# EDGAR Filing Document

**Accession Number:** 0000783325
**File Stem:** 0000107815-23-000121
**Filing Date:** 2023-3
**Character Count:** 364480
**Document Hash:** c73cea4be42d101d9d96e57bdbb88ec6
**Contains OCR:** False
**Source Format:** 

## Filing Content

## Filing Summary
**0000107815-23-000121.hdr.sgml**: 20230323

**ACCESSION NUMBER**: 0000107815-23-000121

**CONFORMED SUBMISSION TYPE**: ARS

**PUBLIC DOCUMENT COUNT**: 1

**CONFORMED PERIOD OF REPORT**: 20221231

**FILED AS OF DATE**: 20230323

**DATE AS OF CHANGE**: 20230323

**EFFECTIVENESS DATE**: 20230323

**FILER**: 

**COMPANY DATA:**
- **COMPANY CONFORMED NAME:** WEC ENERGY GROUP, INC.
- **CENTRAL INDEX KEY:** 0000783325
- **STANDARD INDUSTRIAL CLASSIFICATION:** ELECTRIC & OTHER SERVICES COMBINED [4931]
- **IRS NUMBER:** 391391525
- **STATE OF INCORPORATION:** WI
- **FISCAL YEAR END:** 1231

**FILING VALUES:**
- **FORM TYPE:** ARS
- **SEC ACT:** 1934 Act
- **SEC FILE NUMBER:** 001-09057
- **FILM NUMBER:** 23754566

**BUSINESS ADDRESS:**
- **STREET 1:** 231 W MICHIGAN ST
- **STREET 2:** P O BOX 1331
- **CITY:** MILWAUKEE
- **STATE:** WI
- **ZIP:** 53201
- **BUSINESS PHONE:** 414-221-2345

**MAIL ADDRESS:**
- **STREET 1:** 231 WEST MICHIGAN STREET
- **STREET 2:** P O BOX 1331
- **CITY:** MILWAUKEE
- **STATE:** WI
- **ZIP:** 53201

**FORMER COMPANY:**
- **FORMER CONFORMED NAME:** WISCONSIN ENERGY CORP
- **DATE OF NAME CHANGE:** 19920703

### Attached PDF Documents

**Attachment 1:** `wec2022ars.pdf`

WEC Energy Group

# FORWARD

2022 Annual Report
Notice of 2023 Annual Meeting and Proxy Statement

# 2022 Financial Highlights

## Earnings per share

![img-0.jpeg](img-0.jpeg)

## Financial Snapshot

(In millions, except per share data and percentages)

|  | 2022 | 2021 | Change |
| --- | --- | --- | --- |
| GAAP earnings | $1,408.1 | $1,300.3 | 8.3% |
| GAAP earnings per share | $4.45 | $4.11 | 8.3% |
| Dividends per share | $2.91 | $2.71 | 7.4% |
| Dividend yield | 3.1% | 2.8% |  |
| Diluted average shares outstanding | 316.1 | 316.3 |  |
| GAAP return on average common equity | 12.63% | 12.16% |  |
| Book value per share | $36.07 | $34.60 | 4.2% |
| Total assets | $41,872 | $38,989 | 7.4% |
| Market capitalization at year-end | $29,575 | $30,619 | -3.4% |
| Market price per share at year-end | $93.76 | $97.07 | -3.4% |
| S&P 500 price per share at year-end | $3,839.50 | $4,766.18 | -19.4% |

## Dividends per share

![img-1.jpeg](img-1.jpeg)

## Total Shareholder Return

WEC Energy Group consistently delivers among the best total returns in the industry. The illustration demonstrates our stock price appreciation plus the compound effect of dividend growth over the past decade.

![img-2.jpeg](img-2.jpeg)

A $100 investment at the end of 2012 grew to a total value of **$350**

![img-3.jpeg](img-3.jpeg)

Executive Chairman

President and Chief Executive Officer

## To our stockholders,

We're pleased to report that we delivered an exceptional year on virtually every meaningful measure - from employee safety to customer satisfaction to growth in earnings per share.

And looking ahead, we see a long runway of opportunity as we usher in a new era of affordable, reliable and clean energy.

Through the questions and answers below, we'd like to share with you a few key thoughts about our company and the future of the energy industry.

### What is important for shareholders to know about the company's performance in 2022?

**Gale:** Our focus on the fundamentals again resulted in a year of solid results. Our employees recorded their safest year since the company doubled its size through a major acquisition in 2015. We delivered record net income and earnings per share. And we exceeded our forecast.

In November, we updated our ESG Progress Plan - the largest five-year investment plan in our history - totaling $20.1 billion for efficiency, sustainability and growth. We expect the plan to drive earnings growth of 6.5 to 7 percent a year from 2023 through 2027.

A key part of the plan is a major commitment to renewable generation projects in both our regulated business and our infrastructure segment.

### Given the strong earnings growth and cash flow, what is your dividend outlook?

**Gale:** At its January meeting, our board of directors raised our quarterly cash dividend by 7.2 percent to a new annual rate of $3.12 per share. This marks the 20th consecutive year that our company will reward shareholders with higher dividends. We expect this dividend increase to rank in the top decile of our industry.

We continue to target a payout ratio of 65 to 70 percent of earnings. We're in the middle of the range now, so we expect our dividend growth will continue to be in line with the growth in earnings per share.

### What are you doing to assure reliability and strengthen your energy infrastructure?

**Scott:** We're dedicating significant resources in our capital investment plan to strengthen the reliability of our networks. Between 2023 and 2027, we expect to invest $3.6 billion to address aging electric infrastructure and further our system hardening. We also are continuing to upgrade our natural gas infrastructure. In Chicago, work continues on our long-term Safety Modernization Program, which is replacing old, corroding iron pipes with safe, state-of-the-art materials.

In addition to infrastructure upgrades, we have planned investments to meet the energy needs of our customers - particularly at times of peak energy demand. For example, construction is underway on two liquefied natural gas storage facilities to provide additional gas supply in Wisconsin - on track to go into service later this year and in 2024.

2022 ANNUAL REPORT | 1

## Where do you see growth in the WEC Infrastructure segment?

**Scott:** A key part of our capital plan is investing in renewable projects outside of our traditional footprint - projects that have long-term contracts with creditworthy customers such as Microsoft, Google and Verizon.

Just last month, we announced that our infrastructure group will acquire an 80 percent ownership interest in phase one of the Samson Solar Energy Center in northeast Texas. Samson I has a capacity of 250 megawatts. It entered commercial service in May 2022 and has a long-term power purchase agreement with AT&T. Pending regulatory approval, we plan to invest approximately $250 million early in 2023.

## With the evolution of the energy industry, what role are you playing in technology development?

**Gale:** We're active in exploring promising technologies that may help shape the future of clean energy. In February, we announced an important pilot project to test a new form of long-duration energy storage. This experiment will take place at our Valley Power Plant in Milwaukee. We're collaborating with EPRI, an independent energy research and development institute, and CMBlu Energy, the developer and manufacturer of the long-duration battery based in California and Germany.

This 1- to 2-megawatt-hour pilot project will be one of the first of its kind on the U.S. electric grid. The project will test the performance of the battery system, including discharge durations of five to 10 hours - up to twice as long as the typical batteries in use today.

**Scott:** And I'm pleased to share with you that the hydrogen pilot we outlined for you last year was completed successfully. Hydrogen and natural gas were tested in blends of up to 25/75 percent to power a reciprocating combustion engine - a modern generating unit that serves customers in the Upper Peninsula of Michigan. The results of this project are a strong indicator that this technology - which produces energy on demand - could run efficiently on very low- and no-carbon fuels.

EPRI will share a complete analysis of both projects with interested parties across the energy industry.

## Given the economic uncertainty we have seen in the past year, how well is WEC Energy Group positioned for a potential recession?

**Gale:** First, I would say that our management team has a strong track record of managing through the ups and downs of economic cycles. Our focus is on the fundamentals. On execution. On financial discipline. In addition, the economy in our region is remarkably diverse. These factors position us well for uncertain times.

As we move forward, we remain committed to a mission that matters - strengthening the fabric of the communities we serve, leading by example, and delivering affordable, reliable and clean energy to the millions of customers who depend on us every day.

Thank you for your confidence, your support and your investment in WEC Energy Group.

Sincerely,

Gale E. Klappa  
Executive Chairman

Scott J. Lauber  
President and  
Chief Executive Officer

March 3, 2023

2 | WEC ENERGY GROUP

## Shaping the future of clean energy

In 2022, in partnership with EPRI, we completed a pilot project - the first of its kind - blending hydrogen with natural gas at one of our modern generating units in Michigan's Upper Peninsula. Our research is providing the utility industry with valuable insight on this technology's potential.

*Emission levels were sampled throughout the pilot.*

2022 ANNUAL REPORT | 3

# An Energy Industry Leader

WEC Energy Group is one of the nation's leading energy companies, with the operational expertise and financial resources to meet the needs of customers across the Midwest.

![img-4.jpeg](img-4.jpeg)

We provide vital services to **4.6 million** customers in Wisconsin, Illinois, Michigan and Minnesota.

**71,700 miles** of electric distribution

**52,000 miles** of natural gas distribution and transmission

**7,700 megawatts** of power generating capacity

**7,000 employees**

WEC Infrastructure has acquired or agreed to acquire majority interests in eight wind farms and two solar energy facilities in the U.S. These resources will provide carbon-free energy for large customers outside of our traditional service area through long-term purchase power agreements.

Nearly

**$1.9 billion**

in projected investments between 2023-2027

4 | WEC ENERGY GROUP

WEC
Energy Group

# 2022 ANNUAL
FINANCIAL STATEMENTS
AND
REVIEW OF OPERATIONS

![img-5.jpeg](img-5.jpeg)

F-1

# TABLE OF CONTENTS

| F-3 | Glossary of Terms and Abbreviations |
| --- | --- |
| F-6 | Cautionary Statement Regarding Forward-Looking Information |
| F-8 | Business of the Company |
| F-9 | Management's Discussion and Analysis of Financial Condition and Results of Operations |
| F-38 | Quantitative and Qualitative Disclosures About Market Risk |
| F-39 | Consolidated Financial Statements |
| F-44 | Notes to Consolidated Financial Statements |
| F-100 | Reports of Independent Registered Public Accounting Firm |
| F-103 | Internal Control Over Financial Reporting |
| F-103 | Market for Our Common Equity and Related Stockholder Matters |
| F-104 | Performance Graph |
| F-105 | Board of Directors |
| F-106 | Officers |

WEC Energy Group

F-2

2022 Annual Financial Statements

# GLOSSARY OF TERMS AND ABBREVIATIONS

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

### Subsidiaries and Affiliates

| ATC | American Transmission Company LLC |
| --- | --- |
| ATC Holdco | ATC Holdco LLC |
| ATC Holding | ATC Holding LLC |
| Bishop Hill III | Bishop Hill Energy III LLC |
| Blooming Grove | Blooming Grove Wind Energy Center LLC |
| Bluewater | Bluewater Natural Gas Holding, LLC |
| Bluewater Gas Storage | Bluewater Gas Storage, LLC |
| Coyote Ridge | Coyote Ridge Wind, LLC |
| Integrys | Integrys Holding, Inc. |
| Jayhawk | Jayhawk Wind, LLC |
| MERC | Minnesota Energy Resources Corporation |
| MGU | Michigan Gas Utilities Corporation |
| NSG | North Shore Gas Company |
| PDL | WPS Power Development, LLC |
| PELLC | Peoples Energy, LLC |
| PGL | The Peoples Gas Light and Coke Company |
| Tatanka Ridge | Tatanka Ridge Wind, LLC |
| Thunderhead | Thunderhead Wind Energy LLC |
| UMERC | Upper Michigan Energy Resources Corporation |
| Upstream | Upstream Wind Energy LLC |
| WBS | WEC Business Services LLC |
| WE | Wisconsin Electric Power Company |
| We Power | W.E. Power, LLC |
| WEC Energy Group | WEC Energy Group, Inc. |
| WECC | Wisconsin Energy Capital Corporation |
| WECI | WEC Infrastructure LLC |
| WECI Wind Holding I | WEC Infrastructure Wind Holding I LLC |
| WECI Wind Holding II | WEC Infrastructure Wind Holding II LLC |
| WEPCo Environmental Trust | WEPCo Environmental Trust Finance I, LLC |
| WG | Wisconsin Gas LLC |
| Wispark | Wispark LLC |
| Wisvest | Wisvest LLC |
| WPS | Wisconsin Public Service Corporation |
| 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 |
| ICC | Illinois Commerce Commission |
| IRS | United States Internal Revenue Service |
| MPSC | Michigan Public Service Commission |
| MPUC | Minnesota Public Utilities Commission |
| 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 |

WEC Energy Group

F-3

2022 Annual Financial Statements

| CWIP | Construction Work in Progress |
| --- | --- |
| FASB | Financial Accounting Standards Board |
| GAAP | Generally Accepted Accounting Principles |
| LIFO | Last-In, First-Out |
| OPEB | Other Postretirement Employee Benefits |
| VIE | Variable Interest Entity |

#### 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 |
| CASAC | Clean Air Scientific Advisory Committee |
| CO 2 | Carbon Dioxide |
| ELG | Steam Electric Effluent Limitation Guidelines |
| FGD | Flue Gas Desulfurization |
| GHG | Greenhouse Gas |
| NAAQS | National Ambient Air Quality Standards |
| NOPP | Notice of Planned Participation |
| NOV | Notice of Violation |
| NOx | Nitrogen Oxide |
| NSPS | New Source Performance Standards |
| PCB | Polychlorinated Biphenyl |
| PM | Particulate Matter |
| SO 2 | Sulfur Dioxide |
| WOTUS | Waters of the United States |
| WPDES | Wisconsin Pollutant Discharge Elimination System |

#### Measurements

| Bcf | Billion Cubic Feet |
| --- | --- |
| Dth | Dekatherm |
| MDth | One Thousand Dekatherms |
| MW | Megawatt |
| MWh | Megawatt-hour |
| μg/m3 | Micrograms Per Cubic Meter |

#### Other Terms and Abbreviations

| 2007 Junior Notes | WEC Energy Group, Inc.'s 2007 Junior Subordinated Notes Due 2067 |
| --- | --- |
| AD/CVD | Antidumping and Countervailing Duties |
| AMI | Advanced Metering Infrastructure |
| ARR | Auction Revenue Right |
| Badger Hollow I | Badger Hollow Solar Park I |
| Badger Hollow II | Badger Hollow Solar Park II |
| CFR | Code of Federal Regulations |
| CIP | Conservation Improvement Program |
| Compensation Committee | Compensation Committee of the Board of Directors of WEC Energy Group, Inc. |
| COVID-19 | Coronavirus Disease - 2019 |
| D.C. Circuit Court of Appeals | United States Court of Appeals for the District of Columbia Circuit |
| Darien | Darien Solar-Battery Park |
| DER | Distributed Energy Resource |
| DRER | Dedicated Renewable Energy Resource |
| ERGS | Elm Road Generating Station |
| ER 1 | Elm Road Generating Station Unit 1 |
| ER 2 | Elm Road Generating Station Unit 2 |
| ESG Progress Plan | WEC Energy Group's Capital Investment Plan for Efficiency, Sustainability, and Growth for 2023-2027 |
| ETB | Environmental Trust Bond |
| EV | Electric Vehicle |
| Exchange Act | Securities Exchange Act of 1934, as amended |

WEC Energy Group

F-4

2022 Annual Financial Statements

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 |
| Holding Company Act | Wisconsin Utility Holding Company Act |
| IRA | Inflation Reduction Act |
| ITC | Investment Tax Credit |
| LIBOR | London Interbank Offered Rate |
| LMP | Locational Marginal Price |
| LNG | Liquefied Natural Gas |
| Maple Flats | Maple Flats Solar Energy Center LLC |
| MISO | Midcontinent Independent System Operator, Inc. |
| MISO Energy Markets | MISO Energy and Operating Reserves Market |
| NYMEX | New York Mercantile Exchange |
| OCPP | Oak Creek Power Plant |
| OC 7 | Oak Creek Power Plant Unit 7 |
| OC 8 | Oak Creek Power Plant Unit 8 |
| Omnibus Stock Incentive Plan | WEC Energy Group Omnibus Stock Incentive Plan, Amended and Restated, Effective as of May 6, 2021 |
| Paris | Paris Solar-Battery Park |
| PIPP | Presque Isle Power Plant |
| Point Beach | Point Beach Nuclear Power Plant |
| PPA | Power Purchase Agreement |
| PSB | Public Service Building |
| PTC | Production Tax Credit |
| PUHCA 2005 | Public Utility Holding Company Act of 2005 |
| PWGS | Port Washington Generating Station |
| PWGS 1 | Port Washington Generating Station Unit 1 |
| PWGS 2 | Port Washington Generating Station Unit 2 |
| QIP | Qualifying Infrastructure Plant |
| RCC | Replacement Capital Covenant (dated May 11, 2007) |
| REC | Renewable Energy Certificate |
| Red Barn | Red Barn Wind Park |
| RICE | Reciprocating Internal Combustion Engine |
| RNG | Renewable Natural Gas |
| ROE | Return on Equity |
| RTO | Regional Transmission Organization |
| S&P | Standard & Poor's |
| Samson I | Samson I Solar Energy Center LLC |
| Sapphire Sky | Sapphire Sky Wind Energy LLC |
| SIP | State Implementation Plan |
| SMP | Safety Modernization Program |
| SOFR | Secured Overnight Financing Rate |
| SPC | COVID-19 Special Purpose Charge |
| SPP | Southwest Power Pool, Inc. |
| SSR | System Support Resource |
| Supreme Court | United States Supreme Court |
| Tax Legislation | Tax Cuts and Jobs Act of 2017 |
| TCR | Transmission Congestion Right |
| Tilden | Tilden Mining Company |
| TPTFA | Third-Party Transaction Fee Adjustment |
| Two Creeks | Two Creeks Solar Park |
| UFLPA | Uyghur Forced Labor Prevention Act |
| VAPP | Valley Power Plant |
| West Riverside | West Riverside Energy Center |
| Whitewater | Whitewater Cogeneration Facility |
| WRO | Withhold Release Order |

WEC Energy Group

F-5

2022 Annual Financial Statements

# CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

Forward-looking statements are subject to a number of risks and uncertainties that could cause our actual results to differ materially from those expressed or implied in the statements. These risks and uncertainties include those described below:

- • Factors affecting utility and non-utility energy infrastructure operations such as catastrophic weather-related damage, environmental incidents, unplanned facility outages and repairs and maintenance, and electric transmission or natural gas pipeline system constraints;
- • Factors affecting the demand for electricity and natural gas, including political or regulatory developments, varying, adverse, or unusually severe weather conditions, including those caused by climate change, changes in economic conditions, customer growth and declines, commodity prices, energy conservation efforts, and continued adoption of distributed generation by customers;
- • The timing, resolution, and impact of rate cases and negotiations, including recovery of deferred and current costs and the ability to earn a reasonable return on investment, and other regulatory decisions impacting our regulated operations;
- • The impact of federal, state, and local legislative and/or regulatory changes, including changes in rate-setting policies or procedures, 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, electrification initiatives and other efforts to reduce the use of natural gas, and tax laws, including those that affect our ability to use PTCs and ITCs;
- • Federal, state, and local legislative and regulatory changes relating to the environment, including climate change and other environmental regulations impacting generation facilities and renewable energy standards, the enforcement of these laws and regulations, changes in the interpretation of regulations or permit conditions by regulatory agencies, and the recovery of associated remediation and compliance costs;
- • The ability to obtain and retain customers, including wholesale customers, due to increased competition in our electric and natural gas markets from retail choice and alternative electric suppliers, and continued industry consolidation;
- • The timely completion of capital projects within budgets and the ability to recover the related costs through rates;
- • The impact of changing expectations and demands of our customers, regulators, investors, and other stakeholders, including heightened emphasis on environmental, social, and governance concerns;
- • 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 (including disruptions from rail congestion), inflation, and other factors;
- • The impact of public health crises, including epidemics and pandemics, on our business functions, financial condition, liquidity, and results of operations;
- • Factors affecting the implementation of our CO2 emission and/or methane emission reduction goals and opportunities and actions related to those goals, including related regulatory decisions, the cost of materials, supplies, and labor, technology advances, the feasibility of competing generation projects, and our ability to execute our capital plan;
- • The financial and operational feasibility of taking more aggressive action to further reduce GHG emissions in order to limit future global temperature increases;
- • The risks associated with inflation and changing commodity prices, including natural gas and electricity;
- • The availability and cost of sources of natural gas and other fossil fuels, purchased power, materials needed to operate environmental controls at our electric generating facilities, or water supply due to high demand, shortages, transportation problems, nonperformance by electric energy or natural gas suppliers under existing power purchase or natural gas supply contracts, or other developments;
- • Any impacts on the global economy, supply chains and fuel prices, generally, from the ongoing conflict between Russia and Ukraine and related sanctions;

WEC Energy Group

F-6

2022 Annual Financial Statements

- • Changes in credit ratings, interest rates, and our ability to access the capital markets, caused by volatility in the global credit markets, our capitalization structure, and market perceptions of the utility industry, us, or any of our subsidiaries;
- • Changes in the method of determining LIBOR or the replacement of LIBOR with an alternative reference rate;
- • Costs and effects of litigation, administrative proceedings, investigations, settlements, claims, and inquiries;
- • The direct or indirect effect on our business resulting from terrorist or other physical attacks and cyber security intrusions, as well as the threat of such incidents, including the failure to maintain the security of personally identifiable information, the associated costs to protect our utility assets, technology systems, and personal information, and the costs to notify affected persons to mitigate their information security concerns and to comply with state notification laws;
- • Restrictions imposed by various financing arrangements and regulatory requirements on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans or advances, that could prevent us from paying our common stock dividends, taxes, and other expenses, and meeting our debt obligations;
- • The risk of financial loss, including increases in bad debt expense, associated with the inability of our customers, counterparties, and affiliates to meet their obligations;
- • Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading markets and fuel suppliers and transporters;
- • The financial performance of ATC and its corresponding contribution to our earnings;
- • The investment performance of our employee benefit plan assets, as well as unanticipated changes in related actuarial assumptions, which could impact future funding requirements;
- • Factors affecting the employee workforce, including loss of key personnel, internal restructuring, work stoppages, and collective bargaining agreements and negotiations with union employees;
- • Advances in technology, and related legislation or regulation supporting the use of that technology, that result in competitive disadvantages and create the potential for impairment of existing assets;
- • Risks related to our non-utility renewable energy facilities, including unfavorable weather, changes in the financial performance and/or creditworthiness of counterparties to the off-take agreements, the ability to replace expiring PPAs under acceptable terms, the availability of reliable interconnection and electricity grids, and exposure to the rules and procedures of the power markets in which these facilities are located;
- • The risk associated with the values of goodwill and other long-lived assets, including intangible assets, and equity method investments, and their possible impairment;
- • Potential business strategies to acquire and dispose of assets or businesses, which cannot be assured to be completed timely or within budgets, and legislative or regulatory restrictions or caps on non-utility acquisitions, investments or projects, including the State of Wisconsin's public utility holding company law;
- • The timing and outcome of any audits, disputes, and other proceedings related to taxes;
- • The effect of accounting pronouncements issued periodically by standard-setting bodies; and
- • Other considerations disclosed elsewhere herein and in other reports we file with the SEC or in other publicly disseminated written documents.

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

WEC Energy Group

F-7

2022 Annual Financial Statements

# BUSINESS OF THE COMPANY

WEC Energy Group, Inc. was incorporated in the state of Wisconsin in 1981 and became a diversified holding company in 1986. We maintain our principal executive offices in Milwaukee, Wisconsin. On June 29, 2015, Wisconsin Energy Corporation acquired 100% of the outstanding common shares of Integrys Energy Group and changed its name to WEC Energy Group, Inc.

In this report, when we refer to 'WEC Energy Group,' 'the Company,' 'us,' 'we,' 'our,' or 'ours,' we are referring to WEC Energy Group, Inc. and all of its subsidiaries. The term 'utility' refers to the regulated activities of the electric and natural gas utility companies, while the term 'non-utility' refers to the activities of the electric and natural gas companies that are not regulated, as well as We Power and Bluewater. The term 'nonregulated' refers to activities at WECI, which holds interests in several renewable generating facilities, and our Corporate and Other Segment.

Our wholly owned subsidiaries are primarily engaged in the business of providing regulated electricity service in Wisconsin and Michigan; regulated natural gas service in Wisconsin, Illinois, Michigan, and Minnesota; and nonregulated renewable energy. In addition, we have an approximate 60% equity interest in ATC, an electric transmission company operating primarily in four states. At December 31, 2022, we conducted our operations in the six reportable segments discussed below.

## WISCONSIN SEGMENT

The Wisconsin segment includes the electric and natural gas utility operations of WE, WPS, WG, and UMERC. At December 31, 2022, these companies served approximately 1,650,800 electric customers and 1,501,800 natural gas customers. This segment also includes steam service to approximately 400 WE steam customers in metropolitan Milwaukee, Wisconsin.

## ILLINOIS SEGMENT

The Illinois segment includes the natural gas utility operations of PGL and NSG. The approximately 1,048,400 natural gas customers served by PGL and NSG at December 31, 2022, were located in Chicago and the northern suburbs of Chicago. PGL also owns and operates a 38.8 billion-cubic-foot natural gas storage field in central Illinois.

## OTHER STATES SEGMENT

The other states segment includes the natural gas utility operations of MERC and MGU, as well as the non-utility operations of MERC related to servicing appliances for customers. These companies served approximately 431,500 natural gas customers at December 31, 2022, with MERC serving customers in various cities and communities throughout Minnesota and MGU serving customers in southern and western Michigan.

## ELECTRIC TRANSMISSION SEGMENT

The electric transmission segment includes our approximate 60% ownership interest in ATC, an electric transmission company regulated by the FERC and certain state regulatory commissions. ATC owns, maintains, monitors, and operates electric transmission systems in Wisconsin, Michigan, Illinois, and Minnesota.

In addition, we own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint.

## NON-UTILITY ENERGY INFRASTRUCTURE SEGMENT

The non-utility energy infrastructure segment includes We Power, Bluewater, and WECI. We Power, through wholly owned subsidiaries, owns and leases certain generating facilities to WE. Bluewater owns natural gas storage facilities in southeastern Michigan and provides natural gas storage and hub services for WE, WPS, and WG. As of December 31, 2022, WECI had controlling ownership interests in seven non-utility wind generating facilities. These wind facilities have a combined nameplate generating capacity of 1,333.7 MWs. In February 2023, WECI completed the acquisitions of Sapphire Sky, a commercially operational 250 MW wind generating facility in Illinois, as well as Samson I, a commercially operational 250 MW solar generating facility in Texas. WECI has also entered into an agreement to acquire an additional solar generating facility currently under construction in Illinois. See Note 2, Acquisitions, for more information on many of these renewable generating facilities.

## CORPORATE AND OTHER SEGMENT

The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, and the PELLC holding company, as well as the operations of Wispark and WBS. This segment also includes Wisvest, WECC, and PDL, which no longer have significant operations.

Wispark develops and invests in real estate, primarily in southeastern Wisconsin. WBS is a wholly owned centralized service company that provides administrative and general support services to our regulated entities, as well as certain administrative and support services to our nonregulated entities.

WEC Energy Group

F-8

2022 Annual Financial Statements

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

## CORPORATE DEVELOPMENTS

### INTRODUCTION

We are a diversified holding company with natural gas and electric utility operations (serving customers in Wisconsin, Illinois, Michigan, and Minnesota), an approximately 60% equity ownership interest in American Transmission Company LLC (ATC) (a for-profit electric transmission company regulated by the Federal Energy Regulatory Commission and certain state regulatory commissions), and non-utility energy infrastructure operations through W.E. Power LLC (which owns generation assets in Wisconsin), Bluewater Natural Gas Holding LLC (which owns underground natural gas storage facilities in Michigan), and WEC Infrastructure LLC (WECI), which holds ownership interests in several renewable generating facilities.

### CORPORATE STRATEGY

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

Throughout our strategic planning process, we take into account important developments, risks and opportunities, including new technologies, customer preferences and affordability, energy resiliency efforts, and sustainability. We published the results of a priority sustainability issue assessment in 2020, identifying the issues that are most important to our company and its stakeholders over the short and long terms. Our risk and priority assessments have formed our direction as a company.

### Creating a Sustainable Future

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

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

As part of our path toward these goals, we are exploring co-firing with natural gas at our ERGS coal-fired units. By the end of 2030, we expect to use coal as a backup fuel only, and we believe we will be in a position to eliminate coal as an energy source by the end of 2035.

We already have retired more than 1,800 megawatts (MW) of coal-fired generation since the beginning of 2018, which included the 2019 retirement of the Presque Isle power plant as well as the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater Unit 4 generating units. See Note 6, Regulatory Assets and Liabilities, for more information related to these power plant retirements. Through our ESG Progress Plan, we expect to retire approximately 1,600 MW of additional fossil-fueled generation by the end of 2026, which includes the planned retirement in 2024-2025 of Oak Creek Power Plant Units 5-8 and the planned retirement in 2026 of jointly-owned Columbia Units 1-2. See Note 7, Property, Plant, and Equipment, for more information related to these planned power plant retirements.

In addition to retiring these older, fossil-fueled plants, we expect to invest approximately $5.4 billion from 2023-2027 in regulated renewable energy in Wisconsin. Our plan is to replace a portion of the retired capacity by building and owning zero-carbon-emitting renewable generation facilities that are anticipated to include the following new investments:

- 700 MW of battery storage; and

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2022 Annual Financial Statements

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

- 100 MW of reciprocating internal combustion engine (RICE) natural gas-fueled generation; and
- the planned purchase of up to 200 MW of capacity in the West Riverside Energy Center - a combined cycle natural gas plant recently completed by Alliant Energy in Wisconsin.

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

In December 2018, WE received approval from the PSCW for two renewable energy pilot programs. The Solar Now pilot is expected to add a total of 35 MW of solar generation to WE's portfolio, allowing non-profit and governmental entities, as well as commercial and industrial customers, to site utility owned solar arrays on their property. Under this program, WE has energized 24 Solar Now projects and currently has another five under construction, together totaling more than 30 MW. The second program, the Dedicated Renewable Energy Resource (DRER) pilot, would allow large commercial and industrial customers to access renewable resources that WE would operate, adding up to 150 MW of renewables to WE's portfolio. The DRER pilot would help these larger customers meet their sustainability and renewable energy goals.

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

We also continue to reduce methane emissions by improving our natural gas distribution system. We set a target across our natural gas distribution operations to achieve net-zero methane emissions by the end of 2030. We plan to achieve our net-zero goal through an effort that includes both continuous operational improvements and equipment upgrades, as well as the use of renewable natural gas (RNG) throughout our utility systems. In 2022, we received approval from the PSCW for our RNG pilots. We have since signed our first five contracts for RNG for our natural gas distribution business, which will be transporting the output of local dairy farms onto our gas distribution system. The RNG supplied will directly replace higher-emission methane from natural gas that would have entered our pipes. Our first five contracts bring us to a total of 1 Bcf of RNG planned to enter our system. We expect to have RNG flowing to our distribution network in 2023, supporting our goal to reduce methane emissions.

As part of our effort to look for new opportunities in sustainable energy, during 2022 we completed testing the effects of blending hydrogen, a clean generating fuel, with natural gas at one of our RICE generating units in the Upper Peninsula of Michigan. We partnered with the Electric Power Research Institute (EPRI) in this research that could help create another viable option for decarbonizing the economy. We are still evaluating the data; however, our initial findings indicate that all project measures exceeded our expectations. The results of this testing continue to be analyzed and will be shared more broadly when complete.

In 2023, we are planning a pilot program with EPRI and CMBlu Energy, a Germany-based designer and manufacturer, to test a new form of long-duration energy storage on the U.S. electric grid. The program will test battery system performance, including the ability to store and discharge energy for up to twice as long as the typical lithium-ion batteries in use today. The pilot is planned for the fourth-quarter of 2023.

## Reliability

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

Below are a few examples of reliability projects that are proposed, currently underway, or recently completed.

- WE and Wisconsin Gas LLC (WG) have received approval to each construct their own liquefied natural gas (LNG) facility to meet anticipated peak demand. Commercial operation of the WE and WG LNG facilities is targeted for the end of 2023 and 2024, respectively.
- The Peoples Gas Light and Coke Company continues to work on its Safety Modernization Program, which primarily involves replacing old iron pipes and facilities in Chicago's natural gas delivery system with modern polyethylene pipes to reinforce the long-term safety and reliability of the system.
- Our utilities continue to upgrade their electric and natural gas distribution systems to enhance reliability.

We expect to spend approximately $3.6 billion from 2023 to 2027 on reliability related projects with continued investment over the next decade. For more details, see Liquidity and Capital Resources - Cash Requirements - Significant Capital Projects.

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2022 Annual Financial Statements

## Operating Efficiency

We continually look for ways to optimize the operating efficiency of our company and will continue to do so under the ESG Progress Plan. For example, we are making progress on our Advanced Metering Infrastructure program, replacing aging meter-reading equipment on both our network and customer property. An integrated system of smart meters, communication networks, and data management programs enables two-way communication between our utilities and our customers. This program reduces the manual effort for disconnects and reconnects and enhances outage management capabilities.

We continue to focus on integrating the resources of all our businesses and finding the best and most efficient processes.

## Financial Discipline

A strong adherence to financial discipline is essential to meeting our earnings projections and maintaining a strong balance sheet, stable cash flows, a growing dividend, and quality credit ratings.

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

Our investment focus remains in our regulated utility and non-utility energy infrastructure businesses, as well as our investment in ATC. In our non-utility energy infrastructure segment, we have acquired or agreed to acquire majority interests in eight wind parks and two solar parks, with total available capacity of more than 2,000 MW. These renewable energy assets represent more than $2.9 billion in committed investments and have long-term agreements to serve customers outside our traditional service areas. Production tax credits from these renewable investments reduce our cash tax expense. In addition, we anticipate that credits generated in 2023 and beyond will be eligible to be transferred to third parties in exchange for cash. See Note 2, Acquisitions, for information on recent and pending transactions.

We expect total capital expenditures for our regulated utility and non-utility energy infrastructure businesses to be approximately $18.1 billion from 2023 to 2027. In addition, we currently forecast that our share of ATC's projected capital expenditures over the next five years will be approximately $2.0 billion. Specific projects included in the $20.1 billion ESG Progress Plan are discussed in more detail below under Liquidity and Capital Resources - Cash Requirements - Significant Capital Projects.

## Exceptional Customer Care

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

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

## Safety

Safety is one of our core values and a critical component of our culture. We are committed to keeping our employees and the public safe through a comprehensive corporate safety program that focuses on employee engagement and elimination of at-risk behaviors.

Under our 'Target Zero' mission, we have an ultimate goal of zero incidents, accidents, and injuries. Management and union leadership work together to reinforce the Target Zero culture. We set annual goals for safety results as well as measurable leading indicators, in order to raise awareness of at-risk behaviors and situations and guide injury-prevention activities. All employees are encouraged to report unsafe conditions or incidents that could have led to an injury. Injuries and tasks with high levels of risk are assessed, and findings and best practices are shared across our companies.

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

## RESULTS OF OPERATIONS

The following discussion and analysis of our Results of Operations includes comparisons of our results for the year ended December 31, 2022 with the year ended December 31, 2021. For a similar discussion that compares our results for the year ended December 31, 2021 with the year ended December 31, 2020, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations in Part II of our 2021 Annual Report on Form 10-K, which was filed with the SEC on February 24, 2022.

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2022 Annual Financial Statements

## CONSOLIDATED EARNINGS

The following table compares our consolidated results for the year ended December 31, 2022 with the year ended December 31, 2021, including favorable or better, "B," and unfavorable or worse, "W," variances:

| (in millions, except per share data) | Year Ended December 31 |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | B (W) |
| Wisconsin | $758.4 | $706.5 | $51.9 |
| Illinois | 226.9 | 223.0 | 3.9 |
| Other states | 39.7 | 35.8 | 3.9 |
| Electric transmission | 129.5 | 106.3 | 23.2 |
| Non-utility energy infrastructure | 324.4 | 279.2 | 45.2 |
| Corporate and other | (70.8) | (50.5) | (20.3) |
| Net income attributed to common shareholders | $1,408.1 | $1,300.3 | $107.8 |
| Diluted earnings per share | $4.45 | $4.11 | $0.34 |

Earnings increased $107.8 million during 2022, compared with 2021. The significant factors impacting the $107.8 million increase in earnings were:

- A $51.9 million increase in net income attributed to common shareholders at the Wisconsin segment, driven by lower operation and maintenance expense, largely due to the amortization of certain regulatory liabilities to offset a portion of our 2022 forecasted revenue deficiencies. The amortization was approved by the PSCW in order to forego filing for 2022 base rate increases. An increase in natural gas margins related to higher retail sales volumes, as well as higher net credits from the non-service components of our net periodic pension and OPEB costs, also contributed to the increase in earnings. These increases in earnings were partially offset by a negative year-over-year impact from collections of fuel and purchased power costs, higher property and revenue taxes, and higher depreciation and amortization.
- A $45.2 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by an increase in PTCs during 2022, primarily due to the Jayhawk wind park that achieved commercial operation in December 2021, higher generation at our other wind parks, and an increase in the PTC rate related to the PTC inflation adjustment issued by the IRS. In addition, Upstream recognized revenue during 2022 related to market settlements it received from SPP in February 2021. Due to a complaint filed with the FERC, the revenue related to these settlements could not be recognized until the FERC issued an order denying the complaint in the first quarter of 2022. A positive impact from a sharing arrangement with one of our Blooming Grove customers, resulting from strong energy prices, also contributed to the increase in earnings.
- A $23.2 million increase in net income attributed to common shareholders at the electric transmission segment, primarily due to the impact of the D.C. Circuit Court of Appeals opinion issued in August 2022 addressing complaints related to ATC's ROE and the year-over-year impact of a goodwill impairment recorded during the fourth quarter of 2021.

These increases in earnings were partially offset by a $20.3 million increase in the net loss attributed to common shareholders at the corporate and other segment, driven by net losses from the investments held in the Integrys rabbi trust during 2022, compared with net gains during 2021. The gains and losses from the investments held in the rabbi trust partially offset the changes in benefit costs related to deferred compensation, which are included in other operation and maintenance expense in our operating segments. See Note 17, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust. A decrease in earnings from our equity method investments in technology and energy-focused investment funds and higher interest expense also contributed to the higher net loss. Partially offsetting these negative impacts was the year-over-year impact from the loss on debt extinguishment recorded in 2021.

### Non-GAAP Financial Measures

The discussions below address the contribution of each of our segments to net income attributed to common shareholders. The discussions include financial information prepared in accordance with GAAP, as well as electric margins and natural gas margins, which are not measures of financial performance under GAAP. Electric margins (electric revenues less fuel and purchased power costs) and natural gas margins (natural gas revenues less cost of natural gas sold) are non-GAAP financial measures because they exclude other operation and maintenance expense, depreciation and amortization, and property and revenue taxes.

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

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of operating

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2022 Annual Financial Statements

performance. The following table shows operating income by segment for our utility operations during years ended December 31, 2022 and 2021:

| (in millions) | Year Ended December 31 |  |
| --- | --- | --- |
|  | 2022 | 2021 |
| Wisconsin | $1,463.1 | $1,309.3 |
| Illinois | 369.7 | 361.6 |
| Other states | 64.2 | 52.4 |

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

## WISCONSIN SEGMENT CONTRIBUTION TO NET INCOME ATTRIBUTED TO COMMON SHAREHOLDERS

The Wisconsin segment's contribution to net income attributed to common shareholders for the year ended December 31, 2022 was $758.4 million, representing a $51.9 million, or 7.3%, increase over the prior year. The increase in earnings was driven by lower operation and maintenance expense, largely due to the amortization of certain regulatory liabilities to offset a portion of our 2022 forecasted revenue deficiencies. The amortization was approved by the PSCW in order to forego filing for 2022 base rate increases. An increase in natural gas margins related to higher retail sales volumes, as well as higher net credits from the non-service components of our net periodic pension and OPEB costs, also contributed to the increase in earnings. These increases in earnings were partially offset by a negative year-over-year impact from collections of fuel and purchased power costs, higher property and revenue taxes, and higher depreciation and amortization.

| (in millions) | Year Ended December 31 |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | B (W) |
| Electric revenues | $4,971.8 | $4,538.6 | $433.2 |
| Fuel and purchased power | 1,881.4 | 1,488.2 | (393.2) |
| Total electric margins | 3,090.4 | 3,050.4 | 40.0 |
| Natural gas revenues | 1,988.7 | 1,498.4 | 490.3 |
| Cost of natural gas sold | 1,327.4 | 906.5 | (420.9) |
| Total natural gas margins | 661.3 | 591.9 | 69.4 |
| Total electric and natural gas margins | 3,751.7 | 3,642.3 | 109.4 |
| Other operation and maintenance | 1,351.3 | 1,455.2 | 103.9 |
| Depreciation and amortization | 754.7 | 726.9 | (27.8) |
| Property and revenue taxes | 182.6 | 150.9 | (31.7) |
| Operating income | 1,463.1 | 1,309.3 | 153.8 |
| Other income, net | 99.9 | 73.9 | 26.0 |
| Interest expense | 555.9 | 555.6 | (0.3) |
| Income before income taxes | 1,007.1 | 827.6 | 179.5 |
| Income tax expense | 247.5 | 119.9 | (127.6) |
| Preferred stock dividends of subsidiary | 1.2 | 1.2 | - |
| Net income attributed to common shareholders | $758.4 | $706.5 | $51.9 |

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

| (in millions) | Year Ended December 31 |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | B (W) |
| Operation and maintenance not included in line items below | $655.8 | $671.2 | $15.4 |
| Transmission (1) | 430.9 | 511.1 | 80.2 |
| Regulatory amortizations and other pass through expenses (2) | 145.5 | 141.6 | (3.9) |
| We Power (3) | 108.1 | 114.9 | 6.8 |
| Earnings sharing mechanisms (4) | (13.5) | 5.8 | 19.3 |
| Other | 24.5 | 10.6 | (13.9) |
| Total other operation and maintenance | $1,351.3 | $1,455.2 | $103.9 |

$^{(1)}$ Represents transmission expense that our electric utilities are authorized to collect in rates. The PSCW has approved escrow accounting for ATC and MISO network transmission expenses for WE and WPS. As a result, WE and WPS defer as a regulatory asset or liability, the difference between actual

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2022 Annual Financial Statements

transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During 2022 and 2021, $516.7 million and $503.6 million, respectively, of costs were billed to our electric utilities by transmission providers.

During 2022, WE and WPS amortized $81.0 million of the regulatory liabilities associated with their transmission escrows to offset certain 2022 revenue deficiencies, as approved by the PSCW in order to forego filing for 2022 base rate increases. This amortization drove the decrease in transmission expense during 2022, compared with 2021.

(2) Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on net income.
(3) Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE. During 2022 and 2021, $121.7 million and $113.1 million, respectively, of costs were billed to or incurred by WE related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.
(4) Represents operation and maintenance associated with the earnings mechanisms we have in place. In 2022, also includes $21.6 million of amortization related to a certain portion of WPS's regulatory liability associated with its 2020 earnings sharing mechanism to offset certain 2022 revenue deficiencies, as approved by the PSCW in order to forego filing for 2022 base rate increases. See Note 26, Regulatory Environment, for more information.

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

| Electric Sales Volumes (MWh - in thousands) | Year Ended December 31 |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | B (W) |
| Customer class |  |  |  |
| Residential | 11,372.6 | 11,460.1 | (87.5) |
| Small commercial and industrial (1) | 12,867.1 | 12,785.1 | 82.0 |
| Large commercial and industrial (1) | 12,181.6 | 12,406.4 | (224.8) |
| Other | 139.0 | 147.6 | (8.6) |
| Total retail (1) | 36,560.3 | 36,799.2 | (238.9) |
| Wholesale | 2,444.7 | 2,862.5 | (417.8) |
| Resale | 3,962.8 | 4,869.2 | (906.4) |
| Total sales in MWh (1) | 42,967.8 | 44,530.9 | (1,563.1) |

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

| Natural Gas Sales Volumes (Therms - in millions) | Year Ended December 31 |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | B (W) |
| Customer class |  |  |  |
| Residential | 1,189.6 | 1,036.7 | 152.9 |
| Commercial and industrial | 746.6 | 634.0 | 112.6 |
| Total retail | 1,936.2 | 1,670.7 | 265.5 |
| Transportation | 1,438.1 | 1,392.6 | 45.5 |
| Total sales in therms | 3,374.3 | 3,063.3 | 311.0 |

| Weather (Degree Days) | Year Ended December 31 |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | B (W) |
| WE and WG (1) |  |  |  |
| Heating (6,518 Normal) | 6,369 | 5,735 | 11.1% |
| Cooling (774 Normal) | 944 | 1,061 | (11.0)% |
| WPS (2) |  |  |  |
| Heating (7,360 Normal) | 7,387 | 6,735 | 9.7% |
| Cooling (538 Normal) | 718 | 643 | 11.7% |
| UMERC (3) |  |  |  |
| Heating (8,387 Normal) | 8,643 | 7,744 | 11.6% |
| Cooling (344 Normal) | 358 | 428 | (16.4)% |

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

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

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

## Electric Revenues

Electric revenues increased $433.2 million during 2022, compared with 2021. To the extent that changes in fuel and purchased power costs are passed through to customers, the changes are offset by comparable changes in revenues. See the discussion of electric utility margins below for more information related to recovery of fuel and purchased power costs and the remaining drivers of the changes in electric revenues.

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2022 Annual Financial Statements

## Electric Utility Margins

Electric utility margins at the Wisconsin segment increased $40.0 million during 2022, compared with 2021. The significant factors impacting the higher electric utility margins were:

- A $103.5 million increase in margins related to the impact of unprotected excess deferred taxes during 2021, which we agreed to return to customers in our PSCW-approved rate orders. This increase in margins is offset in income taxes. See Note 16, Income Taxes, and Note 26, Regulatory Environment, for more information.
- A $9.6 million increase in other revenues, primarily related to third-party use of our assets.

These increases in margins were partially offset by:

- A $50.8 million year-over-year negative impact from collections of fuel and purchased power costs compared with costs collected in rates. Under the Wisconsin fuel rules, the margins of our electric utilities are impacted by under- or over-collections of certain fuel and purchased power costs that are within a 2% price variance from the costs included in rates, and the remaining variance beyond the 2% price variance is generally deferred for future recovery or refund to customers. As a result of the higher fuel costs in both 2021 and 2022, WPS was unable to defer a portion of its under-collected fuel and purchased power costs due to earning an ROE in excess of the PSCW authorized amount.
- Lower margins of $14.9 million driven by the expiration of certain wholesale contracts.
- An $8.4 million net decrease in margins related to lower sales volumes, driven by the impact of cooler weather during the 2022 cooling season, compared with 2021. As measured by cooling degree days, 2022 was 11.0% cooler than 2021 in the Milwaukee area.

## Natural Gas Revenues

Natural gas revenues increased $490.3 million during 2022, compared with 2021. Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues. The average per-unit cost of natural gas increased approximately 27% during 2022, compared with 2021. The remaining drivers of changes in natural gas revenues are described in the discussion of natural gas utility margins below.

## Natural Gas Utility Margins

Natural gas utility margins at the Wisconsin segment increased $69.4 million during 2022, compared with 2021. The most significant factors impacting the higher natural gas utility margins were:

- A $59.7 million increase in margins from higher sales volumes, driven by the continued economic recovery in Wisconsin from the COVID-19 pandemic, as well as colder weather during the 2022 heating season, compared with 2021. As measured by heating degree days, 2022 was 11.1% and 9.7% colder than 2021 in the Milwaukee area and Green Bay area, respectively.
- A $9.9 million increase in margins related to the amortization of a certain portion of WG's regulatory liability consisting of credit balances associated with the escrow of natural gas storage service costs from Bluewater Gas Storage. In September 2021, the PSCW issued a written order for our Wisconsin utilities approving certain accounting treatments to offset certain 2022 revenue deficiencies in order to forego filing for 2022 base rate increases. See Note 26, Regulatory Environment, for more information.

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

Other operating expenses at the Wisconsin segment decreased $44.4 million during 2022, compared with 2021. The significant factors impacting the decrease in other operating expenses were:

- An $80.2 million decrease in transmission expense driven by the amortization of a certain portion of WE's and WPS's regulatory liabilities associated with transmission escrow balances, as discussed in the notes under the other operation and maintenance table above.
- A $19.3 million decrease in expense related to the earnings sharing mechanisms in place at our Wisconsin utilities, as discussed in the notes under the other operation and maintenance table above. See Note 26, Regulatory Environment, for more information.
- A $14.5 million decrease in other operation and maintenance expense due to increases to certain regulatory assets resulting from decisions included in the December 2022 Wisconsin rate orders.
- An $8.6 million decrease in other operation and maintenance expense during 2022, compared with 2021, related to certain COVID-19 expenditures.
- A $6.8 million decrease in other operation and maintenance expense related to the We Power leases, as discussed in the notes under the other operation and maintenance table above.
- A $3.1 million decrease in other operating and maintenance expense related to our power plants, driven by increases to certain plant-related regulatory assets resulting from decisions included in the December 2022 Wisconsin rate orders. This decrease in expense was partially offset by increased maintenance at our plants, including a planned outage at the Weston power plant, and reductions in refined coal credits during 2022, compared with 2021.

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2022 Annual Financial Statements

• A $2.8 million decrease in expense related to higher gains on land sales during 2022, compared with 2021.
• A $2.4 million decrease in expense related to charitable projects supporting our customers and the communities within our service territories.

These decreases in other operating expenses were partially offset by:

• A $31.7 million increase in property and revenue taxes, driven by higher gross receipt and property taxes.
• A $29.3 million increase in electric and natural gas distribution expenses, primarily driven by higher costs to manage system reliability, for storm restoration, and for overall maintenance of our distribution system during 2022.
• A $27.8 million net increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan and an increase related to the We Power leases. These increases were partially offset by $10.2 million of deferred depreciation related to capital investments made by WG since it's last rate case, as approved by the PSCW in an order that allowed our Wisconsin utilities to offset certain 2022 revenue deficiencies in order to forego filing for 2022 base rate increases.
• A $3.9 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

# Other Income, Net

Other income, net at the Wisconsin segment increased $26.0 million during 2022, compared with 2021, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 20, Employee Benefits, for more information on our benefit costs. Higher AFUDC-Equity due to continued capital investment also contributed to the increase in other income, net.

# Interest Expense

Interest expense at the Wisconsin segment increased $0.3 million during 2022, compared with 2021. The increase was primarily driven by WE and WPS issuing long-term debt during the third and fourth quarters of 2022, respectively. Also driving the increase was an increase to short-term debt interest rates. These increases were partially offset by the deferral of interest expense related to capital investments made by WG since its last rate case, as approved by the PSCW in an order that allowed our Wisconsin utilities to offset certain 2022 revenue deficiencies in order to forego filing for a 2022 base rate increase. See Note 26, Regulatory Environment, for more information. Also offsetting the increases was lower interest expense on finance lease liabilities, primarily related to the We Power leases, as finance lease liabilities decrease each year as payments are made. Higher AFUDC-Debt due to continued capital investment also contributed to offsetting the increases.

# Income Tax Expense

Income tax expense at the Wisconsin segment increased $127.6 million during 2022, compared with 2021. The increase was primarily due to an approximate $100 million negative impact related to the lower year-over-year amortization of the unprotected excess deferred tax benefits from the Tax Legislation in connection with the Wisconsin rate orders approved by the PSCW, effective January 1, 2020. The impact due to the benefit from the amortization of these unprotected excess deferred tax benefits in 2021 did not impact earnings as there was an offsetting impact in operating income. Also contributing to the increase was higher pre-tax income in 2022. See Note 16, Income Taxes, and Note 26, Regulatory Environment, for more information.

# ILLINOIS SEGMENT CONTRIBUTION TO NET INCOME ATTRIBUTED TO COMMON SHAREHOLDERS

The Illinois segment's contribution to net income attributed to common shareholders for the year ended December 31, 2022 was $226.9 million, representing a $3.9 million, or 1.7%, increase over the prior year. The increase was driven by a gain on the sale of certain real estate in Chicago, as well as higher natural gas margins due to PGL's continued capital investment in the SMP project under its QIP rider and NSG's rate increase, effective September 15, 2021. These positive impacts were partially offset by increases in various operating expenses, as discussed below.

WEC Energy Group

F-16

2022 Annual Financial Statements

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

| (in millions) | Year Ended December 31 |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | B (W) |
| Natural gas revenues | $1,890.9 | $1,672.8 | $218.1 |
| Cost of natural gas sold | 792.5 | 628.4 | (164.1) |
| Total natural gas margins | 1,098.4 | 1,044.4 | 54.0 |
| Other operation and maintenance | 459.2 | 433.5 | (25.7) |
| Depreciation and amortization | 230.9 | 218.1 | (12.8) |
| Property and revenue taxes | 38.6 | 31.2 | (7.4) |
| Operating income | 369.7 | 361.6 | 8.1 |
| Other income, net | 14.1 | 7.3 | 6.8 |
| Interest expense | 73.8 | 66.6 | (7.2) |
| Income before income taxes | 310.0 | 302.3 | 7.7 |
| Income tax expense | 83.1 | 79.3 | (3.8) |
| Net income attributed to common shareholders | $226.9 | $223.0 | $3.9 |

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

| (in millions) | Year Ended December 31 |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | B (W) |
| Operation and maintenance not included in the line items below | $319.4 | $320.3 | $0.9 |
| Riders (1) | 127.2 | 112.1 | (15.1) |
| Regulatory amortizations (1) | (2.4) | (1.5) | 0.9 |
| Other | 15.0 | 2.6 | (12.4) |
| Total other operation and maintenance | $459.2 | $433.5 | $(25.7) |

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

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

| Natural Gas Sales Volumes (Therms - in millions) | Year Ended December 31 |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | B (W) |
| Customer Class |  |  |  |
| Residential | 907.0 | 819.2 | 87.8 |
| Commercial and industrial | 353.7 | 319.5 | 34.2 |
| Total retail | 1,260.7 | 1,138.7 | 122.0 |
| Transportation | 839.5 | 760.1 | 79.4 |
| Total sales in therms | 2,100.2 | 1,898.8 | 201.4 |

| Weather (Degree Days) (1) | Year Ended December 31 |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | B (W) |
| Heating (5,993 Normal) | 6,140 | 5,468 | 12.3% |

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

## Natural Gas Revenues

Natural gas revenues increased $218.1 million during 2022, compared with 2021. Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues. The average per-unit cost of natural gas sold increased approximately 14% during 2022, compared with 2021. The remaining drivers of changes in natural gas revenues are described in the discussion of margins below.

WEC Energy Group

F-17

2022 Annual Financial Statements

## Natural Gas Utility Margins

Natural gas utility margins at the Illinois segment, net of the $15.1 million impact of the riders referenced in the table above, increased $38.9 million during 2022, compared with 2021. The increase in margins was primarily driven by:

- A $24.9 million increase in revenues at PGL due to continued capital investment in the SMP project. PGL recovers the costs related to the SMP through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023. For information on the QIP rider and PGL's plan to recover these costs after 2023, see Note 26, Regulatory Environment.
- An $8.0 million increase related to the impact of the NSG rate order approved by the ICC, effective September 15, 2021, which includes the Variable Income Tax Adjustment Rider in base rates. The Variable Income Tax Adjustment Rider recovers or refunds changes in actual income tax expense resulting from changes in income tax rates and amortization of deferred taxes, which differ from amounts included in rates. See Note 26, Regulatory Environment, for more information on NSG's rate order.
- A $5.0 million increase in the invested capital tax adjustment rider, which did not impact net income as it was offset in property and revenue taxes. The invested capital tax adjustment rider is a mechanism that allows PGL and NSG to recover or refund the difference between the cost of invested capital tax incurred and the amount collected through base rates.

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

Other operating expenses at the Illinois segment increased $30.8 million, net of the $15.1 million impact of the riders referenced in the table above, during 2022, compared with 2021. The significant factors impacting the increase in operating expenses were:

- A $22.4 million increase in expenses related to charitable projects supporting our customers and the communities within our service territories.
- A $12.8 million increase in depreciation and amortization, primarily driven by PGL's continued capital investment in the SMP project.
- A $12.7 million increase in natural gas distribution and maintenance costs, primarily related to maintaining the natural gas infrastructure, including costs associated with PGL's gas storage field.
- An $11.4 million increase in expenses associated with the settlement of legal claims.
- A $9.8 million increase in benefit costs, primarily due to higher pension and stock-based compensation costs.
- A $7.4 million increase in property and revenue taxes, primarily driven by an increase in the invested capital tax related to continued capital investment. This increase was offset in natural gas utility margins.
- A $6.9 million increase in customer service expense, primarily driven by higher call volumes.

These increases in operating expenses were partially offset by a $54.5 million pre-tax gain on the sale of certain real estate in Chicago. See Note 3, Dispositions, for more information.

## Other Income, Net

Other income, net at the Illinois segment increased $6.8 million during 2022, compared with 2021, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 20, Employee Benefits, for more information on our benefit costs.

## Interest Expense

Interest expense at the Illinois segment increased $7.2 million during 2022, compared with 2021, driven primarily by $225.0 million and $100.0 million of long-term debt issuances in November 2021 and December 2022, respectively, and increased short-term debt interest rates.

## Income Tax Expense

Income tax expense at the Illinois segment increased $3.8 million during 2022, compared with 2021, driven by an increase in pre-tax income and a $1.3 million negative impact associated with previously unrecognized tax benefits recorded in 2021. See Note 16, Income Taxes, for more information.

## OTHER STATES SEGMENT CONTRIBUTION TO NET INCOME ATTRIBUTED TO COMMON SHAREHOLDERS

The other states segment's contribution to net income attributed to common shareholders for the year ended December 31, 2022 was $39.7 million, representing a $3.9 million, or 10.9%, increase over the prior year. The increase was driven by higher natural gas margins due to a rate increase at MGU, effective January 1, 2022, and higher sales volumes during 2022, compared with 2021. These positive impacts were partially offset by increases in operating expenses, as well as interest expense, as discussed below.

WEC Energy Group

F-18

2022 Annual Financial Statements

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

| (in millions) | Year Ended December 31 |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | B (W) |
| Natural gas revenues | $618.5 | $519.0 | $99.5 |
| Cost of natural gas sold | 391.6 | 319.3 | (72.3) |
| Total natural gas margins | 226.9 | 199.7 | 27.2 |
| Other operation and maintenance | 98.5 | 90.4 | (8.1) |
| Depreciation and amortization | 40.9 | 38.1 | (2.8) |
| Property and revenue taxes | 23.3 | 18.8 | (4.5) |
| Operating income | 64.2 | 52.4 | 11.8 |
| Other income, net | 2.5 | 1.1 | 1.4 |
| Interest expense | 13.9 | 6.2 | (7.7) |
| Income before income taxes | 52.8 | 47.3 | 5.5 |
| Income tax expense | 13.1 | 11.5 | (1.6) |
| Net income attributed to common shareholders | $39.7 | $35.8 | $3.9 |

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

| (in millions) | Year Ended December 31 |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | B (W) |
| Operation and maintenance not included in line items below | $77.8 | $70.5 | $(7.3) |
| Regulatory amortizations and other pass through expenses (1) | 20.7 | 19.8 | (0.9) |
| Other | - | 0.1 | 0.1 |
| Total other operation and maintenance | $98.5 | $90.4 | $(8.1) |

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

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

| Natural Gas Sales Volumes (Therms - in millions) | Year Ended December 31 |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | B (W) |
| Customer Class |  |  |  |
| Residential | 353.1 | 301.1 | 52.0 |
| Commercial and industrial | 227.6 | 188.5 | 39.1 |
| Total retail | 580.7 | 489.6 | 91.1 |
| Transportation | 794.8 | 801.6 | (6.8) |
| Total sales in therms | 1,375.5 | 1,291.2 | 84.3 |

| Weather (Degree Days) (1) | Year Ended December 31 |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | B (W) |
| MERC |  |  |  |
| Heating (7,973 Normal) | 8,585 | 7,440 | 15.4% |
| MGU |  |  |  |
| Heating (6,177 Normal) | 6,277 | 5,755 | 9.1% |

$^{(1)}$ Normal heating degree days for MERC and MGU are based on a 20-year moving average and 15-year moving average, respectively, of monthly temperatures from various weather stations throughout their respective territories.

## Natural Gas Revenues

Natural gas revenues increased $99.5 million during 2022, compared with 2021. Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues. The average per-unit cost of natural gas sold increased approximately 4.0% during 2022, compared with 2021. The remaining drivers of changes in natural gas revenues are described in the discussion of margins below.

WEC Energy Group

F-19

2022 Annual Financial Statements

## Natural Gas Utility Margins

Natural gas utility margins increased $27.2 million during 2022, compared with 2021. The increase in margins was primarily driven by:

- A $13.0 million increase related to the new rates at MGU that went into effect in 2022. See Note 26, Regulatory Environment, for more information.
- A $9.3 million increase related to higher sales volumes due to both continued economic recovery and colder weather during 2022, compared with 2021.
- A $2.6 million increase related to MERC's GUIC rider, which was in place through December 31, 2022. The GUIC rider allowed MERC to recover previously approved GUIC incurred to replace or modify natural gas facilities to the extent the work is required by state, federal, or other government agencies and exceeds the costs included in base rates.
- A $1.2 million increase related to MERC CIP revenue, which was offset in operation and maintenance expense. Rebates and programs are available to residential and commercial customers of MERC through the CIP, which is funded by rate payers using the Conservation Cost Recovery Charge and the Conservation Cost Recovery Adjustment funds that are collected on their monthly billing statements.

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

Other operating expenses at the other states segment increased $15.4 million during 2022, compared with 2021. The significant factors impacting the increase in operating expenses were:

- A $7.9 million increase in natural gas operations and customer service expense, primarily driven by various operation and maintenance projects approved in MGU's rate case and an increase in costs related to safety and reliability programs at MERC.
- A $4.5 million increase in property and revenue taxes, driven by higher use tax at MGU.
- A $2.8 million increase in depreciation and amortization related to continued capital investment.
- A $1.2 million increase in operation and maintenance expense due to MERC's CIP program, which has an offsetting increase in margins.

## Other Income, Net

Other income, net at the other states segment increased $1.4 million during 2022, compared with 2021, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 20, Employee Benefits, for more information on our benefit costs.

## Interest Expense

Interest expense at the other states segment increased $7.7 million during 2022, compared with 2021, driven primarily by the deferral of $4.9 million of interest expense during 2021, as approved by the MPSC to mitigate the impacts from delaying the filing of MGU's 2021 rate case. See Note 26, Regulatory Environment, for additional information. This deferred interest expense is now being amortized over a four-year period as a result of MGU's approved rate increase.

## Income Tax Expense

Income tax expense at the other states segment increased $1.6 million during 2022, compared with 2021, driven by an increase in pre-tax income.

## ELECTRIC TRANSMISSION SEGMENT CONTRIBUTION TO NET INCOME ATTRIBUTED TO COMMON SHAREHOLDERS

| (in millions) | Year Ended December 31 |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | B (W) |
| Equity in earnings of transmission affiliates | $194.7 | $158.1 | $36.6 |
| Other expense | - | 0.1 | 0.1 |
| Interest expense | 19.4 | 19.4 | - |
| Income before income taxes | 175.3 | 138.6 | 36.7 |
| Income tax expense | 45.8 | 32.3 | (13.5) |
| Net income attributed to common shareholders | $129.5 | $106.3 | $23.2 |

WEC Energy Group

F-20

2022 Annual Financial Statements

## Equity in Earnings of Transmission Affiliates

Equity in earnings of transmission affiliates increased $36.6 million during 2022, compared with 2021, driven by:

- A $20.5 million increase in equity earnings due to the impact of a D.C. Circuit Court of Appeals opinion issued in August 2022 addressing complaints related to ATC's ROE. For information on this D.C. Circuit Court of Appeals opinion, see Factors Affecting Results, Liquidity, and Capital Resources - Regulatory, Legislative, and Legal Matters - American Transmission Company Allowed Return on Equity Complaints.
- An $8.5 million increase in equity earnings related to a goodwill impairment recorded during the fourth quarter of 2021 by ATC Holdco, which was formed to invest in transmission-related projects outside of ATC's traditional footprint.

Continued capital investment by ATC also contributed to the year-over-year increase in equity earnings.

## Income Tax Expense

Income tax expense at the electric transmission segment increased $13.5 million during 2022, compared with 2021, driven by an increase in pre-tax income and a $3.3 million negative impact associated with a previously recorded reversal of a tax remeasurement in 2021.

## NON-UTILITY ENERGY INFRASTRUCTURE SEGMENT CONTRIBUTION TO NET INCOME ATTRIBUTED TO COMMON SHAREHOLDERS

| (in millions) | Year Ended December 31 |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | B (W) |
| Operating income | $372.8 | $350.3 | $22.5 |
| Interest expense | 68.9 | 71.0 | 2.1 |
| Income before income taxes | 303.9 | 279.3 | 24.6 |
| Income tax expense (benefit) | (20.9) | 3.1 | 24.0 |
| Net (income) loss attributed to noncontrolling interests | (0.4) | 3.0 | (3.4) |
| Net income attributed to common shareholders | $324.4 | $279.2 | $45.2 |

## Operating Income

Operating income at the non-utility energy infrastructure segment increased $22.5 million during 2022, compared with 2021, driven by:

- A $15.2 million positive impact from recognition of revenue related to our Upstream wind park in 2022 that was associated with market settlements received from SPP in February 2021. These settlements were subject to a FERC complaint, so we were not able to recognize them as revenue until the FERC issued an order denying that complaint in 2022.
- A $13.4 million positive impact from a sharing arrangement with one of our Blooming Grove customers resulting from strong energy prices.

These increases in operating income were partially offset by:

- A $5.1 million negative impact from higher operating losses at our Jayhawk wind park that achieved commercial operation in December 2021. The site experienced operating losses in 2022 due to SPP reliability curtailments reducing output and transmission congestion reducing energy market prices.

## Interest Expense

Interest expense at the non-utility energy infrastructure segment decreased $2.1 million during 2022, compared with 2021, primarily due to a lower principal balance as a result of the semi-annual principal payments on long-term debt.

## Income Tax Expense (Benefit)

At the non-utility energy infrastructure segment, $20.9 million of income tax benefit was recorded during 2022, compared with $3.1 million of income tax expense recorded during 2021. The change was primarily due to a $30.3 million increase in PTCs in 2022, driven by the Jayhawk wind park that achieved commercial operation in December 2021, higher generation at our other wind parks, and an increase in the PTC rate related to the PTC inflation adjustment issued by the IRS. This favorable change in the income tax benefit was partially offset by higher pre-tax earnings in 2022.

WEC Energy Group

F-21

2022 Annual Financial Statements

# CORPORATE AND OTHER SEGMENT CONTRIBUTION TO NET INCOME ATTRIBUTED TO COMMON SHAREHOLDERS

| (in millions) | Year Ended December 31 |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | B (W) |
| Operating loss | $(11.7) | $(18.9) | $7.2 |
| Other income, net | 14.6 | 51.7 | (37.1) |
| Interest expense | 119.4 | 92.8 | (26.6) |
| Loss on debt extinguishment | - | 36.3 | 36.3 |
| Loss before income taxes | (116.5) | (96.3) | (20.2) |
| Income tax benefit | (45.7) | (45.8) | (0.1) |
| Net loss attributed to common shareholders | $(70.8) | $(50.5) | $(20.3) |

## Operating Loss

The operating loss at the corporate and other segment decreased $7.2 million during 2022, compared with 2021, driven by the resolution of a previously recorded liability as certain outstanding matters reached a favorable outcome in 2022.

## Other Income, Net

Other income, net at the corporate and other segment decreased $37.1 million during 2022, compared with 2021. The decrease was driven by a $12.6 million net loss from the investments held in the Integrys rabbi trust during 2022, compared with an $18.6 million net gain during 2021. The gains and losses from the investments held in the rabbi trust partially offset the changes in benefit costs related to deferred compensation, which are included in other operation and maintenance expense in our operating segments. See Note 17, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust. An $11.9 million decrease in earnings from our equity method investments in technology and energy-focused investment funds also contributed to the lower other income, net.

## Interest Expense

Interest expense at the corporate and other segment increased $26.6 million during 2022, compared with 2021, due to a $900.0 million long-term debt issuance in September 2022. See Note 14, Long-Term Debt, for more information. Also contributing to the increase was higher short-term debt interest rates.

## Loss on Debt Extinguishment

There was no loss on debt extinguishment during 2022, as we did not refinance any debt obligations prior to maturity during 2022.

## Income Tax Benefit

The income tax benefit at the corporate and other segment decreased $0.1 million during 2022, compared with 2021, driven by $10.3 million of previously unrecognized tax benefits recorded during 2021. This decrease in income tax benefit was offset by higher pre-tax loss and a $3.9 million increase in excess tax benefits recognized related to stock option exercises during 2022, compared with 2021.

# LIQUIDITY AND CAPITAL RESOURCES

## OVERVIEW

We expect to maintain adequate liquidity to meet our cash requirements for operation of our businesses 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, 2022 with the year ended December 31, 2021. For a similar discussion that compares our cash flows for the year ended December 31, 2021 with the year ended December 31, 2020, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources in Part II of our 2021 Annual Report on Form 10-K, which was filed with the SEC on February 24, 2022.

WEC Energy Group

F-22

2022 Annual Financial Statements

## CASH FLOWS

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

| (in millions) | 2022 | 2021 | Change in 2022 Over 2021 |
| --- | --- | --- | --- |
| Cash provided by (used in): |  |  |  |
| Operating activities | $2,060.7 | $2,032.7 | $28.0 |
| Investing activities | (2,642.4) | (2,311.8) | (330.6) |
| Financing activities | 676.4 | 294.0 | 382.4 |

### Operating Activities

Net cash provided by operating activities increased $28.0 million during 2022, compared with 2021, driven by:

- A $696.2 million increase in cash from higher overall collections from customers as a result of an increase in natural gas sales volumes during 2022, compared with 2021, driven by the continued economic recovery from the COVID-19 pandemic and colder weather. In addition, we continued to recover the natural gas costs we under-collected from our Illinois and Minnesota customers related to the extreme weather conditions that occurred in February 2021. See Note 26, Regulatory Environment, for more information on the recovery of these natural gas costs.
- A $51.2 million increase in cash related to a decrease in contributions and payments related to pension and OPEB plans during 2022, compared with 2021.

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

- A $461.3 million decrease in cash from higher payments for fuel and purchased power at our plants during 2022, compared with 2021. Our plants incurred higher fuel costs throughout 2022 as a result of an increase in the price of natural gas.
- A $174.3 million decrease in cash from higher payments for operating and maintenance expenses. During 2022, our payments were higher for reliability and storm restoration, transmission, benefit costs, natural gas distribution and maintenance costs, natural gas storage costs, and customer service.
- A $28.3 million decrease in cash related to higher payments for property and revenue taxes, driven by higher gross receipt taxes, property taxes, and an increase in the Illinois invested capital tax during 2022, compared with 2021.
- An $18.6 million decrease in cash related to higher cash paid for income taxes, driven by higher taxable income during 2022, compared with 2021.
- A $12.8 million decrease in cash related to higher payments for environmental remediation related to work completed on former manufactured gas plant sites during 2022, compared with 2021.
- A $12.6 million decrease in cash related to lower distributions from ATC during 2022, compared with 2021.
- An $11.4 million decrease in cash related to higher payments for interest related to increases in long-term and short-term debt interest rates during 2022, compared with 2021.

### Investing Activities

Net cash used in investing activities increased $330.6 million during 2022, compared with 2021, driven by:

- The acquisition of a 90% ownership interest in Thunderhead in September 2022 for $382.0 million. See Note 2, Acquisitions, for more information.
- A $62.1 million increase in cash paid for capital expenditures during 2022, compared with 2021, which is discussed in more detail below.
- Capital contributions paid to transmission affiliates of $45.5 million during 2022. See Note 21, Investment in Transmission Affiliates, for more information. There were no payments to transmission affiliates during 2021.
- The purchase of spectrum frequencies for $19.2 million during 2022. See Note 10, Goodwill and Intangibles, for more information.
- A $17.8 million increase in cash paid for ATC's construction costs during 2022, compared with 2021, which will be reimbursed in the future. See Note 21, Investment in Transmission Affiliates, for more information.

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

- The acquisition of a 90% ownership interest in Jayhawk in February 2021 for $119.9 million. See Note 2, Acquisitions, for more information.
- A $47.1 million increase in proceeds from the sale of assets during 2022, compared with 2021, primarily related to the sale of real estate owned by PGL. See Note 3, Dispositions, for more information.

WEC Energy Group

F-23

2022 Annual Financial Statements

• Insurance proceeds of $41.6 million received during 2022 for property damage, primarily related to the PSB water damage claim. See Note 7, Property, Plant, and Equipment, for more information.

## Capital Expenditures

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

| Reportable Segment (in millions) | 2022 | 2021 | Change in 2022 Over 2021 |
| --- | --- | --- | --- |
| Wisconsin | $1,610.8 | $1,389.7 | $221.1 |
| Illinois | 484.9 | 533.7 | (48.8) |
| Other states | 101.1 | 95.9 | 5.2 |
| Non-utility energy infrastructure | 101.8 | 215.4 | (113.6) |
| Corporate and other | 16.3 | 18.1 | (1.8) |
| Total capital expenditures | $2,314.9 | $2,252.8 | $62.1 |

The increase in cash paid for capital expenditures at the Wisconsin segment during 2022, compared with 2021, was primarily driven by higher payments for capital expenditures related to Paris and other renewable energy projects, the new natural gas-fired generation being constructed at WPS's existing Weston power plant site, and WG's LNG facility. These increases were partially offset by lower payments for capital expenditures related to upgrades to WE's and WPS's natural gas distribution systems and the restoration of WE's PSB. See Note 7, Property, Plant, and Equipment, for more information on the PSB.

The decrease in cash paid for capital expenditures at the Illinois segment during 2022, compared with 2021, was primarily driven by lower capital expenditures related to upgrades at the Manlove Gas Storage Field and upgrades to PGL's natural gas distribution system.

The decrease in cash paid for capital expenditures at the non-utility energy infrastructure segment during 2022, compared with 2021, was primarily driven by lower payments for capital expenditures related to the construction of Jayhawk, which went into commercial operation in December 2021. See Note 2, Acquisitions, for more information. This decrease in cash paid for capital expenditures was partially offset by an increase in capital expenditures for wastewater treatment system modifications for We Power's ERGS units. See Note 24, Commitments and Contingencies, for more information on the wastewater treatment system modifications.

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

## Financing Activities

Net cash provided by financing activities increased $382.4 million during 2022, compared with 2021, driven by:

- A $1,168.3 million increase in cash due to a decrease in retirements of long-term debt during 2022, compared with 2021.
- A $340.0 million increase in cash due to a repayment of a 364-day term loan during 2021.
- A $51.6 million increase in cash due to a decrease in payments for debt extinguishment and issuance costs during 2022, compared with 2021.
- A $17.9 million increase in cash received from the exercise of stock options during 2022, compared with 2021.

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

- A $711.8 million decrease in cash due to $252.6 million of net repayments of commercial paper during 2022, compared with $459.2 million of net borrowings of commercial paper during 2021.
- A $384.5 million decrease in cash due to lower issuances of long-term debt during 2022, compared with the same period in 2021.
- A $63.1 million decrease in cash due to higher dividends paid on our common stock during 2022, compared with 2021. In January 2022, our Board of Directors increased our quarterly dividend by $0.05 per share (7.4%) effective with the March 2022 dividend payment.
- A $36.1 million decrease in cash due to an increase in common stock purchased during 2022, compared with 2021, to satisfy requirements of our stock-based compensation plans.

## 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.

WEC Energy Group

F-24

2022 Annual Financial Statements

## CASH REQUIREMENTS

We require funds to support and grow our businesses. Our significant cash requirements primarily consist of capital and investment expenditures, payments to retire and pay interest on long-term debt, the payment of common stock dividends to our shareholders, and the funding of our ongoing operations. Our significant cash requirements are discussed in further detail below.

### 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, 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 24, Commitments and Contingencies.

| (in millions) | 2023 | 2024 | 2025 |
| --- | --- | --- | --- |
| Wisconsin | $2,530.7 | $2,432.8 | $2,445.5 |
| Illinois | 557.1 | 659.5 | 614.0 |
| Other states | 111.8 | 115.0 | 104.7 |
| Non-utility energy infrastructure | 747.0 | 683.8 | 217.2 |
| Corporate and other | 28.1 | 17.0 | 2.7 |
| Total | $3,974.7 | $3,908.1 | $3,384.1 |

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

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

- We have received approval to invest in 100 MW of utility-scale solar within our Wisconsin segment. WE has partnered with an unaffiliated utility to construct a solar project, Badger Hollow II, that will be located in Iowa County, Wisconsin. Once constructed, WE will own 100 MW of this project. WE's share of the cost of this project is estimated to be approximately $151 million. Commercial operation of Badger Hollow II is targeted for 2023.
- WE and WPS, along with an unaffiliated utility, received PSCW approval to acquire and construct Paris, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Kenosha County, Wisconsin and once fully constructed, WE and WPS will collectively own 180 MW of solar generation and 99 MW of battery storage of this project. WE's and WPS's combined share of the cost of this project is estimated to be approximately $390 million, with construction of the solar portion expected to be completed in 2023.
- WE and WPS, along with an unaffiliated utility, received PSCW approval to acquire and construct Darien, 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 fully constructed, WE and WPS will collectively own 225 MW of solar generation and 68 MW of battery storage of this project. WE's and WPS's combined share of the cost of this project is estimated to be approximately $400 million, with construction of the solar portion expected to be completed in 2024.
- WPS, along with an unaffiliated utility, received PSCW approval to acquire Red Barn, a utility-scale wind-powered electric generating facility. The project will be located in Grant County, Wisconsin and once constructed, WPS will own 82 MW of this project. WPS's share of the cost of this project is estimated to be approximately $160 million, with construction expected to be completed in the first half of 2023.
- In April 2021, WE and WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire the Koshkonong Solar-Battery Park, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Dane County, Wisconsin and once fully constructed, WE and WPS will collectively own 270 MW of solar generation and 149 MW of battery storage of this project. If approved, WE's and WPS's combined share of the cost of this project is estimated to be approximately $585 million, with construction of the solar portion expected to be completed in 2025.
- WE and WPS received PSCW approval to construct 128 MWs of natural gas-fired generation at WPS's existing Weston power plant site in northern Wisconsin. The new facility will consist of seven RICE units. We estimate the cost of this project to be approximately $170 million, with construction expected to be completed in 2023.
- Effective January 1, 2023, WE and WPS completed the acquisition of Whitewater, a commercially operational 236.5 MW dual fueled (natural gas and low sulfur fuel oil) combined cycle electrical generation facility in Whitewater, Wisconsin. The cost of this facility was approximately $75.0 million, which includes transaction costs and working capital. See Note 15, Leases, for more information.
- In January 2022, WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire a portion of West Riverside's nameplate capacity. WPS is also requesting approval to assign the option to purchase part of West Riverside to WE. If

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approved, WPS or WE would acquire 100 MW of capacity, in the first of two potential option exercises. West Riverside is a combined cycle natural gas plant recently completed by an unaffiliated utility in Rock County, Wisconsin. If approved, our share of the cost of this ownership interest is approximately $91 million, with the transaction expected to close in the second quarter of 2023. In addition, WPS could exercise a second option to acquire an additional 100 MW of capacity. If approved, our share of the cost of this ownership interest is expected to be approximately $90 million, with the transaction expected to close in 2024.

In March 2022, the DOC opened an investigation into whether new tariffs should be imposed on solar panels and cells imported from multiple southeast Asian countries. See Factors Affecting Results, Liquidity, and Capital Resources - Regulatory, Legislative, and Legal Matters - United States Department of Commerce Complaints and Factors Affecting Results, Liquidity, and Capital Resources - Regulatory, Legislative, and Legal Matters - Uyghur Forced Labor Prevention Act for information on the potential impacts to our solar projects as a result of the DOC investigation and CBP actions related to solar panels, respectively. The expected in-service dates identified above already reflect some of these impacts.

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

PGL is continuing work on the SMP, a project under which PGL is replacing approximately 2,000 miles of Chicago's aging natural gas pipeline infrastructure. PGL currently recovers these costs through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023. After 2023, PGL will return to the traditional ratemaking process to recover the costs of necessary infrastructure improvements. PGL's projected average annual investment through 2025 is between $280 million and $300 million. See Note 26, Regulatory Environment, for more information on the SMP.

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

We expect to provide total capital contributions to ATC (not included in the above table) of approximately $244 million from 2023 through 2025. We do not expect to make any contributions to ATC Holdco during that period.

## 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, 2022:

| (in millions) | Interest Payments Due by Period |  |  |  |  |
| --- | --- | --- | --- | --- | --- |
|  | Total | Less Than 1 Year | 1-3 Years | 3-5 Years | More Than 5 Years |
| Interest payments on long-term debt (1) | $8,639.1 | $578.2 | $1,096.1 | $940.4 | $6,024.4 |

$^{(1)}$ The interest due on our variable rate debt is based on the interest rates that were in effect on December 31, 2022.

## Common Stock Dividends

On January 19, 2023, our Board of Directors increased our quarterly dividend to $0.78 per share effective with the first quarter of 2023 dividend payment, an increase of 7.2%. This equates to an annual dividend of $3.12 per share. In addition, the Board of Directors affirmed our dividend policy that continues to target a dividend payout ratio of 65-70% of earnings.

We have been paying consecutive quarterly dividends dating back to 1942 and expect to continue paying quarterly cash dividends in the future. 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, our ability as a holding company to pay common stock dividends primarily depends on the availability of funds received from our subsidiaries. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans, or advances. 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 and non-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 24, Commitments and Contingencies, for more information, including our minimum future commitments related to these purchase obligations.

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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.

| (in millions) | Payments Due by Period |  |  |  |  |
| --- | --- | --- | --- | --- | --- |
|  | Total | Less Than 1 Year | 1-3 Years | 3-5 Years | More Than 5 Years |
| Purchase orders | $526.2 | $218.3 | $223.8 | $72.1 | $12.0 |

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

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 20, Employee Benefits, for our expected contributions in 2023 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, 2022 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 24, 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. For additional information, see Note 13, Short-Term Debt and Lines of Credit, Note 19, Guarantees, and Note 23, Variable Interest Entities.

## SOURCES OF CASH

### Liquidity

We anticipate meeting our short-term and long-term cash requirements to operate our businesses and implement our corporate strategy through internal generation of cash from operations and access to the capital markets, which allows us to obtain external short-term borrowings, including commercial paper and term loans, and intermediate or long-term debt securities. Cash generated from operations is primarily driven by sales of electricity and natural gas to our utility customers, reduced by costs of operations. Our access to the capital markets is critical to our overall strategic plan and allows us to supplement cash flows from operations with external borrowings to manage seasonal variations, working capital needs, commodity price fluctuations, unplanned expenses, and unanticipated events.

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

The amount, type, and timing of any financings in 2023, as well as in subsequent years, will be contingent on investment opportunities and our cash requirements and will depend upon prevailing market conditions, regulatory approvals for certain subsidiaries, and other factors. Our regulated utilities plan to maintain capital structures consistent with those approved by their respective regulators.

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

At December 31, 2022, our current liabilities exceeded our current assets by $1,423.3 million. We do not expect this to have an impact on our liquidity as we currently believe that our cash and cash equivalents, our available capacity of $1,454.2 million under existing revolving credit facilities, cash generated from ongoing operations, and access to the capital markets are adequate to meet our short-term and long-term cash requirements.

See Note 13, Short-Term Debt and Lines of Credit, and Note 14, Long-Term Debt, for more information about our credit facilities and debt securities.

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## Investments in Outside Trusts

We maintain investments in outside trusts to fund the obligation to provide pension and certain OPEB benefits to current and future retirees. As of December 31, 2022, these trusts had investments of approximately $3.5 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 20, Employee Benefits.

## Capitalization Structure

The following table shows our capitalization structure as of December 31, 2022 and 2021, as well as an adjusted capitalization structure that we believe is consistent with how a majority of the rating agencies currently view our 2007 Junior Notes:

| (in millions) | 2022 |  | 2021 |  |
| --- | --- | --- | --- | --- |
|  | Actual | Adjusted | Actual | Adjusted |
| Common shareholders' equity | $11,376.9 | $11,626.9 | $10,913.2 | $11,163.2 |
| Preferred stock of subsidiary | 30.4 | 30.4 | 30.4 | 30.4 |
| Long-term debt (including current portion) | 15,647.4 | 15,397.4 | 13,693.1 | 13,443.1 |
| Short-term debt | 1,647.1 | 1,647.1 | 1,897.0 | 1,897.0 |
| Total capitalization | $28,701.8 | $28,701.8 | $26,533.7 | $26,533.7 |
| Total debt | $17,294.5 | $17,044.5 | $15,590.1 | $15,340.1 |
| Ratio of debt to total capitalization | 60.3% | 59.4% | 58.8% | 57.8% |

Included in long-term debt on our balance sheets as of December 31, 2022 and 2021, is $500.0 million principal amount of the 2007 Junior Notes. The adjusted presentation attributes $250.0 million of the 2007 Junior Notes to common shareholders' equity and $250.0 million to long-term debt.

The adjusted presentation of our consolidated capitalization structure is included as a complement to our capitalization structure presented in accordance with GAAP. Management evaluates and manages our capitalization structure, including our total debt to total capitalization ratio, using the GAAP calculation as adjusted to reflect the treatment of the 2007 Junior Notes by the majority of rating agencies. Therefore, we believe the non-GAAP adjusted presentation reflecting this treatment is useful and relevant to investors in understanding how management and the rating agencies evaluate our capitalization structure.

## Debt Covenants

Certain of our short-term and long-term debt agreements contain financial covenants that we must satisfy, including debt to capitalization ratios and debt service coverage ratios. At December 31, 2022, we were in compliance with all such covenants related to outstanding short-term and long-term debt. We expect to be in compliance with all such debt covenants for the foreseeable future. See Note 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, 2022. From time to time, we may enter into commodity contracts that could require collateral or a termination payment in the event of a credit rating change to below BBB- at S&P Global Ratings, a division of S&P Global Inc., and/or Baa3 at Moody's Investors Service, Inc. If WE had a sub-investment grade credit rating at December 31, 2022, it could have been required to post $100 million of additional collateral or other assurances pursuant to the terms of a PPA. We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.

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.

In December 2022, Moody's changed the rating outlook for WG to stable from negative as a result of the rate case decision WG received in December 2022. Moody's affirmed WG's ratings including its A3 senior unsecured rating and its P-2 short term rating for commercial paper. See Note 26, Regulatory Environment, for more information on the rate case decision.

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.

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# FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

## 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.

### Wisconsin

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.

### Michigan

Michigan has adopted a limited retail choice program. Under Michigan law, our retail customers may choose an alternative electric supplier to provide power supply service. As a result, some of our small retail customers have switched to an alternative electric supplier. At December 31, 2022, Michigan law limited customer choice to 10% of an electric utility's Michigan retail load. Our iron ore mine customer, Tilden, is exempt from this 10% cap based on current law, but Tilden is required under a long-term agreement to purchase electric power from UMERC through March 2039. In addition, certain load increases by facilities already using an alternative electric supplier can still be serviced by their alternative electric supplier, when various conditions exist, even if the cap has already been met. When a customer switches to an alternative electric supplier, we continue to provide distribution and customer service functions for the customer.

### Natural Gas Utility Industry

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.

### Wisconsin

Our Wisconsin utilities 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 their local natural gas utility. 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 are currently unable to predict the impact, if any, of potential future industry restructuring on our results of operations or financial position.

### Illinois

Absent extraordinary circumstances, potential competitors are not allowed to construct competing natural gas distribution systems in the service territories for PGL and NSG. A charter from the State of Illinois gives PGL the right to provide natural gas distribution service in the City of Chicago as a public utility. Further, the 'first in the field' and public interest standards limit the ability of potential competitors to operate in an existing utility service territory. In addition, we believe it would be impractical to construct competing duplicate distribution facilities due to the high cost of installation.

Since 2002, PGL and NSG have, under ICC-approved tariffs, provided their customers with the option to choose a third-party natural gas supplier. There are no state laws requiring PGL and NSG to make this choice option available to customers, but since this option is currently provided to our Illinois customers under tariff, ICC approval would be needed to withdraw those tariffs.

An interstate pipeline may seek to provide transportation service directly to our Illinois end users, which would bypass our natural gas transportation service. However, PGL and NSG have anti-bypass tariffs approved by the ICC, which allow them to negotiate rates with customers that are potential bypass candidates to help ensure that such customers continue to use utility transportation service.

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### ***Minnesota***

Natural gas utilities in the state of Minnesota do not have exclusive franchise service territories and, as a matter of law and policy, natural gas utilities may compete for new customers. However, natural gas utilities have customarily avoided competing for existing customers of other utilities, as there would be duplicative utility facilities and/or increased costs to customers. If this approach were to change, it could lead to a greater level of competition amongst utilities to obtain customers.

MERC offers 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. MERC has provided its commercial and industrial customers with the option to choose a third-party natural gas supplier since 2006. We are not required by the MPUC or state law to make this choice option available to customers, but since this option is currently provided to our Minnesota commercial and industrial customers, we would need MPUC approval to eliminate it.

### ***Michigan***

The option to choose a third-party natural gas supplier has been provided to UMERC's natural gas customers (formerly WPS's Michigan natural gas customers) since the late 1990s and MGU's customers since 2005. We are not required by the MPSC or state law to make this choice option available to customers, but since this option is currently provided to our Michigan customers, we would need MPSC approval to eliminate it.

## REGULATORY, LEGISLATIVE, AND LEGAL MATTERS

### Regulatory Recovery

Our utilities account for their regulated operations in accordance with accounting guidance under the Regulated Operations Topic of the FASB ASC. Our rates are determined by various regulatory commissions.

Regulated entities are allowed to defer certain costs that would otherwise be charged to expense if the regulated entity believes the recovery of those costs is probable. We record regulatory assets pursuant to generic and/or specific orders issued by our regulators. Recovery of the deferred costs in future rates is subject to the review and approval by those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of the deferred costs, including those referenced below, is not approved by our regulators, the costs would be charged to income in the current period. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities. See Note 6, Regulatory Assets and Liabilities, for more information on our regulatory assets and liabilities.

In January 2014, the ICC approved PGL's use of the QIP rider as a recovery mechanism for costs incurred related to investments in QIP. This rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudence. In March 2022, PGL filed its 2021 reconciliation with the ICC, which, along with the 2020, 2019, 2018, 2017, and 2016 reconciliations, are still pending. In addition, costs incurred during 2022 under the QIP rider are also still subject to reconciliation and review. As of December 31, 2022, there can be no assurance that all costs incurred under the QIP rider during the open reconciliation years, which include 2016 through 2022, will be deemed recoverable by the ICC.

See Note 26, Regulatory Environment, for more information regarding recent and pending rate proceedings, orders, and investigations involving our utilities.

### Petitions Before PSCW Regarding Third-Party Financed Distributed Energy Resources

In May 2022, two petitions were filed with the PSCW requesting a declaratory ruling that the owner of a third-party financed DER is not a 'public utility' as defined under Wisconsin law and, therefore, is not subject to the PSCW's jurisdiction under any statute or rule regulating public utilities. The parties that filed the petitions provide financing to their customers for installation of DERs (including solar panels and energy storage) on the customer's property. A DER is connected to the host customer's utility meter and is used for the customer's energy needs. It may also be connected to the grid for distribution.

In July 2022, the PSCW found that the specific facts and circumstances merited the opening of a docket for each petition to consider whether to grant all or part of the requested declaratory ruling.

On December 1, 2022, the PSCW granted one petitioner's request for a declaratory ruling, finding that the owner of the third-party financed DER at issue in the petitioner's brief is not a public utility under Wisconsin law. The ruling was limited to the specific facts and circumstances of the lease presented in that petition. A second petition is also being considered. Although the finding in the first petition was limited to the specific facts and circumstances of the lease presented in that petition, similar findings or a broader policy position could adversely impact our business operations.

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## Climate and Equitable Jobs Act

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

Effective September 15, 2021, the new legislation prohibits utilities from charging customers a fee when they elect to pay for service with a credit card. Utilities are now required to incur these expenses and seek recovery through a rate proceeding or by establishing a recovery mechanism. In December 2021, the ICC approved the use of a TPTFA rider for PGL. The TPTFA rider allows PGL to recover the costs incurred for these third-party transaction fees. See Note 26, Regulatory Environment, for more information on the rider. NSG recovers costs related to these third-party transaction fees through its base rates, effective September 15, 2021.

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

## Uyghur Forced Labor Prevention Act

The CBP issued a WRO in June 2021, applicable to certain silica-based products originating from the Xinjiang Uyghur Autonomous Region of China (Xinjiang), such as polysilicon, included in the manufacturing of solar panels. In June 2022, the WRO was superseded by the implementation of the UFLPA, which was signed into law by President Biden in December 2021. The UFLPA establishes a rebuttable presumption that any imports wholly or partially manufactured in Xinjiang are prohibited from entering the United States. While our suppliers were able to provide the CBP sufficient documentation to meet WRO compliance requirements, and we expect the same will be true for UFLPA purposes, we cannot currently predict what, if any, impact the UFLPA will have on the overall supply of solar panels into the United States and the related impact to timing and cost of solar projects included in our capital plan.

## United States Department of Commerce Complaints

In August 2021, a group of anonymous domestic solar manufacturers filed a petition (AD/CVD) with the DOC seeking to impose new tariffs on solar panels and cells imported from several countries, including Malaysia, Vietnam, and Thailand. The petitioners claimed that Chinese solar manufacturers are shifting products to these countries to avoid the tariffs required on products imported from China. In November 2021, the DOC rejected this petition. In denying the petition, the DOC cited the anonymous group's refusal of the DOC's request to provide more detail and identify its members due to the members' concerns about retribution from the dominant Chinese solar industry.

In February 2022, a California based company filed a petition (AD/CVD) with the DOC seeking to impose new tariffs on solar panels and cells imported from multiple countries, including Malaysia, Vietnam, Thailand, and Cambodia. While the petition is similar to the one rejected by the DOC in November 2021, there are notable differences. The group added Cambodia to the petition and requested that the DOC conduct a country-wide inquiry into each of the four countries. In March 2022, the DOC decided to act on the February petition and investigate the claim. On December 2, 2022, the DOC announced its preliminary determination that certain companies are circumventing anti-dumping and countervailing duty orders on solar cells and modules from China. As the next step, the DOC will conduct in-person audits to verify the information that was the basis of the finding. If the DOC makes a final determination, which is currently expected in the second quarter of 2023, that such circumvention is occurring it would be able to apply any final tariffs retroactively to November 4, 2021. If imposed, the new tariffs could further disrupt the supply of solar modules to the United States, and could impact the cost and timing of our solar projects.

In June 2022, the Biden Administration used its executive powers to issue a 24-month tariff moratorium on solar panels manufactured in Cambodia, Malaysia, Thailand, and Vietnam. The moratorium comes as a direct response to concerns raised about the adverse impact from the ongoing DOC complaint on the U.S. solar industry. As the DOC will continue its investigation discussed above, companies may still be subject to tariffs after the moratorium ends; however, U.S. companies will reportedly be exempt from any retroactive tariffs that previously could have applied. The Biden Administration also announced that it plans to invoke the Defense Production Act to accelerate the production of solar panels in the U.S. The Biden Administration's actions did not address whether WROs applied to panels under previous complaints would be affected.

## 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.

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2022 Annual Financial Statements

## Inflation Reduction Act

In August 2022, President Biden signed into law the IRA, which provides for $258 billion in energy-related provisions over a 10-year period. The provisions of the IRA are intended to, among other things, lower gasoline and electricity prices, incentivize domestic clean energy investment, manufacturing, and production, and promote reductions in carbon emissions. We believe that we and our customers can benefit from the IRA's provisions that extend tax benefits for renewable technologies, increase or restore higher rates for PTCs, add an option to claim PTCs for solar projects, expand qualified ITC facilities to include standalone energy storage, and its provision to allow companies to transfer tax credits generated from renewable projects. The IRA also implements a 15% corporate alternative minimum tax and a 1% excise tax on stock repurchases. Although significant regulatory guidance is expected on the tax provisions in the IRA, we currently believe the provisions on alternative minimum tax and stock repurchases will not have a material impact on us. Overall, we believe the IRA will help reduce our cost of investing in projects that will support our commitment to reduce emissions and provide customers affordable, reliable, and clean energy over the longer term.

## Return on Equity Incentive for Membership in a Transmission Organization

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

## American Transmission Company Allowed Return on Equity Complaints

The ROE allowed by the FERC helps determine how much transmission owners, such as ATC, earn on their transmission assets as well as how much consumers pay for those assets. When two complaints were filed arguing the base ROE for MISO transmission owners, including ATC, was too high, the FERC started analyzing the base ROE for these transmission owners.

The base ROEs listed in the two ROE complaint sections below do not include the 50 basis point ROE incentive currently provided for membership in a transmission organization. See the Return on Equity Incentive for Membership in a Transmission Organization section above for more information on this incentive.

**First Return on Equity Complaint** - In November 2013, a group of MISO industrial customers filed a complaint with the FERC asking that the FERC order a reduction to the base ROE used by MISO transmission owners, including ATC, from 12.2% to 9.15%. Due to this complaint, the FERC and the D.C. Circuit Court of Appeals issued the following orders and opinion. The refunds resulting from these orders and opinion are also described below.

- • Orders Issued by the FERC
  - ◦ September 2016 Order - On September 28, 2016, the FERC issued an order reducing the base ROE for MISO transmission owners to 10.32% for the period covered by the first complaint, November 12, 2013 through February 11, 2015 and September 28, 2016 going forward.
  - ◦ November 2019 Order - On November 21, 2019, the FERC issued another order after directing MISO transmission owners and other stakeholders to provide briefs and comments on a proposed change to the methodology for calculating base ROE. In this order, the FERC expanded its base ROE methodology to include the capital-asset pricing model in addition to the discounted cash flow model to better reflect how investors make their investment decisions. The FERC also rejected the use of the risk premium model as part of its base ROE methodology in this order. The FERC's modified methodology further reduced the base ROE for all MISO transmission owners, including ATC, to 9.88% for the period covered by the first complaint. In response to this FERC decision, requests for the FERC to rehear the November 2019 Order in its entirety were filed by various parties.
  - ◦ May 2020 Order - On May 21, 2020, the FERC issued an order that granted in part and denied in part the requests to rehear the November 2019 Order. In this May 2020 Order, the FERC made additional revisions to its base ROE methodology, including reinstating the use of the risk premium model. The additional revisions made by the FERC increased the base ROE for all MISO transmission owners, including ATC, from the 9.88% authorized in the November 2019 Order to 10.02% for the period covered by the first complaint. Various parties then filed requests to rehear certain parts of the May 2020 Order with the FERC.
  - ◦ November 2020 Order - In response to the rehearing requests filed concerning certain parts of the May 2020 Order, the FERC issued an order in November 2020 that confirmed the ROE previously authorized in its May 2020 Order.
  - ◦ Refunds - Due to the base ROE changes resulting from these FERC orders, ATC was required to provide refunds, with interest, for the 15-month refund period from November 12, 2013 through February 11, 2015 and for the period from September 28, 2016 through November 19, 2020. In January 2022, ATC completed providing WE, WPS, and UMERC with the net refunds related to the transmission costs they paid during the period covered by the first complaint. The refunds were applied to WE's and WPS's PSCW-approved escrow accounting for transmission expense.
- • Opinion Issued by the D.C. Circuit Court of Appeals
  - ◦ August 2022 Decision - Since several petitions for review were filed with the D.C. Circuit Court of Appeals concerning this ROE complaint, the D.C. Circuit Court of Appeals issued an opinion on August 9, 2022 addressing these petitions. In its August 2022

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Decision, the D.C. Circuit Court of Appeals ruled the FERC failed to adequately explain why it reinstated the use of the risk premium model as part of its ROE methodology in its May 2020 Order after previously rejecting the model in its November 2019 Order. Due to this ruling, the D.C. Circuit Court of Appeals vacated the FERC's previous orders and remanded the issue of determining an appropriate base ROE for MISO transmission owners back to the FERC for additional proceedings. As of December 31, 2022, the FERC had not provided a ruling in response to the August 2022 Decision issued by the D.C. Circuit Court of Appeals.

- Refunds - Since the FERC is required to conduct more proceedings, additional refunds could still be required for the 15-month period from November 12, 2013 through February 11, 2015 and for the period from September 28, 2016 until the date of any future order. Therefore, ATC recorded a liability on its financials for these potential refunds, which reduced our equity earnings from ATC by $18.6 million during the third quarter of 2022. The liability recorded by ATC is based on a 9.88% base ROE for the first complaint period. If it is ultimately determined a refund is required for the first complaint period, we would not expect any such refund to have a material impact on our financial statements or results of operations in the future. In addition, WE, WPS, and UMERC would be entitled to receive a portion of the refund from ATC for the benefit of their customers.

**Second Return on Equity Complaint** - In February 2015, a second complaint was filed with the FERC requesting a reduction in the base ROE used by MISO transmission owners, including ATC, to 8.67%, with a refund effective date retroactive to February 12, 2015. To resolve this complaint, the following orders and opinion were issued by the FERC and the D.C. Circuit Court of Appeals. The orders and opinion discussed below are the same orders and opinion described above in the first complaint section.

- Orders Issued by the FERC
  - November 2019 Order - Similar to the first complaint, the November 2019 Order stated the newly calculated base ROE of 9.88% was also reasonable for the period covered by the second complaint, February 12, 2015 through May 10, 2016. However, in the November 2019 Order, the FERC relied on certain provisions of the Federal Power Act to dismiss the second complaint and to determine refunds were not allowed for this period.
  - May 2020 Order - In its May 2020 Order, the FERC stated the newly calculated base ROE of 10.02% was also reasonable for the period covered by the second complaint. However, the FERC relied on the same provisions of the Federal Power Act to again dismiss the complaint and to determine refunds were not allowed for this period. In addition, the FERC denied in its May 2020 Order the requests to rehear both the dismissal of the second complaint and the determination that no refunds are allowed for the second complaint period.
- Opinion Issued by the D.C. Circuit Court of Appeals
  - August 2022 Decision - The August 2022 Decision issued by the D.C. Circuit Court of Appeals affirmed both the FERC's dismissal of the second complaint and the FERC's finding that no refunds are allowed for the second complaint period. Therefore, during the third quarter of 2022, we reduced the liability previously recorded for the potential refunds related to the second complaint period by $39.1 million, which increased our equity earnings from ATC.

## Environmental Matters

See Note 24, 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 utilities' rates are amounts to recover fuel, natural gas, and purchased power costs. Our utilities have recovery mechanisms in place that generally allow them 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.

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 riders and other mechanisms that allow for cost recovery or refund of uncollectible expense.

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 higher than our normal winter weather expectations. As a result

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of this extreme weather event, we requested approval for the recovery of an additional $322 million of natural gas costs across our service territories, above what was either set as a benchmark in our respective GCRMs or included in rates. See Note 26, Regulatory Environment, for more information on our recovery efforts associated with these costs.

## Weather

Our utilities' 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. PGL, NSG, and MERC have decoupling mechanisms in place that help reduce the impacts of weather. Decoupling mechanisms differ by state and allow utilities to recover or refund certain differences between actual and authorized margins. A summary of actual weather information in our utilities' service territories during 2022 and 2021, as measured by degree days, can be found in Results of Operations.

## Interest Rates

We are exposed to interest rate risk resulting from our short-term and long-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. We may also enter into derivative financial instruments, such as swaps, to mitigate interest rate exposure.

Based on the variable rate debt outstanding at December 31, 2022 and 2021, a hypothetical increase in market interest rates of one percentage point would have increased annual interest expense by $21.4 million and $24.0 million in 2022 and 2021, 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. The financial risks associated with investment returns are mitigated at our Wisconsin utilities through the requirement that WE, WPS, and WG implement escrow accounting treatment for pension and OPEB costs in 2023 and 2024, as required by the December 2022 rate order issued by the PSCW. We also believe that the financial risks associated with investment returns would be partially mitigated at our other utilities through future rate actions by regulators. See Note 26, Regulatory Environment, for more information on 2023 and 2024 rates at our Wisconsin utilities.

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

| (in millions) | As of December 31, 2022 | Expected Return on Assets in 2023 |
| --- | --- | --- |
| Pension trust funds | $2,628.0 | 6.88% |
| OPEB trust funds | $835.3 | 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.

We consult with our investment advisors on an annual basis to help us 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

We have electric and natural gas utility operations that serve customers in Wisconsin, Illinois, Minnesota, and Michigan. 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 reductions. We monitor the global supply chain, and related disruptions, in order to ensure we are able to procure the necessary materials and other resources necessary to both maintain our energy services in a safe and reliable manner and to grow our infrastructure in accordance with our capital plan.

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

## 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 judgments 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 ratemaking principles followed by the various 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. See Note 6, Regulatory Assets and Liabilities, for more information on our regulatory assets and liabilities.

### Goodwill

We completed our annual goodwill impairment tests for all of our reporting units that carried a goodwill balance as of July 1, 2022. No impairments were recorded as a result of these tests. For all of our reporting units, the fair values calculated in step one of the test were greater than their carrying values. The fair values for the reporting units were calculated using a combination of the income approach and the market approach. The income approach received a weighting of 60% while the market approach received a weighting of 40% to determine an overall valuation.

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 all of our reporting units are regulated, a fair recovery of and return on costs prudently incurred to serve customers is assumed. An unfavorable outcome in a rate case could cause the fair values of our reporting units to decrease.

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

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

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

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For all of our reporting units that carried a goodwill balance at July 1, 2022, the fair value exceeded its carrying value by over 50%. Based on these results, our reporting units are not at risk of failing step one of the goodwill impairment test.

See Note 10, Goodwill and Intangibles, 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(k), Asset Impairment, for our policy on accounting for abandonments.

Performing an impairment evaluation involves a significant degree of estimation and judgment 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 recent comparable third-party sales for our nonregulated operations, 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 26, 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 20, 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. Changes in benefit costs are mitigated at our Wisconsin utilities through the requirement that WE, WPS, and WG implement escrow accounting treatment for pension and OPEB costs in 2023 and 2024, as required by the December 2022 rate orders issued by the PSCW. See Note 26, Regulatory Environment, for more information on 2023 and 2024 rates at our Wisconsin utilities. We believe that changes to benefit costs at our other utilities would be recovered or refunded through the ratemaking process.

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 (including amounts capitalized to our balance sheets). 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 2022 Pension Cost |
| --- | --- | --- | --- |
| Discount rate | (0.5) | $114.5 | $17.8 |
| Discount rate | 0.5 | (101.6) | (11.1) |
| Rate of return on plan assets | (0.5) | N/A | 14.8 |
| Rate of return on plan assets | 0.5 | N/A | (14.8) |

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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 (including amounts capitalized to our balance sheets). 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 2022 Postretirement Benefit Cost |
| --- | --- | --- | --- |
| Discount rate | (0.5) | $19.2 | $2.6 |
| Discount rate | 0.5 | (17.2) | (2.6) |
| Health care cost trend rate | (0.5) | (10.4) | (3.8) |
| Health care cost trend rate | 0.5 | 11.6 | 4.3 |
| Rate of return on plan assets | (0.5) | N/A | 4.9 |
| Rate of return on plan assets | 0.5 | N/A | (4.9) |

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 6.88% in 2022 and 2021, and 6.87% in 2020. The actual rate of return on pension plan assets, net of fees, was (14.03)%, 9.5%, and 12.65%, in 2022, 2021, and 2020, 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 20, 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 $663.1 million and $531.7 million as of December 31, 2022 and 2021, respectively. The changes in unbilled revenues are primarily due to changes in the cost of natural gas, weather, and customer rates.

## 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(q), 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 consolidated 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 2023 annual effective tax rate to be between 13.0% and 14.0%. Our effective tax rate calculations are revised every quarter based on the best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.

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# QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See Management's Discussion and Analysis of Financial Condition and Results of Operations - Factors Affecting Results, Liquidity, and Capital Resources - Market Risks and Other Significant Risks, as well as Note 1(r), Fair Value Measurements, Note 1(s), Derivative Instruments, and Note 19, Guarantees, for information concerning potential market risks to which we are exposed.

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# **WEC ENERGY GROUP, INC.**  
 **CONSOLIDATED INCOME STATEMENTS**

| Year Ended December 31 (in millions, except per share amounts) | 2022 | 2021 | 2020 |
| --- | --- | --- | --- |
| Operating revenues | $9,597.4 | $8,316.0 | $7,241.7 |
| Operating expenses |  |  |  |
| Cost of sales | 4,358.9 | 3,311.0 | 2,319.5 |
| Other operation and maintenance | 1,938.0 | 2,005.5 | 2,032.2 |
| Depreciation and amortization | 1,122.6 | 1,074.3 | 975.9 |
| Property and revenue taxes | 253.7 | 210.3 | 208.0 |
| Total operating expenses | 7,673.2 | 6,601.1 | 5,535.6 |
| Operating income | 1,924.2 | 1,714.9 | 1,706.1 |
| Equity in earnings of transmission affiliates | 194.7 | 158.1 | 175.8 |
| Other income, net | 128.8 | 133.2 | 79.5 |
| Interest expense | 515.1 | 471.1 | 493.7 |
| Loss on debt extinguishment | - | 36.3 | 38.4 |
| Other expense | (191.6) | (216.1) | (276.8) |
| Income before income taxes | 1,732.6 | 1,498.8 | 1,429.3 |
| Income tax expense | 322.9 | 200.3 | 227.9 |
| Net income | 1,409.7 | 1,298.5 | 1,201.4 |
| Preferred stock dividends of subsidiary | 1.2 | 1.2 | 1.2 |
| Net (income) loss attributed to noncontrolling interests | (0.4) | 3.0 | (0.3) |
| Net income attributed to common shareholders | $1,408.1 | $1,300.3 | $1,199.9 |
| Earnings per share |  |  |  |
| Basic | $4.46 | $4.12 | $3.80 |
| Diluted | $4.45 | $4.11 | $3.79 |
| Weighted average common shares outstanding |  |  |  |
| Basic | 315.4 | 315.4 | 315.4 |
| Diluted | 316.1 | 316.3 | 316.5 |

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

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# **WEC ENERGY GROUP, INC.**  
 **CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME**

| Year Ended December 31 (in millions) | 2022 | 2021 | 2020 |
| --- | --- | --- | --- |
| Net income | $1,409.7 | $1,298.5 | $1,201.4 |
| Other comprehensive income (loss), net of tax |  |  |  |
| Derivatives accounted for as cash flow hedges |  |  |  |
| Net derivative gain (loss), net of tax expense (benefit) of $0.0, $0.2, and $(1.6), respectively | - | 0.6 | (4.3) |
| Reclassification of realized net derivative (gain) loss to net income, net of tax | (0.3) | 0.9 | 1.5 |
| Cash flow hedges, net | (0.3) | 1.5 | (2.8) |
| Defined benefit plans |  |  |  |
| Pension and OPEB adjustments arising during the period, net of tax expense (benefit) of $(1.3), $0.7, and $(0.2), respectively | (3.5) | 1.7 | (0.5) |
| Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax | 0.2 | 0.4 | 0.6 |
| Defined benefit plans, net | (3.3) | 2.1 | 0.1 |
| Other comprehensive income (loss), net of tax | (3.6) | 3.6 | (2.7) |
| Comprehensive income | 1,406.1 | 1,302.1 | 1,198.7 |
| Preferred stock dividends of subsidiary | 1.2 | 1.2 | 1.2 |
| Comprehensive (income) loss attributed to noncontrolling interests | (0.4) | 3.0 | (0.3) |
| Comprehensive income attributed to common shareholders | $1,404.5 | $1,303.9 | $1,197.2 |

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

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# **WEC ENERGY GROUP, INC.**
**CONSOLIDATED BALANCE SHEETS**

| At December 31 |  |  |
| --- | --- | --- |
| (in millions, except share and per share amounts) |  |  |
|  | 2022 | 2021 |
| Assets |  |  |
| Current assets |  |  |
| Cash and cash equivalents | $28.9 | $16.3 |
| Accounts receivable and unbilled revenues, net of reserves of $199.3 and $198.3, respectively | 1,818.4 | 1,505.7 |
| Materials, supplies, and inventories | 807.1 | 635.8 |
| Prepaid taxes | 201.8 | 182.1 |
| Other prepayments | 69.8 | 63.4 |
| Other | 261.7 | 253.4 |
| Current assets | 3,187.7 | 2,656.7 |
| Long-term assets |  |  |
| Property, plant, and equipment, net of accumulated depreciation and amortization of $10,383.8 and $9,889.3, respectively | 29,113.8 | 26,982.4 |
| Regulatory assets (December 31, 2022 and December 31, 2021 include $92.4 and $100.7, respectively, related to WEPCo Environmental Trust) | 3,264.6 | 3,264.8 |
| Equity investment in transmission affiliates | 1,909.2 | 1,789.4 |
| Goodwill | 3,052.8 | 3,052.8 |
| Pension and OPEB assets | 916.7 | 881.3 |
| Other | 427.3 | 361.1 |
| Long-term assets | 38,684.4 | 36,331.8 |
| Total assets | $41,872.1 | $38,988.5 |
| Liabilities and Equity |  |  |
| Current liabilities |  |  |
| Short-term debt | $1,647.1 | $1,897.0 |
| Current portion of long-term debt (December 31, 2022 and December 31, 2021 include $8.9 and $8.8, respectively, related to WEPCo Environmental Trust) | 881.2 | 169.4 |
| Accounts payable | 1,198.1 | 1,005.7 |
| Other | 884.6 | 680.9 |
| Current liabilities | 4,611.0 | 3,753.0 |
| Long-term liabilities |  |  |
| Long-term debt (December 31, 2022 and December 31, 2021 include $94.1 and $102.7, respectively, related to WEPCo Environmental Trust) | 14,766.2 | 13,523.7 |
| Deferred income taxes | 4,625.6 | 4,308.5 |
| Deferred revenue, net | 370.7 | 389.2 |
| Regulatory liabilities | 3,735.5 | 3,946.0 |
| Environmental remediation liabilities | 499.6 | 532.6 |
| Pension and OPEB obligations | 171.6 | 219.0 |
| Other | 1,475.3 | 1,203.2 |
| Long-term liabilities | 25,644.5 | 24,122.2 |
| Commitments and contingencies (Note 24) |  |  |
| Common shareholders' equity |  |  |
| Common stock - $0.01 par value; 325,000,000 shares authorized; 315,434,531 shares outstanding | 3.2 | 3.2 |
| Additional paid in capital | 4,115.2 | 4,138.1 |
| Retained earnings | 7,265.3 | 6,775.1 |
| Accumulated other comprehensive loss | (6.8) | (3.2) |
| Common shareholders' equity | 11,376.9 | 10,913.2 |
| Preferred stock of subsidiary | 30.4 | 30.4 |
| Noncontrolling interests | 209.3 | 169.7 |
| Total liabilities and equity | $41,872.1 | $38,988.5 |

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

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# **WEC ENERGY GROUP, INC.**  
 **CONSOLIDATED STATEMENTS OF CASH FLOWS**

| Year Ended December 31 (in millions) | 2022 | 2021 | 2020 |
| --- | --- | --- | --- |
| Operating activities |  |  |  |
| Net income | $1,409.7 | $1,298.5 | $1,201.4 |
| Reconciliation to cash provided by operating activities |  |  |  |
| Depreciation and amortization | 1,122.6 | 1,074.3 | 975.9 |
| Deferred income taxes and ITCs, net | 280.1 | 151.1 | 209.4 |
| Contributions and payments related to pension and OPEB plans | (15.1) | (66.3) | (113.2) |
| Equity income in transmission affiliates, net of distributions | (74.3) | (25.1) | (29.1) |
| Net change in transmission regulatory assets and liabilities | (85.8) | 5.7 | 36.2 |
| Net gain on disposition of assets | (66.2) | (6.2) | (3.5) |
| Change in - |  |  |  |
| Accounts receivable and unbilled revenues, net | (342.1) | (249.2) | 16.1 |
| Materials, supplies, and inventories | (171.3) | (107.2) | 21.2 |
| Amounts recoverable from customers | 60.0 | (82.3) | 0.9 |
| Collateral on deposit | (108.1) | 4.6 | 15.6 |
| Other current assets | (27.7) | 17.6 | (3.1) |
| Accounts payable | 121.5 | 126.9 | (61.3) |
| Other current liabilities | 126.9 | (17.2) | (41.2) |
| Other, net | (169.5) | (92.5) | (29.3) |
| Net cash provided by operating activities | 2,060.7 | 2,032.7 | 2,196.0 |
| Investing activities |  |  |  |
| Capital expenditures | (2,314.9) | (2,252.8) | (2,238.8) |
| Acquisition of Thunderhead, net of cash acquired of $0.5 | (382.0) | - | - |
| Acquisition of Jayhawk | - | (119.9) | - |
| Acquisition of Blooming Grove, net of restricted cash acquired of $24.1 | - | - | (364.6) |
| Acquisition of Tatanka Ridge | - | - | (239.9) |
| Acquisition of intangible assets | (19.2) | - | - |
| Capital contributions to transmission affiliates | (45.5) | - | (21.2) |
| Proceeds from the sale of assets | 69.0 | 21.9 | 20.3 |
| Proceeds from the sale of investments held in rabbi trust | 15.4 | 18.7 | 56.2 |
| Purchase of investments held in rabbi trust | - | - | (37.8) |
| Payments for ATC's construction costs that will be reimbursed | (24.8) | (7.0) | (3.5) |
| Reimbursement for ATC's construction costs | 10.2 | - | 1.1 |
| Insurance proceeds received for property damage | 41.6 | - | 23.2 |
| Other, net | 7.8 | 27.3 | (1.8) |
| Net cash used in investing activities | (2,642.4) | (2,311.8) | (2,806.8) |
| Financing activities |  |  |  |
| Exercise of stock options | 33.6 | 15.7 | 43.8 |
| Purchase of common stock | (69.2) | (33.1) | (99.2) |
| Dividends paid on common stock | (917.9) | (854.8) | (798.0) |
| Issuance of long-term debt | 1,999.3 | 2,383.8 | 2,373.6 |
| Retirement of long-term debt | (92.1) | (1,260.4) | (1,767.0) |
| Issuance of short-term loan | 2.7 | 0.9 | 340.0 |
| Repayment of short-term loan | - | (340.0) | - |
| Change in commercial paper | (252.6) | 459.2 | 606.1 |
| Payments for debt extinguishment and issuance costs | (15.6) | (67.2) | (55.8) |
| Purchase of additional ownership interest in Upstream from noncontrolling interest | - | - | (31.0) |
| Other, net | (11.8) | (10.1) | (11.4) |
| Net cash provided by financing activities | 676.4 | 294.0 | 601.1 |
| Net change in cash, cash equivalents, and restricted cash | 94.7 | 14.9 | (9.7) |
| Cash, cash equivalents, and restricted cash at beginning of year | 87.5 | 72.6 | 82.3 |
| Cash, cash equivalents, and restricted cash at end of year | $182.2 | $87.5 | $72.6 |

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

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# **WEC ENERGY GROUP, INC.**  
 **CONSOLIDATED STATEMENTS OF EQUITY**

| (in millions, except per share amounts) | WEC Energy Group Common Shareholders' Equity |  |  |  |  | Preferred Stock of Subsidiary | Non-controlling Interests | Total Equity |
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
|  | Common Stock | Additional Paid In Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Total Common Shareholders' Equity |  |  |  |
| Balance at December 31, 2019 | $3.2 | $4,186.6 | $5,927.7 | $(4.1) | $10,113.4 | $30.4 | $110.8 | $10,254.6 |
| Net income attributed to common shareholders | - | - | 1,199.9 | - | 1,199.9 | - | - | 1,199.9 |
| Net income attributed to noncontrolling interests | - | - | - | - | - | - | 0.3 | 0.3 |
| Other comprehensive loss | - | - | - | (2.7) | (2.7) | - | - | (2.7) |
| Common stock dividends of $2.53 per share | - | - | (798.0) | - | (798.0) | - | - | (798.0) |
| Exercise of stock options | - | 43.8 | - | - | 43.8 | - | - | 43.8 |
| Purchase of common stock | - | (99.2) | - | - | (99.2) | - | - | (99.2) |
| Purchase of additional ownership interest in Upstream from noncontrolling interest | - | - | - | - | - | - | (31.0) | (31.0) |
| Acquisition of noncontrolling interests | - | - | - | - | - | - | 85.0 | 85.0 |
| Distributions to noncontrolling interests | - | - | - | - | - | - | (2.7) | (2.7) |
| Stock-based compensation and other | - | 12.5 | - | - | 12.5 | - | - | 12.5 |
| Balance at December 31, 2020 | $3.2 | $4,143.7 | $6,329.6 | $(6.8) | $10,469.7 | $30.4 | $162.4 | $10,662.5 |
| Net income attributed to common shareholders | - | - | 1,300.3 | - | 1,300.3 | - | - | 1,300.3 |
| Net loss attributed to noncontrolling interests | - | - | - | - | - | - | (3.0) | (3.0) |
| Other comprehensive income | - | - | - | 3.6 | 3.6 | - | - | 3.6 |
| Common stock dividends of $2.71 per share | - | - | (854.8) | - | (854.8) | - | - | (854.8) |
| Exercise of stock options | - | 15.7 | - | - | 15.7 | - | - | 15.7 |
| Purchase of common stock | - | (33.1) | - | - | (33.1) | - | - | (33.1) |
| Acquisition of noncontrolling interests | - | - | - | - | - | - | 6.3 | 6.3 |
| Capital contributions from noncontrolling interest | - | - | - | - | - | - | 7.6 | 7.6 |
| Distributions to noncontrolling interests | - | - | - | - | - | - | (4.1) | (4.1) |
| Stock-based compensation and other | - | 11.8 | - | - | 11.8 | - | 0.5 | 12.3 |
| Balance at December 31, 2021 | $3.2 | $4,138.1 | $6,775.1 | $(3.2) | $10,913.2 | $30.4 | $169.7 | $11,113.3 |
| Net income attributed to common shareholders | - | - | 1,408.1 | - | 1,408.1 | - | - | 1,408.1 |
| Net income attributed to noncontrolling interests | - | - | - | - | - | - | 0.4 | 0.4 |
| Other comprehensive loss | - | - | - | (3.6) | (3.6) | - | - | (3.6) |
| Common stock dividends of $2.91 per share | - | - | (917.9) | - | (917.9) | - | - | (917.9) |
| Exercise of stock options | - | 33.6 | - | - | 33.6 | - | - | 33.6 |
| Purchase of common stock | - | (69.2) | - | - | (69.2) | - | - | (69.2) |
| Acquisition of noncontrolling interests | - | - | - | - | - | - | 42.5 | 42.5 |
| Capital contributions from noncontrolling interest | - | - | - | - | - | - | 1.1 | 1.1 |
| Distributions to noncontrolling interests | - | - | - | - | - | - | (4.3) | (4.3) |
| Stock-based compensation and other | - | 12.7 | - | - | 12.7 | - | (0.1) | 12.6 |
| Balance at December 31, 2022 | $3.2 | $4,115.2 | $7,265.3 | $(6.8) | $11,376.9 | $30.4 | $209.3 | $11,616.6 |

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

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# **WEC ENERGY GROUP, INC.**
**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

# **NOTE 1-SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES**

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

As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, statements of comprehensive income, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. On our financial statements, we consolidate our majority-owned subsidiaries which we control, and VIEs of which we are the primary beneficiary. We reflect noncontrolling interests for the portion of entities that we do not own as a component of consolidated equity separate from the equity attributable to our shareholders. The noncontrolling interests that we reported as equity on our balance sheet as of December 31, 2022 related to the minority interests held by third parties in the wind generating facilities that are included in our non-utility energy infrastructure segment.

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

- Wisconsin segment - Consists of WE, WPS, and WG, which are engaged primarily in the generation of electricity and the distribution of electricity and natural gas in Wisconsin; and UMERC, which generates electricity and distributes electricity and natural gas to customers located in the Upper Peninsula of Michigan.
- Illinois segment - Consists of PGL and NSG, which are engaged primarily in the distribution of natural gas in Illinois.
- Other states segment - Consists of MERC and MGU, which are engaged primarily in the distribution of natural gas in Minnesota and Michigan, respectively.
- Electric transmission segment - Consists of our approximate 60% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions, and our approximate 75% ownership interest in ATC Holdco, which invests in transmission-related projects outside of ATC's traditional footprint.
- Non-utility energy infrastructure segment - Consists of We Power, which is principally engaged in the ownership of electric power generating facilities for long-term lease to WE, and Bluewater, which owns underground natural gas storage facilities in Michigan. WECI, which holds our ownership interests in several wind generating facilities, is also included in this segment. See Note 2, Acquisitions, for more information on the recently acquired WECI renewable generating facilities.
- Corporate and other segment - Consists of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Wisvest, WECC, WBS, and also included the operations of PDL prior to the sale of its remaining solar facilities in the fourth quarter of 2020. See Note 3, Dispositions, for more information on the sale of these solar facilities.

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

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

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

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

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

# **Revenues from Contracts with Customers**

**Electric Utility Operating Revenues** - Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the

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electricity is delivered and consumed by the customer simultaneously. For our Wisconsin residential and commercial and industrial customers and the majority of our Michigan residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. In our Michigan service territory, a limited number of residential and commercial and industrial customers can purchase the commodity from a third party. In this case, the delivery of the electricity represents our sole performance obligation.

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

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

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

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

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

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

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

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The tariffs of our natural gas utilities include various rate mechanisms that allow them to recover or refund changes in prudently incurred costs from rate case-approved amounts. The rates for all of our natural gas utilities include one-for-one recovery mechanisms for natural gas commodity costs. Under normal circumstances, we defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year. However, as a result of the extreme weather in the Midwest in February 2021, the cost of gas purchased for our natural gas customers was temporarily driven significantly higher than our normal winter weather expectations. See Note 26, Regulatory Environment, for more information on the recovery of these high natural gas costs.

In addition, the rates of PGL and NSG, and the residential tariffs of WE, WPS, and WG, include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. The rates of PGL and NSG include riders for cost recovery of both environmental cleanup costs and energy conservation and management program costs. Finally, PGL's rates include a rider for pass through of income tax expense changes resulting from the Tax Legislation and a cost recovery mechanism for SMP costs, and similarly, the rates of MERC and MGU include riders to recover costs incurred to replace or modify natural gas facilities.

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

**Other Natural Gas Operating Revenues** - We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment. Bluewater has entered into long-term service agreements for natural gas storage services with WE, WPS, and WG, and also provides limited service to unaffiliated customers. All amounts associated with the service agreements with WE, WPS, and WG have been eliminated at the consolidated level.

**Other Non-Utility Operating Revenues** - Wind generation revenues from WECI's ownership interests in wind generation facilities continued to grow in 2022. See Note 2, Acquisitions, for more information on recent acquisitions. Most of these wind generation facilities have offtake agreements with unaffiliated third parties for all of the energy to be produced by the facility, some of which are bundled with capacity and RECs. We consider bundled energy, capacity and RECs within these offtake agreements to be distinct performance obligations as each are often transacted separately in the marketplace.

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

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

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

As part of the construction of the We Power electric generating units, we capitalized interest during construction, which is included in property, plant, and equipment. As allowed by the PSCW, we collected these carrying costs from WE's utility customers during construction. The equity portion of these carrying costs was recorded as a contract liability, which is presented as deferred revenue, net on our balance sheets. We continually amortize the deferred carrying costs to revenues over the related lease term that We Power has with WE. During 2022, 2021, and 2020, we recorded $23.4 million, $23.3 million, and $22.9 million, respectively, of revenues related to these deferred carrying costs.

### **Other Operating Revenues**

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

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

- The rates of PGL, NSG, and MERC include decoupling mechanisms. These mechanisms differ by state and allow the utilities to recover or refund the differences between actual and authorized margins for certain customer classes. See Note 26, Regulatory Environment, for more information.
- PGL and NSG were authorized to implement a SPC rider for the recovery of incremental direct costs resulting from the COVID-19 pandemic, foregone late fees and reconnection charges, and the costs associated with their bill payment assistance programs. See Note 26, Regulatory Environment, for more information.
- MERC's rates include a CIP rider, which includes a financial incentive for meeting energy savings goals.
- WE and WPS provide wholesale electric service to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.

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

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 primarily generated from the sale of electricity and natural gas by our regulated utility operations. Credit losses associated with our utility operations are analyzed at the reportable segment level as we believe contract terms, political and economic risks, and the regulatory environment are similar at this level as our reportable segments are generally based on the geographic location of the underlying utility operations.

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

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

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

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

| (in millions) | 2022 | 2021 |
| --- | --- | --- |
| Natural gas in storage | $446.3 | $326.0 |
| Materials and supplies | 257.0 | 225.3 |
| Fossil fuel | 103.8 | 84.5 |
| Total | $807.1 | $635.8 |

PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. Inventories stated on a LIFO basis represented approximately 13% and 19% of total inventories at December 31, 2022 and 2021, respectively. The estimated replacement cost of natural gas in inventory at December 31, 2022 and 2021, exceeded the LIFO cost by $98.3 million and $114.2 million, respectively. In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per Dth of $3.41 at December 31, 2022, and $3.67 at December 31, 2021.

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

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

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

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

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

| Annual Utility Composite Depreciation Rates | 2022 | 2021 | 2020 |
| --- | --- | --- | --- |
| WE | 3.06% | 3.09% | 3.19% |
| WPS | 2.67% | 2.66% | 2.63% |
| WG | 2.47% | 2.44% | 2.33% |
| PGL | 3.13% | 3.12% | 3.16% |
| NSG | 2.43% | 2.52% | 2.48% |
| MERC | 2.56% | 2.58% | 2.47% |
| MGU | 2.75% | 2.70% | 2.67% |
| UMERC | 3.01% | 2.94% | 2.97% |

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

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

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

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

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

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

|  | 2022 |  |
| --- | --- | --- |
|  | Average AFUDC Retail Rate | Average AFUDC Wholesale Rate |
| WE | 8.68% | 5.35% |
| WPS | 7.55% | 5.49% |
| WG | 8.32% | N/A |
| UMERC | 6.28% | N/A |
| WBS | 7.55% | N/A |

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

| (in millions) | 2022 | 2021 | 2020 |
| --- | --- | --- | --- |
| AFUDC-Debt |  |  |  |
| WE | $6.9 | $2.9 | $2.6 |
| WPS | 2.3 | 3.5 | 4.6 |
| WG | 1.4 | 0.2 | 0.6 |
| UMERC | 0.1 | 0.1 | - |
| WBS | 0.1 | 0.1 | 0.1 |
| Other | 0.2 | - | 0.1 |
| Total AFUDC-Debt | $11.0 | $6.8 | $8.0 |
| AFUDC-Equity |  |  |  |
| WE | $18.8 | $7.9 | $7.0 |
| WPS | 5.8 | 9.0 | 11.8 |
| WG | 3.9 | 0.6 | 1.6 |
| UMERC | 0.1 | 0.1 | 0.1 |
| WBS | 0.3 | 0.2 | 0.2 |
| Other | 0.5 | 0.2 | 0.2 |
| Total AFUDC-Equity | $29.4 | $18.0 | $20.9 |

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

At December 31, 2022 and 2021, we had $4.7 million and $3.3 million, respectively, of capitalized implementation costs related to cloud computing arrangements that are hosted service contracts. We amortize the implementation costs on a straight-line basis over the cloud computing service arrangement term once the component of the hosted service is ready for its intended use. Accumulated amortization at December 31, 2022 and 2021, was $1.5 million and $0.6 million, respectively. Amortization expense for the years ended December 31, 2022, 2021, and 2020 was not significant. The presentation of the implementation costs, along with the related accumulated amortization, follows the prepaid hosting fees.

**(k) Asset Impairment**-Goodwill and other intangible assets with indefinite lives are subject to an annual impairment test. Interim impairment tests are performed when impairment indicators are present. During the third quarter of each year, we perform an annual impairment test at all of our reporting units that carry a goodwill balance. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit's net assets exceeds the reporting unit's fair value. An impairment loss is recorded as the excess of the carrying amount of the goodwill over its fair value. For our indefinite-lived intangible assets, an impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. An impairment loss is measured as the excess of the carrying amount of the intangible assets over its fair value. No impairment losses were recorded for our indefinite-lived intangible assets during the years ended December 31, 2022 and 2021. See Note 10, Goodwill and Intangibles, for more information.

We periodically assess the recoverability of certain long-lived assets when factors indicate the carrying value of such assets may be impaired or such assets are planned to be sold. Long-lived assets that would be subject to an impairment assessment generally include any assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future, as well as assets within nonregulated operations that are proposed to be sold or are currently generating operating losses. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds 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 over 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, and Note 7, Property, Plant, and Equipment, for more information.

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2022 Annual Financial Statements

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

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

**(m) Intangible Liabilities**-Our finite-lived intangible liabilities include revenue contracts, consisting of PPAs and a proxy revenue swap, in addition to interconnection agreements, which were all obtained through the acquisitions of wind generation facilities by WECI in our non-utility energy infrastructure segment. Intangible liabilities are amortized on a straight-line basis over their estimated useful life. Amortization of revenue contracts is recorded within operating revenues in the income statements. Amortization related to the interconnection agreements is recorded within other operation and maintenance in the income statements. The straight-line method of amortization is used because it best reflects the pattern in which the economic benefits of the intangibles are consumed or otherwise used. The amounts and useful lives assigned to intangible liabilities assumed impact the amount and timing of future amortization.

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

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

### **Stock Options**

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

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

|  | 2022 | 2021 | 2020 |
| --- | --- | --- | --- |
| Stock options granted | 437,269 | 530,612 | 554,594 |
| Estimated weighted-average fair value per stock option | $14.71 | $13.20 | $10.94 |
| Assumptions used to value the options: |  |  |  |
| Risk-free interest rate | 0.2% - 1.6% | 0.1% - 0.9% | 0.2% - 1.9% |
| Dividend yield | 3.2% | 2.9% | 3.0% |
| Expected volatility | 21.0% | 21.0% | 16.3% |
| Expected life (years) | 8.7 | 8.7 | 8.6 |

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

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2022 Annual Financial Statements

### **Restricted Shares**

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

Our restricted shares are classified as equity awards.

### **Performance Units**

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

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

The WEC Energy Group Performance Unit Plan was amended and restated, effective January 1, 2023. In accordance with the amended plan, the Compensation Committee selected multiple performance measures that will be weighted to determine the ultimate payout for the awards granted in 2023. The ultimate number of units awarded will be based on our total shareholder return compared to the total shareholder return of a peer group of companies over three years (55%), and our performance against the weighted average authorized ROE of all of our utility subsidiaries (45%). In addition, the Compensation Committee selected the level of our stock price to earnings ratio compared to our peer companies as a performance measure that can increase the payout by up to 25%. In no event can the performance unit payout be greater than 200% of the target award.

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

**(o) Earnings Per Share**-We compute basic earnings per share by dividing our net income attributed to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per share is computed in a similar manner, but includes the exercise and/or conversion of all potentially dilutive securities. Such dilutive securities include in-the-money stock options. The calculation of diluted earnings per share for the years ended December 31, 2022, 2021, and 2020 excluded 653,323; 769,030; and 207,445 stock options, respectively, that had an anti-dilutive effect.

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

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

See Note 15, Leases, for more information.

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

ITCs 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. The amount of the credit is based upon power production from our qualifying generation facilities. We file a consolidated federal income tax return. Accordingly, we allocate federal current tax expense, benefits, and credits to our subsidiaries based on their separate tax computations and our ability to monetize all credits on our consolidated federal return. 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.

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2022 Annual Financial Statements

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Utility customers can elect to be on a budget plan. Under this type of plan, a monthly installment amount is calculated based on estimated annual usage. During the year, the monthly installment amount is reviewed by comparing it to actual usage. If necessary, an

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adjustment is made to the monthly amount. Annually, the budget plan is reconciled to actual annual usage. Payments in excess of actual customer usage are recorded within other current liabilities on our balance sheets.

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

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

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

We review our estimated costs of remediation annually for our manufactured gas plant sites and 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.

**(x) Customer Concentrations of Credit Risk**-The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Credit risk exposure at WE, WPS, WG, PGL, and NSG is mitigated by their recovery mechanisms for uncollectible expense discussed in Note 1(d), Operating Revenues. As a result, we did not have any significant concentrations of credit risk at December 31, 2022. In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2022.

## NOTE 2-ACQUISITIONS

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

### Acquisition of Wind Generation Facilities in Illinois

In February 2023, WECI completed the acquisition of a 90% ownership interest in Sapphire Sky, a commercially operational 250 MW wind generating facility in McLean County, Illinois, for a total investment of approximately $442.9 million, which includes transaction costs. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 12 years. Sapphire Sky qualifies for PTCs and is included in the non-utility energy infrastructure segment.

In October 2022, WECI signed an agreement to acquire an 80% ownership interest in Maple Flats, a 250 MW solar generating facility under construction in Clay County, Illinois, for approximately $360 million. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years. The transaction is subject to FERC approval and commercial operation is expected to begin during the first half of 2024, at which time the transaction is expected to close. Maple Flats is expected to qualify for PTCs and will be included in the non-utility energy infrastructure segment.

In December 2020, WECI completed the acquisition of a 90% ownership interest in Blooming Grove, a commercially operational 250 MW wind generating facility in McLean County, Illinois, for a total investment of $364.6 million, which includes transaction costs and is net of restricted cash acquired of $24.1 million. Blooming Grove has offtake agreements for all the energy produced with affiliates of two investment grade multinational companies for 12 years. Blooming Grove qualifies for PTCs and is included in the non-utility energy infrastructure segment.

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2022 Annual Financial Statements

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

| (in millions) |  |
| --- | --- |
| Accounts receivable | $0.3 |
| Net property, plant, and equipment | 488.3 |
| Other long-term assets | 2.9 |
| Accounts payable | (13.7) |
| Other current liabilities | (1.5) |
| Other long-term liabilities | (68.7) |
| Noncontrolling interest | (43.0) |
| Total purchase price | $364.6 |

### **Acquisition of a Solar Generation Facility in Texas**

In January 2023, WECI signed an agreement to acquire an 80% ownership interest in Samson I, a 250 MW solar generating facility in Lamar County, Texas, for approximately $250 million. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years. Commercial operation was achieved in May 2022. Samson I is expected to qualify for PTCs and will be included in the non-utility energy infrastructure segment.

### **Acquisition of Electric Generation Facilities in Wisconsin**

Effective January 1, 2023, WE and WPS completed the acquisition of Whitewater, a commercially operational 236.5 MW dual fueled (natural gas and low sulfur fuel oil) combined cycle electrical generation facility in Whitewater, Wisconsin, for $72.7 million, which excludes working capital and transaction costs. See Note 15, Leases, for more information.

In January 2022, WPS, along with an unaffiliated utility, received PSCW approval to acquire Red Barn, a utility-scale wind-powered electric generating facility. The project will be located in Grant County, Wisconsin and once constructed, WPS will own 82 MW of this project. WPS's share of the cost of this project is estimated to be $160 million, with commercial operation expected to begin in the first half of 2023, at which time the transaction is expected to close. Red Barn is expected to qualify for PTCs.

### **Acquisition of a Wind Generation Facility in Nebraska**

In September 2022, WECI completed the acquisition of a 90% ownership interest in Thunderhead, a 300 MW wind generating facility in Antelope and Wheeler counties in Nebraska. The purchase price was $382.0 million, which includes transaction costs and is net of cash acquired. Thunderhead achieved commercial operation in November 2022. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 12 years. Thunderhead qualifies for PTCs and is included in the non-utility energy infrastructure segment.

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

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

### **Acquisition of a Wind Generation Facility in Kansas**

In February 2021, WECI completed the acquisition of a 90% ownership interest in Jayhawk, a 190 MW wind generating facility in Bourbon and Crawford counties, Kansas, for $119.9 million, which included transaction costs. This project became commercially operational in December 2021. Subsequent to the acquisition, WECI incurred an additional $161.3 million of capital expenditures as of December 31, 2022 for the project for a total investment of $281.2 million. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 10 years. Jayhawk qualifies for PTCs. WECI is entitled to 99% of the tax benefits related to this facility for the first 10 years of commercial operation, after which it will be entitled to tax benefits equal to its ownership interest. Jayhawk is included in the non-utility energy infrastructure segment.

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2022 Annual Financial Statements

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

| (in millions) |  |
| --- | --- |
| Net property, plant, and equipment | $145.3 |
| Other long-term liabilities | (11.8) |
| Long-term debt | (7.3) |
| Noncontrolling interest | (6.3) |
| Total purchase price | $119.9 |

### **Acquisition of a Wind Generation Facility in South Dakota**

In December 2020, WECI completed the acquisition of an 85% ownership interest in Tatanka Ridge, a 155 MW wind generating facility in Deuel County, South Dakota, that became commercially operational in January 2021. WECI's total investment was $239.9 million, which included transaction costs. Tatanka Ridge has offtake agreements for all the energy produced with an affiliate of an investment grade multinational company for 12 years and a well-established electric cooperative that serves utilities in multiple states for 10 years. Tatanka Ridge qualifies for PTCs. WECI is entitled to 99% of the tax benefits related to this facility for the first 11 years of commercial operation, after which it will be entitled to tax benefits equal to its ownership interest. Tatanka Ridge is included in the non-utility energy infrastructure segment.

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

| (in millions) |  |
| --- | --- |
| Other current assets | $37.3 |
| Net property, plant, and equipment | 301.2 |
| Other current liabilities | (37.3) |
| Other long-term liabilities | (19.3) |
| Noncontrolling interest | (42.0) |
| Total purchase price | $239.9 |

## **NOTE 3-DISPOSITIONS**

### **Illinois Segment**

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

In May 2022, we sold approximately 11 acres of real estate owned by PGL that was no longer being utilized in its operations, for $55.1 million. The real estate was located in Chicago, Illinois. As a result of the sale, a pre-tax gain in the amount of $54.5 million was recorded within other operation and maintenance expense on our income statement. The book value of the real estate included in the sale was not material and, therefore, was not presented as held for sale.

### **Corporate and Other Segment**

#### ***Sale of Certain WPS Power Development, LLC Solar Power Generation Facilities***

In November 2020, we sold a portfolio of residential solar facilities owned by PDL for $10.5 million. These solar facilities were located in California and Hawaii. During the fourth quarter of 2020, we recorded an after-tax gain on the sale of $3.0 million primarily related to the recognition of deferred ITCs, which were included as a reduction of income tax expense on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations of these facilities remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.

WEC Energy Group

F-55

2022 Annual Financial Statements

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

| (in millions) | Wisconsin | Illinois | Other States | Total Utility Operations | Non-Utility Energy Infrastructure | Corporate and Other | Reconciling Eliminations | WEC Energy Group Consolidated |
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Year ended December 31, 2022 |  |  |  |  |  |  |  |  |
| Electric | $4,956.2 | $ - | $ - | $4,956.2 | $ - | $ - | $ - | $4,956.2 |
| Natural gas | 1,980.7 | 1,883.7 | 601.8 | 4,466.2 | 54.3 | - | (51.8) | 4,468.7 |
| Total regulated revenues | 6,936.9 | 1,883.7 | 601.8 | 9,422.4 | 54.3 | - | (51.8) | 9,424.9 |
| Other non-utility revenues | - | - | 18.7 | 18.7 | 133.6 | - | (9.1) | 143.2 |
| Total revenues from contracts with customers | 6,936.9 | 1,883.7 | 620.5 | 9,441.1 | 187.9 | - | (60.9) | 9,568.1 |
| Other operating revenues | 23.6 | 7.2 | (2.0) | 28.8 | 402.1 | 0.5 | (402.1) (1) | 29.3 |
| Total operating revenues | $6,960.5 | $1,890.9 | $618.5 | $9,469.9 | $590.0 | $0.5 | $(463.0) | $9,597.4 |

| (in millions) | Wisconsin | Illinois | Other States | Total Utility Operations | Non-Utility Energy Infrastructure | Corporate and Other | Reconciling Eliminations | WEC Energy Group Consolidated |
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Year ended December 31, 2021 |  |  |  |  |  |  |  |  |
| Electric | $4,516.6 | $ - | $ - | $4,516.6 | $ - | $ - | $ - | $4,516.6 |
| Natural gas | 1,490.3 | 1,630.3 | 494.0 | 3,614.6 | 46.8 | - | (43.8) | 3,617.6 |
| Total regulated revenues | 6,006.9 | 1,630.3 | 494.0 | 8,131.2 | 46.8 | - | (43.8) | 8,134.2 |
| Other non-utility revenues | - | - | 17.8 | 17.8 | 92.8 | - | (9.1) | 101.5 |
| Total revenues from contracts with customers | 6,006.9 | 1,630.3 | 511.8 | 8,149.0 | 139.6 | - | (52.9) | 8,235.7 |
| Other operating revenues | 30.1 | 42.5 | 7.2 | 79.8 | 399.9 | 0.5 | (399.9) (1) | 80.3 |
| Total operating revenues | $6,037.0 | $1,672.8 | $519.0 | $8,228.8 | $539.5 | $0.5 | $(452.8) | $8,316.0 |

| (in millions) | Wisconsin | Illinois | Other States | Total Utility Operations | Non-Utility Energy Infrastructure | Corporate and Other | Reconciling Eliminations | WEC Energy Group Consolidated |
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Year Ended December 31, 2020 |  |  |  |  |  |  |  |  |
| Electric | $4,266.1 | $ - | $ - | $4,266.1 | $ - | $ - | $ - | $4,266.1 |
| Natural gas | 1,195.6 | 1,267.9 | 361.0 | 2,824.5 | 44.4 | - | (42.0) | 2,826.9 |
| Total regulated revenues | 5,461.7 | 1,267.9 | 361.0 | 7,090.6 | 44.4 | - | (42.0) | 7,093.0 |
| Other non-utility revenues | - | - | 17.1 | 17.1 | 66.6 | 1.7 | (9.1) | 76.3 |
| Total revenues from contracts with customers | 5,461.7 | 1,267.9 | 378.1 | 7,107.7 | 111.0 | 1.7 | (51.1) | 7,169.3 |
| Other operating revenues | 11.8 | 54.0 | 6.0 | 71.8 | 397.5 | 0.5 | (397.4) (1) | 72.4 |
| Total operating revenues | $5,473.5 | $1,321.9 | $384.1 | $7,179.5 | $508.5 | $2.2 | $(448.5) | $7,241.7 |

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

WEC Energy Group

F-56

2022 Annual Financial Statements

## Revenues from Contracts with Customers

**Electric Utility Operating Revenues** - The following table disaggregates electric utility operating revenues into customer class:

| (in millions) | Year Ended December 31 |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
| Residential | $1,879.1 | $1,768.0 | $1,743.9 |
| Small commercial and industrial | 1,530.4 | 1,415.7 | 1,325.9 |
| Large commercial and industrial | 1,042.2 | 931.9 | 821.5 |
| Other | 29.9 | 29.3 | 29.0 |
| Total retail revenues | 4,481.6 | 4,144.9 | 3,920.3 |
| Wholesale | 153.9 | 157.7 | 174.0 |
| Resale | 256.7 | 161.9 | 130.4 |
| Steam | 28.4 | 28.7 | 21.3 |
| Other utility revenues | 35.6 | 23.4 | 20.1 |
| Total electric utility operating revenues | $4,956.2 | $4,516.6 | $4,266.1 |

**Natural Gas Utility Operating Revenues** - The following tables disaggregate natural gas utility operating revenues into customer class:

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

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

| (in millions) | Wisconsin | Illinois | Other States | Total Natural Gas Utility Operating Revenues |
| --- | --- | --- | --- | --- |
| Year Ended December 31, 2020 |  |  |  |  |
| Residential | $752.6 | $802.2 | $220.8 | $1,775.6 |
| Commercial and industrial | 338.1 | 221.0 | 115.8 | 674.9 |
| Total retail revenues | 1,090.7 | 1,023.2 | 336.6 | 2,450.5 |
| Transportation | 79.1 | 215.6 | 31.5 | 326.2 |
| Other utility revenues (1) | 25.8 | 29.1 | (7.1) | 47.8 |
| Total natural gas utility operating revenues | $1,195.6 | $1,267.9 | $361.0 | $2,824.5 |

$^{(1)}$ Includes the revenues subject to the purchased gas recovery mechanisms of our utilities.

$^{(2)}$ During 2022, we continued to recover natural gas costs we under-collected from our customers in 2021 related to the extreme weather experienced in February 2021, as well as higher natural gas costs incurred at the majority of our segments during 2022. As these amounts are billed to customers, they are reflected in retail revenues with an offsetting decrease in other utility revenues.

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

See Note 26, Regulatory Environment, for more information.

WEC Energy Group

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2022 Annual Financial Statements

**Other Natural Gas Operating Revenues** - We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment. Bluewater has entered into long-term service agreements for natural gas storage services with WE, WPS, and WG, and also provides limited service to unaffiliated customers. All amounts associated with the service agreements with WE, WPS, and WG have been eliminated at the consolidated level.

**Other Non-Utility Operating Revenues** - Other non-utility operating revenues consist primarily of the following:

| (in millions) | Year Ended December 31 |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
| Wind generation revenues | $101.0 | $60.3 | $34.6 |
| We Power revenues | 23.4 | 23.3 | 22.9 |
| Appliance service revenues | 18.7 | 17.8 | 17.1 |
| Other | 0.1 | 0.1 | 1.7 |
| Total other non-utility operating revenues | $143.2 | $101.5 | $76.3 |

### Other Operating Revenues

Other operating revenues consist primarily of the following:

| (in millions) | Year Ended December 31 |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
| Late payment charges (1) | $55.6 | $54.9 | $29.4 |
| Alternative revenues (2) | (30.3) | 21.2 | 38.8 |
| Other | 4.0 | 4.2 | 4.2 |
| Total other operating revenues | $29.3 | $80.3 | $72.4 |

$^{(1)}$ The increase in late payment charges during 2021, compared with 2020, was a result of the expiration of various regulatory orders from our utility commissions in response to the COVID-19 pandemic, which included the suspension of late payment charges during a designated time period. See Note 26, 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 customers subject to decoupling mechanisms, wholesale true-ups, conservation improvement rider true-ups, and certain late payment charges.

## NOTE 5-CREDIT LOSSES

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

| (in millions) | Wisconsin | Illinois | Other States | Total Utility Operations | Non-Utility Energy Infrastructure | Corporate and Other | WEC Energy Group Consolidated |
| --- | --- | --- | --- | --- | --- | --- | --- |
| December 31, 2022 |  |  |  |  |  |  |  |
| Accounts receivable and unbilled revenues | $1,199.4 | $624.2 | $164.4 | $1,988.0 | $25.4 | $4.3 | $2,017.7 |
| Allowance for credit losses | 82.0 | 111.0 | 6.3 | 199.3 | - | - | 199.3 |
| Accounts receivable and unbilled revenues, net (1) | $1,117.4 | $513.2 | $158.1 | $1,788.7 | $25.4 | $4.3 | $1,818.4 |
| Total accounts receivable, net - past due greater than 90 days (1) | $51.9 | $52.9 | $1.9 | $106.7 | $ - | $ - | $106.7 |
| Past due greater than 90 days - collection risk mitigated by regulatory mechanisms (1) | 97.0% | 100.0% | - % | 96.8% | - % | - % | 96.8% |

| (in millions) | Wisconsin | Illinois | Other States | Total Utility Operations | Non-Utility Energy Infrastructure | Corporate and Other | WEC Energy Group Consolidated |
| --- | --- | --- | --- | --- | --- | --- | --- |
| December 31, 2021 |  |  |  |  |  |  |  |
| Accounts receivable and unbilled revenues | $1,053.1 | $523.1 | $105.7 | $1,681.9 | $17.0 | $5.1 | $1,704.0 |
| Allowance for credit losses | 84.0 | 105.5 | 8.8 | 198.3 | - | - | 198.3 |
| Accounts receivable and unbilled revenues, net (1) | $969.1 | $417.6 | $96.9 | $1,483.6 | $17.0 | $5.1 | $1,505.7 |
| Total accounts receivable, net - past due greater than 90 days (1) | $46.5 | $36.6 | $3.4 | $86.5 | $ - | $ - | $86.5 |
| Past due greater than 90 days - collection risk mitigated by regulatory mechanisms (1) | 97.6% | 100.0% | - % | 94.8% | - % | - % | 94.8% |

WEC Energy Group

F-58

2022 Annual Financial Statements

(1) Our exposure to credit losses for certain regulated utility customers is mitigated by regulatory mechanisms we have in place. Specifically, rates related to all of the customers in our Illinois segment, as well as the residential rates of WE, WPS, and WG in our Wisconsin segment, include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between the actual provision for credit losses and the amounts recovered in rates. As a result, at December 31, 2022, $1,079.1 million, or 59.3%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses.

A rollforward of the allowance for credit losses by reportable segment for the years ended December 31, 2022, 2021, and 2020, is included below:

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

On a consolidated basis, there was a $1.0 million increase in the allowance for credit losses during the year ended December 31, 2022. We believe that the high energy costs that customers are seeing, which have been driven by high natural gas prices, contributed to higher past due accounts receivable balances and a related increase in the allowance for credit losses. The increase was substantially offset by customer write-offs related to collection practices returning to pre-pandemic levels, including the restoration of our ability to disconnect customers. After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance.

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

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

| (in millions) | Wisconsin | Illinois | Other States | Total Utility Operations | Corporate and Other | WEC Energy Group Consolidated |
| --- | --- | --- | --- | --- | --- | --- |
| Balance at January 1, 2020 | $59.9 | $75.9 | $4.1 | $139.9 | $0.1 | $140.0 |
| Provision for credit losses | 47.5 | 51.1 | 4.3 | 102.9 | - | 102.9 |
| Provision for credit losses deferred for future recovery or refund | 24.6 | 30.6 | - | 55.2 | - | 55.2 |
| Write-offs charged against the allowance | (65.9) | (63.0) | (3.4) | (132.3) | - | (132.3) |
| Recoveries of amounts previously written off | 36.0 | 17.0 | 1.4 | 54.4 | - | 54.4 |
| Sale of PDL residential solar facilities | - | - | - | - | (0.1) | (0.1) |
| Balance at December 31, 2020 | $102.1 | $111.6 | $6.4 | $220.1 | $ - | $220.1 |

The allowance for credit losses increased during the year ended December 31, 2020, driven by higher past due accounts receivable balances at our utility segments, primarily related to residential customers. This increase in accounts receivable balances in arrears was driven by 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 Wisconsin and Illinois customers during the year ended December 31, 2020.

WEC Energy Group

F-59

2022 Annual Financial Statements

## NOTE 6-REGULATORY ASSETS AND LIABILITIES

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

| (in millions) | 2022 | 2021 | See Note |
| --- | --- | --- | --- |
| Regulatory assets (1)(2) |  |  |  |
| Pension and OPEB costs (3) | $714.3 | $802.3 | 20 |
| Plant retirement related items | 688.6 | 722.3 |  |
| Environmental remediation costs (4) | 610.7 | 630.9 | 24 |
| Income tax related items | 461.9 | 458.8 | 16 |
| AROs | 169.7 | 194.2 | 1(l), 9 |
| Derivatives | 133.8 | 33.1 | 1(s) |
| SSR (5) | 123.5 | 129.5 |  |
| Securitization | 92.4 | 100.7 | 23 |
| Uncollectible expense | 69.3 | 42.6 | 5 |
| MERC extraordinary natural gas costs (6) | 35.1 | 59.7 | 26 |
| Energy efficiency programs (7) | 33.9 | 22.0 |  |
| Energy costs recoverable through rate adjustments | 26.9 | 85.4 | 1(d), 26 |
| Other, net | 146.8 | 85.6 |  |
| Total regulatory assets | $3,306.9 | $3,367.1 |  |
| Balance sheet presentation |  |  |  |
| Other current assets | $42.3 | $102.3 |  |
| Regulatory assets | 3,264.6 | 3,264.8 |  |
| Total regulatory assets | $3,306.9 | $3,367.1 |  |

$^{(1)}$ Based on prior and current rate treatment, we believe it is probable that our utilities will continue to recover from customers the regulatory assets in this table. In accordance with GAAP, our regulatory assets do not include the allowance for ROE that is capitalized for regulatory purposes. This allowance was $27.3 million and $30.9 million at December 31, 2022 and 2021, respectively.

$^{(2)}$ As of December 31, 2022, we had $237.9 million of regulatory assets not earning a return, $35.3 million of regulatory assets earning a return based on short-term interest rates, and $123.5 million of regulatory assets earning a return based on long-term interest rates. The regulatory assets not earning a return primarily relate to certain environmental remediation costs, uncollectible expense, MERC's extraordinary natural gas costs, our invested capital tax rider, and unamortized loss on reacquired debt. The other regulatory assets in the table either earn a return at the applicable utility's weighted average cost of capital or the cash has not yet been expended, in which case the regulatory assets are offset by liabilities.

$^{(3)}$ Primarily represents the unrecognized future pension and OPEB costs related to our defined benefit pension and OPEB plans. We are authorized recovery of these regulatory assets over the average remaining service life of each plan.

$^{(4)}$ As of December 31, 2022, we had made cash expenditures of $111.1 million related to these environmental remediation costs. The remaining $499.6 million represents our estimated future cash expenditures.

$^{(5)}$ This regulatory asset relates to WE's 2014 announcement to retire the PIPP. Despite WE's intent to retire the PIPP, MISO designated the PIPP as an SSR, which meant the PIPP's operation was necessary for reliability, and the plant could not be shut down until new generation or transmission facilities were built. In December 2014, the PSCW authorized escrow accounting for WE's SSR revenues because of the fluctuations in the actual revenues WE received under the PIPP SSR agreements. The rate order WE received from the PSCW in December 2019 authorized recovery of this SSR regulatory asset over a 15-year period that began on January 1, 2020.

$^{(6)}$ Represents the extraordinary natural gas costs MERC incurred during February 2021 that are being recovered over 27 months, beginning in September 2021. See Note 26, Regulatory Environment, for more information on our recovery efforts associated with these costs.

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

WEC Energy Group

F-60

2022 Annual Financial Statements

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

| (in millions) | 2022 | 2021 | See Note |
| --- | --- | --- | --- |
| Regulatory liabilities |  |  |  |
| Income tax related items | $1,956.6 | $1,998.5 | 16 |
| Removal costs (1) | 1,260.9 | 1,248.0 |  |
| Pension and OPEB benefits (2) | 340.5 | 397.3 | 20 |
| Derivatives | 76.7 | 124.1 | 1(s) |
| Energy costs refundable through rate adjustments | 53.4 | 13.7 | 1(d) |
| Uncollectible expense | 24.0 | 37.1 | 5 |
| Earnings sharing mechanisms | 12.9 | 28.4 | 26 |
| Electric transmission costs (3) | 0.4 | 84.2 |  |
| Other, net | 66.5 | 29.0 |  |
| Total regulatory liabilities | $3,791.9 | $3,960.3 |  |
| Balance sheet presentation |  |  |  |
| Other current liabilities | $56.4 | $14.3 |  |
| Regulatory liabilities | 3,735.5 | 3,946.0 |  |
| Total regulatory liabilities | $3,791.9 | $3,960.3 |  |

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

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

$^{(3)}$ In accordance with the PSCW's approval of escrow accounting for ATC and MISO network transmission expenses for our Wisconsin electric utilities, WE and WPS defer as a regulatory asset or liability the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During 2022, WE and WPS amortized $81.0 million of their transmission regulatory liabilities to offset certain 2022 revenue deficiencies, as approved by the PSCW in order to forego filing for 2022 base rate increases. See Note 26, Regulatory Environment, for more information.

## Pleasant Prairie Power Plant

The Pleasant Prairie power plant was retired on April 10, 2018. The net book value of this plant was $575.1 million at December 31, 2022, representing book value less cost of removal and accumulated depreciation. In addition, previously deferred unprotected tax benefits from the Tax Legislation related to the unrecovered balance of this plant were $17.5 million as of December 31, 2022. The net amount of $557.6 million was classified as a regulatory asset on our balance sheet at December 31, 2022 due to the retirement of the plant. This regulatory asset does not include certain other previously recorded deferred tax liabilities of $156.7 million related to the retired Pleasant Prairie power plant. Pursuant to its rate order issued by the PSCW in December 2019, WE will continue to amortize this regulatory asset on a straight-line basis through 2039, using the composite depreciation rates approved by the PSCW before this plant was retired. The amortization is included in depreciation and amortization in the income statement. WE also has FERC approval to continue to collect the net book value of the Pleasant Prairie power plant using the approved composite depreciation rates, in addition to a return on the remaining net book value.

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

## Presque Isle Power Plant

Pursuant to MISO's April 2018 approval of the retirement of the PIPP, these units were retired on March 31, 2019. The net book value of the PIPP was $163.7 million at December 31, 2022, representing book value less cost of removal and accumulated depreciation. In addition, previously deferred unprotected tax benefits from the Tax Legislation related to the unrecovered balance of these units were $5.2 million as of December 31, 2022. The net amount of $158.5 million was classified as a regulatory asset on our balance sheet at December 31, 2022 as a result of the retirement of the plant. This regulatory asset does not include certain other previously recorded deferred tax liabilities of $44.4 million related to the retired PIPP. After the retirement of the PIPP, a portion of the regulatory asset and related cost of removal reserve was transferred to UMERC for recovery from its retail customers. Effective with its rate order issued by the PSCW in December 2019, WE received approval to collect a return of and on its share of the net book value of the PIPP and, as a result, will continue to amortize the regulatory assets on a straight-line basis through 2037, using the composite depreciation rates approved by the PSCW before the units were retired. UMERC will also continue to amortize the regulatory assets on a straight-line basis using the composite depreciation rates approved by the PSCW before the units were retired. This amortization is included in depreciation and amortization in the income statement. UMERC will address the accounting and regulatory treatment related to the retirement of the PIPP with the MPSC in conjunction with a future rate case. WE also has FERC approval to continue to collect the net book value of the PIPP using the approved composite depreciation rates, in addition to a return on the net book value.

WEC Energy Group

F-61

2022 Annual Financial Statements

## Pulliam Power Plant

In connection with a MISO ruling, WPS retired Pulliam Units 7 and 8 on October 21, 2018. The net book value of the Pulliam units was $36.6 million at December 31, 2022, 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, 2022 as a result of the retirement of the plant. Effective with its rate order issued by the PSCW in December 2019, WPS received approval to collect a return of and on the entire net book value of the Pulliam units and, as a result, will continue to amortize this regulatory asset on a straight-line basis through 2031, using the composite depreciation rates approved by the PSCW before these generating units were retired. The amortization is included in depreciation and amortization in the income statement. WPS also has FERC approval to continue to collect the net book value of the Pulliam power plant using the approved composite depreciation rates, in addition to a return on the remaining net book value.

## Edgewater Unit 4

The Edgewater 4 generating unit was retired on September 28, 2018. The net book value of the generating unit was $3.2 million at December 31, 2022, 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, 2022 as a result of the retirement of the plant. Effective with its rate order issued by the PSCW in December 2019, WPS received approval to collect a return of and on the entire net book value of the Edgewater 4 generating unit and, as a result, will continue to amortize this regulatory asset on a straight-line basis through 2026, using the composite depreciation rates approved by the PSCW before this generating unit was retired. The amortization is included in depreciation and amortization in the income statement. WPS also has FERC approval to continue to collect the net book value of the Edgewater 4 generating unit using the approved composite depreciation rates, in addition to a return on the remaining net book value.

## NOTE 7-PROPERTY, PLANT, AND EQUIPMENT

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

| (in millions) | 2022 | 2021 |
| --- | --- | --- |
| Electric - generation | $5,480.5 | $6,981.4 |
| Electric - distribution | 8,233.3 | 7,854.7 |
| Natural gas - distribution, storage, and transmission | 14,203.3 | 13,526.6 |
| Property, plant, and equipment to be retired, net | 1,085.6 | 277.0 |
| Other | 2,302.7 | 2,212.6 |
| Less: Accumulated depreciation | 8,416.2 | 8,894.9 |
| Net | 22,889.2 | 21,957.4 |
| CWIP | 972.1 | 406.0 |
| Net utility and non-utility property, plant, and equipment | 23,861.3 | 22,363.4 |
| We Power generation | 3,237.1 | 3,240.5 |
| Renewable generation | 2,537.1 | 1,837.5 |
| Natural gas storage | 292.2 | 289.9 |
| Net non-utility energy infrastructure | 6,066.4 | 5,367.9 |
| Corporate services | 163.0 | 188.7 |
| Other | 23.8 | 27.0 |
| Less: Accumulated depreciation | 1,082.3 | 994.4 |
| Net | 5,170.9 | 4,589.2 |
| CWIP | 81.6 | 29.8 |
| Net other property, plant, and equipment | 5,252.5 | 4,619.0 |
| Total property, plant, and equipment | $29,113.8 | $26,982.4 |

## 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) | 2022 | 2021 | 2020 |
| --- | --- | --- | --- |
| Severance liability at January 1 | $4.9 | $0.7 | $2.1 |
| Severance expense | 11.3 | 4.6 | - |
| Severance payments | - | (0.4) | (0.1) |
| Other | - | - | (1.3) |
| Total severance liability at December 31 | $16.2 | $4.9 | $0.7 |

WEC Energy Group

F-62

2022 Annual Financial Statements

## Wisconsin Segment Plant to be Retired

### Oak Creek Power Plant Units 5 - 8

As a result of a PSCW approval for the construction of a solar and battery project received in December 2022, retirement of the OCPP generating units 5 - 8 became probable. OCPP units 5 and 6 are expected to be retired by May 2024, while units 7 and 8 are expected to be retired by late 2025. The total net book value of WE's ownership share of units 5 - 8 was $812.5 million at December 31, 2022, which does not include deferred taxes. 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 continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

### Columbia Units 1 and 2

As a result of a MISO ruling received in June 2021, retirement of the jointly-owned Columbia generating units 1 and 2 became probable. Columbia generating units 1 and 2 are expected to be retired by June 2026. The net book value of WPS's ownership share of unit 1 and unit 2 was $84.0 million and $189.1 million, respectively, at December 31, 2022, which does not include deferred taxes. 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 WPS continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

### Public Service Building and Steam Tunnel Assets

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

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

## NOTE 8-JOINTLY OWNED UTILITY FACILITIES

We Power and WPS hold joint ownership interests in certain electric generating facilities. They are entitled to their share of generating capability and output of each facility equal to their respective ownership interest. They pay their ownership share of additional construction costs and have supplied their own financing for all jointly owned projects. We record We Power's and WPS's proportionate share of significant jointly owned electric generating facilities as property, plant, and equipment on the balance sheets.

We Power leases its ownership interest in ER 1 and ER 2 to WE, and WE operates these units. WE and WPS record their respective share of fuel inventory purchases and operating expenses, unless specific agreements have been executed to limit their maximum exposure to additional costs. WE's and WPS's proportionate share of direct expenses for the joint operation of these plants is recorded within operating expenses in the income statements.

Information related to jointly owned utility facilities at December 31, 2022 was as follows:

| (in millions, except for percentages and MW) | We Power |  | WPS |  |  |  |
| --- | --- | --- | --- | --- | --- | --- |
|  | Elm Road Generating Station Units 1 and 2 | Weston Unit 4 | Columbia Energy Center Units 1 and 2 | Forward Wind | Two Creeks | Badger Hollow I (2) |
| Ownership | 83.34% | 70.0% | 27.5% | 44.6% | 66.7% | 66.7% |
| Share of capacity (MW) (1) | 1,060.8 | 387.3 | 311.1 | 61.5 | 100.0 | 100.0 |
| In-service date | 2010 and 2011 | 2008 | 1975 and 1978 | 2008 | 2020 | 2021 |
| Property, plant, and equipment | $2,425.1 | $612.1 | $426.1 | $119.3 | $136.8 | $146.2 |
| Accumulated depreciation | $(505.7) | $(213.0) | $(159.7) | $(53.9) | $(9.7) | $(4.9) |
| CWIP | $64.1 | $1.2 | $6.8 | $0.2 | $0.1 | $ - |

$^{(1)}$ Capacity for our jointly-owned electric generation facilities, other than Forward Wind, Two Creeks, and Badger Hollow I, 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 2023 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 2021 for Badger Hollow I.

WEC Energy Group

F-63

2022 Annual Financial Statements

WE, along with an unaffiliated utility, received PSCW approval to construct Badger Hollow II, a solar project that will be located in Iowa County, Wisconsin. Once constructed, WE will own 66.7%, or 100 MW, of Badger Hollow II. Commercial operation is targeted for 2023. The CWIP balance for Badger Hollow II was $107.5 million as of December 31, 2022.

WE and WPS, along with an unaffiliated utility, received PSCW approval to construct Paris, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Kenosha County, Wisconsin and once fully constructed, WE and WPS will collectively own 90%, or 180 MW of solar generation and 99 MW of battery storage, of this project. Commercial operation of the solar facility is targeted for 2023. The CWIP balance for Paris was $207.6 million as of December 31, 2022.

WE and WPS, along with an unaffiliated utility, received PSCW approval to construct Darien, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Rock and Walworth counties, Wisconsin and once constructed, WE and WPS will collectively own 90%, or 225 MW of solar generation and 68 MW of battery storage of this project. Commercial operation of the solar facility is targeted for 2024. The CWIP balance for Darien was $9.4 million as of December 31, 2022.

## NOTE 9-ASSET RETIREMENT OBLIGATIONS

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

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

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) | 2022 | 2021 | 2020 |
| --- | --- | --- | --- |
| Balance as of January 1 | $462.0 | $513.5 | $483.5 |
| Accretion | 16.1 | 21.2 | 20.7 |
| Additions and revisions to estimated cash flows | 15.0 (1) | (53.9) (2) | 39.7 (3) |
| Liabilities settled | (13.8) | (18.8) | (30.4) |
| Balance as of December 31 | $479.3 | $462.0 | $513.5 |

$^{(1)}$ AROs increased $12.1 million in 2022, as a result of an ARO being recorded for the legal requirement to dismantle, at retirement, the Thunderhead non-utility wind generation project. Also in 2022, AROs increased $1.9 million due to revisions made to estimated cash flows primarily for changes in the cost to retire natural gas distribution mains and service pipes at PGL and NSG.

$^{(2)}$ AROs decreased $152.0 million in 2021, due to revisions made to estimated cash flows primarily for changes in the cost to retire natural gas distribution lines at PGL and NSG. Also in 2021, AROs increased $50.7 million due to new natural gas distribution lines being placed into service at PGL and NSG. AROs increased by $26.3 million as a result of AROs being recorded for the legal requirement to dismantle, at retirement, the Badger Hollow I solar generation project and the Tatanka Ridge and Jayhawk non-utility wind generation projects. AROs increased $7.8 million due to revisions made to removal estimates for wind generation projects at WE and WPS. AROs increased $6.8 million due to revisions made to the removal estimates for fly ash landfills and ash ponds at WPS.

$^{(3)}$ AROs increased $39.3 million in 2020, primarily due to new natural gas distribution lines being placed into service at PGL. Also in 2020, AROs increased by $8.5 million as a result of AROs being recorded for the legal requirement to dismantle, at retirement, the Two Creeks solar generation project. AROs decreased $9.2 million due to revisions made to estimated cash flows for the abatement of asbestos at WE.

## NOTE 10-GOODWILL AND INTANGIBLES

### Goodwill

Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. The table below shows our goodwill balances by segment at December 31, 2022. We had no changes to the carrying amount of goodwill during the years ended December 31, 2022 and 2021.

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

$^{(1)}$ We had no accumulated impairment losses related to our goodwill as of December 31, 2022.

During the third quarter of 2022, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of July 1, 2022. No impairments resulted from these tests.

WEC Energy Group

F-64

2022 Annual Financial Statements

## Intangible Assets

At December 31, 2022 and 2021, we had $24.9 million and $5.7 million, respectively, of indefinite-lived intangible assets. During 2022, we purchased additional spectrum frequencies for $19.2 million. The spectrum frequencies enable the utilities to transmit data and voice communications over a wavelength dedicated to us throughout our service territories. We also have $5.7 million of other indefinite-lived intangible assets, primarily related to a MGU trade name from a previous acquisition. These indefinite-lived intangible assets are included in other long-term assets on our balance sheets.

## Intangible Liabilities

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

| (in millions) | December 31, 2022 |  |  | December 31, 2021 |  |  |
| --- | --- | --- | --- | --- | --- | --- |
|  | Gross Carrying Amount | Accumulated Amortization | Net Carrying Amount | Gross Carrying Amount | Accumulated Amortization | Net Carrying Amount |
| PPAs (1) | $343.9 | $(16.9) | $327.0 | $87.9 | $(6.5) | $81.4 |
| Proxy revenue swap (2) | 7.2 | (2.8) | 4.4 | 7.2 | (2.1) | 5.1 |
| Interconnection agreements (3) | 4.7 | (0.7) | 4.0 | 4.7 | (0.5) | 4.2 |
| Total intangible liabilities | $355.8 | $(20.4) | $335.4 | $99.8 | $(9.1) | $90.7 |

$^{(1)}$ Represents PPAs related to the acquisition of Blooming Grove, Tatanka Ridge, Jayhawk, and Thunderhead expiring between 2030 and 2034. The weighted-average remaining useful life of the PPAs is 11 years.

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

$^{(3)}$ Represents interconnection agreements related to the acquisitions of Tatanka Ridge and Bishop Hill III, expiring in 2040 and 2041, respectively. These agreements relate to payments for connecting our facilities to the infrastructure of another utility to facilitate the movement of power onto the electric grid. The weighted-average remaining useful life of the interconnection agreements is 18 years.

Amortization related to these intangible liabilities for the years ended December 31, 2022, 2021, and 2020 was $11.3 million, $7.5 million, and $0.8 million, respectively. Amortization for the next five years is estimated to be:

| (in millions) | For the Years Ending December 31 |  |  |  |  |
| --- | --- | --- | --- | --- | --- |
|  | 2023 | 2024 | 2025 | 2026 | 2027 |
| Amortization to be recorded as an increase to operating revenues | $29.8 | $29.8 | $29.8 | $29.8 | $29.8 |
| Amortization to be recorded as a decrease to other operation and maintenance | 0.2 | 0.2 | 0.2 | 0.2 | 0.2 |

## NOTE 11-COMMON EQUITY

### Stock-Based Compensation

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

| (in millions) | 2022 | 2021 | 2020 |
| --- | --- | --- | --- |
| Stock options | $6.5 | $6.5 | $6.0 |
| Restricted stock | 7.0 | 6.1 | 7.4 |
| Performance units | 21.3 | 3.1 | 22.3 |
| Stock-based compensation expense | $34.8 | $15.7 | $35.7 |
| Related tax benefit | $9.6 | $4.3 | $9.8 |

Stock-based compensation costs capitalized during 2022, 2021, and 2020 were not significant.

WEC Energy Group

F-65

2022 Annual Financial Statements

## Stock Options

The following is a summary of our stock option activity during 2022:

| 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, 2022 | 3,111,907 | $69.84 |  |  |
| Granted | 437,269 | $96.04 |  |  |
| Exercised | (622,459) | $54.05 |  |  |
| Forfeited | (16,778) | $92.16 |  |  |
| Outstanding as of December 31, 2022 | 2,909,939 | $77.03 | 6.2 | $49.7 |
| Exercisable as of December 31, 2022 | 1,807,644 | $67.40 | 5.0 | $47.8 |

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, 2022. This is calculated as the difference between our closing stock price on December 31, 2022, 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, 2022, 2021, and 2020 was $29.2 million, $12.9 million, and $47.1 million, respectively. The actual tax benefit from option exercises for the same periods was approximately $8.0 million, $3.5 million, and $12.9 million, respectively.

As of December 31, 2022, approximately $2.3 million of unrecognized compensation cost related to unvested and outstanding stock options was expected to be recognized over the next 1.5 years on a weighted-average basis.

During the first quarter of 2023, the Compensation Committee awarded 257,780 non-qualified stock options with a weighted-average exercise price of $93.69 and a weighted-average grant date fair value of $19.58 per option to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

## Restricted Shares

The following restricted stock activity occurred during 2022:

| Restricted Shares | Number of Shares | Weighted-Average Grant Date Fair Value |
| --- | --- | --- |
| Outstanding and unvested as of January 1, 2022 | 99,061 | $88.89 |
| Granted | 72,211 | $96.04 |
| Released | (76,109) | $88.51 |
| Forfeited | (5,278) | $92.80 |
| Outstanding and unvested as of December 31, 2022 | 89,885 | $94.73 |

The intrinsic value of restricted stock released was $7.5 million, $6.5 million, and $11.1 million for the years ended December 31, 2022, 2021, and 2020, respectively. The actual tax benefit from released restricted shares for the same years was $2.1 million, $1.8 million, and $3.1 million, respectively.

As of December 31, 2022, approximately $2.8 million of unrecognized compensation cost related to unvested and outstanding restricted stock was expected to be recognized over the next 1.7 years on a weighted-average basis.

During the first quarter of 2023, the Compensation Committee awarded 75,453 restricted shares to certain of our directors, officers, and other key employees under its normal schedule of awarding long-term incentive compensation. The grant date fair value of these awards was $93.69 per share.

## Performance Units

During 2022, 2021, and 2020, the Compensation Committee awarded 171,492; 152,382; and 153,465 performance units, respectively, to officers and other key employees under the WEC Energy Group Performance Unit Plan.

Performance units with an intrinsic value of $20.2 million, $27.7 million, and $34.5 million were settled during 2022, 2021, and 2020, respectively. The actual tax benefit from the distribution of performance units for the same years was $5.1 million, $6.8 million, and $8.4 million, respectively.

At December 31, 2022, we had 375,834 performance units outstanding, including dividend equivalents. A liability of $22.4 million was recorded on our balance sheet at December 31, 2022 related to these outstanding units. As of December 31, 2022, approximately $13.5 million of unrecognized compensation cost related to unvested and outstanding performance units was expected to be recognized over the next 1.7 years on a weighted-average basis.

WEC Energy Group

F-66

2022 Annual Financial Statements

During the first quarter of 2023, we settled performance units with an intrinsic value of $9.7 million. The actual tax benefit from the distribution of these awards was $2.4 million. In January 2023, the Compensation Committee also awarded 157,035 performance units to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

## Restrictions

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

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

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

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

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

WECI Wind Holding I's and WECI Wind Holding II's long-term debt obligations contain various conditions that must be met prior to them making any cash distributions. Included in these provisions is a requirement to maintain a debt service coverage ratio of 1.2 or greater for the 12-month period prior to the distribution.

WEC Energy Group and Integrys have the option to defer interest payments on their junior subordinated notes, from time to time, for one or more periods of up to 10 consecutive years per period. During any period in which they defer interest payments, they may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, their respective common stock.

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

As of December 31, 2022, restricted net assets of our consolidated subsidiaries totaled approximately $9.8 billion. Our equity in undistributed earnings of investees accounted for by the equity method was approximately $487 million.

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

## Share Purchases

We have instructed our independent agents to purchase shares on the open market to fulfill obligations under various stock-based employee benefit and compensations plans and to provide shares to participants in our dividend reinvestment and stock purchase plan. As a result, no new shares of common stock were issued in 2022, 2021, or 2020.

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

| (in millions) | 2022 | 2021 | 2020 |
| --- | --- | --- | --- |
| Shares purchased | 0.7 | 0.4 | 1.0 |
| Cost of shares purchased | $69.2 | $33.1 | $99.2 |

## Common Stock Dividends

During the year ended December 31, 2022, our Board of Directors declared common stock dividends which are summarized below:

| Date Declared | Date Payable | Per Share | Period |
| --- | --- | --- | --- |
| January 20, 2022 | March 1, 2022 | $0.7275 | First quarter |
| April 21, 2022 | June 1, 2022 | $0.7275 | Second quarter |
| July 21, 2022 | September 1, 2022 | $0.7275 | Third quarter |
| October 20, 2022 | December 1, 2022 | $0.7275 | Fourth quarter |

WEC Energy Group

F-67

2022 Annual Financial Statements

On January 19, 2023, our Board of Directors declared a quarterly cash dividend of $0.78 per share, which equates to an annual dividend of $3.12 per share. The dividend is payable on March 1, 2023, to shareholders of record on February 14, 2023. In addition, the Board of Directors affirmed our dividend policy that continues to target a dividend payout ratio of 65-70% of earnings.

## NOTE 12-PREFERRED STOCK

The following table shows preferred stock authorized and outstanding at December 31, 2022 and 2021:

| (in millions, except share and per share amounts) | Shares Authorized | Shares Outstanding | Redemption Price Per Share | Total |
| --- | --- | --- | --- | --- |
| WEC Energy Group |  |  |  |  |
| $0.01 par value Preferred Stock | 15,000,000 | - | - | $ - |
| WE |  |  |  |  |
| $100 par value, Six Per Cent. Preferred Stock | 45,000 | 44,498 | - | 4.4 |
| $100 par value, Serial Preferred Stock 3.60% Series | 2,286,500 | 260,000 | $101 | 26.0 |
| $25 par value, Serial Preferred Stock | 5,000,000 | - | - | - |
| WPS |  |  |  |  |
| $100 par value, Preferred Stock | 1,000,000 | - | - | - |
| PGL |  |  |  |  |
| $100 par value, Cumulative Preferred Stock | 430,000 | - | - | - |
| NSG |  |  |  |  |
| $100 par value, Cumulative Preferred Stock | 160,000 | - | - | - |
| Total |  |  |  | $30.4 |

## 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) | 2022 | 2021 |
| --- | --- | --- |
| Commercial paper |  |  |
| Amount outstanding at December 31 | $1,643.5 | $1,896.1 |
| Average interest rate on amounts outstanding at December 31 | 4.64% | 0.26% |
| Operating expense loans |  |  |
| Amount outstanding at December 31 (1) | $3.6 | $0.9 |

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

Our average amount of commercial paper borrowings based on daily outstanding balances during 2022, was $1,487.2 million with a weighted-average interest rate during the period of 1.98%.

In order to enhance our liquidity position in response to the COVID-19 pandemic, in March 2020, WEC Energy Group entered into a $340.0 million 364-day term loan. In March 2021, we repaid the term loan using the net proceeds from the issuance of our $600.0 million aggregate principal amount of 0.80% Senior Notes due March 15, 2024.

WEC Energy Group, WE, WPS, WG, and PGL have entered into bank back-up credit facilities to maintain short-term credit liquidity which, among other terms, require them to maintain, subject to certain exclusions, a total funded debt to capitalization ratio of 70.0%, 65.0%, 65.0%, 65.0%, and 65.0% or less, respectively. As of December 31, 2022, all companies were in compliance with their respective ratio.

WEC Energy Group

F-68

2022 Annual Financial Statements

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

| (in millions) | Maturity | 2022 |
| --- | --- | --- |
| Revolving credit facility (WEC Energy Group) | September 2026 | $1,500.0 |
| Revolving credit facility (WE) | September 2026 | 500.0 |
| Revolving credit facility (WPS) | September 2026 | 400.0 |
| Revolving credit facility (WG) | September 2026 | 350.0 |
| Revolving credit facility (PGL) | September 2026 | 350.0 |
| Total short-term credit capacity |  | $3,100.0 |
| Less: |  |  |
| Letters of credit issued inside credit facilities |  | $2.3 |
| Commercial paper outstanding |  | 1,643.5 |
| Available capacity under existing facilities |  | $1,454.2 |

Each of the revolving credit facilities has a renewal provision for two extensions, subject to lender approval. Each extension is for a period of one year.

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

WEC Energy Group

F-69

2022 Annual Financial Statements

## 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) | 2022 |  |  | 2021 |  |
| --- | --- | --- | --- | --- | --- |
|  | Maturity Date | Weighted Average Interest Rate | Balance | Weighted Average Interest Rate | Balance |
| WEC Energy Group Senior Notes (unsecured) (1) | 2023-2033 | 2.44% | $3,970.0 | 1.67% | $3,070.0 |
| WEC Energy Group Junior Notes (unsecured) (1) (2) | 2067 | 6.72% | 500.0 | 2.27% | 500.0 |
| WE Debentures (unsecured) | 2024-2095 | 4.22% | 3,285.0 | 4.13% | 2,785.0 |
| WEPCo Environmental Trust (secured, nonrecourse) (6) (10) | 2023-2035 | 1.58% | 105.9 | 1.58% | 114.7 |
| WPS Senior Notes (unsecured) | 2025-2051 | 4.11% | 1,975.0 | 3.89% | 1,675.0 |
| WG Debentures (unsecured) | 2024-2046 | 3.35% | 790.0 | 3.35% | 790.0 |
| Integrys Junior Notes (unsecured) (3) | 2073 | 6.00% | 221.4 | 6.00% | 221.4 |
| PGL First and Refunding Mortgage Bonds (secured) (4) | 2024-2047 | 3.41% | 1,970.0 | 3.31% | 1,870.0 |
| NSG First Mortgage Bonds (secured) (5) | 2027-2043 | 3.56% | 157.0 | 3.56% | 157.0 |
| MERC Senior Notes (unsecured) | 2025-2047 | 3.04% | 210.0 | 3.04% | 210.0 |
| MGU Senior Notes (unsecured) | 2025-2047 | 3.18% | 150.0 | 3.18% | 150.0 |
| UMERC Senior Notes (unsecured) | 2029 | 3.26% | 160.0 | 3.26% | 160.0 |
| Bluewater Gas Storage Senior Notes (unsecured) (6) | 2023-2047 | 3.76% | 112.6 | 3.76% | 115.2 |
| ATC Holding Senior Notes (unsecured) | 2025-2030 | 4.05% | 475.0 | 4.05% | 475.0 |
| We Power Subsidiaries Notes (secured, nonrecourse) (6) (7) | 2023-2041 | 5.62% | 896.5 | 5.60% | 934.7 |
| WECC Notes (unsecured) | 2028 | 6.94% | 50.0 | 6.94% | 50.0 |
| WECI Wind Holding I Senior Notes (secured, nonrecourse) (6) (8) | 2023-2032 | 2.75% | 332.1 | 2.75% | 374.6 |
| WECI Wind Holding II Senior Notes (secured, nonrecourse) (6) (9) | 2023 - 2031 | 6.38% | 199.3 | - % | - |
| Total |  |  | 15,559.8 |  | 13,652.6 |
| Integrys acquisition fair value adjustment |  |  | 1.2 |  | 2.9 |
| Jayhawk acquisition |  |  | 7.3 |  | 7.3 |
| Unamortized debt issuance costs |  |  | (81.8) |  | (77.7) |
| Unamortized discount, net and other |  |  | (22.3) |  | (21.7) |
| Total long-term debt, including current portion (11) |  |  | 15,464.2 |  | 13,563.4 |
| Current portion of long-term debt |  |  | (808.5) |  | (91.0) |
| Total long-term debt |  |  | $14,655.7 |  | $13,472.4 |

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

(2) Variable interest rate reset quarterly. The rates were 6.72% and 2.27% as of December 31, 2022 and 2021, respectively. Until their expiration on November 15, 2021, we had two interest rate swaps with a combined notional value of $250.0 million. The swaps provided a fixed interest rate of 4.9765% on $250.0 million of the outstanding notes. See Note 18, Derivative Instruments, for more information on the two interest rate swaps.

(3) The terms of Integrys's 2013 6.00% Junior Notes, due August 1, 2073, provide that, effective August 2023, they will bear interest at a variable rate, which we expect to based off of SOFR, and will reset quarterly.

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

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

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

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

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

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

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

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

(11) The amount of long-term debt on our balance sheets includes finance lease obligations of $183.2 million and $129.7 million at December 31, 2022 and 2021, respectively.

WEC Energy Group

F-70

2022 Annual Financial Statements

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

### WEC Energy Group, Inc.

In September 2022, we issued $500.0 million of 5.00% Senior Notes due September 27, 2025, and $400.0 million of 5.15% Senior Notes due October 1, 2027, and used the net proceeds to repay short-term debt and for other corporate purposes.

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

### Wisconsin Electric Power Company

In September 2022, WE issued $500.0 million of 4.75% Debentures due September 30, 2032, and intends 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.

### Wisconsin Public Service Corporation

In November 2022, WPS issued $300.0 million of 5.35% Senior Notes due November 10, 2025, and used the net proceeds to repay short-term debt and for other corporate purposes.

### The Peoples Gas Light and Coke Company

In December 2022, PGL issued $100.0 million of 5.23% Bonds, Series MMM due December 1, 2027, and used the net proceeds for general corporate purposes, including capital expenditures and the refinancing of short-term debt.

### WEC Infrastructure Wind Holding II LLC

In December 2022, WECI Wind Holding II issued $199.3 million of 6.38% Senior Notes due December 31, 2031, and used the net proceeds to return a portion of WECI's previously invested capital in the subsidiaries of WECI Wind Holding II.

### Maturities of Long-Term Debt Outstanding

The following table shows the long-term debt securities (excluding finance leases) maturing within one year of December 31, 2022:

| (in millions) | Interest Rate | Maturity Date (1) | Principal Amount |
| --- | --- | --- | --- |
| WEC Energy Group Senior Notes (unsecured) | 0.55% | September | $700.0 |
| WEPCo Environmental Trust (secured, nonrecourse) | 1.58% | Semi-annually | 8.9 |
| Bluewater Gas Storage Senior Notes (unsecured) | 3.76% | Semi-annually | 2.8 |
| We Power Subsidiaries Notes - PWGS (secured, nonrecourse) | 4.91% | Monthly | 7.6 |
| We Power Subsidiaries Notes - ERGS (secured, nonrecourse) | 5.209% | Semi-annually | 14.7 |
| We Power Subsidiaries Notes - ERGS (secured, nonrecourse) | 4.673% | Semi-annually | 11.1 |
| We Power Subsidiaries Notes - PWGS (secured, nonrecourse) | 6.00% | Monthly | 6.6 |
| WECI Wind Holding I Senior Notes (secured, nonrecourse) | 2.75% | Semi-annually | 42.0 |
| WECI Wind Holding II Senior Notes (secured, nonrecourse) | 6.38% | Semi-annually | 14.8 |
| Total |  |  | $808.5 |

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

The following table shows the future maturities of our long-term debt outstanding (excluding obligations under finance leases) as of December 31, 2022:

| (in millions) | Payments |
| --- | --- |
| 2023 | $808.5 |
| 2024 | 1,239.6 |
| 2025 | 1,685.5 |
| 2026 | 126.8 |
| 2027 | 1,230.7 |
| Thereafter | 10,468.7 |
| Total | $15,559.8 |

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

WEC Energy Group

F-71

2022 Annual Financial Statements

## NOTE 15-LEASES

### Obligations Under Operating Leases

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

- Leases of office space, primarily related to several floors we are leasing in the Aon Center office building in Chicago, Illinois, though April 2029.
- Land we are leasing related to our Rothschild biomass plant through June 2051.
- Land we are leasing related to our Solar Now projects.

The operating leases generally require us to pay property taxes, insurance premiums, and operating and maintenance costs associated with the leased property. Certain of our leases contain options for early termination or to renew past the initial term, as set forth in the lease agreements. These options are not included in our calculation of the lease obligations, as it is not reasonably certain that they will be exercised.

### Obligations Under Finance Leases

In accordance with ASC Subtopic 980-842, Regulated Operations - Leases, the expense recognition pattern of our finance leases at our regulated entities resembles that of an operating lease. The difference between the minimum lease payments and the sum of imputed interest and unadjusted amortization costs calculated under Topic 842 is deferred as a regulatory asset on our balance sheets in accordance with Subtopic 980-842.

### Power Purchase Commitment

In 1997, WE entered into a 25-year PPA with LSP-Whitewater Limited Partnership. The contract, for 236.5 MW of firm capacity from a natural gas-fired cogeneration facility, included zero minimum energy requirements. The PPA expired on May 31, 2022; however, in November 2021, WE entered into a tolling agreement with LSP-Whitewater Limited Partnership that commenced on June 1, 2022. Concurrent with the execution of the tolling agreement, WE and WPS entered into an asset purchase agreement to acquire the natural gas-fired cogeneration facility for $72.7 million, which excludes working capital and transaction costs. This asset purchase agreement was approved by the PSCW in December 2022, and the acquisition closed effective January 1, 2023.

### Land Leases - Utility Solar Generation

WE and WPS, along with an unaffiliated utility, have entered into various land leases related to their investment in utility-scale solar generation. Each lease has an initial term and one or more optional extensions. We expect the optional extensions to be exercised, and, as a result, all of the land leases are being amortized over an extended term of approximately 50 years. Once a solar project achieves commercial operation, the lease liability is remeasured to reflect the final total acres being leased. Our payments related to these leases are being recovered through rates.

WEC Energy Group

F-72

2022 Annual Financial Statements

## Amounts Recognized in the Financial Statements and Other Information

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

| (in millions) | 2022 | 2021 | 2020 |
| --- | --- | --- | --- |
| Finance lease expense |  |  |  |
| Amortization of right of use assets (1) | $6.0 | $8.1 | $6.3 |
| Interest on lease liabilities (2) | 0.9 | 1.6 | 2.5 |
| Operating lease expense (3) | 6.1 | 3.4 | 5.4 |
| Short-term lease expense (3) | 0.9 | 0.2 | 0.3 |
| Total lease expense | $13.9 | $13.3 | $14.5 |
| Other information |  |  |  |
| Cash paid for amounts included in the measurement of lease liabilities |  |  |  |
| Operating cash flows from finance leases | $0.9 | $1.6 | $2.5 |
| Operating cash flows from operating leases | $5.7 | $5.3 | $6.7 |
| Financing cash flows from finance leases | $6.0 | $8.1 | $6.3 |
| Non-cash activities: |  |  |  |
| Right of use assets obtained in exchange for finance lease liabilities | $57.6 | $73.6 | $22.8 |
| Right of use assets obtained in exchange for operating lease liabilities | $ - | $0.5 | $ - |
| Weighted-average remaining lease term - finance leases | 30.0 years | 20.5 years | 41.5 years |
| Weighted-average remaining lease term - operating leases | 12.0 years | 12.5 years | 13.0 years |
| Weighted-average discount rate - finance lease (4) | 3.9% | 2.4% | 4.9% |
| Weighted average discount rate - operating leases (4) | 3.4% | 3.4% | 3.4% |

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

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

$^{(3)}$ Operating and short-term lease expense were included as a component of operation and maintenance expense.

$^{(4)}$ Because our leases do not provide an implicit rate of return, we used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments.

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

| (in millions) | 2022 | 2021 | Balance Sheet Location |
| --- | --- | --- | --- |
| Right of use assets |  |  |  |
| Operating lease right of use assets, net | $15.7 | $19.5 | Other long-term assets |
| Finance lease right of use assets, net |  |  |  |
| Power purchase commitment | $71.8 | $76.7 |  |
| Land leases - utility solar generation | $102.4 | $47.0 |  |
| Other | $1.1 | $0.3 |  |
| Total finance lease right of use assets, net (1) | $175.3 | $124.0 | Property, plant, and equipment, net |
| Lease obligations |  |  |  |
| Current operating lease liabilities | $4.0 | $3.7 | Other current liabilities |
| Long-term operating lease liabilities | $25.4 | $29.1 | Other long-term liabilities |
| Current finance lease liabilities |  |  |  |
| Power purchase commitment | $72.7 | $78.4 | Current portion of long-term debt |
| Long-term finance lease liabilities |  |  |  |
| Land leases - utility solar generation | $109.3 | $51.0 |  |
| Other | $1.2 | $0.3 |  |
| Total long-term finance lease liabilities | $110.5 | $51.3 | Long-term debt |

$^{(1)}$ Amounts are net of accumulated amortization of $146.3 million and $139.7 million at December 31, 2022 and 2021, respectively.

WEC Energy Group

F-73

2022 Annual Financial Statements

Future minimum lease payments under our operating and finance leases and the present value of our net minimum lease payments as of December 31, 2022, were as follows:

| (in millions) | Total Operating Leases | Power Purchase Commitment | Land Leases - Utility Solar Generation | Other | Total Finance Leases |
| --- | --- | --- | --- | --- | --- |
| 2023 | $4.9 | $72.7 | $3.6 | $ - | $76.3 |
| 2024 | 4.3 | - | 3.9 | 0.1 | 4.0 |
| 2025 | 3.8 | - | 4.0 | 0.1 | 4.1 |
| 2026 | 3.9 | - | 4.0 | 0.1 | 4.1 |
| 2027 | 4.0 | - | 4.1 | 0.1 | 4.2 |
| Thereafter | 16.6 | - | 304.1 | 2.7 | 306.8 |
| Total minimum lease payments | 37.5 | 72.7 | 323.7 | 3.1 | 399.5 |
| Less: Interest | (8.1) | - | (214.4) | (1.9) | (216.3) |
| Present value of minimum lease payments | 29.4 | 72.7 | 109.3 | 1.2 | 183.2 |
| Less: Short-term lease liabilities | (4.0) | (72.7) | - | - | (72.7) |
| Long-term lease liabilities | $25.4 | $ - | $109.3 | $1.2 | $110.5 |

As of February 23, 2023, 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 the years ended December 31:

| (in millions) | 2022 | 2021 | 2020 |
| --- | --- | --- | --- |
| Current tax expense | $50.2 | $93.9 | $49.2 |
| Deferred income taxes, net | 278.5 | 111.0 | 182.2 |
| ITCs | (5.8) | (4.6) | (3.5) |
| Total income tax expense | $322.9 | $200.3 | $227.9 |

### 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:

| (in millions) | 2022 |  | 2021 |  | 2020 |  |
| --- | --- | --- | --- | --- | --- | --- |
|  | Amount | Effective Tax Rate | Amount | Effective Tax Rate | Amount | Effective Tax Rate |
| Statutory federal income tax | $363.5 | 21.0% | $315.1 | 21.0% | $299.9 | 21.0% |
| State income taxes net of federal tax benefit | 109.7 | 6.3% | 96.1 | 6.4% | 90.5 | 6.3% |
| Wind PTCs | (107.6) | (6.2)% | (81.3) | (5.4)% | (51.5) | (3.6)% |
| Federal excess deferred tax amortization (1) | (36.9) | (2.1)% | (37.3) | (2.5)% | (36.7) | (2.6)% |
| AFUDC-Equity | (6.2) | (0.4)% | (3.8) | (0.3)% | (4.4) | (0.3)% |
| ITC restored | (5.8) | (0.3)% | (4.6) | (0.3)% | (3.5) | (0.2)% |
| Federal excess deferred tax amortization - Wisconsin unprotected (2) | (0.8) | - % | (77.9) | (5.2)% | (57.6) | (4.0)% |
| Other, net | 7.0 | 0.3% | (6.0) | (0.3)% | (8.8) | (0.7)% |
| Total income tax expense | $322.9 | 18.6% | $200.3 | 13.4% | $227.9 | 15.9% |

$^{(1)}$ The Tax Legislation required our regulated utilities to remeasure their deferred income taxes and we began to amortize the resulting excess protected deferred income taxes beginning in 2018 in accordance with normalization requirements. The decrease in income tax expense related to the amortization of the deferred tax benefits is offset by a decrease in revenue as the benefits are returned to customers, resulting in no impact on net income.

$^{(2)}$ In accordance with the rate order received from the PSCW in December 2019, our Wisconsin utilities are amortizing these unprotected deferred tax benefits over periods ranging from two years to four years, to reduce near-term rate impacts to their customers. The decrease in income tax expense related to the amortization of the deferred tax benefits is offset by a decrease in revenue as the benefits are returned to customers, resulting in no impact on net income.

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

WEC Energy Group

F-74

2022 Annual Financial Statements

## Deferred Income Tax Assets and Liabilities

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

| (in millions) | 2022 | 2021 |
| --- | --- | --- |
| Deferred tax assets |  |  |
| Tax gross up - regulatory items | $459.0 | $469.5 |
| Future tax benefits | 187.7 | 104.6 |
| Deferred revenues | 86.8 | 97.8 |
| Other | 190.2 | 205.9 |
| Total deferred tax assets | 923.7 | 877.8 |
| Valuation allowance | (1.2) | (1.2) |
| Net deferred tax assets | $922.5 | $876.6 |
| Deferred tax liabilities |  |  |
| Property-related | $4,072.5 | $3,909.0 |
| Investment in affiliates | 839.7 | 648.6 |
| Employee benefits and compensation | 219.5 | 170.6 |
| Deferred costs - plant retirements | 212.8 | 223.9 |
| Other | 203.6 | 233.0 |
| Total deferred tax liabilities | 5,548.1 | 5,185.1 |
| Deferred tax liability, net | $4,625.6 | $4,308.5 |

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

The components of net deferred tax assets associated with federal and state tax benefit carryforwards as of December 31, 2022 and 2021 are summarized in the tables below:

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

| 2021 (in millions) | Gross Value | Deferred Tax Effect | Valuation Allowance | Earliest Year of Expiration |
| --- | --- | --- | --- | --- |
| Future tax benefits as of December 31, 2021 |  |  |  |  |
| Federal tax credit | $ - | $91.5 | $ - | 2041 |
| State net operating loss | 72.0 | 4.4 | (1.2) | 2031 |
| Other state benefits | - | 8.7 | - | 2023 |
| Balance as of December 31, 2021 | $72.0 | $104.6 | $(1.2) |  |

## Unrecognized Tax Benefits

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

| (in millions) | 2022 | 2021 | 2020 |
| --- | --- | --- | --- |
| Balance as of January 1 | $6.8 | $11.9 | $17.9 |
| Additions for tax positions of prior years | 0.3 | - | 1.6 |
| Additions based on tax positions related to the current year | 0.4 | 1.6 | 0.1 |
| Reductions for tax positions of prior years | (1.2) | (6.7) | (7.7) |
| Balance as of December 31 | $6.3 | $6.8 | $11.9 |

The amount of unrecognized tax benefits as of December 31, 2022 and 2021, excludes deferred tax assets related to uncertainty in income taxes of $1.3 million and $1.2 million, respectively. As of December 31, 2022 and 2021, the net amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations was $5.1 million and $5.7 million, respectively.

WEC Energy Group

F-75

2022 Annual Financial Statements

Interest accrued related to unrecognized tax benefits is as follows:

| (in millions) | 2022 | 2021 | 2020 |
| --- | --- | --- | --- |
| Balance as of January 1 | $0.1 | $0.5 | $0.8 |
| Interest expense (income) related to unrecognized tax benefits | 0.4 | (0.4) | (0.3) |
| Balance as of December 31 | $0.5 | $0.1 | $0.5 |

For the years ended December 31, 2022, 2021, and 2020, we recognized no penalties related to unrecognized tax benefits in our consolidated income statements. At December 31, 2022 and 2021, we had no amounts accrued for penalties related to unrecognized tax benefits.

Although analysis of our unrecognized tax benefits is ongoing, the potential estimated decrease in the total amounts of unrecognized tax benefits within the next 12 months is approximately $2.3 million associated with statutes of limitations on certain tax years. We do not anticipate any significant increases in the total amounts of unrecognized tax benefits within the next 12 months.

We file income tax returns in the United States federal jurisdiction and state tax returns based on income in our major state operating jurisdictions of Wisconsin, Illinois, Michigan, and Minnesota. We also file tax returns in other state and local jurisdictions with varying statutes of limitations. As of December 31, 2022, with a few exceptions, we were subject to examination by federal and state or local tax authorities for the 2017 through 2022 tax years in our major operating jurisdictions as follows:

| Jurisdiction | Years |
| --- | --- |
| Federal | 2019-2022 |
| Illinois | 2017-2022 |
| Michigan | 2018-2022 |
| Minnesota | 2018-2022 |
| Wisconsin | 2018-2022 |

## 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:

| (in millions) | December 31, 2022 |  |  |  |
| --- | --- | --- | --- | --- |
|  | Level 1 | Level 2 | Level 3 | Total |
| Derivative assets |  |  |  |  |
| Natural gas contracts | $16.3 | $16.2 | $ - | $32.5 |
| FTRs | - | - | 7.8 | 7.8 |
| Coal contracts | - | 34.5 | - | 34.5 |
| Total derivative assets | $16.3 | $50.7 | $7.8 | $74.8 |
| Investments held in rabbi trust | $50.9 | $ - | $ - | $50.9 |
| Derivative liabilities |  |  |  |  |
| Natural gas contracts | $81.4 | $15.2 | $ - | $96.6 |

| (in millions) | December 31, 2021 |  |  |  |
| --- | --- | --- | --- | --- |
|  | Level 1 | Level 2 | Level 3 | Total |
| Derivative assets |  |  |  |  |
| Natural gas contracts | $46.4 | $18.2 | $ - | $64.6 |
| FTRs | - | - | 2.4 | 2.4 |
| Coal contracts | - | 53.0 | - | 53.0 |
| Total derivative assets | $46.4 | $71.2 | $2.4 | $120.0 |
| Investments held in rabbi trust | $79.6 | $ - | $ - | $79.6 |
| Derivative liabilities |  |  |  |  |
| Natural gas contracts | $8.4 | $6.7 | $ - | $15.1 |

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 at our

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2022 Annual Financial Statements

electric utilities and certain of our non-utility wind parks to manage electric transmission congestion costs in the MISO Energy Markets. During 2022, we also held TCRs, which were used at certain of our non-utility wind parks to manage electric transmission congestion costs in the SPP Integrated Marketplace, but these TCRs settled prior to December 31, 2022.

We hold investments in the Integrys rabbi trust. These investments are restricted as they can only be withdrawn from the trust to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans. These investments are included in other long-term assets on our balance sheets. We recorded $12.7 million of net unrealized losses in earnings related to the investments held at the end of the period during the year ended December 31, 2022. For the years ended December 31, 2021 and 2020, the net unrealized gains included in earnings related to the investments held at the end of the period were $16.0 million and $6.3 million, respectively.

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

| (in millions) | 2022 | 2021 | 2020 |
| --- | --- | --- | --- |
| Balance at the beginning of the period | $2.4 | $2.4 | $3.1 |
| Purchases | 23.7 | 6.1 | 7.6 |
| Realized and unrealized gains included in earnings (1) | 0.5 | - | - |
| Settlements | (18.8) | (6.1) | (8.3) |
| Balance at the end of the period | $7.8 | $2.4 | $2.4 |
| Losses included in earnings attributable to the change in unrealized losses of Level 3 derivatives held at the end of the reporting period (1) | $(0.4) | $ - | $ - |

$^{(1)}$ Amounts relate to FTRs and TCRs acquired by certain wind generating facilities included in our non-utility energy infrastructure segment. These realized and unrealized gains and losses are recorded in operating revenues on our income statements.

## Fair Value of Financial Instruments

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

| (in millions) | 2022 |  | 2021 |  |
| --- | --- | --- | --- | --- |
|  | Carrying Amount | Fair Value | Carrying Amount | Fair Value |
| Preferred stock of subsidiary | $30.4 | $22.7 | $30.4 | $30.3 |
| Long-term debt, including current portion (1) | 15,464.2 | 13,921.3 | 13,563.4 | 14,819.4 |

$^{(1)}$ The carrying amount of long-term debt excludes finance lease obligations of $183.2 million and $129.7 million at December 31, 2022 and 2021, respectively.

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

## NOTE 18-DERIVATIVE 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. None of the derivatives shown below were designated as hedging instruments.

| (in millions) | December 31, 2022 |  | December 31, 2021 |  |
| --- | --- | --- | --- | --- |
|  | Derivative Assets | Derivative Liabilities | Derivative Assets | Derivative Liabilities |
| Current |  |  |  |  |
| Natural gas contracts | $32.5 | $88.2 | $60.6 | $14.0 |
| FTRs | 7.8 | - | 2.4 | - |
| Coal contracts | 18.9 | - | 44.0 | - |
| Total current | 59.2 | 88.2 | 107.0 | 14.0 |
| Long-term |  |  |  |  |
| Natural gas contracts | - | 8.4 | 4.0 | 1.1 |
| Coal contracts | 15.6 | - | 9.0 | - |
| Total long-term | 15.6 | 8.4 | 13.0 | 1.1 |
| Total | $74.8 | $96.6 | $120.0 | $15.1 |

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2022 Annual Financial Statements

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

| (in millions) | December 31, 2022 |  | December 31, 2021 |  | December 31, 2020 |  |
| --- | --- | --- | --- | --- | --- | --- |
|  | Volumes | Gains | Volumes | Gains | Volumes | Gains (Losses) |
| Natural gas contracts | 183.3 Dth | $299.5 | 197.6 Dth | $136.5 | 188.6 Dth | $(54.1) |
| FTRs and TCRs | 27.2 MWh | 11.8 | 28.2 MWh | 17.7 | 29.8 MWh | 4.1 |
| Total |  | $311.3 |  | $154.2 |  | $(50.0) |

At December 31, 2022 and 2021, we had posted cash collateral of $122.4 million and $13.9 million, respectively. We had also received cash collateral of $13.2 million at December 31, 2021.

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

| (in millions) | December 31, 2022 |  | December 31, 2021 |  |
| --- | --- | --- | --- | --- |
|  | Derivative Assets | Liabilities | Derivative Assets | Liabilities |
| Gross amount recognized on the balance sheet | $74.8 | $96.6 | $120.0 | $15.1 |
| Gross amount not offset on the balance sheet | (17.5) | (82.5) (1) | (15.2) (2) | (9.2) (3) |
| Net amount | $57.3 | $14.1 | $104.8 | $5.9 |

$^{(1)}$ Includes cash collateral posted of $65.0 million.

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

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

## Cash Flow Hedges

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

We previously entered into forward interest rate swap agreements to mitigate the interest rate exposure associated with the issuance of long-term debt related to the acquisition of Integrys. These swap agreements were settled in 2015, and we continue to amortize amounts out of accumulated other comprehensive loss into interest expense over the periods in which the interest costs are recognized in earnings.

The table below shows the amounts related to these cash flow hedges recorded in other comprehensive income (loss) and in earnings, along with our total interest expense on the income statements, for the years ended December 31:

| (in millions) | 2022 | 2021 | 2020 |
| --- | --- | --- | --- |
| Derivative gain (loss) recognized in other comprehensive income / loss | $ - | $0.8 | $(5.9) |
| Net derivative gain (loss) reclassified from accumulated other comprehensive loss to interest expense | 0.4 | (1.3) | (2.1) |
| Total interest expense line item on the income statements | 515.1 | 471.1 | 493.7 |

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

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2022 Annual Financial Statements

## NOTE 19-GUARANTEES

The following table shows our outstanding guarantees:

| (in millions) | Total Amounts Committed at December 31, 2022 | Expiration |  |  |
| --- | --- | --- | --- | --- |
|  |  | Less Than 1 Year | 1 to 3 Years | Over 3 Years |
| Standby letters of credit (1) | $115.7 | $8.0 | $0.2 | $107.5 |
| Surety bonds (2) | 34.0 | 33.9 | 0.1 | - |
| Other guarantees (3) | 9.4 | - | - | 9.4 |
| Total guarantees | $159.1 | $41.9 | $0.3 | $116.9 |

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

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

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

## NOTE 20-EMPLOYEE BENEFITS

### Pension and Other Postretirement Employee Benefits

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

Generally, former Wisconsin Energy Corporation employees who started with the company after 1995 receive a benefit based on a percentage of their annual salary plus an interest credit, while employees who started before 1996 receive a benefit based upon years of service and final average salary. Wisconsin Energy Corporation management employees hired after December 31, 2014, and certain new represented employees hired after May 1, 2017, receive an annual company contribution to their 401(k) savings plan instead of being enrolled in the defined benefit plans.

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

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

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2022 Annual Financial Statements

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

| (in millions) | Pension Benefits |  | OPEB Benefits |  |
| --- | --- | --- | --- | --- |
|  | 2022 | 2021 | 2022 | 2021 |
| Change in benefit obligation |  |  |  |  |
| Obligation at January 1 | $3,136.6 | $3,346.4 | $530.2 | $556.1 |
| Service cost | 50.8 | 54.3 | 14.3 | 15.7 |
| Interest cost | 91.8 | 87.5 | 15.4 | 14.5 |
| Participant contributions | - | - | 12.5 | 12.5 |
| Plan amendments | - | - | 0.2 | (3.9) |
| Actuarial gain | (682.3) | (101.3) | (127.9) | (20.3) |
| Benefit payments | (281.0) | (250.3) | (45.7) | (47.5) |
| Federal subsidy on benefits paid | N/A | N/A | 1.4 | 1.2 |
| Transfer | - | - | 1.9 | 1.9 |
| Obligation at December 31 | $2,315.9 | $3,136.6 | $402.3 | $530.2 |
| Change in fair value of plan assets |  |  |  |  |
| Fair value at January 1 | $3,328.9 | $3,225.0 | $1,000.2 | $951.4 |
| Actual return on plan assets | (431.3) | 291.8 | (135.4) | 79.9 |
| Employer contributions | 11.4 | 62.4 | 3.7 | 3.9 |
| Participant contributions | - | - | 12.5 | 12.5 |
| Benefit payments | (281.0) | (250.3) | (45.7) | (47.5) |
| Fair value at December 31 | $2,628.0 | $3,328.9 | $835.3 | $1,000.2 |
| Funded status at December 31 | $312.1 | $192.3 | $433.0 | $470.0 |

In 2022 and 2021, we had actuarial gains related to our pension benefit obligations of $682.3 million and $101.3 million, respectively, both of which were primarily driven by changes in our discount rates. The discount rate for our pension benefits was 5.49%, 2.96%, and 2.67%, in 2022, 2021, and 2020, respectively.

In 2022, we had an actuarial gain related to our OPEB benefit obligation of $127.9 million, which was primarily driven by an increase in our discount rate. The discount rate for our OPEB benefits was 5.50% and 2.92%, in 2022 and 2021, respectively. The 2021 actuarial gain related to our OPEB benefit obligations was not significant.

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

| (in millions) | Pension Benefits |  | OPEB Benefits |  |
| --- | --- | --- | --- | --- |
|  | 2022 | 2021 | 2022 | 2021 |
| Pension and OPEB assets | $470.6 | $389.0 | $446.1 | $492.3 |
| Pension and OPEB obligations | 158.5 | 196.7 | 13.1 | 22.3 |
| Total net assets | $312.1 | $192.3 | $433.0 | $470.0 |

The accumulated benefit obligation for all defined benefit pension plans was $2,250.6 million and $3,010.5 million as of December 31, 2022 and 2021, respectively.

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

| (in millions) | 2022 | 2021 |
| --- | --- | --- |
| Accumulated benefit obligation | $185.7 | $372.4 |
| Fair value of plan assets | 32.8 | 186.3 |

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

| (in millions) | 2022 | 2021 |
| --- | --- | --- |
| Projected benefit obligation | $191.3 | $383.0 |
| Fair value of plan assets | 32.8 | 186.3 |

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2022 Annual Financial Statements

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

| (in millions) | 2022 | 2021 |
| --- | --- | --- |
| Accumulated benefit obligation | $20.6 | $25.1 |
| Fair value of plan assets | 7.4 | 2.8 |

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

| (in millions) | Pension Benefits |  | OPEB Benefits |  |
| --- | --- | --- | --- | --- |
|  | 2022 | 2021 | 2022 | 2021 |
| Pre-tax accumulated other comprehensive income (loss) (1) |  |  |  |  |
| Net actuarial loss (gain) | $12.2 | $7.5 | $(1.6) | $(1.4) |
| Prior service credits | - | - | - | (0.1) |
| Total | $12.2 | $7.5 | $(1.6) | $(1.5) |
| Net regulatory assets (liabilities) (2) |  |  |  |  |
| Net actuarial loss (gain) | $669.2 | $798.6 | $(200.8) | $(300.1) |
| Prior service credits | (2.1) | (0.5) | (44.2) | (60.3) |
| Total | $667.1 | $798.1 | $(245.0) | $(360.4) |

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

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

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

| (in millions) | Pension Benefits |  |  | OPEB Benefits |  |  |
| --- | --- | --- | --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 | 2022 | 2021 | 2020 |
| Service cost | $50.8 | $54.3 | $50.1 | $14.3 | $15.7 | $15.2 |
| Interest cost | 91.8 | 87.5 | 102.8 | 15.4 | 14.5 | 18.6 |
| Expected return on plan assets | (208.0) | (200.9) | (190.3) | (68.9) | (66.0) | (60.3) |
| Plan settlement | 6.2 | 3.9 | 17.9 | - | - | - |
| Plan curtailment | - | - | - | - | (6.4) | - |
| Amortization of prior service cost (credit) | 1.6 | 1.6 | 1.6 | (15.9) | (15.9) | (15.0) |
| Amortization of net actuarial loss (gain) | 75.3 | 109.4 | 102.6 | (24.7) | (24.4) | (22.4) |
| Net periodic benefit cost (credit) | $17.7 | $55.8 | $84.7 | $(79.8) | $(82.5) | $(63.9) |

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 |  |
| --- | --- | --- | --- | --- |
|  | 2022 | 2021 | 2022 | 2021 |
| Discount rate | 5.49% | 2.96% | 5.50% | 2.92% |
| Rate of compensation increase | 4.00% | 4.00% | N/A | N/A |
| Interest credit rate | 4.61% | 3.73% | N/A | N/A |
| Assumed medical cost trend rate (Pre 65) | N/A | N/A | 6.50% | 5.70% |
| Ultimate trend rate (Pre 65) | N/A | N/A | 5.00% | 5.00% |
| Year ultimate trend rate is reached (Pre 65) | N/A | N/A | 2031 | 2028 |
| Assumed medical cost trend rate (Post 65) | N/A | N/A | 6.00% | 5.67% |
| 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 | 2031 | 2028 |

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2022 Annual Financial Statements

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

|  | Pension Benefits |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
| Discount rate | 3.18% | 2.71% | 3.34% |
| Expected return on plan assets | 6.88% | 6.88% | 6.87% |
| Rate of compensation increase | 4.00% | 4.00% | 4.00% |
| Interest credit rate | 3.78% | 3.71% | 3.70% |

|  | OPEB Benefits |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
| Discount rate | 2.92% | 2.66% | 3.39% |
| Expected return on plan assets | 7.00% | 7.00% | 7.00% |
| Assumed medical cost trend rate (Pre 65) | 5.70% | 5.85% | 6.00% |
| Ultimate trend rate (Pre 65) | 5.00% | 5.00% | 5.00% |
| Year ultimate trend rate is reached (Pre 65) | 2028 | 2028 | 2028 |
| Assumed medical cost trend rate (Post 65) | 5.67% | 5.80% | 5.91% |
| Ultimate trend rate (Post 65) | 5.00% | 5.00% | 5.00% |
| Year ultimate trend rate is reached (Post 65) | 2028 | 2028 | 2028 |

We consult with our investment advisors on an annual basis to help us forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the trust. For 2023, the expected return on assets assumption is 6.88% for the pension plans and 7.00% for the OPEB plans.

## Plan Assets

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

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

The legacy Wisconsin Energy Corporation pension trust target asset allocations are 30% equity investments, 55% fixed income investments, and 15% private equity and real estate investments. The legacy Integrys pension trust target asset allocations are 40% equity investments, 45% fixed income investments, and 15% private equity and real estate investments. The legacy Wisconsin Energy Corporation OPEB trust target asset allocations are 50% equity investments, 40% fixed income investments, and 10% real estate investments. The two largest legacy OPEB trusts for Integrys have the same target asset allocations of 45% equity investments, 45% fixed income investments, and 10% real estate investments. Equity securities include investments in large-cap, mid-cap, and small-cap companies. Fixed income securities include corporate bonds of companies from diversified industries, mortgage and other asset backed securities, commercial paper, and United States Treasuries.

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

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2022 Annual Financial Statements

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

| (in millions) | December 31, 2022 |  |  |  |  |  |  |  |
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
|  | Pension Plan Assets |  |  |  | OPEB Assets |  |  |  |
|  | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total |
| Asset Class |  |  |  |  |  |  |  |  |
| Equity securities: |  |  |  |  |  |  |  |  |
| United States equity | $231.5 | $ - | $ - | $231.5 | $92.5 | $ - | $ - | $92.5 |
| International equity | 202.2 | - | - | 202.2 | 83.9 | - | - | 83.9 |
| Fixed income securities: (1) |  |  |  |  |  |  |  |  |
| United States bonds | - | 838.7 | - | 838.7 | 129.8 | 145.3 | - | 275.1 |
| International bonds | - | 95.0 | - | 95.0 | - | 13.2 | - | 13.2 |
|  | 433.7 | 933.7 | - | 1,367.4 | 306.2 | 158.5 | - | 464.7 |
| Investments measured at net asset value: |  |  |  |  |  |  |  |  |
| Equity securities |  |  |  | 466.0 |  |  |  | 186.6 |
| Fixed income securities |  |  |  | 101.0 |  |  |  | 65.5 |
| Other |  |  |  | 693.6 |  |  |  | 118.5 |
| Total |  |  |  | $2,628.0 |  |  |  | $835.3 |

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

| (in millions) | December 31, 2021 |  |  |  |  |  |  |  |
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
|  | Pension Plan Assets |  |  |  | OPEB Assets |  |  |  |
|  | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total |
| Asset Class |  |  |  |  |  |  |  |  |
| Equity securities: |  |  |  |  |  |  |  |  |
| United States equity | $417.1 | $ - | $ - | $417.1 | $135.4 | $ - | $ - | $135.4 |
| International equity | 313.7 | - | - | 313.7 | 109.1 | - | - | 109.1 |
| Fixed income securities: (1) |  |  |  |  |  |  |  |  |
| United States bonds | - | 1,068.7 | - | 1,068.7 | 165.0 | 192.3 | - | 357.3 |
| International bonds | - | 118.5 | - | 118.5 | - | 15.6 | - | 15.6 |
|  | 730.8 | 1,187.2 | - | 1,918.0 | 409.5 | 207.9 | - | 617.4 |
| Investments measured at net asset value: |  |  |  |  |  |  |  |  |
| Equity securities |  |  |  | 659.2 |  |  |  | 224.5 |
| Fixed income securities |  |  |  | 127.7 |  |  |  | 112.3 |
| Other |  |  |  | 624.0 |  |  |  | 46.0 |
| Total |  |  |  | $3,328.9 |  |  |  | $1,000.2 |

$^{(1)}$ 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 $14.5 million to the pension plans and $2.1 million to the OPEB plans in 2023, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

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

| (in millions) | Pension Benefits | OPEB Benefits |
| --- | --- | --- |
| 2023 | $209.6 | $34.5 |
| 2024 | 207.2 | 34.3 |
| 2025 | 200.1 | 34.2 |
| 2026 | 202.1 | 34.3 |
| 2027 | 193.5 | 34.4 |
| 2028-2032 | 866.5 | 168.0 |

## Savings Plans

We sponsor 401(k) savings plans which allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. A percentage of employee contributions are matched by us through a contribution into the employee's savings plan account, up to certain limits. The 401(k) savings plans include an Employee Stock Ownership Plan. Certain employees receive an employer retirement contribution, in which amounts are contributed to the employee's savings plan account based on the

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employee's wages, age, and years of service. Total costs incurred under all of these plans were $54.4 million, $51.8 million, and $49.7 million in 2022, 2021, and 2020, respectively.

## NOTE 21-INVESTMENT IN TRANSMISSION AFFILIATES

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

| (in millions) | 2022 |  |  |
| --- | --- | --- | --- |
|  | ATC | ATC Holdco | Total |
| Balance at January 1 | $1,766.9 | $22.5 | $1,789.4 |
| Add: Earnings from equity method investment | 192.6 | 2.1 | 194.7 |
| Add: Capital contributions | 45.5 | - | 45.5 |
| Less: Distributions | 120.4 | - | 120.4 |
| Balance at December 31 | $1,884.6 | $24.6 | $1,909.2 |

| (in millions) | 2021 |  |  |
| --- | --- | --- | --- |
|  | ATC | ATC Holdco | Total |
| Balance at January 1 | $1,733.5 | $30.8 | $1,764.3 |
| Add: Earnings (loss) from equity method investment | 166.4 | (8.3) | 158.1 |
| Less: Distributions | 133.0 | - | 133.0 |
| Balance at December 31 | $1,766.9 | $22.5 | $1,789.4 |

| (in millions) | 2020 |  |  |
| --- | --- | --- | --- |
|  | ATC | ATC Holdco | Total |
| Balance at January 1 | $1,684.7 | $36.1 | $1,720.8 |
| Add: Earnings from equity method investment | 174.3 | 1.5 | 175.8 |
| Add: Capital contributions | 21.2 | - | 21.2 |
| Less: Distributions | 146.7 | - | 146.7 |
| Less: Return of capital | - | 6.8 | 6.8 |
| Balance at December 31 | $1,733.5 | $30.8 | $1,764.3 |

In November 2019 and May 2020, the FERC issued orders that addressed complaints related to ATC's allowed ROE. Due to the various petitions related to the complaint filed in February 2015, our financials at December 31, 2021 and 2020, included a $39.1 million liability for potential future refunds that ATC may have been required to provide. In August 2022, a decision issued by the D.C. Circuit Court of Appeals affirmed the FERC's previous orders related to the February 2015 complaint. Therefore, during the third quarter of 2022, we reversed the liability that was previously recorded, which increased our equity earnings from ATC.

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

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

| (in millions) | 2022 | 2021 | 2020 |
| --- | --- | --- | --- |
| Charges to ATC for services and construction | $18.9 | $22.9 | $27.5 |
| Charges from ATC for network transmission services | 363.7 | 361.0 | 350.5 |
| Net refund (payment) from (to) ATC related to FERC ROE orders | (0.1) | 7.3 | 10.7 |

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