or MISO, or MISO has otherwise allowed for the generation and delivery of such Energy. In the event that (x) Buyer declines to make an offer with respect to any Capacity, Energy, Ancillary Services, and Environmental Attributes associated with an Uprate as provided above or (y) if Seller declines to accept Buyer’s offer, then Seller shall have the right to sell to any third party the incremental Capacity, Energy, and associated Ancillary Services and Environmental Attributes generated at the Facilities as a direct result of such Uprate not accepted by the Buyer; provided that, in the case of clause (x), such third party sales are at prices no less than, and non-price terms no less economically beneficial to Seller than the prices and non-price terms in Buyer’s offer.

(b)Notwithstanding anything to the contrary in this Agreement, changes to the Buyer’s Capacity Amount resulting from any Uprate shall be conditioned upon the receipt

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of all requisite regulatory approvals, applicable to such Uprate, by the Party to whom such regulatory approvals apply.

2.10. [Reserved]

2.11. Reactive Power

Without limiting the general application of Section 2.2 and Section 2.3:

(a)Seller agrees that it shall not have any rights to the production or absorption, if applicable, of Buyer’s Product Share of Reactive Power and that Seller shall, consistent with the requirements of any Governing Authority, not operate the Facilities to produce real power at a level or in a manner that compromises its ability to operate the Facilities to produce or absorb, if applicable, Reactive Power to maintain the output voltage or power factor at the applicable CPNode in any agreement governing Seller’s obligation to produce or absorb, if applicable, Reactive Power consistent with the Interconnection Agreement.

(b)If requested by MISO, ATC, or the Balancing Authority Function, Seller shall adjust Reactive Power (as so requested), subject to Prudent Utility Practice and current Interconnection Agreement requirements, with the costs thereof being absorbed by the Seller Contingency Tranche to the extent that funds are available therein, and thereafter paid by Buyer. As between the Parties, Buyer shall have the right to receive any compensation paid by any third party for Buyer’s Product Share of Reactive Power (including for any increases in reactive power output or capability of the Facilities after the Effective Date) produced or absorbed by the Facilities. Any disagreement about the amount of such compensation shall be resolved in accordance with the Dispute Resolution Procedures.

2.12. Station Service

During any period in which any Unit is operating, Seller shall be permitted to satisfy the Station Service Load using Energy generated by any such Unit. If Seller is not able to self-supply Energy to satisfy Station Service Load, Seller shall compensate Buyer for the Station Service Load at the MISO Real-Time Market LMP for the appropriate CPNode, including any transmission or settlement charges associated with such Energy, during any period of time in which the Facilities are not operating or are not generating sufficient Energy to meet the Station Service Load of the Facilities. In the event that any fees, damages, penalties or transmission charges are assessed against Buyer (in its capacity as Buyer under this PPA) by any Governing Authority in connection with the Station Service Load or any Energy obtained to serve the Station Service Load, Seller shall reimburse Buyer for such fees, damages, penalties or transmission charges within ten (10) Business Days of invoice receipt therefor. Any invoice submitted by Buyer to Seller pursuant to this Section 2.12 shall include a written statement explaining in reasonable detail the calculation of the amount due from Seller. As of the date of execution of this Agreement, the Station Service Load related to each Unit is calculated as approximately twenty-five

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(25) MW per Unit. In the event such amount is materially changed for any reason, Seller shall give Buyer prompt written notice of such change.

2.13. CT and Solar Field Capacity

For the avoidance of doubt, any Capacity, Accredited Capacity, Energy, Ancillary Services, or Environmental Attributes of the CT or Solar Field, or any other ancillary generation facilities, will be retained by Seller and will not constitute part of the Products to be provided to Buyer hereunder.

ARTICLE III: PAYMENTS

3.1. Purchase Payments

The amounts to be paid to the Seller by the Buyer for purchases of Capacity, Energy, Ancillary Services, and Environmental Attributes under this Agreement shall be determined as follows:

(a)Delivered Energy Payment. With respect to each Billing Cycle, Buyer shall make a payment to Seller equal to the sum of (i) the product of: (A) the applicable “Delivered Energy Charge” set forth in Exhibit A; (B) the applicable Delivered Energy Charge Shaping Factor set forth in Exhibit C; and (C) the sum of the MISO FinSched Energy (On-Peak and Off-Peak, as appropriate) for the Operating Days in such Billing Cycle, and (ii) any Gross Receipts Tax Payment applicable to the invoice for such Billing Cycle (pursuant to Section 20.3(d)) (each, a “Delivered Energy Payment”).

(b)Ancillary Services and Environmental Attributes. The Delivered Energy Payment includes Buyer’s full payment for any and all Ancillary Services and Environmental Attributes received by Buyer hereunder, and no additional payment from Buyer in respect thereof shall be due at any time. For the avoidance of doubt, Seller specifically agrees that it shall not be entitled to any payment for Buyer’s Product Share of Reactive Power under this Agreement, notwithstanding its obligation to operate the Facilities in accordance with Section 2.3 and Section 2.11. Any and all revenues Seller receives from MISO for Buyer’s Product Share of Ancillary Services from the Facilities in each Billing Cycle shall be credited pro rata to Buyer in the same Billing Cycle and offset with any other payments due from Buyer to Seller under this Agreement (unless otherwise directly transferred to Buyer as provided in Section 2.3). Buyer’s pro-rata share of such revenues is equal to the sum of (A) Buyer’s Product Share multiplied by the Ancillary Services revenues associated with Unit 1, and (B) Buyer’s Product Share multiplied by the Ancillary Services revenues associated with Unit 2.

3.2. Peak Adjustment Payment

If applicable, Seller shall make a payment to Buyer as determined in accordance with Exhibit G (each, a “Peak Adjustment Payment”).

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ARTICLE IV: SCHEDULING

4.1. Scheduling

Seller shall submit its Generation Offers and Financial Bilateral Transactions in accordance with applicable MISO rules and procedures. Notwithstanding the foregoing, Seller shall have the option to not Schedule Energy from Unit 1 and/or Unit 2 in the MISO Day-Ahead Market in instances where the applicable Unit(s) is/are being ramped up to return to service following a Scheduled Maintenance Outage or an Unscheduled Outage; provided, however, that Seller shall hold harmless, defend and indemnify Buyer from and against any charges or fees, including Revenue Sufficiency Guarantee charges, levied on Buyer as a result of Seller’s Scheduling in the MISO Real-Time Market up to Buyer’s Product Share thereof. Exhibit H includes other scheduling provisions applicable to this Agreement.

4.2. Failure to Schedule

(a)If Seller fails to Schedule Energy (including Replacement Energy) in accordance with Section 2.4(a) or Section 4.1, as applicable, and such failure is not excused under the terms of this Agreement, then Seller shall pay to Buyer, within five (5) Business Days of receipt of an invoice therefor, an amount equal to the positive difference, if any, of (i) the MISO Day-Ahead Market LMP for such applicable period multiplied by the amount of such Energy that Seller failed to Schedule, plus any charges, penalties, damages, fees and other costs, including MISO charges, incurred by Buyer resulting from such failure minus (ii) the amount of the Delivered Energy Payment related to such Energy that Seller failed to Schedule and that Buyer would have incurred under this Agreement had such Energy been Scheduled. Any invoice submitted by Buyer to Seller pursuant to this Section 4.2(a) shall include a written statement explaining in reasonable detail the calculation of the amount due from Seller.

(b)If Buyer fails to Schedule Energy (including Replacement Energy) that is Scheduled by Seller in accordance with Exhibit H (i.e., if Buyer fails, notwithstanding the “Seller AutoApproval” setting, to provide any required confirmation of MISO FinScheds for any portion of the Product properly submitted by Seller) and such failure is not excused under the terms of this Agreement, then Buyer shall pay to Seller, within five (5) Business Days of receipt of an invoice therefor, an amount equal to the positive difference, if any, of (i) the amount of the Delivered Energy Payment related to amount of such Energy that Buyer failed to Schedule and that Seller would have received under this Agreement had such Energy been Scheduled by Buyer, plus any charges, penalties, damages, fees and other costs, including MISO charges, incurred by Seller resulting from such failure, minus (ii) the MISO Day-Ahead Market LMP for such applicable period multiplied by such Energy that Buyer failed to Schedule. Any invoice submitted by Seller to Buyer pursuant to this Section 4.2(b) shall include a written statement explaining in reasonable detail the calculation of the amount due from Buyer.

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ARTICLE V: MAINTENANCE AND OPERATION

5.1. Scheduled Maintenance

(a)Scheduling Procedure.

Subject to Section 5.1(b) below, Seller shall submit to Buyer a schedule of maintenance of the Facilities (each, a “Maintenance Schedule” and each item thereon a “Scheduled Maintenance Outage”) for each Calendar Year and a projection of scheduled outages for the following four (4) years thereafter no later than twelve (12) months before the beginning of any year (or not later than three (3) months prior to the deadline for submittal of any such schedule to MISO or any other applicable Governing Authority, if earlier), except that within thirty (30) days following the Effective Date, Seller shall submit to Buyer a Maintenance Schedule for the remainder of the Calendar Year in which the Effective Date occurs and for the following Calendar Year. Each Maintenance Schedule shall meet the requirements set forth in Section 5.1.

Within thirty (30) days of receipt of such Maintenance Schedule, Buyer may request reasonable modifications therein to the extent the requested modifications are not contrary to Prudent Utility Practice. Subject to Section 5.1(b) below, Buyer and Seller shall work together to schedule Scheduled Maintenance Outages to meet their mutual requirements and the requirements of MISO and/or Transmission Owner, it being understood that Buyer shall consider, among other things, its reserve requirements, energy delivery commitments, costs of replacement power and other generating resources and expected loads in requesting such reasonable modifications; provided, that in the event of a disagreement, such scheduling shall be resolved by the Administrative Committee. All Scheduled Maintenance Outages shall be of a duration that is no longer than that reasonably necessary to carry out the required maintenance activities. Seller shall provide notice to Buyer as soon as practicable but in any event no later than forty-eight (48) hours prior to the expected cessation of maintenance activities and shall promptly inform Buyer of the completion of such activities.

Scheduled Maintenance Outages for the subsequent three- (3-) year period of the Maintenance Schedule may only be rescheduled within a period of time from thirty (30) days prior to the projected start of such Scheduled Maintenance Outage to thirty (30) days after the projected end of such Scheduled Maintenance Outage; provided, however, that no Scheduled Maintenance Outage in such subsequent three-(3) year period may be rescheduled so that all or any portion of such Scheduled Maintenance Outage falls within a different Calendar Year; and provided, further, that if Seller experiences an extended Unscheduled Outage and desires to move a Scheduled Maintenance Outage into a prior or subsequent Calendar Year, any such rescheduling shall require the consent of Buyer, not to be unreasonably withheld.

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(b)Limitations on Scheduled Maintenance Outages

Scheduled Maintenance Outages may not occur during the Peak Period.

5.2. Derate Notices

In the event of any Derate, Seller must notify the Dispatch Authority Function and the Balancing Authority Function telephonically of such Derate as soon as practicable after Seller becomes aware of the necessity or occurrence thereof (each, a “Derate Notice”), with written confirmation within twenty-four (24) hours of such oral notice. During any ongoing Derate, Seller shall provide updated information to the Dispatch Authority Function and the Balancing Authority Function to the extent required or requested by the Dispatch Authority Function or Balancing Authority Function. During any ongoing Derate, Seller shall provide updates as often as practicable, but no less than daily, to Buyer of the nature and expected duration of such Derate as well as the magnitude and timing of actual and expected output changes of the Facilities and such other information as may assist Buyer in assessing the reliability and expected quantity of output from the Facilities, and Seller shall provide Buyer with oral notice (confirmed promptly by email) as much prior notice as practicable of when the Derate is expected to be remedied.

5.3. Operation

(a)Operation

Seller shall manage, control, operate and maintain all parts of the Facilities in a manner consistent with Prudent Utility Practice, the terms and conditions of this Agreement and the Interconnection Agreement. As between the Parties, Seller shall bear the sole responsibility for complying with all applicable Laws associated with operating the Facilities, including all environmental, permitting and zoning requirements in effect during the Term of this Agreement.

(b)Communications Protocol

(i)Seller and Buyer have developed written communications procedures for the Facilities (the “Communications Protocol”), which include processes related to Seller’s interface with MISO, ATC, ERO, Balancing Authority, and Governing Authorities, operating communications between Seller and Buyer, and testing procedures. The Communications Protocol is deemed incorporated herein by this reference.

(ii)The Communications Protocol shall be reviewed by the Administrative Committee at any time requested by a Party and any mutually agreed changes shall be made. In the event the Parties are unable to agree upon any changes to the Communications Protocol, such disagreement shall be resolved in accordance with the Dispute Resolution Procedures.

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(c)Authorizations

Seller shall, at its own expense, acquire and maintain, comply with and, as necessary, renew and modify from time to time, any and all permits, licenses, approvals and other Authorizations of any Governing Authority required for the lawful operation and maintenance of the Facilities. Copies of said Authorizations shall be made available to Buyer for review upon Buyer’s written request. Buyer shall not be liable for any violation by Seller of any Authorization required to be obtained by Seller pursuant to this Section 5.3(c).

(d)Testing

(i)Notice of Testing

Seller shall notify Buyer in writing at least thirty (30) days prior to the expected date of any Performance Test (as described and defined in Section 5.3(d)(ii) below) or any other testing of the net capability of the Facilities (including for any Uprate); provided, that Seller may postpone any such test until such test is able to be performed with prior written notice to Buyer of such postponement and of the date and time such test is actually to be performed. Buyer may have a representative present at the time of each such test so long as the above required notices were given, although the failure to have such a representative present shall not invalidate the result of the applicable test.

(ii)Performance Tests

Seller shall perform (A) a performance test each year, on a date mutually agreed by the Parties, at Seller’s expense, which shall measure the net capability of the Facilities (including any Uprate) and (B) a performance test as soon as practicable, consistent with the MISO Business Practice Manual, (I) prior to the outage during which an Uprate is performed but prior to any coastdown and (II) following start-up from an outage during which an Uprate is performed, in each case in accordance with the procedures set forth in Exhibit K (each, a “Performance Test”). In addition to the required Performance Test, either Party may request a Performance Test at any reasonable time, at the expense of the Party requesting such test. All Performance Tests shall be conducted in accordance with testing procedures (x) to confirm the Accredited Capacity constituting Buyer’s Capacity Amount (pursuant to Transmission Provider requirements) or (y) as otherwise mutually agreed by the Parties. For the avoidance of doubt, as of the execution of this Agreement the current Performance Test standards are the MISO Business Practice Manual.

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(e)Other Operations Obligations

(i)Information Requirements

Seller shall provide Buyer with the following real-time telemetered data (scanned no less frequently than once every four seconds) for the duration of the Term: (A) net Unit output (MW and VARs), (B) status (i.e., open or closed) of generator breakers and generator disconnect switches, and (C) MW and VARs at each metering point. Seller shall provide Buyer with copies of any scheduling notices or requests submitted to MISO concurrently with the submission thereof. In addition, Seller shall provide Buyer with any other information Buyer may reasonably request regarding the operation of Unit 1 and Unit 2.

(ii)SCADA Data

Seller shall provide and make available to Buyer, on a real-time basis, all data generated by the SCADA system at the Facilities, including all four-second meter data.

(iii)Quality of Energy

All Energy delivered hereunder shall be three-phase, sixty (60) Hertz (plus or minus variations as may be required or allowed by MISO), alternating current, at a voltage acceptable to the MISO, or shall otherwise comply with such other specifications of MISO, regional reliability council or other authority responsible for the safety and reliability of the electric grid with authority over the Delivery Point as may be in effect at the time of delivery.

(iv)Buyer’s Right of Access to Facilities

Seller shall provide Buyer with the right to enter Seller’s premises at the Facilities during normal business hours to (i) review records maintained pursuant to this Agreement, (ii) obtain information regarding operation of the Facilities, (iii) visually inspect the Facilities, (iv) observe the testing, operation and maintenance of the Facilities and (v) undertake any other activities reasonably necessary for Buyer to fulfill its rights and obligations hereunder. Buyer shall provide prior written notice to Seller of the date and time of such proposed entry and the identity of all Persons conducting such entry, which prior written notice shall in no event be provided less than three (3) Business Days prior to the date of such entry. Seller shall schedule Buyer’s entries upon Seller’s premises at the Facilities so as to minimize any disruption of the operation of the Facilities due to such entries or to any activities carried out by Buyer at the Facilities during any such entry. Each such Person conducting any such entry shall observe and comply with all of Seller’s applicable safety and security rules at all times during such entry, as such rules shall have been presented to such Person by Seller or by any operator on behalf of Seller prior to or at the time of such visit.

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(v)Maintenance of Books and Records

Seller shall maintain at the Facilities site for a period of not less than five (5) years from the date of preparation thereof: (i) all measurements by Metering Devices of Energy delivered from the Facilities pursuant to this Agreement; (ii) all data and information necessary to calculate payments as provided in this Agreement, including invoices, receipts, charts, printouts, electronic media, magnetic tapes and other materials and documents; and (iii) an accurate and up-to-date operating log at the Facilities with records of: real and reactive power production from the Facilities for each hour, changes in operating status of the Facilities and scheduled outages of the Facilities. Buyer shall be permitted to inspect such operating log upon prior written request during normal business hours and copies of such log shall be provided, if requested, at Buyer’s expense, within ten (10) days of such request.

(vi)Interconnection

As between the Parties, Seller shall be responsible to maintain and operate Seller’s electric interconnection facilities in accordance with the Interconnection Agreement. Seller shall not permit any action or inaction under the Interconnection Agreement that could adversely affect Buyer’s rights, benefits, liability or obligations under this Agreement and shall not consent to (unless required by a Governing Authority) any modification of the Interconnection Agreement that would adversely affect Buyer’s rights hereunder without Buyer’s prior written consent, such consent not to be unreasonably withheld. Furthermore, subject to any prohibitions of a Governing Authority, Seller shall:

(A)promptly advise Buyer of all communications and notices to be made by or to Seller under the Interconnection Agreement; and

(B)use commercially reasonable efforts to ensure that the Transmission Owner’s and/or MISO’s planned maintenance schedules for the transmission system are coordinated with the Scheduled Maintenance Outages for the Facilities.

ARTICLE VI: METERING

6.1. Metering

(a)The electric watt-hour meters and any other Energy measuring devices and equipment used for purposes of this Agreement (“Metering Devices”), shall at all times during the Term meet the requirements set by MISO and all applicable Governing Authorities and as set forth in the Interconnection Agreement. Seller shall own, operate, maintain and replace Metering Devices, including those Metering Devices shown on Exhibit D, sufficient to permit an accurate determination of the quantity and time of delivery of Energy delivered to the

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Delivery Point. Seller’s Metering Devices shall be used for measurements under this Agreement. Seller shall calibrate the Metering Devices in accordance with Prudent Utility Practice, but no less than once during each refueling outage on the Maintenance Schedule. Buyer or Buyer’s representative shall have the right to be present during any calibration of the Metering Devices and Seller shall provide reasonable notice to Buyer of any such calibration.

(b)The Buyer shall have the right to inspect and require a test of the Metering Devices (to be performed by Seller) from time to time at its discretion, and any inaccuracy disclosed by such tests shall be promptly corrected. If errors greater than one-half of one percent (0.5%) are discovered, the test shall be at Seller’s expense. Upon reasonable notice, Seller shall provide the Buyer access to the Metering Devices at Buyer’s expense during normal business hours and from time to time for the purposes of reading, inspecting and witnessing any testing of such equipment.

(c)If any Metering Device used to determine the amount of Delivered Energy is found to be in error by more than three quarters of one percent (0.75%), the payments for Delivered Energy made since the previous test of such Metering Device shall be adjusted to reflect the corrected measurements determined pursuant to this Article VI. The amount of such adjustment payment shall be equal to the total adjustment that would be due if the inaccurate Metering Device were deemed to be equally inaccurate during the entire period since the previous test of such Metering Device, divided by two (2); provided, however, that if the period of inaccuracy can be ascertained, then the Parties shall adjust the payments for Delivered Energy for that ascertained period of inaccuracy. Any amount payable as a result of such correction shall be paid to the Party entitled to such payment within thirty (30) days of notice of such correction.

ARTICLE VII: BILLING AND PAYMENT

7.1. Billing and Payment

(a)Seller shall send a billing statement to Buyer on or before the tenth (10th) day after the end of each Billing Cycle. If any net amount is due to Seller with respect to any such billing statement, Buyer shall pay such amount to Seller within ten (10) days after receipt of such billing statement. If any net amount is due to Buyer with respect to any such billing statement, Seller shall pay such amount to Buyer on or before the fifteenth (15th) day after the end of such Billing Cycle. The billing statement shall show (i) the megawatt-hours of Delivered Energy for such Billing Cycle as Scheduled by the Seller and confirmed by the Buyer pursuant to Exhibit H; (ii) the amounts due to Seller for that Billing Cycle in respect of (A) the Delivered Energy Payment, and (B) any other amounts due to Seller hereunder; (iii) the amounts due Buyer for that Billing Cycle in respect of (x) the Peak Adjustment Payment, if applicable, (unless Buyer makes the election provided for in Exhibit G) and (y) any other amounts due to Buyer hereunder; and (iv) the data reasonably pertinent to the calculation of the payments due to Seller or Buyer. Any amounts due and payable and not paid by the due date will be deemed delinquent and will

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accrue interest at the Prime Rate, such interest to be calculated from and including the due date to but excluding the date the delinquent amount is paid in full.

(b)In the event of a dispute as to the amount of any bill, the disputing Party shall notify the other Party of the amount in dispute and Buyer or Seller, as applicable, shall pay to the other Party the undisputed portion of the bill on or prior to the due date therefor, as identified in Section 7.1(a). Buyer or Seller, as applicable, shall pay, with an interest charge computed at the Prime Rate, from and including the date payment was due to but excluding the date payment is made, any portion of the disputed amount ultimately found to be proper. In the event of a refund, Buyer or Seller, as applicable, shall pay, with an interest charge computed at the Prime Rate, from and including the date the disputed payment was made to but excluding the date the refund payment is made, any refund amount ultimately found to be due to the other Party.

(c)Neither the Buyer nor Seller shall have the right to challenge any billing statement rendered or received hereunder after a period of the longer of (A) two (2) years from the date such statement was rendered or (B) ten (10) days after the last MISO settlement statement for the last Operating Day included in the billing statement. In the event that any such billing statement depends in whole or in part upon estimated data, this two- (2-) year limitation period shall be deemed to begin on the first day of the Billing Cycle in which such estimated data is adjusted to actual.

(d)Each Party reserves to itself all rights, setoffs, counterclaims, recoupment, combination of accounts, liens and other remedies, rights and defenses which such Party has or may be entitled to (whether by operation of law or in equity, under contract or otherwise). The obligations of each Party to make payments under this Agreement may be offset against each other, setoff or recouped therefrom.

ARTICLE VIII: PERFORMANCE SECURITY

8.1. Seller Performance Security

If at any time from the Unit 1 Commencement Date forward Seller (or Seller’s Guarantor) has Insufficient Credit Status, Seller shall deliver to Buyer within two (2) Business Days following the commencement of such Insufficient Credit Status either (a) a Letter of Credit; (b) a guaranty from a Seller’s Guarantor (substantially in the form attached hereto as Exhibit E-1, the “Seller’s Guaranty”) (so long as such Insufficient Credit Status is not with respect to such Seller’s Guarantor) or (c) other collateral in form and substance reasonably acceptable to Buyer, in each case in an amount equal to one hundred million dollars ($100,000,000), which amount shall reduce ratably beginning on January 1, 2031 and on January 1st of each year thereafter until the end of the Term. Costs of a Letter of Credit posted hereunder shall be borne by the applicant for such Letter of Credit.

8.2. Buyer Performance Security

If at any time from the Unit 1 Commencement Date forward Buyer (or Buyer’s Guarantor) has Insufficient Credit Status, Buyer shall deliver to Seller within two (2) Business Days

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following the commencement of such Insufficient Credit Status either (a) a Letter of Credit; (b) a guaranty from a Buyer’s Guarantor (substantially in the form attached hereto as Exhibit E-2, the “Buyer’s Guaranty”) (so long as such Insufficient Credit Status is not with respect to such Buyer’s Guarantor) or (c) other collateral in form and substance reasonably acceptable to Seller, in each case in the same amount as the initial Seller Performance Security amount. Costs of a Letter of Credit posted hereunder shall be borne by the applicant for such Letter of Credit.

8.3. Draws; Replenishments; Return

A Non-Defaulting Party may draw upon the Buyer Performance Security or the Seller Performance Security, as applicable, following the occurrence of an Event of Default by such other Party or pursuant to the other provisions of this Agreement in order to recover any damages to which such Non-Defaulting Party is entitled under this Agreement. In the event of such a draw on the Buyer Performance Security or the Seller Performance Security, as applicable, then, except in the circumstances when the Non-Defaulting Party establishes an Early Termination Date pursuant to Section 10.2 or this Agreement otherwise terminates, the Defaulting Party shall within two (2) Business Days replenish the Seller Performance Security (if the Defaulting Party is Seller) or the Buyer Performance Security (if the Defaulting Party is Buyer), as applicable, to the full amount required by Section 8.1 or 8.2, as applicable. The foregoing obligations to replenish the Seller Performance Security and the Buyer Performance Security shall expire with respect to the Performance Security in question once there have been three (3) such instances of replenishment of the Performance Security in question. Buyer’s or Seller’s obligation to maintain the Performance Security shall terminate, and Buyer or Seller, as applicable, shall return promptly such Performance Security upon the occurrence of the following: (i) the Term of the Agreement has ended; and (ii) all payment obligations of Buyer or Seller, as applicable, arising under this Agreement, including any indemnification payments or other damages arising out of an Event of Default are paid in full (whether directly or indirectly such as through set-off or netting).

8.4. Reporting

(a)Seller shall promptly notify Buyer of any Insufficient Credit Status relating to Seller or to Seller’s Guarantor or any circumstance that results in Seller’s failure to be in compliance with the Seller Performance Security requirements of this Article VIII: . From time to time, at Buyer’s written request, Seller shall provide Buyer promptly with such evidence as Buyer may reasonably request that any Seller Performance Security is in full compliance with this Agreement.

(b)Buyer shall promptly notify Seller of any Insufficient Credit Status relating to Buyer or any circumstance that results in Buyer’s failure to be in compliance with the Buyer Performance Security requirements of this ARTICLE VIII. From time to time, at Seller’s written request, Buyer shall provide Seller promptly with such evidence as Seller may reasonably request that Buyer and any Buyer Performance Security is in full compliance with this Agreement.

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ARTICLE IX: FORCE MAJEURE

9.1. Conditions of Excuse for Seller

If, as a result of an event of Force Majeure, Seller is rendered wholly or partly unable to perform its obligations under this Agreement, Seller shall be excused except as specifically provided elsewhere in this Agreement, from only that portion of its performance that is prevented by such Force Majeure event to the extent so prevented; provided, that:

(a)Seller gives Buyer prompt written notice and in any event within twenty-four (24) hours or as soon as reasonably practicable after the day that Seller obtains actual knowledge thereof, describing the particulars of the event of, and how such event qualifies as a Force Majeure, provided that the failure to provide such notice, or any deficiency in such notice, shall not affect Seller’s ability to claim excuse unless such failure has actually resulted in prejudice to Buyer;

(b)the permitted suspension of performance is of no greater scope and of no longer duration than is required by the event of Force Majeure and the effects thereof; and

(c)Seller exercises its commercially reasonable efforts to eliminate or mitigate the effects of the Force Majeure condition (except that resolution of strikes or other labor disputes shall be at Seller’s discretion).

9.2. Conditions of Excuse for Buyer

If, as a result of an event of Force Majeure, Buyer is rendered wholly or partly unable to perform its obligations under this Agreement, Buyer shall be excused except as specifically provided elsewhere in this Agreement, from only that portion of its performance that is prevented by such Force Majeure event to the extent so prevented; provided that:

(a)Buyer gives Seller prompt written notice within twenty-four (24) hours or as soon as reasonably practicable after the day that Buyer obtains actual knowledge thereof describing the particulars of the event of, and how such event qualifies as a Force Majeure, provided that the failure to provide such notice, or any deficiency in such notice, shall not affect Buyer’s ability to claim excuse unless such failure has actually resulted in prejudice to Seller;

(b)the permitted suspension of performance is of no greater scope and of no longer duration than is required by the event of Force Majeure and the effects thereof; and

(c)Buyer exercises its commercially reasonable efforts to eliminate or mitigate the effects of the Force Majeure condition (except that resolution of strikes or other labor disputes shall be at Buyer’s discretion).

9.3. Burden of Proof

The burden of proof as to whether a Force Majeure has occurred shall be upon the Party claiming Force Majeure.

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9.4. Payment and Security Obligations Not Excused

Notwithstanding anything in this Agreement to the contrary, no payment obligation arising under this Agreement and no obligation to provide a Buyer Performance Security or a Seller Performance Security, as applicable, shall be excused by such event of Force Majeure.

9.5. Time Limits

(a)If at any time during the period of Force Majeure the non-performing Party fails to undertake or ceases undertaking its commercially reasonable efforts to remedy its inability to perform, then the non-performing Party shall no longer be excused from its performance.

(b)Seller shall, within sixty (60) days of the occurrence of a Force Majeure affecting Seller’s performance under this Agreement that Seller reasonably anticipates will last more than twelve (12) months after the commencement thereof, deliver to Buyer a detailed plan for the remedy of the Force Majeure condition, which plan shall include a detailed specification of Seller’s proposal (including a timetable) to remedy the Force Majeure condition and restore the Facilities to maximum attainable operating status.

(c)Notwithstanding anything to the contrary in this Agreement, if, as a result of an event of Force Majeure, Buyer is rendered wholly or partly unable to perform its obligations under this Agreement, Seller may offer and sell the Products to any third party until such time as the Buyer can resume performance under this Agreement.

9.6. Deadline Extended

Whenever either Party is required to commence or complete any action within a specified period, the performance of which action is excused under the terms of this Agreement by reasons of an event of Force Majeure, such period shall be extended by an amount equal to the duration of the period such performance was excused by such event of Force Majeure occurring or continuing during such period; provided, however, that the Term shall not be extended.

ARTICLE X: EVENTS OF DEFAULT; REMEDIES

10.1. List of Events of Default

Each of the following events, unless and to the extent expressly excused under the terms of this Agreement, shall constitute an “Event of Default” of the defaulting party (“Defaulting Party”), the other Party being the non-defaulting party (“Non-Defaulting Party”):

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(a)The failure of a Party to make any undisputed payment due hereunder and such failure shall continue for five (5) Business Days after written notice demanding such payment is received.

(b)Any representation or warranty made by a Party herein or in any certificate or other document delivered by such Party pursuant hereto was false or misleading in any material respect when made, unless such false or misleading representation or warranty is capable of being cured or remedied and (i) the representation and warranty is contained in Sections 11.1(a) and 11.2(a) hereof and such Party shall promptly commence and diligently pursue action to cause such representation and warranty to become true in all material respects within two (2) Business Days or (ii) as to any other representation or warranty such Party shall promptly commence and diligently pursue action to cause such representation or warranty to become true in all material respects and does so within thirty (30) days after notice thereof has been given to such Party by the other Party.

(c)In the event a Party (or, during any period in which a Seller’s Guaranty is in effect, Seller’s Guarantor; or during any period in which a Buyer’s Guaranty is in effect, Buyer’s Guarantor) shall cease doing business as a going concern; shall generally not pay its debts as they become due or admit in writing its inability to pay its debts as they become due; shall file a voluntary petition in bankruptcy or shall be adjudicated as bankrupt or insolvent; shall file any petition or answer seeking any reorganization, arrangement, composition, readjustment, liquidation, dissolution or similar relief under the present or any future federal bankruptcy code or any other present or future applicable Law; shall seek or consent to or acquiesce in the appointment of any trustee, receiver, custodian or liquidator of such Party or of all or any substantial part of its properties; shall make an assignment for the benefit of creditors; or shall take any corporate action to authorize or that is in contemplation of the actions set forth above in this Section 10.1(c).

(d)In the event that within thirty (30) days after the commencement of any proceeding against a Party (or, during any period in which a Seller’s Guaranty is in effect, Seller’s Guarantor; or during any period in which a Buyer’s Guaranty is in effect, Buyer’s Guarantor) seeking any reorganization, arrangement, composition, readjustment, liquidation, dissolution or similar relief under the present or any future federal bankruptcy code or any other statute or Law, such proceeding shall not have been dismissed, or if, within thirty (30) days after the appointment without the consent or acquiescence of such Party of any trustee, receiver, custodian or liquidator of such Party or of all or any substantial part of its properties, such appointment shall not have been vacated or stayed on appeal or otherwise, or if, within thirty (30) days after the expiration of any such stay, such appointment shall not have been vacated.

(e)A Party fails to comply or cause compliance with the Seller Performance Security or Buyer Performance Security, as applicable, requirements of Article VIII: , or Buyer’s Guarantor, if any, or Seller’s Guarantor, if any, breaches any of its obligations under the Buyer’s Guaranty or Seller’s Guaranty, as applicable, or if

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any representation or warranty made by Buyer’s Guarantor or Seller’s Guarantor, as applicable, in the Buyer’s Guaranty or Seller’s Guaranty, as applicable, shall prove to be incorrect in any material respect when made, unless any of the foregoing is cured by the end of the second (2nd) Business Day following receipt of a written notice from the other Party of a failure under this Section 10.1(e).

(f)The failure of Seller to provide Buyer’s employees, agents and other representatives reasonable access to witness testing of or to examine the Metering Devices after receiving notice to do so by Buyer as required under this Agreement, if such failure is not remedied (by re-testing) within ten (10) Business Days following receipt of a written notice by Buyer of such failure, subject to the Facilities being available for generating purposes at such time.

(g)Seller, or any of its employees, contractors, subcontractors, agents or representatives, willfully adjusts the Metering Devices or the interconnection facilities without Buyer’s written consent where such adjustment is intended to have the effect of falsely increasing the amounts owed by Buyer under this Agreement (it being agreed and understood that in any event, Seller shall correct the adjustment and compensate Buyer for the damages arising from such breach within ten (10) Business Days after notice is received by Seller).

(h)A Party violates the requirements of Article XVIII: through an attempted or purported assignment or transfer of this Agreement or an ownership interest in the Facilities or through a Change in Control.

(i)A material default in performance or observance of any agreement, undertaking, covenant or other obligation (other than as specified in the other provisions of this Section 10.1) contained in this Agreement by a Party unless, within thirty (30) days after written notice from the other Party specifying the nature of such material default, such Party cures such default or, if such cure cannot reasonably be completed within thirty (30) days and if such Party within such thirty (30) day period commences, and thereafter diligently and continuously proceeds to cure such default, said period shall be extended for such further period as shall be necessary for such Party diligently and continuously to cure such default, provided that the extended cure period shall not exceed ninety (90) days from the date of the original notice.

10.2. Remedies

If an Event of Default occurs at any time during the Term, the Non-Defaulting Party may, for so long as the Event of Default is continuing, subject to the provisions of Article XIX: , take one or more of the following actions: (i) establish a date (which date shall be no more than ten (10) Business Days after the Non-Defaulting Party delivers written notice of such date to the Defaulting Party) on which this Agreement shall terminate (the “Early Termination Date”), (ii) proceed by appropriate proceedings in accordance with this Agreement at Law, in equity or otherwise, to protect and enforce its right to damages (actual or liquidated) or, where the Event of Default is one other than the failure to pay

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money, equitable relief, including specific performance, and (iii) immediately cease performance or withhold any payments, or both, due in respect of this Agreement. For avoidance of doubt, in the event the Non-Defaulting Party ceases performance or withholds payment as provided in (iii) above, the Defaulting Party shall continue to be obligated to pay damages relating to the Defaulting Party’s failure to perform during such cessation or period of withholding. Notwithstanding anything to the contrary in this Agreement, if an Event of Default under Section 10.1(a) with respect to Buyer has occurred and is continuing, Seller may offer and sell Energy, Ancillary Services, and Environmental Attributes from the Facilities to any third party until such time as the Buyer can resume performance under this Agreement. The proceeds of any such sale shall be applied as an offset to amounts otherwise owed by Buyer to Seller under this Agreement.

10.3. Rights of Specific Performance

In the case of an Event of Default, the Parties recognize that any remedy at law may be inadequate because this Agreement is unique and/or because the actual damages of the Non-Defaulting Party may be difficult to reasonably ascertain and/or may exceed the amount of any guaranty or other collateral available to the Non-Defaulting Party. Therefore, the Parties agree that the Non-Defaulting Party shall be entitled to pursue an action for specific performance, and the Defaulting Party waives all of its rights to assert as a defense to such action that the Non-Defaulting Party’s remedy at law is adequate.

10.4. Limitation of Liability

THE PARTIES CONFIRM THAT THE EXPRESS REMEDIES AND MEASURES OF DAMAGES PROVIDED IN THIS AGREEMENT SATISFY THE ESSENTIAL PURPOSES HEREOF FOR BREACH OF ANY PROVISION FOR WHICH AN EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED. UNLESS EXPRESSLY HEREIN OTHERWISE PROVIDED, AND EXCEPT FOR (AND SPECIFICALLY LIMITED TO THE EXTENT OF) THE PAYMENT OF LIQUIDATED DAMAGES SPECIFIED HEREIN, NEITHER PARTY NOR THEIR AFFILIATES SHALL BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY OR INDIRECT DAMAGES, LOST PROFITS (WHICH DOES NOT INCLUDE RECOVERY FOR ACCRUED DELIVERED ENERGY PAYMENTS) OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR CONTRACT; PROVIDED, HOWEVER, THAT THIS SENTENCE SHALL NOT APPLY (A) TO LIMIT THE LIABILITY OF A PARTY WHOSE ACTIONS GIVING RISE TO SUCH LIABILITY CONSTITUTE WILLFUL MISCONDUCT OR (B) TO ANY INDEMNITY OBLIGATION PROVIDED HEREIN. TO THE EXTENT ANY DAMAGES REQUIRED TO BE PAID HEREUNDER ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE THAT THE ACTUAL DAMAGES ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, OTHERWISE OBTAINING AN ADEQUATE REMEDY IS INCONVENIENT, AND THE LIQUIDATED DAMAGES DO NOT CONSTITUTE A PENALTY AND ARE A REASONABLE ADVANCE APPROXIMATION OF THE HARM OR LOSS. THE PARTIES FURTHER EXPRESSLY AGREE THAT NEITHER SHALL HAVE THE RIGHT, AND EACH WAIVES ALL RIGHTS, TO BRING AN ACTION AGAINST THE OTHER

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(INCLUDING ANY AFFILIATE OF THE OTHER) IN TORT OR STRICT LIABILITY FOR ANY ACT(S) OR OMISSIONS CONSTITUTING A BREACH OR ALLEGED BREACH OF CONTRACT.

10.5. Disclaimer of Warranties

NEITHER PARTY TO THIS AGREEMENT MAKES ANY REPRESENTATION, WARRANTY OR INDEMNITY, EXPRESS OR IMPLIED, TO THE OTHER PARTY TO THIS AGREEMENT EXCEPT FOR THE REPRESENTATIONS, WARRANTIES AND INDEMNITIES EXPRESSLY SET FORTH IN THIS AGREEMENT.

ARTICLE XI: REPRESENTATIONS, WARRANTIES AND COVENANTS

11.1. Representations and Warranties of Buyer

Buyer makes the following representations and warranties to Seller, each of which is true and correct as of the Effective Date and representations and warranties (a)-(f) shall also be true and correct as of the Execution Date:

(a)Buyer is a corporation duly organized, validly existing, and in good standing under the Laws of the State of Wisconsin.

(b)Buyer possesses all requisite power and authority to enter into and perform this Agreement and to carry out the transactions contemplated herein. Buyer has all legal power and authority to own and use its properties and to transact the business in which it engages or proposes to engage and holds or will obtain on or before the time required all Authorizations necessary and required therefor.

(c)Except with respect to the Buyer Approval, Buyer’s execution, delivery and performance of this Agreement have been duly authorized by, or are in accordance with, its articles of incorporation and by-laws; this Agreement has been duly executed and delivered for it by the signatories so authorized; and this Agreement constitutes Buyer’s legal, valid and binding obligation, enforceable against it in accordance with the terms hereof, except as such enforceability may be limited by applicable bankruptcy laws from time to time in effect that affect creditors’ rights generally or by general principles of equity (regardless of whether such enforcement is considered in equity or at law).

(d)Except with respect to the Buyer Approval and the PSCW Approval, Buyer’s execution, delivery and performance of this Agreement (i) will not result in a breach or violation of, or constitute a default under, or conflict with any material Authorization, or any material contract, lease or other agreement or instrument to which it is a party, or by which it or its properties may be bound or affected; and (ii) does not require any Authorization, or the consent, authorization or notification of any other Person, or any other action by or with respect to any other Person (except for Authorizations and consents or authorizations of other Persons already obtained, notifications already delivered, or other actions already taken or necessary or required Authorizations it will obtain on or before the time required).

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(e)No suit, action or arbitration, or legal, administrative or other proceeding is pending or, to Buyer’s knowledge, has been threatened against Buyer that purports to materially adversely affect the validity or enforceability of this Agreement or the ability of Buyer to perform its obligations hereunder, or that would, if adversely determined, have a material adverse effect on the business or financial condition of Buyer. There are no bankruptcy, insolvency, reorganization, receivership or other proceedings pending against or being contemplated by Buyer, or, to Buyer’s knowledge, threatened against it.

(f)Buyer is not in breach of, in default under, or in violation of, any applicable Law, or the provisions of any Authorization, or in breach of, in default under, or in violation of, or in conflict with any provision of any promissory note, indenture or any evidence of indebtedness or security therefor, lease, contract, or other agreement by which it is bound, except for any such breaches, defaults, violations or conflicts which, individually or in the aggregate, could not reasonably be expected to have a material adverse effect on the business or financial condition of Buyer or its ability to perform its obligations hereunder.

(g)Buyer is a qualified MISO Network Customer as defined in the MISO Tariff.

11.2. Representations and Warranties of Seller

Seller makes the following representations and warranties to Buyer as of the Execution Date and the Effective Date:

(a)Seller is a limited liability company duly organized, validly existing and in good standing under the Laws of the State of Wisconsin and qualified to do business in the State of Wisconsin, and is the sole owner of the Facilities.

(b)Seller possesses all requisite power and authority to enter into and perform this Agreement and to carry out the transactions contemplated herein. Seller has all legal power and authority to own and use its properties and to transact the business in which it engages or proposes to engage and holds or will obtain on or before the time required all Authorizations necessary and required therefor.

(c)Seller’s execution, delivery and performance of this Agreement have been duly authorized by, or are in accordance with, its articles of organization and operating agreement; this Agreement has been duly executed and delivered for it by the signatories so authorized; and this Agreement constitutes Seller’s legal, valid and binding obligation, enforceable against it in accordance with the terms hereof, except as such enforceability may be limited by applicable bankruptcy laws from time to time in effect that affect creditors’ rights generally, or by general principles of equity (regardless of whether such enforcement is considered in equity or at law).

(d)Seller’s execution, delivery and performance of this Agreement (i) will not result in a breach or violation of, or constitute a default under, or conflict with any Authorization, or any contract, lease or other agreement or instrument to which it is a party, or by which it or its properties may be bound or affected; and (ii) does

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not require any Authorization, or the consent, authorization or notification of any other Person, or any other action by or with respect to any other Person (except for Authorizations and consents or authorizations of other Persons already obtained, notifications already delivered, or other actions already taken or necessary or required Authorizations it will obtain on or before the time required).

(e)No suit, action or arbitration, or legal, administrative or other proceeding is pending or, to Seller’s knowledge, has been threatened against Seller that purports to materially adversely affect the validity or enforceability of this Agreement or the ability of Seller to perform its obligations hereunder, or that would, if adversely determined, have a material adverse effect on the business or financial condition of Seller. There are no bankruptcy, insolvency, reorganization, receivership or other proceedings pending against or being contemplated by Seller, or, to Seller’s knowledge, threatened against it.

(f)Seller is not in breach of, in default under, or in violation of, or in conflict with any applicable Law, or the provisions of any Authorization, or in breach of, in default under, or in violation of, or in conflict with, any provision of any promissory note, indenture or any evidence of indebtedness or security therefor, lease, contract, or other agreement by which it is bound, except for any such breaches, defaults, violations or conflicts which, individually or in the aggregate, could not reasonably be expected to have a material adverse effect on the business or financial condition of Seller or its ability to perform its obligations hereunder.

11.3. Covenants of Seller

Seller hereby covenants and agrees that throughout the Term:

(a)Subject to Section 13.2, as well as actions taken by Seller that are required with respect to activities of the Medical Isotopes Project, no modifications to, or expansion of, the Facilities that would have a material adverse effect on Buyer’s rights or obligations under this Agreement will occur without the prior written consent of Buyer, such consent not to be unreasonably withheld.

11.4. Covenants of Parties Relating to Regulatory Matters

Buyer shall use commercially reasonable efforts to, as promptly as practicable after the Execution Date, and at its sole expense, prepare and make with PSCW all necessary filings, applications, notices, or other documentation required to be made in order to obtain a final written order of PSCW’s approving this Agreement (“PSCW Approval”). Except as provided in the preceding sentence, Buyer shall use its best efforts to ensure that (a) PSCW Approval is obtained on or prior to the applicable date set forth in Section 13.2(a) and (b) on or prior to the Unit 1 Commencement Date, Buyer is a qualified MISO customer as defined in the MISO Tariff. Buyer shall keep Seller informed as promptly as reasonably practicable and consult with Seller with respect to the content of filings, applications, notices or other documentation relating to PSCW Approval and MISO qualification. Seller

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shall reasonably cooperate with Buyer in connection with Buyer’s efforts to file for and obtain PSCW Approval.

11.5. Buyer Approval

The obligations of Buyer under this Agreement are subject to Buyer diligently pursuing and receiving all approvals of the board of directors of Buyer and its Affiliates, including, if applicable, the approval of the board of directors of WEC Energy Group, Inc., as Buyer determines in its sole discretion are required under its and their respective constituting documents for the performance by Buyer of its obligations under this Agreement (the, “Buyer Approval”), on or prior to the date that is 10 days after the Execution Date (the “Buyer Approval Date”).

ARTICLE XII: INDEMNITY

12.1. Indemnification By Seller

(a)Seller shall defend, indemnify and hold harmless Buyer and its officers, directors, employees and agents from and against any and all costs, expense, damage, liability or loss, including reasonable attorneys’ fees, resulting from or arising out of any Claims arising from the failure of Seller to fulfill its obligations under this Agreement.

(b)Seller shall defend, indemnify and hold harmless Buyer and its officers, directors, employees and agents from and against all loss, damage, expense, costs and liability, including reasonable attorneys’ fees, arising from any Claims against Buyer arising from injury to or death of Persons or damage to or destruction of property occurring at the Facilities to the extent such injury, death or damage is not caused by the willful misconduct of Buyer, its Affiliates or Associates while on Seller’s premises at the Facilities.

12.2. Indemnification by Buyer

(a)Buyer shall defend, indemnify and hold harmless Seller and its officers, directors, employees and agents from and against all loss, damage, expense, costs and liability, including reasonable attorneys’ fees, resulting from or arising out of any Claims arising from the failure of Buyer to fulfill its obligations under this Agreement.

(b)Buyer shall defend, indemnify and hold harmless Seller and its officers, directors, employees and agents from and against all loss, damage, expense, costs and liability, including reasonable attorneys’ fees, arising from any Claims against Seller arising from injury to or death of Persons or damage to or destruction of property occurring at the Facilities to the extent such injury, death or property damage is caused by the negligence or willful misconduct of Buyer, its Affiliates or Associates while at the Facilities and not by the willful misconduct by Seller, its Affiliates, or Associates while on Seller’s premises at the Facilities.

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12.3. Joint Negligence

In the case of joint or concurring negligence or other fault of the Parties giving rise to a loss or Claim against either one or both of them, each shall have rights of contribution against the other Party in proportion to their comparative negligence as determined by the court trying the matter in dispute. Each Party shall promptly notify the other Party of the assertion of any Claim against which such other Party may be required to provide indemnity hereunder and shall give the other Party an opportunity to defend such Claim. These indemnification provisions are for the protection of the Parties hereto only and shall not establish, of themselves, any liability to third parties.

12.4. Responsibility for Employees

The Parties agree that, as between themselves, each Party shall be responsible for the acts and omissions of, and any Claims by, its employees and agents, irrespective of any limitation on the amount or type of damages, compensation or benefits payable by or for such Party under Workers’ Compensation Laws, disability benefit acts or other employee benefit acts; provided, however, that the foregoing is not intended to create third party beneficiary rights in any party not a Party to this Agreement. Each Party shall indemnify the other Party from and against all liabilities, Claims, damages, suits, fines or judgments for injury or death to any third party and damage to or destruction of property of any third party, to the extent caused by such Party’s employees’ or agents’ negligence or willful misconduct.

12.5. Notice and Participation

If any Party entitled to indemnification hereunder (the “Indemnified Party”) intends to seek indemnification under this Article XII: from any other Party (the “Indemnifying Party”) with respect to any Claim, the Indemnified Party shall give the Indemnifying Party notice of such Claim upon the receipt of actual knowledge or information by the Indemnified Party of any possible Claim or of the commencement of such Claim, which period shall in no event be later than the lesser of (i) fifteen (15) Business Days prior to the last day for responding to such Claim or (ii) one-half of the period allowed for responding to such Claim. The Indemnifying Party shall have no liability under this ARTICLE XII for any Claim for which such notice is not provided, to the extent that the failure to give such notice prejudices the Indemnifying Party. The Indemnifying Party shall have the right to assume the defense of any such Claim, at its sole cost and expense, with counsel designated by the Indemnifying Party and reasonably satisfactory to the Indemnified Party; provided, however, that if the defendants in any such Claim include both the Indemnified Party and the Indemnifying Party, and the Indemnified Party shall have reasonably concluded that there may be legal defenses available to it which are different from or additional to those available to the Indemnifying Party, the Indemnified Party shall have the right to select separate counsel, at the Indemnifying Party’s expense, to assert such legal defenses and to otherwise participate in the defense of such Claim on behalf of such Indemnified Party. Should any Indemnified Party be entitled to indemnification under this ARTICLE XII as a result of a Claim, and should the Indemnifying Party fail to assume the defense of such Claim, the Indemnified Party may, at the expense of the Indemnifying Party, contest (or,

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with or without the prior consent of the Indemnifying Party, settle) such Claim. Except to the extent expressly provided herein, no Indemnified Party shall settle any Claim with respect to which it has sought or intends to seek indemnification pursuant to this Section 12.5 without the prior written consent of the Indemnifying Party, which consent shall not be unreasonably withheld. Except to the extent expressly provided herein, no Indemnifying Party shall settle any Claim with respect to which it may be liable to provide indemnification pursuant to this Article XII: without the prior written consent of the Indemnified Party, which consent shall not be unreasonably withheld; provided, however, that if the Indemnifying Party has reached a bona fide monetary settlement agreement with the plaintiff(s) in any such Claim and the Indemnified Party does not consent to such settlement agreement, then the dollar amount specified in the settlement agreement, plus the Indemnified Party’s legal fees and other costs related to the defense of the Claim prior to the date of such settlement agreement, shall act as an absolute maximum limit on the indemnification obligation of the Indemnifying Party.

12.6. Payment of Indemnification Claims

The Indemnifying Party shall pay any amount due pursuant to this Article XII within ten (10) Business Days after the determination of the amount of any such indemnification, to the extent that the existence and entitlement to indemnification is not disputed by the Indemnifying Party, or within ten (10) Business Days after the conclusion of any Dispute Resolution Procedures, to the extent that the existence or entitlement to indemnification is disputed by the Indemnifying Party and is established pursuant to such Dispute Resolution Procedures.

12.7. Survival of Obligation

The duty to indemnify under this ARTICLE XII shall continue in full force and effect notwithstanding the expiration or termination of this Agreement, with respect to any loss, liability, damage, claim or other expense based on facts or conditions which occurred prior to such termination.

ARTICLE XIII: TERM

13.1. Term and Conditions Precedent

(a)Subject to the terms and conditions of this Agreement (including those in the Preamble, as to which provisions of this Agreement are deemed effective as of the Execution Date), this Agreement shall become fully effective on the Effective Date, provided that (i) Buyer has obtained PSCW Approval; (ii) Buyer has obtained Buyer Approval; and (iii) Buyer is at that time a qualified MISO customer as defined in the MISO Tariff.

(b)Unless terminated earlier, as expressly provided herein, this Agreement shall continue to be effective until the expiration of the Delivery Period. Notwithstanding anything to the contrary under this Agreement, (i) the obligation of Seller to sell, and the obligation of Buyer to purchase (including the obligation to make any payments for), any Products with respect to Unit 1 shall only be

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effective during the Delivery Period – Unit 1, and (ii) the obligation of Seller to sell, and the obligation of Buyer to purchase (including the obligation to make any payments for), any Products with respect to Unit 2 shall only be effective during the Delivery Period – Unit 2.

13.2. Termination

(a)Seller or Buyer shall have the right to terminate this Agreement with immediate effect upon written notice to the other if PSCW Approval is not obtained on or before January 1, 2028; provided, however, that such date shall automatically be extended to July 1, 2028 if, as of January 1, 2028, the PSCW Approval is (in the good faith determination of Buyer) still reasonably capable of being obtained and Buyer is pursuing the PSCW Approval in good faith.

(b)Seller or Buyer shall have the right to terminate this Agreement with immediate effect upon written notice to the other if Buyer Approval is not obtained on or before the Buyer Approval Date.

(c)If the continued operation of a Unit pursuant to this Agreement has become materially adverse to Seller such that the continued operation of such Unit is no longer feasible, prudent or sustainable, Seller shall have the right to elect to permanently shut down such Unit upon written notice of termination of this Agreement in relation to such Unit effective on the later of (i) twenty-four (24) months after such notice, and (ii) the permanent shutdown of such Unit; provided, that (1) in the event that the resulting early Unit 1 Termination Date or Unit 2 Termination Date would fall during any Peak Period, the Unit I Termination Date or Unit 2 Termination Date, as applicable, shall be extended until the day after the end of such Peak Period; and (2) this Agreement shall be in full force and effect and Seller shall continue to perform its obligations under this Agreement, and shall be liable for any failure to perform as provided herein, through such remaining effectiveness of this Agreement (as to such Unit and through the remainder of the Term as to the other Unit). In order to exercise its termination rights under this provision, Seller shall provide documentation reasonably acceptable to Buyer that the shutdown of a Unit constitutes a permanent shutdown. A certification of permanent cessation of operations submitted to the NRC pursuant to 10 CFR § 50.82(a)(l)(i) shall constitute acceptable documentation.

(d)Neither Party shall have any further liability upon the effectiveness of a termination of this Agreement pursuant to this Section 13.2 except for those obligations that by their express terms are to survive termination of this Agreement.

13.3. Effect of Termination

Termination of this Agreement shall not terminate the rights or duties of either Party hereunder with respect to any obligations due to be performed on or before the effective date of termination.

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ARTICLE XIV: ADMINISTRATIVE COMMITTEE

14.1. Purpose

From time to time various administrative and technical matters may arise in connection with the terms and conditions of this Agreement which will require the cooperation and consultation of the Parties and the exchange of information. As a means of providing for such cooperation, consultation and exchange, an Administrative Committee is hereby established with the functions described in Section 14.3. However, the Administrative Committee shall not (a) have the authority to amend this Agreement or (b) diminish in any manner the authority or responsibility of either Party as set forth in the various sections of this Agreement. Membership

The Administrative Committee shall have two (2) members, each an “Operating Contact.” Within sixty (60) days after execution of this Agreement, each Party shall designate its Operating Contact (and alternate) and shall promptly give written notice thereof to the other Party. Thereafter, each Party shall promptly give written notice to the other Party of any change in the designation of its Operating Contact. All actions taken by the Administrative Committee must be approved by both Operating Contacts.

14.2. Meetings

Meetings as are reasonably required may be called by either Operating Contact with as much advance notice as is practicable. Meetings may be attended by other representatives of the Parties. Meetings of the Administrative Committee under this Agreement may (and generally shall, following the Execution Date) be held jointly with meetings of the administrative committee under the Existing PPA, in order to coordinate activities among and disposition of matters affecting Seller and Buyer relating to all Facilities covered by the PPAs.

14.3. Functions

The Administrative Committee shall have the following functions:

(a)Provide liaison between the Parties at the management level and exchange information with respect to significant matters arising under this Agreement.

(b)Appoint ad hoc committees, the members of which need not be the Operating Contacts, as necessary to perform detailed work and conduct studies regarding matters requiring investigation.

(c)Review, discuss and attempt to resolve disputes arising under this Agreement; provided, that the Administrative Committee shall not limit the provisions of Article XIX: .

(d)Provide liaison between the Parties concerning the status and operation of the Facilities.

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14.4. Expenses

Each Party shall be responsible for the salary and out-of-pocket expenses of its Operating Contact and its other attendees. All other expenses incurred in connection with the performance by the Administrative Committee of its functions shall be allocated and paid as determined by the Administrative Committee.

ARTICLE XV: NOTICES

15.1. Notices in Writing

All notices or other communications which are required or permitted under this Agreement shall be effective if they are in writing and delivered personally or by certified mail (postage prepaid and return receipt requested), reputable overnight delivery service, or telecopy or other confirmable form of electronic delivery, to the following address (except as to notices which are required by this Agreement to be delivered to a Party’s Operating Contact or to the Dispatch Authority Function or the Balancing Authority Function, which shall be delivered to such Party’s Operating Contact or to the Dispatch Authority Function or the Balancing Authority Function, as the case may be):

(a)if to Seller:

NextEra Energy Point Beach, LLC

700 Universe Boulevard

Juno Beach, FL 33408

Attention: Matthew Roskot and Vice President, Business Management – North

[    ] and dl-nextera-north-

[    ]

(b)With a copy to:

NextEra Energy Resources, LLC

700 Universe Boulevard

Juno Beach, FL 33408

Attention: General Counsel

[    ] and

[    ]

(c)if to the Buyer:

Wisconsin Electric Power Company

333 West Everett Street, Room A214

Milwaukee, Wisconsin 53203

Attention: Trading and Operations

[    ]

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or to such other person or address as the addressee may have specified in a notice duly given to the sender as provided herein.

15.2. Date of Notification

All notices or communications duly delivered or mailed and postmarked to a Party hereto as provided in Section 15.1 shall be effective as of the date of receipt.

15.3. Oral Notice in Emergency

Notwithstanding the provisions of Section 15.1, any notice required hereunder with respect to an occurrence or event requiring immediate attention may be made orally, by telephone or otherwise, provided such notice shall be confirmed in writing within 24 hours thereafter. Each Party shall make any such oral notice directly to the Operating Contact of the other Party.

ARTICLE XVI: CONFIDENTIALITY

16.1. Confidentiality.

(a)Confidential Information. Except as otherwise expressly provided in this Section 16.1, each Party agrees that all Confidential Information will be kept confidential and will not be disclosed by such Party; provided, that the foregoing restriction shall not apply to information which (i) is lawfully and independently obtained by an Party from a third party without restriction as to disclosure by such Party, (ii) was known by a Party prior to its disclosure by or on behalf the disclosing Party, (iii) is in the public domain or enters into the public domain through no fault of a Party, (iv) is independently developed by a Party without reference to information provided by or on behalf of the disclosing Party, or (v) a Party is required by Law or legal process to disclose (in which case such Party shall promptly notify the other Party in writing prior to making any such disclosure in order to facilitate such Party’s efforts to seek a protective order or other appropriate remedy from the proper authority, and agrees to cooperate with the other Party in seeking such order or other remedy). A Party may disclose Confidential Information to its Affiliates and any of its or its Affiliates’ respective Representatives, using the same degree of care used to protect its own confidential or proprietary information of like importance, but in any case using no less than a reasonable degree of care; provided, such Representatives agree to keep such Confidential Information confidential on terms substantially similar to the terms set forth herein, and such Party shall be responsible for such Representatives doing so. Confidential Information shall not otherwise be disclosed to any third party without the prior written consent of the Parties.

(b)Notification. The Parties further agree to notify each other of any requests by a third party, including any Governing Authority, for the disclosure of any information to be treated as confidential pursuant to this Article XVI: and to

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reasonably cooperate with each other in attempting to preserve the confidentiality of such information to the greatest extent consistent with applicable Laws.

(c)Permitted Disclosures. Notwithstanding anything to the contrary herein, without the consent of the other Party (but subject to this Section 16.1(c)), a Party may provide Confidential Information to the PSCW, NRC, FERC, MISO or any other Governing Authority having jurisdiction over Point Beach or any stock exchange as may be necessary in connection with this Agreement or any WEPCO Power Purchase Agreement. Prior to any such disclosure to any Governing Authority, the disclosing Party shall seek confidential treatment for the Confidential Information provided to any such Governing Authority and the disclosing Party shall notify the other Party as far in advance as practical of its intention to release to any Governing Authority any such Confidential Information. In the event that a Party is requested or required by Governing Authority or a party to Governing Authority proceeding to disclose any Confidential Information, the applicable Party requested or required to make the disclosure shall provide the other Party with prompt written notice of any such request or requirement so that the other Party may seek a protective order or other appropriate remedy and/or waive compliance with this Section 16.1. If, in the absence of a protective order or other remedy or the receipt of a waiver from the applicable Party, the Party requested or required to make the disclosure is legally compelled to disclose the other Party’s Confidential Information to any Governing Authority or a party in a Governing Authority proceeding, the Party requested or required to make the disclosure may, without liability hereunder, disclose to such Governing Authority or such party only that portion of the other Party’s Confidential Information which is legally required to be disclosed. In addition, without the consent of the other Party, a Party may disclose the existence, but not the terms and conditions of, this Agreement and any WEPCO Power Purchase Agreement to third parties as may be necessary to perform its obligations under this Agreement or any WEPCO Power Purchase Agreement.

16.2. Survival of Confidentiality

The provisions of this Article XVI: shall survive the expiration or termination of this Agreement for a period of three (3) years.

ARTICLE XVII: INSURANCE

17.1. Coverage and Amounts of Seller

From and after the Effective Date, Seller shall procure, pay premiums for and maintain in full force and effect the insurance coverages described below.

(a)Worker’s Compensation Insurance with statutory limits as required by the Laws of the State of Wisconsin, and Employer’s Liability with minimum limits of one million dollars ($1,000,000) or as established by state or federal Law, if applicable. This insurance shall include all applicable maritime coverages as required by Law.

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This policy is to be endorsed to include a waiver of subrogation in favor of the Buyer.

(b)Commercial General and Umbrella/Excess Liability insurance, including coverage for (i) premises/operations, (ii) independent contractor, (iii) products and completed operations, (iv) broad form contractual liability, (v) broad form property damage, (vi) explosion, collapse and underground damage exclusion deletion, and (vii) personal injury, all with limits of not less than twenty five million dollars ($25,000,000) each occurrence and in the aggregate.

(c)Business Auto Liability Insurance, covering all vehicles and automobiles whether owned, leased, or rented when used by Seller in connection with performance of this Agreement and including commercially reasonable coverage for each accident of bodily injury and property damage.

(d)Nuclear primary and excess property insurance in the amount that is reasonably consistent with the custom in the commercial nuclear power industry and which, at a minimum, satisfies the requirements of 10 CFR 50.54(w), currently one billion sixty million dollars ($1,060,000,000). Deductibles shall be reasonably consistent with the custom in the commercial nuclear power industry, but shall not exceed $10,000,000 (plus ten percent (10%) co-insurance for the first four hundred million dollars ($400,000,000) of loss) without the written consent of Buyer, such consent not to be unreasonably withheld.

(e)Nuclear liability insurance from American Nuclear Insurers in accordance with the Price Anderson Act until such time as the NRC shall release Seller from this obligation. Should the Price Anderson Act be repealed, the Seller shall at its cost, provide insurance or other similar financial protection affording coverage consistent with coverages maintained for other nuclear power plants from the commercial marketplace to the extent such coverage is commercially available and to the extent that such coverage is available at commercially reasonable rates. Such insurance shall include, at a minimum, the following policies (as such are in effect for Unit 1 and Unit 2 as of the Effective Date):

(i)Facility Form

(ii)Secondary Financial Protection

(iii)Master Worker

(iv)Suppliers and Transporters

(f)NEIL nuclear business interruption and extra expense insurance in an amount that is reasonably consistent with the custom in the commercial nuclear power industry, but only to the extent of available limits remaining and in coordination with the amount purchased by the Buyer.

(g)Notwithstanding the foregoing, Seller may self-insure to meet the minimum insurance requirements above to the extent it maintains a self-insurance program; provided that Seller (or its guarantor’s) Credit Rating is rated Investment Grade or

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better and that its self-insurance program meets the above minimum insurance requirements. Self-insurance shall be approved and recognized by the State of Wisconsin for workers compensation and automobile liability. For any period of time that Seller (or its guarantor’s) does not have an Investment Grade Credit Rating, Seller shall comply with the above minimum insurance requirements. In the event that Seller is permitted to self-insure pursuant to this Section 17.1, Seller shall notify Buyer that Seller meets the requirements to self-insure and that its self-insurance program meets the above minimum insurance requirements.

17.2. Insurance Certificates

On the Effective Date, and thereafter from time to time at the request of Buyer, Seller shall provide certificates of insurance from insurance companies having a Best rating of A minus or better confirming that the insurance coverages required herein are maintained. Seller shall use commercially reasonable efforts to provide certificates that provide that Buyer be given thirty (30) days prior written notice by the insurer, or its authorized representative, of any cancellation and ten (10) days’ prior written notice due to cancellation for non­payment of premiums for any required coverage provided by such insurer as evidenced by the certificates. In addition, Seller agrees to provide notice to Buyer of any material change in the insurance coverages or policies required hereby.

17.3. Coverage For Full Term

All required coverages shall remain in full force and effect during the Term. Seller’s liability under this Agreement shall not be limited to or by the insurance coverages required by this Agreement.

ARTICLE XVIII: ASSIGNMENT

18.1. Binding Effect

This Agreement shall be binding upon and shall inure to the benefit of the Parties and their respective successors and permitted assignees.

18.2. Assignment

Neither Party may assign its rights or delegate its duties under this Agreement or undergo a change in control except to the extent that any such action would constitute a Permitted Transfer (including the provisions thereof with respect to a Change in Control).

18.3. Permitted Transfer.

Notwithstanding Section 18.2 or anything expressed or implied to the contrary in this Agreement or any WEPCO Power Purchase Agreement, each of the transactions set forth in clauses (a) and (b) of this Section 18.3 (each, a “Permitted Transfer”) are permitted to occur under this Agreement.

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(a)With respect to Seller, each of the following transactions may be effectuated without any Buyer’s consent, but with prior notice to Seller:

(i)transactions among Affiliates of Seller, including any corporate reorganization, merger, combination or similar transaction or transfer of assets or ownership interests involving Seller or its Affiliates; provided (i) no Person that is not a wholly-owned, direct or indirect subsidiary of NextEra Energy, Inc. becomes Seller, (ii) the transferee shall have (A) executed and delivered to Buyer a written agreement under which the transferee assumes in writing all of NEPB’s duties and obligations, under this Agreement and the Existing PPA, and otherwise agreed to be bound by all of the terms and conditions of this Agreement and the Existing PPA, and (B) an Investment Grade Credit Rating or provided Seller Performance Security that complies with Section 8.1, and (iii) if any subsidiary of NextEra Energy, Inc. other than NEPB is to become Seller, such subsidiary shall be a successor entity to NEPB via merger or acquisition of all or substantially all of NEPB’s assets, or shall otherwise be a Qualified Operator;

(ii)a Change in Control of NextEra Energy, Inc., NextEra Energy Resources, LLC, or NextEra Energy Capital Holdings, Inc.; provided, that, in the event the relevant transferee, general partner, surviving entity, or recipient of “control” (as defined in Rule 12b-2 under the Securities Exchange Act of 1934) does not have an Investment Grade Credit Rating, such Change in Control shall require the consent of Buyer;

(iii)a transfer of Point Beach (or the direct or indirect ownership of equity interests in NEPB) packaged with any of the following: (A) all or substantially all of the assets of NextEra Energy Resources, LLC or NextEra Energy, Inc.; (B) all or substantially all of NextEra Energy Resources, LLC or its ultimate parent company’s energy generation portfolio; or (C) all or substantially all of NextEra Energy Resources, LLC’s or its ultimate parent company’s nuclear generation portfolio; provided, that in the case of each of (A), (B) and (C): the transferee (x) shall have executed and delivered to Buyer a written agreement under which the transferee assumes in writing all of NEPB’s duties and obligations under this Agreement and the Existing PPA, and otherwise agrees to be bound by all of the terms and conditions of this Agreement and the Existing PPA, (y) shall have an Investment Grade Credit Rating or provides Seller Performance Security that complies with Section 8.1 and (z) shall be (or have contracted with) a Qualified Operator.

(b)With respect to Buyer, each of the following transactions may be effectuated without the consent of Seller, but with prior notice to Seller:

(i)transactions among Affiliates of Buyer, including any corporate reorganization, merger, combination or similar transaction or transfer of assets or ownership interests involving Buyer or its Affiliates; provided (i)

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no Person that is not a wholly-owned, direct or indirect subsidiary of WEC Energy Group, Inc. becomes Buyer, and (ii) if any subsidiary of WEC Energy Group, Inc, other than WEPCO, is to become Buyer, the transferee shall have (A) executed and delivered to Seller a written agreement under which the transferee assumes in writing all of WEPCO’s duties and obligations under this Agreement and the Existing PPA, and otherwise agreed to be bound by all of the terms and conditions of this Agreement and the Existing PPA, and (B) an Investment Grade Credit Rating or provided Buyer Performance Security that complies with Section 8.2; or

(ii)a Change in Control of WEPCO or WEC Energy Group, Inc.; provided, that, in the event the relevant transferee, general partner, surviving entity, or recipient of “control” (as defined in Rule 12b-2 under the Securities Exchange Act of 1934) does not have an Investment Grade Credit Rating, such Change in Control shall require the consent of NEPB.

(c)All Permitted Transfers shall be subject to the receipt of any required authorizations, consents or approvals from any Governing Authority, including without limitation, the NRC. No transaction shall be a Permitted Transfer if it would result in the loss or recapture of any ITC, Nuclear PTC, PTC, or other applicable Tax attributes. Once an assignee provides replacement Seller Performance Security or Buyer Performance Security, as applicable, the existing credit support of the applicable Party shall be promptly returned to the transferring Party.

ARTICLE XIX: DISPUTE RESOLUTION

19.1. General Provisions

Every Dispute between the Parties arising out of or in connection with this Agreement shall be resolved in accordance with this ARTICLE XIX, to the extent permitted by Law.

19.2. Negotiation

In the event of a Dispute, the Parties shall in good faith attempt to resolve such Dispute by negotiations through the Administrative Committee following provision by a Party of written notice to the other Party specifying the existence of a Dispute. Should resolution not be achieved within fifteen (15) days of a Party having given written notice of the Dispute to the other Party, through Operating Contacts on the Administrative Committee, the Administrative Committee shall refer the Dispute to senior executives of the Parties who shall have authority to settle the matter (the “Senior Executives”). Within fifteen (15) days after receipt by a Party of the referral notice, the Party receiving the notice shall submit to the disputing Party a written response. The referral notice and the response shall each include: (a) a statement of the submitting Party’s position and a summary of arguments supporting that position; and (b) the name and title of the Senior Executive who will represent the submitting Party and of any other natural person who will accompany the Senior Executive. Within thirty (30) days after delivery of the disputing Party’s referral

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notice, the Senior Executives of the Parties shall meet at a mutually acceptable time and place, and thereafter as often as they reasonably deem necessary, to attempt to resolve the Dispute. All reasonable requests for information made by the Parties to each other will be honored. All negotiations pursuant to this Section 19.2 are confidential and shall be treated as compromise and settlement negotiations for purposes of applicable rules of evidence. If the Dispute has not been resolved by negotiation between the Senior Executives within forty-five (45) days of receipt of the disputing Party’s referral notice, or if the Senior Executives failed to meet within thirty (30) days after receipt of the disputing Party’s referral notice, any Party may then submit such Dispute (other than with respect to a Budget Dispute) to the courts pursuant to Section 22.2(b).

19.3. Binding Upon Parties

In the resolution of any Dispute pursuant to this Article XIX, each of the Parties, their Operating Contacts and Senior Executives shall give effect to this Article XIX.

19.4. Continued Performance

Subject to the provisions of Section 10.2, notwithstanding any Dispute between the Parties and pending the final decision of a Dispute, each Party shall continue to perform its respective obligations under this Agreement.

ARTICLE XX: COMPLIANCE WITH LAWS; TAXES

20.1. Compliance with Laws

Each Party shall at all times comply with all applicable Laws relating to the performance of its obligations under this Agreement. Each Party shall give all required notices, shall procure and maintain all necessary Authorizations and inspections necessary for its performance of this Agreement, and shall pay all charges and fees in connection therewith.

20.2. Mobile-Sierra

It is the intent of the Parties that the rates and all other terms and conditions of the services provided hereunder shall not be subject to change under Sections 205 or 206 of the Federal Power Act of 1935, 16 U.S.C. § 791 et seq., (or any successor legislation) without the consent of both Parties. Each of the Parties hereto agrees not to unilaterally file with the FERC a change in the rates, terms or conditions of this Agreement. Moreover, absent agreement of all Parties to a proposed change, the standard of review for changes to any rate, term or condition of this Agreement proposed by a non-Party or the FERC or any other Governing Authority acting sua sponte shall be the “public interest” standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Services Corp., 350 U.S. 332 (1956) and Federal Power Commission v. Sierra Pac Power Co., 350 U.S. 348 (1956) and clarified by Morgan Stanley Capital Group, Inc. v. Public Util. Dist. No. 1 of Snohomish County, 554 U.S. 527 (2008). To the extent that the FERC adopts specific language that parties must incorporate into agreements in order to bind the FERC, third parties and themselves to a public interest standard of review, the Parties hereby incorporate such language herein by reference.

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20.3. Taxes and Other Charges

(a)Seller’s Taxes

Seller is liable for and shall pay, or cause to be paid, or reimburse Buyer if Buyer has paid, all Taxes applicable to any transaction arising out of this Agreement at or prior to the Delivery Point on the sale of Energy, Capacity, Ancillary Services, or Environmental Attributes to Buyer. Seller shall indemnify, defend and hold harmless Buyer from any Claims for such Taxes applicable prior to the Delivery Point.

(b)Buyer’s Taxes

Buyer is liable for and shall pay, or cause to be paid, or reimburse Seller if Seller has paid, all Taxes applicable to any transaction arising out of this Agreement after the Delivery Point on the sale by Buyer of Energy, Capacity, or Ancillary Services. Buyer shall indemnify, defend and hold harmless Seller from any Claims for such Taxes applicable after the Delivery Point.

(c)Certificate of Tax Exemption

Either Party, upon written request of the other, shall provide a certificate of exemption or other reasonably satisfactory evidence of exemption if either Party is exempt from Taxes.

(d)Gross Receipts Tax

Buyer is liable for any Gross Receipts Tax applicable to any transaction arising out of this Agreement. If Seller pays any such Gross Receipts Tax, then Seller shall include such amounts so paid in the next Billing Cycle invoice as provided in Sections 3.1(a) and 7.1 (the “Gross Receipts Tax Payment”).

ARTICLE XXI: CHANGE IN LAW

21.1. Change in Law

In the event there is a change or changes in any Laws or interpretations thereof, enacted or adopted after the Execution Date or any Law or interpretation thereof, enacted or adopted after the Execution Date results in the application of any Law to a new or different class of parties (a “Change in Law”), the Party affected by such Change in Law with respect to its obligations under this Agreement shall be responsible for the burden (subject to its right to claim the occurrence of Force Majeure with respect to any Change in Law or prospective Change in Law that has arisen on or before the Effective Date) and, except as provided in Section 21.2 or elsewhere in this Agreement, shall be permitted to retain the benefits of such Change in Law. For the avoidance of doubt, except as specifically provided elsewhere in this Agreement, the terms and conditions of this Agreement shall not be subject to change due to a Change in Law.

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21.2. Environmental Attributes

Buyer is entitled to one hundred percent (100%) of all Environmental Attributes attributable to the Products (including all revenues and other benefits arising from such Environmental Attributes). Seller agrees to execute a separate agreement to transfer to Buyer any revenue, or any other benefit received by Seller for Environmental Attributes attributable to the Products, and to execute all documents and agreements and take all steps necessary for Seller to take, if any, in order to permit Buyer to market Environmental Attributes conveyed to Buyer hereunder, provided that Buyer shall pay all of the incremental costs, if any, with respect to the documentation and related creation and issuance of such Environmental Attributes in excess of the amount available in the Seller Contingency Tranche. Failing any such agreement, Seller agrees to credit to Buyer such revenues as provided in Section 3.1(b) until such time as an agreement is executed, provided that any costs related to the documentation and related creation of Environmental Attributes shall be netted against any such revenues.

21.3. MISO Changes

In the event that, at any time during the Term, (i) the MISO Tariff is materially changed in a manner that (a) makes it impossible to implement this Agreement as intended or (b) materially adversely affects Seller or Buyer such that the benefits and burdens of this Agreement are no longer as contemplated by the original intentions of the Parties, (ii) MISO fails to exist (and has no equivalent successor) or the Transmission Owner is no longer a part of MISO, or (iii) if an applicable regional reliability council issues a directive, rule or regulation that materially adversely affects Seller or Buyer such that the benefits and burdens of this Agreement are no longer as contemplated by the original intentions of the Parties, the Parties shall use their commercially reasonable efforts to reform this Agreement in order to give effect to the original intentions of the Parties regarding the appropriate allocation of benefits and burdens to each Party.

ARTICLE XXII: MISCELLANEOUS

22.1. Recording Telephone Conversations

Each Party agrees that the other Party or its representatives may record any or all telephone conversations between representatives of the two Parties pursuant to or relating to this Agreement. Each Party is hereby advised that telephone conversations with Buyer’s personnel relating to Section 2.4 and Article IV: are routinely recorded and each Party agrees to obtain any necessary consent of its personnel regarding such recording. Each Party further agrees that such recorded telephone conversations shall not be deemed inadmissible in any arbitration proceeding or court of law by virtue of the recorded nature of the conversations. Each Party hereby waives any objection to the introduction of such recorded telephone conversations as evidence in any court of law to the extent such objections are based on the recorded nature of such conversations.

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22.2. Governing Law

(a)This Agreement shall be governed by and construed in accordance with the Law of the State of Wisconsin as to all matters, including but not limited to matters of validity, construction, effect, performance and remedies.

(b)The Parties hereby irrevocably submit to the exclusive jurisdiction of the United States District Court for the Eastern District of Wisconsin or, in the event that jurisdiction for any matter cannot be established in the United States District Court for the Eastern District of Wisconsin, in the Circuit Court for Manitowoc County, solely in respect of the interpretation and enforcement of the provisions of this Agreement and of the documents referred to in this Agreement, and in respect of the transactions contemplated hereby, and hereby waive, and agree not to assert, as a defense in any action, suit or proceeding for the interpretation or enforcement hereof or of any such document, that it is not subject thereto or that such action, suit or proceeding may not be brought or is not maintainable in said courts or that the venue thereof may not be appropriate or that this Agreement or any such document may not be enforced in or by such courts, and the Parties hereto irrevocably agree that all claims with respect to such action or proceeding shall be heard and determined in such a court. The Parties hereby consent to and grant any such court jurisdiction over the Person of such Parties solely for such purpose and over the subject matter of such dispute and agree that mailing of process or other papers in connection with any such action or proceeding in the manner provided in Article XV: hereof or in such other manner as may be permitted by Law shall be valid and sufficient service thereof.

(c)EACH PARTY ACKNOWLEDGES AND AGREES THAT ANY CONTROVERSY WHICH MAY ARISE UNDER THIS AGREEMENT IS LIKELY TO INVOLVE COMPLICATED AND DIFFICULT ISSUES, AND THEREFORE EACH PARTY HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVES ANY RIGHT A PARTY MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY LITIGATION RESULTING FROM, ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY. EACH PARTY CERTIFIES AND ACKNOWLEDGES THAT (i) NO REPRESENTATIVE, AGENT OR ATTORNEY OF THE OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER, (ii) EACH PARTY UNDERSTANDS AND HAS CONSIDERED THE IMPLICATIONS OF THIS WAIVER, (iii) EACH PARTY MAKES THIS WAIVER VOLUNTARILY AND (iv) EACH PARTY HAS BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION 22.2(c).

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22.3. Entire Agreement; Amendment

This Agreement constitutes the entire agreement between the Parties pertaining to the subject matter of this Agreement, and supersedes and terminates any letters of intent and all prior and contemporaneous agreements, understandings, negotiations and discussions with the Parties, whether oral or written, regarding said subject matter, and there are no warranties, representations or other agreements between the Parties in connection with the subject matter of this Agreement, except as specifically set forth in this Agreement. No amendment, supplement, modification, waiver or termination of this Agreement shall be binding unless executed in writing by the Party to be bound thereby. No waiver of any of the provisions of this Agreement shall be deemed or shall constitute a waiver of any other provision of this Agreement, whether or not similar, nor shall such waiver constitute a continuing waiver unless otherwise expressly provided.

22.4. No Implied Waiver

The failure or delay of any Party hereto to enforce at any time any of the provisions of this Agreement, or to require at any time performance of the other Party hereto of any of the provisions hereof, shall neither be construed to be a waiver of such provisions nor affect the validity of this Agreement or any part hereof or the right of such Party thereafter to enforce each and every such provision.

22.5. Severability

If any provision of this Agreement shall be determined to be unenforceable, void or otherwise contrary to any Law, such condition shall in no manner operate to render any other provision of this Agreement unenforceable, void or contrary to any Law, and this Agreement shall continue in force in accordance with the remaining terms and provisions hereof, unless such condition invalidates the purpose or intent of this Agreement. In the event that any of the provisions, or portions or applications thereof, of this Agreement are held unenforceable or invalid by any court of competent jurisdiction, Seller and Buyer shall negotiate in good faith to attempt to implement a reformation of the provisions of this Agreement with a view toward effecting the purposes of this Agreement by replacing the offending provision with a valid provision the economic effect of which comes as close as possible to that of the offending provision.

22.6. No Exclusivity/Dedication of Assets

This Agreement is not intended to be an exclusive arrangement between Buyer and Seller. No undertaking by a Party hereto to the other Party hereto under any provision of this Agreement shall constitute the dedication of that Party’s assets or any portion thereof to the public.

22.7. Expenses

Each Party shall pay the fees and expenses of its respective counsel, accountants, brokers, consultants, investment bankers and other experts incident to the negotiation and preparation of this Agreement.

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22.8. Counterparts

This Agreement may be executed simultaneously in two (2) or more counterparts, each of which shall be deemed an original but all of which together shall constitute one and the same instrument.

22.9. Survival

The applicable provisions of this Agreement shall continue in effect after the termination of this Agreement, to the extent necessary to provide for final billing and adjustment, and to make other appropriate settlements hereunder. Those provisions hereof that by their express terms are intended to survive this Agreement shall so survive for the periods indicated. Without limitation of the foregoing, Article VII: , Article VIII: , Article X: , Article XII: and Article XIX: shall survive the termination of this Agreement.

22.10. Individual Responsibility

This Agreement shall not be construed to create or give rise to any partnership, joint venture, agency or other relationship between Seller and Buyer other than that of purchaser and seller. Each Party shall be solely and individually responsible for its own covenants, obligations and liabilities as herein provided, and the Parties do not intend to create any joint, several or joint and several obligations to any third party. Neither this Agreement, nor any grant, lease or license related thereto, shall create or be construed to create any new entity, such as a partnership, association or joint venture.

22.11. No Duty To Third Parties

This Agreement is for the sole benefit of the Parties hereto, and except as specifically provided herein nothing in this Agreement or any action taken hereunder shall be construed to create any duty, liability or standard of care to any Person not a party to this Agreement. Except as specifically provided herein, no Person shall have any rights or interest, direct or indirect, in this Agreement or the services to be provided hereunder, or both, except Buyer and Seller. The Parties specifically disclaim any intent to create any rights in any Person as a third-party beneficiary to this Agreement or the services to be provided hereunder, or both.

22.12. Forward Contract

The Parties acknowledge and agree that this Agreement, the transactions contemplated hereby, and any instrument(s) that may be provided by either Party hereunder (including any guaranty) shall each, and together, constitute one and the same “forward contract” within the meaning of the United States Bankruptcy Code, and Seller, Seller’s Guarantor and Buyer shall each constitute a “forward contract merchant” under the United Stated Bankruptcy Code.

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22.13. Press Releases

Neither Buyer nor Seller shall, without the approval of the other, make any press release or other public announcement which describes the substantive terms of this Agreement; provided, that subject to Article XVI: the foregoing shall not preclude communications or disclosures (i) necessary to implement the provisions of this Agreement, (ii) to comply with accounting and United States Securities and Exchange Commission disclosure obligations or (iii) in connection with the application for any Authorization.

[Signature Pages Follow]

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IN WITNESS WHEREOF, each of the Parties hereto has caused this Agreement to be duly executed on its behalf by its duly authorized officer as of the date first set forth above.

NEXTERA ENERGY POINT BEACH, LLC

By: /s/ Matthew Roskot

Name: Matthew Roskot

Title: President

WISCONSIN ELECTRIC POWER COMPANY

By: /s/ Michael W. Hooper

Name: Michael W. Hooper

Title: President

[Signature Page to Power Purchase Agreement]

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EXHIBIT A

DELIVERED ENERGY CHARGES

Year			Delivered Energy
			Charge (in $/MWh)
2030			[ ]
2031			[ ]
2032			[ ]
2033			[ ]
2034			[ ]
2035			[ ]
2036			[ ]
2037			[ ]
2038			[ ]
2039			[ ]
2040			[ ]
2041			[ ]
2042			[ ]
2043			[ ]
2044			[ ]
2045			[ ]
2046			[ ]
2047			[ ]
2048			[ ]
2049			[ ]
2050			[ ]
2051			[ ]
2052			[ ]
2053			[ ]

For each month during the Term, the Delivered Energy Charge set forth above shall apply to Energy purchased by Buyer under this Agreement, with adjustments to be made with respect to any Uprate accepted by Buyer under this Agreement. Commencing in the year 2032, the Delivered Energy Charge numbers reflect an increase of [ ] per annum. The Delivered Energy Charge shall be adjusted by multiplying the amount of such charge by the Delivered Energy Charge Shaping Factor for such month as set forth on Exhibit C hereto.

A-1

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EXHIBIT B

BUYER’S CAPACITY AMOUNT AND CAPACITY TESTING PROCEDURES

For any given month during the Term, the Buyer’s Capacity Amount shall be as set forth in the table below:

Column A

Column B

Column C

Column D

Column E

Column F

5-Year Rolling Average Inlet Circ Water Temperature

Capacity of the

Buyer’s

Buyer’s

Total Buyer’s

Facilities (MW)

Product

Capacity

Capacity Amount

Share

Amount by Unit

(Unit 1 + Unit 2

(%)

(C x D)

from E)

Month

Unit 1

Unit 2

Unit 1

Unit 2

Unit 1/Unit 2

Unit 1

Unit 2

Total

January

February

March

April

May

June

July

August

September

October

November

December

Column A – Depicts the month of the applicable year. For the avoidance of doubt, the Buyer’s Capacity Amount for the applicable months in question are only applicable to (i) Unit 1 during the Delivery Period – Unit 1 and (ii) Unit 2 during the Delivery Period – Unit 2, and such Buyer’s Capacity Amount shall be prorated in any month in which (a) with respect to Unit 1, the Unit 1 Commencement Date or Unit 1 Termination Date occurred, (b) with respect to Unit 2, the Unit 2 Commencement Date or Unit 2 Termination Date occurred, or (c) the Early Termination Date occurred.

Column B – Depicts the 5-year rolling average inlet circulating water temperature for each unit for each month of the applicable year updated on an annual basis.

Column C – Sets forth the Capacity of each Unit for the applicable month set forth opposite in Column A. The Capacity for each Unit set forth in Column C will be updated annually (or at any other time as mutually agreed by the Parties) over the Term of this Agreement to reflect the Capacity of the applicable Unit based on the Performance Tests. Note that the amounts to be listed are not guaranteed Capacity amounts but only estimates, as Buyer’s Capacity entitlement shall only be Buyer’s Product Share of the actual Accredited Capacity/Capacity.

If the annual update for Column C falls within a plus or minus three percent (3%) band of the existing Column C in the aggregate, then no changes shall be made to the Column C.

B-1

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Column D – Sets forth the prevailing Buyer’s Product Share for each Unit for the applicable month set forth opposite in Column A.

Column E – Sets forth Buyer’s Capacity Amount for each Unit for the applicable month set forth opposite in Column A by multiplying the values in Column C amounts per Unit times Column D prevailing Buyer’s Product Share for each Unit.

Column F – Shall be the sum of the Buyer’s Capacity Amounts for Units 1 and 2 from Column E.

B-2

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EXHIBIT C

Delivered Energy Charge Shaping Factor

Month			On-Peak Hours			Off-Peak Hours
January			[ ]			[ ]
February			[ ]			[ ]
March			[ ]			[ ]
April			[ ]			[ ]
May			[ ]			[ ]
June			[ ]			[ ]
July			[ ]			[ ]
August			[ ]			[ ]
September			[ ]			[ ]
October			[ ]			[ ]
November			[ ]			[ ]
December			[ ]			[ ]

C-1

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EXHIBIT D

DIAGRAM OF METERING DEVICES

The Metering Devices identified above as numbers 3, 4, 7 and 8 are revenue quality meters.

D-1

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EXHIBIT E-1

FORM OF SELLER’S GUARANTY

THIS GUARANTY (this “Guaranty”), dated as of [________ , 202__] (the “Effective Date”), is made by NEXTERA ENERGY CAPITAL HOLDINGS, INC., a Florida corporation (“Guarantor”), in favor of WISCONSIN ELECTRIC POWER COMPANY, a Wisconsin corporation (“Counterparty”).

RECITALS:

A.WHEREAS, Counterparty and Guarantor’s indirect, wholly-owned subsidiary NEXTERA ENERGY POINT BEACH, LLC, a Wisconsin limited liability company (“Obligor”) have entered into, or concurrently herewith are entering into, that certain Power Purchase Agreement dated as of [_____ , 20 ] (the “Agreement”); and

B.WHEREAS, Guarantor will directly or indirectly benefit from the Agreement between Obligor and Counterparty;

NOW THEREFORE, in consideration of the foregoing premises and as an inducement for Counterparty’s execution, delivery and performance of the Agreement, and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, Guarantor hereby agrees for the benefit of Counterparty as follows:

*        *        *

1.GUARANTY. Subject to the terms and provisions hereof, Guarantor hereby absolutely and irrevocably guarantees the timely payment when due of all obligations owing by Obligor to Counterparty arising pursuant to the Agreement on or after the Effective Date (the “Obligations”). This Guaranty shall constitute a guarantee of payment and not of collection. The obligation and liability of Guarantor under this Guaranty shall be subject to the following limitations:

(a)Notwithstanding anything herein or in the Agreement to the contrary, the maximum aggregate obligation and liability of Guarantor under this Guaranty, and the maximum recovery from Guarantor under this Guaranty, shall in no event exceed One Hundred Million U.S. Dollars (U.S. $100,000,000), as of the date hereof, with such amount to reduce ratably beginning on January 1, 2031 and on January 1st of each year thereafter until the end of the Term (such amount, the “Maximum Recovery Amount”).

(b)The obligation and liability of Guarantor under this Guaranty is specifically limited to payments expressly required to be made under the Agreement, as well as costs of collection and enforcement of this Guaranty (including attorney’s fees) to the extent reasonably and actually incurred by the Counterparty (subject in all instances, to the limitations imposed by the Maximum Recovery Amount as specified in Section 1(a) above). In no event, however, shall Guarantor be liable for or obligated to pay any consequential, indirect, incidental, lost profit, special, exemplary, punitive, equitable or tort damages.

2.DEMANDS AND PAYMENT.

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(a)If Obligor fails to pay any Obligation to Counterparty when such Obligation is due and owing under the Agreement (an “Overdue Obligation”), Counterparty may present a written demand to Guarantor calling for Guarantor’s payment of such Overdue Obligation pursuant to this Guaranty (a “Payment Demand”).

(b)Guarantor’s obligation hereunder to pay any particular Overdue Obligation(s) to Counterparty is conditioned upon Guarantor’s receipt of a Payment Demand from Counterparty satisfying the following requirements: (i) such Payment Demand must identify the specific Overdue Obligation(s) covered by such demand, the specific date(s) upon which such Overdue Obligation(s) became due and owing under the Agreement, and the specific provision(s) of the Agreement pursuant to which such Overdue Obligation(s) became due and owing; (ii) such Payment Demand must be delivered to Guarantor in accordance with Section 9 below; and (iii) the specific Overdue Obligation(s) addressed by such Payment Demand must remain due and unpaid at the time of such delivery to Guarantor.

(c)After issuing a Payment Demand in accordance with the requirements specified in Section 2(b) above, Counterparty shall not be required to issue any further notices or make any further demands with respect to the Overdue Obligation(s) specified in that Payment Demand, and Guarantor shall be required to make payment with respect to the Overdue Obligation(s) specified in that Payment Demand within five (5) Business Days after Guarantor receives such demand. As used herein, the term “Business Day” shall mean all weekdays (i.e., Monday through Friday) other than any weekdays during which commercial banks or financial institutions are authorized to be closed to the public in the State of Florida, the State of Wisconsin or the State of New York.

3.REPRESENTATIONS AND WARRANTIES. Guarantor represents and warrants that:

(a)it is a corporation duly organized and validly existing under the laws of the State of Florida and has the corporate power and authority to execute, deliver and carry out the terms and provisions of this Guaranty;

(b)no authorization, approval, consent or order of, or registration or filing with, any court or other governmental body having jurisdiction over Guarantor is required on the part of Guarantor for the execution and delivery of this Guaranty; and

(c)this Guaranty constitutes a valid and legally binding agreement of Guarantor, enforceable against Guarantor in accordance with the terms hereof, except as the enforceability thereof may be limited by the effect of any applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting creditors' rights generally and by general principles of equity.

4.RESERVATION OF CERTAIN DEFENSES. Without limiting Guarantor’s own defenses and rights hereunder, Guarantor reserves to itself all rights, setoffs, counterclaims and other defenses to which Obligor is or may be entitled arising from or out of the Agreement, except for defenses (if any) based upon the bankruptcy, insolvency, dissolution or liquidation of Obligor or any lack of power or authority of Obligor to enter into and/or perform the Agreement.

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5.AMENDMENT OF GUARANTY. No term or provision of this Guaranty shall be amended, modified, altered, waived or supplemented except in a writing signed by Guarantor and Counterparty.

6.WAIVERS AND CONSENTS. Subject to and in accordance with the terms and provisions of this Guaranty:

(a)The liability of Guarantor under this Guaranty shall be irrevocable, absolute and unconditional irrespective of, and without limiting the foregoing, Guarantor hereby irrevocably waives any defenses it may now have or hereafter acquire in any way relating to, any or all of:

(i)promptness, diligence, presentment, demand of payment, acceptance, notice of acceptance, protest, notice of dishonor and any other notices with respect to any of the Guaranteed Obligations and this Guaranty, except as set forth in Section 2 above;

(ii)any right to require that any action or proceeding be brought against Obligor or any other person, or to require that Counterparty seek enforcement of any performance against Obligor or any other person, prior to any action against Guarantor under the terms hereof;

(iii)any change in the time, manner or place of payment of, or in any other term of, all or any of the Guaranteed Obligations (including renewals, extensions or other alterations thereof), or any other amendment, modification or waiver of, or any consent to departure from, the terms of such Guaranteed Obligations;

(iv)the release of any person (other than Obligor or Guarantor) from liability for payment of all or any of the Obligations or any receipt, substitution, surrender, exchange or release any collateral or other security for any or all of the Guaranteed Obligations;

(v)the occurrence or continuance of any event of bankruptcy, reorganization or insolvency with respect to Obligor, or any disallowance of all or any portion of any claim by Counterparty, its successors or assigns in connection with any such proceeding or in the event that all or any part of any payment is recovered from Counterparty as a preference payment or fraudulent transfer under the Federal Bankruptcy Code or any applicable law, or the dissolution, liquidation or winding up of Guarantor or Obligor; or

(vi)any circumstance whatsoever or any act of Counterparty or any existence of or reliance on any representation by Counterparty that might otherwise constitute a legal or equitable defense available to, or a discharge of, a guarantor or surety.

(b)No delay by Counterparty in the exercise of (or failure by Counterparty to exercise) any rights hereunder shall operate as a waiver of such rights, a waiver of any other rights or a release of Guarantor from its obligations hereunder (with the understanding, however, that the foregoing shall not be deemed to constitute a waiver by Guarantor of any rights or

E-1-3

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defenses which Guarantor may at any time have pursuant to or in connection with any applicable statutes of limitation).

7.REINSTATEMENT. Guarantor agrees that this Guaranty shall continue to be effective or shall be reinstated, as the case may be, if all or any part of any payment made hereunder is at any time avoided or rescinded or must otherwise be restored or repaid by Counterparty as a result of the bankruptcy or insolvency of Obligor, all as though such payments had not been made.

8.TERMINATION. This Guaranty and Guarantor’s obligations hereunder will terminate automatically and immediately upon the termination or expiration of the Agreement; provided, however, that no such termination shall affect Guarantor's liability with respect to any Obligation incurred prior to the time the termination is effective, which Obligation shall remain subject to this Guaranty.

9.NOTICE. Any Payment Demand, notice, request, instruction, correspondence or other document to be given hereunder (herein collectively called “Notice”) by Counterparty to Guarantor, or by Guarantor to Counterparty, as applicable, shall be in writing and may be delivered either by (i) U.S. certified mail with postage prepaid and return receipt requested, or (ii) recognized nationwide courier service with delivery receipt requested, in either case to be delivered to the following address (or to such other U.S. address as may be specified via Notice provided by Guarantor or Counterparty, as applicable, to the other in accordance with the requirements of this Section 9):

TO GUARANTOR: *			TO COUNTERPARTY:
NEXTERA ENERGY CAPIT HOLDINGS, INC. 700 Universe Blvd. Juno Beach, Florida 33408 Attn: Treasurer
[Tel: (561) 694-6204 -- for use connection with courier deliveries]			[Tel: ( ) _ _ _ for use in
			connection with courier deliveries]

*    (NOTE: Copies of any Notices to Guarantor under this Guaranty shall also be sent via facsimile to ATTN: Contracts Group, Legal, Fax No. (561) 625-7504 and ATTN: Credit Department, Fax No. (561) 625-7642. However, such facsimile transmissions shall not be deemed effective for delivery purposes under this Guaranty.)

Any Notice given in accordance with this Section 9 will (i) if delivered during the recipient's normal business hours on any given Business Day, be deemed received by the designated recipient on such date, and (ii) if not delivered during the recipient's normal business hours on any given Business Day, be deemed received by the designated recipient at the start of the recipient's normal business hours on the next Business Day after such delivery.

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10.MISCELLANEOUS.

(a)This Guaranty shall in all respects be governed by, and construed in accordance with, the law of the State of New York, without regard to principles of conflicts of laws thereunder (other than Sections 5-1401 and 5-1402 of the New York General Obligations Law).

(b)This Guaranty shall be binding upon Guarantor and its successors and permitted assigns and inure to the benefit of and be enforceable by Counterparty and its successors and permitted assigns. Guarantor may not assign this Guaranty in part or in whole without the prior written consent of Counterparty. Counterparty may not assign its rights or benefits under this Guaranty in part or in whole without the prior written consent of Guarantor.

(c)This Guaranty embodies the entire agreement and understanding between Guarantor and Counterparty and supersedes all prior agreements and understandings relating to the subject matter hereof.

(d)The headings in this Guaranty are for purposes of reference only, and shall not affect the meaning hereof. Words importing the singular number hereunder shall include the plural number and vice versa, and any pronouns used herein shall be deemed to cover all genders. The term "person" as used herein means any individual, corporation, partnership, joint venture, limited liability company, association, joint-stock company, trust, unincorporated association, or government (or any agency or political subdivision thereof).

(e)Wherever possible, any provision in this Guaranty which is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective only to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any one jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

(f)Counterparty (by its acceptance of this Guaranty) and Guarantor each hereby irrevocably: (i) consents and submits to the exclusive jurisdiction of the United States District Court for the Southern District of New York, or if that court does not have subject matter jurisdiction, to the exclusive jurisdiction of the Supreme Court of the State of New York, New York County (without prejudice to the right of any party to remove to the United States District Court for the Southern District of New York) for the purposes of any suit, action or other proceeding arising out of this Guaranty or the subject matter hereof or any of the transactions contemplated hereby brought by Counterparty, Guarantor or their respective successors or assigns; and (ii) waives (to the fullest extent permitted by applicable law) and agrees not to assert any claim that it is not personally subject to the jurisdiction of the above-named courts, that the suit, action or proceeding is brought in an inconvenient forum, that the venue of the suit, action or proceeding is improper or that this Guaranty or the subject matter hereof may not be enforced in or by such court.

(g)COUNTERPARTY (BY ITS ACCEPTANCE OF THIS GUARANTY) AND GUARANTOR EACH HEREBY IRREVOCABLY, INTENTIONALLY AND VOLUNTARILY WAIVES THE RIGHT TO TRIAL BY JURY WITH RESPECT TO ANY LEGAL PROCEEDING BASED ON, OR ARISING OUT OF, UNDER OR IN

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CONNECTION WITH, THIS GUARANTY OR THE AGREEMENT, OR ANY COURSE OF CONDUCT, COURSE OF DEALING, STATEMENTS (WHETHER VERBAL OR WRITTEN) OR ACTIONS OF ANY PERSON RELATING HERETO OR THERETO. THIS PROVISION IS A MATERIAL INDUCEMENT TO GUARANTOR’S EXECUTION AND DELIVERY OF THIS GUARANTY.

(h)    Delivery of an executed signature page of this Guaranty by facsimile or email shall be effective as delivery of a manually executed counterpart hereof. The words “execute,” “execution,” “signed,” “signature,” and words of similar import in this Guaranty shall be deemed to include electronic signatures or digital signatures, or the keeping of records in electronic form, each of which shall be of the same legal effect, validity or enforceability as manually executed signatures or a paper-based recordkeeping system, as the case may be, to the extent and as provided for under applicable law, including the Electronic Signatures in Global and National Commerce Act of 2000, the Electronic Signatures and Records Act of 1999, or any other similar state laws based on the Uniform Electronic Transactions Act.

*        *        *

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IN WITNESS WHEREOF, Guarantor has executed this Guaranty on [_________ , 202_], but it is effective as of the Effective Date.

NEXTERA ENERGY CAPITAL HOLDINGS, INC.

By:________________________________________

Name:______________________________________

Title:_______________________________________

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EXHIBIT E-2

FORM OF BUYER’S GUARANTY

THIS GUARANTY (this “Guaranty”), dated as of [_________ , 202_] (the “Effective Date”), is made by [INSERT GUARANTOR NAME], a [Insert jurisdiction and type of entity] (“Guarantor”), in favor of NEXTERA ENERGY POINT BEACH, LLC, a Wisconsin limited liability company (“Counterparty”).

RECITALS:

A.WHEREAS, Counterparty and Guarantor’s [direct] [indirect], wholly-owned subsidiary WISCONSIN ELECTRIC POWER COMPANY, a Wisconsin corporation (“Obligor”) have entered into, or concurrently herewith are entering into, that certain Power Purchase

Agreement dated as of [______ , 202_] (the “Agreement”); and

B.WHEREAS, Guarantor will directly or indirectly benefit from the Agreement between Obligor and Counterparty;

NOW THEREFORE, in consideration of the foregoing premises and as an inducement for Counterparty’s execution, delivery and performance of the Agreement, and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, Guarantor hereby agrees for the benefit of Counterparty as follows:

*        *        *

1.GUARANTY. Subject to the terms and provisions hereof, Guarantor hereby absolutely and irrevocably guarantees the timely payment when due of all obligations owing by Obligor to Counterparty arising pursuant to the Agreement on or after the Effective Date (the “Obligations”). This Guaranty shall constitute a guarantee of payment and not of collection. The obligation and liability of Guarantor under this Guaranty shall be subject to the following limitations:

(a)Notwithstanding anything herein or in the Agreement to the contrary, the maximum aggregate obligation and liability of Guarantor under this Guaranty, and the maximum recovery from Guarantor under this Guaranty, shall in no event exceed One Hundred Million U.S. Dollars (U.S. $100,000,000.00) (the “Maximum Recovery Amount”).

(b)The obligation and liability of Guarantor under this Guaranty is specifically limited to payments expressly required to be made under the Agreement, as well as costs of collection and enforcement of this Guaranty (including attorney’s fees) to the extent reasonably and actually incurred by the Counterparty (subject in all instances, to the limitations imposed by the Maximum Recovery Amount as specified in Section 0 above). In no event, however, shall Guarantor be liable for or obligated to pay any consequential, indirect, incidental, lost profit, special, exemplary, punitive, equitable or tort damages.

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1)DEMANDS AND PAYMENT.

(a)If Obligor fails to pay any Obligation to Counterparty when such Obligation is due and owing under the Agreement (an “Overdue Obligation”), Counterparty may present a written demand to Guarantor calling for Guarantor’s payment of such Overdue Obligation pursuant to this Guaranty (a “Payment Demand”).

(b)Guarantor’s obligation hereunder to pay any particular Overdue Obligation(s) to Counterparty is conditioned upon Guarantor’s receipt of a Payment Demand from Counterparty satisfying the following requirements: (i) such Payment Demand must identify the specific Overdue Obligation(s) covered by such demand, the specific date(s) upon which such Overdue Obligation(s) became due and owing under the Agreement, and the specific provision(s) of the Agreement pursuant to which such Overdue Obligation(s) became due and owing; (ii) such Payment Demand must be delivered to Guarantor in accordance with Section 9 below; and (iii) the specific Overdue Obligation(s) addressed by such Payment Demand must remain due and unpaid at the time of such delivery to Guarantor.

(c)After issuing a Payment Demand in accordance with the requirements specified in Section 2(b) above, Counterparty shall not be required to issue any further notices or make any further demands with respect to the Overdue Obligation(s) specified in that Payment Demand, and Guarantor shall be required to make payment with respect to the Overdue Obligation(s) specified in that Payment Demand within five (5) Business Days after Guarantor receives such demand. As used herein, the term “Business Day” shall mean all weekdays (i.e., Monday through Friday) other than any weekdays during which commercial banks or financial institutions are authorized to be closed to the public in the State of Florida, the State of Wisconsin or the State of New York.

2)REPRESENTATIONS AND WARRANTIES. Guarantor represents and warrants that:

(a)it is a corporation duly organized and validly existing under the laws of the State of [●] and has the corporate power and authority to execute, deliver and carry out the terms and provisions of this Guaranty;

(b)no authorization, approval, consent or order of, or registration or filing with, any court or other governmental body having jurisdiction over Guarantor is required on the part of Guarantor for the execution and delivery of this Guaranty; and

(c)this Guaranty constitutes a valid and legally binding agreement of Guarantor, enforceable against Guarantor in accordance with the terms hereof, except as the enforceability thereof may be limited by the effect of any applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting creditors' rights generally and by general principles of equity.

3)RESERVATION OF CERTAIN DEFENSES. Without limiting Guarantor’s own defenses and rights hereunder, Guarantor reserves to itself all rights, setoffs, counterclaims and other defenses to which Obligor is or may be entitled arising from or out of the Agreement, except

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for defenses (if any) based upon the bankruptcy, insolvency, dissolution or liquidation of Obligor or any lack of power or authority of Obligor to enter into and/or perform the Agreement.

4)AMENDMENT OF GUARANTY. No term or provision of this Guaranty shall be amended, modified, altered, waived or supplemented except in a writing signed by Guarantor and Counterparty.

5)WAIVERS AND CONSENTS. Subject to and in accordance with the terms and provisions of this Guaranty:

(a)The liability of Guarantor under this Guaranty shall be irrevocable, absolute and unconditional irrespective of, and without limiting the foregoing, Guarantor hereby irrevocably waives any defenses it may now have or hereafter acquire in any way relating to, any or all of:

(i)promptness, diligence, presentment, demand of payment, acceptance, notice of acceptance, protest, notice of dishonor and any other notices with respect to any of the Guaranteed Obligations and this Guaranty, except as set forth in Section 2 above;

(ii)any right to require that any action or proceeding be brought against Obligor or any other person, or to require that Counterparty seek enforcement of any performance against Obligor or any other person, prior to any action against Guarantor under the terms hereof;

(iii)any change in the time, manner or place of payment of, or in any other term of, all or any of the Guaranteed Obligations (including renewals, extensions or other alterations thereof), or any other amendment, modification or waiver of, or any consent to departure from, the terms of such Guaranteed Obligations;

(iv)the release of any person (other than Obligor or Guarantor) from liability for payment of all or any of the Obligations or any receipt, substitution, surrender, exchange or release any collateral or other security for any or all of the Guaranteed Obligations;

(v)the occurrence or continuance of any event of bankruptcy, reorganization or insolvency with respect to Obligor, or any disallowance of all or any portion of any claim by Counterparty, its successors or assigns in connection with any such proceeding or in the event that all or any part of any payment is recovered from Counterparty as a preference payment or fraudulent transfer under the Federal Bankruptcy Code or any applicable law, or the dissolution, liquidation or winding up of Guarantor or Obligor;

(vi)any right of set-off or counterclaim against or in respect of the obligations of Guarantor hereunder, except as set forth in Section 4 above;

( )    any change, restructuring or termination of the corporate structure or existence of Obligor or any of its subsidiaries, including by merger, consolidation, transfer of interests or other change in ownership or control;

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(viii)any lack of validity or enforceability of the Agreement, this Guaranty or any other agreement, document or instrument related to the transactions contemplated hereby or thereby;

( )    any failure of Counterparty to disclose to either Obligor or Guarantor any information relating to the business, condition (financial or otherwise), operations, performance, properties or prospects of either Obligor or any of its subsidiaries now or hereafter known to Counterparty (Guarantor waiving any duty on the part of Counterparty to disclose such information);

(i)any lack of due diligence by Counterparty in the creation, perfection, collection or protection of or realization upon any collateral securing, or guaranty of, the Guaranteed Obligations;

(ii)any permitted assignment of the Agreement, this Guaranty or any agreement or instrument relating thereto or hereto by Counterparty; or

(ix)any circumstance whatsoever or any act of Counterparty or any existence of or reliance on any representation by Counterparty that might otherwise constitute a legal or equitable defense available to, or a discharge of, a guarantor or surety.

(b)No delay by Counterparty in the exercise of (or failure by Counterparty to exercise) any rights hereunder shall operate as a waiver of such rights, a waiver of any other rights or a release of Guarantor from its obligations hereunder (with the understanding, however, that the foregoing shall not be deemed to constitute a waiver by Guarantor of any rights or defenses which Guarantor may at any time have pursuant to or in connection with any applicable statutes of limitation).

(c)Guarantor hereby irrevocably, unconditionally and expressly waives, and agrees that it shall not at any time insist upon, plead or in any manner whatsoever claim or take the benefit or advantage of, any appraisal, valuation, stay, extension, marshaling of assets or redemption laws, or exemption, whether now or at any time hereafter in force, which may delay, prevent or otherwise affect the performance by Guarantor of its obligations under, or the enforcement by Counterparty of, this Guaranty.

6)REINSTATEMENT. Guarantor agrees that this Guaranty shall continue to be effective or shall be reinstated, as the case may be, if all or any part of any payment made hereunder is at any time avoided or rescinded or must otherwise be restored or repaid by Counterparty as a result of the bankruptcy or insolvency of Obligor, all as though such payments had not been made.

7)TERMINATION. This Guaranty and Guarantor’s obligations hereunder will terminate automatically and immediately upon the termination or expiration of the Agreement; provided, however, that no such termination shall affect Guarantor's liability with respect to any Obligation incurred prior to the time the termination is effective, which Obligation shall remain subject to this Guaranty.

8)NOTICE. Any Payment Demand, notice, request, instruction, correspondence or other document to be given hereunder (herein collectively called “Notice”) by Counterparty to

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Guarantor, or by Guarantor to Counterparty, as applicable, shall be in writing and may be delivered either by (i) U.S. certified mail with postage prepaid and return receipt requested, or (ii) recognized nationwide courier service with delivery receipt requested, in either case to be delivered to the following address (or to such other U.S. address as may be specified via Notice provided by Guarantor or Counterparty, as applicable, to the other in accordance with the requirements of this Section 9):

TO GUARANTOR: [*]			TO COUNTERPARTY: [*]
			NEXTERA ENERGY POINT BEACH, LLC 700 Universe Blvd. Juno Beach, Florida 33408 Attn: Matthew Roskot and General
			Counsel
[Tel: ( ) _ _ _ for use in			[Tel: (561) 694-6204 -- for use in connection with courier deliveries]
connection with courier deliveries]

*    (NOTE: Copies of any Notices to Counterparty under this Guaranty shall also be sent via facsimile to ATTN: Contracts Group, Legal, Fax No. (561) 625-7504 and ATTN: Credit Department, Fax No. (561) 625-7642. However, such facsimile transmissions shall not be deemed effective for delivery purposes under this Guaranty.)

Any Notice given in accordance with this Section 9 will (i) if delivered during the recipient's normal business hours on any given Business Day, be deemed received by the designated recipient on such date, and (ii) if not delivered during the recipient's normal business hours on any given Business Day, be deemed received by the designated recipient at the start of the recipient's normal business hours on the next Business Day after such delivery.

9)MISCELLANEOUS.

(a)This Guaranty shall in all respects be governed by, and construed in accordance with, the law of the State of Wisconsin, without regard to principles of conflicts of laws thereunder that would result in the application of any law other than the law of the State of Wisconsin.

(b)This Guaranty shall be binding upon Guarantor and its successors and permitted assigns and inure to the benefit of and be enforceable by Counterparty and its successors and permitted assigns. Guarantor may not assign this Guaranty in part or in whole without the prior written consent of Counterparty. Counterparty may not assign its rights or benefits under this Guaranty in part or in whole without the prior written consent of Guarantor.

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(c)This Guaranty embodies the entire agreement and understanding between Guarantor and Counterparty and supersedes all prior agreements and understandings relating to the subject matter hereof.

(d)The headings in this Guaranty are for purposes of reference only, and shall not affect the meaning hereof. Words importing the singular number hereunder shall include the plural number and vice versa, and any pronouns used herein shall be deemed to cover all genders. The term "person" as used herein means any individual, corporation, partnership, joint venture, limited liability company, association, joint-stock company, trust, unincorporated association, or government (or any agency or political subdivision thereof).

(e)Wherever possible, any provision in this Guaranty which is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective only to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any one jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

(f)Counterparty (by its acceptance of this Guaranty) and Guarantor each hereby irrevocably:

(i)consents and submits to the exclusive jurisdiction of the United States District Court for the Eastern District of Wisconsin, or if that court does not have subject matter jurisdiction, to the exclusive jurisdiction of the Circuit Court for Manitowoc County (without prejudice to the right of any party to remove to the United States District Court for the Eastern District of Wisconsin) for the purposes of any suit, action or other proceeding arising out of this Guaranty or the subject matter hereof or any of the transactions contemplated hereby brought by Counterparty, Guarantor or their respective successors or assigns; and (ii) waives (to the fullest extent permitted by applicable law) and agrees not to assert any claim that it is not personally subject to the jurisdiction of the above-named courts, that the suit, action or proceeding is brought in an inconvenient forum, that the venue of the suit, action or proceeding is improper or that this Guaranty or the subject matter hereof may not be enforced in or by such court.

(g)COUNTERPARTY (BY ITS ACCEPTANCE OF THIS GUARANTY) AND GUARANTOR EACH HEREBY IRREVOCABLY, INTENTIONALLY AND VOLUNTARILY WAIVES THE RIGHT TO TRIAL BY JURY WITH RESPECT TO ANY LEGAL PROCEEDING BASED ON, OR ARISING OUT OF, UNDER OR IN CONNECTION WITH, THIS GUARANTY OR THE AGREEMENT, OR ANY COURSE OF CONDUCT, COURSE OF DEALING, STATEMENTS (WHETHER VERBAL OR WRITTEN) OR ACTIONS OF ANY PERSON RELATING HERETO OR THERETO. THIS PROVISION IS A MATERIAL INDUCEMENT TO GUARANTOR’S EXECUTION AND DELIVERY OF THIS GUARANTY.

(h)Delivery of an executed signature page of this Guaranty by facsimile or email shall be effective as delivery of a manually executed counterpart hereof. The words “execute,” “execution,” “signed,” “signature,” and words of similar import in this Guaranty shall be deemed to include electronic signatures or digital signatures, or the keeping of records in electronic form, each of which shall be of the same legal effect, validity or enforceability as manually executed signatures or a paper-based recordkeeping system, as the case may

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be, to the extent and as provided for under applicable law, including the Electronic Signatures in Global and National Commerce Act of 2000, the Electronic Signatures and Records Act of 1999, or any other similar state laws based on the Uniform Electronic Transactions Act.

*        *        *

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IN WITNESS WHEREOF, Guarantor has executed this Guaranty on [_________ , 202_], but it is effective as of the Effective Date.

[INSERT GUARANTOR NAME]

By:_______________________________________

Name:____________________________________

Title:_____________________________________

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EXHIBIT F

FORM OF LETTER OF CREDIT

[ISSUING BANK] IRREVOCABLE STANDBY LETTER OF CREDIT

DATE OF ISSUANCE:

[Date of issuance]

[BENEFICIARY] (“Beneficiary”)

[Address]

Attention: [Contact Person]

Re: [ISSUING BANK] Irrevocable Standby Letter of Credit No._

Sirs/Mesdames:

We hereby establish in favor of Beneficiary (sometimes alternatively referred to herein as “you”) this Irrevocable Standby Letter of Credit No. __________ (the “Letter of Credit”) for the account of [Insert Applicant Name], located at [Insert Account Party Address] (“Account Party”), effective immediately and expiring on the date determined as specified in numbered paragraph 5 below.

We have been informed that this Letter of Credit is issued pursuant to the terms of that certain Power Purchase Agreement, dated as of _____, between Account Party and Beneficiary (the “Agreement”).

1.Stated Amount. The maximum amount available for drawing by you under this Letter of Credit shall be [written dollar amount] United States Dollars (US$[dollar amount]) (such maximum amount referred to as the “Stated Amount”).

2.Drawings. A drawing hereunder may be made by you on any Business Day on or prior to the date this Letter of Credit expires by delivering to [ISSUING BANK], at any time during its business hours on such Business Day, at [bank address] (or at such other address as may be designated by written notice delivered to you as contemplated by numbered paragraph 8 hereof), a copy of this Letter of Credit together with (i) a Draw Certificate executed by an authorized person substantially in the form of Attachment A hereto (the “Draw Certificate”), appropriately completed and signed by your authorized officer (signing as such) and (ii) your draft substantially in the form of Attachment B hereto (the “Draft”), appropriately completed and signed by your authorized officer (signed as such). Partial drawings and multiple presentations may be made under this Letter of Credit. Draw Certificates and Drafts under this Letter of Credit may be presented by Beneficiary by means of facsimile to our fax no. [insert fax number] or original documents sent by overnight delivery or courier to [ISSUING BANK] at our address set forth above, Attention:___________ (or at such other address as may be designated by written notice delivered to you as contemplated by numbered paragraph 8 below). If presentation is made by facsimile transmission, you must contact us at [insert phone number] to confirm our receipt of the transmission. In the event of a presentation by facsimile transmission, the original of such documents need not be sent to us.

3.Time and Method for Payment. We hereby agree to honor a drawing hereunder made in compliance with this Letter of Credit by transferring in immediately available funds the amount specified in the Draft delivered to us in connection with such drawing to such account at such bank in the United States as you may specify in your Draw Certificate. If the Draw Certificate is presented to us at such

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address by 12:00 noon, (Eastern Standard Time) time on any Business Day, payment will be made not later than our close of business on third succeeding business day and if such Draw Certificate is so presented to us after 12:00 noon, (Eastern Standard Time) time on any Business Day, payment will be made on the fourth succeeding Business Day. In clarification, we agree to honor the Draw Certificate as specified in the preceding sentences, without regard to the truth or falsity of the assertions made therein.

4.Non-Conforming Demands. If a demand for payment made by you hereunder does not, in any instance, conform to the terms and conditions of this Letter of Credit, we shall give you prompt notice not later than two Business Day that the demand for payment was not effectuated in accordance with the terms and conditions of this Letter of Credit, stating the reasons therefor and that we will upon your instructions hold any documents at your disposal or return the same to you. Upon being notified that the demand for payment was not effectuated in conformity with this Letter of Credit, you may correct any such non­conforming demand and re-submit on or before the then current expiry date.

5.Expiration, Initial Period and Automatic Extension. The initial period of this Letter of Credit shall terminate on [one year from the issuance date] (the “Initial Expiration Date”). The Letter of Credit shall be automatically extended without amendment for one (1) year periods from the Initial Expiration Date or any future expiration date, unless at least sixty (60) days prior to any such expiration date we send you notice by registered mail or courier at your address first shown (or such other address as may be designated by you as contemplated by numbered paragraph 8) that we elect not to consider this Letter of Credit extended for any such additional one year period. Notwithstanding the foregoing extension provision, this Letter of Credit shall automatically expire at the close of business on the date on which we receive a Cancellation Certificate in the form of Attachment C hereto executed by your authorized officer and sent along with the original of this Letter of Credit and all amendments (if any). Upon receipt by you of such notice of non-extension, you may draw hereunder up to the available amount, on or before the then current expiry date, against presentation to us of your Draft, appropriately completed and signed by your authorized officer (signed as such).

6.Business Day. As used herein, “Business Day” shall mean any day on which commercial banks are not authorized or required to close in the State of New York, and inter-bank payments can be effected on the Fedwire system.

7.Governing Law. THIS LETTER OF CREDIT IS GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH THE INTERNATIONAL STANDBY PRACTICES, ICC PUBLICATION NO. 590 (THE “ISP98”), AND AS TO MATTERS NOT ADDRESSED IN ISP98, BY THE LAWS OF THE STATE OF NEW YORK.

8.Notices. All communications to you in respect of this Letter of Credit shall be in writing and shall be delivered to the address first shown for you above or such other address as may from time to time be designated by you in a written notice to us. All documents to be presented to us hereunder and all other communications to us in respect of this Letter of Credit, which other communications shall be in writing, shall be delivered to the address for us indicated above, or such other address as may from time to time be designated by us in a written notice to you.

9.Irrevocability. This Letter of Credit is irrevocable.

10.Complete Agreement. This Letter of Credit sets forth in full our undertaking, and such undertaking shall not in any way be modified, amended, amplified or limited by reference to any document, instrument or agreement referred to herein, except for the ISP98 and Attachment A, Attachment B and Attachment C hereto and the notices referred to herein and any such reference shall not be deemed to incorporate herein by reference any document, instrument or agreement except as set forth above.

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Sincerely,

[ISSUING BANK]

_________________________________

By: _

Title:

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ATTACHMENT A

FORM OF DRAW CERTIFICATE

TO: [ISSUING BANK]

[Address]

The undersigned hereby certifies to [ISSUING BANK] (“Issuer”), with reference to Irrevocable Letter of Credit No. ___________________ (the “Letter of Credit”) issued by Issuer in favor of the undersigned (“Beneficiary”), as follows:

(1)The undersigned is the ______________ of Beneficiary and is duly authorized by Beneficiary to execute and deliver this Certificate on behalf of Beneficiary.

(2)Beneficiary hereby makes demand against the Letter of Credit by Beneficiary’s presentation of the draft accompanying this Certificate, for payment of_________________________ U.S. dollars (US$_________ ), which amount, when aggregated together with any additional amount that has not been drawn under the Letter of Credit, is not in excess of the Stated Amount (as in effect of the date hereof).

(3)[The Account Party has failed to perform its obligations under the Agreement when due.]

(4)You are hereby directed to make payment of the requested drawing to: (insert wire instructions)

Beneficiary Name and Address:

By:_____________________

Title:____________________

Date:____________________

(5)Capitalized terms used herein and not otherwise defined herein shall have the respective meanings set forth in the Letter of Credit.

[INSERT BENEFICIARY NAME]

By:_____________________

Title:____________________

Date:___________________

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ATTACHMENT B

DRAWING UNDER IRREVOCABLE LETTER OF CREDIT NO.

TO: [ISSUING BANK]

[Address]

Date:

PAY TO: [INSERT BENEFICIARY NAME]

U.S.$_________________

FOR VALUE RECEIVED AND CHARGE TO THE ACCOUNT OF LETTER OF CREDIT NO. .

[INSERT BENEFICIARY NAME]

By:_____________________

Title:____________________

Date:____________________

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ATTACHMENT C

CANCELLATION CERTIFICATE

TO: [ISSUING BANK]

[Address]

Irrevocable Letter of Credit No.

The undersigned, being authorized by the undersigned (“Beneficiary”), hereby certifies on behalf of Beneficiary to [ISSUING BANK] (“Issuer”), with reference to Irrevocable Letter of Credit No. _____________ issued by Issuer to Beneficiary (the “Letter of Credit”), that it is returning the Letter of Credit to Issuer for cancellation.

Pursuant to Section 5 thereof, the Letter of Credit shall expire upon Issuer’s receipt of this certificate.

Capitalized terms used herein and not otherwise defined herein shall have the respective meanings set forth in the Letter of Credit.

[INSERT BENEFICIARY NAME]

By:_____________________

Title:____________________

Date:____________________

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EXHIBIT G

PEAK ADJUSTMENT PAYMENT

During each month of June, July and August for each Calendar Year during the relevant Delivery Period of the Term (the “Peak Period”), Seller must achieve the Target Capacity Factor for the Facilities as set forth in this Exhibit G. If Seller fails to achieve such Target Capacity Factor for any such month, Seller shall be responsible for a payment to Buyer (the “Peak Adjustment Payment”) calculated in accordance with the following formula:

[    ] (in 2030 dollars escalating by [    ] for each year of the Term)

where

TEM = Targeted Energy for the month, which shall be the product of: (i) the applicable capacity amount for the month (as set forth pursuant to the then-prevailing version of Exhibit B); (ii) the number of hours in the month; and (iii) the Target Capacity Factor.

DEM = Delivered Energy for the month.

If the resulting product of the above formula is positive, then such positive amount shall equal the Peak Adjustment Payment for the month in question and Seller shall pay that Peak Adjustment Payment in accordance with this Exhibit G. If the resulting product is zero or negative, then neither Seller nor Buyer shall owe a Peak Adjustment Payment for the month.

If it is determined that Seller owes Buyer a Peak Adjustment Payment for a particular month, Buyer shall have the right to either (a) demand payment of that Peak Adjustment Payment in writing, in which case Seller shall make such payment to Buyer within five (5) Business Days after the written demand for payment is received, or (b) include the Peak Adjustment Payment on the invoices for such Billing Cycle pursuant to Section 7.1(a).

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EXHIBIT H

SCHEDULING PROVISIONS

(a)Scheduling of Generation Offers. Seller, shall submit its Generation Offer, as a DNR, for the Facilities into the MISO Day-Ahead Market and the MISO Real-Time Market for dispatch with a dispatch minimum for each hour of the Operating Day equal to no less than the full expected Net Energy Output (consistent with the MISO Tariff) except as agreed otherwise by Buyer, provided, however, that during any Derate, Seller shall be obligated to schedule Generation Offers under Section 4.1 and this Exhibit H with respect to the full expected Net Energy Output, and provided further that Seller shall reasonably coordinate with Buyer in responding to a negative LMP.

(b)Scheduling of Financial Bilateral Transactions.

Unless otherwise mutually agreed by the Parties, for each Operating Day, Seller shall submit one or more MISO FinScheds that reflect the Buyer’s Product Share of the Net Energy Output plus any Replacement Energy for such Operating Day and Buyer shall accept each such MISO FinSched no later than the deadline established by MISO for such acceptance, with each utilizing the appropriate MISO electronic scheduling system and protocols in accordance with the following Scheduling parameters:

(i)Seller and Buyer shall work together using commercially reasonable efforts to provide the necessary documentation to MISO to facilitate the processing of MISO FinScheds;

(ii)At least forty-eight (48) hours prior to the deadline established by MISO, but no later than two Business Days after the relevant Operating Day (the “Scheduling Window”), Seller shall submit a MISO FinSched for settlement in the MISO Day-Ahead Market for Buyer’s Product Share of the actual Net Energy Output or Replacement Energy or both, as applicable, for the relevant Operating Day;

(iii)At least forty-eight (48) hours prior to the deadline established by MISO, Seller shall enter the MISO FinScheds under MISO Financial Bilateral Contracts with the following settings: (i) “Settlement Market” shall be “Day Ahead”; “Source Location” shall be the CPNode; “Delivery Point” shall be the CPNode; “Sink Location” shall be the WEC.S; and (iii) “Scheduling Approval” shall be set to “Seller AutoApproval.” If Buyer disputes any component of any MISO FinScheds submitted by Seller, then the Parties will subsequently work together to resolve any disputes raised by Buyer regarding the MISO FinScheds within the deadline established by MISO for the modification of MISO FinScheds; and

(iv)No true-up to the MISO FinSched shall be made; provided, that Seller may make revisions to any MISO FinSched during the applicable Scheduling

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Window by giving Buyer email notice of such revision(s) with confirmation (by e-mail) as soon as practicable.

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EXHIBIT I

MISO BUSINESS PRACTICE MANUAL

(as attached)

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EXHIBIT J

REPLACEMENT ENERGY PROVISIONS

(A)    Replacement Energy Generally

In order to clarify the circumstances and conditions under which Seller will be entitled to furnish Replacement Energy under the Agreement during any Derate associated with a Scheduled Maintenance Outage or an Unscheduled Outage and the circumstances and conditions under which certain Replacement Energy may be used to satisfy the Target Capacity Factor during such Derate, the following procedures shall govern Seller’s right to supply Replacement Energy pursuant to Section 2.4(a) of the Agreement and its right to apply any Replacement Energy furnished to the Target Capacity Factor:

1.In order to effectively elect to supply, and in order to effectively supply, Replacement Energy, Seller must deliver to Buyer a properly completed and delivered Replacement Energy Notice (a “Replacement Energy Notice”), in the form attached and labeled as Schedule A to this Exhibit J, which shall comply in all respects, and shall demonstrate that the elected attempt to supply Replacement Energy complies in all respects, with the conditions and requirements set forth herein and in the Agreement.

2.A Replacement Energy Notice with respect to any Scheduled Outage for which Replacement Energy is to be provided must be received by Buyer via e-mail addressed to: [ ] (or such successors as Buyer shall appoint by notice to Seller) on or before the Notice Time.

3.A Replacement Energy Notice with respect to any Unscheduled Outages for which Replacement Energy is to be provided must be received by Buyer via e-mail addressed to: [ ] (or such successors as Buyer shall appoint by notice to Seller) no later than the Notice Time.

4.Each Replacement Energy Notice must include: the actual (if the Derate has then occurred) or (if the Derate is expected to occur in the future) the estimated date and time of the Derate, and, in each case, the estimated Net Energy Output of each Unit for each of the 168 consecutive hours of the Replacement Energy period (the 168 consecutive hour period commencing with the first hour that Replacement Energy is Scheduled to be provided with respect to a particular Derate and ending on the earlier of (A) the end of the 168th consecutive hour thereafter, or (B) the end of the hour during which such Derate is remedied, is herein referred to as a “Replacement Energy Period”).

5.Each Replacement Energy Notice must include Seller’s best good-faith estimate of the Net Energy Output from each Unit for the 168 consecutive hours commencing with the first hour for which Replacement Energy is to be provided by Seller. In order for any

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purported Replacement Energy Notice to be valid and effective, the 168-hour estimate of Net Energy Output for each Unit for the days included therein must be the same as the corresponding information for the corresponding days that are contained in the then most recent seven-day “PBNP Power Projection” received by Buyer from Point Beach plant personnel. Seller covenants and agrees that it will continue throughout the Term of the Agreement to provide seven-day PBNP Power Projections to Buyer in the same form, prepared in the same manner and prepared by personnel at the same level and with the same degree of care as the same are being furnished to Buyer as of the Settlement Effective Date.

6.Seller may revise the estimated Net Energy Output on a daily basis to reflect accurately operating conditions at the Facilities or to reflect one or more additional Derate events occurring during (or overlapping with) a particular Replacement Energy Period, any such change to be consistent with a corresponding revision of the PBNP Power Projection for each affected hour of the Replacement Energy period in question. In order to revise the estimated Net Energy Output, NextEra shall deliver a properly completed Replacement Energy Revised Estimate in the form attached and labeled as Schedule B to this Exhibit J, which shall be delivered by Seller to Buyer via email addressed to:[ ] (or such successors as Buyer shall appoint by notice to NextEra) prior to the Notice Time and shall be effective as and when so delivered.

7.The quantity of Replacement Energy that shall be supplied during each hour of the Replacement Energy Period in question shall be equal to (and not more or less than) the Buyer’s Capacity Amount (as defined in the Agreement) less the then-current estimate for such hour of Net Energy Output delivered by Seller to Buyer pursuant to Paragraphs 5 and 6, above. The combination of actual Net Energy Output and Replacement Energy for any hour during a Replacement Energy Period shall not exceed Buyer’s Capacity Amount with respect to such hour.

8.Replacement Energy is only permitted to be supplied upon the occurrence and during the continuance of a Derate event for which a valid and effective Replacement Energy Notice has been timely delivered and upon compliance with all of the other requirements and conditions contained herein and in the Agreement. Once a Derate event occurs, until it is remedied all events and circumstances that cause the Net Energy Output to meet the definition of “Derate” in the Agreement shall be considered to be part of the same original Derate.

9.Seller may supply Replacement Energy with respect to a Derate that is expected to last, or that in fact lasts, less than 168 consecutive hours.

10.Upon delivery by Seller of a complying Replacement Energy Notice, Seller will be obligated throughout the term of the related Replacement Energy Period to supply and deliver the quantities of Replacement Energy set forth in its Replacement Energy Notice, as the same may be superseded by a Replacement Energy Revised Notice.

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11.Notwithstanding the foregoing provisions hereof and the provisions of the Agreement, Replacement Energy may not be supplied with respect to a Unit during any period when the Energy production of such Unit is being ramped up or ramped down, except to the extent (and then only to the extent) that such ramp up or ramp down occurs during the Peak Period.

0.    (a)    Notwithstanding the foregoing provisions hereof and the provisions of the Agreement to the contrary, to the extent a Replacement Energy Notice is delivered by Seller that contemplates the supply of Replacement Energy in whole or in part during a Peak Period, or Replacement Energy is delivered during the Peak Period, and the Derate to which such Replacement Energy relates is remedied in less than 168 consecutive hours (a “Short Derate”), the Replacement Energy supplied during such Peak Period in respect of a Short Derate shall not be counted toward Seller’s obligation to meet the Target Capacity Factor, as required by Exhibit G and Section 3.2 of the Agreement, with respect to such Peak Period.

(b)    DEM (as defined in Exhibit G) shall not include any Replacement Energy supplied during such Peak Period in respect of a Short Derate.

(B)    Replacement Energy and Derates

1.For any Derate declared by Seller and whereby Seller has notified Buyer in accordance with the terms and conditions of the PPA:

(a)a Ramp Down Period (i) shall begin at the start of the Hour Ending (HE) clock-hour within which a Derate commences (as confirmed by a Ramp Down Notice), and (ii) shall expire at the end of the HE clock-hour within which the Unit has either (A) a zero (0) Energy production level, or (B) has achieved a stable Energy production level greater than zero (0) (each of (A) or (B), a “Stable Lever”), such Stable Level as confirmed in writing by Seller to Buyer transmitted electronically within twenty-four (24) hours of achieving such Stable Level (a “Stable Energy Notice”), the receipt of which is Acknowledged by Buyer; provided, if, within the twenty-four (24) hour period immediately following the expiration of the Ramp Period, the affected Unit’s Energy production level increases or decreases by more than five percent (5%) from the Stable Level, then Seller shall promptly issue a Ramp Notice to Buyer and the affected Unit shall no longer be at a Stable Level and the Ramp Period shall resume or be deemed continuing, provided, further, that after the twenty-four (24) hour period immediately following the expiration of the Ramp Period, a new Ramp Period shall commence once the affected Unit’s Energy production level increases or decreases by more than five percent (5%) from the Stable Level regardless of whether Seller has delivered a Ramp Notice; and

(b)a Ramp Up Period (i) shall begin at the end of the Hour Ending (HE) clock-hour within which a Unit commences to increase Energy production from the Stable Level (as confirmed by a Ramp Up Notice), and (ii) shall expire at the end of the HE clock-hour within which a Unit has achieved one hundred percent (100%) power or upon the occurrence of a Subsequent Derate (defined below); provided, if, within the twenty-four (24) hour period

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immediately following the expiration of the Ramp Period the affected Unit’s Energy production level increases or decreases by more than five percent (5%) of the Stable Level, then Seller shall promptly issue a Ramp Notice to Buyer and the affected Unit shall no longer be at a Stable Level and the Ramp Period shall resume and be deemed continuing, provided, further, that after the twenty-four (24) hour period immediately following the expiration of the Ramp Period, a new Ramp Period shall commence once the affected Unit’s Energy production level increases or decreases by more than five percent (5%) from the Stable Level regardless of whether Seller has delivered a Ramp Notice.

2.At no time shall Seller be permitted to provide Replacement Energy while in a Ramp Period associated with a Derate or Subsequent Derate (defined herein), except to the extent (and only to the extent) such Ramp Period occurs during the Peak Period and in accordance with the PPA.

3.If Buyer has Acknowledged a Ramp Notice with respect to a Unit, such Unit is in the Ramp Period, and a subsequent Derate outside of the Peak Period has occurred and is declared by Seller in accordance with the terms and conditions of the PPA (a “Subsequent Derate”), then Seller shall be permitted to supply Buyer with Replacement Energy with respect to the Subsequent Derate in accordance with Section 2.4 of the PPA; provided:

(a)Seller has notified Buyer in writing of the Subsequent Derate in accordance with Section 5.2 of the PPA or its equivalent (a “Subsequent Derate Notice”); and

(b)Seller shall not commence supplying Buyer with Replacement Energy solely with respect to such Subsequent Derate occurring outside of the Peak Period until each of the following has occurred (i) the issuance by Seller to Buyer of a Stable Energy Notice with respect to the Subsequent Derate, the receipt of which is Acknowledged by Buyer, and (ii) the first to occur of (A) a period of 120 full hours have elapsed from the issuance and Acknowledgement of such Stable Energy Notice pursuant to this subpart (d)(ii)(A), or (B) the Unit has a zero (0) Energy production level; and

(c)Seller shall discontinue supplying Buyer with Replacement Energy with respect to the Subsequent Derate if the affected Unit’s Energy production is no longer at a Stable Level as noted in the respective Ramp Notice. For the purposes of this subpart (d)(iii), if, within the twenty-four (24) hour period immediately following the expiration of the Ramp Period the affected Unit’s Energy production level increases or decreases by more than five percent (5%) of the Stable Level, then the affected Unit shall be deemed to be no longer at a Stable Level and the Ramp Period shall rest1me and be deemed continuing, provided, further, that after the twenty-four (24) hour period immediately following the expiration of the Ramp Period, a new Ramp Period shall commence once the affected Unit’s Energy production level increases or decreases by more than five percent (5%) from the Stable Level regardless of whether Seller has delivered a Ramp Notice.

4.The following conditions shall apply with respect to supplying Replacement Energy during any Derate or Subsequent Derate:

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(a)Seller may provide Buyer with Replacement Energy in accordance with the PPA;

(b)the amount of Replacement Energy supplied by Seller to Buyer with respect to an affected Unit shall not exceed the difference between (A) a power level equal to 50% of the then-current Buyer’s Capacity Amount, and (B) the Stable Level of the affected Unit (as confirmed in the applicable Stable Energy Notice);

(c)if Seller provides Buyer notice of its intent to discontinue its Replacement Energy election with respect to a Derate, then Seller may not subsequently provide Buyer with Replacement Energy for the remainder of such Derate, except upon the occurrence of a Subsequent Derate where the affected Unit has a zero (0) Energy production level, subject to compliance with subpart (d) of this Letter Agreement; and

(d)in the event Replacement Energy is being delivered with respect to one Unit (“Unit X”) and the other Unit (“Unit Y”) is in a Ramp Period outside of the Peak Period, then, for purposes of calculating the maximum estimated Replacement Energy to be supplied to Unit X during the pendency of Unit Y’s Ramp Period, the Parties agree that, (i) with respect to the calculation of Replacement Energy included in a Replacement Energy Notice, the estimated Energy production for the Unit Y in a Ramp Period shall be assumed to be the highest of the preceding three (3) hours prior to entering the Ramp Period, and (ii) with respect to the calculation of the Replacement Energy MISO FinSched for Unit X, the Energy production for the Unit Y in a Ramp Period shall be assumed to be the highest of the preceding three hours prior to entering the Ramp Period to ensure Buyer is not receiving Replacement Energy for Unit Y when in Ramp Period.

For the avoidance of doubt, it is the intention of the Parties in this Exhibit J to clarify the Parties’ intent with respect to certain provisions of the Agreement (in particular, the procedures to be used by them with respect to Replacement Energy) but not to modify or amend the Agreement. In the event of any apparent conflict between the provisions of the Agreement and the provisions of this Exhibit J, the provisions of this Exhibit J shall constitute evidence of the Parties’ intent with respect to the affected and relevant provisions of the Agreement.

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SCHEDULE A TO EXHIBIT J

FORM OF REPLACEMENT ENERGY NOTICE

This email serves as written notice that NextEra Energy Point Beach elects to provide Replacement Energy to Point Beach during the Derate event {BRIEFLY DESCRIBE EXPECTED DERATE EVENT] [scheduled to occur] [that has occurred] at Unit__. The Replacement Energy election will be effective for the Weekly Schedule of power flow dates [_/_/20_]_[0000] to[_/ _/20_] [2359]. Replacement Energy will be delivered to Delivery Point WEC.PTBHGB2. Pursuant to the PPA, NextEra Energy Point Beach is providing with this Replacement Energy Notice an hourly forecast that identifies the expected Net Energy Output from the Facilities. Such forecast may be modified on a daily basis pursuant to the terms of the PPA to comply with the requirements set forth therein. The FinSched Replacement Energy each day will be [MONTHLY BUYER’S CAPACITY AMOUNT FOR THE APPLICABLE MONTH] MW less the estimated Net Energy Output submitted by NextEra to WEPCO for the applicable Operating Day.

Thank you.

[Name, title and contact information for NextEra person furnishing notice]

Attachment:1

_______________________

1 NTD: Net Energy Output Week file to be provided at the time, based on then-prevailing metrics.

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SCHEDULE B TO EXHIBIT J

FORM OF REPLACEMENT ENERGY REVISED ESTIMATE NOTICE

This email serves as written notice that NextEra Energy Point Beach hereby revises its previously furnished estimate of Net Energy Output relating to its election to provide Replacement Energy to Point Beach during the Derate event [BRIEFLY DESCRIBE EXPECTED DERATE EVENT] [scheduled to occur] [that has occurred] at Unit_. The Replacement Energy Revised Estimate Notice will be effective for the Weekly Schedule of power flow dates[_/_/20_]_[ 0000] to [_/_/20_] [2359]. Replacement Energy will be delivered to Delivery Point WEC.PTBHGB2. Pursuant to the PPA, NextEra Energy Point Beach is providing with this Replacement Energy Revised Estimate Notice an hourly forecast that identifies the revised expected Net Energy Output from the Facilities. Such forecast may be modified on a daily basis pursuant to the terms of the PPA to comply with the requirements set forth therein. The FinSched Replacement Energy each day will be [MONTHLY BUYER’S CAPACITY AMOUNT FOR THE APPLICABLE MONTH] MW less the estimated Net Energy Output submitted by NextEra to WEPCO for the applicable Operating Day.

Thank you.

[Name, title and contact information for NextEra person furnishing notice]

Attachment:2

_______________________

2 NTD: Net Energy Output Week file to be provided at the time, based on then-prevailing metrics.

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EXHIBIT K

Performance Tests and Procedure

Procedures

1)The Performance Test shall consist of a four-hour test conducted simultaneously for both Units in accordance with the current MISO Business Practice Manual (as defined in the Transmission Provider Tariff) or other current Transmission Provider Tariff; provided, that if the MISO Business Practice Manual or other Transmission Provider Tariff is materially modified following the Effective Date (including in a manner that materially increases the burden of such test or otherwise results in a material change in the economic outcome of such tests, in each case, compared to such burden or results as of the Effective Date), then the Parties shall in good faith negotiate such modifications or amendments to such testing procedures to preserve the original intent of the Parties with respect thereto. Both Units shall be in operation throughout the duration of the Performance Test with the physical conditions of the Units being consistent with the requirements of MISO Business Practice Manual.

2)The Performance Test shall be conducted during the peak load period of the day.

3)The results of the Performance Test shall be corrected for the 4-hour Performance Test period by comparing the actual inlet circulating water temperature average for the 4-hour period to 650 F degree inlet circulating water temperatures with the correction MWe based on the Capacity Correction Curve listed in the Table 1 of this Attachment B (the “Capacity Test Correction”).

4)A Performance Test shall be performed prior to any Uprate to demonstrate and verify current Unit performance, in accordance with this Attachment. A predicted post Uprate set of monthly Buyer’s Capacity Amounts shall be provided by the Operator. The predicted Buyer’s Capacity Amounts shall be verified by (i) a Performance Test within one (1) year of the completion of the Uprate and (ii) review of one (1) year of operating data following such Uprate, and adjusted, if appropriate, to reflect the results of the Performance Test and the operating data.

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Table 1 Capacity Correction Curve

Circ Water Temperature (°F)			U1 Correction Coefficient (MWe)			U2 Correction Coefficient (MWe)
32			[ ]			[ ]
33			[ ]			[ ]
34			[ ]			[ ]
35			[ ]			[ ]
36			[ ]			[ ]
37			[ ]			[ ]
38			[ ]			[ ]
39			[ ]			[ ]
40			[ ]			[ ]
41			[ ]			[ ]
42			[ ]			[ ]
43			[ ]			[ ]
44			[ ]			[ ]
45			[ ]			[ ]
46			[ ]			[ ]
47			[ ]			[ ]
48			[ ]			[ ]
49			[ ]			[ ]
50			[ ]			[ ]
51			[ ]			[ ]
52			[ ]			[ ]
53			[ ]			[ ]
54			[ ]			[ ]
55			[ ]			[ ]
56			[ ]			[ ]
57			[ ]			[ ]
58			[ ]			[ ]
59			[ ]			[ ]
60			[ ]			[ ]
61			[ ]			[ ]
62			[ ]			[ ]
63			[ ]			[ ]
64			[ ]			[ ]
65			[ ]			[ ]
66			[ ]			[ ]
67			[ ]			[ ]
68			[ ]			[ ]
69			[ ]			[ ]
70			[ ]			[ ]
71			[ ]			[ ]
72			[ ]			[ ]
73			[ ]			[ ]
74			[ ]			[ ]
75			[ ]			[ ]
76			[ ]			[ ]
77			[ ]			[ ]
78			[ ]			[ ]
79			[ ]			[ ]
80			[ ]			[ ]

K-2

Exhibit 31.1

Certification Pursuant to

Rule 13a-14(a) or 15d-14(a),

as Adopted Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002

I, Scott J. Lauber, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of WEC Energy Group, Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an Annual Report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:			October 30, 2026
			/s/ SCOTT J. LAUBER
			Scott J. Lauber
			President and Chief Executive Officer
			(Principal Executive Officer)

Exhibit 31.2

Certification Pursuant to

Rule 13a-14(a) or 15d-14(a),

as Adopted Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002

I, Xia Liu, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of WEC Energy Group, Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an Annual Report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:			October 30, 2026
			/s/ XIA LIU
			Xia Liu
			Executive Vice President and Chief Financial Officer
			(Principal Financial Officer)

Exhibit 32.1

Certification Pursuant to

18 U.S.C. Section 1350,

As Adopted Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of WEC Energy Group, Inc. (the "Company") on Form 10-Q for the quarter ended September 30, 2026, as filed with the Securities and Exchange Commission on October 30, 2026 (the "Report"), I, Scott J. Lauber, President and Chief Executive Officer of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1)The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ SCOTT J. LAUBER
Scott J. Lauber
President and Chief Executive Officer
October 30, 2026

Exhibit 32.2

Certification Pursuant to

18 U.S.C. Section 1350,

As Adopted Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of WEC Energy Group, Inc. (the "Company") on Form 10-Q for the quarter ended September 30, 2026, as filed with the Securities and Exchange Commission on October 30, 2026 (the "Report"), I, Xia Liu, Executive Vice President and Chief Financial Officer of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1)The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ XIA LIU
Xia Liu
Executive Vice President and Chief Financial Officer
October 30, 2026