UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2021

OR

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

For the transition period from ________________ to ___________________

Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	IRS Employer Identification No.
001-03016	WISCONSIN PUBLIC SERVICE CORPORATION	39-0715160

(A Wisconsin Corporation)

2830 South Ashland Avenue

P.O. Box 19001

Green Bay, WI 54307-9001

(800) 450-7260

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

None

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

None

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes ☐    No ☒

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes ☐    No ☒

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 has filed a report on and attestation to its management’s assessment of

the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.

7262(b)) by the registered public accounting firm that prepared or issued its audit report.    ☐

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

Yes ☐    No ☒

As of June 30, 2021 (and currently), all of the common stock of Wisconsin Public Service Corporation is held by Integrys Holding, Inc., a wholly owned subsidiary of WEC Energy Group, Inc.

State the aggregate market value of the voting and non-voting common equity held by non-affiliates of the Registrant.

None.

Number of shares outstanding of each class of common stock, as of

January 31, 2022

Common Stock, $4 par value, 23,896,962 shares outstanding

The Registrant meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing with the reduced disclosure format set forth in General Instruction I(2).

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WISCONSIN PUBLIC SERVICE CORPORATION

ANNUAL REPORT ON FORM 10-K

For the Year Ended December 31, 2021

TABLE OF CONTENTS

					Page
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION					1
PART I					3
ITEM 1.	BUSINESS				3
	A.	INTRODUCTION			3
	B.	UTILITY SEGMENT			3
	C.	OTHER SEGMENT			10
	D.	REGULATION			11
	E.	ENVIRONMENTAL COMPLIANCE			13
	F.	HUMAN CAPITAL			13
ITEM 1A.	RISK FACTORS				15
ITEM 1B.	UNRESOLVED STAFF COMMENTS				25
ITEM 2.	PROPERTIES				26
ITEM 3.	LEGAL PROCEEDINGS				27
ITEM 4.	MINE SAFETY DISCLOSURES				27
PART II					27
ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES				27
ITEM 6.	RESERVED				27
ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS				28
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK				47
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA				48
	A.	Report of Independent Registered Public Accounting Firm			48
	B.	Income Statements			50
	C.	Balance Sheets			51
	D.	Statements of Cash Flows			52
	E.	Statements of Equity			53
	F.	Notes to Financial Statements			54
		Note 1	Summary of Significant Accounting Policies	54
		Note 2	Acquisition	62
		Note 3	Related Parties	62
		Note 4	Operating Revenues	64
		Note 5	Credit Losses	65
		Note 6	Regulatory Assets and Liabilities	66
		Note 7	Property, Plant, and Equipment	68
		Note 8	Jointly Owned Utility Facilities	68
		Note 9	Asset Retirement Obligations	69
		Note 10	Goodwill	70
		Note 11	Common Equity	70
		Note 12	Preferred Stock	72
		Note 13	Short-Term Debt and Lines of Credit	72
		Note 14	Long-Term Debt	73
		Note 15	Leases	73
		Note 16	Income Taxes	75
		Note 17	Fair Value Measurements	77
		Note 18	Derivative Instruments	78
		Note 19	Employee Benefits	79
		Note 20	Segment Information	83
		Note 21	Commitments and Contingencies	84

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		Note 22	Supplemental Cash Flow Information	88
		Note 23	Regulatory Environment	89
		Note 24	Other Income, Net	90
		Note 25	New Accounting Pronouncements	91
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE				92
ITEM 9A.	CONTROLS AND PROCEDURES				92
ITEM 9B.	OTHER INFORMATION				92
ITEM 9C.	DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS				92
PART III					93
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANT				93
ITEM 11.	EXECUTIVE COMPENSATION				93
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS				93
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE				93
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES				93
PART IV					95
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES				95
ITEM 16.	FORM 10-K SUMMARY				97
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS					98
SIGNATURES					99

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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
Bluewater	Bluewater Natural Gas Holding, LLC
Integrys	Integrys Holding, Inc.
UMERC	Upper Michigan Energy Resources Corporation
WBS	WEC Business Services LLC
WE	Wisconsin Electric Power Company
WEC Energy Group	WEC Energy Group, Inc.
WRPC	Wisconsin River Power Company
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
IRS	United States Internal Revenue Service
PSCW	Public Service Commission of Wisconsin
SEC	Securities and Exchange Commission
WDNR	Wisconsin Department of Natural Resources
Accounting Terms
AFUDC	Allowance for Funds Used During Construction
ARO	Asset Retirement Obligation
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
CWIP	Construction Work in Progress
FASB	Financial Accounting Standards Board
GAAP	Generally Accepted Accounting Principles
OPEB	Other Postretirement Employee Benefits
Environmental Terms
ACE	Affordable Clean Energy
Act 141	2005 Wisconsin Act 141
BATW	Bottom Ash Transport Water
BTA	Best Technology Available
CAA	Clean Air Act
CO2	Carbon Dioxide
ELG	Steam Electric Effluent Limitation Guidelines
GHG	Greenhouse Gas
NAAQS	National Ambient Air Quality Standards
NOV	Notice of Violation
NOx	Nitrogen Oxide
SO2	Sulfur Dioxide
WOTUS	Waters of the United States
Measurements
Dth	Dekatherm
MW	Megawatt
MWh	Megawatt-hour
Other Terms and Abbreviations
AIA	Affiliated Interest Agreement
AMI	Advanced Metering Infrastructure

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ARR	Auction Revenue Right
Badger Hollow I	Badger Hollow Solar Park I
CDC	Centers for Disease Control and Prevention
CFR	Code of Federal Regulations
Compensation Committee	Compensation Committee of the Board of Directors of WEC Energy Group, Inc.
COVID-19	Coronavirus Disease – 2019
Crane Creek	Crane Creek Wind Park
D.C. Circuit Court of Appeals	United States Court of Appeals for the District of Columbia Circuit
ESG Progress Plan	WEC Energy Group's Capital Investment Plan for Efficiency, Sustainability, and Growth for 2021-2025
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
Forward Wind	Forward Wind Energy Center
FTR	Financial Transmission Right
GCRM	Gas Cost Recovery Mechanism
ITC	Investment Tax Credit
LIBOR	London Interbank Offered Rate
LMP	Locational Marginal Price
MISO	Midcontinent Independent System Operator, Inc.
MISO Energy Markets	MISO Energy and Operating Reserves Market
NYMEX	New York Mercantile Exchange
Omnibus Stock Incentive Plan	WEC Energy Group Omnibus Stock Incentive Plan, Amended and Restated, Effective as of May 6, 2021
PPA	Power Purchase Agreement
PTC	Production Tax Credit
RNG	Renewable Natural Gas
ROE	Return on Equity
RTO	Regional Transmission Organization
Supreme Court	United States Supreme Court
Tax Legislation	Tax Cuts and Jobs Act of 2017
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, effective tax rates, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, climate-related matters, the 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 Item 1A. Risk Factors and those identified below:

•Factors affecting utility operations such as catastrophic weather-related damage, including climate change, 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 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 health pandemics, including the COVID-19 pandemic, on our business functions, financial condition, liquidity, and results of operations;

•The impact of recent and future federal, state, and local legislative and/or regulatory changes, including changes in rate-setting policies or procedures, 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 and state 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, future inflation, and other factors;

•Factors affecting the implementation of WEC Energy Group's 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 the ability to execute WEC Energy Group's 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;

•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 or us;

•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;

•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 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;

•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, which cannot be assured to be completed timely or within budgets;

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

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

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

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

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PART I

ITEM 1. BUSINESS

A. INTRODUCTION

In this report, when we refer to "us," "we," "our," or "ours," we are referring to Wisconsin Public Service Corporation. The term "utility" refers to our regulated activities, while the term "non-utility" refers to our activities that are not regulated. References to "Notes" are to the Notes to Financial Statements included in this Annual Report on Form 10-K.

We are an indirect, wholly owned subsidiary of WEC Energy Group and were incorporated in the state of Wisconsin in 1883. We serve customers in northeastern and central Wisconsin. We conduct our business primarily through our utility reportable segment.

For more information about our utility operations, including financial and geographic information, see Note 20, Segment Information, and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations. For information about our business strategy, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Corporate Developments.

Available Information

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports are made available on WEC Energy Group's website, www.wecenergygroup.com, free of charge, as soon as reasonably practicable after they are filed with or furnished to the SEC. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov.

B. UTILITY SEGMENT

Electric Utility Operations

We generate and distribute electric energy to customers located in northeastern and central Wisconsin.

Operating Revenues

For information about our operating revenues disaggregated by customer class for the years ended December 31, 2021, 2020, and 2019, see Note 4, Operating Revenues.

Electric Sales

Our electric energy deliveries included supply and distribution sales to retail, wholesale, and resale customers. In 2021, retail revenues accounted for 90.5% of total electric operating revenues, wholesale revenues accounted for 7.4% of total electric operating revenues, and resale revenues accounted for 1.0% of total electric operating revenues. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Utility Segment Contribution to Net Income for information on MWh sales by customer class.

We are authorized to provide retail electric service in designated territories in the state of Wisconsin, as established by indeterminate permits and boundary agreements with other utilities.

We buy and sell wholesale electric power by participating in the MISO Energy Markets. The cost of our individual generation offered into the MISO Energy Markets compared to our competitors affects how often our generating units are dispatched and whether we buy or sell power, based on our customers' needs. We provide wholesale electric service to various customers, including electric cooperatives, municipal joint action agencies, other investor-owned utilities, municipal utilities, and energy marketers. For more information, see D. Regulation.

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The majority of our sales for resale are sold into an energy market operated by MISO at market rates based on availability of our generation and market demand. Retail fuel costs are reduced by the amount that revenue exceeds the costs of sales derived from these opportunity sales.

Electric Sales Forecast

Our service territory experienced higher weather-normalized retail electric sales in 2021, as compared with 2020, due to a partial recovery from the impact of the first year of the COVID-19 pandemic and the expansion of a large industrial customer. We currently forecast retail electric sales volumes to remain flat over the next five years, assuming normal weather. Electric peak demand is expected to be flat over the next five years.

Customers

	Year Ended December 31
(in thousands)	2021	2020	2019
Electric customers – end of year
Residential	401.7	398.3	394.9
Small commercial and industrial	55.0	54.7	54.4
Large commercial and industrial	0.2	0.2	0.2
Total electric customers – end of year	456.9	453.2	449.5

Electric Commercial and Industrial Retail Customers

We provide electric utility service to a diversified base of customers in industries such as paper, metals and other manufacturing, food products, governmental, and health services.

Electric Generation and Supply Mix

Our electric supply strategy is to provide our customers with energy from plants using a diverse fuel mix that is expected to balance a stable, reliable, and affordable supply of electricity with environmental stewardship. Through our participation in the MISO Energy Markets, we supply a significant amount of electricity to our customers from power plants that we own. We supplement our internally generated power supply with long-term PPAs and through spot purchases in the MISO Energy Markets. We also sell excess power supply into the MISO Energy Markets when it is economical, which reduces net fuel costs by offsetting costs of purchased power. All options, including owned generation resources and purchased power opportunities, are continually evaluated on a real-time basis to select and dispatch the lowest-cost resources available to meet system load requirements.

The table below indicates our sources of electric energy supply as a percentage of sales for the three years ended December 31, as well as estimates for 2022:

	Estimate (1)		Actual
	2022		2021		2020		2019
Company-owned generation units:
Coal (2)	43.3	%	39.4	%	34.5	%	36.5	%
Natural gas combined cycle	19.5	%	31.0	%	31.9	%	30.4	%
Natural gas/oil peaking units	1.3	%	2.5	%	1.4	%	1.4	%
Renewables (3)	8.2	%	7.1	%	7.4	%	5.4	%
Total company-owned generation units	72.3	%	80.0	%	75.2	%	73.7	%
Power purchase contracts:
Renewables (3)	5.6	%	4.7	%	4.9	%	4.6	%
Other (4)	—	%	—	%	5.8	%	5.8	%
Total power purchase contracts	5.6	%	4.7	%	10.7	%	10.4	%
Purchased power from MISO	22.1	%	15.3	%	14.1	%	15.9	%
Total purchased power	27.7	%	20.0	%	24.8	%	26.3	%
Total electric utility supply	100.0	%	100.0	%	100.0	%	100.0	%

(1)    The values included in the estimate assume a natural gas price based on the December 2021 NYMEX.

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(2)    In 2021, we used more coal generation for electric supply, compared with 2020. Even though coal costs also increased in 2021, it was still more cost effective than natural gas due to increased natural gas prices in 2021. Due to the higher natural gas prices, coal generation is also expected to increase in 2022. We still anticipate using less coal in the future as we plan to achieve our emission reduction goals through the addition of renewable generation and eventual closure of existing coal generating facilities if approved by regulators.

(3)    Includes hydroelectric, solar, and wind generation.

(4)    Represents system energy and capacity purchases used to meet customer requirements and certain FERC regulations.

Electric Generation Facilities

Our generation portfolio is a mix of energy resources having different operating characteristics and fuel sources designed to balance providing energy that is stable, reliable, and affordable with environmental stewardship. We own 2,497 MW of generation capacity, including wholly owned and jointly owned facilities. Our facilities include coal-fired plants, natural gas-fired plants, and renewable generation. Certain of our natural gas-fired generation units have the ability to burn oil if natural gas is not available due to delivery constraints. For more information about our facilities, see Item 2. Properties.

In November 2021, we added to our electrical generation portfolio when Badger Hollow I, a new utility scale solar facility with a 150 MW nameplate capacity in Iowa County, Wisconsin, achieved commercial operation. We own 100 MW of Badger Hollow I.

Creating a Sustainable Future

WEC Energy Group's 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 supply with demand, while maintaining reliable, affordable energy for our customers. The retirements will contribute to meeting WEC Energy Group's and our goals to reduce CO2 emissions from electric generation.

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

As part of our path toward these goals, by the end of 2030, WEC Energy Group expects its use of coal will account for less than 5% of the power it supplies to its customers, and WEC Energy Group believes it will be in a position to eliminate coal as an energy source by 2035.

WEC Energy Group has already retired more than 1,800 MWs of coal-fired generation since the beginning of 2018, which included the 2018 retirement of the Pulliam power plant and the jointly-owned Edgewater Unit 4 generating units. See Note 6, Regulatory Assets and Liabilities, for more information related to these power plant retirements. Through the ESG Progress Plan, WEC Energy Group expects to retire approximately 1,600 MW of additional fossil-fueled generation by 2025, which includes the planned retirement in 2023-2024 of the jointly-owned Columbia Units 1-2.

In August 2021, the PSCW approved pilot programs for us to install and maintain 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, WEC Energy Group pledged to expand the EV charging network within our service territory. In doing so, WEC Energy Group joined a coalition of utility companies in a unified effort to make EV charging convenient and widely available throughout the Midwest. The coalition WEC Energy Group joined is planning to help build and grow EV charging corridors, enabling the general public to safely and efficiently charge their vehicles.

See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Corporate Developments for more information on the ESG Progress Plan.

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Renewable Generation

We meet a portion of our electric generation supply with various renewable energy resources, including wind, solar, and hydroelectric. This helps us maintain compliance with renewable energy legislation. These renewable energy resources also help us maintain diversity in our generation portfolio, which effectively serves as a price hedge against future fuel costs, and will help mitigate the risk of potential unknown costs associated with any future carbon restrictions for electric generators.

Wind

In January 2022, we, along with an unaffiliated utility, received approval from the PSCW 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, we will own 82 MW of this project. Construction of the project is expected to be completed by the end of 2022.

In September 2021, we, along with WE, received approval to accelerate capital investments to repower major components of Crane Creek, which is expected to be completed by the end of 2022.

Solar and Battery Storage

As part of our commitment to invest in zero-carbon generation, we have filed applications with the PSCW for approval to invest in 112 MW of utility-scale solar and 54 MW of battery storage, including the following:

•In April 2021, we, along with WE and 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 will own 45 MW of solar generation and 25 MW of battery storage of this project. If approved, construction of the project is expected to be completed by the second quarter of 2024.

•In March 2021, we, along with WE and 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 will own 37 MW of solar generation and 12 MW of battery storage of this project. If approved, construction of the project is expected to be completed by the end of 2023.

•In February 2021, we, along with WE and an unaffiliated utility, filed an application with the PSCW for 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 will own 30 MW of solar generation and 17 MW of battery storage of this project. If approved, construction of the project is expected to be completed by the end of 2023.

Natural Gas-Fired Generation

We have filed applications with the PSCW for approval to invest in up to 282.3 MW of natural gas-fired generation, including the following:

•In December 2021, we, along with WE, filed an application with the PSCW for approval 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. If approved, our share of this facility for 50% of the capacity is 118.3 MW, with the transaction expected to close in January 2023.

•In April 2021, we, along with WE, filed an application with the PSCW for approval to construct a natural gas-fired generation facility at our existing Weston power plant site in northern Wisconsin. The new facility will consist of seven reciprocating internal combustion engines. Once constructed, we will own 64 MW of this project. If approved, construction of the project is expected to be completed by the end of 2023.

In addition, in January 2022, we, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire a portion of West Riverside's nameplate capacity. We are also requesting approval to assign the option to purchase part of West Riverside to WE. If approved, we or WE would acquire 100 MW of capacity, in the first of two potential option exercises. West

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Riverside is a new, combined-cycle natural gas plant recently completed by an unaffiliated utility in Rock County, Wisconsin. If approved, the transaction is expected to close in the second quarter of 2023.

Electric System Reliability

The PSCW requires us to maintain a planning reserve margin above our projected annual peak demand forecast to help ensure reliability of electric service to our customers. These planning reserve requirements are consistent with the MISO calculated planning reserve margin. In 2008, the PSCW established a 14.5% reserve margin requirement for long-term planning (planning years two through ten). For short-term planning (planning year one), the PSCW requires Wisconsin utilities to follow the planning reserve margin established by MISO. MISO has an 18.3% installed capacity reserve margin requirement for the planning year from June 1, 2021, through May 31, 2022, and a 17.9% installed capacity reserve margin requirement for the planning year from June 1, 2022, through May 31, 2023. MISO's short-term reserve margin requirements experience year-to-year fluctuations, primarily due to changes in the generation resource mix and average forced outage rate of generation within the MISO footprint.

We believe that we have adequate capacity through company-owned generation units and power purchase contracts to meet the MISO calculated planning reserve margin during the current planning year. We also fully anticipate that we will have adequate capacity to meet the planning reserve margin requirements for the upcoming planning year.

Fuel and Purchased Power Costs

Our retail electric rates in Wisconsin are established by the PSCW and include base amounts for fuel and purchased power costs. The electric fuel rules set by the PSCW generally allow us to defer, for subsequent rate recovery or refund, under- or over-collections of actual fuel and purchased power costs beyond a 2% price variance from the costs included in the rates charged to customers. For more information about the fuel rules, see D. Regulation.

Our average fuel and purchased power costs per MWh by fuel type, including delivery costs, were as follows for the years ended December 31:

	2021		2020		2019
Coal	$	23.00	$	23.10	$	24.34
Natural gas combined cycle	22.36		15.80		19.38
Natural gas/oil peaking units	69.07		32.33		46.61
Purchased power	49.42		34.09		34.71

We purchase coal under long-term contracts, which helps with price stability. In the past, coal and associated transportation services were exposed to volatility in pricing due to changing domestic and world-wide demand for coal and diesel fuel. We have PSCW approval for a hedging program to moderate this volatility exposure. This program allows us to hedge, over a 36-month period, up to 75% of our potential risks related to rail transportation fuel surcharge exposure. The results of this hedging program, when used, are reflected in the average costs of fuel and purchased power.

We purchase natural gas for our plants on the spot market from natural gas marketers, utilities, and producers, and we arrange for transportation of the natural gas to our plants. We have firm and interruptible transportation, as well as balancing and storage agreements, intended to support our plants' variable usage. We also have PSCW approval for a hedging program to moderate volatility related to natural gas price risk. This program allows us to hedge, over a 36-month period, up to 75% of our estimated natural gas use for electric generation. The results of this hedging program are reflected in the average costs of natural gas.

Coal Supply

We diversify the coal supply for our jointly-owned electric generating facilities by purchasing coal from several mines in Wyoming and Pennsylvania, as well as from various other states. For 2022, approximately 83% of our total projected coal requirements of 2.5 million tons are contracted under fixed-price contracts. See Note 21, Commitments and Contingencies, for more information on amounts of coal purchases and coal deliveries under contract.

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The annual tonnage amounts contracted for the next three years are as follows.

(in thousands)	Annual Tonnage
2022	2,080
2023	1,900
2024	1,300

Coal Deliveries

All of our coal requirements are expected to be shipped by unit trains that we own under existing transportation agreements. The unit trains transport the coal for electric generating facilities from mines in Wyoming and Pennsylvania. Additional small volume agreements may also be used to supplement the normal coal supply for our facilities.

Power Purchase Commitments

We enter into short and long-term power purchase commitments to meet a portion of our anticipated electric energy supply needs. Our power purchase commitments with unaffiliated parties consist of 100 MW per year for 2022 through 2026, which exclude planning capacity purchases. Through WEC Energy Group's ESG Progress Plan, we retired some of our older, less efficient coal-fired generation in 2018. To procure additional planning capacity, we purchased capacity from the MISO annual auction to ensure that we maintain our compliance with planning reserve requirements as established by the PSCW and MISO.

Seasonality

Our electric utility sales are impacted by seasonal factors and varying weather conditions. We sell more electricity during the summer months because of the residential cooling load. We continue to upgrade our electric distribution system, including substations, transformers, and lines, to meet the demand of our customers. In 2021, our generating plants performed as expected during the warmest periods of the summer, and all power purchase commitments under firm contract were received. During this period, we did not require public appeals for conservation, and we did not interrupt or curtail service to non-firm customers who participate in load management programs. We did have economic interruption events; however, service to customers was not curtailed. Economic interruptions are declared during times in which the price of electricity in the regional market exceeds the cost of operating our peaking generation. During this time, interruptible customers can choose to continue using electricity at a price based on wholesale market prices or to reduce their load.

Competition

We face competition from various entities and other forms of energy sources available to customers, including self-generation by customers and alternative energy sources. We compete with other utilities for sales to municipalities and cooperatives as well as with other utilities and marketers for wholesale electric business.

For more information on competition in our service territory, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Competitive Markets.

Natural Gas Utility Operations

We are authorized to provide retail natural gas distribution service in designated territories in the state of Wisconsin, as established by indeterminate permits and boundary agreements with other utilities. Our natural gas utility provides service to customers located in northeastern Wisconsin.

We provide natural gas utility service to residential, commercial and industrial, and transportation customers. Major industries served include real estate, paper, restaurants, food products, and governmental. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Utility Segment Contribution to Net Income for information on natural gas sales volumes by customer class.

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Operating Revenues

For information about our operating revenues disaggregated by customer class for the years ended December 31, 2021, 2020, and 2019, see Note 4, Operating Revenues.

Natural Gas Sales Forecast

Our service territory experienced higher weather-normalized retail natural gas deliveries (excluding natural gas deliveries for electric generation) in 2021 as compared to 2020 due to strong growth in deliveries to transportation service customers. We currently forecast retail natural gas delivery volumes to grow at a rate between 1.0% and 1.3% over the next five years, assuming normal weather.

Customers

	Year Ended December 31
(in thousands)	2021	2020	2019
Customers – end of year
Residential	302.3	300.2	297.6
Commercial and industrial	34.7	34.5	34.3
Transport	0.9	0.9	0.9
Total customers	337.9	335.6	332.8

Natural Gas Supply, Pipeline Capacity and Storage

We have been able to meet our contractual obligations with both our suppliers and our customers. For more information on our natural gas utility supply and transportation contracts, see Note 21, Commitments and Contingencies.

Pipeline Capacity and Storage

The interstate pipelines serving Wisconsin access supply from natural gas producing areas in the Southern and Eastern United States, along with western Canada. We have contracted for long-term firm capacity from a number of these sources. This strategy reflects management's belief that overall supply security is enhanced by geographic diversification of the supply portfolio.

Due to variations in natural gas usage in Wisconsin, we have also contracted for substantial underground storage capacity, primarily in Michigan. We have entered into a long-term service agreement for natural gas storage with a wholly owned subsidiary of Bluewater. Bluewater, a wholly owned subsidiary of WEC Energy Group, owns natural gas storage facilities in Michigan and provides approximately one-third of our current storage needs. We target storage inventory levels at approximately 40% of forecasted demand for November through March. Diversity of natural gas supply enables us to manage significant changes in demand and to optimize our overall natural gas supply and capacity costs. We generally inject natural gas into storage during the spring and summer months and withdraw it in the winter months.

We hold daily transportation and storage capacity entitlements with interstate pipeline companies as well as other service providers under varied-length long-term contracts.

Natural gas pipeline capacity and storage and natural gas supplies under contract can be resold in secondary markets. Peak or near-peak demand generally occurs only a few times each year. The secondary markets facilitate utilization of capacity and supply during times when the contracted capacity and supply are in excess of utility demand. The proceeds from these transactions are passed through to customers, subject to our approved GCRM. For information on our GCRM, see Note 1(d), Operating Revenues.

Combined with our storage capability, management believes that the volume of natural gas under contract is sufficient to meet our forecasted firm peak-day and seasonal demand. Our forecasted design peak-day throughput is 8.5 million therms for the 2021 through 2022 heating season. Our peak daily send-out during 2021 was 6.0 million therms on February 15, 2021.

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Natural Gas Supply

We have contracts with suppliers for natural gas acquired in the Chicago, Illinois market hub and in some of the producing areas discussed above. The pricing of the term contracts is based upon first of the month indices.

We expect to continue to make natural gas purchases in the spot market as price and other circumstances dictate. We have supply relationships with a number of sellers from whom we purchase natural gas in the spot market.

Hedging Natural Gas Supply Prices

We have PSCW approval to hedge up to 60% of planned winter demand and up to 15% of planned summer demand using a mix of NYMEX-based natural gas options and futures contracts. This approval allows us to pass 100% of the hedging costs (premiums, brokerage fees and losses) and proceeds (gains) to customers through our GCRM.

To the extent that opportunities develop and physical supply operating plans are supportive, we also have PSCW approval to utilize NYMEX-based natural gas derivatives to capture favorable forward-market price differentials. That approval provides for 100% of the related proceeds to accrue to our GCRM.

Seasonality

Since the majority of our customers use natural gas for heating, customer use is sensitive to weather and is generally higher during the winter months. Accordingly, we are subject to some variations in earnings and working capital throughout the year as a result of changes in weather.

Our working capital needs are met by cash generated from operations and debt (both long-term and short-term). The seasonality of natural gas revenues causes the timing of cash collections to be concentrated from January through June. A portion of our winter natural gas supply needs is typically purchased and stored from April through November. Also, planned capital spending on our natural gas distribution facilities is concentrated in April through November. Because of these timing differences, the cash flow from customers is typically supplemented with temporary increases in short-term borrowings (from external sources) during the late summer and fall. Short-term debt is typically reduced over the January through June period.

Competition

We face varying degrees of competition from other entities and other forms of energy available to consumers. Many large commercial and industrial customers have the ability to switch between natural gas and alternative fuels. In addition, all of our customers have the opportunity to choose a natural gas supplier other than us. We offer natural gas transportation services for customers that elect to purchase natural gas directly from a third-party supplier. We continue to earn distribution revenues from these transportation customers for their use of our distribution systems to transport natural gas to their facilities. As such, the loss of revenue associated with the cost of natural gas that our transportation customers purchase from third-party suppliers has little impact on our net income, as it is offset by an equal reduction to natural gas costs.

For more information on competition in our service territory, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Competitive Markets.

Environmental Goals

WEC Energy Group continues to reduce methane emissions by improving its natural gas distribution systems. WEC Energy Group set a target across its natural gas distribution operations to achieve net-zero methane emissions by the end of 2030. WEC Energy Group plans to achieve its net-zero goal through an effort that includes both continuous operational improvements and equipment upgrades, as well as the use of RNG throughout its utility systems.

C. OTHER SEGMENT

Our other segment includes our non-utility activities as well as equity earnings from our investment in WRPC. We own 50% of the stock of WRPC. WRPC owns two hydroelectric plants, and we are entitled to 50% of the total capacity from its plants.

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D. REGULATION

In addition to the specific regulations noted below, we are also subject to various other regulations, which primarily consist of regulations, where applicable, of the EPA, the WDNR, and the United States Army Corps of Engineers.

Rates

Our retail electric and natural gas rates are regulated by the PSCW, and the FERC regulates our wholesale electric rates. Decisions by these regulators can significantly impact our liquidity, financial condition, and results of operations. The following table compares our utility operating revenues by regulatory jurisdiction for each of the three years ended December 31:

	2021				2020				2019
(in millions)	Amount		Percent		Amount		Percent		Amount		Percent
Electric
Wisconsin	$	1,074.8	91.0	%	$	1,009.6	88.8	%	$	967.0	86.7	%
FERC – Wholesale (1)	106.1		9.0	%	127.4		11.2	%	148.4		13.3	%
Total	1,180.9		100.0	%	1,137.0		100.0	%	1,115.4		100.0	%
Natural Gas – Wisconsin	340.0		100.0	%	270.1		100.0	%	296.5		100.0	%
Total utility operating revenues	$	1,520.9			$	1,407.1			$	1,411.9

(1)    On March 31, 2019, UMERC's natural gas-fired generation in the Upper Peninsula of Michigan began commercial operation. Prior to its generating units achieving commercial operation, UMERC purchased a portion of its power from us. The revenues received from UMERC are included in the FERC – Wholesale line above. See Note 3, Related Parties, for additional information.

Retail Rates

The PSCW has general supervisory and regulatory powers over public utilities in its jurisdiction including, but not limited to, approval of retail utility rates and standards of service, security issuances, mergers, affiliate transactions, location and construction of electric generating units and natural gas facilities, and certain other additions and extensions to utility facilities.

Historically, retail rates approved by the PSCW have been designed to provide utilities the opportunity to generate revenues to recover all prudently-incurred costs, along with a return on investment sufficient to pay interest on debt and provide a reasonable ROE. Rates charged to customers vary according to customer class and rate jurisdiction. We are subject to an earnings sharing mechanism in which a portion of our earnings are required to be refunded to customers if we earn above our authorized ROE. See Note 23, Regulatory Environment, for more information on our earnings sharing mechanism. The table below reflects our approved ROE and capital structure during 2021.

Regulated Retail Rates	Regulatory Commission	Authorized ROE	Average Common Equity Component
Electric and natural gas	PSCW	10.0%	52.5%

In addition to amounts collected from customers through approved base rates, we have certain recovery mechanisms in place that allow us to recover or refund prudently incurred costs that differ from those approved in base rates.

Embedded within our electric rates is an amount to recover fuel and purchased power costs. The Wisconsin retail fuel rules require us to defer, for subsequent rate recovery or refund, any under-collection or over-collection of fuel and purchased power costs that are outside of our symmetrical fuel cost tolerance, which the PSCW typically sets at plus or minus 2% of our approved fuel and purchased power cost plan. Our deferred fuel and purchased power costs are subject to an excess revenues test. If our ROE in a given year exceeds the ROE authorized by the PSCW, the recovery of under-collected fuel and purchased power costs would be reduced by the amount by which our return exceeds the authorized amount.

Our natural gas utility operates under a GCRM as approved by the PSCW. Generally, the GCRM allows for a dollar-for-dollar recovery of prudently incurred natural gas costs.

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See Note 1(d), Operating Revenues, for more information on the significant mechanisms we had in place during 2021 that allowed us to recover or refund changes in prudently incurred costs from rate case-approved amounts.

We file periodic requests with the PSCW for changes in retail rates. Our rate requests are based on forward looking test years, which reflect additions to infrastructure and changes in costs incurred or expected to be incurred. For information on our regulatory proceedings, see Note 23, Regulatory Environment. Orders from the PSCW can be viewed at https://psc.wi.gov/. The material and information contained on this website are not intended to be a part of, nor are they incorporated by reference into, this Annual Report on Form 10-K.

Wholesale Rates

The FERC regulates our wholesale sales of electric energy, capacity, and ancillary services. We have received market-based rate authority from the FERC. Market-based rate authority allows wholesale electric sales to be made in the MISO market and directly to third parties based on the negotiated market value of the transaction. We also make wholesale sales pursuant to cost-based formula rates. Cost-based formula rates provide for recovery of our costs and an approved rate of return. The predetermined formula is initially based on our expenses from the previous year, but is eventually trued up to reflect actual, current-year costs.

Electric Transmission, Capacity, and Energy Markets

In connection with its status as a FERC-approved RTO, MISO operates bid-based energy markets. MISO is responsible for monitoring and ensuring equal access to the electric transmission system in its footprint.

In MISO, base transmission costs are currently being paid by load-serving entities located in the service territories of each MISO transmission owner. The FERC has previously confirmed the use of the current transmission cost allocation methodology. Certain additional costs for new transmission projects are allocated throughout the MISO footprint.

As part of MISO, a market-based platform is used for valuing transmission congestion premised upon an LMP system. The LMP system includes the ability to hedge transmission congestion costs through ARRs and FTRs. ARRs are allocated to market participants by MISO, and FTRs are purchased through auctions. A new allocation and auction were completed for the period of June 1, 2021, through May 31, 2022. The resulting ARR allocation and the secured FTRs are expected to mitigate our transmission congestion risk for that period.

MISO has an annual zonal resource adequacy requirement to ensure there is sufficient generation capacity to serve the MISO market. To meet this requirement, capacity resources can be acquired through MISO's annual capacity auction, bilateral contracts for capacity, or provided from generating or demand response resources. All of our capacity requirements during the planning year from June 1, 2021, through May 31, 2022 were met.

Other Electric Regulations

We are subject to the Federal Power Act and the corresponding regulations developed by certain federal agencies. The Energy Policy Act amended the Federal Power Act in 2005 to, among other things, make electric utility industry consolidation more feasible, authorize the FERC to review proposed mergers and the acquisition of generation facilities, change the FERC regulatory scheme applicable to qualifying cogeneration facilities, and modify certain other aspects of energy regulations and federal tax policies applicable to us. Additionally, the Energy Policy Act created an Electric Reliability Organization to be overseen by the FERC, which established mandatory electric reliability standards and has the authority to levy monetary sanctions for failure to comply with these standards.

We are subject to Act 141 in Wisconsin which contains certain minimum requirements for renewable energy generation.

All of our hydroelectric facilities follow FERC guidelines and/or regulations.

Other Natural Gas Regulations

Almost all of the natural gas we distribute is transported to our distribution systems by interstate pipelines. The pipelines' transportation and storage services are regulated by the FERC under the Natural Gas Act and the Natural Gas Policy Act of 1978. In addition, the Pipeline and Hazardous Materials Safety Administration and the PSCW are responsible for monitoring and enforcing

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requirements governing our natural gas safety compliance programs for our pipelines under United States Department of Transportation regulations. These regulations include 49 CFR Part 191 (Transportation of Natural and Other Gas by Pipeline; Annual Reports, Incident Reports, and Safety-Related Condition Reports), 49 CFR Part 192 (Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards), and 49 CFR Part 195 (Transportation of Hazardous Liquids by Pipeline).

We are required to provide natural gas service and grant credit (with applicable deposit requirements) to customers within our service territory. We are generally not allowed to discontinue natural gas service during winter moratorium months to residential heating customers who do not pay their bills. Federal and certain state governments have programs that provide for a limited amount of funding for assistance to our low-income customers.

Compliance Costs

The regulations and oversight described above significantly influence our operating environment, and may cause us to incur compliance and other related costs and may affect our ability to recover these costs from our utility customers. Any anticipated capital expenditures for compliance with government regulations for the next three years are included in the estimated capital expenditures described in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Cash Requirements.

E. ENVIRONMENTAL COMPLIANCE

Our operations, especially as they relate to our coal-fired generating facilities, are subject to extensive environmental regulation by state and federal environmental agencies governing air and water quality, hazardous and solid waste management, environmental remediation, and management of natural resources. Costs associated with complying with these requirements are significant. Additional future environmental regulations or revisions to existing laws, including for example, additional regulation related to GHG emissions, coal combustion products, air emissions, water use, or wastewater discharges and other climate change issues, could significantly increase these environmental compliance costs.

Anticipated expenditures for environmental compliance and certain remediation issues for the next three years are included in the estimated capital expenditures described in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Cash Requirements. For a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change, see Note 21, Commitments and Contingencies.

F. HUMAN CAPITAL

We believe our employees are among our most important resources, so investing in human capital is critical to our success. We strive to foster a diverse workforce and inclusive workplace; attract, retain and develop talented personnel; and keep our employees safe and healthy.

WEC Energy Group's Board of Directors retains collective responsibility for comprehensive risk oversight of WEC Energy Group and its subsidiaries, including critical areas that could impact our sustainability, such as human capital. Management regularly reports to WEC Energy Group's Board of Directors on human capital management topics, including corporate culture, diversity and inclusion, employee development, and safety and health. WEC Energy Group's Board of Directors delegates specified duties to its committees. In addition to its responsibilities relative to executive compensation, the Compensation Committee has oversight responsibility for reviewing organizational matters that could significantly impact us, including succession planning. The Compensation Committee reviews recruiting and development programs and priorities, receives updates on key talent, and assesses workforce diversity across WEC Energy Group and its subsidiaries.

Workforce

As of December 31, 2021, we had 1,139 employees, including 803 that are represented under union agreements. We believe we have very good overall relations with our workforce. In order to attract and retain talent, we provide competitive wages and benefits to our employees based on their performance, role, location, and market data. Our compensation package also includes a 401(k) savings plan with an employer match, an annual incentive plan based on meeting company goals, healthcare and insurance benefits, vacation and paid time off days, as well as other benefits.

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Diversity and Inclusion

We are committed to fostering a diverse workforce and inclusive workplace. Our commitment is a core strategic competency and an integral part of our culture. As of December 31, 2021, women represented approximately 14% of our workforce and minorities represented approximately 3% of our workforce. WEC Energy Group has a number of initiatives that promote diverse workforce contributions, educate employees about diversity and inclusion, and ensure its companies, including us, are attractive employers for persons of diverse backgrounds. These initiatives include nine business resource groups (voluntary, employee-led groups organized around a particular shared background or interest), mentoring programs, and training for leaders on countering unconscious bias, building inclusive teams, and preventing workplace harassment. We also support external leadership and educational programs that support, train, and promote women and minorities in the communities we serve.

Safety and Health

WEC Energy Group's Executive Safety Committee directs our safety and health strategy, works to ensure consistency across groups, and reinforces our ongoing safety commitment that we refer to as “Target Zero.” Under our Target Zero commitment, we have an ultimate goal of zero incidents, accidents, and injuries. 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. We monitor and set goals for Occupational Safety and Health Administration (OSHA) lost-time incidents and days away, restricted or transferred (DART) metrics, as well as leading indicators, which together raise awareness about employee safety and guide injury-prevention activities.

We also provide employees various benefits and resources designed to promote healthy living, both at work and at home. We encourage employees to receive preventive examinations and to proactively care for their health through free health screenings, wellness challenges, and other resources.

In response to the COVID-19 pandemic, we have implemented safety protocols and new procedures to protect our employees and customers. See Factors Affecting Results, Liquidity, and Capital Resources – Coronavirus Disease – 2019, for additional information.

Development and Training

Employee training and development of both technical and leadership skills are integral aspects of our human capital strategy. We provide employees with a wide range of development opportunities, including online training, simulations, live classes, and mentoring to assist with their career advancement. These programs include safety and technical job skill training as well as soft-skill programs focused on relevant subjects, including communication and change management. Development of leadership skills remains a top priority and is specialized for all levels of employees. We have specific leadership programs for aspiring leaders and new supervisors, managers, and directors. This development of our employees is an integral part of our succession planning and provides continuity for our senior leadership.

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ITEM 1A. RISK FACTORS

We are subject to a variety of risks, many of which are beyond our control, that may adversely affect our business, financial condition, and results of operations. You should carefully consider the following risk factors, as well as the other information included in this report and other documents filed by us with the SEC from time to time, when making an investment decision.

Risks Related to Legislation and Regulation

Our business is significantly impacted by governmental regulation and oversight.

We are subject to significant state, local, and federal governmental regulations, including regulations by the PSCW and the FERC. These regulations significantly influence our operating environment, may affect our ability to recover costs from utility customers, and cause us to incur substantial compliance and other costs. Changes in regulations, interpretations of regulations, or the imposition of new regulations could also significantly impact us, including requiring us to change our business operations. Many aspects of our operations are regulated and impacted by government regulation, including, but not limited to: the rates we charge our retail electric and natural gas customers; our authorized rate of return; construction and operation of electric generating facilities and electric and natural gas distribution systems, including the ability to recover such costs; decommissioning generating facilities, the ability to recover the related costs, and continuing to recover the return on the net book value of these facilities; wholesale power service practices; electric reliability requirements and accounting; participation in the interstate natural gas pipeline capacity market; standards of service; issuance of securities; short-term debt obligations; transactions with affiliates; and billing practices. Failure to comply with any applicable rules or regulations may lead to customer refunds, penalties, and other payments, which could materially and adversely affect our results of operations and financial condition.

The rates we are allowed to charge our customers for retail and wholesale services have the most significant impact on our financial condition, results of operations, and liquidity. Rate regulation provides us an opportunity to recover prudently incurred costs and earn a reasonable rate of return on invested capital. However, our ability to obtain rate adjustments in the future is dependent upon regulatory action, and there is no assurance that our regulators will consider all of our costs to have been prudently incurred. In addition, our rate proceedings may not always result in rates that fully recover our costs or provide for a reasonable ROE. We defer certain costs and revenues as regulatory assets and liabilities for future recovery from or refund to customers, as authorized by our regulators. Future recovery of regulatory assets is not assured and is subject to review and approval by our regulators. If recovery of regulatory assets is not approved or is no longer deemed probable, these costs would be recognized in current period expense and could have a material adverse impact on our results of operations, cash flows, and financial condition.

We believe we have obtained the necessary permits, approvals, authorizations, certificates, and licenses for our existing operations, have complied in all material respects with all of their associated terms, and that our business is conducted in accordance with applicable laws. These permits, approvals, authorizations, certificates, and licenses may be revoked or modified by the agencies that granted them if facts develop that differ significantly from the facts assumed when they were issued. In addition, discharge permits and other approvals and licenses are often granted for a term that is less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. In addition, existing regulations may be revised or reinterpreted by federal, state, and local agencies, or these agencies may adopt new laws and regulations that apply to us. We cannot predict the impact on our business and operating results of any such actions by these agencies.

If we are unable to recover costs of complying with regulations or other associated costs in customer rates in a timely manner, or if we are unable to obtain, renew, or comply with these governmental permits, approvals, authorizations, certificates, or licenses, our results of operations and financial condition could be materially and adversely affected.

We face significant costs to comply with existing and future environmental laws and regulations.

Our operations are subject to extensive and evolving federal, state, and local environmental laws, regulations, and permit requirements related to, among other things, air emissions (including, but not limited to: CO2, methane, mercury, SO2, and NOx), protection of natural resources, water quality, wastewater discharges, and management of hazardous and toxic substances and solid wastes and soils. For example, the EPA adopted and implemented (or is in the process of implementing) regulations governing the emission of NOx, ozone, fine particulates, and other air pollutants under the CAA through the NAAQS, climate change regulations, New Source Performance Standards for GHG emissions from new, modified, and reconstructed fossil-fueled power plants, and other air quality regulations. The EPA also finalized regulations under the Clean Water Act that govern cooling water intake structures at

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our power plants and revised the effluent guidelines for steam electric generating plants. Several of these rules are being challenged or reviewed by agencies under the Biden Administration's Executive Order 13990, which creates additional uncertainty. As a result of these challenges and reviews, existing environmental laws and regulations may be revised or new laws or regulations may be adopted at the federal, state, or local level.

We incur significant capital and operating resources to comply with these environmental laws, regulations, and requirements, including costs associated with the installation of pollution control equipment; operating restrictions on our facilities; and environmental monitoring, emissions fees, and permits at our facilities. The operation of emission control equipment and compliance with rules regulating our intake and discharge of water could also increase our operating costs and reduce the generating capacity of our power plants. These regulations may create substantial additional costs in the form of taxes or emission allowances and could affect the availability and/or cost of fossil fuels and our ability to continue operating certain generating units. Failure to comply with these laws, regulations, and requirements, even if caused by factors beyond our control, may result in the assessment of civil or criminal penalties and fines. We continue to assess the potential cost of complying, and to explore different alternatives in order to comply, with these and other environmental regulations.

As a result of these compliance costs and other factors, certain of our coal-fired electric generating facilities have become uneconomical to maintain and operate, which has resulted in these units being retired or converted to an alternative type of fuel. As part of WEC Energy Group's commitment to a cleaner energy future, we have already retired approximately 300 MW of coal-fired generation since the beginning of 2018. Under the ESG Progress Plan, WEC Energy Group expects to retire approximately 1,600 MW of additional fossil-fueled generation by 2025, to be replaced with the construction of zero-carbon emitting renewables and clean natural gas-fueled generation.

We are also subject to significant liabilities related to the investigation and remediation of environmental impacts at certain of our current and former facilities and at third-party owned sites. We accrue liabilities and defer costs (recorded as regulatory assets) incurred in connection with our former manufactured gas plant sites. These costs include all costs incurred to date that we expect to recover, management's best estimates of future costs for investigation and remediation and related legal expenses, and are net of amounts recovered (or that may be recovered) from insurance or other third parties. Due to the potential for the imposition of stricter standards and greater regulation in the future, the possibility that other potentially responsible parties may not be willing or financially able to contribute to cleanup costs, a change in conditions or the discovery of additional contamination, our remediation costs could increase, and the timing of our capital and/or operating expenditures in the future may accelerate or could vary from the amounts currently accrued.

Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, occurs frequently throughout the United States. This litigation has included claims for damages alleged to have been caused by GHG and other emissions and exposure to regulated substances and/or requests for injunctive relief in connection with such matters. In addition to claims relating to our current facilities, we may also be subject to potential liability in connection with the environmental condition of facilities that we previously owned and operated, regardless of whether the liabilities arose before, during, or after the time we owned or operated these facilities. If we fail to comply with environmental laws and regulations or cause (or caused) harm to the environment or persons, that failure or harm may result in the assessment of civil penalties and damages against us. The incurrence of a material environmental liability or a material judgment in any action for personal injury or property damage related to environmental matters could have a material adverse effect on our results of operations and financial condition.

In the event we are not able to recover all of our environmental expenditures and related costs from our customers in the future, our results of operations and financial condition could be adversely affected. Further, increased costs recovered through rates could contribute to reduced demand for electricity and natural gas, which could adversely affect our results of operations, cash flows, and financial condition.

Our operations, capital expenditures, and financial results may be affected by the impact of greenhouse gas legislation, regulation, and emission reduction goals.

There is continued scientific and political attention to issues concerning the existence and extent of climate change. Management expects this attention to continue since climate change is one of President Biden's primary initiatives, with significant actions expected by his administration during his term in office. As a result, we expect the EPA and states to adopt and implement additional regulations to restrict emissions of GHGs. In addition, there is increasing activism from other stakeholders, including institutional investors and other sources of financing, to accelerate the transition to lower GHG emissions.

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Costs associated with such legislation, regulation, and emission reduction goals could be significant. GHG regulations that may be adopted in the future, at either the federal or state level, or other necessary changes to WEC Energy Group's ESG Progress Plan, may cause our environmental compliance spending to differ materially from the amounts currently estimated. These regulations, as well as changes in the fuel markets and advances in technology, could make additional electric generating units uneconomic to maintain or operate, may impact how we operate our existing fossil-fueled power plants, and could affect unit retirement and replacement decisions in the future under the ESG Progress Plan. These regulations could also adversely affect our future results of operations, cash flows, and financial condition. There is no guarantee that we will be allowed to fully recover costs incurred to comply with these and other federal and state regulations or that cost recovery will not be delayed or otherwise conditioned.

In addition, our natural gas delivery systems may generate fugitive gas as a result of normal operations and as a result of excavation, construction, and repair. Fugitive gas typically vents to the atmosphere and consists primarily of methane. CO2 is also a byproduct of natural gas consumption. Certain states outside our service territories have passed legislation banning natural gas used in new construction in order to limit these GHG emissions. Future statewide or nationwide actions like these to regulate GHG emissions could increase the price of natural gas, restrict the use of natural gas, cause us to accelerate the replacement and/or updating of our natural gas delivery systems, and adversely affect our ability to operate our natural gas facilities. A significant increase in the price of natural gas may increase rates for our natural gas customers, which could reduce natural gas demand.

In May 2021, WEC Energy Group announced goals to achieve reductions in carbon emissions from its electric generation fleet by 60% by 2025 and by 80% by 2030, both from a 2005 baseline. Over the longer term, the target for WEC Energy Group's generation fleet is net-zero CO2 emissions by 2050. WEC Energy Group also believes it will be in a position to eliminate coal as an energy source by 2035. We continue to monitor the financial and operational feasibility of taking more aggressive action to further reduce GHG emissions in order to limit future global temperature increases. WEC Energy Group's plan to replace older, fossil-fueled generation with zero-carbon emitting renewables and clean natural gas-fueled generation will contribute to the achievement of our goals related to reducing CO2 and methane emissions as well as coal as an energy source. However, our ability to achieve such goals depends on many external factors, including the development of relevant energy technologies and the ability to execute WEC Energy Group's capital plan. These efforts could impact how we operate our electric generating units and natural gas facilities and lead to increased competition and regulation, all of which could have a material adverse effect on our operations and financial condition.

Changes in tax legislation, IRS audits, or our inability to use certain tax benefits and carryforwards, may adversely affect our financial condition, results of operations, and cash flows, as well as our credit ratings.

Tax legislation and regulations can adversely affect, among other things, our financial condition, results of operations, cash flows, liquidity, and credit ratings. Future changes to corporate tax rates or policies, including under the Biden Administration, could require us to take material charges against earnings. Such changes include, among other things, increasing the federal corporate income tax rate, disallowing use of certain tax benefits and carryforwards, limiting interest deductions, and altering the expensing of capital expenditures. Our inability to manage these changes, an adverse determination by one of the applicable taxing jurisdictions, or additional interpretations, implementing regulations, amendments, or technical corrections by the Treasury Department, the IRS, or state income tax authorities, could significantly impact our financial results and cash flows.

We have significantly reduced our federal and state income tax liabilities in the past through tax credits, net operating losses, and charitable contribution deductions. A reduction in or disallowance of these tax benefits could adversely affect our earnings and cash flows. We have not fully used these allowed tax benefits in our previous tax filings and have carried them forward to use against future taxable income. Our inability to generate sufficient taxable income in the future to fully use these tax carryforwards before they expire, could significantly affect our tax obligations and financial results.

In addition, we have invested, and plan to continue to invest, in renewable energy generating facilities. These facilities generate PTCs or ITCs that we use to reduce our federal tax obligations. The amount of tax credits we earn depends on the amount of electricity produced, the applicable tax credit rate, or the amount of the investment in qualifying property. A variety of operating and economic factors, including transmission constraints, adverse weather conditions, and breakdown or failure of equipment, could significantly reduce the PTCs generated by the wind parks we have invested in, resulting in a material adverse impact on our financial condition and results of operations. In addition, any reductions or eliminations of these tax credits or other governmental incentives that promote renewable energy generating facilities may limit our ability to make further investments in renewable energy generating facilities or reduce the returns on our existing investments.

We are also uncertain as to how credit rating agencies, capital markets, the FERC, or state public utility commissions will treat any future changes to federal or state tax legislation. These impacts could subject us to credit rating downgrades. In addition, certain

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financial metrics used by credit rating agencies, such as our funds from operations-to-debt percentage, could be negatively impacted by changes in federal or state income tax legislation.

We could be subject to higher costs and penalties as a result of mandatory reliability standards.

We are subject to mandatory reliability and critical infrastructure protection standards established by the North American Electric Reliability Corporation and enforced by the FERC. The critical infrastructure protection standards focus on controlling access to critical physical and cyber security assets. Compliance with the mandatory reliability standards could subject us to higher operating costs. If we are found to be in noncompliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, or damage to our reputation.

Risks Related to the Operation of Our Business

The ongoing COVID-19 pandemic has adversely affected, and could continue to adversely affect, our business functions, financial condition, liquidity, and results of operations.

The COVID-19 pandemic has adversely impacted the economy and financial markets, which has adversely affected our business. During 2021, commercial and industrial retail sales volumes began to improve due to the continued economic recovery in our service territories. However, there are still questions regarding the extent and duration of the COVID-19 pandemic itself. Orders limiting the capacity of various businesses could be adopted in the future depending on how the virus continues to mutate and spread. The resulting effects of any future orders could have a variety of adverse impacts on us, including a decrease in revenues, increased bad debt expense; increases in past due accounts receivable balances, and access to the capital markets at unreasonable terms or rates.

The COVID-19 pandemic and any additional related government responses could impair our ability to develop, construct, and operate facilities. Risks include extended disruptions to supply chains and inflation, resulting in increased costs for labor, materials, and services, which could adversely impact our ability to implement our corporate strategy. We may also be adversely impacted by reduced labor availability and productivity as a result of COVID-19 infections, although we have taken precautions with regard to employee hygiene and facility cleanliness, imposed travel limitations on our employees, implemented additional protocols for our field employees who travel to customer premises, provided additional employee benefits, and implemented remote work policies where appropriate. We could also be impacted by possible labor disruptions, employee attrition, and a reduced ability to replace departing employees as a result of employees who leave or forego employment to avoid surcharges imposed on our medical plan or other required precautionary measures.

Despite our efforts to manage the impacts of the COVID-19 pandemic, the extent to which COVID-19 may continue to affect us depends on factors beyond our knowledge or control. Therefore, we are currently unable to determine what additional impact the COVID-19 pandemic may have on our business plans and operations, liquidity, financial condition, and results of operations, but will continue to monitor COVID-19 developments and modify our plans as conditions change.

Our operations are subject to risks arising from the reliability of our electric generation, transmission, and distribution facilities, natural gas infrastructure facilities, renewable energy facilities, and other facilities, as well as the reliability of third-party transmission providers.

Our financial performance depends on the successful operation of our electric generation, natural gas and electric distribution facilities, and renewable energy facilities. The operation of these facilities involves many risks, including operator error and the breakdown or failure of equipment or processes.

Potential breakdown or failure may occur due to severe weather as a result of climate change or otherwise (i.e., storms, tornadoes, floods, droughts, etc); catastrophic events (i.e., fires, earthquakes, explosions, pandemic health events, etc.); significant changes in water levels in waterways; fuel supply or transportation disruptions; accidents; employee labor disputes; construction delays or cost overruns; shortages of or delays in obtaining equipment, material, and/or labor; performance below expected levels; operating limitations that may be imposed by environmental or other regulatory requirements; terrorist attacks; or cyber security intrusions. Any of these events could lead to substantial financial losses, including increased maintenance costs, and unanticipated capital expenditures. Because our electric generation and renewable energy facilities are interconnected with third-party transmission facilities, the operation of our facilities could also be adversely affected by events impacting their systems. Unplanned outages at our power plants may reduce our revenues, cause us to incur significant costs if we are required to operate our higher cost electric generators or purchase replacement power to satisfy our obligations, and could result in additional maintenance expenses.

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Insurance, warranties, performance guarantees, or recovery through the regulatory process may not cover any or all of these lost revenues or increased expenses, which could adversely affect our results of operations and cash flows.

Our operations are subject to various conditions that can result in fluctuations in energy sales to customers, including customer growth and general economic conditions in our service areas, varying weather conditions, and energy conservation efforts.

Our results of operations and cash flows are affected by the demand for electricity and natural gas, which can vary greatly based upon:

•Fluctuations in customer growth and general economic conditions in our service areas. Customer growth and energy use can be negatively impacted by population declines as well as economic factors in our service territories, including workforce reductions, stagnant wage growth, changing levels of support from state and local government for economic development, business closings, and reductions in the level of business investment. We are impacted by economic cycles and the competitiveness of the commercial and industrial customers we serve. Any economic downturn, disruption of financial markets, or reduced incentives by state government for economic development could adversely affect the financial condition of our customers and demand for their products or services. These risks could directly influence the demand for electricity and natural gas as well as the need for additional power generation and generating facilities. We could also be exposed to greater risks of accounts receivable write-offs if customers are unable to pay their bills.

•Weather conditions. Demand for electricity is greater in the summer and winter months when cooling and heating is necessary. In addition, demand for natural gas peaks in the winter heating season. As a result, our overall results may fluctuate substantially on a seasonal basis. In addition, milder temperatures during the summer cooling season and during the winter heating season, as a result of climate change or otherwise, may result in lower revenues and net income.

•Our customers' continued focus on energy conservation. Our customers' use of electricity and natural gas has decreased as a result of continued individual conservation efforts, including the use of more energy efficient technologies. Customers could also voluntarily reduce their consumption of energy in response to decreases in their disposable income and increases in energy prices. Conservation of energy can be influenced by certain federal and state programs that are intended to influence how consumers use energy. For example, several states, including Wisconsin, have adopted energy efficiency targets to reduce energy consumption.

As part of our planning process, we estimate the impacts of changes in customer growth and general economic conditions, weather, and customer energy conservation efforts, but risks still remain. Any of these matters, as well as any regulatory delay in adjusting rates as a result of reduced sales from effective conservation measures or the adoption of new technologies, could adversely impact our results of operations and financial condition.

Our operations are subject to the effects of global climate change.

A changing climate creates uncertainty and could result in broad changes, both physical and financial in nature, to our service territories.

If climate changes occur that result in extreme temperatures in our service territories, our financial results could be adversely impacted by lower electric and natural gas usage and higher natural gas costs. An extreme weather event could result in downed wires and poles or damage to other operating equipment, which could result in us foregoing sales of electricity and lost revenues. 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 and for the use of fuel at our generation facilities was temporarily driven significantly higher than our normal winter weather expectations. Although our utilities have regulatory mechanisms in place for recovering all prudently incurred gas costs, regulatory commissions could disallow recovery or order the refund of any costs determined to be imprudent.

In addition, our operations could be adversely affected and our facilities placed at greater risk of damage should changes in global climate produce, among other possible conditions, unusual variations in temperature and weather patterns, which could result in more intense, frequent and extreme weather events, such as wind storms, floods, tornadoes, snow and ice storms, or abnormal levels of precipitation. Extreme weather may result in unexpected increases in customer load, requiring us to procure additional power at wholesale prices for our retail operations, unpredictable curtailment of customer load by MISO to maintain grid reliability, or other grid reliability issues. Any of these events could lead to substantial financial losses including increased maintenance costs and unanticipated capital expenditures. The cost of storm restoration efforts may also not be fully recoverable through the regulatory process.

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Our corporate strategy may be impacted by policy and legal, technology, market, and reputational risks and opportunities that are associated with the transition to lower GHG emissions. In addition, changes in policy to combat climate change, including mitigation and adaptation efforts, and technology advancement, each of which can also accelerate the implications of a transition to lower emissions, may materially adversely impact our results of operations and cash flows through significant capital expenditures and investments in renewable generation.

Our operations and corporate strategy may be adversely affected by supply chain disruptions and inflation.

Our business is dependent on the global supply chain to ensure that equipment, materials, and other resources are available to both expand and maintain services in a safe and reliable manner. Current domestic and global supply chain disruptions are delaying the delivery, and in some cases resulting in shortages of, materials, equipment, and other resources that are critical to our business operations. Failure to eliminate or manage the constraints in the supply chain may eventually impact the availability of items that are necessary to support normal operations as well as materials that are required to implement our corporate strategy for continued infrastructure growth, including our renewable energy projects.

Moreover, prices of equipment, materials, and other resources have increased recently as a result of these supply chain disruptions and may continue to increase in the future, as a result of inflation. Although inflation in the United States has been relatively low in recent years, during 2021 the United States economy began experiencing a significant inflationary effect. While we cannot predict any future trends in the rate of inflation, the global COVID-19 pandemic and other factors have brought uncertainty to the near-term economic outlook. Increases in inflation raise our costs for labor, materials, and services, and failure to secure these resources on economically acceptable terms, as well as any regulatory delay in adjusting rates to account for increased costs, may adversely impact our financial condition and results of operations.

We are actively involved with multiple significant capital projects, which are subject to a number of risks and uncertainties that could adversely affect project costs and completion of construction projects.

Our business requires substantial capital expenditures for investments in, among other things, capital improvements to our electric generating facilities, electric and natural gas distribution infrastructure, and other projects, including projects for environmental compliance. We also expect to continue constructing and investing in renewable energy generating facilities as part of the ESG Progress Plan, including repowering existing wind generation projects in our generation portfolio.

Achieving the intended benefits of any large construction project is subject to many uncertainties, some of which we will have limited or no control over, that could adversely affect project costs and completion time. For example, the timing of the completion of Badger Hollow I was impacted by supply chain disruptions, primarily related to the COVID-19 pandemic. Additional supply chain disruptions, including solar panel shortages and increasing material costs as a result of government tariffs and other factors, could impact the timing of completion of our other renewable projects. Additional risks include, but are not limited to, the ability to adhere to established budgets and time frames; the availability of labor or materials at estimated costs; the ability of contractors to perform under their contracts; strikes; adverse weather conditions; potential legal challenges; changes in applicable laws or regulations; rising interest rates; the impact of pandemic health events; other governmental actions; continued public and policymaker support for such projects; and events in the global economy. In addition, certain of these projects require the approval of the PSCW. If construction of commission-approved projects should materially and adversely deviate from the schedules, estimates, and projections on which the approval was based, our regulators may deem the additional capital costs as imprudent and disallow recovery of them through rates, and otherwise available PTCs and ITCs for renewable energy projects could be lost or lose value.

To the extent that delays occur, costs become unrecoverable, tax credits are lost or lose value, or we (or third parties with whom we invest and/or partner) otherwise become unable to effectively manage and complete our (or their) capital projects, our results of operations, cash flows, and financial condition may be adversely affected.

Our operations are subject to risks beyond our control, including but not limited to, cyber security intrusions, terrorist attacks, acts of war, or unauthorized access to personally identifiable information.

We have been subject to attempted cyber attacks from time to time, and will likely continue to be subject to such attempted attacks; however, these prior attacks have not had a material impact on our system or business operations. Despite the implementation of security measures, all assets and systems are potentially vulnerable to disability, failures, or unauthorized access due to physical or cyber security intrusions caused by human error, vendor bugs, terrorist attacks, or other malicious acts. These threats could result in a full or partial disruption of our ability to generate, transmit, purchase, or distribute electricity or natural gas

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or cause environmental repercussions. If our assets or systems were to fail, be physically damaged, or be breached, and were not recovered in a timely manner, we may be unable to perform critical business functions, and data, including sensitive information, could be compromised.

We operate in an industry that requires the use of sophisticated information technology systems and network infrastructure, which control an interconnected system of generation, distribution, and transmission systems shared with third parties. A successful physical or cyber security intrusion may occur despite our security measures or those that we require our vendors to take, which include compliance with reliability standards and critical infrastructure protection standards. Successful cyber security intrusions, including those targeting the electronic control systems used at our generating facilities and electric and natural gas transmission and distribution systems, could disrupt our operations and result in loss of service to customers. Attacks may come through ransomware, software updates or patches, or firmware that hackers can manipulate. These intrusions may cause unplanned outages at our power plants, which may reduce our revenues or cause us to incur significant costs if we are required to operate our higher cost electric generators or purchase replacement power to satisfy our obligations, and could result in additional maintenance expenses. The risk of such intrusions may also increase our capital and operating costs as a result of having to implement increased security measures for protection of our information technology and infrastructure.

Our continued efforts to integrate, consolidate, and streamline our operations have also resulted in increased reliance on current and recently completed projects for technology systems. We implement procedures to protect our systems, but we cannot guarantee that the procedures we have implemented to protect against unauthorized access to secured data and systems are adequate to safeguard against all security breaches. The failure of any of these or other similarly important technologies, or our inability to support, update, expand, and/or integrate these technologies with those of our affiliates could materially and adversely impact our operations, diminish customer confidence and our reputation, materially increase the costs we incur to protect against these risks, and subject us to possible financial liability or increased regulation or litigation.

Our business requires the collection and retention of personally identifiable information of our customers and employees, who expect that we will adequately protect such information. Security breaches may expose us to a risk of loss or misuse of confidential and proprietary information. A significant theft, loss, or fraudulent use of personally identifiable information may lead to potentially large costs to notify and protect the impacted persons, and/or could cause us to become subject to significant litigation, costs, liability, fines, or penalties, any of which could materially and adversely impact our results of operations as well as our reputation with customers and regulators, among others. In addition, we may be required to incur significant costs associated with governmental actions in response to such intrusions or to strengthen our information and electronic control systems. We may also need to obtain additional insurance coverage related to the threat of such intrusions.

Threats to our systems and operations continue to emerge as new ways to compromise components into our systems or networks are developed. Any operational disruption or environmental repercussions caused by these on-going threats to our assets and technology systems could result in a significant decrease in our revenues or significant reconstruction or remediation costs, which could materially and adversely affect our results of operations, financial condition, and cash flows. The costs of repairing damage to our facilities, operational disruptions, protecting personally identifiable information, and notifying impacted persons, as well as related legal claims, may also not be recoverable in rates, may exceed the insurance limits on our insurance policies, or, in some cases, may not be covered by insurance.

Advances in technology, and legislation or regulations supporting such technology, could make our electric generating facilities less competitive and may impact the demand for natural gas.

Advances in new technologies that produce or store power or reduce power consumption are ongoing and include renewable energy technologies, customer-oriented generation, energy storage devices, and energy efficiency technologies. We generate power at central station power plants and utility-scale renewable generation facilities to achieve economies of scale and produce power at a competitive cost. There are distributed generation technologies that produce power, including fuel cells, microturbines, wind turbines, solar cells, and related energy storage devices, which have become more cost competitive than they were in the past. It is possible that legislation or regulations could be adopted supporting the use of these technologies at below cost or that permit third-party sales from such facilities, and allow these facilities to interconnect to our distribution system. There is also a risk that advances in technology will continue to reduce the costs of these alternative methods of producing power to a level that is competitive with that of central station and utility-scale renewable power production.

We cannot predict the effect that development of alternative energy sources or new technology may have on our natural gas operations, including whether subsidies of alternative energy sources by local, state, and federal governments might be expanded, or what impact this might have on the supply of or the demand for natural gas.

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If these technologies become cost competitive and achieve economies of scale, our market share could be eroded, and the value of our generating facilities and natural gas distribution systems could be reduced. Advances in technology, or changes in legislation or regulations, could also change the channels through which our customers purchase or use power and natural gas, which could reduce our sales and revenues or increase our expenses.

We transport and distribute natural gas, which involves numerous risks that may result in accidents and other operating risks and costs.

Inherent in natural gas distribution activities are a variety of hazards and operational risks, such as leaks, accidental explosions, and mechanical problems, which could materially and adversely affect our results of operations, financial condition, and cash flows. In addition, these risks could result in serious injury to employees and non-employees, loss of human life, significant damage to property, environmental pollution, impairment of operations, and substantial losses to us. The location of natural gas pipelines near populated areas, including residential areas, commercial business centers, and industrial sites, could increase the level of damages resulting from these risks. These activities may subject us to litigation and/or administrative proceedings from time to time, which could result in substantial monetary judgments, fines, or penalties against us, or be resolved on unfavorable terms.

We may fail to attract and retain an appropriately qualified workforce.

We operate in an industry that requires many of our employees to possess unique technical skill sets. Events such as an aging workforce without appropriate replacements, the mismatch of skill sets to future needs, or the unavailability of contract resources may lead to operating challenges or increased costs. These operating challenges include lack of resources, loss of knowledge, and a lengthy time period associated with skill development. In addition, current and prospective employees may determine that they do not wish to work for us. For example, we are currently subject to workforce trends occurring in the United States triggered by the decisions of employees to leave the workforce and/or their employer at higher rates as compared with prior years. This high demand for replacement employees as a result of this trend may lead to higher labor costs than currently budgeted for and adversely affect our results of operations. Failure to hire and obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be adversely affected.

Our counterparties may fail to meet their obligations, including obligations under power purchase, natural gas supply, natural gas pipeline capacity, and transportation agreements.

We are exposed to the risk that counterparties to various arrangements who owe us money, electricity, natural gas, or other commodities or services will not be able to perform their obligations. Should the counterparties to these arrangements fail to perform or if capacity is inadequate, we may be required to replace the underlying commitment at current market prices or we may be unable to meet all of our customers' electric and natural gas requirements unless or until alternative supply arrangements are put in place. In such event, we may incur losses, and our results of operations, financial position, or liquidity could be adversely affected.

We have entered into several power purchase, natural gas supply, natural gas pipeline capacity, and transportation agreements with non-affiliated companies. Revenues are dependent on the continued performance by the counterparties of their obligations under these agreements. Although we have a comprehensive credit evaluation process and contractual protections, it is possible that one or more counterparties could fail to perform their obligations. If this were to occur, we generally would expect that any operating and other costs that were initially allocated to a defaulting customer's power purchase, natural gas supply, natural gas pipeline capacity, or transportation agreement would be reallocated among our retail customers. To the extent these costs are not allowed to be reallocated by our regulators or there is any regulatory delay in adjusting rates, a counterparty default under these agreements could have a negative impact on our results of operations and cash flows.

Risks Related to Economic and Market Volatility

Our business is dependent on our ability to successfully access capital markets on competitive terms and rates.

We rely on access to credit and capital markets to support our capital requirements, including expenditures for our utility infrastructure and to comply with future regulatory requirements, to the extent not satisfied by the cash flow generated by our operations. We have historically secured funds from a variety of sources, including the issuance of short-term and long-term debt securities. In addition, we rely on a committed bank credit agreement as back-up liquidity, which allows us to access the low cost

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commercial paper markets. Successful implementation of our long-term business strategies, including capital investment, is dependent upon our ability to access the capital markets, including the banking and commercial paper markets, on competitive terms and rates. Interest rates may increase in the future, which may affect our results of operations and our ability to earn our approved rate of return. Rising interest rates may also impair our ability to cost-effectively finance capital expenditures and to refinance maturing debt.

Our access to the credit and capital markets could be limited, or our cost of capital significantly increased, due to any of the following risks and uncertainties:

•A rating downgrade;

•Failure to comply with debt covenants;

•An economic downturn or uncertainty;

•Prevailing market conditions and rules;

•Concerns over foreign economic conditions;

•Changes in tax policy;

•Changes in investment criteria of institutional investors or banks, including any policies that would limit or restrict funding for companies with fossil fuel-related investments;

•War or the threat of war;

•The overall health and view of the utility and financial institution industries; and

•The replacement of LIBOR with an alternative reference rate.

LIBOR is the subject of national, international, and other regulatory reform, which is expected to cause LIBOR to cease to exist after June 2023. Various alternative reference rates are being evaluated by market participants, with the secured overnight financing rate being the most widely adopted alternative to date. We cannot predict the consequences and timing of the development of alternative reference rates, or the performance of LIBOR as it is being phased out through June 2023. The transition to alternative reference rates could include an increase in our interest expense.

If any of these risks or uncertainties limit our access to the credit and capital markets or significantly increase our cost of capital, it could limit our ability to implement, or increase the costs of implementing, our business plan, which, in turn, could materially and adversely affect our results of operations, cash flows, and financial condition.

A downgrade in our credit ratings could negatively affect our ability to access capital at reasonable costs and/or require the posting of collateral.

There are a number of factors that impact our credit ratings, including, but not limited to, capital structure, regulatory environment, the ability to cover liquidity requirements, and other requirements for capital. We could experience a downgrade in ratings if the rating agencies determine that the level of business or financial risk of us or the utility industry has deteriorated. Changes in rating methodologies by the rating agencies could also have a negative impact on credit ratings.

Any downgrade by the rating agencies could:

•Increase borrowing costs under our existing credit facility;

•Require the payment of higher interest rates in future financings and possibly reduce the pool of creditors;

•Decrease funding sources by limiting our access to the commercial paper market;

•Limit the availability of adequate credit support for our operations; and

•Trigger collateral requirements in various contracts.

Fluctuating commodity prices could negatively impact our electric and natural gas utility operations.

Our operating and liquidity requirements are impacted by changes in the forward and current market prices of natural gas, coal, electricity, renewable energy credits, and ancillary services.

We burn natural gas in several of our electric generation plants, and as a supplemental fuel at one of our coal-fired plants. In many instances the cost of purchased power is tied to the cost of natural gas. The cost of natural gas has increased, and may continue to increase because of disruptions in the supply of natural gas due to a curtailment in production or distribution, international market conditions, the demand for natural gas, and the availability of shale gas and potential regulations and/or other government action affecting its accessibility.

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For Wisconsin retail electric customers, we bear the risk for the recovery of fuel and purchased power costs within a symmetrical 2% fuel tolerance band compared to the forecast of fuel and purchased power costs established in our rate structure. Prudently incurred fuel and purchased power costs are recovered dollar-for-dollar from our wholesale electric customers. We receive dollar-for-dollar recovery of prudently incurred natural gas costs from our natural gas customers.

Changes in commodity prices could result in:

•Higher working capital requirements, particularly related to natural gas inventory, accounts receivable, and cash collateral postings;

•Reduced profitability to the extent that lower revenues, increased bad debt, and higher interest expense are not recovered through rates;

•Higher rates charged to our customers, which could impact our competitive position;

•Reduced demand for energy, which could impact revenues and operating expenses; and

•Shutting down of generation facilities if the cost of generation exceeds the market price for electricity.

We may not be able to obtain an adequate supply of coal, which could limit our ability to operate our coal-fired facilities.

We operate jointly-owned coal-fired electric generating units. Although we generally carry sufficient coal inventory at our generating facilities to protect against an interruption or decline in supply, there can be no assurance that the inventory levels will be adequate. While we have coal supply and transportation contracts in place, we cannot assure that the counterparties to these agreements will be able to fulfill their obligations to supply coal to us or that we will be able to take delivery of all the coal volume contracted for. Coal deliveries may occasionally be restricted because of rail congestion and maintenance, derailments, weather, the COVID-19 pandemic, and supplier financial hardship. Supplier financial hardship is a result of decreased demand for coal due to increased natural gas and renewable energy generation, the impact of environmental regulations, and environmental concerns related to coal-fired generation.

If we are unable to obtain our coal requirements under our coal supply and transportation contracts, we may be required to purchase coal at higher prices or we may be forced to reduce generation at our jointly-owned coal-fired units, which could lead to increased fuel costs. The increase in fuel costs could result in either reduced margins on net sales into the MISO Energy Markets, a reduction in the volume of net sales into the MISO Energy Markets, and/or an increase in net power purchases in the MISO Energy Markets. There is no guarantee that we would be able to fully recover any increased costs in rates or that recovery would not otherwise be delayed, either of which could adversely affect our results of operations and cash flows.

Our use of derivative contracts could result in financial losses.

We use derivative instruments such as swaps, options, futures, and forwards to manage commodity price exposure. We could recognize financial losses as a result of volatility in the market value of these contracts or if a counterparty fails to perform. These risks are managed through risk management policies, which might not work as planned and cannot entirely eliminate the risks associated with these activities. In addition, although our hedging programs must be approved by the PSCW, derivative contracts entered into for hedging purposes might not offset the underlying exposure being hedged as expected, resulting in financial losses. In the absence of actively quoted market prices and pricing information from external sources, the value of these financial instruments can involve management's judgment or use of estimates. Changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

Restructuring in the regulated energy industry and competition in the retail and wholesale markets could have a negative impact on our business and revenues.

The regulated energy industry continues to experience significant structural changes. Deregulation or other changes in law in the states where we serve our customers could allow third-party suppliers to contract directly with customers for their natural gas and electric supply requirements. In addition, legislation or regulation that supports distributed energy technologies or that allows third party sales from such technologies could result in further competition. This increased competition in the retail and wholesale markets could have a material adverse financial impact on us.

The FERC continues to support the existing RTOs that affect the structure of the wholesale market within these RTOs. In connection with its status as a FERC-approved RTO, MISO implemented bid-based energy markets that are part of the MISO Energy Markets. All market participants, including us, must submit day-ahead and/or real-time bids and offers for energy at locations across the MISO

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region. MISO then calculates the most efficient solution for all of the bids and offers made into the market that day and establishes an LMP that reflects the market price for energy. We are required to follow MISO's instructions when dispatching generating units to support MISO's responsibility for maintaining the stability of the transmission system. MISO also implemented an ancillary services market for operating reserves that schedules energy and ancillary services at the same time as part of the energy market, allowing for more efficient use of generation assets in the MISO Energy Markets. These market designs continue to have the potential to increase the costs of transmission, the costs associated with inefficient generation dispatching, the costs of participation in the MISO Energy Markets, and the costs associated with estimated payment settlements.

The FERC rules related to transmission are designed to facilitate competition in the wholesale electricity markets among regulated utilities, non-utility generators, wholesale power marketers, and brokers by providing greater flexibility and more choices to wholesale customers, including initiatives designed to encourage the integration of renewable sources of supply. In addition, along with transactions contemplating physical delivery of energy, financial laws and regulations impact hedging and trading based on futures contracts and derivatives that are traded on various commodities exchanges, as well as over-the-counter. Technology changes in the power and fuel industries also have significant impacts on wholesale transactions and related costs. We currently cannot predict the impact of these and other developments or the effect of changes in levels of wholesale supply and demand, which are driven by factors beyond our control.

We may experience poor investment performance of benefit plan holdings due to changes in assumptions and market conditions.

We have significant obligations related to pension and OPEB plans. If WEC Energy Group is unable to successfully manage our benefit plan assets and medical costs, our cash flows, financial condition, or results of operations could be adversely impacted. Our cost of providing these plans is dependent upon a number of factors, including actual plan experience, changes made to the plans, and assumptions concerning the future. Types of assumptions include earnings on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation, estimated withdrawals by retirees, and our required or voluntary contributions to the plans. Plan assets are subject to market fluctuations and may yield returns that fall below projected return rates. In addition, medical costs for both active and retired employees may increase at a rate that is significantly higher than we currently anticipate. Our funding requirements could be impacted by a decline in the market value of plan assets, changes in interest rates, changes in demographics (including the number of retirements), or changes in life expectancy assumptions.

General Risks

We may be unable to obtain insurance on acceptable terms or at all, and the insurance coverage we do obtain may not provide protection against all significant losses.

Our ability to obtain insurance, as well as the cost and coverage of such insurance, could be affected by developments affecting our business; international, national, state, or local events; and the financial condition of insurers and our contractors that are required to acquire and maintain insurance for our benefit. Insurance coverage may not continue to be available at all or at rates or terms similar to those presently available to us. In addition, our insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. Any losses for which we are not fully insured or that are not covered by insurance at all could materially adversely affect our results of operations, cash flows, and financial position.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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ITEM 2. PROPERTIES

We own our principal properties outright. However, the major portion of our electric utility distribution lines and natural gas utility distribution mains and services are located on or under streets and highways, on land owned by others, and are generally subject to granted easements, consents, or permits.

Electric Facilities

The following table summarizes information on our electric generation facilities, including wholly-owned and jointly owned facilities, as of December 31, 2021:

Name	Location	Fuel	Number of Generating Units	Capacity In MW (1)
Coal-fired plants
Columbia	Portage, WI	Coal	2	311	(2)
Weston	Rothschild, WI	Coal	2	720	(2)
Total coal-fired plants			4	1,031
Natural gas-fired plants
De Pere Energy Center	De Pere, WI	Natural Gas/Oil	1	165
Fox Energy Center	Wrightstown, WI	Natural Gas	3	577
Pulliam	Green Bay, WI	Natural Gas/Oil	1	81
West Marinette	Marinette, WI	Natural Gas/Oil	3	150
Weston	Rothschild, WI	Natural Gas/Oil	3	65
Total natural gas-fired plants			11	1,038
Renewables
Hydro plants (17 in number)	WI	Hydro	51	67	(3) (4)
Badger Hollow I	WI	Solar	41	100	(2)
Two Creeks	WI	Solar	48	100	(2)
Wind sites (2 in number)	WI and IA	Wind	152	161	(2)
Total renewables			292	428
Total system			307	2,497

(1)    Capacity for our electric generation facilities, other than wind and solar generating facilities, is based on rated capacity, which is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. Values are primarily based on the net dependable expected capacity ratings for summer 2022 established by tests and may change slightly from year to year. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand. Capacity for wind generating facilities is based on nameplate capacity, which is the amount of energy a turbine should produce at optimal wind speeds. Capacity for solar generating facilities is based on nameplate capacity, which is the maximum output that a generator should produce at continuous full power.

(2)    We jointly own these facilities with various other utilities. The capacity indicated for each of these units is equal to our portion of total plant capacity based on our percent of ownership.

•Wisconsin Power and Light Company, an unaffiliated utility, operates the Columbia units. We hold a 27.5% ownership interest in Columbia.

•We operate the Weston 4 facility and hold a 70.0% ownership interest in this facility. Dairyland Power Cooperative, an unaffiliated energy cooperative, holds the remaining 30.0% interest.

•We jointly own Badger Hollow I with Madison Gas and Electric Company, an unaffiliated utility. We hold a 66.7% ownership interest in this facility and Madison Gas Electric Company owns the remaining 33.3%.

•We jointly own Two Creeks with Madison Gas and Electric Company, an unaffiliated utility. We hold a 66.7% ownership interest in this facility and Madison Gas and Electric Company owns the remaining 33.3%.

•We jointly own Forward Wind with Wisconsin Power and Light Company and Madison Gas and Electric Company, two unaffiliated utilities. We hold a 44.6% ownership interest in this facility, while the unaffiliated utilities collectively own the remaining 55.4%.

(3)     All of our hydroelectric facilities follow FERC guidelines and/or regulations.

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(4)    WRPC owns and operates the Castle Rock and Petenwell units. We hold a 50.0% ownership interest in WRPC and are entitled to 50.0% of the total capacity at Castle Rock and Petenwell. Our share of capacity for Castle Rock and Petenwell is 7.0 MW and 10.3 MW, respectively.

As of December 31, 2021, we operated approximately 13,900 miles of overhead distribution lines and approximately 8,800 miles of underground distribution cable, as well as 118 electric distribution substations and approximately 194,000 line transformers.

Natural Gas Facilities

At December 31, 2021, our natural gas properties were located in northeastern Wisconsin and consisted of the following:

•Approximately 8,400 miles of natural gas distribution mains,

•Approximately 250 miles of natural gas transmission mains,

•Approximately 311,800 natural gas lateral services, and

•Approximately 90 natural gas distribution and transmission gate stations.

Our natural gas distribution and gas storage systems included distribution mains and transmission mains connected to the pipeline transmission systems of ANR Pipeline Company, Great Lakes Transmission Company, Guardian Pipeline L.L.C., Union Gas, and Vector Pipeline.

We also own office buildings, natural gas regulating and metering stations, and major service centers, including garage and warehouse facilities, in certain communities we serve. Where distribution lines and services and natural gas distribution mains and services occupy private property, we have in some, but not all instances, obtained consents, permits, or easements for these installations from the apparent owners or those in possession of those properties, generally without an examination of ownership records or title.

ITEM 3. LEGAL PROCEEDINGS

In addition to those legal proceedings discussed in Note 21, Commitments and Contingencies, and Note 23, Regulatory Environment, 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.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

There is no established public trading market for our common stock, as Integrys, a wholly-owned subsidiary of WEC Energy Group, owns all of our outstanding common stock. See Note 11, Common Equity, for more information.

ITEM 6. RESERVED

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CORPORATE DEVELOPMENTS

Introduction

We are an electric and natural gas utility and an indirect wholly owned subsidiary of WEC Energy Group. We derive revenues primarily from the distribution and sale of electricity and natural gas to retail customers in Wisconsin. We also provide wholesale electric service to numerous utilities and cooperatives for resale. We conduct our business primarily through our utility reportable segment. See Note 20, Segment Information, for more information on our reportable business segments.

Corporate Strategy

Our goal is to continue to build and sustain long-term value for our customers and WEC Energy Group's shareholders by focusing on the fundamentals of our business: environmental stewardship; reliability; operating efficiency; financial discipline; exceptional customer care; and safety. WEC Energy Group's capital investment plan for efficiency, sustainability and growth, referred to as its ESG Progress Plan, provides a roadmap to achieve this goal. It is an aggressive plan to cut emissions, maintain superior reliability, deliver significant savings for customers, and grow WEC Energy Group's and our investment in the future of energy.

Throughout its strategic planning process, WEC Energy Group takes into account important developments, risks and opportunities, including new technologies, customer preferences and affordability, energy resiliency efforts, and sustainability. WEC Energy Group published the results of a priority sustainability issue assessment in 2020, identifying the issues that are most important to the company and its stakeholders over the short and long terms. This risk and priority assessment has formed WEC Energy Group's direction as a company.

Creating a Sustainable Future

WEC Energy Group's 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 at its electric utilities including us. When taken together, the retirements and new investments should better balance supply with demand, while maintaining reliable, affordable energy for our customers. The retirements will contribute to meeting WEC Energy Group's and our goals to reduce CO2 emissions from electric generation.

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

As part of our path toward these goals, by the end of 2030, WEC Energy Group expects its use of coal will account for less than 5% of the power it supplies to its customers, and WEC Energy Group believes it will be in a position to eliminate coal as an energy source by 2035.

WEC Energy Group has already retired more than 1,800 MWs of coal-fired generation since the beginning of 2018, which included the 2018 retirement of the Pulliam power plant as well as the jointly-owned Edgewater Unit 4 generating units. See Note 6, Regulatory Assets and Liabilities, for more information related to these power plant retirements. Through the ESG Progress Plan, WEC Energy Group expects to retire approximately 1,600 MW of additional fossil-fueled generation by 2025, which includes the planned retirement in 2023-2024 of the jointly-owned Columbia Units 1-2.

In addition to retiring these older, fossil-fueled plants, WEC Energy Group expects to invest approximately $3.5 billion from 2022-2026 in regulated renewable energy in Wisconsin. WEC Energy Group's 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 made by either us or WE based on specific customer needs:

•1,400 MW of utility-scale solar (amount does not include WE's Badger Hollow Solar Park II, which is currently under construction);

•800 MW of battery storage; and

•100 MW of wind.

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WEC Energy Group also plans on investing in a combination of clean, natural gas-fired generation, made by either us or WE based on specific customer needs, including:

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

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

•the planned purchase of Whitewater, 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 previously received approval from the PSCW to invest in 200 MW of utility-scale solar. We partnered with an unaffiliated utility to construct two solar projects now in service in Wisconsin: Two Creeks and Badger Hollow I. We own 100 MW of each project for a total of 200 MW.

In August 2021, the PSCW approved pilot programs for us to install and maintain 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, WEC Energy Group pledged to expand the EV charging network within its utilities' electric service territories. In doing so, WEC Energy Group joined a coalition of utility companies in a unified effort to make EV charging convenient and widely available throughout the Midwest. The coalition WEC Energy Group joined is planning to help build and grow EV charging corridors, enabling the general public to safely and efficiently charge their vehicles.

WEC Energy Group also continues to reduce methane emissions by improving its natural gas distribution system. WEC Energy Group set a target across its natural gas distribution operations to achieve net-zero methane emissions by the end of 2030. WEC Energy Group plans to achieve its net-zero goal through an effort that includes both continuous operational improvements and equipment upgrades, as well as the use of RNG throughout its utility systems.

As part of WEC Energy Group's effort to look for new opportunities in sustainable energy, it is testing the effects of blending hydrogen, a clean generating fuel, with natural gas at one of its RICE generating units in the Upper Peninsula of Michigan. WEC Energy Group is 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.

Reliability

We have made significant reliability-related investments in recent years, and in accordance with the 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.

We completed work on our System Modernization and Reliability Project, which involved modernizing parts of our electric distribution system, including burying or upgrading lines. The project focused on constructing facilities to improve the reliability of electric service we provide to our customers.

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 AMI 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 us and our customers. This program reduces the manual effort for disconnects and reconnects and enhances outage management capabilities.

WEC Energy Group continues to focus on integrating the resources of its businesses and finding the best and most efficient processes while meeting all applicable legal and regulatory requirements.

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Financial Discipline

A strong adherence to financial discipline is essential to meeting our earnings projections and maintaining a strong balance sheet, stable cash flows, 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, and equipment, that are no longer strategic to operations, are not performing as intended, or have an unacceptable risk profile. See Note 2, Acquisition, for more information on our acquisition of Whitewater.

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 all of the WEC Energy Group companies. It has moved all utilities, including us, 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 the WEC Energy Group 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

The following discussion and analysis of our Results of Operations includes comparisons of our results for the year ended December 31, 2021 with the year ended December 31, 2020. For a similar discussion that compares our results for the year ended December 31, 2020 with the year ended December 31, 2019, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations in Part II of our 2020 Annual Report on Form 10-K, which was filed with the SEC on February 25, 2021.

Earnings

Our earnings for the year ended December 31, 2021 were $231.1 million, compared with $221.6 million for the year ended December 31, 2020. See below for additional information on the $9.5 million increase in earnings.

Non-GAAP Financial Measures

The discussion below addresses the contribution of our utility segment to net income. The discussion includes 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.

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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 utility segment 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. Our utility segment operating income for the years ended December 31, 2021 and 2020 was $288.8 million and $308.2 million, respectively. The discussion below includes a table that provides the calculation of electric margins and natural gas margins, along with a reconciliation to the most directly comparable GAAP measure, operating income.

Utility Segment Contribution to Net Income

	Year Ended December 31
(in millions)	2021		2020		B (W)
Electric revenues	$	1,180.9	$	1,137.0	$	43.9
Fuel and purchased power costs	387.2		318.9		(68.3)
Total electric margins	793.7		818.1		(24.4)
Natural gas revenues	340.0		270.1		69.9
Cost of natural gas sold	210.0		139.4		(70.6)
Total natural gas margins	130.0		130.7		(0.7)
Total electric and natural gas margins	923.7		948.8		(25.1)
Other operation and maintenance	406.4		426.3		19.9
Depreciation and amortization	188.6		174.3		(14.3)
Property and revenue taxes	39.9		40.0		0.1
Operating income	288.8		308.2		(19.4)
Other income, net	36.8		29.9		6.9
Interest expense	64.7		63.5		(1.2)
Income before income taxes	260.9		274.6		(13.7)
Income tax expense	30.9		54.2		23.3
Net income	$	230.0	$	220.4	$	9.6

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

	Year Ended December 31
(in millions)	2021		2020		B (W)
Operation and maintenance not included in line items below	$	211.5	$	207.1	$	(4.4)
Transmission (1)	152.1		159.9		7.8
Regulatory amortizations and other pass through expenses (2)	38.6		37.6		(1.0)
Earnings sharing mechanism (3)	4.2		21.6		17.4
Other	—		0.1		0.1
Total other operation and maintenance	$	406.4	$	426.3	$	19.9

(1)    Represents transmission expense that we are authorized to collect in rates. The PSCW has approved escrow accounting for ATC and MISO network transmission expenses. As a result, we 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 2021 and 2020, $147.3 million and $146.8 million, respectively, of costs were billed to us by transmission providers.

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

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(3)    See Note 23, Regulatory Environment, for more information about our earnings sharing mechanism.

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

	Year Ended December 31
	MWh (in thousands)
Electric Sales Volumes	2021	2020	B (W)
Customer class
Residential	3,024.8	3,038.9	(14.1)
Small commercial and industrial	4,019.0	3,865.1	153.9
Large commercial and industrial	3,973.1	3,682.7	290.4
Other	26.7	26.9	(0.2)
Total retail	11,043.6	10,613.6	430.0
Wholesale	1,726.8	2,035.9	(309.1)
Resale	243.2	784.1	(540.9)
Total sales in MWh	13,013.6	13,433.6	(420.0)

	Year Ended December 31
	Therms (in millions)
Natural Gas Sales Volumes	2021	2020	B (W)
Customer class
Residential	238.4	247.6	(9.2)
Commercial and industrial	173.7	184.5	(10.8)
Total retail	412.1	432.1	(20.0)
Transport	473.5	437.9	35.6
Total sales in therms	885.6	870.0	15.6

	Year Ended December 31
	Degree Days
Weather (1)	2021	2020	B (W)
Heating (7,380 normal)	6,735	7,139	(5.7)	%
Cooling (532 normal)	643	660	(2.6)	%

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

Electric Revenues

Electric revenues increased $43.9 million during 2021, compared with 2020. 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 recovery of fuel and purchased power costs and the remaining drivers of the changes in electric revenues.

Electric Utility Margins

Electric utility margins decreased $24.4 million during 2021, compared with 2020. Margins did not change significantly from the PSCW-approved Wisconsin rate orders as the positive impact of increased rates was more than offset by a $27.6 million negative impact related to unprotected excess deferred taxes, which we agreed to return to customers over two years and is offset in income taxes. See Note 23, Regulatory Environment, for more information.

The significant factors impacting the lower electric utility margins were:

•A $27.6 million year-over-year negative impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, our margins 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

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the 2% price variance is generally deferred for future recovery or refund to customers. In 2021, we were unable to defer our portion of the under-collected fuel and purchased power costs due to earning an ROE in excess of the PSCW authorized amount.

•Lower margins of $13.8 million driven by a decrease in wholesale customers related to the expiration of certain wholesale contracts.

These decreases in margins were partially offset by an $18.2 million net increase in margins related to higher retail sales volumes. Commercial and industrial retail sales volumes improved during 2021, compared with 2020, primarily due to the continued economic recovery in Wisconsin from the COVID-19 pandemic and the expansion of a large industrial customer.

Natural Gas Revenues

Natural gas revenues increased $69.9 million during 2021, compared with 2020. 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 40.2% during 2021, compared with 2020. 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 decreased $0.7 million during 2021, compared with 2020. The most significant factor impacting the lower natural gas utility margins was a decrease from lower retail sales volumes, including the impact of weather.

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

Other operating expenses at the utility segment decreased $5.7 million during 2021, compared with 2020. The significant factors impacting the decrease in other operating expenses were:

•A $17.4 million decrease in expense related to our earnings sharing mechanism. See Note 23, Regulatory Environment, for more information on our rate orders.

•A $7.8 million decrease in transmission expense driven by a decrease in electric wholesale customers related to the expiration of certain wholesale contracts.

•A $7.4 million net decrease in operating expense related to our power plants, primarily driven by reduced costs at Columbia and Weston.

•A $3.9 million decrease in benefit costs, primarily due to lower stock-based compensation.

These decreases in other operating expenses were partially offset by:

•A $14.3 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan.

•An $8.6 million increase in electric and natural gas distribution expenses, primarily driven by significant storms in 2021.

•A $2.7 million increase in customer service expenses, primarily related to additional costs from an information technology project created to improve the billing, call center, and credit collection functions, as well as higher call volumes and metering costs.

•A $2.6 million increase in expenses related to charitable projects supporting our customers and the communities within our service territories.

•A $1.8 million increase in property and liability insurance premiums.

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Other Income, Net

Other income, net increased $6.9 million during 2021, compared with 2020, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 19, Employee Benefits, for more information on our benefit costs. This increase was partially offset by lower AFUDC – Equity, driven by Two Creeks being placed in service in November 2020.

Interest Expense

Interest expense increased $1.2 million during 2021, compared with 2020, driven by lower AFUDC – Debt recorded on capital projects, primarily related to Two Creeks being placed in service in November 2020.

Income Tax Expense

Income tax expense decreased $23.3 million during 2021, compared with 2020. This decrease was primarily due to a $27.6 million increase in 2021 of the amortization of the unprotected excess deferred tax benefits from the Tax Legislation in connection with our Wisconsin rate order approved by the PSCW, effective January 1, 2020. This item did not impact earnings as it was offset in operating income. See Note 16, Income Taxes, and Note 23, Regulatory Environment, for more information.

Other Segment Contribution to Net Income

	Year Ended December 31
(in millions)	2021		2020		B (W)
Net income	$	1.1	$	1.2	$	(0.1)

LIQUIDITY AND CAPITAL RESOURCES

Overview

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

The following discussion and analysis of our Liquidity and Capital Resources includes comparisons of our cash flows for the year ended December 31, 2021 with the year ended December 31, 2020. For a similar discussion that compares our cash flows for the year ended December 31, 2020 with the year ended December 31, 2019, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources in Part II of our 2020 Annual Report on Form 10-K, which was filed with the SEC on February 25, 2021.

Cash Flows

The following table summarizes our cash flows during the years ended December 31:

(in millions)	2021		2020		Change in 2021 Over 2020
Cash provided by (used in):
Operating activities	$	438.3	$	453.4	$	(15.1)
Investing activities	(397.7)		(527.0)		129.3
Financing activities	(40.9)		74.0		(114.9)

Operating Activities

Net cash provided by operating activities decreased $15.1 million during 2021, compared with 2020, driven by an $80.1 million decrease in cash related to higher payments for fuel and purchased power at our plants during 2021, compared with the same period in 2020. We incurred higher natural gas costs throughout 2021, compared with 2020, as a result of an increase in the price of natural gas. Increased coal costs also drove higher payments for fuel used at our plants.

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This decrease in net cash provided by operating activities was partially offset by:

•A $38.3 million increase in cash related to higher cash received for income taxes during 2021, compared with 2020, driven by an increase in tax credits used.

•A $35.3 million increase in cash due to realized gains on derivative instruments as well as higher collateral received from counterparties during 2021, both driven by higher natural gas prices.

Investing Activities

Net cash used in investing activities decreased $129.3 million during 2021, compared with 2020, driven by a decrease in cash paid for capital expenditures, which is discussed in more detail below. Partially offsetting this decrease was $7.1 million of insurance proceeds received from the cash surrender value of life insurance in 2020.

Capital Expenditures

Capital expenditures for the years ended December 31 were as follows:

(in millions)	2021		2020		Change in 2021 Over 2020
Capital expenditures	$	389.7	$	530.7	$	(141.0)

The decrease in cash paid for capital expenditures during 2021, compared with 2020, was driven by lower payments for capital expenditures related to Badger Hollow I, Two Creeks, and upgrades of automated meter reading devices during 2021. These decreases were partially offset by higher payments for capital expenditures related to Crane Creek during 2021.

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

Financing Activities

Net cash related to financing activities decreased $114.9 million during 2021, compared with 2020, and was driven by a $160.0 million decrease in equity contributions received from our parent during 2021, compared with 2020, to balance our capital structure.

This decrease in cash was partially offset by a $450.0 million increase in cash due to the issuance of long-term debt during 2021. A portion of these proceeds was used to redeem $400.0 million of long-term debt with higher interest rates. There were no issuances or repayments of long-term debt during 2020.

Significant Financing Activities

For more information on our financing activities, see Note 13, Short-Term Debt and Lines of Credit, and Note 14, Long-Term Debt.

Cash Requirements

We require funds to support and grow our business. 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 parent, and the funding of our ongoing operations. Our significant cash requirements are discussed in further detail below.

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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 21, Commitments and Contingencies.

(in millions)
2022	$	627.2
2023	537.3
2024	621.6
Total	$	1,786.1

We continue to upgrade our 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.

WEC Energy Group is 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.

•In February 2021, we, along with WE and an unaffiliated utility, filed an application with the PSCW for 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 will own 30 MW of solar generation and 17 MW of battery storage of this project. If approved, our share of the cost of this project is estimated to be approximately $65 million, with construction expected to be completed by the end of 2023.

•We, along with WE, received approval to accelerate capital investments in two wind parks. Our share of the investment is expected to be approximately $69 million to repower major components of Crane Creek, which is expected to be completed by the end of 2022.

•In March 2021, we, along with WE and 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 will own 37 MW of solar generation and 12 MW of battery storage of this project. Our share of the cost of this project is estimated to be approximately $65 million, with construction expected to be completed by the end of 2023.

•We, 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, we will own 82 MW of this project. If approved, our share of the cost of this project is estimated to be $150 million, with construction expected to be completed by the end of 2022.

•In April 2021, we, along with WE and 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 will own 45 MW of solar generation and 25 MW of battery storage of this project. If approved, our share of the cost of this project is estimated to be approximately $97 million, with construction expected to be completed by the second quarter of 2024.

•In April 2021, we, along with WE, filed an application with the PSCW for approval to construct a natural gas-fired generation facility at our existing Weston power plant site in northern Wisconsin. The new facility will consist of seven reciprocating internal combustion engines. Once constructed, we will own 64 MW of this project. If approved, our share of the cost of this project is estimated to be approximately $85 million, with construction expected to be completed by the end of 2023.

•In November 2021, we, along with WE, 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.

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In December 2021, we, along with WE, filed an application with the PSCW for approval to acquire Whitewater. If approved, our share of the cost of this facility is estimated to be $36.3 million for 50% of the capacity, with the transaction expected to close in January 2023. See Note 2, Acquisition, for more information.

•In January 2022, we, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire a portion of West Riverside's nameplate capacity. We are also requesting approval to assign the option to purchase part of West Riverside to WE. If approved, we 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, and we don't assign the option to WE, our share of the cost of this ownership interest would be approximately $91 million, with the transaction expected to close in the second quarter of 2023.

See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Withhold Release Order Related to Silica-Based Products for information on the potential impacts to our solar projects as a result of CBP actions related to solar panels.

Long-Term Debt

A significant amount of cash is required to retire and pay interest on our long-term debt obligations. See Note 14, Long-Term Debt, for more information on our outstanding long-term debt, including a schedule of our long-term debt maturities over the next five years. The following table summarizes our required interest payments on long-term debt (excluding finance lease obligations) as of December 31, 2021:

	Interest Payments Due by Period
(in millions)	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
Interest payments on long-term debt	$	1,500.7	$	65.1	$	130.2	$	130.2	$	1,175.2

Common Stock Dividends

During the years ended December 31, 2021, 2020, and 2019, we paid common stock dividends of $260.0 million, $260.0 million, and $120.0 million, respectively, to the sole holder of our common stock, Integrys. Any payment of future dividends is subject to approval by our Board of Directors and is dependent upon future earnings, capital requirements, and financial and other business conditions. In addition, various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to Integrys in the form of cash dividends, loans, or advances. We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future. See Note 11, Common Equity for more information related to these restrictions and our other common stock matters.

Other Significant Cash Requirements

Our utility operations have purchase obligations under various contracts for the procurement of fuel, power, and gas supply, as well as the related storage and transportation. These costs are a significant component of funding our ongoing operations. See Note 21, Commitments and Contingencies, for more information, including our minimum future commitments related to these purchase obligations.

In addition to our energy-related purchase obligations, we have commitments for other costs incurred in the normal course of business, including costs related to information technology services, meter reading services, maintenance and other service agreements for certain generating facilities, and various engineering agreements. Our estimated future cash requirements related to these purchase obligations are reflected below.

	Payments Due by Period
(in millions)	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
Purchase orders	$	23.8	$	11.4	$	7.9	$	4.5	$	—

We have various finance and operating lease obligations. Our finance lease obligations primarily relate to land leases for our solar projects. See Note 15, Leases, for more information, including an analysis of our minimum lease payments due in future years.

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We make contributions to our pension and OPEB plans based upon various factors affecting us, including our liquidity position and tax law changes. See Note 19, Employee Benefits, for our expected contributions in 2022 and our expected pension and OPEB payments for the next 10 years. We expect the majority of these future pension and OPEB payments to be paid from our outside trusts. See Sources of Cash–Investments in Outside Trusts below for more information.

In addition to the above, our balance sheet at December 31, 2021 included various other liabilities that, due to the nature of the liabilities, the amount and timing of future payments cannot be determined with certainty. These liabilities include AROs, liabilities for the remediation of manufactured gas plant sites, and liabilities related to the accounting treatment for uncertainty in income taxes. For additional information on these liabilities, see Note 9, Asset Retirement Obligations, Note 21, Commitments and Contingencies, and Note 16, Income Taxes, respectively.

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. See Note 1(q), Guarantees, and Note 13, Short-Term Debt and Lines of Credit, for more information.

Sources of Cash

Liquidity

We anticipate meeting our short-term and long-term cash requirements to operate our business and implement our corporate strategy through internal generation of cash from operations, equity contributions from our parent, and access to the capital markets, which allows us to obtain external short-term borrowings, including commercial paper, 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.

See Factors Affecting Results, Liquidity, and Capital Resources – Coronavirus Disease – 2019, for additional information on the impacts of the COVID-19 pandemic on our liquidity.

We maintain a bank back-up credit facility, which provides liquidity support for our 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, and other factors. We plan to maintain a capital structure consistent with that approved by the PSCW. For more information on our approved capital structure, see Item 1. Business – D. Regulation.

The issuance of our securities is subject to the approval of the PSCW. Additionally, with respect to the public offering of securities, we file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the PSCW, 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 December 31, 2021, our current liabilities exceeded our current assets by $143.3 million. We do not expect this to have any impact on our liquidity as we currently believe that our cash and cash equivalents, our available capacity of $67.7 million under our existing revolving credit facility, 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 13, Short-Term Debt and Lines of Credit, and Note 14, Long-Term Debt, for more information about our credit facility and securities.

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Investments in Outside Trusts

We maintain investments in outside trusts to fund the obligation to provide pension and certain OPEB benefits to current and future retirees. As of December 31, 2021, these trusts had investments of approximately $1.2 billion, consisting of fixed income and equity securities, that are subject to the volatility of the stock market and interest rates. The performance of existing plan assets, long-term discount rates, changes in assumptions, and other factors could affect our future contributions to the plans, our financial position if our accumulated benefit obligation exceeds the fair value of the plan assets, and future results of operations related to changes in pension and OPEB expense and the assumed rate of return. For additional information, see Note 19, Employee Benefits.

Debt Covenants

At December 31, 2021, 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. See Note 13, Short-Term Debt and Lines of Credit, Note 14, Long-Term Debt, and Note 11, Common Equity, for more information.

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 December 31, 2021. 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. We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.

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

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

Coronavirus Disease – 2019

The COVID-19 pandemic has adversely impacted the economy and financial markets, which has adversely affected our business. During 2021, commercial and industrial retail sales volumes began to improve due to the continued economic recovery in our service territories. However, there are still questions regarding the extent and duration of the COVID-19 pandemic itself. Orders limiting the capacity of various businesses could be adopted again in the future depending on how the virus continues to mutate and spread. The resulting effects of any future orders could have a variety of adverse impacts on us, including a decrease in revenues, increased bad debt expense, increases in past due accounts receivable balances, and access to the capital markets at unreasonable terms or rates.

Liquidity and Financial Markets

Upon the initial enactment of certain COVID-19 related shelter-in-place orders in early to mid-March 2020, commercial paper markets became more expensive and related terms became less flexible. In response to these signs of market instability, the Federal Reserve implemented certain measures, including a reduction in its benchmark Federal Funds rate and the establishment of various programs to restore liquidity and stability into the short-term funding markets. These measures had an almost immediate mitigating effect on commercial paper rates and availability in 2020. As of December 31, 2021, the disruptions in the commercial paper and long-term debt markets as a result of the COVID-19 pandemic have subsided.

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Allowance for Credit Losses

Economic disruptions caused by the COVID-19 pandemic, including higher unemployment rates and the inability of some businesses to recover from the pandemic, caused a higher percentage of our accounts receivable balances to become uncollectible. Although impacts on our results of operations related to higher uncollectible receivable balances were mitigated by regulatory mechanisms and certain COVID-19 specific regulatory orders we received, the increase in past due receivables we experienced resulted in higher working capital requirements. However, with normal collection practices now underway, we continue to see an improvement in our past due receivable balances, as evidenced by a decrease in our allowance for credit losses. See Note 5, Credit Losses, for more information.

Our exposure to credit losses for certain regulated utility customers is mitigated by a regulatory mechanism we have in place. Specifically, our residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. In addition, we have received specific orders related to the deferral of certain costs (including credit losses) and foregone revenues related to the COVID-19 pandemic. The additional protections provided by these COVID-19 specific regulatory orders are still being assessed and will be subject to prudency reviews. See Note 23, Regulatory Environment, for more information.

Loss of Business

Many of the commercial and industrial customers in our service territory have recovered, or are recovering, from the COVID-19 pandemic. However, we are still seeing a decrease in the consumption of electricity and natural gas by some of our customers as they continue to experience lower demand for their products and services, or are not operating at full capacity. The extent to which the pandemic related decrease in consumption will continue to impact our results of operations and liquidity is dependent upon the duration of the COVID-19 pandemic and the ability of our customers to continue, or to resume, normal operations.

Employee Safety

The health and safety of our employees during the COVID-19 pandemic is paramount and enables us to continue to provide critical services to our customers.

We are taking into consideration CDC guidelines and have taken precautions with regard to employee hygiene and facility cleanliness, imposed travel limitations on our employees, provided additional employee benefits, and implemented remote-work policies where appropriate. We have an incident management team and updated our pandemic continuity plan, which includes identifying critical work groups and ensuring safe-harbor plans are in place. We have minimized the unnecessary risk of exposure to COVID-19 by implementing self-quarantine measures and have adopted additional precautionary measures for our critical work groups.

Additional protocols have been implemented for our field employees who travel to customer premises in order to protect them, our customers, and the public. We have modified our work protocols to ensure compliance with social distancing and face covering recommendations. We are developing return-to-the workplace strategies for those employees currently working remotely, taking into consideration factors such as any updated CDC guidelines, new variants, any increases in COVID-19 cases in our service territories, and the overall level of risk to our employees and customers.

All of these safety measures have caused us to incur additional costs, and depending upon the duration of the COVID-19 pandemic, could have a material impact on our results of operations and liquidity.

We continue to provide our employees with educational information regarding the COVID-19 vaccine and are providing incentives and imposing surcharges on our medical plan to encourage employees to obtain the vaccine. Enforcement of these surcharges and precautionary measures may adversely impact our operations, including possible labor disruptions, employee attrition, and a reduced ability to replace departing employees.

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Competitive Markets

Electric Utility Industry

The FERC supports large RTOs, which directly impacts the structure of the wholesale electric market. Due to the FERC's support of RTOs, MISO uses the MISO Energy Markets to carry out its operations, including the use of LMP to value electric transmission congestion and losses. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant and adverse financial impact on us.

Electric utility revenues in Wisconsin are regulated by the PSCW. The PSCW continues to maintain the position that the question of whether to implement electric retail competition in Wisconsin should ultimately be decided by the Wisconsin legislature. No such legislation has been introduced in Wisconsin to date. It is uncertain when, if at all, retail choice might be implemented in Wisconsin.

Natural Gas Utility Industry

We offer both natural gas transportation service and interruptible natural gas sales to enable customers to better manage their energy costs. Customers continue to switch between firm system supply, interruptible system supply, and transportation service each year as the economics and service options change.

Due to the PSCW's previous proceedings on natural gas industry regulation in a competitive environment, the PSCW currently provides all Wisconsin customer classes with competitive markets the option to choose a third-party natural gas supplier. All of our Wisconsin non-residential customer classes have competitive market choices and, therefore, can purchase natural gas directly from either a third-party supplier or us. Since third-party suppliers can be used in Wisconsin, the PSCW has also adopted standards for transactions between a utility and its natural gas marketing affiliates.

We offer natural gas transportation services to our customers that elect to purchase natural gas directly from a third-party supplier. Since these transportation customers continue to use our distribution systems to transport natural gas to their facilities, we earn distribution revenues from them. As such, the loss of revenue associated with the cost of natural gas that our transportation customers purchase from third-party suppliers has little impact on our net income, as it is substantially offset by an equal reduction to natural gas costs.

We are currently unable to predict the impact, if any, of potential future industry restructuring on our results of operations or financial position.

Regulatory, Legislative, and Legal Matters

Regulatory Recovery

We account for our regulated operations in accordance with accounting guidance under the Regulated Operations Topic of the FASB ASC. Our rates are determined by the PSCW and the FERC. See Item 1. Business – D. Regulation for more information on these commissions. See Note 23, Regulatory Environment, for additional information regarding recent rate proceedings and orders.

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 our regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of the deferred costs 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 December 31, 2021, our regulatory assets were $347.9 million, and our regulatory liabilities were $743.9 million.

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,

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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 cannot currently predict what, if any, impact this supply disruption will have on our future solar projects included in WEC Energy Group's capital plan.

United States Department of Commerce Complaint

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 claim 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.

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 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.

Environmental Matters

See Note 21, 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, described in further detail below, include but are not limited to:

Commodity Costs

In the normal course of providing energy, we are subject to market fluctuations in the costs of coal, natural gas, purchased power, and fuel oil used in the delivery of coal. We manage our fuel and natural gas supply costs through a portfolio of short and long-term procurement contracts with various suppliers for the purchase of coal, natural gas, and fuel oil. In addition, we manage the risk of price volatility through natural gas and electric hedging programs.

Embedded within our rates are amounts to recover fuel, natural gas, and purchased power costs. We have recovery mechanisms in place that allow us to recover or refund all or a portion of the changes in prudently incurred fuel, natural gas, and purchased power costs from rate case-approved amounts. See Item 1. Business – D. Regulation for more information on these mechanisms.

Higher commodity costs can increase our working capital requirements, result in higher gross receipts taxes, and lead to increased energy efficiency investments by our customers to reduce utility usage and/or fuel substitution. Higher commodity costs combined with slower economic conditions also expose us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills. See Note 5, Credit Losses, for more information on our mechanism that allows for cost recovery or refund of uncollectible expense.

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Weather

Our utility rates are based upon estimated normal temperatures. Our electric utility margins are unfavorably sensitive to below normal temperatures during the summer cooling season and, to some extent, to above normal temperatures during the winter heating season. Our natural gas utility margins are unfavorably sensitive to above normal temperatures during the winter heating season. The fixed charge included in our natural gas rates helps to mitigate the impacts of weather. A summary of actual weather information in our service territory during 2021 and 2020, as measured by degree days, may be found in Results of Operations.

Interest Rates

We are exposed to interest rate risk resulting from our short-term borrowings and projected near-term debt financing needs. We manage exposure to interest rate risk by limiting the amount of our variable rate obligations and continually monitoring the effects of market changes on interest rates. When it is advantageous to do so, we enter into long-term fixed rate debt.

Based on our variable rate debt outstanding at December 31, 2021 and 2020, a hypothetical increase in market interest rates of one percentage point would have increased annual interest expense by $3.3 million and $2.1 million in 2021 and 2020, respectively. This sensitivity analysis was performed assuming a constant level of variable rate debt during the period and an immediate increase in interest rates, with no other changes for the remainder of the period.

Marketable Securities Return

We use various trusts to fund our pension and OPEB obligations. These trusts invest in debt and equity securities. Changes in the market prices of these assets can affect future pension and OPEB expenses. Additionally, future contributions can also be affected by the investment returns on trust fund assets. We believe that the financial risks associated with investment returns would be partially mitigated through future rate actions by the PSCW.

The fair value of our trust fund assets and expected long-term returns were approximately:

(in millions)	As of December 31, 2021		Expected Return on Assets in 2022
Pension trust funds	$	859.4	7.00	%
OPEB trust funds	$	303.6	7.00	%

Fiduciary oversight of the pension and OPEB trust fund investments is the responsibility of an Investment Trust Policy Committee. The Committee works with external actuaries and investment consultants on an ongoing basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target asset allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. The targeted asset allocations are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments. Investment strategies utilize a wide diversification of asset types and qualified external investment managers.

WEC Energy Group consults with its investment advisors on an annual basis to help it forecast expected long-term returns on plan assets by reviewing actual historical returns and calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the funds.

Economic Conditions

Our service territories are within the state of Wisconsin. As such, we are exposed to market risks in the regional Midwest economy. In addition, any economic downturn or disruption of national or international markets could adversely affect the financial condition of our customers and demand for their products, which could affect their demand for our products.

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

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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 WEC Energy Group's capital plan, which includes us. For additional information concerning risks related to inflation and supply chain disruptions, see 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.

For additional information concerning risk factors, including market risks, see the Cautionary Statement Regarding Forward-Looking Information at the beginning of this report and Item 1A. Risk Factors.

Critical Accounting Policies and Estimates

The preparation of financial statements in compliance with GAAP requires the application of accounting policies, as well as the use of estimates, assumptions, and judgements that could have a material impact on our financial statements and related disclosures. Judgments regarding future events may include the likelihood of success of particular projects, legal and regulatory challenges, and anticipated recovery of costs. Actual results may differ significantly from estimated amounts based on varying assumptions.

Our significant accounting policies are described in Note 1, Summary of Significant Accounting Policies. The following is a list of accounting policies and estimates that require management's most difficult, subjective, or complex judgments and may change in subsequent periods.

Regulatory Accounting

Our utility operations follow the guidance under the Regulated Operations Topic of the FASB ASC (Topic 980). Our financial statements reflect the effects of the rate-making principles followed by the jurisdictions regulating us. Certain items that would otherwise be immediately recognized as revenues and expenses are deferred as regulatory assets and regulatory liabilities for future recovery or refund to customers, as authorized by our regulators.

Future recovery of regulatory assets, including the timeliness of recovery and our ability to earn a reasonable return, is not assured and is generally subject to review by regulators in rate proceedings for matters such as prudence and reasonableness. Once approved, the regulatory assets and liabilities are amortized into earnings over the rate recovery or refund period. If recovery or refund of costs is not approved or is no longer considered probable, these regulatory assets or liabilities are recognized in current period earnings. Management regularly assesses whether these regulatory assets and liabilities are probable of future recovery or refund by considering factors such as changes in the regulatory environment, earnings from our electric and natural gas utility operations, rate orders issued by our regulators, historical decisions by our regulators regarding regulatory assets and liabilities, and the status of any pending or potential deregulation legislation.

The application of the Regulated Operations Topic of the FASB ASC would be discontinued if all or a separable portion of our utility operations no longer met the criteria for application. Our regulatory assets and liabilities would be written off to income as an unusual or infrequently occurring item in the period in which discontinuation occurred. As of December 31, 2021, we had $347.9 million in regulatory assets and $743.9 million in regulatory liabilities. See Note 6, Regulatory Assets and Liabilities, for more information.

Goodwill

We completed our annual goodwill impairment test for our utility reporting unit as of July 1, 2021. No impairment was recorded as a result of this test. At July 1, 2021, our utility reporting unit had $36.4 million of goodwill. The fair value calculated in step one of the test was greater than its carrying value. The fair value of our reporting unit was calculated using a combination of the income approach and the market approach.

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

Key assumptions used in the income approach included ROE, the long-term growth rate used to determine the terminal value at the end of the discrete forecast period, and the discount rate. The discount rate is applied to estimated future cash flows and is one of

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the most significant assumptions used to determine fair value under the income approach. As interest rates rise, the calculated fair value will decrease. The discount rate is based on the weighted-average cost of capital, taking into account both the after-tax cost of debt and cost of equity. The terminal year ROE is driven by our current allowed ROE. The terminal growth rate is based primarily on a combination of historical and forecasted statistics for real gross domestic product and personal income for our service area.

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

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

The fair value of our reporting unit exceeded its carrying value by over 50%. Based on this result, our reporting unit is not at risk of failing step one of the goodwill impairment test.

See Note 10, Goodwill, for more information.

Long-Lived Assets

In accordance with ASC 980-360, Regulated Operations – Property, Plant, and Equipment, we periodically assess the recoverability of certain long-lived assets when events or changes in circumstances indicate that the carrying amount of those long-lived assets may not be recoverable. Examples of events or changes in circumstances include, but are not limited to, a significant decrease in the market price, a significant change in use, a regulatory decision related to recovery of assets from customers, adverse legal factors or a change in business climate, operating or cash flow losses, or an expectation that the asset might be sold or abandoned. See Note 1(j), Asset Impairment, for our policy on accounting for abandonments.

Performing an impairment evaluation involves a significant degree of estimation and judgement by management in areas such as identifying circumstances that indicate an impairment may exist, identifying and grouping affected assets, and developing the undiscounted future cash flows. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset. The fair value of the asset is assessed using various methods, including internally developed discounted cash flow analysis, expected recovery of regulated assets, and analysis from outside advisors.

See Note 7, Property, Plant, and Equipment, for more information on our generating units probable of being retired. See Note 6, Regulatory Assets and Liabilities, and Note 23, Regulatory Environment, for more information on our retired generating units, including various approvals we received from the FERC and the PSCW.

Pension and Other Postretirement Employee Benefits

The costs of providing non-contributory defined pension benefits and OPEB, described in Note 19, Employee Benefits, are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.

Pension and OPEB costs are impacted by actual employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans, and earnings on plan assets. Pension and OPEB costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, mortality and discount rates, and expected health care cost trends. Changes made to the plan provisions may also impact current and future pension and OPEB costs.

Pension and OPEB plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity and fixed income market returns, as well as changes in general interest rates, may result in increased or decreased benefit costs in future periods. We believe that such changes in costs would be recovered or refunded through the rate-making process.

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The following table shows how a given change in certain actuarial assumptions would impact the projected benefit obligation and the reported net periodic pension cost. Each factor below reflects an evaluation of the change based on a change in that assumption only.

Actuarial Assumption (in millions, except percentages)	Percentage-Point Change in Assumption	Impact on Projected Benefit Obligation		Impact on 2021 Pension Cost
Discount rate	(0.5)	$	59.1	$	6.1
Discount rate	0.5	(51.0)		(5.2)
Rate of return on plan assets	(0.5)	N/A		3.7
Rate of return on plan assets	0.5	N/A		(3.7)

The following table shows how a given change in certain actuarial assumptions would impact the accumulated OPEB obligation and the reported net periodic OPEB cost. Each factor below reflects an evaluation of the change based on a change in that assumption only.

Actuarial Assumption (in millions, except percentages)	Percentage-Point Change in Assumption	Impact on Postretirement Benefit Obligation		Impact on 2021 Postretirement Benefit Cost
Discount rate	(0.5)	$	9.8	$	0.7
Discount rate	0.5	(8.5)		(0.7)
Health care cost trend rate	(0.5)	(6.9)		(0.9)
Health care cost trend rate	0.5	8.0		1.0
Rate of return on plan assets	(0.5)	N/A		1.5
Rate of return on plan assets	0.5	N/A		(1.5)

The discount rates are selected based on hypothetical bond portfolios consisting of noncallable, high-quality corporate bonds across the full maturity spectrum. From the hypothetical bond portfolios, a single rate is determined that equates the market value of the bonds purchased to the discounted value of the plans' expected future benefit payments.

We establish our expected return on assets based on consideration of historical and projected asset class returns, as well as the target allocations of the benefit trust portfolios. The assumed long-term rate of return on pension plan assets was 7.00% in 2021 and 2020, and 7.25% in 2019. The actual rate of return on pension plan assets, net of fees, was 10.19%, 14.63%, and 22.22% in 2021, 2020, and 2019, respectively.

In selecting assumed health care cost trend rates, past performance and forecasts of health care costs are considered. For more information on health care cost trend rates and a table showing future payments that we expect to make for our pension and OPEB, see Note 19, Employee Benefits.

Unbilled Revenues

We record utility operating revenues when energy is delivered to our customers. However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated.

Unbilled revenues are estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses, and applicable customer rates. Energy demand for the unbilled period or changes in rate mix due to fluctuations in usage patterns of customer classes could impact the accuracy of the unbilled revenue estimate. Total unbilled utility revenues were $73.0 million and $63.7 million as of December 31, 2021 and 2020, respectively. The changes in unbilled revenues are primarily due to changes in the cost of natural gas, weather, and customer rates.

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Income Tax Expense

Significant management judgment is required in determining our provision for income taxes, deferred income tax assets and liabilities, the liability for unrecognized tax benefits, and any valuation allowance recorded against deferred income tax assets. The assumptions involved are supported by historical data, reasonable projections, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. Significant changes in these assumptions could have a material impact on our financial condition and results of operations. See Note 1(n), Income Taxes, and Note 16, Income Taxes, for a discussion of accounting for income taxes.

We are required to estimate income taxes for each of our applicable tax jurisdictions as part of the process of preparing financial statements. This process involves estimating current income tax liabilities together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for income tax and accounting purposes. These differences result in deferred income tax assets and liabilities, which are included within our balance sheets. We also assess the likelihood that our deferred income tax assets will be recovered through future taxable income. To the extent we believe that realization is not likely, we establish a valuation allowance, which is offset by an adjustment to income tax expense in our income statements.

Uncertainty associated with the application of tax statutes and regulations, the outcomes of tax audits and appeals, changes in income tax law, enacted tax rates or amounts subject to income tax, and changes in the regulatory treatment of any tax reform benefits requires that judgments and estimates be made in the accrual process and in the calculation of effective tax rates. Only income tax benefits that meet the "more likely than not" recognition threshold may be recognized or continue to be recognized. Unrecognized tax benefits are re-evaluated quarterly and changes are recorded based on new information, including the issuance of relevant guidance by the courts or tax authorities and developments occurring in the examinations of our tax returns.

We expect our 2022 annual effective tax rate to be between 23% and 24%. 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.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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, as well as Note 1(o), Fair Value Measurements, Note 1(p), Derivative Instruments, and Note 1(q), Guarantees, for information concerning potential market risks to which we are exposed.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

A. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholder and the Board of Directors of Wisconsin Public Service Corporation

Opinion on the Financial Statements

We have audited the accompanying balance sheets of Wisconsin Public Service Corporation (the "Company") as of December 31, 2021 and 2020, the related statements of income, equity, and cash flows for each of the three years in the period ended December 31, 2021, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Regulatory Assets and Liabilities - Impact of rate regulation on financial statements — Refer to Notes 6 and 23 to the financial statements

Critical Audit Matter Description

The Company is subject to regulation by state and federal regulatory bodies (collectively the “Commissions”) which have jurisdiction with respect to the rates of electric and gas distribution. Management has determined the Company meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the Regulated Operations Topic of the Financial Accounting Standards Board’s Accounting Standard Codification.

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Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in the utility business. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. The Commissions’ regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Certain items that would otherwise be immediately recognized as revenues and expenses are deferred as regulatory assets and regulatory liabilities for future recovery or refund to customers, as authorized by the Company’s regulators. Future decisions of the Commissions will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates, and any refunds that may be required.

While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service, (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment or (3) timely recovery of costs incurred. The Company had $347.9 million and $743.9 million of regulatory assets and liabilities, respectively, as of December 31, 2021.

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Given that management’s accounting judgments can be based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due its inherent complexities.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the Commissions included the following procedures, among others:

•We tested the effectiveness of management’s controls over regulatory assets and liabilities, including management’s controls over the identification of costs recorded as regulatory assets and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates.

•We inquired of Company management and independently obtained and read: (1) relevant regulatory orders issued by the state and federal Commissions for the Company and other public utilities, (2) company filings, (3) filings made by intervenors and (4) other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. To assess completeness, we evaluated the information obtained and compared it to management’s recorded regulatory asset and liability balances.

•For regulatory matters in process, we inspected the Company’s filings with the Commissions and the filings with the Commissions by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.

•We obtained management’s analysis regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

/s/ DELOITTE & TOUCHE LLP

Milwaukee, Wisconsin

February 24, 2022

We have served as the Company's auditor since 2002.

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B. INCOME STATEMENTS

Year Ended December 31
(in millions)	2021		2020		2019
Operating revenues	$	1,520.9	$	1,407.1	$	1,411.9
Operating expenses
Cost of sales	597.2		458.3		540.6
Other operation and maintenance	406.4		426.3		396.2
Depreciation and amortization	188.6		174.3		166.2
Property and revenue taxes	39.9		40.0		41.3
Total operating expenses	1,232.1		1,098.9		1,144.3
Operating income	288.8		308.2		267.6
Other income, net	38.2		31.4		39.6
Interest expense	64.7		63.5		63.4
Other expense	(26.5)		(32.1)		(23.8)
Income before income taxes	262.3		276.1		243.8
Income tax expense	31.2		54.5		59.1
Net income	$	231.1	$	221.6	$	184.7

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

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C. BALANCE SHEETS

At December 31
(in millions, except share and per share amounts)	2021		2020
Assets
Current assets
Cash and cash equivalents	$	2.4	$	2.7
Accounts receivable and unbilled revenues, net of reserves of $11.1 and $18.3, respectively	226.6		190.8
Accounts receivable from related parties	26.1		27.6
Materials, supplies, and inventories	112.9		92.7
Prepaid taxes	40.0		39.0
Derivative assets	22.2		3.1
Other	12.3		9.1
Current assets	442.5		365.0
Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $1,808.4 and $1,750.7, respectively	5,098.6		4,885.9
Regulatory assets	347.9		449.4
Goodwill	36.4		36.4
Pension and OPEB assets	260.7		159.2
Other	49.6		38.0
Long-term assets	5,793.2		5,568.9
Total assets	$	6,235.7	$	5,933.9
Liabilities and Equity
Current liabilities
Short-term debt	$	331.0	$	210.5
Current portion of long-term debt	—		400.0
Accounts payable	130.8		129.6
Accounts payable to related parties	42.6		48.8
Other	81.4		81.0
Current liabilities	585.8		869.9
Long-term liabilities
Long-term debt	1,690.6		1,244.8
Deferred income taxes	782.2		682.7
Deferred ITCs	74.8		41.3
Regulatory liabilities	735.5		772.6
Environmental remediation liabilities	95.0		88.3
Other	128.8		117.6
Long-term liabilities	3,506.9		2,947.3
Commitments and contingencies (Note 21)
Common shareholder's equity
Common stock – $4 par value; 32,000,000 shares authorized; 23,896,962 shares issued and outstanding	95.6		95.6
Additional paid in capital	1,491.5		1,436.4
Retained earnings	555.9		584.7
Common shareholder's equity	2,143.0		2,116.7
Total liabilities and equity	$	6,235.7	$	5,933.9

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

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D. STATEMENTS OF CASH FLOWS

Year Ended December 31
(in millions)	2021		2020		2019
Operating activities
Net income	$	231.1	$	221.6	$	184.7
Reconciliation to cash provided by operating activities
Depreciation and amortization	188.6		174.3		166.2
Deferred income taxes and ITCs, net	84.6		40.4		125.2
Change in –
Accounts receivable and unbilled revenues, net	(24.5)		32.2		(8.1)
Materials, supplies, and inventories	(20.2)		13.7		(3.4)
Prepaid taxes	(1.0)		24.4		(22.0)
Other current assets	(3.3)		0.2		(4.0)
Accounts payable	3.2		(47.3)		22.3
Other current liabilities	0.9		(0.2)		0.7
Other, net	(21.1)		(5.9)		(40.5)
Net cash provided by operating activities	438.3		453.4		421.1
Investing activities
Capital expenditures	(389.7)		(530.7)		(517.8)
Proceeds from cash surrender value of life insurance	—		7.1		6.6
Other, net	(8.0)		(3.4)		(4.7)
Net cash used in investing activities	(397.7)		(527.0)		(515.9)
Financing activities
Retirement of long-term debt	(400.0)		—		—
Issuance of long-term debt	450.0		—		300.0
Change in short-term debt	120.5		119.0		(192.9)
Payment of dividends to parent	(260.0)		(260.0)		(120.0)
Equity contribution from parent	55.0		215.0		105.0
Other, net	(6.4)		—		(3.9)
Net cash provided by (used in) financing activities	(40.9)		74.0		88.2
Net change in cash and cash equivalents	(0.3)		0.4		(6.6)
Cash and cash equivalents at beginning of year	2.7		2.3		8.9
Cash and cash equivalents at end of year	$	2.4	$	2.7	$	2.3

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

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E. STATEMENTS OF EQUITY

(in millions)	Common Stock		Additional Paid-In Capital		Retained Earnings		Total Common Shareholder's Equity
Balance at December 31, 2018	$	95.6	$	1,115.9	$	558.4	$	1,769.9
Net income	—		—		184.7		184.7
Equity contribution from parent	—		105.0		—		105.0
Payment of dividends to parent	—		—		(120.0)		(120.0)
Stock-based compensation and other	—		0.2		—		0.2
Balance at December 31, 2019	$	95.6	$	1,221.1	$	623.1	$	1,939.8
Net income	—		—		221.6		221.6
Equity contribution from parent	—		215.0		—		215.0
Payment of dividends to parent	—		—		(260.0)		(260.0)
Stock-based compensation and other	—		0.3		—		0.3
Balance at December 31, 2020	$	95.6	$	1,436.4	$	584.7	$	2,116.7
Net income	—		—		231.1		231.1
Equity contribution from parent	—		55.0		—		55.0
Payment of dividends to parent	—		—		(260.0)		(260.0)
Stock-based compensation and other	—		0.1		0.1		0.2
Balance at December 31, 2021	$	95.6	$	1,491.5	$	555.9	$	2,143.0

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

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F. NOTES TO FINANCIAL STATEMENTS

NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) Nature of Operations—We are an electric and natural gas utility company that serves electric and natural gas customers in northeastern Wisconsin. We are subject to the jurisdiction of, and regulation by, the PSCW, which has general supervisory and regulatory powers over virtually all phases of the public utility industry in Wisconsin. In addition, we are subject to the jurisdiction of the FERC, which regulates our natural gas pipelines and wholesale electric rates. We are an indirect, wholly owned subsidiary of WEC Energy Group.

As used in these notes, the term "financial statements" includes the income statements, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted.

These financial statements reflect our proportionate interests in certain jointly owned utility facilities. See Note 8, Jointly Owned Utility Facilities, for more information. Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method.

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

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

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

Revenues from Contracts with Customers

Electric Utility Operating Revenues

Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity.

The transaction price of the performance obligations for residential and commercial and industrial customers is valued using the rates, charges, terms, and conditions of service included in our tariffs, which have been approved by the PSCW. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month. Our retail electric rates in Wisconsin include base amounts for fuel and purchased power costs, which also impact our revenues. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under- or over-collections of actual fuel and purchased power costs beyond a 2% price variance from the costs included in the rates charged to customers. We monitor the deferral of under-collected costs to ensure that it does not cause us to earn a greater ROE than authorized by the PSCW. In addition, our residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. See Note 23, Regulatory Environment, for more information on how COVID-19 has affected our cost recovery mechanism.

Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have us provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at

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the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric operations and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis.

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

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

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

Natural Gas Utility Operating Revenues

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

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

Our tariffs include various rate mechanisms that allow us to recover or refund changes in prudently incurred costs from rate case-approved amounts. Our rates include a one-for-one recovery mechanism for natural gas commodity costs. Under normal circumstances, we defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year. However, as a result of the extreme weather in the Midwest in February 2021, the cost of gas purchased for our natural gas customers was temporarily driven significantly higher than our normal winter weather expectations. See Note 23, Regulatory Environment, for more information on the recovery of these high natural gas costs.

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In addition, our residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. See Note 23, Regulatory Environment, for more information on how COVID-19 has affected our cost recovery mechanism.

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

Other Operating Revenues

Alternative Revenues

Alternative revenues are created from programs authorized by regulators that allow us to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers.

Our only alternative revenue program relates to the wholesale electric service that we provide to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.

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

Effective January 1, 2020, we adopted FASB ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, using the modified retrospective transition method. This ASU amends the impairment model to utilize an expected loss methodology in place of the incurred loss methodology for financial instruments, including trade receivables. The amendment requires entities to consider a broader range of information to estimate expected credit losses, which may result in earlier recognition of loss. The cumulative effect of adopting this standard was not significant to our financial statements.

Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are generated from the sale of electricity and natural gas by our regulated utility operations. Our regulated utility operations are included in our utility segment. No accounts receivable and unbilled revenue balances were reported in the other segment at December 31, 2021 and 2020.

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 the PSCW, 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. See Note 23, Regulatory Environment, for information on certain regulatory actions that were and/or are being taken for the purpose of ensuring that essential utility services are available to our customers during the COVID-19 pandemic.

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

(in millions)	2021		2020
Materials and supplies	$	50.5	$	45.8
Natural gas in storage	33.5		18.9
Fossil fuel	28.9		28.0
Total	$	112.9	$	92.7

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

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

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

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

We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the PSCW that include estimates for salvage value and removal costs. Annual utility composite depreciation rates were 2.66%, 2.63%, and 2.44% in 2021, 2020, and 2019, respectively.

We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 5 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement.

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

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

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

Approximately 50% of our retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. Our average AFUDC retail rates were 7.55% for 2021 and 2020, and 7.72% for 2019. Our average AFUDC wholesale rates were 1.04%, 5.59%, and 2.58% for 2021, 2020, and 2019, respectively.

We recorded the following AFUDC for the years ended December 31:

(in millions)	2021		2020		2019
AFUDC – Debt	$	3.5	$	4.6	$	2.4
AFUDC – Equity	9.0		11.8		5.7

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(j) Asset Impairment—Goodwill is subject to an annual impairment test. Interim impairment tests are performed when impairment indicators are present. During the third quarter of each year, we perform an annual goodwill impairment test. The carrying amount of our goodwill is considered not recoverable if the carrying amount of our net assets exceeds our fair value. An impairment loss is recorded for the excess of the carrying amount of the goodwill over its implied fair value. See Note 10, Goodwill, for more information.

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

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

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

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

(l) Stock-Based Compensation—Our employees participate in the WEC Energy Group stock-based compensation plans. In accordance with the Omnibus Stock Incentive Plan, WEC Energy Group provides long-term incentives through its equity interests to its non-employee directors, officers, and other key employees. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in WEC Energy Group common stock, cash, or a combination thereof. In addition to those shares of WEC Energy Group common stock that are subject to awards outstanding as of May 6, 2021, 9.0 million shares of WEC Energy Group common stock are reserved for issuance under the plan.

Stock-based compensation expense is allocated to us based on the outstanding awards held by our employees and our allocation of labor costs. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period. We account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period.

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Stock Options

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

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

	2021			2020			2019
Stock options granted	18,021			22,042			21,638
Estimated weighted-average fair value per stock option	$	13.20		$	10.82		$	8.60
Assumptions used to value the options:
Risk-free interest rate	0.1% – 0.9%			1.6% – 1.9%			2.5% – 2.7%
Dividend yield	2.9		%	3.0		%	3.6		%
Expected volatility	21.0		%	16.0		%	17.0		%
Expected life (years)	8.7			8.6			8.5

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

Restricted Shares

WEC Energy Group restricted shares granted to our employees have a vesting period of three years with one-third of the award vesting on each anniversary of the grant date. The restricted shares are classified as equity awards.

Performance Units

Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. Under the plan, the ultimate number of units that will be awarded is dependent on WEC Energy Group's total shareholder return (stock price appreciation plus dividends) as compared to the total shareholder return of a peer group of companies over three years, as well as other performance metrics as may be determined by the Compensation Committee. Participants may earn between 0% and 175% of the performance unit award based on WEC Energy Group's total shareholder return. Pursuant to the terms of the plan, these percentages can be adjusted upwards or downwards by up to 10% based on WEC Energy Group's performance against additional performance measures, if any, adopted by the Compensation Committee. Performance units also accrue forfeitable dividend equivalents in the form of additional performance units.

All grants of performance units are settled in cash and are accounted for as liability awards accordingly. The fair value of the performance units reflects our estimate of the final expected value of the awards, which is based on WEC Energy Group's stock price and performance achievement under the terms of the award. Stock-based compensation costs are generally recorded over the performance period, which is three years.

See Note 11, Common Equity, for more information on WEC Energy Group's stock-based compensation plans.

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

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Significant Judgments and Other Information

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

See Note 15, Leases, for more information.

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

ITCs associated with regulated operations are deferred and amortized over the life of the assets. PTCs are recognized in the period in which such credits are generated. We are included in WEC Energy Group's consolidated federal and state income tax returns. In accordance with our tax allocation agreement with WEC Energy Group, we are allocated income tax payments and refunds based upon the benefit for loss method, where attributes are realized when WEC Energy Group is able to realize them. See Note 16, Income Taxes, for more information.

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

(o) Fair Value Measurements—Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).

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

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

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

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

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

When possible, we base the valuations of our derivative 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.

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

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

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

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

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

liabilities. See Note 18, Derivative Instruments, for more information.

(q) Guarantees—We follow the guidance of the Guarantees Topic of the FASB ASC, which requires, under certain circumstances, that the guarantor recognize a liability for the fair value of the obligation undertaken in issuing the guarantee at its inception. As of December 31, 2021, we had $20.6 million of standby letters of credit issued by financial institutions for the benefit of third parties that have extended credit to us, which automatically renew each year unless proper termination notice is given. These amounts are not reflected on our balance sheets.

(r) Employee Benefits—The costs of pension and OPEB plans are expensed over the periods during which employees render service. These costs are distributed among WEC Energy Group's subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for our net periodic benefit cost calculated under GAAP. See Note 19, Employee Benefits, for more information.

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

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

(t) Environmental Remediation Costs—We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including coal combustion residual landfills and manufactured gas plant sites. See Note 9, Asset Retirement Obligations, for more information regarding coal combustion residual landfills and Note 21, Commitments and Contingencies, for more information regarding manufactured gas plant sites.

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

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

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

(u) Customer Concentrations of Credit Risk—The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Our credit risk exposure is mitigated by our recovery mechanism for uncollectible expense discussed in Note 1(d), Operating Revenues. As a result, we did not have any significant concentrations of credit risk at December 31, 2021. In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2021.

NOTE 2—ACQUISITION

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.

Acquisition of Electric Generation Facility in Wisconsin

In November 2021, we, along with WE, 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. WE currently purchases all of the capacity from this generation facility pursuant to a PPA. In December 2021, we, along with WE, filed an application with the PSCW for approval to acquire Whitewater. If approved, our share of the cost of this facility is estimated to be $36.3 million for 50% of the capacity. The transaction is expected to close in January 2023.

NOTE 3—RELATED PARTIES

We routinely enter into transactions with related parties, including WEC Energy Group, its other subsidiaries, ATC, and other affiliated entities.

We provide and receive services, property, and other items of value to and from our ultimate parent, WEC Energy Group, and other subsidiaries of WEC Energy Group pursuant to an AIA that became effective in 2017. The AIA was approved by the appropriate regulators, including the PSCW. In accordance with the AIA, WBS provides several categories of services to us (including financial, human resource, and administrative services).

We provide services to WRPC under an operating agreement approved by the PSCW. We are also under a service agreement with WRPC where we are billed for services provided by WRPC. Services are billed to and from WRPC under these agreements at a fully allocated cost.

We pay ATC for 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. Services are billed to and from ATC under agreements approved by the PSCW, at each of our fully allocated costs. 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.

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

(in millions)	December 31, 2021		December 31, 2020
Accounts receivable
Services provided to ATC	$	0.9	$	2.4
Amounts due from ATC for transmission infrastructure upgrades (1)	8.4		3.0
Accounts payable
Services received from ATC	8.9		9.0

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(1)    The transmission infrastructure upgrades primarily related to the construction of our new solar project, Badger Hollow I.

The following table shows activity associated with our related party transactions for the years ended December 31:

(in millions)	2021			2020		2019
Transactions with WE
Natural gas related sales to WE (1)	$	2.9		$	1.5	$	2.0
Charges to WE for services and other items (2)	9.4			8.3		9.3
Charges from WE for services and other items (2)	11.8			12.5		13.2
Transactions with UMERC
Electric sales to UMERC (3)	—			—		4.5
Natural gas related sales to UMERC (1)	2.6			2.0		2.8
Charges to UMERC for services and other items (2)	3.1			4.4		4.2
Transactions with Bluewater
Storage service fees	10.3			10.6		11.2
Natural gas related sales to Bluewater (1)	1.9			1.9		1.1
Transactions with WBS
Charges to WBS for services and other items (2)	15.4			22.2		32.5
Charges from WBS for services and other items (2)	67.4		(5)	69.0		87.0
Transactions related to ATC
Charges to ATC for services and construction	8.0			11.9		11.0
Charges from ATC for network transmission services	107.0			107.4		107.8
Net refund from ATC related to FERC ROE orders	2.3			3.3		—
Transactions with WRPC
Rental payments to WRPC (4)	1.9			1.9		1.9
Charges from WRPC for services	2.4			2.6		2.5
Charges to WRPC for operations	0.6			1.2		0.8

(1)    Includes amounts related to the sale of natural gas and/or pipeline capacity.

(2)    Includes amounts charged for services, pass through costs, asset and liability transfers, and other items in accordance with the approved AIA. As required by FERC regulations for centralized service companies, WBS renders services at cost. Services provided by any regulated subsidiary to another regulated subsidiary or WBS are priced at cost.

(3)    On March 31, 2019, UMERC's natural gas-fired generation in the Upper Peninsula of Michigan began commercial operation. Prior to its generating units achieving commercial operation, UMERC purchased a portion of its power from us.

(4)    We have an agreement with WRPC whereby we receive 50% of the energy generated from its hydroelectric power generation facilities.

(5)    Includes $5.4 million for the transfer of certain software assets from WBS.

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NOTE 4—OPERATING REVENUES

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

Disaggregation of Operating Revenues

The following tables present our operating revenues disaggregated by revenue source for our utility segment. We do not have any revenues associated with our other segment. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors. 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.

	Year Ended December 31
(in millions)	2021		2020		2019
Wisconsin Public Service Corporation
Electric utility	$	1,176.7	$	1,136.9	$	1,114.1
Natural gas utility	338.8		269.5		295.5
Total revenues from contracts with customers	1,515.5		1,406.4		1,409.6
Other operating revenues	5.4		0.7		2.3
Total operating revenues	$	1,520.9	$	1,407.1	$	1,411.9

Revenues from Contracts with Customers

Electric Utility Operating Revenues

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

	Year Ended December 31
(in millions)	2021		2020		2019
Residential	$	423.5	$	420.0	$	369.4
Small commercial and industrial	376.2		353.6		355.9
Large commercial and industrial	256.6		220.0		223.3
Other	8.4		8.4		8.4
Total retail revenues	1,064.7		1,002.0		957.0
Wholesale	86.7		95.1		105.8
Resale	11.4		19.6		28.7
Other utility revenues	13.9		20.2		22.6
Total electric utility operating revenues	$	1,176.7	$	1,136.9	$	1,114.1

Natural Gas Utility Operating Revenues

The following table disaggregates natural gas utility operating revenues into customer class:

	Year Ended December 31
(in millions)	2021		2020		2019
Residential	$	202.0	$	156.4	$	178.4
Commercial and industrial	122.0		83.9		105.9
Total retail revenues	324.0		240.3		284.3
Transportation	19.4		19.6		17.1
Other utility revenues (1)	(4.6)		9.6		(5.9)
Total natural gas utility operating revenues	$	338.8	$	269.5	$	295.5

(1)    Includes the revenues subject to our purchased gas recovery mechanism. As these amounts are billed to customers, they are reflected in retail revenues with an offsetting decrease in other utility revenues.

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Other Operating Revenues

Other operating revenues consist of the following:

	Year Ended December 31
(in millions)	2021		2020		2019
Late payment charges (1)	$	3.9	$	2.0	$	3.2
Alternative revenues (2)	1.4		(1.4)		(1.1)
Rental revenues	0.1		0.1		0.2
Total other operating revenues	$	5.4	$	0.7	$	2.3

(1)    The increase in late payment charges during 2021, compared with 2020, was a result of the expiration of a regulatory order from the PSCW in response to the COVID-19 pandemic, which included the suspension of late payment charges during a designated time period. See Note 23, Regulatory Environment, for more information.

(2)    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 wholesale customers subject to true-ups, as discussed in Note 1(d), Operating Revenues.

NOTE 5—CREDIT LOSSES

The table below shows our gross third-party receivable balances and related allowance for credit losses.

(in millions)	December 31, 2021			December 31, 2020
Accounts receivable and unbilled revenues	$	237.7		$	209.1
Allowance for credit losses	11.1			18.3
Accounts receivable and unbilled revenues, net (1)	$	226.6		$	190.8
Total accounts receivable, net – past due greater than 90 days (1)	$	8.0		$	12.6
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	97.3		%	94.4		%

(1)    Our exposure to credit losses for certain regulated utility customers is mitigated by a regulatory mechanism we have in place. Specifically, our residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. As a result, at December 31, 2021, $97.7 million, or 43.1%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. In addition, we have received specific orders related to the deferral of certain costs (including credit losses) incurred as a result of the COVID-19 pandemic. The additional protections related to our accounts receivable and unbilled revenue balances provided by these orders are subject to prudency reviews and are still being assessed. They are not reflected in the percentage in the above table or this note. See Note 23, Regulatory Environment, for more information on these orders.

A rollforward of the allowance for credit losses for the years ended December 31, 2021 and 2020, is included below:

	Year Ended December 31
(in millions)	2021		2020
Balance at December 31	$	18.3	$	4.2
Provision for credit losses	6.2		8.2
Provision for credit losses deferred for future recovery or refund	(7.0)		9.7
Write-offs charged against the allowance	(10.0)		(8.1)
Recoveries of amounts previously written off	3.6		4.3
Balance at December 31	$	11.1	$	18.3

The allowance for credit losses decreased at December 31, 2021, compared to December 31, 2020, primarily related to normal collection practices resuming in April 2021. Higher year-over-year natural gas prices drove an increase in gross accounts receivable balances, partially offsetting the decrease in the allowance for credit losses attributed to collection efforts. See Note 23, Regulatory Environment, for more information.

The increase in the allowance for credit losses at December 31, 2020, compared to December 31, 2019, was driven by higher past due accounts receivable balances, primarily related to our residential customers. This increase in accounts receivable balances in

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arrears was driven by economic disruptions caused by the COVID-19 pandemic, including higher unemployment rates. Also, as a result of the COVID-19 pandemic and related regulatory orders we received, we were unable to disconnect any of our customers during the year ended December 31, 2020.

NOTE 6—REGULATORY ASSETS AND LIABILITIES

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

(in millions)	2021		2020		See Note
Regulatory assets (1) (2)
Environmental remediation costs (3)	$	120.1	$	116.1	21
Pension and OPEB costs (4)	74.1		161.4		19
Income tax related items	54.5		46.7		16
Plant retirement related items	50.2		58.5
ReACT™	15.6		18.2		23
AROs	14.2		13.1		9
Uncollectible expense	5.5		12.5		5
Forward Wind (5)	2.8		10.3
Other, net	10.9		12.6
Total regulatory assets	$	347.9	$	449.4

(1)    Based on prior and current rate treatment, we believe it is probable that we will continue to recover from customers the regulatory assets in this table. In accordance with GAAP, our regulatory assets do not include the allowance for ROE that is capitalized for regulatory purposes. This allowance was $12.3 million and $16.6 million at December 31, 2021 and 2020, respectively.

(2)    As of December 31, 2021, we had $32.4 million of regulatory assets not earning a return. The regulatory assets not earning a return primarily relate to certain environmental remediation costs and our electric real-time market pricing program. The other regulatory assets in the table either earn a return at our weighted average cost of capital or the cash has not yet been expended, in which case the regulatory assets are offset by liabilities.

(3)    As of December 31, 2021, we had made cash expenditures of $25.1 million related to these environmental remediation costs. The remaining $95.0 million represents our estimated future cash expenditures.

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

(5)    In April 2018, we, along with two unaffiliated utilities, purchased Forward Wind. Based on an order from the PSCW, we were allowed to defer as a regulatory asset the incremental non-fuel costs associated with the purchase, ownership, and operation of Forward Wind. In the rate order we received from the PSCW in December 2019, we were authorized recovery of this regulatory asset over a period of two years that began on January 1, 2020.

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

(in millions)	2021		2020		See Note
Regulatory liabilities
Income tax related items	$	352.7	$	397.0	16
Removal costs (1)	189.9		193.7
Pension and OPEB benefits (2)	116.5		115.9		19
Derivatives (3)	26.9		3.1		18
Earnings sharing mechanism	26.7		36.8		23
Electric transmission costs (4)	19.7		16.8
Energy costs refundable through rate adjustments	8.4		9.7		1(d)
Other, net	3.1		3.2
Total regulatory liabilities	$	743.9	$	776.2
Balance sheet presentation
Other current liabilities	$	8.4	$	3.6
Regulatory liabilities	735.5		772.6
Total regulatory liabilities	$	743.9	$	776.2

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

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

(3)    For most energy-related physical and financial contracts that qualify as derivatives, the PSCW allows the effects of fair value accounting to be offset to regulatory assets and liabilities.

(4)    In accordance with the PSCW's approval of escrow accounting for our ATC and MISO network transmission expenses, we 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.

Pulliam Power Plant

In connection with a MISO ruling, we retired Pulliam Units 7 and 8 on October 21, 2018. The net book value of the Pulliam units was $38.0 million at December 31, 2021, representing book value less cost of removal and accumulated depreciation. This amount was classified as a regulatory asset on our balance sheet at December 31, 2021 as a result of the retirement of the plant. Effective with our rate order issued by the PSCW in December 2019, we received approval to collect a return of and on the entire net book value of the Pulliam units, and as a result, will continue to amortize this regulatory asset on a straight-line basis through 2031, using the composite depreciation rates approved by the PSCW before these generating units were retired. Amortization is included in depreciation and amortization in the income statement. We have FERC approval to continue to collect the net book value of the Pulliam power plant using the approved composite depreciation rates, in addition to a return on the remaining net book value. FERC has completed its prudency review of Pulliam, concluding that the retirement of this plant was prudent.

Edgewater Unit 4

The Edgewater 4 generating unit was retired on September 28, 2018. The net book value of the generating unit was $3.6 million at December 31, 2021, representing book value less cost of removal and accumulated depreciation. This amount was classified as a regulatory asset on our balance sheet at December 31, 2021 as a result of the retirement of the plant. Effective with our rate order issued by the PSCW in December 2019, we received approval to collect a return of and on the entire net book value of the Edgewater 4 generating unit, and as a result, will continue to amortize this regulatory asset on a straight-line basis through 2026, using the composite depreciation rates approved by the PSCW before this generating unit was retired. Amortization is included in depreciation and amortization in the income statement. We have FERC approval to continue to collect the net book value of the Edgewater 4 generating unit using the approved composite depreciation rates, in addition to a return on the remaining net book value. FERC has completed its prudency review of Edgewater 4, concluding that the retirement of this plant was prudent.

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NOTE 7—PROPERTY, PLANT, AND EQUIPMENT

Property, plant, and equipment consisted of the following utility and non-utility assets at December 31:

(in millions)	2021		2020
Electric – generation	$	2,816.7	$	2,981.5
Electric – distribution	2,076.3		1,921.2
Natural gas – distribution, storage, and transmission	1,159.5		1,064.1
Property, plant, and equipment to be retired, net	277.0		—
Other	482.5		434.8
Less: Accumulated depreciation	1,808.4		1,750.7
Net	5,003.6		4,650.9
CWIP	95.0		235.0
Total property, plant, and equipment	$	5,098.6	$	4,885.9

Severance Liability for Plant Retirements

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

(in millions)	2021		2020		2019
Severance liability at January 1	$	—	$	—	$	2.8
Severance expense	1.6		—		—
Severance payments	—		—		(1.5)
Other	—		—		(1.3)
Total severance liability at December 31	$	1.6	$	—	$	—

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 our ownership share of unit 1 and unit 2 was $89.1 million and $187.9 million, respectively, at December 31, 2021. These amounts were classified as plant to be retired within property, plant, and equipment on our balance sheet. These units are included in rate base, and we continue to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

NOTE 8—JOINTLY OWNED UTILITY FACILITIES

We hold a joint ownership interest in certain electric generating facilities. We are entitled to our share of generating capability and output of each facility equal to our respective ownership interest. We pay our ownership share of additional construction costs, fuel inventory purchases, and operating expenses, unless specific agreements have been executed to limit our maximum exposure to additional costs. We record our proportionate share of significant jointly owned electric generating facilities as property, plant, and equipment on the balance sheets.

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Information related to jointly owned utility facilities at December 31, 2021 was as follows:

(in millions, except for percentages and MW)	Weston Unit 4			Columbia Energy Center Units 1 and 2			Forward Wind			Two Creeks (2)			Badger Hollow I (3)
Ownership	70.0		%	27.5		%	44.6		%	66.7		%	66.7		%
Share of capacity (MW) (1)	387.3			311.1			61.5			100.0			100.0
In-service date	2008			1975 and 1978			2008			2020			2021
Property, plant, and equipment	$	598.4		$	425.4		$	122.5		$	136.7		$	134.5
Accumulated depreciation	$	(224.3)		$	(161.9)		$	(53.3)		$	(5.3)		$	(0.4)
CWIP	$	3.8		$	3.9		$	—		$	—		$	0.1

(1)    Capacity for Weston Unit 4 and Columbia Energy Center Units 1 and 2 is based on rated capacity, which is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. Values are primarily based on the net dependable expected capacity ratings for summer 2022 established by tests and may change slightly from year to year. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand. Capacity for Forward Wind is based on nameplate capacity, which is the amount of energy a turbine should produce at optimal wind speeds. Capacity for Two Creeks and Badger Hollow I is based on nameplate capacity, which is the maximum output that a generator should produce at continuous full power.

(2)    Commercial operation was achieved in November 2020 for Two Creeks.

(3)    Commercial operation was achieved in November 2021 for Badger Hollow I.

We, 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, we will own 90.0%, or 82 MW of this project. Construction is expected to be completed by the end of 2022.

Our proportionate share of direct expenses for the joint operation of these plants is recorded in operating expenses in the income statements. We have supplied our own financing for all jointly owned projects.

NOTE 9—ASSET RETIREMENT OBLIGATIONS

We have recorded AROs primarily for asbestos abatement at certain generation facilities, office buildings, and service centers; the dismantling of wind generation projects; the dismantling of solar generation projects; the disposal of polychlorinated biphenyls-contaminated transformers; and the closure of coal combustion residual landfills at certain generation facilities. We establish regulatory assets and liabilities to record the differences between ongoing expense recognition under the ARO accounting rules and the rate-making practices for retirement costs authorized by the PSCW.

On our balance sheets, AROs are recorded within other long-term liabilities. The following table shows changes to our AROs during the years ended December 31:

(in millions)	2021			2020			2019
Balance as of January 1	$	45.5		$	41.5		$	50.8
Accretion	1.8			1.8			2.5
Additions and revisions to estimated cash flows	8.6		(1)	8.2		(2)	(3.7)
Liabilities settled	(0.1)			(6.0)		(3)	(8.1)		(4)
Balance as of December 31	$	55.8		$	45.5		$	41.5

(1)    AROs increased $10.8 million in 2021, due to the legal requirement to dismantle, at retirement, the Badger Hollow I solar generation project. Also in 2021, AROs increased $6.8 million due to revisions made to the removal estimates for fly ash landfills and ash ponds. AROs decreased $8.9 million due to revisions made to removal estimates for wind generation projects.

(2)    This increase in AROs during 2020 was primarily due to the legal requirement to dismantle, at retirement, the Two Creeks solar generation project.

(3)    AROs decreased $3.8 million in 2020, due to the settlement of AROs for the abatement of asbestos at our generation facilities. Also in 2020, AROs decreased $2.2 million, due to the settlement of AROs for the closure of coal combustion residual landfills at certain generation facilities.

(4)    AROs decreased $8.1 million in 2019, primarily due to the settlement of AROs for the abatement of asbestos at our generation facilities.

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NOTE 10—GOODWILL

Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. We had no changes to the carrying amount of goodwill during the years ended December 31, 2021 and 2020. We had no accumulated impairment losses related to our goodwill as of December 31, 2021.

During the third quarter of 2021, we completed our annual goodwill impairment test as of July 1, 2021. No impairment resulted from this test.

NOTE 11—COMMON EQUITY

Stock-Based Compensation

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

(in millions)	2021		2020		2019
Stock options	$	1.1	$	1.0	$	0.8
Restricted stock	1.0		1.2		1.2
Performance units	0.4		4.1		7.4
Stock-based compensation expense	$	2.5	$	6.3	$	9.4
Related tax benefit	$	0.7	$	1.7	$	2.6

Stock-based compensation costs capitalized during 2021, 2020, and 2019 were not significant.

Stock Options

The following is a summary of our employees' WEC Energy Group stock option activity during 2021:

Stock Options	Number of Options	Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Life (in years)	Aggregate Intrinsic Value (in millions)
Outstanding as of January 1, 2021	69,145	$	74.01
Granted	18,021	$	91.06
Exercised	(9,600)	$	64.98
Transferred	1,053	$	91.06
Outstanding as of December 31, 2021	78,619	$	79.25	7.5	$	1.4
Exercisable as of December 31, 2021	27,947	$	70.37	6.4	$	0.7

The aggregate intrinsic value of outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they exercised all of their options on December 31, 2021. This is calculated as the difference between WEC Energy Group's closing stock price on December 31, 2021, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the years ended December 31, 2021, 2020, and 2019 was $0.3 million, $0.9 million, and $0.5 million, respectively. Cash received by WEC Energy Group from exercises of its options by our employees was $0.6 million, $1.5 million, and $1.1 million during the years ended December 31, 2021, 2020, and 2019, respectively. The actual tax benefit from option exercises for the same periods was approximately $0.1 million, $0.3 million and $0.1 million, respectively.

As of December 31, 2021, we expected to recognize approximately $0.5 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group stock options over the next 1.7 years on a weighted-average basis.

During the first quarter of 2022, the Compensation Committee awarded 16,079 non-qualified WEC Energy Group stock options with an exercise price of $96.04 and a weighted-average grant date fair value of $14.71 per option to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

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Restricted Shares

The following is a summary of our employees' WEC Energy Group restricted stock activity during 2021:

Restricted Shares	Number of Shares	Weighted-Average Grant Date Fair Value
Outstanding and unvested as of January 1, 2021	3,182	$	78.37
Granted	1,254	$	91.06
Released	(1,622)	$	74.04
Transferred	73	$	91.06
Forfeited	(311)	$	82.79
Outstanding and unvested as of December 31, 2021	2,576	$	87.10

The intrinsic value of WEC Energy Group restricted stock held by our employees that was released was $0.1 million, $0.2 million, and $0.4 million for the years ended December 31, 2021, 2020, and 2019, respectively. The actual tax benefit from released restricted shares for the same years was $0.1 million each year.

As of December 31, 2021, we expected to recognize approximately $0.5 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group restricted stock over the next 1.7 years on a weighted-average basis.

During the first quarter of 2022, the Compensation Committee awarded 1,522 WEC Energy Group restricted shares to our officers and other key employees under its normal schedule of awarding long-term incentive compensation. The grant date fair value of these awards was $96.04 per share.

Performance Units

During 2021, 2020, and 2019, the Compensation Committee awarded 5,437; 7,017; and 8,178 WEC Energy Group performance units, respectively, to our officers and other key employees under the WEC Energy Group Performance Unit Plan.

Performance units with an intrinsic value of $1.2 million, $1.8 million, and $0.8 million were settled during 2021, 2020, and 2019, respectively. The actual tax benefit from the distribution of performance units for the same years was $0.2 million, $0.4 million, and $0.2 million, respectively.

At December 31, 2021, our employees held 17,742 WEC Energy Group performance units, including dividend equivalents. A liability of $0.9 million was recorded on our balance sheet at December 31, 2021 related to these outstanding units. As of December 31, 2021, we expected to recognize approximately $1.9 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group performance units over the next 2.0 years on a weighted-average basis.

During the first quarter of 2022, performance units held by our employees with an intrinsic value of $0.7 million were settled. The actual tax benefit from the distribution of these awards was $0.1 million. In January 2022, the Compensation Committee also awarded 6,608 WEC Energy Group performance units to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

Restrictions

Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to the sole holder of our common stock, Integrys, in the form of cash dividends, loans, or advances. In addition, Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group, Integrys, or their subsidiaries.

In accordance with our most recent rate order, we may not pay common dividends above the test year forecasted amount reflected in our rate case, if it would cause our average common equity ratio, on a financial basis, to fall below our authorized level of 52.5%. A return of capital in excess of the test year amount can be paid by us at the end of the year provided that our average common equity ratio does not fall below the authorized level.

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

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As of December 31, 2021, our restricted retained earnings totaled approximately $472 million.

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

NOTE 12—PREFERRED STOCK

We have 1,000,000 shares of preferred stock with a $100 par value authorized for issuance, of which none were issued and outstanding at December 31, 2021 and 2020.

NOTE 13—SHORT-TERM DEBT AND LINES OF CREDIT

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

(in millions, except percentages)	2021			2020
Commercial paper
Amount outstanding at December 31	$	331.0		$	210.5
Average interest rate on amounts outstanding at December 31	0.21		%	0.18		%

Our average amount of commercial paper borrowings based on daily outstanding balances during 2021 was $171.6 million, with a weighted-average interest rate during the period of 0.16%.

We have entered into a bank back-up credit facility to maintain short-term credit liquidity which, among other terms, requires us to maintain, subject to certain exclusions, a total funded debt to capitalization ratio of 65% or less. As of December 31, 2021, we were in compliance with this ratio.

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

(in millions)	Maturity	2021
Revolving credit facility (1)	October 2022	$	400.0
Less:
Letters of credit issued inside credit facility		1.3
Commercial paper outstanding		331.0
Available capacity under existing agreement		$	67.7

(1)    We intend to request approval from the PSCW to extend the maturity of our credit facility to September 2026. Lenders have agreed to the extension, subject to our receipt of PSCW approval.

This facility has a renewal provision for two extensions, subject to lender approval. Each extension is for a period of one year.

Our bank back-up credit facility contains customary covenants, including certain limitations on our ability to sell assets. The credit facility also contains customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, Employee Retirement Income Security Act of 1974 defaults and change of control.

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NOTE 14—LONG-TERM DEBT

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

(in millions)	Interest Rate	Year Due	2021		2020
Senior Notes (unsecured)	3.35%	2021	$	—	$	400.0
	6.08%	2028	50.0		50.0
	5.55%	2036	125.0		125.0
	3.671%	2042	300.0		300.0
	4.752%	2044	450.0		450.0
	3.30%	2049	300.0		300.0
	2.85%	2051	450.0		—
Total			1,675.0		1,625.0
Unamortized debt issuance costs			(14.2)		(10.7)
Unamortized discount, net			(1.5)		(0.8)
Total long-term debt, including current portion (1)			1,659.3		1,613.5
Current portion of long-term debt			—		(400.0)
Total long-term debt			$	1,659.3	$	1,213.5

(1)    The amount of long-term debt on our balance sheet includes finance lease obligations of $31.3 million at both December 31, 2021 and December 31, 2020.

We amortize debt premiums, discounts, and debt issuance costs over the life of the debt using the straight-line method and we include the costs in interest expense.

In November 2021, we issued $450.0 million of 2.85% Senior Notes due December 1, 2051, and intend to allocate an amount equal to the net proceeds for the construction and development of eligible green expenditures, which include existing and new expenditures for the acquisition, construction and development of wind and solar electric generating facilities and related energy storage assets.

In November 2021, our $400.0 million 3.35% Senior Notes due November 21, 2021, matured, and the outstanding principal was paid with proceeds we received from the issuance of the $450.0 million 2.85% Senior Notes Due December 1, 2051, pending their allocation to the payment or reimbursement of eligible green expenditures.

The following table shows the future maturities of our long-term debt outstanding (excluding obligations under finance leases) as of December 31, 2021:

(in millions)	Payments
2022	$	—
2023	—
2024	—
2025	—
2026	—
Thereafter	1,675.0
Total	$	1,675.0

Our long-term debt obligations contain covenants related to payment of principal and interest when due and various other obligations. Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations.

NOTE 15—LEASES

Obligations Under Finance Leases

In accordance with the Regulated Operations - Leases Topic of the FASB ASC, the timing of lease expense recognized for our leases discussed below resembles the expense recognition pattern of an operating lease, as the amortization of the right of use assets is modified from what would typically be recorded for a finance lease. We record the difference between the minimum lease

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payments and the sum of imputed interest and unadjusted amortization costs calculated under the finance lease accounting rules as a regulatory asset on our balance sheets.

Two Creeks Solar Park

Related to our investment in Two Creeks, we, along with an unaffiliated utility, entered into several land leases in Manitowoc County, Wisconsin that commenced in the third quarter of 2019. The leases are for a total of approximately 800 acres of land. Each lease has an initial term of 30 years with two optional 10-year extensions. We expect the two optional extensions to be exercised, and, as a result, the land leases are being amortized over the 50-year extended term of the leases. The lease payments are being recovered through rates. After achieving commercial operation in November 2020, the lease liability was remeasured as a result of finalizing the total acres being leased.

Our total obligation under the finance leases for Two Creeks as of December 31, 2021 and 2020, was $13.7 million and $11.0 million, respectively, and will decrease to zero over the remaining lives of the leases.

Badger Hollow Solar Park I

Related to our investment in Badger Hollow I, we, along with an unaffiliated utility, entered into several land leases in Iowa County, Wisconsin that commenced in the third quarter of 2019. The leases are for a total of approximately 1,300 acres of land. Each lease has an initial construction term that ends upon achieving commercial operation, then automatically extends for 25 years with an option for an additional 25-year extension. We expect the optional extension to be exercised, and, as a result, the land leases are being amortized over the extended term of the leases. The lease payments are being recovered through rates. Upon achieving commercial operation in November 2021, the lease liability was remeasured as a result of finalizing the total acres being leased.

Our total obligation under the finance leases for Badger Hollow I as of December 31, 2021 and 2020, was $17.6 million and $20.3 million, respectively, and will decrease to zero over the remaining lives of the leases.

Amounts Recognized in the Financial Statements and Other Information

Lease expense and cash payments related to the Two Creeks and Badger Hollow I finance leases were not significant in 2021 or 2020. Other information related to these leases for the years ended December 31 are as follows:

Other information (dollar amounts in millions)	2021			2020
Non-cash activity – net reduction of right of use assets and finance lease liabilities due to remeasurements	$	0.3		$	—
Weighted average remaining lease term	49.6 years			50.0 years
Weighted average discount rate (1)	3.3		%	4.2		%

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

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The following table summarizes our finance lease right of use assets, which were included in property, plant, and equipment on our balance sheets at December 31:

(in millions)	2021		2020
Two Creeks land leases
Under finance leases	$	13.3	$	10.8
Accumulated amortization	(0.6)		(0.3)
Total Two Creeks land leases	$	12.7	$	10.5
Badger Hollow I land leases
Under finance leases	$	16.6	$	19.5
Accumulated amortization	(0.9)		(0.6)
Total Badger Hollow I land leases	$	15.7	$	18.9
Total finance lease right of use assets	$	28.4	$	29.4

Future minimum lease payments under our finance leases and the present value of our net minimum lease payments as of December 31, 2021, were as follows:

(in millions)	Two Creeks		Badger Hollow I		Total Finance Leases
2022	$	0.3	$	0.5	$	0.8
2023	0.3		0.5		0.8
2024	0.3		0.5		0.8
2025	0.3		0.5		0.8
2026	0.3		0.5		0.8
Thereafter	30.2		39.3		69.5
Total minimum lease payments	31.7		41.8		73.5
Less: Interest	(18.0)		(24.2)		(42.2)
Present value of minimum lease payments	13.7		17.6		31.3
Less: Short-term lease liabilities	—		—		—
Long-term lease liabilities	$	13.7	$	17.6	$	31.3

Long-term lease liabilities related to our finance leases were included in long-term debt on our balance sheets.

As of February 24, 2022, we have not entered into any material leases that have not yet commenced.

NOTE 16—INCOME TAXES

Income Tax Expense

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

(in millions)	2021		2020		2019
Current tax expense (benefit)	$	(18.3)	$	49.8	$	(66.1)
Deferred income taxes, net	51.1		5.1		125.5
ITCs	(1.6)		(0.4)		(0.3)
Total income tax expense	$	31.2	$	54.5	$	59.1

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Statutory Rate Reconciliation

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

	2021				2020				2019
(in millions)	Amount		Effective Tax Rate		Amount		Effective Tax Rate		Amount		Effective Tax Rate
Statutory federal income tax	$	55.1	21.0	%	$	58.0	21.0	%	$	51.2	21.0	%
State income taxes net of federal tax benefit	16.3		6.2	%	16.9		6.1	%	15.1		6.2	%
Federal excess deferred tax amortization – Wisconsin unprotected (1)	(33.0)		(12.6)	%	(12.7)		(4.6)	%	—		—	%
Federal excess deferred tax amortization (2)	(5.2)		(2.0)	%	(5.1)		(1.8)	%	(4.6)		(1.9)	%
AFUDC – Equity	(1.9)		(0.7)	%	(2.5)		(0.9)	%	(1.2)		(0.5)	%
Other, net	(0.1)		—	%	(0.1)		(0.1)	%	(1.4)		(0.6)	%
Total income tax expense	$	31.2	11.9	%	$	54.5	19.7	%	$	59.1	24.2	%

(1)    In accordance with the rate order received from the PSCW in December 2019, we are amortizing these unprotected deferred tax benefits over periods ranging from two years to four years, to reduce near-term rate impacts to our customers. The decrease in income tax expense related to the amortization of the deferred tax benefits is offset by a decrease in revenue as the benefits are returned to customers, resulting in no impact on net income.

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

See Note 23, Regulatory Environment, for more information about the impact of the Tax Legislation and the Wisconsin rate orders.

Deferred Income Tax Assets and Liabilities

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

(in millions)	2021		2020
Deferred tax assets
Tax gross up – regulatory items	$	102.4	$	106.5
Future tax benefits	8.7		33.3
Other	20.5		22.2
Total deferred tax assets	$	131.6	$	162.0
Deferred tax liabilities
Property-related	822.1		749.1
Employee benefits and compensation	49.5		44.6
Other	42.2		51.0
Total deferred tax liabilities	913.8		844.7
Deferred tax liability, net	$	782.2	$	682.7

Consistent with rate-making treatment, deferred taxes in the table above are offset for temporary differences that have related regulatory assets and liabilities.

The components of net deferred tax assets associated with federal tax benefit carryforwards as of December 31, 2021 and 2020 are summarized in the tables below:

2021 (in millions)	Gross Value		Deferred Tax Effect		Earliest Year of Expiration
Future tax benefits as of December 31, 2021
Federal tax credit	$	—	$	8.7	2041
Balance as of December 31, 2021	$	—	$	8.7

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2020 (in millions)	Gross Value		Deferred Tax Effect		Earliest Year of Expiration
Future tax benefits as of December 31, 2020
Federal tax credit	$	—	$	33.3	2040
Balance as of December 31, 2020	$	—	$	33.3

Unrecognized Tax Benefits

We had no unrecognized tax benefits at December 31, 2021 and 2020.

We do not expect any unrecognized tax benefits to affect our effective tax rate in periods after December 31, 2021.

For the years ended December 31, 2021, 2020, and 2019, we recognized no interest expense and no penalties related to unrecognized tax benefits in our income statements. At December 31, 2021 and 2020, we had no interest accrued and no penalties accrued related to unrecognized tax benefits on our balance sheets.

We do not anticipate any significant increases in the total amounts of unrecognized tax benefits within the next 12 months.

Our primary tax jurisdictions include federal and the state of Wisconsin. With a few exceptions, we are no longer subject to federal income tax examinations by the IRS for years prior to 2018. As of December 31, 2021, we were subject to examination by the Wisconsin taxing authority for tax years 2017 through 2021.

NOTE 17—FAIR VALUE MEASUREMENTS

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

	December 31, 2021
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	6.5	$	3.0	$	—	$	9.5
FTRs	—		—		1.4		1.4
Coal contracts	—		15.3		—		15.3
Total derivative assets	$	6.5	$	18.3	$	1.4	$	26.2
Derivative liabilities
Natural gas contracts	$	1.4	$	0.2	$	—	$	1.6

	December 31, 2020
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	1.6	$	0.1	$	—	$	1.7
FTRs	—		—		1.2		1.2
Coal contracts	—		0.4		—		0.4
Total derivative assets	$	1.6	$	0.5	$	1.2	$	3.3
Derivative liabilities
Natural gas contracts	$	1.6	$	0.3	$	—	$	1.9
Coal contracts	—		0.5		—		0.5
Total derivative liabilities	$	1.6	$	0.8	$	—	$	2.4

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

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

(in millions)	2021		2020		2019
Balance at the beginning of the period	$	1.2	$	1.3	$	3.0
Purchases	3.1		4.1		5.4
Settlements	(2.9)		(4.2)		(7.1)
Balance at the end of the period	$	1.4	$	1.2	$	1.3

Fair Value of Financial Instruments

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

	December 31, 2021				December 31, 2020
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion (1)	$	1,659.3	$	1,903.2	$	1,613.5	$	1,935.9

(1)    The carrying amount of long-term debt excludes finance lease obligations of $31.3 million at both December 31, 2021 and 2020.

The fair value of our long-term debt is categorized within Level 2 of the fair value hierarchy.

NOTE 18—DERIVATIVE INSTRUMENTS

None of our derivatives are designated as hedging instruments. 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.

	December 31, 2021				December 31, 2020
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Current
Natural gas contracts	$	9.2	$	1.5	$	1.7	$	1.7
FTRs	1.4		—		1.2		—
Coal contracts	11.6		—		0.2		0.3
Total current	22.2		1.5		3.1		2.0
Long-term
Natural gas contracts	0.3		0.1		—		0.2
Coal contracts	3.7		—		0.2		0.2
Total long-term	4.0		0.1		0.2		0.4
Total	$	26.2	$	1.6	$	3.3	$	2.4

Realized gains (losses) on derivatives are primarily recorded in cost of sales on the income statements. Our estimated notional sales volumes and realized gains (losses) were as follows for the years ended:

	December 31, 2021			December 31, 2020			December 31, 2019
(in millions)	Volumes	Gains		Volumes	Gains (Losses)		Volumes	Gains (Losses)
Natural gas contracts	37.5 Dth	$	21.8	38.1 Dth	$	(8.7)	35.4 Dth	$	(5.3)
FTRs	7.0 MWh	8.7		8.3 MWh	1.4		9.1 MWh	7.2
Total		$	30.5		$	(7.3)		$	1.9

At December 31, 2021 and 2020, we had posted cash collateral of $6.3 million and $3.7 million, respectively.

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

	December 31, 2021				December 31, 2020
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Gross amount recognized on the balance sheet	$	26.2	$	1.6	$	3.3	$	2.4
Gross amount not offset on the balance sheet	(1.4)		(1.4)		(1.6)		(1.6)
Net amount	$	24.8	$	0.2	$	1.7	$	0.8

NOTE 19—EMPLOYEE BENEFITS

Pension and Other Postretirement Employee Benefits

We have our own noncontributory, qualified pension plan.

We serve as plan sponsor and administrator for certain OPEB plans. The benefits are funded through irrevocable trusts, as allowed for income tax purposes. Our balance sheets reflect only the liabilities associated with our past and current employees and our share of the plan assets and obligations. WEC Energy Group also offers medical, dental, and life insurance benefits to our active employees and their dependents. We expense the allocated costs of these benefits as incurred.

The defined benefit pension plans are closed to all new hires. In addition, the service accruals for the defined benefit pension plans were frozen for non-union employees as of January 1, 2013. These employees receive an annual company contribution to their

401(k) savings plan, which is calculated based on age, wages, and full years of vesting service as of December 31 each year.

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

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

	Pension Benefits				OPEB Benefits
(in millions)	2021		2020		2021		2020
Change in benefit obligation
Obligation at January 1	$	816.2	$	734.0	$	148.5	$	147.2
Service cost	10.6		9.9		4.3		4.4
Interest cost	21.9		25.2		4.2		5.1
Plan amendments	—		—		(3.5)		—
Actuarial loss (gain)	(37.1)		83.5		2.3		(1.2)
Participant contributions	—		—		1.1		1.1
Benefit payments	(38.5)		(36.4)		(10.0)		(8.1)
Obligation at December 31	$	773.1	$	816.2	$	146.9	$	148.5
Change in fair value of plan assets
Fair value at January 1	$	816.3	$	747.5	$	288.3	$	263.4
Actual return on plan assets	80.6		104.6		23.3		31.1
Employer contributions	1.0		0.6		0.9		0.1
Participant contributions	—		—		1.1		1.1
Benefit payments	(38.5)		(36.4)		(10.0)		(8.1)
Net transfer from affiliates	—		—		—		0.7
Fair value at December 31	$	859.4	$	816.3	$	303.6	$	288.3
Funded status at December 31	$	86.3	$	0.1	$	156.7	$	139.8

In 2021 we had actuarial gains related to our pension obligations of $37.1 million and actuarial losses in 2020 of $83.5 million, both of which were primarily driven by changes in our discount rates. The discount rate for our pension benefits was 3.00%, 2.74%, and 3.45%, in 2021, 2020, and 2019, respectively.

The actuarial gains and losses related to our OPEB benefit obligations were not significant for 2021 or 2020.

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

	Pension Benefits				OPEB Benefits
(in millions)	2021		2020		2021		2020
Pension and OPEB assets	$	92.9	$	7.6	$	167.8	$	151.6
Other long-term liabilities	6.6		7.5		11.1		11.8
Total net assets	$	86.3	$	0.1	$	156.7	$	139.8

The accumulated benefit obligation for the defined benefit pension plans was $705.0 million and $730.8 million at December 31, 2021 and 2020, respectively.

The following table shows information for pension plans with an accumulated benefit obligation in excess of plan assets. There were no plan assets related to these pension plans. Amounts presented are as of December 31:

(in millions)	2021		2020
Accumulated benefit obligation	$	6.6	$	7.5

The following table shows information for pension plans with a projected benefit obligation in excess of plan assets. There were no plan assets related to these pension plans. Amounts presented are as of December 31:

(in millions)	2021		2020
Projected benefit obligation	$	6.6	$	7.5

The following table shows information for OPEB plans with an accumulated benefit obligation in excess of plan assets. There were no plan assets related to these OPEB plans. Amounts presented are as of December 31:

(in millions)	2021		2020
Accumulated benefit obligation	$	11.1	$	11.8

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

	Pension Benefits				OPEB Benefits
(in millions)	2021		2020		2021		2020
Net regulatory assets (liabilities)
Net actuarial loss (gain)	$	87.3	$	179.9	$	(64.6)	$	(67.7)
Prior service credits	—		—		(41.4)		(54.6)
Total	$	87.3	$	179.9	$	(106.0)	$	(122.3)

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

	Pension Benefits						OPEB Benefits
(in millions)	2021		2020		2019		2021		2020		2019
Service cost	$	10.6	$	9.9	$	8.7	$	4.3	$	4.4	$	4.1
Interest cost	21.9		25.2		28.2		4.2		5.1		6.5
Expected return on plan assets	(51.8)		(48.6)		(48.0)		(20.4)		(18.2)		(16.5)
Plan curtailment	—		—		—		(6.4)		—		—
Amortization of prior service credit	—		—		—		(10.3)		(10.5)		(11.5)
Amortization of net actuarial loss (gain)	26.6		23.7		17.8		(3.7)		(1.4)		1.7
Net periodic benefit cost (credit)	$	7.3	$	10.2	$	6.7	$	(32.3)	$	(20.6)	$	(15.7)

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

	Pension Benefits		OPEB Benefits
	2021	2020	2021	2020
Discount rate	3.00%	2.74%	2.98%	2.72%
Rate of compensation increase	4.00%	4.00%	N/A	N/A
Interest credit rate	2.25%	2.25%	N/A	N/A
Assumed medical cost trend rate (Pre 65)	N/A	N/A	5.70%	5.85%
Ultimate trend rate (Pre 65)	N/A	N/A	5.00%	5.00%
Year ultimate trend rate is reached (Pre 65)	N/A	N/A	2028	2028
Assumed medical cost trend rate (Post 65)	N/A	N/A	5.60%	5.70%
Ultimate trend rate (Post 65)	N/A	N/A	5.00%	5.00%
Year ultimate trend rate is reached (Post 65)	N/A	N/A	2028	2028

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

	Pension Benefits
	2021	2020	2019
Discount rate	2.74%	3.45%	4.30%
Expected return on assets	7.00%	7.00%	7.25%
Rate of compensation increase	4.00%	4.00%	4.00%
Interest credit rate	2.25%	2.25%	2.25%

	OPEB Benefits
	2021	2020	2019
Discount rate	2.95%	3.48%	4.29%
Expected return on assets	7.00%	7.00%	7.25%
Assumed medical cost trend rate (Pre 65)	5.85%	6.00%	6.25%
Ultimate trend rate (Pre 65)	5.00%	5.00%	5.00%
Year ultimate trend rate is reached (Pre 65)	2028	2028	2024
Assumed medical cost trend rate (Post 65)	5.70%	5.80%	5.90%
Ultimate trend rate (Post 65)	5.00%	5.00%	5.00%
Year ultimate trend rate is reached (Post 65)	2028	2028	2028

WEC Energy Group consults with its investment advisors on an annual basis to help forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund. For 2022, the expected return on asset assumption for the pension plan and OPEB plans is 7.00%.

Plan Assets

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

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

Our pension trust target asset allocations are 45% equity investments, 45% fixed income investments, and 10% private equity and real estate investments. The OPEB trust has a target asset allocation of 45% equity investments and 55% fixed income investments. Equity securities include investments in large-cap, mid-cap, and small-cap companies. Fixed income securities include corporate

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bonds of companies from diversified industries, mortgage and other asset backed securities, commercial paper, and United States Treasuries.

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

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

	December 31, 2021
	Pension Plan Assets								OPEB Assets
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Asset Class
Equity securities:
United States equity	$	123.8	$	—	$	—	$	123.8	$	41.1	$	—	$	—	$	41.1
International equity	94.7		—		—		94.7		34.6		—		—		34.6
Fixed income securities: (1)
United States bonds	—		165.4		—		165.4		64.7		43.0		—		107.7
International bonds	—		27.1		—		27.1		—		3.1		—		3.1
	$	218.5	$	192.5	$	—	$	411.0	$	140.4	$	46.1	$	—	$	186.5
Investments measured at net asset value							$	448.4							$	117.1
Total	$	218.5	$	192.5	$	—	$	859.4	$	140.4	$	46.1	$	—	$	303.6

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

	December 31, 2020
	Pension Plan Assets								OPEB Assets
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Asset Class
Equity securities:
United States equity	$	124.2	$	—	$	—	$	124.2	$	43.0	$	—	$	—	$	43.0
International equity	97.3		—		—		97.3		37.4		—		—		37.4
Fixed income securities: (1)
United States bonds	—		166.3		—		166.3		56.6		39.5		—		96.1
International bonds	—		26.5		—		26.5		—		1.9		—		1.9
	$	221.5	$	192.8	$	—	$	414.3	$	137.0	$	41.4	$	—	$	178.4
Investments measured at net asset value							$	402.0							$	109.9
Total	$	221.5	$	192.8	$	—	$	816.3	$	137.0	$	41.4	$	—	$	288.3

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

Cash Flows

We expect to contribute $0.6 million to the pension plans and $0.9 million to the OPEB plans in 2022, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

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

(in millions)	Pension Benefits		OPEB Benefits
2022	$	36.4	$	8.5
2023	37.2		8.7
2024	37.5		8.8
2025	37.8		8.9
2026	38.2		9.3
2027-2031	192.2		48.0

Savings Plans

WEC Energy Group sponsors 401(k) savings plans that allow substantially all of our full-time employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. A percentage of employee contributions are matched by us through a contribution into the employee's savings plan account, up to certain limits. The 401(k) savings plans include an Employee Stock Ownership Plan. Certain employees receive an employer retirement contribution, which amounts are contributed to an employee's savings plan account based on the employee's wages, age, and years of service. Total costs incurred under all of these plans were $11.0 million, $10.1 million, and $10.4 million in 2021, 2020, and 2019, respectively.

NOTE 20—SEGMENT INFORMATION

We use net income to measure segment profitability and to allocate resources to our businesses. At December 31, 2021, we reported two segments, which are described below.

Our utility segment includes our electric and natural gas utility operations, which serve customers in northeastern and central Wisconsin. Our electric utility operations are engaged in the generation, distribution, and sale of electricity. Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers as well as the transportation of customer-owned natural gas.

Our other segment primarily consists of equity earnings from our investment in WRPC.

All of our operations and assets are located within the United States. The following tables show summarized financial information related to our reportable segments for the years ended December 31, 2021, 2020, and 2019.

2021 (in millions)	Utility		Other		Wisconsin Public Service Corporation
External revenues	$	1,520.9	$	—	$	1,520.9
Other operation and maintenance	406.4		—		406.4
Depreciation and amortization	188.6		—		188.6
Other income, net	36.8		1.4		38.2
Interest expense	64.7		—		64.7
Income tax expense	30.9		0.3		31.2
Net income	230.0		1.1		231.1
Capital expenditures	389.7		—		389.7
Total assets	6,224.3		11.4		6,235.7

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2020 (in millions)	Utility		Other		Wisconsin Public Service Corporation
External revenues	$	1,407.1	$	—	$	1,407.1
Other operation and maintenance	426.3		—		426.3
Depreciation and amortization	174.3		—		174.3
Other income, net	29.9		1.5		31.4
Interest expense	63.5		—		63.5
Income tax expense	54.2		0.3		54.5
Net income	220.4		1.2		221.6
Capital expenditures	530.7		—		530.7
Total assets	5,923.3		10.6		5,933.9

2019 (in millions)	Utility		Other		Wisconsin Public Service Corporation
External revenues	$	1,411.9	$	—	$	1,411.9
Other operation and maintenance	396.2		—		396.2
Depreciation and amortization	166.2		—		166.2
Other income, net	38.2		1.4		39.6
Interest expense	63.4		—		63.4
Income tax expense	58.7		0.4		59.1
Net income	183.7		1.0		184.7
Capital expenditures	517.8		—		517.8
Total assets	5,595.7		45.9		5,641.6

NOTE 21—COMMITMENTS AND CONTINGENCIES

We 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

We have obligations to distribute and sell electricity and natural gas to our customers and 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 following table shows our minimum future commitments related to these purchase obligations as of December 31, 2021.

				Payments Due By Period
(in millions)	Date Contracts Extend Through	Total Amounts Committed		2022		2023		2024		2025		2026		Later Years
Electric utility:
Purchased power	2050	$	267.6	$	51.1	$	49.1	$	50.4	$	45.4	$	42.2	$	29.4
Coal supply and transportation	2025	90.9		34.8		30.6		16.8		8.7		—		—
Natural gas utility supply and transportation	2048	431.5		52.6		43.9		34.1		20.9		20.7		259.3
Total		$	790.0	$	138.5	$	123.6	$	101.3	$	75.0	$	62.9	$	288.7

Environmental Matters

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

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

•the development of additional sources of renewable electric energy supply;

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

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

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

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

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

•the remediation of former manufactured gas plant sites;

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

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

Air Quality

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 service territory were designated as partial nonattainment: Door and Manitowoc. This re-designation was 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 boundaries for 13 counties associated with six nonattainment areas, including several in Wisconsin. Under the new designations, the partial nonattainment areas of Door and Manitowoc counties have been expanded.

In February 2021, the WDNR proposed draft revisions to the Wisconsin Administrative Code to adopt the 2015 ozone standard and incorporate by reference the federal air pollution monitoring requirements related to the NAAQS. The Natural Resources Board adopted the rule as proposed during their June 2021 meeting and the rule is now in legislative review. 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 associated state or federal rules.

Particulate Matter

In addition to the 2015 ozone standard, in December 2020, the EPA completed its 5-year review of the 2012 standard for particulate matter, including 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. A proposed rule-making is expected in summer 2022, and a final rule is expected in spring 2023. All counties within our service territory are in attainment with the current 2012 standards. If the EPA lowers the standard to 10 or 11 micrograms per cubic meter, our service territory should remain in attainment. If the EPA lowers it 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.

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Climate Change

The ACE rule, effective since September 2019, was vacated by the D.C. Circuit Court of Appeals in January 2021. The ACE rule replaced the Clean Power Plan and provided existing coal-fired generating units with standards for achieving GHG emission reductions. In a memorandum issued to the EPA regional administrators in February 2021, the EPA stated that the D.C. Circuit Court decision meant that no existing rule regulates GHG emissions from electric generating units. The EPA is currently reviewing its options for such regulations and has signaled that a draft rule may be released in 2022 at the earliest. 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 expected to review 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. Arguments are expected to take place in early 2022 with a decision expected by the summer of 2022.

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. The rule became effective in March 2021; 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 June 2022. WEC Energy Group continues to move forward on the ESG Progress Plan, which is heavily focused on reducing GHG emissions.

The 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 approximately 300 MW of coal-fired generation since the beginning of 2018. Through its ESG Progress Plan, WEC Energy Group expects to retire approximately 1,600 MW of additional fossil-fueled generation by 2025, which includes the planned retirements in 2023-2024 of the jointly-owned Columbia Units 1-2. In May 2021, WEC Energy Group announced goals to achieve reductions in carbon emissions from its electric generation fleet by 60% by 2025 and by 80% by 2030, both from a 2005 baseline. WEC Energy Group expects to achieve these goals by making operating refinements, retiring less efficient generating units, and executing its capital plan. Over the longer term, the target for WEC Energy Group's generation fleet is net-zero CO2 emissions by 2050.

WEC Energy Group also continues to reduce methane emissions by improving its natural gas distribution system. WEC Energy Group set a target across its natural gas distribution operations to achieve net-zero methane emissions by 2030. WEC Energy Group plans to achieve its net-zero goal through an effort that includes both continuous operational improvements and equipment upgrades, as well as the use of RNG throughout its utility systems.

We are required to report our CO2 equivalent emissions from the electric generating facilities we operate under the EPA Greenhouse Gases Reporting Program. Based upon our preliminary analysis of the data, we estimate that we will report CO2 equivalent emissions of approximately 6.0 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 operations distribute and sell. Based upon our preliminary analysis of the data, we estimate that we will report CO2 equivalent emissions of approximately 3.5 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. 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 will apply it when establishing BTA requirements for cooling water intake structures at existing facilities. These BTA requirements are incorporated into Wisconsin Pollutant Discharge Elimination System permits for our facilities.

We have received interim BTA determinations for Weston Units 2, 3, and 4. A final BTA decision for the Weston facility is expected during its next permit renewal in late 2023.

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As a result of past capital investments completed to address Section 316(b) compliance, 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 at existing facilities. This rule created new requirements for several types of power plant wastewaters. The new requirement that affects us relates to discharge limits for BATW. Our Weston power plant facility already has 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 systems at Weston Unit 3 (to be completed by December 2023). Based on engineering cost estimates, we expect that compliance with the ELG rule will require approximately $10 million in capital investment. 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 Wisconsin Pollutant Discharge Elimination System permit deadlines.

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.

Land Quality

Manufactured Gas Plant Remediation

We have identified sites at which we 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. We 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 the state of Wisconsin in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure.

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

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

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

(in millions)	2021		2020
Regulatory assets	$	120.1	$	116.1
Reserves for future environmental remediation	95.0		88.3

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Renewables, Efficiency, and Conservation

Wisconsin Legislation

In 2005, Wisconsin enacted Act 141, which established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources annually. We have achieved our required renewable energy percentage of 9.74% by constructing various wind parks, two solar parks, and by also relying on renewable energy purchases. We continue to review our renewable energy portfolio and acquire cost-effective renewables as needed to meet our requirements on an ongoing basis. The PSCW administers the renewable program related to Act 141, and we fund the program, along with other utilities, based on 1.2% of our annual retail operating revenues.

Enforcement and Litigation Matters

We 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

Weston and Pulliam Power Plants

In November 2009, the EPA issued an NOV to us, 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. 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 Eastern District of Wisconsin in March 2013.

With the retirement of Pulliam Units 7 and 8 in October 2018, we completed the mitigation projects required by the Consent Decree and received a completeness letter from the EPA in October 2018. See Note 6, Regulatory Assets and Liabilities, for more information about the retirement. We are working with the EPA on a closeout process for the Consent Decree.

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 us. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. We, 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. See Note 6, Regulatory Assets and Liabilities, for more information about the retirement. Wisconsin Power and Light Company has started the process to close out this Consent Decree.

NOTE 22—SUPPLEMENTAL CASH FLOW INFORMATION

	Year Ended December 31
(in millions)	2021		2020		2019
Cash paid for interest, net of amount capitalized	$	63.2	$	62.4	$	58.2
Cash received for income taxes, net	(55.2)		(16.9)		(33.9)
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs	15.5		23.7		43.3
Increase in receivable related to insurance proceeds	4.3		—		—

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NOTE 23—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. We have a regulatory mechanism in place for recovering all prudently incurred gas costs.

In March 2021, we filed our revised natural gas rate sheets with the PSCW reflecting approximately $28 million of natural gas costs in excess of the benchmark set in our GCRM. We recovered these excess costs over a period of three months, beginning in April 2021.

Coronavirus Disease – 2019

The global outbreak of COVID-19 was declared a pandemic by the World Health Organization and the CDC. COVID-19 has spread globally, including throughout the United States and, in turn, our service territory. In response to the COVID-19 pandemic, Wisconsin declared a public health emergency and issued a shelter-in-place order, which has since been lifted.

In March 2020, the PSCW issued two orders in response to the COVID-19 pandemic. The first order required all public utilities in the state of Wisconsin, including us, to temporarily suspend disconnections, the assessment of late fees, and deposit requirements for all customer classes. In addition, it required utilities to reconnect customers that were previously disconnected, offer deferred payment arrangements to all customers, and streamline the application process for customers applying for utility service.

In the second order issued in March 2020, the PSCW authorized Wisconsin utilities to defer expenditures and certain foregone revenues resulting from compliance with the first order, and expenditures as otherwise incurred to ensure safe, reliable, and affordable access to utility services during the declared public health emergency. The PSCW affirmed that this authorization for deferral included the incremental increase in uncollectible expense above what was being recovered in rates. As we already have a cost recovery mechanism in place to recover uncollectible expense for residential customers, this deferral only impacted the recovery of uncollectible expense for our commercial and industrial customers. See Note 5, Credit Losses, for information regarding changes to our allowance for credit losses. On December 16, 2021, the PSCW approved a motion to end all COVID-related deferrals as of December 31, 2021. Our deferrals related to the COVID-19 pandemic were not significant as of December 31, 2021. The PSCW will review the recoverability and examine the prudency of any deferred amounts in future rate proceedings.

In June 2020, the PSCW issued a written order providing a timeline for the lifting of the temporary provisions required in the first March 2020 order. Utilities were allowed to disconnect commercial and industrial customers and require deposits for new service as of July 25, 2020 and July 31, 2020, respectively. After August 15, 2020, utilities were no longer required to offer deferred payment arrangements to all customers. Additionally, utilities were authorized to reinstate late fees except for the period between the first order and this supplemental order. We resumed charging late payment fees in late August 2020. Late payment fees were not charged on outstanding balances that were billed between the first order and late August 2020.

Subsequent to the June 2020 order, the PSCW extended the moratorium on disconnections of residential customers until November 1, 2020. In accordance with Wisconsin regulations, utilities are generally not allowed to disconnect residential customers for non-payment during the winter moratorium, which began on November 1, 2020 and ended on April 15, 2021. Utilities were allowed to continue assessing late payment fees during the winter moratorium. On April 5, 2021, the PSCW issued a written order indicating that it would not extend the moratorium on disconnections further; therefore, utilities could begin disconnecting residential customers for non-payment after April 15, 2021. Utilities are required to offer a deferred payment arrangement to low-income residential customers prior to disconnecting service. The order also allowed us to resume charging late payment fees on the full balance of all outstanding arrears, regardless of the associated dates the service was provided, after April 15, 2021.

2022 Rates

In March 2021, we filed an application with the PSCW for the approval of certain accounting treatments that will allow us to maintain our current electric and natural gas base rates through 2022 and forego filing a rate case for one year. In connection with the request, we also entered into an agreement, dated March 23, 2021, with various stakeholders. Pursuant to the terms of the agreement, the stakeholders fully supported the application. In September 2021, the PSCW issued a written order approving the application.

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The final order reflects the following:

•We will amortize, in 2022, certain previously deferred balances to offset approximately half of our forecasted revenue deficiency.

•We will defer any increases in tax expense due to changes in tax law that occur in 2021 and/or 2022.

•We will maintain our earnings sharing mechanism for 2022, with modification. The earnings sharing mechanism was modified to authorize us to retain 100% of the first 15 basis points of earnings above our currently authorized ROE. This modification expires on December 31, 2022. The earnings sharing mechanism otherwise remains as previously authorized.

•We will file a full 2023-2024 test-year rate case no later than May 1, 2022.

2020 and 2021 Rates

In March 2019, we filed an application with the PSCW to increase our retail electric and natural gas rates, effective January 1, 2020. In August 2019, we filed an application with the PSCW for approval of a settlement agreement entered into with certain intervenors to resolve several outstanding issues in our rate case. In December 2019, the PSCW issued a written order that approved the settlement agreement without material modification and addressed the remaining outstanding issues that were not included in the settlement agreement. The new rates were effective January 1, 2020. The final order reflected the following:

2020 Effective rate increase
Electric (1) (2)	$	15.8	million	/	1.6%
Gas (3)	$	4.3	million	/	1.4%
ROE	10.0%
Common equity component average on a financial basis	52.5%

(1)    Amount is net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impacts. The rate order reflected the majority of the unprotected deferred tax benefits from the Tax Legislation being amortized over two years. Approximately $11 million of tax benefits were amortized in 2020 and approximately $39 million were amortized in 2021. Unprotected deferred tax benefits by their nature are eligible to be returned to customers in a manner and timeline determined to be appropriate by the PSCW.

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

(3)    Amount is net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impacts. The rate order reflected all of the unprotected deferred tax benefits from the Tax Legislation being amortized evenly over four years, which results in approximately $5 million of previously deferred tax benefits being amortized each year. Unprotected deferred tax benefits by their nature are eligible to be returned to customers in a manner and timeline determined to be appropriate by the PSCW.

Our rate order allows us to collect the previously deferred revenue requirement for ReACT™ costs above the authorized $275.0 million level. The total cost of the ReACT™ project was $342 million. This regulatory asset is being collected from customers over eight years.

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

NOTE 24—OTHER INCOME, NET

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

(in millions)	2021		2020		2019
Non-service components of net periodic benefit costs	$	26.8	$	16.7	$	18.0
AFUDC – Equity	9.0		11.8		5.7
Other, net	2.4		2.9		15.9
Other income, net	$	38.2	$	31.4	$	39.6

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NOTE 25—NEW ACCOUNTING PRONOUNCEMENTS

Simplifying the Accounting for Income Taxes

In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes. The new standard removes certain exceptions for performing intraperiod allocation and calculating income taxes in interim periods and also adds guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. The guidance was effective for annual and interim periods beginning after December 15, 2020. The adoption of ASU 2019-12, effective January 1, 2021, did not have a significant impact on our financial statements and related disclosures.

Reference Rate Reform

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, 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 1) the types of assistance received, 2) an entity’s accounting for the assistance, and 3) 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 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. 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.

Management's Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2021.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

This Annual Report on Form 10-K does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by our independent registered public accounting firm pursuant to rules of the SEC that permit us to provide only management's report in this annual report.

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 fourth quarter of 2021 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANT

Omitted pursuant to General Instruction I(2)c.

ITEM 11. EXECUTIVE COMPENSATION

Omitted pursuant to General Instruction I(2)c.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Omitted pursuant to General Instruction I(2)c.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Omitted pursuant to General Instruction I(2)c.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The following is a summary of the fees for professional services provided to us by Deloitte & Touche LLP in 2021 and 2020:

Fees	2021		2020
Audit fees (1)	$	968,911	$	877,176
Tax fees	—		—
All other fees (2)	908		673
Total fees	$	969,819	$	877,849

(1)    Audit fees. Consists of aggregate fees for the audits of the annual financial statements and reviews of the interim condensed financial statements included in quarterly reports. Audit fees also include services that are normally provided by Deloitte & Touche LLP in connection with statutory and regulatory filings or engagements, including comfort letters, consents, and other services related to SEC matters, and consultations arising during the course of the audits and reviews concerning financial accounting and reporting standards.

(2)    All other fees. Consists of fees for services provided to us by Deloitte & Touche LLP for products and services other than the services reported above. All Other Fees relate to utility training seminars and a subscription cost for the use of a Deloitte & Touche LLP accounting research tool.

No fees were paid to Deloitte & Touche LLP pursuant to the "de minimus" exception to the pre-approval policy permitted under the Exchange Act.

Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Registered Public Accounting Firm

The Audit and Oversight Committee (Audit Committee) of the Board of Directors of WEC Energy Group, which is comprised solely of independent directors, is responsible for reviewing and approving, in advance, all audit, audit-related, tax, and other services of the independent auditor. The Committee has the sole authority to select, evaluate, and where appropriate, terminate and replace the independent auditor.

The Audit Committee is committed to ensuring the independence of the auditor, both in appearance as well as in fact. In order to assure continuing auditor independence, the Audit Committee periodically considers whether there should be a regular rotation of the independent external audit firm. In addition, the Audit Committee is directly involved in the selection of the independent auditor's lead audit partner.

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Pre-Approval Process

Before engagement of the independent auditor for the next year's audit, the independent auditor will submit (i) a description of all services anticipated to be rendered during the following year, as well as an estimate of the fees for each of the services, for the Audit Committee to approve, and (ii) written confirmation that the performance of any non-audit services is permissible and will not impact the firm's independence. Annual pre-approval will be deemed effective for a period of twelve months from the date of the pre-approval, unless the Audit Committee specifically provides for a different period. A fee level will be established for all permissible, pre-approved non-audit services. Any additional audit service, audit related service, tax service and other service must also be pre-approved.

The Audit Committee delegated pre-approval authority to the Audit Committee's chair. The Audit Committee chair is required to report any pre-approval decisions at the next Audit Committee meeting. Under the pre-approval policy, the Audit Committee may not delegate to management its responsibilities to pre-approve services performed by the independent auditor.

Prohibited Activities are services prohibited by the SEC or by the Public Company Accounting Oversight Board to be performed by our independent auditor. These services include:

•bookkeeping or other services related to the accounting records or financial statements of the Company;

•financial information systems design and implementation;

•appraisal or valuation services, fairness opinions or contribution-in-kind reports;

•actuarial services;

•internal audit outsourcing services;

•management functions or human resources;

•broker-dealer, investment advisor or investment banking services;

•legal services and expert services unrelated to the audit;

•services provided for a contingent fee or commission; and

•services related to planning, marketing or opining in favor of the tax treatment of a confidential transaction or aggressive tax position transaction that was initially recommended, directly or indirectly, by the independent auditor.

In addition, the independent auditor may not provide any services, including personal financial counseling and tax services, to any officer or other employee of WEC Energy Group or its subsidiaries who serves in a financial reporting oversight role or to the chair of the Audit Committee or to an immediate family member of these individuals, including spouses, spousal equivalents, and dependents.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

1.	Financial Statements and Report of Independent Registered Public Accounting Firm Included in Part II of This Report
	Description	Page in 10-K
	Report of Independent Registered Public Accounting Firm (PCAOB No. 34).	48
	Income Statements for the three years ended December 31, 2021, 2020, and 2019.	50
	Balance Sheets as of December 31, 2021 and 2020.	51
	Statements of Cash Flows for the three years ended December 31, 2021, 2020, and 2019.	52
	Statements of Equity for the three years ended December 31, 2021, 2020, and 2019.	53
	Notes to Financial Statements.	54
2.	Financial Statement Schedules Included in Part IV of This Report
	Schedule II, Valuation and Qualifying Accounts, for the three years ended December 31, 2021, 2020, and 2019.	98
	Other schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto.
3.	Exhibits and Exhibit Index
	The following exhibits are filed or furnished with or incorporated by reference in the report with respect to Wisconsin Public Service Corporation (File No. 1-3016). An asterisk (*) indicates that the exhibit has previously been filed with the SEC and is incorporated herein by reference.

Number		Exhibit
3	Articles of Incorporation and By-laws
	3.1*	Restated Articles of Incorporation of Wisconsin Public Service Corporation ("WPS''), as effective May 26, 1972, and amended through May 31, 1988 and Articles of Amendment to Restated Articles of Incorporation of WPS dated June 9, 1993 (Exhibit 4.1 to Registration Statement on Form S-3, Reg. No. 333-182491, filed July 2, 2012).
	3.2*	By-Laws of WPS, as amended through June 29, 2015, Inclusive (Exhibit 3.2 to Form 10-K for the year ended December 31, 2015).
4	Instruments defining the rights of security holders, including indentures
	4.1*	Indenture, dated as of December 1, 1998, by and between WPS and U.S. Bank National Association (successor to Firstar Bank Milwaukee, N.A., National Association) (Exhibit 4A to Form 8-K filed December 18, 1998).
	4.2*	First Supplemental Indenture, dated as of December 1, 1998, by and between WPS and Firstar Bank Milwaukee, N.A., National Association (Exhibit 4C to Form 8-K filed December 18, 1998).
	4.3*	Fifth Supplemental Indenture, dated as of December 1, 2006, by and between WPS and U.S. Bank National Association (Exhibit 4.1 to Form 8-K filed November 30, 2006).

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	4.4*	Ninth Supplemental Indenture, dated as of December 1, 2012, by and between WPS and U.S. Bank National Association (Exhibit 4.1 to Form 8-K filed November 29, 2012).
	4.5*	Tenth Supplemental Indenture, dated as of November 1, 2013, by and between WPS and U.S. Bank National Association (Exhibit 4.1 to Form 8-K filed November 18, 2013).
	4.6*	Thirteenth Supplemental Indenture, dated as of August 14, 2019, by and between WPS and U.S. Bank National Association (Exhibit 4.1 to Form 8-K filed August 14, 2019).
	4.7*	Fourteenth Supplemental Indenture, dated as of November 18, 2021, by and between WPS and U.S. Bank National Association (Exhibit 4.1 to Form 8-K filed November 18, 2021).
		Certain agreements and instruments with respect to unregistered debt not exceeding 10% of the total assets of the Registrant have been omitted as permitted by related instructions. We agree pursuant to Item 601(b)(4) of Regulation S-K to furnish to the Securities and Exchange Commission, upon request, a copy of all such agreement and instruments.
10	Material Contracts
	10.1* #	Joint Plant Agreement by and between WPS and Dairyland Power Cooperative, dated as of November 23, 2004 (Exhibit 10.19 to Integrys Energy Group's and WPS's Form 10-K for the year ended December 31, 2004).
		Note: Certain compensatory plans, contracts or arrangements in which directors or executive officers of WPS participate are not filed as WPS exhibits in reliance on the exclusion in Item 601(b)(10)(iii)(C)(6) of Regulation S-K. WPS is a wholly-owned subsidiary of WEC Energy Group, Inc., Commission File No. 001-09057, and such compensatory plans, contracts or arrangements are filed as exhibits to WEC Energy Group’s periodic reports under the Securities Exchange Act of 1934.
23	Consents of Experts and Counsel
	23.1	Deloitte & Touche LLP – Milwaukee, WI, Consent of Independent Registered Public Accounting Firm for WPS.
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 File
	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

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	101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

#	Portions of this exhibit have been redacted and are subject to a confidential treatment request filed with the Secretary of the SEC pursuant to Rule 24b-2 under the Securities and Exchange Act of 1934, as amended. The redacted material was filed separately with the SEC.
	Exhibit 21 has been omitted pursuant to General Instruction I(2)b.

ITEM 16. FORM 10-K SUMMARY

None.

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SCHEDULE II

WISCONSIN PUBLIC SERVICE CORPORATION

VALUATION AND QUALIFYING ACCOUNTS

Allowance for Doubtful Accounts (in millions)	Balance at Beginning of Period		Expense (1)		Deferral		Net Write-offs (2)		Balance at End of Period
December 31, 2021	$	18.3	$	6.2	$	(7.0)	$	(6.4)	$	11.1
December 31, 2020	4.2		8.2		9.7		(3.8)		18.3
December 31, 2019	4.2		5.5		—		(5.5)		4.2

(1)    Net of recoveries.

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

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.

		WISCONSIN PUBLIC SERVICE CORPORATION
	By	/s/ SCOTT J. LAUBER
Date:	February 24, 2022	Scott J. Lauber
		Chairman of the Board, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

/s/ SCOTT J. LAUBER	February 24, 2022
Scott J. Lauber, Chairman of the Board, President, Chief Executive Officer and
Director -- Principal Executive Officer
/s/ XIA LIU	February 24, 2022
Xia Liu, Executive Vice President and Chief Financial
Officer and Director -- Principal Financial Officer
/s/ WILLIAM J. GUC	February 24, 2022
William J. Guc, Vice President, Controller, and Assistant
Corporate Secretary -- Principal Accounting Officer
/s/ MARGARET C. KELSEY	February 24, 2022
Margaret C. Kelsey, Director
/s/ GALE E. KLAPPA	February 24, 2022
Gale E. Klappa, Director
/s/ WILLIAM MASTORIS	February 24, 2022
William Mastoris, Director
/s/ PAUL J. SPICER	February 24, 2022
Paul J. Spicer, Director

Supplemental Information to be Furnished with Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act:

Wisconsin Public Service Corporation is not required to send an annual report or proxy statement to its sole shareholder, Integrys Holding, Inc., a wholly-owned subsidiary of WEC Energy Group, Inc., and will not prepare such a report after the filing of this Annual Report on Form 10-K for the year ended December 31, 2021. Accordingly, Wisconsin Public Service Corporation will not file such a report with the Securities and Exchange Commission.

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