WEC ENERGY GROUP, INC. - Quarter Report: 2022 March (Form 10-Q)

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 March 31, 2022


☐			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

(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 (March 31, 2022):

Common Stock, $.01 Par Value, 315,434,531 shares outstanding

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WEC ENERGY GROUP, INC.

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended March 31, 2022

TABLE OF CONTENTS

Page

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

PART I.

FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS (UNAUDITED)

Condensed Consolidated Income Statements

Condensed Consolidated Statements of Comprehensive Income

Condensed Consolidated Balance Sheets

Condensed Consolidated Statements of Cash Flows

Condensed Consolidated Statements of Equity

Notes to Condensed Consolidated Financial Statements

Page

Regulatory Assets and Liabilities

Note 6

Property, Plant, and Equipment

Note 7

Common Equity

Note 8

Short-Term Debt and Lines of Credit

Note 9

Materials, Supplies, and Inventories

Note 10

Income Taxes

Note 11

Fair Value Measurements

Note 12

Derivative Instruments

Goodwill and Intangibles

Note 16

Investment in Transmission Affiliates

Note 17

Segment Information

Note 18

Variable Interest Entities

Note 19

Commitments and Contingencies

Note 20

Supplemental Cash Flow Information

Note 21

Regulatory Environment

Note 22

New Accounting Pronouncements

ITEM 2.

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

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 4.

CONTROLS AND PROCEDURES

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

ITEM 6.

EXHIBITS

SIGNATURE


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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

Bishop Hill III						Bishop Hill Energy III LLC
Blooming Grove						Blooming Grove Wind Energy Center LLC
Bluewater						Bluewater Natural Gas Holding, LLC
Coyote Ridge						Coyote Ridge Wind, LLC
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
Tatanka Ridge						Tatanka Ridge Wind LLC
UMERC						Upper Michigan Energy Resources Corporation

Upstream						Upstream Wind Energy LLC
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
Wispark						Wispark 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
IEPA						Illinois Environmental Protection Agency


MPUC						Minnesota Public Utilities Commission
PSCW						Public Service Commission of Wisconsin
SEC						United States Securities and Exchange Commission
WDNR						Wisconsin Department of Natural Resources

Accounting Terms



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
ACE						Affordable Clean Energy
BATW						Bottom Ash Transport Water

BTA						Best Technology Available
CAA						Clean Air Act
CASAC						Clean Air Scientific Advisory Committee
CO2						Carbon Dioxide

ELG						Steam Electric Effluent Limitation Guidelines


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FGD						Flue Gas Desulfurization
GHG						Greenhouse Gas
GMZ						Groundwater Management Zone

NAAQS						National Ambient Air Quality Standards
NOV						Notice of Violation
NOx						Nitrogen Oxide
VN						Violation Notice
WOTUS						Waters of the United States
WPDES						Wisconsin Pollutant Discharge Elimination System

Measurements
Dth						Dekatherm
MW						Megawatt
MWh						Megawatt-hour

Other Terms and Abbreviations
2007 Junior Notes						WEC Energy Group, Inc.'s 2007 Junior Subordinated Notes Due 2067

AD/CVD						Antidumping and Countervailing Duties
AG						Attorney General
AMI						Advanced Metering Infrastructure
Badger Hollow I						Badger Hollow Solar Park I
Badger Hollow II						Badger Hollow Solar Park II

CIP						Conservation Improvement Program
COVID-19						Coronavirus Disease – 2019

D.C. Circuit Court of Appeals						United States Court of Appeals for the District of Columbia Circuit
ERGS						Elm Road Generating Station
ESG Progress Plan						WEC Energy Group's Capital Investment Plan for Efficiency, Sustainability, and Growth for 2022-2026
ETB						Environmental Trust Bond
EV						Electric Vehicle
Exchange Act						Securities Exchange Act of 1934, as amended
Executive Order 13990						Executive Order 13990 of January 20, 2021 – Protecting Public Health and the Environment and Restoring Science To Tackle the Climate Crisis
FTR						Financial Transmission Right
GCRM						Gas Cost Recovery Mechanism

ITC						Investment Tax Credit
LIBOR						London Interbank Offered Rate
LNG						Liquefied Natural Gas
MISO						Midcontinent Independent System Operator, Inc.

OCPP						Oak Creek Power Plant


OC 7						Oak Creek Power Plant Unit 7
OC 8						Oak Creek Power Plant Unit 8

PPA						Power Purchase Agreement
PSB						Public Service Building
PTC						Production Tax Credit
PWGS						Port Washington Generation Station
QIP						Qualifying Infrastructure Plant
RICE						Reciprocating Internal Combustion Engine
RNG						Renewable Natural Gas
ROE						Return on Equity
Sapphire Sky						Sapphire Sky Wind Energy LLC
SMP						Safety Modernization Program


SPP						Southwest Power Pool, Inc.

Supreme Court						United States Supreme Court
Tax Legislation						Tax Cuts and Jobs Act of 2017
Thunderhead						Thunderhead Wind Energy LLC
TPTFA						Third-Party Transaction Fee Adjustment


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Two Creeks						Two Creeks Solar Park


West Riverside						West Riverside Energy Center
Whitewater						Whitewater Cogeneration Facility
WRO						Withhold Release Order


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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 ESG Progress 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 2021 Annual Report on Form 10-K, and those identified below:

•Factors affecting utility operations such as catastrophic weather-related damage, environmental incidents, unplanned facility outages and repairs and maintenance, 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, including those caused by climate change, changes in economic conditions, customer growth and declines, commodity prices, energy conservation efforts, and continued adoption of distributed generation by customers;

•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 expiration and non-renewal of the QIP rider, deregulation and restructuring of the electric and/or natural gas utility industries, transmission or distribution system operation, the approval process for new construction, reliability standards, pipeline integrity and safety standards, allocation of energy assistance, energy efficiency mandates, and tax laws, including those that affect our ability to use PTCs and ITCs;

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

•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;

•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 supply chain disruptions, inflation, and other factors;

•The impact of health pandemics, including any new developments relating to the COVID-19 pandemic, on our business functions, financial condition, liquidity, and results of operations;

•Factors affecting the implementation of our CO2 emission and/or methane emission reduction goals and opportunities and actions related to those goals, including related regulatory decisions, the cost of materials, supplies, and labor, technology advances, the feasibility of competing generation projects, and our ability to execute our capital plan;


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•The financial and operational feasibility of taking more aggressive action to further reduce GHG emissions in order to limit future global temperature increases;

•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, supply chains and fuel prices, generally, from the ongoing conflict between Russia and Ukraine;

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

•Changes in the method of determining LIBOR or the replacement of LIBOR with an alternative reference rate;

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

•The direct or indirect effect on our business resulting from terrorist attacks and cyber security 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 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;

•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 related to our non-utility renewable energy facilities, including unfavorable weather, the ability to replace expiring long-term PPAs under acceptable terms, and the availability of reliable interconnection and electricity grids;

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

•Potential business strategies to acquire and dispose of assets or businesses, 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;


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•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.


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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited)	Three Months Ended
	March 31
(in millions, except per share amounts)		2022		2021
Operating revenues		$	2,908.1	$	2,691.4

Operating expenses
Cost of sales		1,383.4		1,265.6
Other operation and maintenance		454.4		479.9
Depreciation and amortization		278.1		261.4
Property and revenue taxes		60.8		55.2
Total operating expenses		2,176.7		2,062.1

Operating income		731.4		629.3

Equity in earnings of transmission affiliates		41.7		42.6
Other income, net		39.6		32.8
Interest expense		117.6		119.5
Other expense		(36.3)		(44.1)

Income before income taxes		695.1		585.2
Income tax expense		127.1		74.9
Net income		568.0		510.3

Preferred stock dividends of subsidiary		0.3		0.3
Net (income) loss attributed to noncontrolling interests		(1.8)		0.1
Net income attributed to common shareholders		$	565.9	$	510.1

Earnings per share
Basic		$	1.79	$	1.62
Diluted		$	1.79	$	1.61

Weighted average common shares outstanding
Basic		315.4		315.4
Diluted		316.2		316.2

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


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WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)	Three Months Ended
	March 31
(in millions)		2022		2021
Net income		$	568.0	$	510.3

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

Reclassification of realized net derivative (gain) loss to net income, net of tax		(0.1)		1.0
Cash flow hedges, net		(0.1)		1.0

Defined benefit plans
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax		0.1		0.1

Other comprehensive income, net of tax		—		1.1

Comprehensive income		568.0		511.4

Preferred stock dividends of subsidiary		0.3		0.3
Comprehensive (income) loss attributed to noncontrolling interests		(1.8)		0.1
Comprehensive income attributed to common shareholders		$	565.9	$	511.2

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


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WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts)	March 31, 2022		December 31, 2021
Assets
Current assets
Cash and cash equivalents	$	33.8	$	16.3
Accounts receivable and unbilled revenues, net of reserves of $200.6 and $198.3, respectively	1,635.7		1,505.7
Materials, supplies, and inventories	368.8		635.8

Prepayments	172.9		245.5

Derivative assets	204.3		107.0
Other	147.1		146.4
Current assets	2,562.6		2,656.7

Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $10,041.4 and $9,889.3, respectively	27,110.2		26,982.4
Regulatory assets (March 31, 2022 and December 31, 2021 include $98.2 and $100.7, respectively, related to WEPCo Environmental Trust)	3,163.6		3,264.8
Equity investment in transmission affiliates	1,818.2		1,789.4
Goodwill	3,052.8		3,052.8
Pension and OPEB assets	910.2		881.3
Other	356.9		361.1
Long-term assets	36,411.9		36,331.8
Total assets	$	38,974.5	$	38,988.5

Liabilities and Equity
Current liabilities
Short-term debt	$	1,450.0	$	1,897.0
Current portion of long-term debt (March 31, 2022 and December 31, 2021 include $8.8, related to WEPCo Environmental Trust)	163.4		169.4
Accounts payable	693.7		1,005.7


Other	957.3		680.9
Current liabilities	3,264.4		3,753.0

Long-term liabilities
Long-term debt (March 31, 2022 and December 31, 2021 include $102.8 and $102.7, respectively, related to WEPCo Environmental Trust)	13,514.3		13,523.7
Deferred income taxes	4,426.2		4,308.5
Deferred revenue, net	383.8		389.2
Regulatory liabilities	4,032.6		3,946.0
Environmental remediation liabilities	517.2		532.6
Pension and OPEB obligations	218.5		219.0
Other	1,173.0		1,203.2
Long-term liabilities	24,265.6		24,122.2

Commitments and contingencies (Note 19)

Common shareholders' equity
Common stock – $0.01 par value; 325,000,000 shares authorized; 315,434,531 shares outstanding	3.2		3.2
Additional paid in capital	4,131.8		4,138.1
Retained earnings	7,111.4		6,775.1
Accumulated other comprehensive loss	(3.2)		(3.2)
Common shareholders' equity	11,243.2		10,913.2

Preferred stock of subsidiary	30.4		30.4
Noncontrolling interests	170.9		169.7
Total liabilities and equity	$	38,974.5	$	38,988.5

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


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WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Three Months Ended
	March 31
(in millions)	2022		2021
Operating activities
Net income	$	568.0	$	510.3
Reconciliation to cash provided by operating activities
Depreciation and amortization	278.1		261.4
Deferred income taxes and ITCs, net	103.8		129.6
Contributions and payments related to pension and OPEB plans	(3.6)		(4.1)
Equity income in transmission affiliates, net of distributions	(7.7)		(9.2)
Change in –
Accounts receivable and unbilled revenues, net	(174.3)		(150.4)
Materials, supplies, and inventories	267.0		175.1
Prepayments	72.6		4.6
Amounts recoverable from customers	10.3		(286.7)
Other current assets	1.1		15.6
Accounts payable	(293.8)		(181.5)
Other current liabilities	289.5		(2.3)
Other, net	(34.2)		(67.2)
Net cash provided by operating activities	1,076.8		395.2

Investing activities
Capital expenditures	(383.5)		(470.6)
Acquisition of Jayhawk	—		(119.4)
Capital contributions to transmission affiliates	(21.1)		—
Proceeds from the sale of assets	9.7		11.3
Proceeds from the sale of investments held in rabbi trust	15.4		12.7
Insurance proceeds received for property damage	41.0		—
Other, net	0.3		24.7
Net cash used in investing activities	(338.2)		(541.3)

Financing activities
Exercise of stock options	11.8		1.2
Purchase of common stock	(23.4)		(6.6)
Dividends paid on common stock	(229.6)		(213.7)
Issuance of long-term debt	—		600.0
Retirement of long-term debt	(15.4)		(14.7)
Issuance of short-term loan	0.9		—
Repayment of short-term loan	—		(340.0)
Change in other short-term debt	(447.9)		143.5
Other, net	(2.9)		(6.6)
Net cash provided by (used in) financing activities	(706.5)		163.1

Net change in cash, cash equivalents, and restricted cash	32.1		17.0
Cash, cash equivalents, and restricted cash at beginning of period	87.5		72.6
Cash, cash equivalents, and restricted cash at end of period	$	119.6	$	89.6

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


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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, 2021	$	3.2	$	4,138.1	$	6,775.1	$	(3.2)	$	10,913.2	$	30.4	$	169.7	$	11,113.3
Net income attributed to common shareholders	—		—		565.9		—		565.9		—		—		565.9
Net income attributed to noncontrolling interests	—		—		—		—		—		—		1.8		1.8
Common stock dividends of $0.7275 per share	—		—		(229.6)		—		(229.6)		—		—		(229.6)
Exercise of stock options	—		11.8		—		—		11.8		—		—		11.8
Purchase of common stock	—		(23.4)		—		—		(23.4)		—		—		(23.4)
Capital contributions from noncontrolling interest	—		—		—		—		—		—		0.4		0.4
Distributions to noncontrolling interests	—		—		—		—		—		—		(1.0)		(1.0)
Stock-based compensation and other	—		5.3		—		—		5.3		—		—		5.3
Balance at March 31, 2022	$	3.2	$	4,131.8	$	7,111.4	$	(3.2)	$	11,243.2	$	30.4	$	170.9	$	11,444.5



	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, 2020	$	3.2	$	4,143.7	$	6,329.6	$	(6.8)	$	10,469.7	$	30.4	$	162.4	$	10,662.5
Net income attributed to common shareholders	—		—		510.1		—		510.1		—		—		510.1
Net loss attributed to noncontrolling interests	—		—		—		—		—		—		(0.1)		(0.1)
Other comprehensive income	—		—		—		1.1		1.1		—		—		1.1
Common stock dividends of $0.6775 per share	—		—		(213.7)		—		(213.7)		—		—		(213.7)
Exercise of stock options	—		1.2		—		—		1.2		—		—		1.2
Purchase of common stock	—		(6.6)		—		—		(6.6)		—		—		(6.6)
Acquisition of a noncontrolling interest	—		—		—		—		—		—		6.2		6.2
Capital contributions from noncontrolling interest	—		—		—		—		—		—		2.0		2.0
Distributions to noncontrolling interests	—		—		—		—		—		—		(0.4)		(0.4)
Stock-based compensation and other	—		5.3		—		—		5.3		—		—		5.3
Balance at March 31, 2021	$	3.2	$	4,143.6	$	6,626.0	$	(5.7)	$	10,767.1	$	30.4	$	170.1	$	10,967.6

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


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WEC ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

March 31, 2022

NOTE 1—GENERAL INFORMATION

WEC Energy Group serves approximately 1.6 million electric customers and 3.0 million natural gas customers, owns approximately 60% of ATC, and owns majority interests in multiple wind generating facilities as part of its non-utility energy infrastructure business.

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 at Bishop Hill III, Blooming Grove, Coyote Ridge, Jayhawk, Tatanka Ridge, and Upstream held by third parties.

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 16, 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, 2021. 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 months ended March 31, 2022, are not necessarily indicative of expected results for 2022 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 (or disposals) of assets or businesses, and transaction costs are capitalized in asset acquisitions. The purchase price of certain acquisitions below includes intangibles recorded as long-term liabilities related to PPAs and interconnection agreements. See Note 15, Goodwill and Intangibles, for more information.

Acquisition of Electric Generation Facility in Wisconsin

In November 2021, WE and WPS signed an asset purchase agreement to acquire Whitewater, a commercially operational 236.5 MW dual fueled (natural gas and low sulfur fuel oil) combined cycle electrical generation facility in Whitewater, Wisconsin, for $72.7 million. The transaction is expected to close in January 2023. In December 2021, WE and WPS filed an application with the PSCW for approval to acquire Whitewater.

Acquisition of a Wind Energy Generation Facility in Illinois

In June 2021, WECI signed an agreement to acquire a 90% ownership interest in Sapphire Sky, a 250 MW wind generating facility under construction in McLean County, Illinois, for approximately $412 million. The project has an offtake agreement with an unaffiliated third party for all of the energy to be produced by the facility for a period of 12 years. WECI's investment in Sapphire Sky is expected to qualify for PTCs. The transaction is subject to FERC approval and commercial operation is expected to begin by the end


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of 2022, at which time the transaction is expected to close. Sapphire Sky will be included in the non-utility energy infrastructure segment.

Acquisition of a Wind Energy Generation Facility in Kansas

In February 2021, WECI completed the acquisition of a 90% ownership interest in Jayhawk, a 190 MW wind generating facility in Bourbon and Crawford counties, Kansas, for $119.9 million, which included transaction costs. The project became commercially operational in December 2021. Subsequent to the acquisition, WECI incurred an additional $147.4 million of capital expenditures for the project for a total investment of $267.3 million. The project has an offtake agreement with an unaffiliated third party for all of the energy to be produced by the facility for a period of 10 years. WECI's investment in Jayhawk qualifies for PTCs. WECI is entitled to 99% of the tax benefits related to this facility for the first 10 years of commercial operation, after which we will be entitled to tax benefits equal to our ownership interest. Jayhawk is included in the non-utility energy infrastructure segment.

Acquisition of Wind Generation Facility in Nebraska

In August 2019, WECI signed an agreement to acquire an 80% ownership interest in Thunderhead, a 300 MW wind generating facility under construction in Antelope and Wheeler counties in Nebraska, for a total investment of approximately $338 million. In February 2020, WECI agreed to acquire an additional 10% ownership interest in Thunderhead for $43 million. The project has an offtake agreement for all of the energy to be produced by the facility for 12 years. WECI's investment in Thunderhead is expected to qualify for PTCs. The transaction was approved by FERC in April 2020, and commercial operation was initially expected to begin by the end of 2020. However, due to a delay in construction of the required substation, Thunderhead is now expected to begin commercial operation in the Fall of 2022. The transaction is expected to close upon commercial operation. Thunderhead will be included in the non-utility energy infrastructure segment.

NOTE 3—OPERATING REVENUES

For more information about our operating revenues, see Note 1(d), Operating Revenues, in our 2021 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 have 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 March 31, 2022
Electric	$	1,187.5	$	—	$	—	$	1,187.5	$	—	$	—	$	—		$	1,187.5
Natural gas	746.8		679.9		238.2		1,664.9		15.3		—		(14.8)			1,665.4
Total regulated revenues	1,934.3		679.9		238.2		2,852.4		15.3		—		(14.8)			2,852.9
Other non-utility revenues	—		—		4.6		4.6		43.7		—		(1.6)			46.7
Total revenues from contracts with customers	1,934.3		679.9		242.8		2,857.0		59.0		—		(16.4)			2,899.6
Other operating revenues	8.0		2.2		(1.9)		8.3		100.5		0.2		(100.5)		(1)	8.5
Total operating revenues	$	1,942.3	$	682.1	$	240.9	$	2,865.3	$	159.5	$	0.2	$	(116.9)		$	2,908.1


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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 March 31, 2021
Electric	$	1,095.0	$	—	$	—	$	1,095.0	$	—	$	—	$	—		$	1,095.0
Natural gas	627.3		693.5		225.6		1,546.4		14.6		—		(13.3)			1,547.7
Total regulated revenues	1,722.3		693.5		225.6		2,641.4		14.6		—		(13.3)			2,642.7
Other non-utility revenues	—		—		4.7		4.7		23.2		—		(1.6)			26.3
Total revenues from contracts with customers	1,722.3		693.5		230.3		2,646.1		37.8		—		(14.9)			2,669.0
Other operating revenues	9.4		9.9		3.0		22.3		99.8		0.1		(99.8)		(1)	22.4
Total operating revenues	$	1,731.7	$	703.4	$	233.3	$	2,668.4	$	137.6	$	0.1	$	(114.7)		$	2,691.4

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

Revenues from Contracts with Customers

Electric Utility Operating Revenues

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


	Three Months Ended March 31
(in millions)		2022		2021
Residential		$	463.1	$	423.7
Small commercial and industrial		370.1		331.4
Large commercial and industrial		229.2		209.5
Other		7.8		7.8
Total retail revenues		1,070.2		972.4
Wholesale		42.4		39.7
Resale		56.8		62.7
Steam		12.1		14.8
Other utility revenues		6.0		5.4
Total electric utility operating revenues		$	1,187.5	$	1,095.0

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 March 31, 2022
Residential	$	502.5	$	465.5	$	161.3	$	1,129.3
Commercial and industrial	272.5		158.3		86.8		517.6
Total retail revenues	775.0		623.8		248.1		1,646.9
Transportation	25.5		80.9		13.9		120.3
Other utility revenues (1)	(53.7)		(24.8)		(23.8)		(102.3)
Total natural gas utility operating revenues	$	746.8	$	679.9	$	238.2	$	1,664.9


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(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Three Months Ended March 31, 2021
Residential	$	347.6	$	333.9	$	87.9	$	769.4
Commercial and industrial	176.4		102.7		43.9		323.0
Total retail revenues	524.0		436.6		131.8		1,092.4
Transportation	24.4		74.2		11.0		109.6
Other utility revenues (1)	78.9		182.7		82.8		344.4
Total natural gas utility operating revenues	$	627.3	$	693.5	$	225.6	$	1,546.4

(1)Includes the revenues subject to the purchased gas recovery mechanisms of our utilities. The amounts for the three months ended March 31, 2021 reflect the higher natural gas costs that were incurred as a result of the extreme winter weather conditions in February 2021. As these amounts are billed to customers, they are reflected in retail revenues with an offsetting decrease in other utility revenues. In 2022, we continued to recover on natural gas costs we under-collected from our customers in 2021, related to the extreme weather. In addition, during the first quarter of 2022 we over-collected natural gas costs due to these costs being lower than what was anticipated in rates. See Note 21, Regulatory Environment, for more information.

Other Natural Gas Operating Revenues

We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment. Bluewater has entered into long-term service agreements for natural gas storage services with WE, WPS, and WG, and also provides limited service to unaffiliated customers. 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 March 31
(in millions)		2022		2021
Wind generation revenues		$	36.2	$	15.8
We Power revenues (1)		5.9		5.8
Appliance service revenues		4.6		4.7


Total other non-utility operating revenues		$	46.7	$	26.3

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

Other Operating Revenues

Other operating revenues consist primarily of the following:


	Three Months Ended March 31
(in millions)		2022		2021
Late payment charges		$	13.6	$	15.0
Alternative revenues (1)		(6.0)		6.2
Other		0.9		1.2
Total other operating revenues		$	8.5	$	22.4

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


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NOTE 4—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 wind generating facilities through agreements with several large high credit quality counterparties.

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

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

We have included tables below that show our gross third-party receivable balances and the related allowance for credit losses at March 31, 2022 and December 31, 2021, by reportable segment.


(in millions)	Wisconsin			Illinois			Other States			Total Utility Operations			Non-Utility Energy Infrastructure			Corporate and Other			WEC Energy Group Consolidated
March 31, 2022
Accounts receivable and unbilled revenues	$	1,072.2		$	612.8		$	125.7		$	1,810.7		$	17.1		$	8.5		$	1,836.3
Allowance for credit losses	85.7			107.0			7.9			200.6			—			—			200.6
Accounts receivable and unbilled revenues, net (1)	$	986.5		$	505.8		$	117.8		$	1,610.1		$	17.1		$	8.5		$	1,635.7

Total accounts receivable, net – past due greater than 90 days (1)	$	55.5		$	43.7		$	3.7		$	102.9		$	—		$	—		$	102.9
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	98.2		%	100.0		%	—		%	95.4		%	—		%	—		%	95.4		%


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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, 2021
Accounts receivable and unbilled revenues	$	1,053.1		$	523.1		$	105.7		$	1,681.9		$	17.0		$	5.1		$	1,704.0
Allowance for credit losses	84.0			105.5			8.8			198.3			—			—			198.3
Accounts receivable and unbilled revenues, net (1)	$	969.1		$	417.6		$	96.9		$	1,483.6		$	17.0		$	5.1		$	1,505.7

Total accounts receivable, net – past due greater than 90 days (1)	$	46.5		$	36.6		$	3.4		$	86.5		$	—		$	—		$	86.5
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	97.6		%	100.0		%	—		%	94.8		%	—		%	—		%	94.8		%

(1)Our exposure to credit losses for certain regulated utility customers is mitigated by regulatory mechanisms we have in place. Specifically, rates related to all of the customers in our Illinois segment, as well as the residential rates of WE, WPS, and WG in our Wisconsin segment, include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between the actual provision for credit losses and the amounts recovered in rates. As a result, at March 31, 2022, $1,008.4 million, or 61.6%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses.

A rollforward of the allowance for credit losses by reportable segment for the three months ended March 31, 2022 and 2021 is included below:


Three Months Ended March 31, 2022 (in millions)	Wisconsin		Illinois		Other States		WEC Energy Group Consolidated
Balance at January 1, 2022	$	84.0	$	105.5	$	8.8	$	198.3
Provision for credit losses	11.8		11.3		0.2		23.3
Provision for credit losses deferred for future recovery or refund	8.8		12.1		—		20.9
Write-offs charged against the allowance	(28.8)		(27.3)		(1.4)		(57.5)
Recoveries of amounts previously written off	9.9		5.4		0.3		15.6
Balance at March 31, 2022	$	85.7	$	107.0	$	7.9	$	200.6

On a consolidated basis, there was a $2.3 million increase in the allowance for credit losses at March 31, 2022, compared to January 1, 2022, driven by an increase in past due accounts receivable balances at our Wisconsin and Illinois reportable segments. We believe that the higher year-over-year energy costs that customers were seeing, which were driven by high natural gas prices, contributed to the higher past due accounts receivable balances. An increase in past due balances is also a trend we generally see over the winter moratorium months, when we are not allowed to disconnect customer service as a result of non-payment. In Wisconsin, the winter moratorium begins on November 1 and ends on April 15, and in Illinois the winter moratorium begins on December 1 and ends on March 31.


Three Months Ended March 31, 2021 (in millions)	Wisconsin		Illinois		Other States		WEC Energy Group Consolidated
Balance at January 1, 2021	$	102.1	$	111.6	$	6.4	$	220.1
Provision for credit losses	13.7		7.1		1.3		22.1
Provision for credit losses deferred for future recovery or refund	22.3		3.1		—		25.4
Write-offs charged against the allowance	(18.5)		(2.8)		(0.5)		(21.8)
Recoveries of amounts previously written off	9.9		3.0		0.4		13.3
Balance at March 31, 2021	$	129.5	$	122.0	$	7.6	$	259.1

The increase in the allowance for credit losses at March 31, 2021, compared to January 1, 2021, was driven by higher past due accounts receivable balances at our utility segments, primarily related to residential customers. This increase in accounts receivable balances in arrears was driven by the continued economic disruptions caused by the COVID-19 pandemic, including continued high unemployment rates. Also, as a result of the winter moratorium rules and the COVID-19 pandemic and related regulatory orders we received, we were unable to disconnect any of our Wisconsin and Illinois residential customers in the first quarter of 2021 and during all of 2020.


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NOTE 5—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets and liabilities were reflected on our balance sheets at March 31, 2022 and December 31, 2021. For more information on our regulatory assets and liabilities, see Note 6, Regulatory Assets and Liabilities, in our 2021 Annual Report on Form 10-K.


(in millions)	March 31, 2022		December 31, 2021
Regulatory assets
Pension and OPEB costs	$	783.1	$	802.3
Plant retirement related items	714.8		722.3
Environmental remediation costs	618.8		630.9
Income tax related items	456.6		458.8
Asset retirement obligations	179.6		194.2
System support resource	128.4		129.5
Securitization	98.2		100.7
Energy costs recoverable through rate adjustments	70.1		85.4
MERC extraordinary natural gas costs	51.6		59.7
Uncollectible expense	47.6		42.6
Energy efficiency programs	20.4		22.0
Derivatives (1)	3.6		33.1
Other, net	82.8		85.6
Total regulatory assets	$	3,255.6	$	3,367.1

Balance sheet presentation
Other current assets	$	92.0	$	102.3
Regulatory assets	3,163.6		3,264.8
Total regulatory assets	$	3,255.6	$	3,367.1

(1)For most energy-related physical and financial contracts that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities. See Note 12, Derivative Instruments, for more information on our derivative asset and liability balances.


(in millions)	March 31, 2022		December 31, 2021
Regulatory liabilities
Income tax related items	$	1,981.6	$	1,998.5
Removal costs	1,247.2		1,248.0
Pension and OPEB benefits	392.8		397.3
Derivatives (1)	245.3		124.1
Energy costs refundable through rate adjustments (2)	97.6		13.7
Electric transmission costs (3)	65.5		84.2
Uncollectible expense	29.7		37.1
Earnings sharing mechanisms (3)	22.5		28.4
Other, net	47.2		29.0
Total regulatory liabilities	$	4,129.4	$	3,960.3

Balance sheet presentation
Other current liabilities	$	96.8	$	14.3
Regulatory liabilities	4,032.6		3,946.0
Total regulatory liabilities	$	4,129.4	$	3,960.3

(1) For most energy-related physical and financial contracts that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities. See Note 12, Derivative Instruments, for more information on our derivative asset and liability balances.

(2) The increase in these regulatory liabilities was primarily related to lower natural gas costs incurred in the first quarter of 2022, compared to what was anticipated in rates.


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(3) The decrease in these regulatory liability balances was primarily related to the PSCW's approval of certain accounting treatments that allowed our Wisconsin utilities to forego applying for a 2022 base rate increase, and instead maintain base rates consistent with 2021 levels. Among the accounting treatments approved was the amortization of certain regulatory liability balances in 2022, to offset a portion of the forecasted revenue deficiency. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on 2022 Wisconsin base rates.

NOTE 6—PROPERTY, PLANT, AND EQUIPMENT

Wisconsin Segment Plant to be Retired

Columbia Units 1 and 2

As a result of a MISO ruling received in June 2021, retirement of the jointly-owned Columbia generating units 1 and 2 became probable. Columbia generating units 1 and 2 are expected to be retired by the end of 2023 and 2024, respectively. The net book value of WPS's ownership share of unit 1 and unit 2 was $87.9 million and $186.2 million, respectively, at March 31, 2022. These amounts were classified as plant to be retired within property, plant, and equipment on our balance sheets. These units are included in rate base, and WPS continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

Public Service Building and Steam Tunnel Assets

During a significant rain event in May 2020, an underground steam tunnel in downtown Milwaukee flooded and steam vented into WE’s PSB. The damage to the building and adjacent steam tunnel assets from the flooding and steam was extensive and required significant repairs and restorations. As of March 31, 2022, WE had incurred $95.3 million of costs related to these repairs and restorations. In 2020, WE received $20.0 million of insurance proceeds to cover a portion of these costs and wrote off $12.5 million of costs that we do not intend to seek recovery for through other operation and maintenance expense. In the first quarter of 2022, WE received $41.0 million of insurance proceeds as a result of a settlement that was reached in February 2022. The remaining $21.8 million of costs is expected to be recovered through rates.

In June 2021, we received approval from the PSCW to restore the PSB and adjacent steam tunnel assets and to defer the project costs, net of insurance proceeds, as a component of rate base. As such, and in light of the agreement with insurers noted above, we do not currently expect a significant impact to our future results of operations.

NOTE 7—COMMON EQUITY

Stock-Based Compensation

During the three months ended March 31, 2022, 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)						437,269
Restricted shares (2)						72,211
Performance units						171,492

(1)Stock options awarded had a weighted-average exercise price of $96.04 and a weighted-average grant date fair value of $14.71 per option.

(2)Restricted shares awarded had a weighted-average grant date fair value of $96.04 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. All of our utility subsidiaries, with the exception of UMERC and MGU, are prohibited from


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loaning funds to us, either directly or indirectly. See Note 11, Common Equity, in our 2021 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 Dividends

On April 21, 2022, our Board of Directors declared a quarterly cash dividend of $0.7275 per share, payable on June 1, 2022, to shareholders of record on May 13, 2022.

NOTE 8—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)	March 31, 2022			December 31, 2021
Commercial paper
Amount outstanding	$	1,448.3		$	1,896.1
Weighted-average interest rate on amounts outstanding	0.92		%	0.26		%
Operating expense loans
Amount outstanding (1)	$	1.7		$	0.9

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

Our average amount of commercial paper borrowings based on daily outstanding balances during the three months ended March 31, 2022 was $1,663.9 million with a weighted-average interest rate during the period of 0.38%.

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	March 31, 2022
WEC Energy Group	September 2026	$	1,500.0
WE	September 2026	500.0
WPS (1)	September 2026	400.0
WG	September 2026	350.0
PGL	September 2026	350.0
Total short-term credit capacity		$	3,100.0

Less:
Letters of credit issued inside credit facilities		$	2.3
Commercial paper outstanding		1,448.3
Available capacity under existing agreements		$	1,649.4

(1) In April 2022, WPS received approval from the PSCW to extend the maturity of its facility to September 2026.

NOTE 9—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:


(in millions)	March 31, 2022		December 31, 2021
Materials and supplies	$	232.2	$	225.3
Fossil fuel	81.3		84.5
Natural gas in storage	55.3		326.0
Total	$	368.8	$	635.8


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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 March 31, 2022, we had a temporary LIFO liquidation credit of $130.7 million recorded within other current liabilities on our balance sheet. Due to seasonality requirements, PGL and NSG expect these interim reductions in LIFO layers to be replenished by year end.

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

NOTE 10—INCOME TAXES

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 March 31, 2022				Three Months Ended March 31, 2021
(in millions)	Amount		Effective Tax Rate		Amount		Effective Tax Rate
Statutory federal income tax	$	145.5	21.0	%	$	122.8	21.0	%
State income taxes net of federal tax benefit	43.6		6.3	%	36.9		6.3	%
PTCs	(44.8)		(6.5)	%	(34.0)		(5.8)	%
Federal excess deferred tax amortization	(15.8)		(2.3)	%	(14.6)		(2.5)	%

Federal excess deferred tax amortization – Wisconsin unprotected	(0.3)		—	%	(30.3)		(5.2)	%
Uncertain tax positions	—		—	%	(8.2)		(1.4)	%

Other	(1.1)		(0.2)	%	2.3		0.4	%
Total income tax expense	$	127.1	18.3	%	$	74.9	12.8	%

The effective tax rate of 18.3% for the three months ended March 31, 2022, differs from the United States statutory federal income tax rate of 21%, primarily due to PTCs generated from ownership interests in wind generation facilities in our non-utility energy infrastructure segment and the impact of the protected deferred tax benefits associated with the Tax Legislation, as discussed in more detail below. These items were partially offset by state income taxes.

The effective tax rate of 12.8% for the three months ended March 31, 2021, differs from the United States statutory federal income tax rate of 21%, primarily due to PTCs generated from ownership interests in wind generation facilities in our non-utility energy infrastructure segment and the recognition of certain unprotected deferred tax benefits created as a result of the Tax Legislation. Effective January 1, 2020, in accordance with the rate order received from the PSCW in December 2019, our Wisconsin utilities began amortizing the unprotected deferred tax benefits over periods ranging from two years to four years, to reduce near-term rate impacts to their customers. In addition, the impact of the protected benefits associated with the Tax Legislation, as discussed in more detail below, drove a decrease in the effective tax rate. These items were partially offset by state income taxes.

The Tax Legislation required our regulated utilities to remeasure their deferred income taxes and we began to amortize the resulting excess protected deferred income taxes beginning in 2018 in accordance with normalization requirements (see federal excess deferred tax amortization line above).

See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on unprotected tax benefits.

NOTE 11—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).


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

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

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

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

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

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

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:


	March 31, 2022
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	176.9	$	3.0	$	—	$	179.9
FTRs	—		—		1.0		1.0
Coal contracts	—		38.2		—		38.2
Total derivative assets	$	176.9	$	41.2	$	1.0	$	219.1

Investments held in rabbi trust	$	59.5	$	—	$	—	$	59.5

Derivative liabilities
Natural gas contracts	$	—	$	1.4	$	—	$	1.4


	December 31, 2021
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	46.4	$	18.2	$	—	$	64.6
FTRs	—		—		2.4		2.4
Coal contracts	—		53.0		—		53.0
Total derivative assets	$	46.4	$	71.2	$	2.4	$	120.0

Investments held in rabbi trust	$	79.6	$	—	$	—	$	79.6

Derivative liabilities
Natural gas contracts	$	8.4	$	6.7	$	—	$	15.1


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The derivative assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy and Operating Reserves Markets.

We hold investments in the Integrys rabbi trust. These investments are restricted as they can only be withdrawn from the trust to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans. These investments are included in other long-term assets on our balance sheets. During the three months ended March 31, 2022, we recorded $3.3 million of net unrealized losses in earnings related to the investments held at the end of the period, compared with $4.0 million of net unrealized gains recorded during the same quarter in 2021.

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


	Three Months Ended March 31
(in millions)		2022		2021
Balance at the beginning of the period		$	2.4	$	2.4
Purchases		—		0.1
Settlements		(1.4)		(1.6)
Balance at the end of the period		$	1.0	$	0.9

Fair Value of Financial Instruments

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


	March 31, 2022				December 31, 2021
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock of subsidiary	$	30.4	$	26.6	$	30.4	$	30.3
Long-term debt, including current portion (1)	13,549.7		13,519.8		13,563.4		14,819.4

(1)The carrying amount of long-term debt excludes finance lease obligations of $128.0 million and $129.7 million at March 31, 2022 and December 31, 2021, respectively.

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

NOTE 12—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 not shown separately on our balance sheets are included in the other current and other long-term line items. The following table shows our derivative assets and derivative liabilities. None of the derivatives shown below were designated as hedging instruments.


	March 31, 2022				December 31, 2021
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Current
Natural gas contracts	$	169.6	$	1.4	$	60.6	$	14.0
FTRs	1.0		—		2.4		—
Coal contracts	33.7		—		44.0		—
Total current	204.3		1.4		107.0		14.0

Long-term
Natural gas contracts	10.3		—		4.0		1.1
Coal contracts	4.5		—		9.0		—
Total long-term	14.8		—		13.0		1.1
Total	$	219.1	$	1.4	$	120.0	$	15.1

Realized gains (losses) on derivatives not designated as hedging instruments are primarily recorded in cost of sales on the income statements. Our estimated notional sales volumes and realized gains (losses) were as follows:








	Three Months Ended March 31, 2022			Three Months Ended March 31, 2021
(in millions)	Volumes	Gains		Volumes	Gains (Losses)
Natural gas contracts	59.5 Dth	$	31.6	59.8 Dth	$	(7.5)
FTRs	7.0 MWh	1.0		8.4 MWh	2.1
Total		$	32.6		$	(5.4)

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 March 31, 2022 and December 31, 2021, we had posted cash collateral of $14.0 million and $13.9 million, respectively. These amounts were recorded on our balance sheets in other current assets. At March 31, 2022 and December 31, 2021, we had also received cash collateral of $146.1 million and $13.2 million, respectively. These amounts were recorded on our balance sheets 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:


	March 31, 2022					December 31, 2021
(in millions)	Derivative Assets			Derivative Liabilities		Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	219.1		$	1.4	$	120.0		$	15.1
Gross amount not offset on the balance sheet	(139.5)		(1)	(0.2)		(15.2)		(2)	(9.2)		(3)
Net amount	$	79.6		$	1.2	$	104.8		$	5.9

(1)Includes cash collateral received of $139.3 million.

(2)Includes cash collateral received of $6.4 million.

(3)Includes cash collateral posted of $0.4 million.

Cash Flow Hedges

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


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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 table below shows the amounts related to these cash flow hedges that were reclassified to interest expense, along with our total interest expense on the income statements:


	Three Months Ended March 31
(in millions)		2022		2021

Net derivative gain (loss) reclassified from accumulated other comprehensive loss to interest expense		$	0.1	$	(1.4)
Total interest expense line item on the income statements		117.6		119.5

We estimate that during the next twelve months $0.4 million will be reclassified from accumulated other comprehensive loss as a decrease to interest expense.

NOTE 13—GUARANTEES

The following table shows our outstanding guarantees:


	Total Amounts Committed at March 31, 2022		Expiration

(in millions)			Less Than 1 Year		1 to 3 Years		Over 3 Years
Standby letters of credit (1)	$	82.3	$	10.5	$	0.2	$	71.6
Surety bonds (2)	12.8		12.8		—		—
Other guarantees (3)	9.4		—		—		9.4
Total guarantees	$	104.5	$	23.3	$	0.2	$	81.0

(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 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 14—EMPLOYEE BENEFITS

The following tables show the components of net periodic benefit cost (credit) for our benefit plans.


		Pension Benefits
	Three Months Ended March 31
(in millions)		2022		2021
Service cost		$	12.4	$	13.9
Interest cost		22.8		21.9
Expected return on plan assets		(52.7)		(50.6)
Loss on plan settlement		—		0.1
Amortization of prior service cost		0.4		0.4
Amortization of net actuarial loss		19.1		27.4
Net periodic benefit cost		$	2.0	$	13.1


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		OPEB Benefits
	Three Months Ended March 31
(in millions)		2022		2021
Service cost		$	3.8	$	4.2
Interest cost		3.9		3.6
Expected return on plan assets		(17.2)		(16.4)

Amortization of prior service credit		(4.0)		(4.0)
Amortization of net actuarial gain		(6.0)		(5.7)
Net periodic benefit credit		$	(19.5)	$	(18.3)

During the three months ended March 31, 2022, we made contributions and payments of $3.1 million related to our pension plans and $0.5 million related to our OPEB plans. We expect to make contributions and payments of $8.0 million related to our pension plans and $2.1 million related to our OPEB plans during the remainder of 2022, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

NOTE 15—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 March 31, 2022. We had no changes to the carrying amount of goodwill during the three months ended March 31, 2022.


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

(1)We had no accumulated impairment losses related to our goodwill as of March 31, 2022.

Intangible Assets

At March 31, 2022 and December 31, 2021, we had $5.7 million of indefinite-lived intangible assets primarily related to a MGU trade name obtained through an acquisition, which is included in other long-term assets on our balance sheets. We had no changes to the carrying amount of these intangible assets during the three months ended March 31, 2022.

Intangible Liabilities

The intangible liabilities below were all obtained through acquisitions by WECI and are classified as other long-term liabilities on our balance sheets.


	March 31, 2022						December 31, 2021
(in millions)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
PPAs (1)	$	87.9	$	(8.5)	$	79.4	$	87.9	$	(6.5)	$	81.4
Proxy revenue swap (2)	7.2		(2.2)		5.0		7.2		(2.1)		5.1
Interconnection agreements (3)	4.7		(0.6)		4.1		4.7		(0.5)		4.2
Total intangible liabilities	$	99.8	$	(11.3)	$	88.5	$	99.8	$	(9.1)	$	90.7

(1) Represents PPAs related to the acquisition of Blooming Grove, Tatanka Ridge, and Jayhawk expiring between 2030 and 2032. The weighted-average remaining useful life of the PPAs is 10 years.

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

(3) Represents interconnection agreements related to the acquisitions of Tatanka Ridge and Bishop Hill III, expiring in 2040 and 2041, respectively. These agreements relate to payments for connecting our facilities to the infrastructure of another utility to facilitate the movement of power onto the electric grid. The weighted-average remaining useful life of the interconnection agreements is 19 years.


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Amortization related to these intangibles for the three months ended March 31, 2022 and 2021, was $2.2 million and $1.9 million, respectively. Amortization for the next five years, including amounts recorded through March 31, 2022, is estimated to be:


	For the Years Ending December 31
(in millions)	2022		2023		2024		2025		2026
Amortization to be recorded in operating revenues	$	8.5	$	8.4	$	8.4	$	8.4	$	8.4
Amortization to be recorded in other operation and maintenance	0.2		0.2		0.2		0.2		0.2

NOTE 16—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 March 31, 2022
(in millions)	ATC		ATC Holdco		Total
Balance at beginning of period	$	1,766.9	$	22.5	$	1,789.4
Add: Earnings from equity method investment	41.0		0.7		41.7
Add: Capital contributions	21.1		—		21.1
Less: Distributions	34.0		—		34.0

Balance at end of period	$	1,795.0	$	23.2	$	1,818.2

	Three Months Ended March 31, 2021
(in millions)	ATC		ATC Holdco		Total
Balance at beginning of period	$	1,733.5	$	30.8	$	1,764.3
Add: Earnings from equity method investment	41.7		0.9		42.6

Less: Distributions	33.4		—		33.4

Add: Other	0.1		—		0.1
Balance at end of period	$	1,741.9	$	31.7	$	1,773.6

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 March 31
(in millions)		2022		2021
Charges to ATC for services and construction		$	6.2	$	6.0
Charges from ATC for network transmission services		91.1		92.6

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


(in millions)	March 31, 2022		December 31, 2021
Accounts receivable for services provided to ATC	$	2.3	$	2.0

Accounts payable for services received from ATC	30.5		30.2
Amounts due from ATC for transmission infrastructure upgrades (1)	15.1		13.0

(1)The transmission infrastructure upgrades were primarily related to WE's and WPS's construction of their new solar projects, Badger Hollow II and Badger Hollow I, respectively.


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


	Three Months Ended March 31
(in millions)		2022		2021
Income statement data
Operating revenues		$	191.0	$	188.7
Operating expenses		95.5		95.1
Other expense, net		28.0		28.5
Net income		$	67.5	$	65.1


(in millions)	March 31, 2022		December 31, 2021
Balance sheet data
Current assets	$	95.5	$	89.8
Noncurrent assets	5,706.8		5,628.1
Total assets	$	5,802.3	$	5,717.9

Current liabilities	$	421.0	$	436.9
Long-term debt	2,562.3		2,513.0
Other noncurrent liabilities	424.7		422.0
Members' equity	2,394.3		2,346.0
Total liabilities and members' equity	$	5,802.3	$	5,717.9

NOTE 17—SEGMENT INFORMATION

We use net income attributed to common shareholders to measure segment profitability and to allocate resources to our businesses. At March 31, 2022, we reported six segments, which are described below.

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

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

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

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

•The non-utility energy infrastructure segment includes:

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

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

◦WECI, which holds our ownership interests in the following wind generating facilities:

▪90% ownership interest in Bishop Hill III, located in Henry County, Illinois,

▪80% ownership interest in Coyote Ridge, located in Brookings County, South Dakota,

▪90% ownership interest in Upstream, located in Antelope County, Nebraska,

▪90% ownership interest in Blooming Grove, located in McLean County, Illinois,

▪85% ownership interest in Tatanka Ridge, located in Deuel County, South Dakota, and

▪90% ownership interest in Jayhawk, located in Bourbon and Crawford counties, Kansas.

See Note 2, Acquisitions, for more information on Jayhawk.

•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, Wisvest LLC, Wisconsin Energy Capital Corporation, and WEC Business Services LLC.


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All of our operations are located within the United States. The following tables show summarized financial information related to our reportable segments for the three months ended March 31, 2022 and 2021:


	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 March 31, 2022
External revenues	$	1,942.3	$	682.1	$	240.9	$	2,865.3	$	—	$	42.6	$	0.2	$	—	$	2,908.1
Intersegment revenues	—		—		—		—		—		116.9		—		(116.9)		—
Other operation and maintenance	312.6		113.6		24.6		450.8		—		10.9		(5.7)		(1.6)		454.4
Depreciation and amortization	187.1		56.8		10.0		253.9		—		34.0		6.5		(16.3)		278.1
Equity in earnings of transmission affiliates	—		—		—		—		41.7		—		—		—		41.7
Interest expense	136.3		17.7		3.3		157.3		4.9		17.2		22.6		(84.4)		117.6
Income tax expense (benefit)	95.4		42.1		10.4		147.9		8.9		(4.9)		(24.8)		—		127.1
Net income	288.4		113.4		31.5		433.3		27.8		93.3		13.6		—		568.0
Net income attributed to common shareholders	288.1		113.4		31.5		433.0		27.8		91.5		13.6		—		565.9


	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 March 31, 2021
External revenues	$	1,731.7	$	703.4	$	233.3	$	2,668.4	$	—	$	22.9	$	0.1	$	—	$	2,691.4
Intersegment revenues	—		—		—		—		—		114.7		—		(114.7)		—
Other operation and maintenance	341.9		109.3		23.2		474.4		—		8.9		(1.8)		(1.6)		479.9
Depreciation and amortization	176.2		52.7		9.2		238.1		—		31.0		6.6		(14.3)		261.4
Equity in earnings of transmission affiliates	—		—		—		—		42.6		—		—		—		42.6
Interest expense	140.1		16.5		1.5		158.1		4.9		18.0		24.2		(85.7)		119.5
Income tax expense (benefit)	48.1		41.4		8.4		97.9		9.8		0.1		(32.9)		—		74.9
Net income	256.6		112.1		24.7		393.4		28.0		71.3		17.6		—		510.3
Net income attributed to common shareholders	256.3		112.1		24.7		393.1		28.0		71.4		17.6		—		510.1

NOTE 18—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,


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along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance.

WEPCo Environmental Trust Finance I, LLC

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

In May 2021, WEPCo Environmental Trust issued ETBs and used the proceeds to acquire environmental control property from WE. The environmental control property is recorded as a regulatory asset on our balance sheets and includes the right to impose, collect, and receive a non-bypassable environmental control charge from WE's retail electric distribution customers until the ETBs are paid in full and all financing costs have been recovered. The ETBs are secured by the environmental control property. Cash collections from the environmental control charge, and funds on deposit in trust accounts, are the sole source of funds to satisfy the debt obligation. The bondholders have no recourse to WE or any of WE's affiliates other than WEPCo Environmental Trust.

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 an indenture trustee of WEPCo Environmental Trust.

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

The following table summarizes the impact of WEPCo Environmental Trust on our balance sheet.


(in millions)	March 31, 2022		December 31, 2021
Assets
Other current assets (restricted cash)	$	5.6	$	2.4
Regulatory assets	98.2		100.7
Other long-term assets (restricted cash)	0.6		0.6

Liabilities
Current portion of long-term debt	8.8		8.8
Accounts payable	0.1		—
Other current liabilities (accrued interest)	0.5		0.1
Long-term debt	102.8		102.7

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 March 31, 2022 and December 31, 2021, our equity investment in ATC was $1,795.0 million and $1,766.9 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


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method investment. At March 31, 2022 and December 31, 2021, our equity investment in ATC Holdco was $23.2 million and $22.5 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.

See Note 16, Investment in Transmission Affiliates, for more information, including any significant assets and liabilities related to ATC and ATC Holdco recorded on our balance sheets.

Power Purchase Commitment

WE has a PPA with LSP-Whitewater Limited Partnership that represents a variable interest. This agreement is for 236.5 MWs of firm capacity from a natural gas-fired cogeneration facility, and we account for it as a finance lease. The agreement expires on May 31, 2022 and includes no minimum energy requirements over the remaining term. We have examined the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity, and there is no residual guarantee associated with the PPA.

In November 2021, WE entered into a tolling agreement with LSP-Whitewater Limited Partnership that commences on June 1, 2022 upon the expiration of the PPA. Concurrent with the execution of the tolling agreement, WE and WPS also entered into an agreement to purchase the natural gas-fired cogeneration facility for $72.7 million. This purchase agreement is subject to regulatory approval by the PSCW, which is expected by the end of 2022. The tolling agreement extends until the earlier of the closing of the asset purchase or December 31, 2022. Since the terms of the tolling agreement are substantially similar to the terms of the PPA, we have determined that we are still not the primary beneficiary of the entity, and we will continue to account for the PPA and tolling agreement as a finance lease.

We have $3.9 million of required capacity payments over the remaining term of the PPA and tolling agreement. We believe that the required capacity payments under the agreements will continue to be recoverable in rates, and our maximum exposure to loss is limited to these capacity payments.

NOTE 19—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 wind 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 wind generating facilities.

Our minimum future commitments related to these purchase obligations as of March 31, 2022, including those of our subsidiaries, were approximately $10.5 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, fine particulates, mercury, and GHGs; water intake and discharges; management of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.


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Air Quality

Cross State Air Pollution Rule – Good Neighbor Plan

The EPA is proposing to update and expand the Cross State Air Pollution Rule to regulate NOx emissions in 25 states as part of the “good neighbor provision." As part of the proposed rule, expected to take effect in May 2023, the EPA would establish a new trading budget that would impose lower NOx emissions budgets on states, at a level that the EPA determined to be achievable through existing emissions controls as well as planned plant retirements.

Based on a review of our existing units' 2020 and 2021 actual ozone season emissions and projected future emissions versus proposed NOx ozone season allocations, we anticipate that we should be able to comply with the expanded rule requirements without procuring additional allowances on the open market.

Our RICE units in the Upper Peninsula of Michigan and planned RICE units in Wisconsin are not subject to this rule as proposed as each unit is expected to be less than 25 MW. We will closely monitor whether the EPA expands coverage of the rule to sources between 15 MW and 25 MW in the final rule. We are evaluating whether our engines for natural gas distribution operations in Michigan and Illinois are subject to the emission limits and operational requirements of the rule beginning in 2026.

National Ambient Air Quality Standards

Ozone

After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, creating a more stringent standard than the 2008 NAAQS. The 2015 ozone standard lowered the 8-hour limit for ground-level ozone. In December 2020, the EPA completed its 5-year review of the ozone standard and issued a final decision to retain, without any changes, the existing 2015 standard. Under Executive Order 13990, the Biden Administration ordered that all agencies review existing regulations, orders, guidance documents, policies, and similar actions promulgated, issued, or adopted between January 20, 2017 and January 20, 2021. In October 2021, the EPA announced that it will reconsider the December 2020 decision to retain the 2015 ozone standards with no changes and that it is targeting the end of 2023 to complete this reconsideration.

The EPA issued final nonattainment area designations for the 2015 ozone standard in April 2018. The following counties within our Wisconsin service territories were designated as partial nonattainment: Door, Kenosha, Sheboygan, Manitowoc, and Northern Milwaukee/Ozaukee. The area designations were challenged in the D.C. Circuit Court of Appeals in Clean Wisconsin et al. v. U.S. Environmental Protection Agency. A decision was issued in July 2020 remanding the rule to the EPA for further evaluation. As a result of the July 2020 remand, in June 2021, the EPA published its final action to revise the nonattainment area designations and/or boundaries for 13 counties associated with six nonattainment areas, including several in Illinois and Wisconsin. Under the new designations, all of Milwaukee and Ozaukee counties are now listed as nonattainment and portions of Racine, Waukesha, and Washington counties have been added to the nonattainment area. Additionally, the Chicago, Illinois, Indiana, and Wisconsin nonattainment area now includes an expanded portion of Kenosha County, and the partial nonattainment areas of Sheboygan, Door, and Manitowoc counties have also been expanded. Preliminary 2019-2021 monitoring data indicates that the Milwaukee and Chicago nonattainment areas will likely be adjusted to "moderate" nonattainment for the 2015 standard.

In February 2022, revisions to the Wisconsin Administrative Code to adopt the 2015 standard were finalized. The amended regulations adopted the standards and incorporated by reference the federal air pollution monitoring requirements related to the standard. We believe that we are well positioned to meet the requirements associated with the 2015 ozone standard and do not expect to incur significant costs to comply with the associated state and federal rules.

Particulate Matter

In December 2020, the EPA completed its 5-year review of the 2012 annual and 24-hour standards for fine particulate matter. The EPA determined that no revisions were necessary to the current standard. This determination was also subject to review under Executive Order 13990 and in June 2021, the EPA announced it would reconsider the December 2020 decision. Under the Biden Administration's policy review, the EPA concluded that the scientific evidence and information from the December 2020 determination supports revising the level of the annual standard for the particulate matter NAAQS to below the current level of 12 micrograms per cubic meter, while retaining the 24-hour standard. In March 2022, the EPA’s CASAC sent a letter to the EPA finalizing its peer review of the particulate matter standards. Based on their review, the majority of the members of the CASAC


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found that lowering the annual standard to within a range of 8 to 10 micrograms per cubic meter was appropriate, while a minority of the members of the committee found that a range of 10 to 11 micrograms per cubic meter would be appropriate. Additionally, a majority of the CASAC members favored lowering the 24-hour standard, while a minority concurred with EPA’s preliminary conclusion to retain the 24-hour standard without revision.

A proposed rule is expected in summer 2022, and a final rule is expected in spring 2023. All counties within our service territories are in attainment with the current 2012 standards. If the EPA lowers the annual standard to 10 or 11 micrograms per cubic meter, our generating facilities within our service territories should remain in attainment. If the EPA lowers it to below 10 micrograms per cubic meter, there could be some non-attainment areas that may affect permitting of some smaller ancillary equipment located at our facilities.

Climate Change

The ACE rule, which replaced the Clean Power Plan, was vacated by the D.C. Circuit Court of Appeals in January 2021. In October 2021, the Supreme Court agreed to review the D.C. Circuit Court's ruling vacating the EPA's ACE rule. The Supreme Court is reviewing a number of issues regarding the scope of the EPA's regulatory authority to utilize Section 111(d) of the CAA to address CO2 emissions. In February 2022, the Supreme Court heard oral arguments, and a decision is expected this summer.

In January 2021, the EPA finalized a rule to revise the New Source Performance Standards for GHG emissions from new, modified, and reconstructed fossil-fueled power plants; however, it was vacated by the D.C. Circuit Court of Appeals in April 2021. The EPA has signaled that a rule replacement is expected by the end of 2022. We continue to move forward on the ESG Progress Plan, which is heavily focused on reducing GHG emissions.

Our ESG Progress Plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables and clean natural gas-fueled generation. We have already retired more than 1,800 MW of coal-fired generation since the beginning of 2018. Through our ESG Progress Plan, we expect to retire approximately 1,600 MW of additional fossil-fueled generation by the end of 2025, which includes the planned retirements in 2023-2024 of OCPP Units 5-8 and the jointly-owned Columbia Units 1-2. In May 2021, we announced goals to achieve reductions in carbon emissions from our electric generation fleet by 60% by the end of 2025 and by 80% by the end of 2030, both from a 2005 baseline. We expect to achieve these goals by making operating refinements, retiring less efficient generating units, and executing our capital plan. Over the longer term, the target for our generation fleet is net-zero CO2 emissions by 2050.

We are required to report our CO2 equivalent emissions from the electric generating facilities we operate under the EPA Greenhouse Gases Reporting Program. We reported CO2 equivalent emissions of 22.0 million metric tonnes to the EPA for 2021. The level of CO2 and other GHG emissions varies from year to year and is dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO.

We are also required to report CO2 equivalent emissions related to the natural gas that our natural gas utilities distribute and sell. We reported aggregated CO2 equivalent emissions of 26.0 million metric tonnes to the EPA for 2021.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act that requires the location, design, construction, and capacity of cooling water intake structures at existing power plants to reflect the BTA for minimizing adverse environmental impacts. The federal rule became effective in October 2014 and 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. In 2016, the WDNR initiated a state rulemaking process to incorporate the federal Section 316(b) requirements into the Wisconsin Administrative Code. This new state rule, NR 111, became effective in June 2020, and the WDNR


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will apply it when establishing BTA requirements for cooling water intake structures at existing facilities. These BTA requirements are incorporated into WPDES permits for WE and WPS facilities.

We have received a final BTA determination for Valley power plant. We have received interim BTA determinations for PWGS, OCPP Units 5-8 and Weston Units 2, 3, and 4. We believe that existing technology at the PWGS satisfies the BTA requirements; however, a final determination will not be made until the WPDES permit is renewed for this facility, which is expected to be by the third quarter of 2022. We also believe that existing technology installed at the OCPP facility meets the BTA requirements; however, it is anticipated that these four generating units will be retired prior to the WDNR making a final BTA decision. In addition, we believe that existing technology installed at the Weston facility will result in a final BTA determination when the WPDES permit is renewed in 2023.

As a result of past capital investments completed to address Section 316(b) compliance at WE and WPS, we believe our fleet overall is well positioned to continue to meet this regulation and do not expect to incur significant additional compliance costs.

Steam Electric Effluent Limitation Guidelines

The EPA's final 2015 ELG rule took effect in January 2016 and was modified in 2020 to revise the treatment technology requirements related to BATW and wet FGD wastewaters at existing facilities. This rule created new requirements for several types of power plant wastewaters. The two new requirements that affect WE and WPS relate to discharge limits for BATW and wet FGD wastewater. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. There will, however, need to be facility modifications to meet water permit requirements for the BATW system at Weston Unit 3, which is expected to be completed by December 2023. Modifications to OC 7 and OC 8 were completed and placed in-service in mid-2021. Wastewater treatment system modifications also will be required for wet FGD discharges and site wastewater from the ERGS units. Based on engineering cost estimates, we expect that compliance with the ELG rule will require an additional $100 million in capital investment. In December 2021, the PSCW Division of Energy Regulation and Analysis issued a Certificate of Authority approving the ERGS FGD wastewater treatment system modification. The BATW modifications do not require PSCW approval prior to construction. All of these ELG required projects are either in-service or are on track for completion by the WPDES permit deadline in December 2023.

In July 2021, the EPA announced that it intends to initiate rulemaking to revise the ELG Rule as modified in 2020. The EPA has stated that the ELG Rule will continue to be implemented and enforced while the agency pursues this rulemaking process. The EPA plans to propose a revised rule in the fall of 2022.

Waters of the United States

In December 2021, the EPA and the United States Army Corps of Engineers together released a proposed rule to repeal the April 2020 Navigable Waters Protection Rule that defined WOTUS. The purpose of this proposed rule will be to restore regulations defining WOTUS that were in place prior to 2015 and to update certain provisions to be consistent with relevant Supreme Court decisions. The pre-2015 approach involves applying factors established through case law and agency precedents to determine whether a wetland or surface drainage feature is subject to federal jurisdiction. In January 2022, the Supreme Court granted certiorari in a case to evaluate the proper test for determining whether wetlands are WOTUS. At this point, our projects requiring federal permits are moving ahead, but we are monitoring to better understand potential future impacts. This case, once decided, should provide clarity regarding the definition of WOTUS. We will continue to monitor this litigation and any subsequent agency action.

Land Quality

Manufactured Gas Plant Remediation

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


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

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

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


(in millions)	March 31, 2022		December 31, 2021
Regulatory assets	$	618.8	$	630.9
Reserves for future environmental remediation	517.2		532.6

Enforcement and Litigation Matters

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

Consent Decrees

Wisconsin Public Service Corporation – Weston and Pulliam Power Plants

In November 2009, the EPA issued an NOV to WPS, which alleged violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam power plants from 1994 to 2009. WPS entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Eastern District of Wisconsin in March 2013. With the retirement of Pulliam Units 7 and 8 in October 2018, WPS completed the mitigation projects required by the Consent Decree and received a completeness letter from the EPA in October 2018. We are working with the EPA on a closeout process for the Consent Decree and expect that process to be completed in 2023.

Joint Ownership Power Plants – Columbia and Edgewater

In December 2009, the EPA issued an NOV to Wisconsin Power and Light Company, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric Company, WE (former co-owner of an Edgewater unit), and WPS. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. WPS, along with Wisconsin Power and Light Company, Madison Gas and Electric Company, and WE, entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013. As a result of the continued implementation of the Consent Decree related to the jointly owned Columbia and Edgewater plants, the Edgewater 4 generating unit was retired in September 2018. Wisconsin Power and Light Company expects to start the process to close out this Consent Decree in early 2023.

NOTE 20—SUPPLEMENTAL CASH FLOW INFORMATION


	Three Months Ended March 31
(in millions)	2022		2021
Cash paid for interest, net of amount capitalized	$	68.3	$	76.8
Cash paid (received) for income taxes, net	0.7		(2.5)
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs	118.7		97.8
Increase in receivable related to insurance proceeds	0.3		2.7


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The statements of cash flows include our activity related to cash, cash equivalents, and restricted cash. Our restricted cash primarily consists of the 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. All assets held within the rabbi trust are restricted as they can only be withdrawn from the trust to make qualifying benefit payments. Our restricted cash also consists of cash on deposit in financial institutions that is restricted to satisfy the requirements of certain debt agreements at WEC Infrastructure Wind Holding I LLC and WEPCo Environmental Trust. The restricted cash we received when WECI acquired ownership interests in certain wind generation projects is included in our restricted cash as well. This cash is restricted as it can only be used to pay for any remaining costs associated with the construction of the wind generation facilities.

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)	March 31, 2022		December 31, 2021
Cash and cash equivalents	$	33.8	$	16.3
Restricted cash included in other current assets	31.8		19.6
Restricted cash included in other long term assets	54.0		51.6
Cash, cash equivalents, and restricted cash	$	119.6	$	87.5

NOTE 21—REGULATORY ENVIRONMENT

Recovery of Natural Gas Costs

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

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

PGL and NSG incurred approximately $131 million and $10 million, respectively, of natural gas costs in February 2021 in excess of the amounts included in their rates. These costs were recovered over a period of 12 months, which started on April 1, 2021. PGL's and NSG's natural gas costs are being reviewed for prudency by the ICC as part of their annual natural gas cost reconciliation. The ICC could order the refund of any costs determined to be imprudent as part of the reconciliation. A decision regarding this review is expected by the end of 2022.

In February 2021, MERC incurred approximately $75 million of natural gas costs in excess of the benchmark set in its GCRM. In August 2021, the MPUC issued a written order approving a joint proposal filed by MERC and four other Minnesota utilities to recover their respective excess natural gas costs. MERC will recover $10 million of these costs through its annual natural gas true-up process over a period of 12 months, and the remaining $65 million over 27 months, both of which started in September 2021. Recovery of these costs and the issue of prudence has been referred to a contested-case proceeding. As a result of the proceeding, the MPUC could disallow recovery or order the refund of any costs determined to be imprudent. A decision regarding this review is expected during the third quarter of 2022.

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


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

2023 and 2024 Rates

In April 2022, WE, WPS, and WG filed requests with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable, effective January 1, 2023. The requests reflected the following:


	WE					WPS					WG
Proposed 2023 rate increase
Electric	$	260.5	million	/	8.4%	$	73.9	million	/	6.2%	N/A
Gas	$	50.7	million	/	10.7%	$	30.3	million	/	8.3%	$	60.1	million	/	8.3%
Steam	$	3.3	million	/	15.5%	N/A					N/A
Proposed ROE (1)	10.0%					10.0%					10.2%
Proposed common equity component average on a financial basis (1)	53.0%					53.0%					53.0%

(1) The proposed ROEs are consistent with each utilities' currently authorized ROE. The common equity component average for each utility is currently 52.5%.

The primary drivers of the requested increases in electric rates are capital investments in new wind, solar, and battery storage; capital investments in natural gas generation; reliability investments, including grid hardening projects to bury power lines and strengthen WE's distribution system against severe weather; and changes in wholesale business with other utilities. Many of these investments have already been approved by the PSCW.

The requested increases in natural gas rates primarily relate to capital investments previously approved by the PSCW, including LNG storage for our natural gas distribution system.

The utilities also proposed continuing to use an earnings sharing mechanism. Under the proposed earnings sharing mechanism, if the utility earns above its authorized ROE: (i) the utility would retain 100.0% of earnings for the first 25 basis points above the authorized ROE; (ii) 50.0% of the next 50 basis points would be required to be refunded to ratepayers; and (iii) 100.0% of any remaining excess earnings would be required to be refunded to ratepayers.

WE and WPS are seeking a limited rate re-opener for 2024 to address additional revenue requirements associated with generation projects that are expected to be placed into service in 2023 and 2024. In addition, WE and WG are requesting a limited rate re-opener for 2024 to address additional revenue requirements associated with LNG projects that are expected to be placed into service in 2023 and 2024, respectively.

We expect a decision from the PSCW in the fourth quarter of 2022, with any rate adjustments expected to be effective January 1, 2023.

The Peoples Gas Light and Coke Company

Qualifying Infrastructure Plant Rider

In July 2013, Illinois Public Act 98-0057, The Natural Gas Consumer, Safety & Reliability Act, became law. This law provides natural gas utilities with a cost recovery mechanism that allows collection, through a surcharge on customer bills, of prudently incurred costs to upgrade Illinois natural gas infrastructure. In January 2014, the ICC approved a QIP rider for PGL, which is in effect through 2023.

PGL's QIP rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2022, PGL filed its 2021 reconciliation with the ICC, which, along with the 2020, 2019, 2018, 2017, and 2016 reconciliations, are still pending.

As of March 31, 2022, there can be no assurance that all costs incurred under PGL's QIP rider during the open reconciliation years will be deemed recoverable by the ICC.


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NOTE 22—NEW ACCOUNTING PRONOUNCEMENTS

Reference Rate Reform

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments apply only to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. The amendments are effective for all entities as of March 12, 2020 through December 31, 2022. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

Government Assistance

In November 2021, the FASB issued ASU No. 2021-10, Government Assistance (Topic 832). The amendments in this update increase the transparency surrounding government assistance by requiring disclosure of: (i) the types of assistance received; (ii) an entity’s accounting for the assistance; and (iii) the effect of the assistance on the entity’s financial statements. The update is effective for annual periods beginning after December 15, 2021. We plan to adopt this pronouncement for our fiscal year ending on December 31, 2022, and we 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 2021 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 American Transmission Company LLC (ATC) (a for-profit electric transmission company regulated by the Federal Energy Regulatory Commission and certain state regulatory commissions), and non-utility energy infrastructure operations through W.E. Power, LLC (which owns generation assets in Wisconsin), Bluewater Natural Gas Holding, LLC (which owns underground natural gas storage facilities in Michigan), and WEC Infrastructure LLC (WECI), which holds ownership interests in several wind generating facilities.

Corporate Strategy

Our goal is to continue to build and sustain long-term value for our shareholders and customers by focusing on the fundamentals of our business: environmental stewardship; reliability; operating efficiency; financial discipline; exceptional customer care; and safety. Our capital investment plan for efficiency, sustainability and growth, referred to as our ESG Progress Plan, provides a roadmap for us to achieve this goal. It is an aggressive plan to cut emissions, maintain superior reliability, deliver significant savings for customers, and grow 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. We published the results of a priority sustainability issue assessment in 2020, identifying the issues that are most important to our company and its stakeholders over the short and long terms. Our risk and priority assessments have formed our direction as a company.

Creating a Sustainable Future

Our ESG Progress Plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables and clean natural gas-fired generation. When taken together, the retirements and new investments should better balance our supply with our demand, while maintaining reliable, affordable energy for our customers. The retirements will contribute to meeting our goals to reduce carbon dioxide (CO2) emissions from our electric generation.

In May 2021, we announced goals to achieve reductions in carbon emissions from our electric generation fleet by 60% by the end of 2025 and by 80% by the end of 2030, both from a 2005 baseline. We expect to achieve these goals by making operating refinements, retiring less efficient generating units, and executing our capital plan. Over the longer term, the target for our generation fleet is net-zero CO2 emissions by 2050.

As part of our path toward these goals, we are exploring co-firing with natural gas at our ERGS coal-fired units. By the end of 2030, we expect our use of coal will account for less than 5% of the power we supply to our customers, and we believe we will be in a position to eliminate coal as an energy source by the end of 2035.

We already have retired more than 1,800 megawatts (MW) of coal-fired generation since the beginning of 2018, which included the 2019 retirement of the Presque Isle power plant as well as the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater Unit 4 generating units. Through our ESG Progress Plan, we expect to retire approximately 1,600 MW of additional fossil-fueled generation by the end of 2025, which includes the planned retirements in 2023-2024 of Oak Creek Power Plant Units 5-8 and the jointly-owned Columbia Units 1-2.


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In addition to retiring these older, fossil-fueled plants, we expect to invest approximately $3.5 billion from 2022-2026 in regulated renewable energy in Wisconsin. Our plan is to replace a portion of the retired capacity by building and owning zero-carbon-emitting renewable generation facilities that are anticipated to include the following new investments:

•1,400 MW of utility-scale solar;

•800 MW of battery storage; and

•100 MW of wind.

We also plan on investing in a combination of clean, natural gas-fired generation, including:

•100 MW of reciprocating internal combustion engine (RICE) natural gas-fueled generation;

•the planned purchase of up to 200 MW of capacity in the West Riverside Energy Center — a new, combined-cycle natural gas plant completed by Alliant Energy in Wisconsin; and

•the planned purchase of the Whitewater Cogeneration Facility, a natural gas-fired combined cycle electric generating facility with a capacity of 236.5 MW.

The new investments discussed above are in addition to the renewable projects currently underway. For more details, see Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.

In addition, we are investing in 300 MW of utility-scale solar within our Wisconsin segment. Wisconsin Public Service Corporation (WPS) partnered with an unaffiliated utility to construct two solar projects now in service in Wisconsin: Two Creeks Solar Park (Two Creeks) and Badger Hollow Solar Park I (Badger Hollow I). WPS owns 100 MW of Two Creeks and 100 MW of Badger Hollow I for a total of 200 MW. Wisconsin Electric Power Company (WE) has partnered with an unaffiliated utility to construct Badger Hollow Solar Park II, which is expected to enter commercial operation in the first half of 2023. Once constructed, WE will own 100 MW of this project.

In December 2018, WE received approval from the PSCW for two renewable energy pilot programs. The Solar Now pilot is expected to add a total of 35 MW of solar generation to WE's portfolio, allowing non-profit and governmental entities, as well as commercial and industrial customers, to site utility owned solar arrays on their property. Under this program, WE has energized 23 Solar Now projects and currently has another one under construction, together totaling more than 27 MW. The second program, the Dedicated Renewable Energy Resource pilot, would allow large commercial and industrial customers to access renewable resources that WE would operate, adding up to 150 MW of renewables to WE's portfolio, and helping these larger customers meet their sustainability and renewable energy goals.

In August 2021, the PSCW approved pilot programs for WE and WPS to install and maintain electric vehicle (EV) charging equipment for customers at their homes or businesses. The programs provide direct benefits to customers by removing cost barriers associated with installing EV equipment. In October 2021, subject to the receipt of any necessary regulatory approvals, we pledged to expand the EV charging network within the service territories of our electric utilities. In doing so, we joined a coalition of utility companies in a unified effort to make EV charging convenient and widely available throughout the Midwest. The coalition we joined is planning to help build and grow EV charging corridors, enabling the general public to safely and efficiently charge their vehicles.

We also continue to reduce methane emissions by improving our natural gas distribution system. We set a target across our natural gas distribution operations to achieve net-zero methane emissions by the end of 2030. We plan to achieve our net-zero goal through an effort that includes both continuous operational improvements and equipment upgrades, as well as the use of renewable natural gas (RNG) throughout our utility systems. In 2022, we signed our first two contracts for RNG for our natural gas distribution business, which will be transporting the output of local dairy farms onto our gas distribution system. The RNG supplied will directly replace higher-emission methane from natural gas that would have entered our pipes. These two contracts represents approximately 50 percent of our 2030 goal for methane reduction. We expect to have RNG flowing to our distribution network by the end of 2022.

As part of our effort to look for new opportunities in sustainable energy, we are testing the effects of blending hydrogen, a clean generating fuel, with natural gas for one of our RICE generating units in the Upper Peninsula of Michigan. We are partnering with the Electric Power Research Institute in this research that could help create another viable option for decarbonizing the economy. The project will be carried out in 2022, and the results will be shared across the industry.


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Reliability

We have made significant reliability-related investments in recent years, and in accordance with our ESG Progress 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 examples of reliability projects that are proposed, currently underway, or recently completed.

•WE and Wisconsin Gas LLC (WG) have received approval to each construct their own liquefied natural gas (LNG) facility to meet anticipated peak demand. Commercial operation of the WE and WG LNG facilities is targeted for the end of 2023 and 2024, respectively.

•The Peoples Gas Light and Coke Company continues to work on its Safety Modernization Program, which primarily involves replacing 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.

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

For more details, see Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.

Operating Efficiency

We continually look for ways to optimize the operating efficiency of our company and will continue to do so under the ESG Progress Plan. For example, we are making 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 disconnects and reconnects and enhances outage management capabilities.

We continue to focus on integrating the resources of all our businesses and finding the best and most efficient processes while meeting all applicable legal and regulatory requirements.

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 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, for information on our acquisition of Whitewater.

Our investment focus remains in our regulated utility and non-utility energy infrastructure businesses, as well as our investment in ATC. In our non-utility energy infrastructure segment, we have acquired or agreed to acquire majority interests in eight wind parks, with total available capacity of more than 1,550 MW. These renewable energy assets represent more than $2.3 billion in committed investments and have long-term agreements to serve customers outside our traditional service areas. Production tax credits from these wind investments reduce our cash tax expense. See Note 2, Acquisitions, for additional information on recent and pending transactions.

We expect total capital expenditures for our regulated utility and non-utility energy infrastructure businesses to be approximately $16.4 billion from 2022 to 2026. In addition, we currently forecast that our share of ATC's projected capital expenditures over the next five years will be $1.3 billion. Specific projects included in the $17.7 billion ESG Progress Plan are discussed in more detail below under Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.


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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.

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 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 MARCH 31, 2022

Consolidated Earnings

The following table compares our consolidated results for the first quarter of 2022 with the first quarter of 2021, including favorable or better, "B", and unfavorable or worse, "W", variances:


	Three Months Ended March 31
(in millions, except per share data)	2022		2021		B (W)
Wisconsin	$	288.1	$	256.3	$	31.8
Illinois	113.4		112.1		1.3
Other states	31.5		24.7		6.8
Electric transmission	27.8		28.0		(0.2)
Non-utility energy infrastructure	91.5		71.4		20.1
Corporate and other	13.6		17.6		(4.0)
Net income attributed to common shareholders	$	565.9	$	510.1	$	55.8

Diluted earnings per share	$	1.79	$	1.61	$	0.18

Earnings increased $55.8 million during the first quarter of 2022, compared with the same quarter in 2021. The significant factors impacting the $55.8 million increase in earnings were:

•A $31.8 million increase in net income attributed to common shareholders at the Wisconsin segment, driven by an increase in natural gas margins related to higher retail sales volumes, primarily due to colder winter weather during the first quarter of 2022, compared with the same quarter in 2021, as well as the continued economic recovery in Wisconsin from the COVID-19 pandemic. Also contributing to the increase in earnings were lower operating expenses, driven by the amortization of certain regulatory liabilities to offset a portion of our 2022 forecasted revenue deficiencies, as approved by the PSCW in order to forego filing for 2022 base rate increases. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on our 2022 Wisconsin base rates. The positive impact from the amortization of the regulatory liabilities was partially


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offset by higher depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan.

•A $20.1 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by the recognition of revenue related to market settlements Upstream received from SPP in February 2021. Due to a complaint filed with the FERC, the revenue related to these settlements could not be recognized until the FERC issued an order denying the complaint in the first quarter of 2022. An increase in PTCs generated in 2022, driven by the Jayhawk wind park that achieved commercial operation in December 2021, and higher generation at our other wind parks, also contributed to the increase in earnings.

•A $6.8 million increase in net income attributed to common shareholders at the other states segment, driven by an increase in natural gas margins due to a rate increase at MGU, effective January 1, 2022, and higher sales volumes as a result of continued economic recovery and colder weather during the first quarter of 2022, compared with the same quarter in 2021.

Expected 2022 Annual Effective Tax Rate

We expect our 2022 annual effective tax rate to be between 18.5% and 19.5%. 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 segments to net income attributed to common shareholders. The discussions include financial information prepared in accordance with GAAP, as well as electric margins and natural gas margins, which are not measures of financial performance under GAAP. Electric margins (electric revenues less fuel and purchased power costs) and natural gas margins (natural gas revenues less cost of natural gas sold) are non-GAAP financial measures because they exclude other operation and maintenance expense, depreciation and amortization, and property and revenue taxes.

We believe that electric and natural gas margins provide 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 electric and natural gas margins internally when assessing the operating performance of our segments as these measures exclude the majority of revenue fluctuations caused by changes in these expenses. Similarly, the presentation of electric and natural gas margins herein is intended to provide supplemental information for investors regarding our operating performance.

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance. The following table shows operating income by segment for our utility operations during the first quarter of 2022 and 2021:


	Three Months Ended March 31
(in millions)	2022		2021
Wisconsin	$	497.7	$	427.7
Illinois	168.2		168.2
Other states	44.6		34.3

Each applicable segment discussion below includes a table that provides the calculation of electric margins and natural gas margins, as applicable, along with a reconciliation to the most directly comparable GAAP measure, operating income.


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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 $288.1 million during the first quarter of 2022, representing a $31.8 million, or 12.4%, increase over the same quarter in 2021. The higher earnings were driven by an increase in natural gas margins related to higher retail sales volumes, primarily due to colder winter weather during the first quarter of 2022, compared with the same quarter in 2021, as well as the continued economic recovery in Wisconsin from the COVID-19 pandemic. Also contributing to the increase in earnings were lower operating expenses, driven by the amortization of certain regulatory liabilities to offset a portion of our 2022 forecasted revenue deficiencies, as approved by the PSCW in order to forego filing for 2022 base rate increases. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on our 2022 Wisconsin base rates. The positive impact from the amortization of the regulatory liabilities was partially offset by higher depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan.


	Three Months Ended March 31
(in millions)	2022		2021		B (W)
Electric revenues	$	1,193.0	$	1,101.8	$	91.2
Fuel and purchased power	406.9		349.4		(57.5)
Total electric margins	786.1		752.4		33.7

Natural gas revenues	749.3		629.9		119.4
Cost of natural gas sold	496.8		397.9		(98.9)
Total natural gas margins	252.5		232.0		20.5

Total electric and natural gas margins	1,038.6		984.4		54.2

Other operation and maintenance	312.6		341.9		29.3
Depreciation and amortization	187.1		176.2		(10.9)
Property and revenue taxes	41.2		38.6		(2.6)
Operating income	497.7		427.7		70.0

Other income, net	22.4		17.1		5.3
Interest expense	136.3		140.1		3.8
Income before income taxes	383.8		304.7		79.1

Income tax expense	95.4		48.1		(47.3)
Preferred stock dividends of subsidiary	0.3		0.3		—
Net income attributed to common shareholders	$	288.1	$	256.3	$	31.8

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


	Three Months Ended March 31
(in millions)	2022		2021		B (W)
Operation and maintenance not included in line items below	$	146.7	$	147.3	$	0.6
Transmission (1)	107.9		127.7		19.8
Regulatory amortizations and other pass through expenses (2)	35.8		37.5		1.7
We Power (3)	27.6		29.4		1.8
Earnings sharing mechanisms (4)	(5.4)		—		5.4
Total other operation and maintenance	$	312.6	$	341.9	$	29.3

(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 first quarter of 2022 and 2021, $126.5 million and $130.6 million, respectively, of costs were billed to our electric utilities by transmission providers.

During the first quarter of 2022, WE and WPS amortized $20.2 million of the regulatory liabilities associated with their transmission escrows to offset certain 2022 revenue deficiencies, as approved by the PSCW in order to forego filing for 2022 base rate increases. This amortization drove the decrease in transmission expense in the first quarter of 2022, compared with the same quarter in 2021. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on 2022 Wisconsin base rates.


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(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 first quarter of 2022 and 2021, $24.8 million and $25.9 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.

(4)Represents amortization of a certain portion of WPS's regulatory liability associated with its 2020 earnings sharing mechanism to offset certain 2022 revenue deficiencies, as approved by the PSCW in order to forego filing for 2022 base rate increases. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on 2022 Wisconsin base rates.

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


	Three Months Ended March 31
	MWh (in thousands)
Electric Sales Volumes	2022	2021	B (W)
Customer Class
Residential	2,844.0	2,808.8	35.2
Small commercial and industrial (1)	3,205.6	3,087.1	118.5
Large commercial and industrial (1)	2,982.1	2,981.9	0.2
Other	40.2	43.9	(3.7)
Total retail (1)	9,071.9	8,921.7	150.2
Wholesale	718.5	730.3	(11.8)
Resale	1,238.8	1,937.5	(698.7)
Total sales in MWh (1)	11,029.2	11,589.5	(560.3)

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


	Three Months Ended March 31
	Therms (in millions)
Natural Gas Sales Volumes	2022	2021	B (W)
Customer Class
Residential	565.3	515.5	49.8
Commercial and industrial	346.2	303.0	43.2
Total retail	911.5	818.5	93.0
Transportation	446.6	427.3	19.3
Total sales in therms	1,358.1	1,245.8	112.3


	Three Months Ended March 31
	Degree Days
Weather	2022	2021	B (W)
WE and WG (1)
Heating (3,267 Normal)	3,325	3,120	6.6	%


WPS (2)
Heating (3,647 Normal)	3,843	3,482	10.4	%


UMERC (3)
Heating (3,960 Normal)	4,339	3,790	14.5	%

(1)Normal degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin.

(2)Normal degree days are based on a 20-year moving average of monthly temperatures from the Green Bay, Wisconsin weather station.

(3)Normal degree days are based on a 20-year moving average of monthly temperatures from the Iron Mountain, Michigan weather station.


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Electric Revenues

Electric revenues increased $91.2 million during the first quarter of 2022, compared with the same quarter in 2021. To the extent that changes in fuel and purchased power costs are passed through to customers, the changes are offset by comparable changes in revenues. See the discussion of electric utility margins below for more information related to the recovery of fuel and purchased power costs and the remaining drivers of the changes in electric revenues.

Electric Utility Margins

Electric utility margins at the Wisconsin segment increased $33.7 million during the first quarter of 2022, compared with the same quarter in 2021. The significant factors impacting the higher electric utility margins were:

•A $35.8 million increase in margins related to the impact of unprotected excess deferred taxes in the first quarter of 2021, which we agreed to return to customers in our PSCW-approved Wisconsin rate orders. This increase in margins is offset in income taxes.

•Securitization revenues of $3.2 million received during the first quarter of 2022 related to an environmental control charge collected from WE's retail electric distribution customers. We began assessing this charge in June 2021, subsequent to the issuance of the ETBs by WEPCo Environmental Trust in May 2021, in accordance with a November 2020 PSCW financing order. See Note 18, Variable Interest Entities, for more information. These revenues are offset in depreciation and amortization as well as interest expense.

•A $3.0 million net increase in margins related to higher retail sales volumes, driven by the impact of colder winter weather during the first quarter of 2022, compared with the same quarter in 2021. As measured by heating degree days, the first quarter of 2022 was 6.6% and 10.4% colder than the same quarter in 2021 in the Milwaukee area and Green Bay area, respectively.

These increases in margins were partially offset by:

•A $4.2 million quarter-over-quarter negative impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, the margins of our electric utilities are impacted by under- or over-collections of certain fuel and purchased power costs that are within a 2% price variance from the costs included in rates, and the remaining variance beyond the 2% price variance is generally deferred for future recovery or refund to customers.

•Lower margins of $3.0 million driven by a decrease in wholesale customers related to the expiration of certain wholesale contracts.

Natural Gas Revenues

Natural gas revenues increased $119.4 million during the first quarter of 2022, compared with the same quarter in 2021. Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues. The average per-unit cost of natural gas increased 12.6% during the first quarter of 2022, compared with the same quarter in 2021. The remaining drivers of changes in natural gas revenues are described in the discussion of natural gas utility margins below.

Natural Gas Utility Margins

Natural gas utility margins at the Wisconsin segment increased $20.5 million during the first quarter of 2022, compared with the same quarter in 2021. The significant factors impacting the higher natural gas utility margins were:

•An $18.7 million increase in margins from higher sales volumes, primarily driven by colder winter weather during the first quarter of 2022, compared with the same quarter in 2021, as well as the continued economic recovery in Wisconsin from the COVID-19 pandemic.

•A $2.5 million increase in margins related to amortization of a certain portion of WG's regulatory liability consisting of credit balances associated with the escrow of natural gas storage service costs from Bluewater Gas Storage, LLC. In September 2021, the PSCW issued a written order for our Wisconsin utilities approving certain accounting treatments to offset certain 2022


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revenue deficiencies in order to forego filing for 2022 base rate increases. See Note 26 Regulatory Environment, in our 2021 Annual Report on Form 10-K for more information.

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

Other operating expenses at the Wisconsin segment decreased $15.8 million during the first quarter of 2022, compared with the same quarter in 2021. The significant factors impacting the decrease in operating expenses were:

•A $19.8 million decrease in transmission expense driven by the amortization of a certain portion of WE's and WPS's regulatory liabilities associated with transmission escrow balances, as discussed in the notes under the other operation and maintenance table above.

•A $5.4 million decrease in expense driven by the amortization of a certain portion of WPS's regulatory liability associated with its 2020 earnings sharing mechanism, as discussed in the notes under the other operation and maintenance table above.

•A $2.1 million decrease related to a gain on land sales during the first quarter of 2022.

•A $1.8 million decrease in other operation and maintenance expense related to the We Power leases, as discussed in the notes under the other operation and maintenance table above.

•A $1.7 million decrease in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

These decreases in other operating expenses were partially offset by:

•A $10.9 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan, as well as an increase related to the We Power leases. In addition, a portion of the increase is related to securitization amortization, which is offset in revenues. The increase in depreciation was partially offset by $2.6 million of depreciation related to capital investments made by WG since it's last rate case, as approved by the PSCW in an order that allowed our Wisconsin utilities to offset certain 2022 revenue deficiencies in order to forego filing for 2022 base rate increases. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for more information.

•An $8.7 million increase in electric and natural gas distribution expenses, primarily driven by increased maintenance expense related to significant winter storms in 2022.

Other Income, Net

Other income, net at the Wisconsin segment increased $5.3 million during the first quarter of 2022, compared with the same quarter in 2021, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 14, Employee Benefits, for more information on our benefit costs.

Interest Expense

Interest expense at the Wisconsin segment decreased $3.8 million during the first quarter of 2022, compared with the same quarter in 2021, primarily due to the deferral of interest expense related to capital investments made by WG since its last rate case, as approved by the PSCW in an order that allowed our Wisconsin utilities to offset certain 2022 revenue deficiencies in order to forego filing for a 2022 base rate increase. Also contributing to the decrease was lower interest expense on finance lease liabilities, primarily related to the WE Power leases, as finance lease liabilities decrease each year as payments are made. See Note 26 Regulatory Environment, in our 2021 Annual Report on Form 10-K for more information.

Income Tax Expense

Income tax expense at the Wisconsin segment increased $47.3 million during the first quarter of 2022, compared with the same quarter in 2021. The increase in income tax expense was due to an approximate $35.7 million negative impact related to the lower quarter-over-quarter amortization of the unprotected excess deferred tax benefits from the Tax Legislation in connection with the


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Wisconsin rate orders approved by the PSCW, effective January 1, 2020. The impact due to the benefit from the amortization of the unprotected excess deferred tax benefits from the Tax Legislation did not impact earnings as there was an offsetting impact in operating income. Also contributing to this increase in income tax expense was an increase in pretax income. See Note 10, Income Taxes, for more information.

Illinois Segment Contribution to Net Income Attributed to Common Shareholders

The Illinois segment's contribution to net income attributed to common shareholders was $113.4 million during the first quarter of 2022, representing a $1.3 million, or 1.2%, increase over the same quarter in 2021. The increase was driven by PGL's continued capital investment in the SMP project under its QIP rider and the impact of NSG's rate order, which became effective September 15, 2021. These increases in earnings were partially offset by higher depreciation and amortization and an increase in costs related to maintenance at the Manlove Gas Storage Field.

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 March 31
(in millions)	2022		2021		B (W)
Natural gas revenues	$	682.1	$	703.4	$	(21.3)
Cost of natural gas sold	331.0		363.6		32.6
Total natural gas margins	351.1		339.8		11.3

Other operation and maintenance	113.6		109.3		(4.3)
Depreciation and amortization	56.8		52.7		(4.1)
Property and revenue taxes	12.5		9.6		(2.9)
Operating income	168.2		168.2		—

Other income, net	5.0		1.8		3.2
Interest expense	17.7		16.5		(1.2)
Income before income taxes	155.5		153.5		2.0

Income tax expense	42.1		41.4		(0.7)
Net income attributed to common shareholders	$	113.4	$	112.1	$	1.3

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


	Three Months Ended March 31
(in millions)	2022		2021		B (W)
Operation and maintenance not included in the line items below	$	70.5	$	66.8	$	(3.7)
Riders (1)	43.5		43.1		(0.4)
Regulatory amortizations (1)	(0.4)		(0.6)		(0.2)

Total other operation and maintenance	$	113.6	$	109.3	$	(4.3)

(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 March 31
	Therms (in millions)
Natural Gas Sales Volumes	2022	2021	B (W)
Customer Class
Residential	429.8	411.9	17.9
Commercial and industrial	172.9	160.0	12.9
Total retail	602.7	571.9	30.8
Transportation	358.7	330.8	27.9
Total sales in therms	961.4	902.7	58.7


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	Three Months Ended March 31
	Degree Days
Weather (1)	2022	2021	B (W)
Heating (3,111 Normal)	3,209	3,003	6.9	%

(1)Normal heating degree days are based on a 12-year moving average of monthly temperatures from Chicago's O'Hare Airport.

Natural Gas Revenues

Natural gas revenues decreased $21.3 million during the first quarter of 2022, compared with the same quarter in 2021. Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues. The average per-unit cost of natural gas sold decreased 14.1% during the first quarter of 2022, compared with the same quarter in 2021. The remaining drivers of changes in natural gas revenues are described in the discussion of margins below.

Natural Gas Utility Margins

Natural gas utility margins at the Illinois segment, net of the $0.4 million impact of the riders referenced in the table above, increased $10.9 million during the first quarter of 2022, compared with the same quarter in 2021. The increase in margins was primarily driven by:

•A $6.3 million increase in revenues at PGL due to continued capital investment in the SMP project. PGL recovers the costs related to the SMP through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023. See Note 21, Regulatory Environment, for more information

•A $5.9 million increase related to the impact of the NSG rate order approved by the ICC, effective September 15, 2021, which includes the Variable Income Tax Adjustment Rider in base rates. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on the 2021 rate order.

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

Other operating expenses at the Illinois segment increased $10.9 million, net of the $0.4 million impact of the riders referenced in the table above, during the first quarter of 2022, compared with the same quarter in 2021. The significant factors impacting the increase in operating expenses were:

•A $4.1 million increase in depreciation expense, primarily driven by PGL's continued capital investment in the SMP project.

•A $3.5 million increase in costs associated with maintenance at the Manlove Gas Storage Field.

•A $2.9 million increase in property and revenue taxes driven by an increase in the invested capital tax related to higher plant placed in service during the first quarter of 2022, compared with the same quarter in 2021. This increase was offset in natural gas utility margins.

Other Income, Net

Other income, net at the Illinois segment increased $3.2 million during the first quarter of 2022, compared with the same quarter in 2021, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 14, Employee Benefits, for more information on our benefit costs.

Interest Expense

Interest expense at the Illinois segment increased $1.2 million during the first quarter of 2022, compared with the same quarter in 2021, primarily due to $225.0 million of long-term debt issuances in November 2021.


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Income Tax Expense

Income tax expense at the Illinois segment increased $0.7 million during the during the first quarter of 2022, compared with the same quarter in 2021, driven by an increase in pretax 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 during the first quarter of 2022 was $31.5 million, representing a $6.8 million, or 27.5%, increase over the same quarter in 2021. The increase was driven by higher natural gas margins due to a rate increase at MGU, effective January 1, 2022, and higher sales volumes as a result of continued economic recovery and colder weather during the first quarter of 2022, compared with the same quarter in 2021.

Since the majority of MGU and MERC 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 March 31
(in millions)	2022		2021		B (W)
Natural gas revenues	$	240.9	$	233.3	$	7.6
Cost of natural gas sold	156.9		161.7		4.8
Total natural gas margins	84.0		71.6		12.4

Other operation and maintenance	24.6		23.2		(1.4)
Depreciation and amortization	10.0		9.2		(0.8)
Property and revenue taxes	4.8		4.9		0.1
Operating income	44.6		34.3		10.3

Other income, net	0.6		0.3		0.3
Interest expense	3.3		1.5		(1.8)
Income before income taxes	41.9		33.1		8.8

Income tax expense	10.4		8.4		(2.0)
Net income attributed to common shareholders	$	31.5	$	24.7	$	6.8

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


	Three Months Ended March 31
(in millions)	2022		2021		B (W)
Operation and maintenance not included in line item below	$	17.4	$	16.1	$	(1.3)
Regulatory amortizations and other pass through expenses (1)	7.2		7.1		(0.1)

Total other operation and maintenance	$	24.6	$	23.2	$	(1.4)

(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 March 31
	Therms (in millions)
Natural Gas Sales Volumes	2022	2021	B (W)
Customer Class
Residential	172.0	149.0	23.0
Commercial and industrial	103.0	85.7	17.3
Total retail	275.0	234.7	40.3
Transportation	261.0	234.2	26.8
Total sales in therms	536.0	468.9	67.1


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	Three Months Ended March 31
	Degree Days
Weather (1)	2022	2021	B (W)
MERC
Heating (3,958 Normal)	4,312	3,785	13.9	%

MGU
Heating (3,156 Normal)	3,234	3,014	7.3	%

(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 temperatures from various weather stations throughout their respective service territories.

Natural Gas Revenues

Natural gas revenues increased $7.6 million during the first quarter of 2022, compared with the same quarter in 2021. To the extent that changes in natural gas costs are passed through to customers, the changes are offset by comparable changes in revenues. See the discussion of natural gas utility margins below for the remaining drivers of changes in natural gas revenues.

Natural Gas Utility Margins

Natural gas utility margins increased $12.4 million during the first quarter of 2022, compared to the same quarter in 2021. The increase in margins was primarily driven by:

•A $6.4 million increase related to the new rates at MGU that went into effect in 2022.

•A $4.4 million increase related to higher sales volumes due to continued economic recovery and colder weather during the first quarter of 2022, as compared to the same quarter in 2021.

•A $1.2 million increase 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 rate payers using the Conservation Cost Recovery Charge and the Conservation Cost Recovery Adjustment funds that are collected on their monthly billing statements.

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 $2.1 million during the first quarter of 2022, compared to the same quarter in 2021. The significant factors impacting the increase in operating expenses were:

•A $1.2 million increase in operation and maintenance expense related to MERC's CIP program, which has an offsetting increase in margins.

•A $0.8 million increase in depreciation and amortization related to continued capital investment.

•A $0.7 million increase in operation and maintenance expense related to higher labor costs and snow removal.

These increases in operating expenses were partially offset by a $1.1 million decrease in bad debt expense related to improvement in past due receivables.

Interest Expense

Interest expense at the other states segment increased $1.8 million during the first quarter of 2022, compared with the same quarter in 2021, primarily due to the deferral of $1.2 million of interest expense in the first quarter of 2021 related to capital investments made by MGU since its last rate case, as approved by the Michigan Public Service Commission. This deferred interest expense is now being amortized over a four-year period as a result of MGU's approved rate increase.


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Income Tax Expense

Income tax expense at the other states segment increased $2.0 million during the first quarter of 2022, compared with the same quarter in 2021, driven by a higher pretax income.

Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders


	Three Months Ended March 31
(in millions)	2022		2021		B (W)
Equity in earnings of transmission affiliates	$	41.7	$	42.6	$	(0.9)
Other expense (income)	0.1		(0.1)		(0.2)
Interest expense	4.9		4.9		—
Income before income taxes	36.7		37.8		(1.1)

Income tax expense	8.9		9.8		$	0.9
Net income attributed to common shareholders	$	27.8	$	28.0	$	(0.2)

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


	Three Months Ended March 31
(in millions)	2022		2021		B (W)
Operating income	$	105.6	$	89.4	$	16.2


Interest expense	17.2		18.0		0.8
Income before income taxes	88.4		71.4		17.0

Income tax expense (benefit)	(4.9)		0.1		5.0
Net (income) loss attributed to noncontrolling interests	(1.8)		0.1		(1.9)
Net income attributed to common shareholders	$	91.5	$	71.4	$	20.1

Operating Income

Operating income at the non-utility energy infrastructure segment increased $16.2 million during the first quarter of 2022, compared with the same quarter in 2021. The increase was primarily due to the recognition of $15.2 million in revenue related to our Upstream wind park in the first quarter of 2022 that was associated with market settlements received from SPP in February 2021. These settlements were subject to a FERC complaint, so we were not able to recognize them as revenue until FERC issued an order denying that complaint in the first quarter of 2022.

Interest Expense

Interest expense at the non-utility energy infrastructure segment decreased $0.8 million during first quarter of 2022, compared with the same quarter in 2021, primarily due to a lower principal balance as a result of the semi-annual principal payments on long-term debt.

Income Tax Expense (Benefit)

Income tax benefit at the non-utility energy infrastructure segment increased $5.0 million as $4.9 million of income tax benefit was recorded during the first quarter of 2022, compared with $0.1 of income tax expense recorded during the same quarter in 2021. The increase was primarily due to a $9.2 million increase in PTCs generated in 2022, driven by the Jayhawk wind park that achieved commercial operation in December 2021 and higher generation at our other wind parks. This increase in the income tax benefit was partially offset by higher pretax earnings during the first quarter of 2022, compared with same quarter in 2021.


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


	Three Months Ended March 31
(in millions)	2022		2021		B (W)
Operating loss	$	(0.5)	$	(4.9)	$	4.4

Other income, net	11.9		13.8		(1.9)
Interest expense	22.6		24.2		1.6

Loss before income taxes	(11.2)		(15.3)		4.1

Income tax benefit	(24.8)		(32.9)		(8.1)
Net income attributed to common shareholders	$	13.6	$	17.6	$	(4.0)

Operating Loss

The operating loss at the corporate and other segment decreased $4.4 million during the first quarter of 2022, compared with the same quarter in 2021. The lower net loss was driven by a $3.0 million increase in operating income at Wispark, primarily due to a positive quarter-over-quarter impact from land sales.

Other Income, Net

Other income, net at the corporate and other segment decreased $1.9 million during the first quarter of 2022, compared with the same quarter in 2021, driven by a $4.6 million net loss from the investments held in the Integrys rabbi trust during the first quarter of 2022, compared with a $4.6 million net gain during the same quarter in 2021. The gains and losses from the investments held in the rabbi trust partially offset the changes in benefits costs related to deferred compensation, which are included in other operation and maintenance expense in our operating segments. See Note 11, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust. The negative impact from the investments held in the rabbi trust was partially offset by a $5.6 million increase in earnings from our equity method investments in technology and energy-focused investment funds.

Interest Expense

Interest expense at the corporate and other segment decreased $1.6 million during the first quarter of 2022, compared with the same quarter in 2021, as we refinanced long-term debt obligations during the fourth quarter of 2021 in order to take advantage of lower interest rates.

Income Tax Benefit

The income tax benefit at the corporate and other segment decreased $8.1 million during the first quarter of 2022, compared with the same quarter in 2021, driven by an $8.3 million decrease in uncertain tax positions in the first quarter of 2021 and a lower pretax loss compared to the same first quarter of 2021. These decreases in income tax benefits were partially offset by a $2.4 million increase in excess tax benefits recognized related to stock option exercises during the first quarter of 2022, compared to the same quarter in 2021.

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 three months ended March 31:


(in millions)	2022		2021		Change in 2022 Over 2021
Cash provided by (used in):
Operating activities	$	1,076.8	$	395.2	$	681.6
Investing activities	(338.2)		(541.3)		203.1
Financing activities	(706.5)		163.1		(869.6)

Operating Activities

Net cash provided by operating activities increased $681.6 million during the first quarter of 2022, compared with the same quarter in 2021, driven by:

•A $643.2 million increase in cash related to higher overall collections from customers as a result of an increase in sales volumes during the first quarter of 2022, compared with the same quarter in 2021, driven by colder winter weather and the continued economic recovery from the COVID-19 pandemic. We also over-collected natural gas costs in the first quarter of 2022, as natural gas costs were lower than what was anticipated in rates. In addition, we continued to recover on the natural gas costs we under-collected from our Illinois and Minnesota customers related to the extreme weather conditions that occurred in February 2021, in accordance with orders from the ICC and MPUC, respectively. See Note 21, Regulatory Environment, for more information on the recovery of these natural gas costs.

•A $180.9 million increase in cash due to realized gains on derivative instruments as well as higher collateral received from counterparties during the first quarter of 2022, driven by an increase in the fair value of our natural gas derivative assets during the first quarter of 2022, compared with the same quarter in 2021.

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

•An $81.8 million decrease in cash from higher payments for fuel and purchased power at our plants during the first quarter of 2022, compared with the same quarter in 2021. We incurred higher natural gas costs during the first quarter of 2022, compared with the same quarter in 2021, as a result of an increase in the price of natural gas at our Wisconsin utilities.

•A $50.4 million decrease in cash from higher payments for operating expenses. During the first quarter of 2022, our payments were higher for storm restoration and the Illinois invested capital tax.

Investing Activities

Net cash used in investing activities decreased $203.1 million during the first quarter of 2022, compared with the same quarter in 2021, driven by:

•The acquisition of a 90% ownership interest in Jayhawk in February 2021 for $119.4 million. See Note 2, Acquisitions, for more information.

•An $87.1 million decrease in cash paid for capital expenditures during the first quarter of 2022, compared with the same quarter in 2021, which is discussed in more detail below.

•Insurance proceeds of $41.0 million received during the first quarter of 2022 for property damage, primarily driven by proceeds received for the PSB claim. See Note 6, Property, Plant, and Equipment, for more information.

These decreases in net cash used in investing activities were partially offset by capital contributions paid to transmission affiliates of $21.1 million during the first quarter of 2022. See Note 16, Investment in Transmission Affiliates, for more information. There were no payments to transmission affiliates during the first quarter of 2021.


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Capital Expenditures

Capital expenditures by segment for the three months ended March 31 were as follows:


Reportable Segment (in millions)	2022		2021		Change in 2022 Over 2021
Wisconsin	$	254.8	$	277.5	$	(22.7)
Illinois	98.6		119.8		(21.2)
Other states	11.5		11.0		0.5
Non-utility energy infrastructure	15.9		59.0		(43.1)
Corporate and other	2.7		3.3		(0.6)
Total capital expenditures	$	383.5	$	470.6	$	(87.1)

The decrease in cash paid for capital expenditures at the Wisconsin segment during the first quarter of 2022, compared with the same quarter in 2021, was primarily driven by lower capital expenditures related to upgrades to WE's natural gas and electric distribution systems. These decreases were partially offset by higher payments for capital expenditures related to WG's LNG facility, Weston power plant's RICE units, and renewable energy projects during the first quarter of 2022.

The decrease in cash paid for capital expenditures at the Illinois segment during the first quarter of 2022, compared with the same quarter in 2021, was primarily driven by lower capital expenditures related to upgrades at the Manlove Gas Storage Field, partially offset by increased capital expenditures for upgrades to PGL's and NSG's natural gas distribution systems.

The decrease in cash paid for capital expenditures at the non-utility energy infrastructure segment during the first quarter of 2022, compared with the same quarter in 2021, was primarily driven by lower capital expenditures related to the construction of Jayhawk. See Note 2, Acquisitions, for more information about Jayhawk.

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

Financing Activities

Net cash related to financing activities decreased $869.6 million during the first quarter of 2022, compared with the same quarter in 2021, driven by:

•A $600.0 million decrease in cash due to the issuance of long-term debt during the first quarter of 2021. We did not issue any long-term debt during the first quarter of 2022.

•A $591.4 million decrease in cash due to $447.9 million of net repayments of commercial paper during the first quarter of 2022, compared with $143.5 million of net borrowings of commercial paper during the same quarter in 2021.

•A $16.8 million decrease in cash due to an increase in the number and cost of shares of our common stock purchased during the first quarter of 2022, compared with the same quarter in 2021, to satisfy requirements of our stock-based compensation plans.

•A $15.9 million decrease in cash due to higher dividends paid on our common stock during the first quarter of 2022, compared with the same quarter in 2021. In January 2022, our Board of Directors increased our quarterly dividend by $0.05 per share (7.4%) effective with the March 2022 dividend payment.

These decreases in cash were partially offset by:

•A $340.0 million increase in cash due to a repayment of a 364-day term loan during the first quarter of 2021. We did not repay any loans during the first quarter of 2022.

•A $10.6 million increase in cash related to the number of stock options exercised during the first quarter of 2022, compared with the same quarter in 2021.

Significant Financing Activities

For more information on our financing activities, see Note 8, Short-Term Debt and Lines of Credit.


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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 2021 Annual Report on Form 10-K for additional information regarding our significant cash requirements.

Significant Capital Projects

We have several capital projects 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 requirements, regulatory restraints and requirements, changes in tax laws and regulations, acquisition and development opportunities, market volatility, economic trends, supply chain disruptions, the COVID-19 pandemic, 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 19, Commitments and Contingencies.


(in millions)	2022 (1)		2023		2024
Wisconsin	$	2,131.7	$	2,148.0	$	2,114.1
Illinois	573.1		586.8		635.0
Other states	119.1		103.6		106.4
Non-utility energy infrastructure	870.8		325.7		297.5
Corporate and other	22.0		17.5		4.3
Total	$	3,716.7	$	3,181.6	$	3,157.3

(1)This includes actual capital expenditures already incurred in 2022, as well as estimated capital expenditures for the remainder of the year.

Our utilities continue to upgrade their electric and natural gas distribution systems to enhance reliability. These upgrades include the AMI program. AMI is an integrated system of smart meters, communication networks, and data management systems that enable two-way communication between utilities and customers.

We are committed to investing in solar, wind, battery storage, and clean natural gas-fired generation. Below are examples of projects that are proposed or currently underway.

•We have received approval to invest in 100 MW of utility-scale solar within our Wisconsin segment. WE has partnered with an unaffiliated utility to construct a solar project, Badger Hollow II, that will be located in Iowa County, Wisconsin. Once constructed, WE will own 100 MW of this project. WE's share of the cost of this project is estimated to be approximately $130 million. Commercial operation of Badger Hollow II is targeted for the first half of 2023.

•WE and WPS, along with an unaffiliated utility, received PSCW approval to acquire and construct the Paris Solar-Battery Park, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Kenosha County, Wisconsin and once constructed, WE and WPS will collectively own 180 MW of solar generation and 99 MW of battery storage of this project. WE's and WPS's combined share of the cost of this project is estimated to be approximately $390 million, with construction expected to be completed by the end of 2023.

•WE and WPS have received approval to accelerate capital investments in two wind parks. The investment is expected to be approximately $154 million to repower major components of Blue Sky Green Field Wind Park and Crane Creek Wind Park, which are expected to be completed by the end of 2022.

•In March 2021, WE and WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire and construct the Darien Solar-Battery Park, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Rock and Walworth counties, Wisconsin and once constructed, WE and WPS will collectively own 225 MW of solar generation and 68 MW of battery storage of this project. If approved, WE's and WPS's combined share of


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the cost of this project is estimated to be approximately $400 million, with construction expected to be completed by the end of 2023.

•WPS, along with an unaffiliated utility, received PSCW approval to acquire the Red Barn Wind Park, a utility-scale wind-powered electric generating facility. The project will be located in Grant County, Wisconsin and once constructed, WPS will own 82 MW of this project. WPS's share of the cost of this project is estimated to be approximately $160 million, with construction expected to be completed by the end of 2022.

•In April 2021, WE and WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire the Koshkonong Solar-Battery Park, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Dane County, Wisconsin and once constructed, WE and WPS will collectively own 270 MW of solar generation and 149 MW of battery storage of this project. If approved, WE's and WPS's combined share of the cost of this project is estimated to be approximately $585 million, with construction expected to be completed by the second quarter of 2024.

•WE and WPS received PSCW approval to construct 128 MWs of natural gas-fired generation at WPS's existing Weston power plant site in northern Wisconsin. The new facility will consist of seven RICE units. We estimate the cost of this project to be approximately $170 million, with construction expected to be completed in 2023.

•In November 2021, WE and WPS signed an asset purchase agreement to acquire Whitewater, a commercially operational 236.5 MW dual fueled (natural gas and low sulfur fuel oil) combined cycle electrical generation facility in Whitewater, Wisconsin. In December 2021, WE and WPS filed an application with the PSCW for approval to acquire Whitewater. If approved, the cost of this facility will be $72.7 million, with the transaction expected to close in January 2023.

•In January 2022, WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire a portion of West Riverside's nameplate capacity. WPS is also requesting approval to assign the option to purchase part of West Riverside to WE. If approved, WPS or WE would acquire 100 MW of capacity, in the first of two potential option exercises. West Riverside is a new, combined-cycle natural gas plant recently completed by an unaffiliated utility in Rock County, Wisconsin. If approved, our share of the cost of this ownership interest is approximately $91 million, with the transaction expected to close in the second quarter of 2023.

In March 2022, the DOC opened an investigation into whether new tariffs should be imposed on solar panels and cells imported from multiple southeast Asian countries, which could impact the timing and cost of our planned solar projects. See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – United States Department of Commerce Complaint and Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Withhold Release Order Related to Silica-Based Products for information on the DOC investigation and potential impacts to our solar projects as a result of CBP actions related to solar panels, respectively.

WE and WG have received PSCW approval to each construct its own LNG facility. Each facility would provide approximately one billion cubic feet of natural gas supply to meet anticipated peak demand without requiring the construction of additional interstate pipeline capacity. These facilities are expected to reduce the likelihood of constraints on WE's and WG's natural gas systems during the highest demand days of winter. The total cost of both projects is estimated to be approximately $370 million, with approximately half being invested by each utility. Commercial operation of the WE and WG LNG facilities is targeted for the end of 2023 and 2024, respectively.

PGL is continuing work on the SMP, a project under which PGL is replacing approximately 2,000 miles of Chicago's aging natural gas pipeline infrastructure. PGL currently recovers these costs through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023. PGL's projected average annual investment through 2024 is between $280 million and $300 million.

The non-utility energy infrastructure line item in the table above includes WECI's planned investments in Thunderhead and Sapphire Sky. See Note 2, Acquisitions, for more information on these wind projects.

We expect to provide total capital contributions to ATC (not included in the above table) of approximately $115 million from 2022 through 2024. We do not expect to make any contributions to ATC Holdco during that period.


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Long-Term Debt

There were no material changes in our outstanding long-term debt during the three months ended March 31, 2022.

Common Stock Dividends

Our current quarterly dividend rate is $0.7275 per share, which equates to an annual dividend of $2.91 per share. For information related to our most recent common stock dividend declared, see Note 7, Common Equity.

Other Significant Cash Requirements

See Note 19, Commitments and Contingencies, for information regarding our minimum future commitments related to purchase obligations for the procurement of fuel, power, and 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 three months ended March 31, 2022.

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 8, Short-Term Debt and Lines of Credit, Note 13, Guarantees, and Note 18, 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, which allows us to obtain external short-term borrowings, including commercial paper and term loans, and intermediate or long-term debt securities. 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.

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 in 2022, 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 2021 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 March 31, 2022, our current liabilities exceeded our current assets by $701.8 million. We do not expect this to have an impact on our liquidity as we currently believe that our cash and cash equivalents, our available capacity of $1,649.4 million under existing


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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, Short-Term Debt and Lines of Credit, for more information about our credit facilities and commercial paper.

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 had 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 2021 Annual Report on Form 10-K.

Capitalization Structure

The following table shows our capitalization structure as of March 31, 2022, as well as an adjusted capitalization structure that we believe is consistent with how a majority of the rating agencies currently view our 2007 Junior Notes:


(in millions)	Actual			Adjusted
Common shareholders' equity	$	11,243.2		$	11,493.2
Preferred stock of subsidiary	30.4			30.4
Long-term debt (including current portion)	13,677.7			13,427.7
Short-term debt	1,450.0			1,450.0
Total capitalization	$	26,401.3		$	26,401.3

Total debt	$	15,127.7		$	14,877.7

Ratio of debt to total capitalization	57.3		%	56.4		%

Included in long-term debt on our balance sheet as of March 31, 2022, is $500.0 million principal amount of the 2007 Junior Notes. The adjusted presentation attributes $250.0 million of the 2007 Junior Notes to common shareholders' equity and $250.0 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 2007 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

At March 31, 2022, we were in compliance with all 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.

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 March 31, 2022. 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 March 31, 2022, it could have been required to post $100 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.


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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.

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 2021 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 matters, critical accounting policies and estimates, and other matters.

COVID-19 Pandemic

We have taken steps to mitigate the impact of the global COVID-19 pandemic. However, the extent to which the COVID-19 pandemic could continue to impact our results of operations and liquidity is largely dependent upon the ability of our customers to resume or maintain normal operations. Adverse impacts to us and our subsidiaries from a prolonged COVID-19 pandemic environment could include a decrease in revenues, increased bad debt expense, increases in past due accounts receivable balances, and access to the capital markets at unfavorable terms or rates.

We will continue to monitor COVID-19 pandemic-related developments affecting our workforce, customers, and suppliers and will implement additional actions that we determine to be necessary in order to mitigate any additional impacts. We cannot predict the full extent of the impacts of COVID-19, which will depend on, among other things, its duration through new variants, the rate and the effectiveness of both vaccinations and treatments, future regulatory and governmental actions, and the ability to maintain normal business activity.

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 Accounting Standard Codification. 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. As of March 31, 2022, our regulatory assets were $3,255.6 million, and our regulatory liabilities were $4,129.4 million.

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 is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2022, PGL filed its 2021 reconciliation with the ICC, which, along with the 2020, 2019, 2018, 2017, and 2016 reconciliations, are still pending. As of March 31, 2022, there can be no assurance that all costs incurred under the QIP rider during the open reconciliation years will be deemed recoverable by the ICC.

See Note 21, Regulatory Environment, above, and Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for more information regarding recent and pending rate proceedings, orders, and investigations involving our utilities.


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Climate and Equitable Jobs Act

On September 15, 2021, the state of Illinois signed into law the Climate and Equitable Jobs Act. This new legislation includes, among other things, a path for Illinois to move towards 100% clean energy, expanded commitments to energy efficiency and renewable energy, additional consumer protections, and expanded ethics reform. The provisions in this legislation with the potential to have the most significant financial impact on PGL and NSG relate to the new consumer protection requirements.

Effective September 15, 2021, the new legislation prohibits utilities from charging customers a fee when they elect to pay for service with a credit card. Utilities are now required to incur these expenses and seek recovery through a rate proceeding or by establishing a recovery mechanism. In December 2021, the ICC approved the use of a TPTFA rider for PGL. The TPTFA rider allows PGL to recover the costs incurred for these third-party transaction fees, effective December 27, 2021. NSG recovers costs related to these third-party transaction fees through its base rates, effective September 15, 2021.

In accordance with the new legislation, effective January 1, 2023, natural gas utilities will also no longer be allowed to charge late payment fees to low-income residential customers. We are currently evaluating the impact this legislation may have on our future results of operations.

Withhold Release Order Related to Silica-Based Products

The CBP issued a WRO in June 2021, applicable to certain silica-based products originating from the Xinjiang Uyghur Autonomous Region of China, such as polysilicon, included in the manufacturing of solar panels. The WRO was issued over allegations of widespread, state-backed forced labor in the region. A significant percentage of the world’s polysilicon supply comes from China, and as a result of the WRO, many solar panels imported into the United States are being held by the CBP on suspicion that they originated from, or contain components that originated from, this region in China. Solar panels will only be released after the importer provides satisfactory evidence to the contrary, which can be an arduous process. We have been notified that solar panel suppliers have experienced delays associated with this WRO. We are evaluating options to mitigate these delays and maintain original project schedules, although we could experience project delays as a result of this WRO. The project delays could impact Badger Hollow II, which is currently under construction. Also, we cannot currently predict what, if any, impact this supply disruption will have on future solar projects included in our capital plan.

United States Department of Commerce Complaints

In August 2021, a group of anonymous domestic solar manufacturers filed a petition (AD/CVD) with the DOC seeking to impose new tariffs on solar panels and cells imported from several countries, including Malaysia, Vietnam, and Thailand. The petitioners claimed that Chinese solar manufacturers are shifting products to these countries to avoid the tariffs required on products imported from China. In September 2021, the DOC asked that the anonymous group amend its petition to provide more detail and asked the group to identify its members. In its response to the DOC, the anonymous group refused and argued that identifying its members could expose them to retribution from the Chinese solar industry, which dominates the global solar supply chain for critical solar panel components. In November 2021, the DOC rejected the petition filed by the anonymous group and cited the group's anonymity as a driving factor in the denial.

In February 2022, a California based company filed a petition (AD/CVD) with the DOC seeking to impose new tariffs on solar panels and cells imported from multiple countries, including Malaysia, Vietnam, Thailand, and Cambodia. While the petition is similar to the one rejected by DOC in November 2021, there are notable differences. The group added Cambodia to the petition and is requesting that the DOC conduct a country-wide inquiry into each of the four countries. In March 2022, the DOC decided to act on the February petition and investigate the claim. This decision alone is having an adverse impact on the United States solar industry. A DOC decision is expected by January 2023. If the DOC determines that the petition has merit, it would be able to apply any final tariffs retroactively to November 4, 2021. If imposed, the new tariffs are expected to further disrupt the supply of solar modules to the United States, and could impact the cost and timing of our solar projects.

Infrastructure Investment and Jobs Act

In November 2021, President Biden signed into law the Infrastructure Investment and Jobs Act, which provides for approximately $1.2 trillion of federal spending over the next five years, including approximately $85 billion for investments in power, utilities, and renewables infrastructure across the United States. We expect funding from this Act will support the work we are doing to reduce GHG emissions, increase EV charging, and strengthen and protect the energy grid. Funding in the Act should also help to expand


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emerging technologies, like hydrogen and carbon management, as we continue the transition to a clean energy future. We believe the Infrastructure Investment and Jobs Act will accelerate investment in projects that will help us meet our net zero emission goals to the benefit of our customers, the communities we serve, and our company.

Return on Equity Incentive for Membership in a Transmission Organization

The FERC currently allows transmission utilities, including ATC, to increase their ROE by 50 basis points as an incentive for membership in a transmission organization, such as MISO. This incentive was established to stimulate infrastructure development and to support the evolving electric grid. However, a Notice of Proposed Rulemaking was issued by the FERC on April 15, 2021 proposing to limit the 50 basis point increase in ROE to only be available to transmission utilities initially joining a transmission organization for the first three years of membership. If this proposal becomes a final rule, ATC would be required to submit, within 30 days of the final rule's effective date, a compliance filing eliminating the 50 basis point incentive from its tariff. As a result, this proposal, if adopted, would reduce our future after-tax equity earnings from ATC by approximately $7 million annually. The transmission costs WE and WPS are required to pay ATC after the effective date would also be reduced by this proposal.

American Transmission Company Allowed Return on Equity Complaints

On November 21, 2019, the FERC issued an order (November 2019 Order) related to the methodology used to calculate the base ROE for all MISO transmission owners, including ATC. Based on this order, the FERC expanded its base ROE methodology to include the capital-asset pricing model in addition to the discounted cash flow model to better reflect how investors make their investment decisions. The FERC's modified methodology reduced the base ROE that ATC is allowed to collect on a going-forward basis, as discussed below. In response to the FERC's decision, requests for the FERC to rehear the November 2019 Order in its entirety were filed by various parties.

On May 21, 2020, the FERC issued an order (May 2020 Order) that granted in part and denied in part the requests to rehear the November 2019 Order. In the May 2020 Order, the FERC made additional revisions to its base ROE methodology, including adding the use of the risk premium model. As discussed below, the additional revisions made by the FERC increased ATC's base ROE authorized in the November 2019 Order on a going-forward basis. Various parties filed requests to rehear certain parts of the May 2020 Order with the FERC, but the FERC issued an order in response to the rehearing requests during November 2020 (November 2020 Order) that confirmed the ROE authorized in the May 2020 Order. Petitions for review of the November 2019 Order, relevant parts of the May 2020 Order, and the November 2020 Order have also been filed with the D.C. Circuit Court of Appeals.

First Return on Equity Complaint

In November 2013, a group of MISO industrial customer organizations filed a complaint with the FERC requesting to reduce the base ROE used by MISO transmission owners, including ATC, from 12.2% to 9.15%. In September 2016, the FERC issued an order requiring MISO transmission owners to collect a reduced base ROE of 10.32%. This order also allowed the continued collection of any previously authorized ROE incentive adders. For MISO transmission owners, a 0.5% incentive adder was approved by the FERC in January 2015. The FERC then issued the November 2019 Order after directing MISO transmission owners and other stakeholders to provide briefs and comments on a proposed change to the methodology for calculating base ROE. The November 2019 Order further reduced the base ROE for all MISO transmission owners, including ATC, to 9.88%, effective as of September 28, 2016 and prospectively. The November 2019 Order also continued to allow the collection of previously authorized ROE incentive adders, but ATC's ROE incentive adder of 0.5% only applies to revenues collected after January 6, 2015. In response to the rehearing requests filed related to the November 2019 Order, the FERC issued another order in May 2020. This May 2020 Order increased the base ROE for all MISO transmission owners, including ATC, from the 9.88% authorized in the November 2019 Order to 10.02%, effective as of September 28, 2016 and prospectively. The May 2020 Order also allowed the continued collection of previously authorized ROE incentive adders. However, ATC's 0.5% ROE incentive adder may be eliminated going forward, as discussed above.

ATC was required to provide refunds, with interest, for the 15-month refund period from November 12, 2013 through February 11, 2015 and for the period from September 28, 2016 through November 19, 2020. In January 2022, ATC completed providing WE and WPS with net refunds related to the transmission costs they paid during the two refund periods. These refunds were applied to WE's and WPS's PSCW-approved escrow accounting for transmission expense.


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Second Return on Equity Complaint

In February 2015, a second complaint was filed with the FERC requesting a reduction in the base ROE used by MISO transmission owners, including ATC, to 8.67%, with a refund effective date retroactive to February 12, 2015. The FERC also addressed this second complaint in the November 2019 Order. Similar to the first complaint, the November 2019 Order stated that the base ROE of 9.88% and the collection of previously authorized ROE incentive adders, such as ATC's 0.5% adder, were reasonable for the period covered by the second complaint, February 12, 2015 through May 10, 2016. However, in the November 2019 Order, the FERC relied on certain provisions of the Federal Power Act to dismiss the second complaint and to determine that refunds were not allowed for this period. In its May 2020 Order, the FERC stated the new base ROE of 10.02% and the collection of previously authorized ROE incentive adders were reasonable for the period covered by the second complaint. However, the FERC relied on the same provisions of the Federal Power Act to again dismiss the complaint and determine that refunds were not allowed for this period. The FERC also denied the requests to rehear both the dismissal of the second complaint and the determination that no refunds are allowed for the second complaint period.

Due to the various outstanding petitions related to the November 2019 Order, May 2020 Order, and November 2020 Order, refunds could still be required for the second complaint period. Therefore, our financials continue to reflect a liability of $39.1 million, reducing our equity earnings from ATC. This liability is based on a 10.52% ROE for the second complaint period. If it is ultimately determined that a refund is required for the second complaint period, we would not expect any such refund to have a material impact on our financial statements or results of operations in the future. In addition, WE and WPS would be entitled to receive a portion of the refund from ATC for the benefit of their customers.

Environmental Matters

See Note 19, 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 inflation and supply chain disruptions described below. In addition, there is continuing uncertainty over the impact that the ongoing conflict between Russia and Ukraine will have 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 2021 Annual Report on Form 10-K for a discussion of market and other significant risks applicable to us.

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, in order to ensure we are able to procure the necessary 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 two risk factors below that are disclosed in Part I of our 2021 Annual Report on Form 10-K.

•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 and inflation.

•Item 1A. Risk Factors – Risks Related to Economic and Market Volatility – Fluctuating commodity prices could negatively impact our electric and natural gas utility operations.

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


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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 2021 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 – COVID-19 Pandemic and Market Risks and Other Significant Risks in Item 2 of Part I of this report, as well as Note 11, Fair Value Measurements, Note 12, Derivative Instruments, and Note 13, 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 first quarter of 2022 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


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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 2021 Annual Report on Form 10-K. See Note 19, Commitments and Contingencies, and Note 21, 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 19, Commitments and Contingencies, Note 21, Regulatory Environment, and below, we are currently, and from time to time, 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.

Environmental Matters

Manlove Field Matter

In September 2017, the Illinois Department of Natural Resources, Office of Oil and Gas Resource Management, issued a VN to PGL related to a leak of natural gas from a well located at the PGL Manlove Gas Storage Field in December 2016. PGL quickly shut down and permanently plugged the well to contain the leak after it was discovered. The leak resulted in the migration of natural gas from the well to the Mahomet Aquifer located in central Illinois and impacted residential freshwater wells. PGL has been working with residents potentially impacted by the natural gas leak and the Illinois state agencies, to investigate and remediate the impacts of the natural gas leak to the Mahomet Aquifer. In October 2017, the Illinois AG filed a complaint against PGL alleging certain violations of the Illinois Environmental Protection Act and the Oil and Gas Act. PGL entered into an Agreed Interim Order with the State of Illinois in October 2017 and a First Amended Agreed Interim Order in September 2019 whereby PGL agreed, among other things, to continue actions it was already undertaking proactively, including the submittal of a GMZ application to the IEPA. A supplemental filing was sent to the IEPA in December 2019. In September 2020, the IEPA sent PGL a letter conditionally approving the GMZ application. PGL has taken steps to implement the requirements of the approved GMZ project.

In addition, in December 2017, the IEPA issued a VN to PGL alleging the same violations as the AG. Lastly, in January 2018, the IEPA issued a VN alleging certain violations of Illinois air emission rules arising from the construction and operation of flaring equipment at the leak site. Both of the IEPA VN matters have been referred to the AG for enforcement.

In the complaint, as is customary in these types of actions, the AG cited to the statutory penalties allowed by law. Ultimately, the pursuit of any civil penalties is at the AG’s discretion. In the event the AG pursues penalties in connection with a final order, we believe that PGL's high level of cooperation and quick action to remedy the situation and to work with the potentially impacted homeowners would be taken into account. At this time, we believe that civil penalties, if any, 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 2021 Annual Report on Form 10-K.


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ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table sets forth information regarding the purchases of our equity securities made by or on behalf of us or any affiliated purchaser (as defined in Exchange Act Rule 10b-18) during the three months ended March 31, 2022:


Issuer Purchases of Equity Securities
2022	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
January 1 – January 31	17,926	$	96.19	—	$	—
February 1 – February 28	—	—		—	—
March 1 – March 31	—	—		—	—
Total (1)	17,926	$	96.19	—

(1)All shares were surrendered by employees to satisfy tax withholding obligations upon vesting of restricted stock.


ITEM 6. EXHIBITS



Number	Exhibit
















10	Material Contracts

	10.1	Retention Agreement by and between WEC Energy Group and Scott J. Lauber, dated February 21, 2022 (Exhibit 10.16 to WEC Energy Group's 12/31/2021 Form 10-K).

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)


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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/ WILLIAM J. GUC
Date:	May 5, 2022	William J. Guc
		Vice President and Controller

		(Duly Authorized Officer and Chief Accounting Officer)


03/31/2022 Form 10-Q			64			WEC Energy Group, Inc.