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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10-K

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

For the fiscal year ended December 31, 2020

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

For the transition period from ________________ to ___________________
Commission
File Number
Registrant; State of Incorporation;
Address; and Telephone Number
IRS Employer
Identification No.
WEC-20201231_G1.JPG
001-09057 WEC ENERGY GROUP, INC. 39-1391525
(A Wisconsin Corporation)
231 West Michigan Street
P.O. Box 1331
Milwaukee, WI 53201
(414) 221-2345

Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Trading Symbol(s) Name of Each Exchange on Which Registered
Common Stock, $.01 Par Value WEC New York Stock Exchange

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

None

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

Yes     No

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

Yes     No




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

Yes     No

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

Yes     No

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

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

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of
the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.
7262(b)) by the registered public accounting firm that prepared or issued its audit report.    

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

Yes     No

The aggregate market value of the common stock of WEC Energy Group, Inc. held by non-affiliates was $27.6 billion based upon the reported closing price of such securities as of June 30, 2020.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date (January 31, 2021):

Common Stock, $.01 par value, 315,434,531 shares outstanding

Documents incorporated by reference:

Portions of WEC Energy Group, Inc.'s Definitive Proxy Statement on Schedule 14A for its Annual Meeting of Shareholders, to be held on May 6, 2021, are incorporated by reference into Part III hereof.



Table of Contents
WEC ENERGY GROUP, INC.
ANNUAL REPORT ON FORM 10-K
For the Year Ended December 31, 2020
TABLE OF CONTENTS
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2020 Form 10-K
i
WEC Energy Group, Inc.


Table of Contents
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2020 Form 10-K
ii
WEC Energy Group, Inc.


Table of Contents
GLOSSARY OF TERMS AND ABBREVIATIONS

The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:
Subsidiaries and Affiliates
ATC American Transmission Company LLC
ATC Holdco ATC Holdco LLC
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.
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
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
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
EPA United States Environmental Protection Agency
FERC Federal Energy Regulatory Commission
ICC Illinois Commerce Commission
IDNR Illinois Department of Natural Resources
IEPA Illinois Environmental Protection Agency
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
2020 Form 10-K
iii
WEC Energy Group, Inc.


Table of Contents
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
Environmental Terms
ACE Affordable Clean Energy
Act 141 2005 Wisconsin Act 141
BATW Bottom Ash Transport Water
BSER Best System of Emission Reduction
BTA Best Technology Available
CAA Clean Air Act
CO2
Carbon Dioxide
CPP Clean Power Plan
CSAPR Cross-State Air Pollution Rule
ELG Steam Electric Effluent Limitation Guidelines
FGD Flue Gas Desulfurization
GHG Greenhouse Gas
GMZ Groundwater Management Zone
NAAQS National Ambient Air Quality Standards
NOV Notice of Violation
NOx Nitrogen Oxide
NSPS New Source Performance Standards
PCB Polychlorinated Biphenyl
SO2 Sulfur Dioxide
VN Violation Notice
Measurements
Bcf Billion Cubic Feet
Dth Dekatherm
MDth One Thousand Dekatherms
MW Megawatt
MWh Megawatt-hour
Other Terms and Abbreviations
2007 Junior Notes WEC Energy Group, Inc.'s 2007 Junior Subordinated Notes Due 2067
AG Attorney General
AMI Advanced Metering Infrastructure
ARR Auction Revenue Right
Badger Hollow I Badger Hollow Solar Park I
Badger Hollow II Badger Hollow Solar Park II
BSGF Blue Sky Green Field Wind Park
CCWP Crane Creek Wind Park
CDC Centers for Disease Control and Prevention
CFR Code of Federal Regulations
Compensation Committee Compensation Committee of the Board of Directors
COVID-19 Coronavirus Disease – 2019
D.C. Circuit Court of Appeals United States Court of Appeals for the District of Columbia Circuit
EGU Electric Utility Generating Unit
ERGS Elm Road Generating Station
ER 1 Elm Road Generating Station Unit 1
ER 2 Elm Road Generating Station Unit 2
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ERP Enterprise Resource Planning
ESG Progress Plan WEC Energy Group's Capital Investment Plan for Efficiency, Sustainability, and Growth for 2021-2025
Exchange Act Securities Exchange Act of 1934, as amended
FTR Financial Transmission Right
GCRM Gas Cost Recovery Mechanism
GUIC Gas Utility Infrastructure Costs
Holding Company Act Wisconsin Utility Holding Company Act
ITC Investment Tax Credit
LIBOR London Interbank Offered Rate
LMP Locational Marginal Price
LNG Liquefied Natural Gas
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 5 Oak Creek Power Plant Unit 5
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 January 1, 2016
PIPP Presque Isle Power Plant
Point Beach Point Beach Nuclear Power Plant
PPA Power Purchase Agreement
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
ROE Return on Equity
RTO Regional Transmission Organization
SMP Natural Gas System Modernization Program
SOX Section 404 of the Sarbanes-Oxley Act
SPC COVID-19 Special Purpose Charge
SSR System Support Resource
Tax Legislation Tax Cuts and Jobs Act of 2017
Thunderhead Thunderhead Wind Energy LLC
Tilden Tilden Mining Company
Two Creeks Two Creeks Solar Park
VAPP Valley Power Plant
VITA Variable Income Tax Adjustment Rider
WHO World Health Organization

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

Forward-looking statements are subject to a number of risks and uncertainties that could cause our actual results to differ materially from those expressed or implied in the statements. These risks and uncertainties include those described in Item 1A. Risk Factors and those identified below:

Factors affecting utility operations such as catastrophic weather-related damage, 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, unusual weather, changes in economic conditions, customer growth and declines, commodity prices, energy conservation efforts, and continued adoption of distributed generation by customers;

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

The impact of health pandemics, including the COVID-19 pandemic, on our business functions, financial condition, liquidity, and results of operations;

The impact of recent and future federal, state, and local legislative and/or regulatory changes, including changes in rate-setting policies or procedures, deregulation and restructuring of the electric and/or natural gas utility industries, transmission or distribution system operation, the approval process for new construction, reliability standards, pipeline integrity and safety standards, allocation of energy assistance, energy efficiency mandates, and tax laws, including the Tax Legislation as well as those that affect our ability to use PTCs and ITCs;

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

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

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

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, and the feasibility of competing generation projects;

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

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

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

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

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

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

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

Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading markets and fuel suppliers and transporters;

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

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

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

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

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

The risk associated with the values of goodwill and other intangible assets 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 ability to maintain effective internal controls in accordance with SOX, while both continuing to integrate and consolidate our enterprise systems;

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

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

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

ITEM 1. BUSINESS

A. INTRODUCTION

In this report, when we refer to "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 wind generating facilities, WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Wisvest, WECC, WBS, and PDL. References to "Notes" are to the Notes to Consolidated Financial Statements included in this Annual Report on Form 10-K.

For more information about our business operations, see Note 22, Segment Information, and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations. For information about our business strategy, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Corporate Developments.

WEC Energy Group, Inc.

We were 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, we acquired 100% of the outstanding common shares of Integrys and changed our name to WEC Energy Group, Inc. Our wholly owned subsidiaries provide or invest in regulated natural gas and electricity, and renewable energy, as well as nonregulated renewable energy. We have an approximately 60% equity interest in ATC (an electric transmission company operating in Illinois, Michigan, Minnesota, and Wisconsin). At December 31, 2020, we had six reportable segments, which are discussed below. For additional information about our reportable segments, see Note 22, Segment Information.

Available Information

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

B. UTILITY ENERGY OPERATIONS

Wisconsin Segment

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

Electric Utility Operations

For the periods presented in this Annual Report on Form 10-K, our electric utility operations included operations of WE, WPS, and UMERC.

WE generates and distributes electric energy to customers located in southeastern Wisconsin (including the metropolitan Milwaukee area), east central Wisconsin, and northern Wisconsin. WE also served an iron ore mine customer, Tilden, in the Upper Peninsula of Michigan, through March 31, 2019 when Tilden became a customer of UMERC.

WPS generates and distributes electric energy to customers located in northeastern and central Wisconsin.

UMERC generates and distributes electric energy to customers located in the Upper Peninsula of Michigan. UMERC began generating electricity when its new natural gas-fired generation achieved commercial operation on March 31, 2019.

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Operating Revenues

For information about our operating revenues disaggregated by customer class for the years ended December 31, 2020, 2019, and 2018, see Note 4, Operating Revenues.

Electric Sales

Our electric energy deliveries included supply and distribution sales to retail, wholesale, and resale customers, and distribution sales to those customers who switched to an alternative electric supplier in the Upper Peninsula of Michigan. In 2020, retail revenues accounted for 91.9% of total electric operating revenues, wholesale revenues accounted for 4.1% of total electric operating revenues, and resale revenues accounted for 3.1% of total electric operating revenues. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Wisconsin Segment Contribution to Net Income Attributed to Common Shareholders for information on MWh sales by customer class.

Our electric utilities are authorized to provide retail electric service in designated territories in the state of Wisconsin, as established by indeterminate permits and boundary agreements with other utilities, and in certain territories in the state of Michigan pursuant to franchises granted by municipalities.

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

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

Steam Sales

WE has a steam utility that generates, distributes, and sells steam supplied by the VAPP to customers in metropolitan Milwaukee, Wisconsin. Steam is used by customers for processing, space heating, domestic hot water, and humidification. Annual sales of steam fluctuate from year to year based on system growth and variations in weather conditions.

Electric Sales Forecast

Our service territory experienced lower weather-normalized retail electric sales in 2020, as compared with 2019, due to the impact of the COVID-19 pandemic. We currently forecast retail electric sales volumes, excluding the Tilden mine located in the Upper Peninsula of Michigan, to grow between 1.0% and 1.3% over the next five years, compared with 2020, assuming normal weather. Electric peak demand is expected to grow between 0.5% and 1.0% over the next five years.

Customers
Year Ended December 31
(in thousands) 2020 2019 2018
Electric customers – end of year
Residential 1,459.3  1,449.7  1,441.3 
Small commercial and industrial 175.8  174.6  173.2 
Large commercial and industrial 0.8  0.9  0.9 
Wholesale and other 3.0  2.7  2.7 
Total electric customers – end of year 1,638.9  1,627.9  1,618.1 
Steam customers – end of year 0.4  0.4  0.4 
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Electric Commercial and Industrial Retail Customers

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

Electric Generation and Supply Mix

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

The table below indicates our sources of electric energy supply as a percentage of sales for the three years ended December 31, as well as estimates for 2021:
Estimate (1)
Actual
2021 2020 2019 2018
Company-owned generation units:
Coal 33.2  % 31.1  % 36.3  % 44.7  %
Natural gas:
Combined cycle 26.3  % 27.8  % 26.8  % 19.7  %
Steam turbine 0.7  % 1.0  % 0.8  % 0.6  %
Natural gas/oil peaking units 2.0  % 2.4  % 0.9  % 1.7  %
Renewables (2)
5.0  % 5.3  % 4.4  % 4.1  %
Total company-owned generation units 67.2  % 67.6  % 69.2  % 70.8  %
Power purchase contracts:
Nuclear 19.6  % 19.5  % 19.8  % 18.6  %
Natural gas 2.4  % 1.9  % 1.8  % 1.5  %
Renewables (2)
2.4  % 1.9  % 2.0  % 2.4  %
Other 1.8  % 1.7  % 1.8  % 1.7  %
Total power purchase contracts 26.2  % 25.0  % 25.4  % 24.2  %
Purchased power from MISO 6.6  % 7.4  % 5.4  % 5.0  %
Total purchased power 32.8  % 32.4  % 30.8  % 29.2  %
Total electric utility supply 100.0  % 100.0  % 100.0  % 100.0  %

(1)    The values included in the estimate assume a natural gas price based on the December 2020 NYMEX.

(2)    Includes hydroelectric, biomass, solar, and wind generation.

Electric Generation Facilities

Our generation portfolio is a mix of energy resources having different operating characteristics and fuel sources designed to balance providing energy that is stable, reliable, and affordable with environmental stewardship. We own 7,666 MW of generation capacity, including owned and jointly owned facilities. We Power's generating units are also included in the generation capacity. Our facilities include coal-fired plants, natural gas-fired plants, and renewable generation. Certain of our natural gas fired generation units have the ability to burn oil if natural gas is not available due to delivery constraints. For more information about our facilities, see Item 2. Properties.

On November 2, 2020, we added to our electric generation portfolio when WPS's new utility-scale solar plant, Two Creeks, with 150 MW nameplate capacity in Manitowoc County, Wisconsin achieved commercial operation. WPS owns 100 MW of Two Creeks.

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On March 31, 2019, we added to our electric generation portfolio when UMERC's new natural gas-fired generation with a 183 MW rated capacity in the Upper Peninsula of Michigan achieved commercial operation.

Creating a Sustainable Future

The ESG Progress Plan includes the retirement of older, fossil-fueled generation, to be replaced with the construction of zero-carbon-emitting renewable generation and 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 CO2 emissions from our electric generation.

In 2019, we met and surpassed our original goal to reduce CO2 emissions by 40% below 2005 levels. In July 2020, we announced new goals to reduce CO2 emissions from our electric generation by 70% below 2005 levels by 2030 and to be net carbon neutral by 2050. We added a near-term goal in November 2020 to reduce CO2 emissions by 55% below 2005 levels by 2025.

We already have retired more than 1,800 MW of coal-fired generation since the beginning of 2018, which included the 2019 retirement of the PIPP 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. As part of the ESG Progress Plan, we expect to retire approximately 1,800 MW of additional fossil-fueled generation by 2025. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Corporate Developments for more information on the ESG Progress Plan.

Renewable Generation

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

In December 2018, WE received approval from the PSCW for the Dedicated Renewable Energy Resource pilot program, a program for customers who wish to access a large-scale renewable project located in Wisconsin that WE would operate. The project will contribute toward meeting WE's peak demand, adding up to 150 MW of renewables to WE's portfolio, and help these larger customers to meet their sustainability and renewable energy goals.

Wind

In February 2021, WE and WPS filed an application with the PSCW for approval to accelerate up to approximately $154 million in capital investments in BSGF and CCWP, to repower major components. In response to the COVID-19 pandemic, the IRS issued guidance extending the period for work to be completed on facilities in order to be eligible for PTCs if certain requirements are met. If approved, WE and WPS each expect to receive an additional 10 years of PTCs, and BSGF and CCWP would be allowed to continue providing a reliable, cost-effective, zero-fuel-cost, zero-emission capacity and energy resource for customers

Solar

In February 2021, WE and WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire and construct the Paris Solar-Battery Park, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Kenosha County, Wisconsin and features 200 MW of solar generation and 110 MW of battery storage. The joint applicants propose that WE would acquire a 75% ownership interest, WPS would acquire a 15% ownership interest, and the unaffiliated utility would acquire the remaining 10% ownership interest. If approved, our share of the cost of this project is estimated to be approximately $385 million with construction expected to begin in 2022 and completed by the end of 2023.

As part of our commitment to invest in zero-carbon generation, we have received approval from the PSCW to invest in 300 MW of utility-scale solar within our Wisconsin segment.

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In August 2019, WE partnered with an unaffiliated utility to construct a solar project, Badger Hollow II, that will be located in Iowa County, Wisconsin and is expected to enter commercial operation in December 2022. Once constructed, WE will own 100 MW of this project.

In April 2019, WPS partnered with an unaffiliated utility to construct two solar projects in Wisconsin: Two Creeks, in service as of November 2020, and Badger Hollow I, construction in progress and targeted for completion in the second quarter of 2021. Badger Hollow I is located in Iowa County, Wisconsin, and Two Creeks is located in Manitowoc County, Wisconsin. WPS owns 100 MW of Two Creeks and will own 100 MW of Badger Hollow I for a total of 200 MW.

In December 2018, WE received approval from the PSCW for the Solar Now pilot program, which is expected to add 35 MW of solar generation to WE's portfolio, allowing non-profit and government entities, as well as commercial and industrial customers to site utility owned solar arrays on their property. Under this program, WE has energized 13 Solar Now projects and currently has another five under construction, together totaling more than 15 MW.

Electric System Reliability

The PSCW requires us to maintain a planning reserve margin above our projected annual peak demand forecast to help ensure reliability of electric service to our customers. These planning reserve requirements are consistent with the MISO calculated planning reserve margin. In 2008, the PSCW established a 14.5% reserve margin requirement for long-term planning (planning years two through ten). For short-term planning (planning year one), the PSCW requires Wisconsin utilities to follow the planning reserve margin established by MISO. MISO has an 18.0% installed capacity reserve margin requirement for the planning year from June 1, 2020, through May 31, 2021, and an 18.3% installed capacity reserve margin requirement for the planning year from June 1, 2021, through May 31, 2022. MISO's short-term reserve margin requirements experience year-to-year fluctuations, primarily due to changes in the generation resource mix and average forced outage rate of generation within the MISO footprint.

Michigan legislation requires all electric providers to demonstrate to the MPSC that they have adequate resources to serve the anticipated needs of their customers for a minimum of four consecutive planning years beginning in the upcoming planning year June 1, 2021, through May 31, 2022. The MPSC has established future planning reserve margin requirements based on the same study conducted by MISO that determines the short-term reserve margin requirements.

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

Fuel and Purchased Power Costs

Our retail electric rates in Wisconsin are established by the PSCW and include base amounts for fuel and purchased power costs. The electric fuel rules set by the PSCW 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. Prudently incurred fuel and purchased power costs are recovered dollar-for-dollar from our Michigan retail electric customers. For more information about the fuel rules, see E. Regulation.

Our average fuel and purchased power costs per MWh by fuel type, including delivery costs, were as follows for the years ended December 31:
2020 2019 2018
Coal $ 20.16  $ 22.77  $ 23.54 
Natural gas combined cycle 16.24  19.55  21.69 
Natural gas/oil peaking units 39.37  51.80  49.06 
Biomass 130.76  102.99  97.33 
Purchased power 43.50  42.53  42.85 

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

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

Coal Supply

We diversify the coal supply for our electric generating facilities and jointly-owned plants by purchasing coal from several mines in Wyoming and Pennsylvania, as well as from various other states. For 2021, approximately 88% of our total projected coal requirements of 8.4 million tons are contracted under fixed-price contracts. See Note 24, Commitments and Contingencies, for more information on amounts of coal purchases and coal deliveries under contract.

The annual tonnage amounts contracted for 2021 and 2022 are set forth below. We have not entered into any coal contracts for years after 2022.
(in thousands) Annual Tonnage
2021 7,380 
2022 2,100 

Coal Deliveries

All of our 2021 and 2022 coal requirements are expected to be shipped by unit trains that we own or lease under existing transportation agreements. The unit trains transport the coal for electric generating facilities from mines in Wyoming and Pennsylvania. Additional small volume agreements may also be used to supplement the normal coal supply for our facilities.

Power Purchase Commitments

We enter into short- and long-term power purchase commitments to meet a portion of our anticipated electric energy supply needs. Our power purchase commitments with unaffiliated parties are 1,379 MW for 2021 and 1,133 MW per year for 2022 through 2025, which exclude planning capacity purchases. Each of these amounts include 1,033 MW per year related to a long-term PPA for electricity generated by Point Beach. As part of our ESG Progress Plan, we retired some of our older, less efficient coal-fired generation in 2018 and 2019. To procure additional planning capacity, we purchased capacity from the MISO annual auction to ensure that we maintain our compliance with planning reserve requirements as established by the PSCW, MPSC, and MISO.

Natural Gas Utility Operations

WE, WPS, and WG are authorized to provide retail natural gas distribution service in designated territories in the state of Wisconsin, as established by indeterminate permits and boundary agreements with other utilities. Our Wisconsin natural gas utilities operate throughout the state of Wisconsin, including the City of Milwaukee and surrounding areas, northeastern Wisconsin, and in large areas of both central and western Wisconsin. In addition, UMERC is authorized to provide retail natural gas distribution service in designated territories in the Upper Peninsula of Michigan.

Our Wisconsin segment natural gas utilities provide service to residential, commercial and industrial, and transportation customers. Major industries served include real estate, restaurants, food products, governmental, and paper. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Wisconsin Segment Contribution to Net Income Attributed to Common Shareholders for information on natural gas sales volumes by customer class in Wisconsin and the Upper Peninsula of Michigan.

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Operating Revenues

For information about our operating revenues disaggregated by customer class for the years ended December 31, 2020, 2019, and 2018, see Note 4, Operating Revenues.

Natural Gas Sales Forecast

Our combined Wisconsin service territories experienced lower weather-normalized retail natural gas deliveries (excluding natural gas deliveries for electric generation) in 2020 as compared to 2019 due to the impact of the COVID-19 pandemic. We currently forecast retail natural gas delivery volumes to grow at a rate between 1.0% and 1.3% over the next five years, compared to 2020, assuming normal weather.

Customers
Year Ended December 31
(in thousands) 2020 2019 2018
Customers – end of year
Residential 1,349.9  1,339.6  1,329.6 
Commercial and industrial 132.3  131.5  130.6 
Transport 3.4  3.2  3.0 
Total customers 1,485.6  1,474.3  1,463.2 

Natural Gas Supply, Pipeline Capacity and Storage

We have been able to meet our contractual obligations with both our suppliers and our customers. For more information on our natural gas utility supply and transportation contracts, see Note 24, Commitments and Contingencies.

Pipeline Capacity and Storage

The interstate pipelines serving Wisconsin originate in major natural gas producing areas of North America: the Oklahoma and Texas basins, western Canada, and the Rocky Mountains. We have contracted for long-term firm capacity from a number of these sources. This strategy reflects management's belief that overall supply security is enhanced by geographic diversification of the supply portfolio.

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

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

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

To ensure a reliable supply of natural gas during peak winter conditions, we have LNG and propane facilities located within our distribution system. These facilities are typically utilized during extreme demand conditions to ensure reliable supply to our customers. In addition to their existing facilities, WE and WG each plan to construct an additional LNG facility. Subject to PSCW approval, 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. Commercial operation of the LNG facilities is targeted for the end of 2023.
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Combined with our storage capability, management believes that the volume of natural gas under contract is sufficient to meet our forecasted firm peak-day and seasonal demand. Our Wisconsin segment natural gas utilities' forecasted design peak-day throughput is 34.8 million therms for the 2020 through 2021 heating season. Our Wisconsin segment natural gas utilities' peak daily send-out during 2020 was 22.8 million therms on February 13, 2020.

Natural Gas Supply

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

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

Hedging Natural Gas Supply Prices

WE, WPS, and WG have PSCW approval to hedge up to 60% of planned winter demand and up to 15% of planned summer demand using a mix of NYMEX-based natural gas options and futures contracts. These approvals allow these companies to pass 100% of the hedging costs (premiums, brokerage fees, and losses) and proceeds (gains) to customers through their respective GCRMs.

To the extent that opportunities develop and physical supply operating plans are supportive, WE, WPS, and WG also have PSCW approval to utilize NYMEX-based natural gas derivatives to capture favorable forward-market price differentials. These approvals provide for 100% of the related proceeds to accrue to these companies' respective GCRMs.

Illinois Segment

Our Illinois segment includes the natural gas utility operations of PGL and NSG. Our customers are located in Chicago and the northern suburbs of Chicago. PGL and NSG provide service to residential, commercial and industrial, and transportation customers. Major industries served include real estate, non-profits, education, restaurants, and wholesale distributors. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Illinois Segment Contribution to Net Income Attributed to Common Shareholders for information on natural gas sales volumes by customer class.

Illinois Utilities Operating Statistics

Operating Revenues

For information about our operating revenues disaggregated by customer class for the years ended December 31, 2020, 2019, and 2018, see Note 4, Operating Revenues.

Customers
Year Ended December 31
(in thousands) 2020 2019 2018
Customers – end of year
Residential 895.9  870.6  863.2 
Commercial and industrial 71.4  71.8  72.1 
Transport 74.8  88.7  97.5 
Total customers 1,042.1  1,031.1  1,032.8 

Natural Gas Supply, Pipeline Capacity, and Storage

We manage portfolios of natural gas supply contracts, storage services, and pipeline transportation services designed to meet varying customer use patterns with safe, reliable natural gas supplies at the best value. For more information on our natural gas utility supply and transportation contracts, see Note 24, Commitments and Contingencies.

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Pipeline Capacity and Storage

We contract with local distribution companies and interstate pipelines to purchase firm transportation services. We believe that having multiple pipelines that serve our natural gas service territory benefits our customers by improving reliability, providing access to a diverse supply of natural gas, and fostering competition among these service providers. These benefits can lead to favorable conditions for our Illinois utilities when negotiating new agreements for transportation and storage services.

We own a 38.8 Bcf storage field (Manlove Field in central Illinois) and contract with various other underground storage service providers for additional storage services. Storage allows us to manage significant changes in daily natural gas demand and to purchase steady levels of natural gas on a year-round basis, which provides a hedge against supply cost volatility. We also own a natural gas pipeline system that connects Manlove Field to Chicago and nine major interstate pipelines. These assets are directed primarily to serving rate-regulated retail customers and are included in our regulatory rate base. We also use a portion of these company-owned storage and pipeline assets as a natural gas hub, which consists of providing transportation and storage services in interstate commerce to our wholesale customers. Customers deliver natural gas to us for storage through an injection into the storage reservoir, and we return the natural gas to the customers under an agreed schedule through a withdrawal from the storage reservoir. Title to the natural gas does not transfer to us. We recognize service fees associated with the natural gas hub services provided to wholesale customers. These service fees reduce the cost of natural gas and services charged to retail customers in rates.

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

Combined with our storage capability, management believes that the volume of natural gas under contract is sufficient to meet our forecasted firm peak-day and seasonal demand. Our Illinois utilities' forecasted design peak-day throughput is 26.3 million therms for the 2020 through 2021 heating season. Our Illinois utilities' peak daily send-out during 2020 was 15.7 million therms on February 13, 2020.

Natural Gas Supply

Our natural gas supply requirements are met through a combination of fixed-price purchases, index-priced purchases, contracted and owned storage, peak-shaving facilities, and natural gas supply call options. We contract for fixed-term firm natural gas supply each year to meet the demand of firm system sales customers. To supplement natural gas supply and manage risk, we purchase additional natural gas supply on the monthly and daily spot markets.

Hedging Natural Gas Supply Prices

Our Illinois utilities further reduce their supply cost volatility through the use of financial instruments, such as commodity futures, swaps, and options as part of their hedging programs. Their hedging programs are reviewed by the ICC as part of the annual purchased gas adjustment reconciliation. They hedge between 25% and 50% of natural gas purchases, with a target of 37.5%.

Natural Gas System Modernization Program

PGL is continuing work on the SMP, a project to replace approximately 2,000 miles of Chicago's aging natural gas pipeline infrastructure that began in 2011. PGL currently recovers these costs through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023. For information on regulatory proceedings related to the SMP, see Note 26, Regulatory Environment.

Other States Segment

Our other states segment includes the natural gas utility operations of MERC and MGU and the non-utility operations of MERC related to servicing appliances for customers. MERC serves customers in various cities and communities throughout Minnesota, and MGU serves customers in southern and western Michigan. MERC and MGU provide service to residential, commercial and industrial, and transportation customers. Major industries served include education, wholesale distributors, non-profits, metals manufacturing, and real estate. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of
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Operations – Other States Segment Contribution to Net Income Attributed to Common Shareholders for information on natural gas sales volumes by customer class for this segment.

Other States Utilities Operating Statistics

Operating Revenues

For information about our operating revenues disaggregated by customer class for the years ended December 31, 2020, 2019, and 2018, see Note 4, Operating Revenues.

Customers
Year Ended December 31
(in thousands) 2020 2019 2018
Customers – end of year
Residential 365.7  360.8  356.5 
Commercial and industrial 35.1  35.0  34.9 
Transport 24.4  24.7  24.7 
Total customers 425.2  420.5  416.1 

Natural Gas Supply, Pipeline Capacity and Storage

We manage portfolios of natural gas supply contracts, storage services, and pipeline transportation services designed to meet varying customer use patterns with safe, reliable natural gas supplies at the best value. For more information on our natural gas utility supply and transportation contracts, see Note 24, Commitments and Contingencies.

Pipeline Capacity and Storage

MGU owns a 2.9 Bcf storage field (Partello in Michigan) and contract with various other underground storage service providers for additional storage services. We contract with local distribution companies and interstate pipelines to purchase firm transportation services. We believe that having diverse capacity and storage benefits our customers.

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

Combined with our storage capability, management believes that the volume of gas under contract is sufficient to meet our forecasted firm peak-day and seasonal demand. Forecasted design peak-day throughput for our other states utilities is 9.2 million therms for the 2020 through 2021 heating season. Our other states utilities' peak daily send-out during 2020 was 6.6 million therms on February 13, 2020.

Natural Gas Supply

Our natural gas supply requirements are met through a combination of fixed-price purchases, index-priced purchases, contracted and owned storage, and natural gas supply call options. We contract for fixed-term firm natural gas supply each year to meet the demand of firm system sales customers. To supplement natural gas supply and manage risk, we purchase additional natural gas supply on the monthly and daily spot markets.

Hedging Natural Gas Supply Prices

Our other states utilities further reduce their supply cost volatility through the use of financial instruments, such as commodity futures, swaps, and options as part of their hedging programs. MERC has MPUC approval to hedge up to 30% of planned winter demand using NYMEX financial instruments. MGU has MPSC approval to hedge up to 20% of its planned annual purchases using NYMEX financial instruments.

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General

Seasonality

Electric Utility Operations – Wisconsin Segment

Our electric utility sales are impacted by seasonal factors and varying weather conditions. We sell more electricity during the summer months because of the residential cooling load. We continue to upgrade our electric distribution system, including substations, transformers, and lines, to meet the demand of our customers. In 2020, our generating plants performed as expected during the warmest periods of the summer, and all power purchase commitments under firm contract were received. During this period, our electric utilities did not require public appeals for conservation, and they did not interrupt or curtail service to non-firm customers who participate in load management programs. WPS did have economic interruption events, however service to customers was not curtailed. Economic interruptions are declared during times in which the price of electricity in the regional market exceeds the cost of operating the company's peaking generation. During this time, interruptible customers can choose to continue using electricity at a price based on wholesale market prices or to reduce their load.

Natural Gas Utility Operations – Wisconsin, Illinois, and Other States Segments

Since the majority of our customers use natural gas for heating, customer use is sensitive to weather and is generally higher during the winter months. Accordingly, we are subject to some variations in earnings and working capital throughout the year as a result of changes in weather. The effect on earnings from these changes in weather are reduced by decoupling mechanisms included in the rates of PGL, NSG, and MERC. These mechanisms differ by state and allow the utilities to recover or refund the differences between actual and authorized margins for certain customer classes.

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

Competition

Electric Utility Operations – Wisconsin Segment

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

Natural Gas Utility Operations – Wisconsin, Illinois, and Other States Segments

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

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

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C. ELECTRIC TRANSMISSION SEGMENT

ATC is a regional transmission company that owns, maintains, monitors, and operates electric transmission systems in Wisconsin, Michigan, Illinois, and Minnesota. ATC is expected to provide comparable service to all customers, including WE, WPS, and UMERC, and to support effective competition in energy markets without favoring any market participant. ATC is regulated by the FERC for all rate terms and conditions of service and is a transmission-owning member of MISO. MISO maintains operational control of ATC's transmission system, and WE, WPS, and UMERC are non-transmission owning members and customers of MISO. As of December 31, 2020, our ownership interest in ATC was approximately 60%. In addition, we owned approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. See Note 21, Investment in Transmission Affiliates, for more information.

In May 2020, the FERC issued an order related to the authorized base ROE for all MISO transmission owners, including ATC. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints, for more information.

D. NON-UTILITY OPERATIONS

Non-Utility Energy Infrastructure Segment

The non-utility energy infrastructure segment includes We Power, which owns and leases generating facilities to WE; Bluewater, which owns underground natural gas storage facilities in Michigan; and WECI, which holds ownership interests in several wind generating facilities. See Item 2. Properties, for more information on our non-utility energy infrastructure facilities.

W.E. Power, LLC

We Power, through wholly owned subsidiaries, designed and built approximately 2,500 MW of generation in Wisconsin. This generation is made up of capacity from the ERGS units, ER 1 and ER 2, which were placed in service in February 2010 and January 2011, respectively, and the PWGS units, PWGS 1 and PWGS 2, which were placed in service in July 2005 and May 2008, respectively. Two unaffiliated entities collectively own approximately 17%, or approximately 211 MW, of ER 1 and ER 2. We Power's share of the ERGS units and both PWGS units are being leased to WE under long-term leases (the ERGS units have 30-year leases and the PWGS units have 25-year leases), and are positioned to continue to provide a significant portion of our generation needs.

Because of the significant investment necessary to construct these generating units, we constructed the plants under Wisconsin's Leased Generation Law, which allows a non-utility affiliate to construct an electric generating facility and lease it to the public utility. The law allows a public utility that has entered into a lease approved by the PSCW to recover fully in its retail electric rates that portion of any payments under the lease that the PSCW has allocated to the public utility's Wisconsin retail electric service, and all other costs that are prudently incurred in the public utility's operation and maintenance of the electric generating facility allocated to the utility's Wisconsin retail electric service. In addition, the PSCW may not modify or terminate a lease it has approved under the Leased Generation Law except as specifically provided in the lease or the PSCW's order approving the lease. This law effectively created regulatory certainty in light of the significant investment being made to construct the units. All four units were constructed under leases approved by the PSCW.

We are recovering our costs of these units, including subsequent capital additions, through lease payments that are billed from We Power to WE and then recovered in WE's rates as authorized by the PSCW and the FERC. Under the lease terms, our return is calculated using a 12.7% ROE and the equity ratio is assumed to be 55% for the ERGS units and 53% for the PWGS units.

Bluewater Natural Gas Holding, LLC

Bluewater, located in Michigan, provides natural gas storage and hub services for our Wisconsin natural gas utilities. WE, WPS, and WG have entered into long-term service agreements for natural gas storage with a wholly owned subsidiary of Bluewater.

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WEC Infrastructure LLC

At December 31, 2020, our non-utility energy infrastructure segment included WECI's ownership interests in the wind generating facilities reflected in the table below.
Name Ownership Interest
Upstream 90.0  %
Bishop Hill III 90.0  %
Coyote Ridge 80.0  %
Blooming Grove 90.0  %
Tatanka Ridge (1)
85.0  %

(1)    Tatanka Ridge achieved commercial operation on January 5, 2021.

Bishop Hill III, Coyote Ridge, Blooming Grove, and Tatanka Ridge have offtake agreements with creditworthy unaffiliated third parties for the sale of all the energy they produce. In addition, Upstream's revenue is substantially fixed over a 10-year period through an agreement with a creditworthy unaffiliated third party. Under the Tax Legislation, all of these investments qualify for PTCs. WECI is entitled to the tax benefits of each facility in proportion to its ownership interest, with the exception of Coyote Ridge and Tatanka Ridge. WECI is entitled to 99% of the tax benefits of Coyote Ridge and Tatanka Ridge for the first 11 years of commercial operation, after which WECI will be entitled to tax benefits equal to its ownership interest. WECI recognizes PTCs as power is generated over 10 years.

In August 2019, WECI signed an agreement to acquire an 80% ownership interest in Thunderhead, a 300 MW wind generating facility under construction in Nebraska. In addition, in February 2020, WECI amended this agreement to acquire an additional 10% ownership interest in Thunderhead. The project has an offtake agreement with an unaffiliated third party for all of the energy to be produced by the facility for 12 years. Under the Tax Legislation, WECI's investments in Thunderhead is expected to qualify for PTCs.

See Note 2, Acquisitions, for more information on these wind generating facilities.

Seasonality

The electricity produced and revenues generated by our wind power plants depend heavily on wind conditions, which are variable. Operating results for wind power plants vary significantly from period to period depending on the wind conditions during the periods in question. Historically, wind production has been greater in the first and fourth quarters.

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, WBS, and PDL (prior to the sale of its remaining solar facilities as discussed in more detail in Note 3, Dispositions). This segment also includes Wisvest and WECC, which no longer have significant operations.

Wispark develops and invests in real estate, primarily in southeastern Wisconsin. Wispark had $28.8 million in real estate holdings at December 31, 2020.

WBS is a wholly owned centralized service company that provides administrative and general support services to our regulated entities. WBS also provides certain administrative and support services to our nonregulated entities.

E. REGULATION

We are a holding company and are subject to the requirements of the PUHCA 2005. We also have various subsidiaries that meet the definition of a holding company under the PUHCA 2005 and are also subject to its requirements.

Pursuant to the non-utility asset cap provisions of Wisconsin's public utility holding company law, the sum of certain assets of all non-utility affiliates in a holding company system generally may not exceed 25% of the assets of all public utility affiliates. However, among other items, the law exempts energy-related assets, including the generating plants constructed by We Power and the other assets in our non-utility energy infrastructure segment, from being counted against the asset cap provided that they are employed in
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qualifying businesses. We report to the PSCW annually on our compliance with this law and provide supporting documentation to show that our non-utility assets are below the non-utility asset cap.

Regulated Utility Operations

In addition to the specific regulations noted above and below, our utilities are subject to various other regulations, which primarily consist of regulations, where applicable, of the EPA; the WDNR; the IDNR; the IEPA; the Michigan Department of Environment, Great Lakes, and Energy (previously Michigan Department of Environmental Quality); the Michigan Department of Natural Resources; the United States Army Corps of Engineers; the Minnesota Department of Natural Resources; and the Minnesota Pollution Control Agency.

Rates

Our utilities' rates are subject to the regulations and oversight of various state regulatory commissions and the FERC, as applicable. Decisions by these regulators can significantly impact our liquidity, financial condition, and results of operations. The following table compares our utility operating revenues by regulatory jurisdiction for each of the three years ended December 31:
2020 2019 2018
(in millions) Amount Percent Amount Percent Amount Percent
Electric
Wisconsin $ 3,823.7  89.4  % $ 3,807.4  88.2  % $ 3,890.4  87.7  %
Michigan 127.2  3.0  % 142.6  3.3  % 152.4  3.4  %
FERC – Wholesale 323.1  7.6  % 367.6  8.5  % 396.1  8.9  %
Total electric 4,274.0  100.0  % 4,317.6  100.0  % 4,438.9  100.0  %
Natural Gas
Wisconsin 1,196.2  41.2  % 1,325.3  42.6  % 1,351.8  42.3  %
Illinois 1,321.9  45.5  % 1,357.1  43.6  % 1,400.0  43.8  %
Minnesota 255.9  8.8  % 281.5  9.0  % 289.8  9.1  %
Michigan 131.5  4.5  % 148.7  4.8  % 152.4  4.8  %
Total natural gas 2,905.5  100.0  % 3,112.6  100.0  % 3,194.0  100.0  %
Total utility operating revenues $ 7,179.5  $ 7,430.2  $ 7,632.9 

Retail Rates

The state regulatory commissions have general supervisory and regulatory powers over public utilities in their respective jurisdictions including, but not limited to, approval of retail utility rates and standards of service, mergers, affiliate transactions, location and construction of electric generating units and natural gas facilities, and certain other additions and extensions to utility facilities. The PSCW, ICC, and MPUC also regulate security issuances at utilities in their respective jurisdictions.

Historically, retail rates approved by the state commissions have been designed to provide utilities the opportunity to generate revenues to recover all prudently-incurred costs, along with a return on investment sufficient to pay interest on debt and provide a reasonable ROE. Rates charged to customers vary according to customer class and rate jurisdiction. WE, WPS, and WG are each subject to an earnings sharing mechanism in which a portion of the utility's earnings are required to be refunded to customers if the utility earns above its authorized ROE. See Note 26, Regulatory Environment, for more information on these earnings sharing mechanisms.

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The table below reflects the various state commissions that regulated each of our utilities' retail rates during 2020, along with the approved ROE and capital structure for each utility during 2020.
Regulated Retail Rates Regulatory Commission Authorized ROE Average Common Equity Component
WE – electric, natural gas, and steam PSCW 10.0% 52.5%
WPS – electric and natural gas PSCW 10.0% 52.5%
WG – natural gas PSCW 10.2% 52.5%
UMERC – electric (former WE customers) MPSC 10.1% 55.3%
UMERC – electric (former WPS customers) MPSC 10.2% 52.94%
PGL – natural gas ICC 9.05% 50.33%
NSG – natural gas ICC 9.05% 50.48%
MERC – natural gas MPUC 9.7% 50.9%
MGU – natural gas MPSC 9.9% 52.0%

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

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

Our natural gas utilities operate under GCRMs as approved by their respective state regulator. Generally, the GCRMs allow for a dollar-for-dollar recovery of prudently incurred natural gas costs.

See Note 1(d), Operating Revenues, for additional information on the significant mechanisms our utilities had in place in 2020 that allowed them to recover or refund changes in prudently incurred costs from rate case-approved amounts.

Our utilities file periodic requests with their respective state commission to request changes in retail rates. All of our utilities' rate requests are based on forward looking test years, which reflect additions to infrastructure and changes in costs incurred or expected to be incurred. For information on our regulatory proceedings, see Note 26, Regulatory Environment. Orders from our respective regulators can be viewed at the following websites:
Regulatory Commission Website
PSCW  https://psc.wi.gov/
ICC https://www.icc.illinois.gov/
MPSC http://www.michigan.gov/mpsc/
MPUC http://mn.gov/puc/

The material and information contained on these websites are not intended to be a part of, nor are they incorporated by reference into, this Annual Report on Form 10-K.

Wholesale Rates

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

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Electric Transmission, Capacity, and Energy Markets

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

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

As part of MISO, a market-based platform is used for valuing transmission congestion premised upon an LMP system. The LMP system includes the ability to hedge transmission congestion costs through ARRs and FTRs. ARRs are allocated to market participants by MISO, and FTRs are purchased through auctions. A new allocation and auction were completed for the period of June 1, 2020, through May 31, 2021. The resulting ARR allocation and the secured FTRs are expected to mitigate our transmission congestion risk for that period.

MISO has an annual zonal resource adequacy requirement to ensure there is sufficient generation capacity to serve the MISO market. To meet this requirement, capacity resources can be acquired through MISO's annual capacity auction, bilateral contracts for capacity, or provided from generating or demand response resources. All of our capacity requirements during the planning year from June 1, 2020, through May 31, 2021 were met.

Other Electric Regulations

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

WE and WPS are subject to Act 141 in Wisconsin, and UMERC is subject to Public Acts 295 and 342 in Michigan, which contain certain minimum requirements for renewable energy generation.

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

Other Natural Gas Regulations

Almost all of the natural gas we distribute is transported to our distribution systems by interstate pipelines. The pipelines' transportation and storage services, including PGL's natural gas hub, are regulated by the FERC under the Natural Gas Act and the Natural Gas Policy Act of 1978. In addition, the Pipeline and Hazardous Materials Safety Administration and the state commissions are responsible for monitoring and enforcing requirements governing our natural gas utilities' safety compliance programs for our pipelines under the United States Department of Transportation regulations. These regulations include 49 CFR Part 191 (Transportation of Natural and Other Gas by Pipeline; Annual Reports, Incident Reports, and Safety-Related Condition Reports), 49 CFR Part 192 (Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards), and 49 CFR Part 195 (Transportation of Hazardous Liquids by Pipeline).

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

Non-Utility Energy Infrastructure Operations

The generation facilities constructed by wholly owned subsidiaries of We Power are being leased on a long-term basis to WE. Environmental permits necessary for operating the facilities are the responsibility of the operating entity, WE. We Power received
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determinations from the FERC that upon the transfer of the facilities by lease to WE, We Power's subsidiaries would not be deemed public utilities under the Federal Power Act and thus would not be subject to the FERC's jurisdiction.

Bluewater is regulated by the FERC under the Natural Gas Act and the Natural Gas Policy Act of 1978. In addition, the Pipeline and Hazardous Materials Safety Administration is responsible for monitoring and enforcing requirements governing Bluewater's safety compliance programs for its pipelines under the United States Department of Transportation regulations. These regulations include 49 CFR Parts 191, 192, and 195. Given that Bluewater is required to route some of its natural gas through Canada, applicable reporting and licensing with the United States Department of Energy and the Canadian National Energy Board are also required, along with routine reporting related to imports and exports.

Bishop Hill III, Blooming Grove, Coyote Ridge, Tatanka Ridge and Upstream are all subject to the FERC’s regulation of wholesale energy under the Federal Power Act.

Compliance Costs

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

F. ENVIRONMENTAL COMPLIANCE

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

Anticipated expenditures for environmental compliance and certain remediation issues for the next three years are included in the estimated capital expenditures described in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital Requirements. For a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change, see Note 24, Commitments and Contingencies.

G. HUMAN CAPITAL

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

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

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Workforce

As of December 31, 2020, we had the following number of employees, including those represented under union agreements:
Total Employees Union Employees
WE 2,460  1,923 
WPS 1,127  814 
(1)
WG 378  259 
PGL 1,492  1,046 
NSG 160  111 
MERC 207  43 
MGU 141  92 
WBS 1,308  — 
Total employees 7,273  4,288 

(1)    WPS's contract with Local 420 of International Union of Operating Engineers expires in April 2021. Negotiations are in progress, which we expect will conclude before the expiration of the current agreement.

We have a local union presence that spans Wisconsin, Illinois, Minnesota, and Michigan. We believe we have very good overall relations with our workforce. In order to attract and retain talent, we provide competitive wages and benefits to our employees based on their performance, role, location, and market data.

Diversity and Inclusion

We are committed to fostering a diverse workforce and inclusive workplace. Our commitment is a core strategic competency and an integral part of our culture. As of December 31, 2020, females and minorities represented approximately 25% and 26% of our workforce, respectively. We have a number of initiatives that promote diverse workforce contributions, educate employees about diversity and inclusion, and make our companies attractive employers for persons of diverse backgrounds. These initiatives include eight business resource groups (voluntary, employee-led groups organized around a particular shared background or interest), mentoring programs, and training for leaders on countering unconscious bias, building inclusive teams, and preventing workplace harassment. We also support external leadership and educational programs that support, train, and promote women and minorities in the communities we serve.

Safety and Health

Our Executive Safety Committee directs our safety and health strategy, works to ensure consistency across groups, and reinforces our ongoing safety commitment that we refer to as “Target Zero.” Under our Target Zero commitment, we have an ultimate goal of zero incidents, accidents, and injuries. Our corporate safety program provides a forum for addressing employee concerns, training employees and contractors on current safety standards, and recognizing those who demonstrate a safety focus. We monitor and set goals for Occupational Safety and Health Administration (OSHA)-recordable and lost-time incidents, as well as leading indicators, which together raise awareness about employee safety and guide injury-prevention activities.

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

During 2020, in response to the COVID-19 pandemic, we implemented safety protocols and new procedures to protect our employees and customers. See Factors Affecting Results, Liquidity, and Capital Resources – Coronavirus Disease – 2019, for additional information.

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Development and Training

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

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ITEM 1A. RISK FACTORS

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

Risks Related to Legislation and Regulation

Our business is significantly impacted by governmental regulation and oversight.

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

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

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

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

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

Our operations are subject to extensive and evolving federal, state, and local environmental laws, regulations, and permit requirements related to, among other things, air emissions (including, but not limited to: CO2, methane, mercury, SO2, and NOx), protection of natural resources, water quality, wastewater discharges, and management of hazardous, toxic, and solid wastes and substances. For example, the EPA adopted and implemented (or is in the process of implementing) regulations governing the emission of NOx, SO2, fine particulate matter, mercury, and other air pollutants under the CAA through the NAAQS, climate change
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regulations including the ACE rule, and other air quality regulations. The EPA also finalized regulations under the Clean Water Act that govern cooling water intake structures at our power plants and revised the effluent guidelines for steam electric generating plants. Several of these rules are being challenged, which creates additional uncertainty. For example, the D.C. Court of Appeals vacated the ACE rule in January 2021. In addition, existing environmental laws and regulations may be revised or new laws or regulations may be adopted at the federal, state, or local level. In particular, it is uncertain how the change in the United States presidential administration will impact the final resolution of several environmental standards or the adoption of new environmental laws and regulations.

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

As a result of these compliance costs and other factors, certain of our coal-fired electric generating facilities have become uneconomical to maintain and operate, which has resulted in these units being retired or converted to an alternative type of fuel. As part of our commitment to a cleaner energy future, we have already retired more than 1,800 MW of coal-fired generation since the beginning of 2018. Under the ESG Progress Plan, we expect to retire approximately 1,800 MW of additional fossil-fueled generation by 2025, to be replaced with the construction of zero-carbon emitting renewable generation and natural gas-fired generation.

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

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

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

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

There is continued scientific and political attention to issues concerning the existence and extent of climate change. Management expects this attention to continue, particularly with the change in the United States presidential administration. Although the previously issued ACE rule was vacated in January 2021 adding additional uncertainty, President Biden has indicated that climate change will become one of his primary initiatives, with significant actions expected by his administration during his term in office. As a result, we expect the EPA and states to adopt and implement additional regulations to restrict emissions of GHGs.

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

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

We also continue to monitor the financial and operational feasibility of taking more aggressive action to further reduce GHG emissions in order to limit future global temperature increases. Our plan to replace older, fossil-fueled generation with zero-carbon emitting renewable generation and natural gas-fired generation will contribute to the achievement of our goals related to reducing CO2 and methane emissions. However, our ability to achieve such goals depends on many external factors, including the development of relevant energy technologies. These efforts could impact how we operate our electric generating units and natural gas facilities and lead to increased competition and regulation, all of which could have a material adverse effect on our operations and financial condition.

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

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

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

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

We are also uncertain as to how credit rating agencies, capital markets, the FERC, or state public utility commissions will treat any future changes to federal or state tax legislation. These impacts could subject us or any of our subsidiaries to credit rating downgrades. In addition, certain financial metrics used by credit rating agencies, such as our funds from operations-to-debt percentage, could be negatively impacted by changes in federal or state income tax legislation.

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

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

Provisions of the Wisconsin Utility Holding Company Act limit our ability to invest in non-utility businesses and could deter takeover attempts by a potential purchaser of our common stock that would be willing to pay a premium for our common stock.

Under the Holding Company Act, we remain subject to certain restrictions that have the potential of limiting our diversification into non-utility businesses. Under the Holding Company Act, the sum of certain assets of all non-utility affiliates in a holding company system generally may not exceed 25% of the assets of all public utility affiliates in the system, subject to certain exemptions for energy-related assets.

In addition, the Holding Company Act precludes the acquisition of 10% or more of the voting shares of a holding company of a Wisconsin public utility unless the PSCW has first determined that the acquisition is in the best interests of utility customers, investors, and the public. This provision and other requirements of the Holding Company Act may delay or reduce the likelihood of a sale or change of control of WEC Energy Group. As a result, shareholders may be deprived of opportunities to sell some or all of their shares of our common stock at prices that represent a premium over market prices.

Risks Related to the Operation of Our Business

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

The global outbreak of COVID-19 was declared a pandemic by the WHO and the CDC and has spread globally, including throughout the United States. There is still considerable uncertainty regarding the extent and duration of the COVID-19 pandemic itself, as well as the measures currently in place to try to contain the virus, such as travel bans and restrictions, quarantines, limitations on business operations, and the timing of widespread availability of the vaccines. Although the shelter-in-place orders that were in effect for our service territories have expired, other orders limiting the capacity of various businesses have been adopted in some jurisdictions. In addition, similar or more restrictive orders could be adopted in the future depending on how the virus continues to spread and/or mutate. Although no longer mandated by all of our regulators, our utility subsidiaries are continuing to temporarily suspend disconnections.

The effects of the COVID-19 pandemic and related government responses have significantly disrupted economic activity in our service territories. Such effects have included, and may continue to include, extended disruptions to supply chains and capital markets, reduced labor availability and productivity, and a prolonged reduction in economic activity. These effects could continue to have a variety of adverse impacts on us and our subsidiaries, including continued reductions in demand for energy, particularly from commercial and industrial customers; impairment of goodwill or long-lived assets; continued decreases in revenue due to the inability to collect late fees; increased bad debt expense; increases in past due accounts receivable balances, impairment of our and our subsidiaries' ability to develop, construct, and operate facilities; and impaired ability to successfully access funds from credit and capital markets.

The COVID-19 pandemic has also caused significant disruption and volatility in the United States capital markets, and any additional or lingering effects on the capital markets may significantly impact us and our subsidiaries. For example, the costs related to our pension and other post-retirement benefit plans are based in part on the value of the plans’ assets. Adverse investment performance for these assets or the failure to maintain sustained growth in pension investments over time could increase our plan costs and funding requirements. Similarly, we rely on access to the capital markets to fund some of our operations and capital requirements. To the extent that access to the capital markets is adversely affected by COVID-19, we may need to consider alternative sources of funding for our operations and for working capital, which may increase our cost of, as well as adversely impact our access to, capital.

We have taken precautions with regard to employee hygiene and facility cleanliness, imposed travel limitations on our employees, provided additional employee benefits, and implemented remote work policies where appropriate. Additional protocols have been implemented for our field employees who travel to customer premises in order to protect them, our customers, and the public.
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As a reaction to the COVID-19 pandemic, it is possible that federal and state fiscal spending to fund COVID-19 relief measures, coupled with a drop in tax revenue from pandemic-related reductions in economic activity, may add to the pressure to raise more tax revenue from federal and state corporate income, other taxes including payroll or property taxes, to enact new types of taxes on businesses and their customers, or to disallow certain deductions.

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

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

Our financial performance depends on the successful operation of our electric generation, natural gas and electric distribution facilities, and renewable energy facilities. The operation of these facilities involves many risks, including operator error and the breakdown or failure of equipment or processes. Potential breakdown or failure may occur due to severe weather; catastrophic events (i.e., fires, earthquakes, explosions, tornadoes, floods, droughts, pandemic health events, etc.); significant changes in water levels in waterways; fuel supply or transportation disruptions; accidents; employee labor disputes; construction delays or cost overruns; shortages of or delays in obtaining equipment, material, and/or labor; performance below expected levels; operating limitations that may be imposed by environmental or other regulatory requirements; terrorist attacks; or cyber security intrusions. Any of these events could lead to substantial financial losses, including increased maintenance costs, unanticipated capital expenditures, and a reduction of revenues related to our non-utility renewable energy facilities.

Because our electric generation and renewable energy facilities are interconnected with third-party transmission facilities, the operation of our facilities could also be adversely affected by events impacting their systems. Unplanned outages at our power plants may reduce our revenues, cause us to incur significant costs if we are required to operate our higher cost electric generators or purchase replacement power to satisfy our obligations, and could result in additional maintenance expenses.

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

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

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

Fluctuations in customer growth and general economic conditions in our service areas. Customer growth and energy use can be negatively impacted by population declines as well as economic factors in our service territories, including workforce reductions, stagnant wage growth, changing levels of support from state and local government for economic development, business closings, and reductions in the level of business investment. Our electric and natural gas utilities are impacted by economic cycles and the competitiveness of the commercial and industrial customers we serve. Any economic downturn, disruption of financial markets, or reduced incentives by state government for economic development could adversely affect the financial condition of our customers and demand for their products or services. These risks could directly influence the demand for electricity and natural gas as well as the need for additional power generation and generating facilities. We could also be exposed to greater risks of accounts receivable write-offs if customers are unable to pay their bills.
Weather conditions. Demand for electricity is greater in the summer and winter months when cooling and heating is necessary. In addition, demand for natural gas peaks in the winter heating season. As a result, our overall results may fluctuate substantially on a seasonal basis. In addition, milder temperatures during the summer cooling season and during the winter heating season, as a result of climate change or otherwise, may result in lower revenues and net income.
Our customers' continued focus on energy conservation. Our customers' use of electricity and natural gas has decreased as a result of continued individual conservation efforts, including the use of more energy efficient technologies. Customers could also voluntarily reduce their consumption of energy in response to decreases in their disposable income and increases in energy prices. Conservation of energy can be influenced by certain federal and state programs that are intended to influence how
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consumers use energy. For example, several states, including Wisconsin and Michigan, have adopted energy efficiency targets to reduce energy consumption.

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

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

Our business requires substantial capital expenditures for investments in, among other things, capital improvements to our electric generating facilities, electric and natural gas distribution infrastructure, natural gas storage, and other projects, including projects for environmental compliance. We also expect to continue constructing and investing in renewable energy generating facilities as part of the ESG Progress Plan, including repowering existing wind generation projects in our generation portfolio, and as part of our non-utility energy infrastructure segment. In addition, WBS continues to invest in technology and the development of software applications to support our utilities.

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

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

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

We have been subject to attempted cyber attacks from time to time, but these attacks have not had a material impact on our system or business operations. Despite the implementation of security measures, all assets and systems are potentially vulnerable to disability, failures, or unauthorized access due to physical or cyber security intrusions caused by human error, vendor bugs, terrorist attacks, or other malicious acts. These threats could result in a full or partial disruption of our ability to generate, transmit, purchase, or distribute electricity or natural gas or cause environmental repercussions. If our assets or systems were to fail, be physically damaged, or be breached, and were not recovered in a timely manner, we may be unable to perform critical business functions, and data, including sensitive information, could be compromised.

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

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

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

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

Advances in technology, and legislation or regulations supporting such technology, could make our electric generating facilities less competitive.

Advances in new technologies that produce power or reduce power consumption are ongoing and include renewable energy technologies, customer-oriented generation, energy storage devices, and energy efficiency technologies. We generate power at central station power plants and utility-scale renewable generation facilities to achieve economies of scale and produce power at a competitive cost. There are distributed generation technologies that produce power, including fuel cells, microturbines, wind turbines, and solar cells, which have become more cost competitive than they were in the past. It is possible that legislation or regulations could be adopted supporting the use of these technologies. There is also a risk that advances in technology will continue to reduce the costs of these alternative methods of producing power to a level that is competitive with that of central station and utility-scale renewable power production. If these technologies become cost competitive and achieve economies of scale, our market share could be eroded, and the value of our generating facilities could be reduced. Advances in technology could also change the channels through which our electric customers purchase or use power, which could reduce our sales and revenues or increase our expenses.

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

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

We face risks related to our non-utility renewable energy facilities that could impact our return on investment or have a negative impact on our financial condition or results of operations.

The production of wind energy depends heavily on suitable wind conditions, which are variable. If wind conditions are unfavorable or below our estimates as a result of climate change or otherwise, our electricity production, and therefore our revenues and PTCs earned from our non-utility renewable energy facilities, may be substantially below our expectations. We base our decisions about which sites to acquire and operate in part on the findings of long-term wind and other meteorological data and studies conducted in
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the proposed area, which measure the wind’s speed and prevailing direction and seasonal variations. Actual conditions at these sites, however, may not conform to the measured data in these studies. For example, if there is an increase in frequency and severity of weather conditions, the disruptions to our sites may become more frequent and severe.

For the majority of our non-utility renewable energy operations, we have entered into long-term PPAs with a small number of customers to purchase the energy produced by our facilities. Although initial agreements are often ten years or more, in the future we may not be able to replace expiring PPAs related to our non-utility renewable energy facilities with contracts on acceptable terms, including at prices that support operation of the facility on a profitable basis. Decreases in the retail prices of electricity supplied by traditional utilities or other clean energy sources in the areas where our non-utility renewable energy facilities are located could harm our ability to offer competitive pricing and could harm our ability to sign PPAs with customers. If we are unable to replace an expiring PPA with an acceptable new revenue contract, we may be required to sell the power produced by the facility at wholesale prices and be exposed to market fluctuations and risks, or the affected site may temporarily or permanently cease operations. If we are unable to replace an expired distributed generation PPA with an acceptable new contract, we may be required to remove the renewable energy facility from the site or, alternatively, we may have to sell the assets, but the sale price may not be sufficient to replace the revenue previously generated by the renewable energy facility.

Our ability to acquire new non-utility renewable energy facilities or generate revenue from existing facilities depends on having interconnection arrangements with transmission providers and a reliable electricity grid. We cannot predict whether transmission facilities will be expanded in specific markets to accommodate or increase competitive access to those markets. In addition, if a transmission network to which one or more of our facilities is connected experiences down time for system emergencies, force majeure, safety, reliability, maintenance or other operational reasons, we may lose revenues and PTCs and be exposed to non-performance penalties and claims from our customers. This risk of curtailment of our non-utility renewable energy facilities may result in a reduced return on our investments, and we may not be compensated for lost energy and ancillary services.

We are a holding company and rely on the earnings of our subsidiaries to meet our financial obligations.

As a holding company with no operations of our own, our ability to meet our financial obligations including, but not limited to, debt service, taxes, and other expenses, as well as pay dividends on our common stock, is dependent upon the ability of our subsidiaries to pay amounts to us, whether through dividends or other payments. Our subsidiaries are separate legal entities that are not required to pay any of our obligations or to make any funds available for that purpose or for the payment of dividends on our common stock. The ability of our subsidiaries to pay amounts to us depends on their earnings, cash flows, capital requirements, and general financial condition, as well as regulatory limitations. Prior to distributing cash to us, our subsidiaries have financial obligations that must be satisfied, including, among others, debt service and preferred stock dividends. In addition, each subsidiary's ability to pay amounts to us depends on any statutory, regulatory, and/or contractual restrictions and limitations applicable to such subsidiary, which may include requirements to maintain specified levels of debt or equity ratios, working capital, or other assets. Our utility subsidiaries are regulated by various state utility commissions, which generally possess broad powers to ensure that the needs of the utility customers are being met.

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

We operate in an industry that requires many of our employees to possess unique technical skill sets. Events such as an aging workforce without appropriate replacements, the mismatch of skill sets to future needs, or the unavailability of contract resources may lead to operating challenges or increased costs. These operating challenges include lack of resources, loss of knowledge, and a lengthy time period associated with skill development. In addition, current and prospective employees may determine that they do not wish to work for us. Failure to hire and obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be adversely affected.

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

We are exposed to the risk that counterparties to various arrangements who owe us money, electricity, natural gas, or other commodities or services will not be able to perform their obligations. Should the counterparties to these arrangements fail to perform or if capacity is inadequate, we may be required to replace the underlying commitment at current market prices or we may be unable to meet all of our customers' electric and natural gas requirements unless or until alternative supply arrangements are put in place. In such event, we may incur losses, and our results of operations, financial position, or liquidity could be adversely affected.
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We have entered into several power purchase, natural gas supply, natural gas pipeline capacity, and transportation agreements with non-affiliated companies. Revenues are dependent on the continued performance by the counterparties of their obligations under these agreements. Although we have a comprehensive credit evaluation process and contractual protections, it is possible that one or more counterparties could fail to perform their obligations. If this were to occur, we generally would expect that any operating and other costs that were initially allocated to a defaulting customer's power purchase, natural gas supply, natural gas pipeline capacity, or transportation agreement would be reallocated among our retail customers. To the extent these costs are not allowed to be reallocated by our regulators or there is any regulatory delay in adjusting rates, a counterparty default under these agreements could have a negative impact on our results of operations and cash flows.

Risks Related to Economic and Market Volatility

Our business is dependent on our ability to successfully access capital markets.

We rely on access to credit and capital markets to support our capital requirements, including expenditures for our utility infrastructure and to comply with future regulatory requirements, to the extent not satisfied by the cash flow generated by our operations. We have historically secured funds from a variety of sources, including the issuance of short-term and long-term debt securities. Successful implementation of our long-term business strategies, including capital investment, is dependent upon our ability to access the capital markets, including the banking and commercial paper markets, on competitive terms and rates. In addition, we rely on committed bank credit agreements as back-up liquidity, which allows us to access the low cost commercial paper markets.

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

A rating downgrade;
Failure to comply with debt covenants;
An economic downturn or uncertainty;
Prevailing market conditions and rules;
Concerns over foreign economic conditions;
Changes in tax policy;
Changes in investment criteria of institutional investors;
War or the threat of war;
The overall health and view of the utility and financial institution industries; and
Changes in the method of determining LIBOR or the replacement of LIBOR with an alternative reference rate.

A portion of our indebtedness provides for interest at variable interest rates, primarily based on LIBOR. LIBOR is the subject of national, international, and other regulatory guidance and proposals for reform, which may cause LIBOR to cease to exist after June 2023 or to perform differently than in the past. While we expect that reasonable alternatives to LIBOR will be implemented prior to the 2023 target date, we cannot predict the consequences and timing of the development of alternative reference rates. The transition to alternative reference rates could include an increase in our interest expense.

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

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

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

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Any downgrade by the rating agencies could:

Increase borrowing costs under certain existing credit facilities;
Require the payment of higher interest rates in future financings and possibly reduce the pool of creditors;
Decrease funding sources by limiting our or our subsidiaries' access to the commercial paper market;
Limit the availability of adequate credit support for our subsidiaries' operations; and
Trigger collateral requirements in various contracts.

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

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

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

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

Changes in commodity prices could result in:

Higher working capital requirements, particularly related to natural gas inventory, accounts receivable, and cash collateral postings;
Reduced profitability to the extent that lower revenues, increased bad debt, and higher interest expense are not recovered through rates;
Higher rates charged to our customers, which could impact our competitive position;
Reduced demand for energy, which could impact revenues and operating expenses; and
Shutting down of generation facilities if the cost of generation exceeds the market price for electricity.

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

We own and operate several coal-fired electric generating units. Although we generally carry sufficient coal inventory at our generating facilities to protect against an interruption or decline in supply, there can be no assurance that the inventory levels will be adequate. While we have coal supply and transportation contracts in place, we cannot assure that the counterparties to these agreements will be able to fulfill their obligations to supply coal to us or that we will be able to take delivery of all the coal volume contracted for. If we are unable to obtain our coal requirements under our coal supply and transportation contracts, we may be required to purchase coal at higher prices or we may be forced to reduce generation at our coal-fired units, which could lead to increased fuel costs. The increase in fuel costs could result in either reduced margins on net sales into the MISO Energy Markets, a reduction in the volume of net sales into the MISO Energy Markets, and/or an increase in net power purchases in the MISO Energy Markets. There is no guarantee that we would be able to fully recover any increased costs in rates or that recovery would not otherwise be delayed, either of which could adversely affect our results of operations and cash flows.

Our use of derivative contracts could result in financial losses.

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

The regulated energy industry continues to experience significant structural changes. Deregulation or other changes in law in the states where we serve our customers could allow third-party suppliers to contract directly with customers for their natural gas and electric supply requirements. This increased competition in the retail and wholesale markets could have a material adverse financial impact on us.

Certain jurisdictions in which we operate, including Michigan and Illinois, have adopted retail choice. Under Michigan law, our retail customers may choose an alternative electric supplier to provide power supply service. The law limits customer choice to 10% of our Michigan retail load. The iron ore mine located in the Upper Peninsula of Michigan is excluded from this cap. When a customer switches to an alternative electric supplier, we continue to provide distribution and customer service functions for the customer. Although Illinois has adopted retail choice, there is currently little or no impact on the net income of our Illinois utilities as they still earn a distribution charge for transporting the natural gas for these customers. It is uncertain whether retail choice might be implemented in Wisconsin or Minnesota.

The FERC continues to support the existing RTOs that affect the structure of the wholesale market within these RTOs. In connection with its status as a FERC-approved RTO, MISO implemented bid-based energy markets that are part of the MISO Energy Markets. All market participants, including us, must submit day-ahead and/or real-time bids and offers for energy at locations across the MISO region. MISO then calculates the most efficient solution for all of the bids and offers made into the market that day and establishes an LMP that reflects the market price for energy. We are required to follow MISO's instructions when dispatching generating units to support MISO's responsibility for maintaining the stability of the transmission system. MISO also implemented an ancillary services market for operating reserves that schedules energy and ancillary services at the same time as part of the energy market, allowing for more efficient use of generation assets in the MISO Energy Markets. These market designs continue to have the potential to increase the costs of transmission, the costs associated with inefficient generation dispatching, the costs of participation in the MISO Energy Markets, and the costs associated with estimated payment settlements.

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

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

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

In addition, we maintain rabbi trusts to fund our deferred compensation plans, which from time to time, hold equity and debt investments that are subject to market fluctuations. Decreases in investment performance of these assets could materially adversely affect our results of operations, cash flows, and financial condition.

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General Risks

We may fail to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act.

We are subject to reporting, disclosure control, and other obligations under SOX. SOX contains provisions requiring our management to report on the effectiveness of our internal control over financial reporting and requires our independent registered public accounting firm to attest to the effectiveness of our internal controls. We have undertaken, and will continue to undertake, a variety of initiatives to integrate, standardize, centralize, and streamline our operations with technology, including, but not limited to, the implementation of several different ERP systems. There is a risk that we will not be able to conclude that our internal control over financial reporting is effective because of the discovery of material weaknesses, with either our current controls and processes or with the implementation of new controls and processes around these new technologies. Any failure to maintain effective internal controls or a determination by our independent registered public accounting firm that we have a material weakness in our internal controls could cause investors to lose confidence in the accuracy or completeness of our financial reports, cause a decline in the market price of our common stock, restrict our access to the capital markets, or subject us to investigations by the SEC or other regulatory authorities.

We have recorded goodwill that could become impaired.

We assess goodwill for impairment on an annual basis or whenever events or circumstances occur that indicate a potential for impairment. If goodwill is deemed to be impaired, we may be required to incur non-cash charges that could materially adversely affect our results of operations. At December 31, 2020, our goodwill was $3,052.8 million.

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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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ITEM 2. PROPERTIES

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

A. REGULATED

Electric Facilities

The following table summarizes information on our electric generation facilities, including owned and jointly owned facilities, as of December 31, 2020:
Name Location Fuel Number of Generating Units
Capacity In MW (1)
Coal-fired plants
Columbia Portage, WI Coal 311 
(2)
ERGS Oak Creek, WI Coal 1,059 
(3) (4)
OCPP Oak Creek, WI Coal 1,076 
Weston Rothschild, WI Coal 719 
(2)
Total coal-fired plants 10  3,165 
Natural gas-fired plants
Concord Watertown, WI Natural Gas/Oil 362 
De Pere Energy Center De Pere, WI Natural Gas/Oil 166 
Fox Energy Center Wrightstown, WI Natural Gas 574 
Germantown Germantown, WI Natural Gas/Oil 268 
F. D. Kuester Negaunee, MI Natural Gas 128 
A. J. Mihm Baraga, MI Natural Gas 55 
Paris Union Grove, WI Natural Gas/Oil 364 
PWGS Port Washington, WI Natural Gas 1,228 
(4)
Pulliam Green Bay, WI Natural Gas/Oil 81 
VAPP Milwaukee, WI Natural Gas 268 
West Marinette Marinette, WI Natural Gas/Oil 149 
Weston Rothschild, WI Natural Gas/Oil 115 
Total natural gas-fired plants 38  3,758 
Renewables
Hydro plants (30 in number) WI and MI Hydro 81  100 
(5) (6)
Rothschild Biomass Plant Rothschild, WI Biomass 45 
(7)
Two Creeks WI Solar 48  100 
(2)
Wind sites (5 in number) WI and IA Wind 350  498 
(2)
Total renewables 480  743 
Total system 528  7,666 

(1)    Capacity for our electric generation facilities, other than wind and solar generating facilities, is based on rated capacity, which is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. Values are primarily based on the net dependable expected capacity ratings for summer 2021 established by tests and may change slightly from year to year. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand. Capacity for wind generating facilities is based on nameplate capacity, which is the amount of energy a turbine should produce at optimal wind speeds. Capacity for solar generating facilities is based on nameplate capacity, which is the maximum output that a generator should produce at continuous full power.

(2)    These facilities are jointly owned by WPS and various other utilities. The capacity indicated for each of these units is equal to WPS's portion of total plant capacity based on its percent of ownership.

Wisconsin Power and Light Company, an unaffiliated utility, operates the Columbia units. WPS holds a 27.5% ownership interest in Columbia.
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WPS operates the Weston 4 facility and holds a 70.0% ownership interest in this facility. Dairyland Power Cooperative, an unaffiliated energy cooperative, holds the remaining 30.0% interest.

Two Creeks is jointly owned by WPS and an unaffiliated utility. WPS holds a 66.7% ownership interest in this facility.

WPS, along with two other unaffiliated utilities, owns Forward Wind Energy Center. WPS holds a 44.6% ownership interest in this facility and the unaffiliated utilities own the remaining 55.4%. See Note 2, Acquisitions, for more information on the Forward Wind Energy Center acquisition.

(3)    This facility is jointly owned by We Power and two other unaffiliated entities. Our share of capacity is equal to We Power's ownership interest of 83.34%.

(4)    These facilities are part of the Company's non-utility energy infrastructure segment. See B. Non-Utility Energy Infrastructure Segment below.

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

(6)    WRPC owns and operates the Castle Rock and Petenwell units. WPS holds a 50.0% ownership interest in WRPC and is entitled to 50.0% of the total capacity at Castle Rock and Petenwell. WPS's share of capacity for Castle Rock and Petenwell is 7.0 MW and 10.3 MW, respectively.

(7)    WE has a biomass power plant that uses wood waste and wood shavings to produce electric power as well as steam to support the paper mill's operations. Fuel for the power plant is supplied by both the paper mill and through contracts with biomass suppliers. The plant also has the ability to burn natural gas if wood waste and wood shavings are not available.

As of December 31, 2020, we operated approximately 36,100 miles of overhead distribution lines and approximately 34,900 miles of underground distribution cable, as well as approximately 450 electric distribution substations and approximately 507,900 line transformers.

Natural Gas Facilities

At December 31, 2020, our natural gas properties were located in Illinois, Wisconsin, Minnesota, and Michigan, and consisted of the following:

Approximately 50,300 miles of natural gas distribution mains,
Approximately 1,100 miles of natural gas transmission mains,
Approximately 2.3 million natural gas lateral services,
Approximately 500 natural gas distribution and transmission gate stations,
Approximately 68.2 Bcf of working gas capacities in underground natural gas storage fields:
Bluewater, 26.5 Bcf of fields located in southeastern Michigan,
Manlove, a 38.8 Bcf field located in central Illinois,
Partello, a 2.9 Bcf field located in southern Michigan,
A 2.0 Bcf LNG plant located in central Illinois,
A peak-shaving facility that can store the equivalent of approximately 80 MDth in liquefied petroleum gas located in Illinois,
Peak propane air systems providing approximately 2,960 Dth per day, and
LNG storage plants with a total send-out capability of 73,600 Dth per day.

Our natural gas distribution and gas storage systems included distribution mains and transmission mains connected to the pipeline transmission systems of Alliance Pipeline, ANR Pipeline Company, Centra Pipelines, Consumers Energy, Enbridge Gas, Great Lakes Transmission Company, Guardian Pipeline L.L.C., Kinder Morgan Illinois Pipeline, Michigan Consolidated Gas Company, Midwestern Gas Pipeline Company, Natural Gas Pipeline Company of America, Nicor Gas, Northern Border Pipeline Company, Northern Natural Gas Company, Panhandle Gas Transmission, Trunkline Gas Pipeline, Vector Pipeline Company, and Viking Gas Transmission. Our LNG storage plants convert and store, in liquefied form, natural gas received during periods of low consumption.

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

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Steam Facilities

As of December 31, 2020, the steam system supplied by the VAPP consisted of approximately 40 miles of both high pressure and low pressure steam piping, approximately four miles of walkable tunnels, and other pressure regulating equipment.

General

Substantially all of PGL's and NSG's properties are subject to the lien of the respective company's mortgage indenture for the benefit of bondholders.

B. NON-UTILITY ENERGY INFRASTRUCTURE SEGMENT

The non-utility energy infrastructure segment includes We Power, Bluewater, and WECI. We Power and Bluewater are considered non-utility energy infrastructure operations, however, their facilities are shown in the regulated section. We Power owns and leases generating facilities to WE. We Power's share of the ERGS units and both PWGS units are being leased to WE under long-term leases. Bluewater provides natural gas storage and hub services primarily to WE, WPS, and WG, and also provides these same services to several unaffiliated companies. WECI has ownership interests in five wind generating facilities.

The following table summarizes information on WECI's wind generating facilities as of December 31, 2020:
Name Location Number of Generating Units
Nameplate Capacity In MW (1)
Wind generating facilities
Upstream Antelope County, Nebraska 81  202.5 
(2)
Bishop Hill III Henry County, Illinois 53  132.1 
(3)
Coyote Ridge Brookings County, South Dakota 39  96.7 
(4)
Blooming Grove McLean County, Illinois 94  250.0 
(5)
Tatanka Ridge Deuel County, South Dakota 56  155.0 
(6)
Total wind generating facilities 323  836.3 

(1)    Nameplate capacity is the amount of energy a turbine should produce at optimal wind speeds.

(2)    In January 2019, WECI completed the acquisition of an 80% ownership interest in Upstream. In February 2020, WECI agreed to acquire an additional 10% ownership interest in this wind park. See Note 2, Acquisitions, for more information.

(3)    In August 2018, WECI completed the acquisition of an 80% ownership interest in Bishop Hill III. In December 2018, WECI acquired an additional 10% ownership interest in this wind park. See Note 2, Acquisitions, for more information.

(4)    In December 2018, WECI completed the acquisition of an 80% ownership interest in Coyote Ridge. See Note 2, Acquisitions, for more information.

(5)    In December 2020, WECI completed the acquisition of a 90% ownership interest in Blooming Grove. See Note 2, Acquisitions, for more information.

(6)    In December 2020, WECI completed the acquisition of an 85% ownership interest in Tatanka Ridge, which achieved commercial operation on January 5, 2021. See Note 2, Acquisitions, for more information.

In August 2019, WECI signed an agreement to acquire an 80% ownership interest in Thunderhead, a 300 MW wind generating facility under construction in Antelope and Wheeler counties in Nebraska. In February 2020, WECI agreed to acquire an additional 10% ownership interest in this wind park. See Note 2, Acquisitions, for more information.

ITEM 3. LEGAL PROCEEDINGS

The following should be read in conjunction with Note 24, Commitments and Contingencies, and Note 26, Regulatory Environment, in this report for additional information on material legal proceedings and matters related to us and our subsidiaries.

In addition to those legal proceedings discussed in Note 24, Commitments and Contingencies, Note 26, Regulatory Environment, and below, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the
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results of these additional legal proceedings cannot be predicted with certainty, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material effect on our financial statements.

Environmental Matters

Manlove Field Matter

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

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

In the complaint, as is customary in these types of actions, the AG cited to the statutory penalties allowed by law. Ultimately, the pursuit of any civil penalties is at the AG’s discretion. In the event the AG pursues penalties in connection with a final order, we believe that PGL's high level of cooperation and quick action to remedy the situation and to work with the potentially impacted homeowners would be taken into account. At this time, we believe that civil penalties, if any, will not have a material impact on our financial statements.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS

The names, ages, and positions of our executive officers are listed below along with their business experience during the past five years. All officers are appointed until they resign, die, or are removed pursuant to our Bylaws. There are no family relationships among these officers, nor is there any agreement or understanding between any officer and any other person pursuant to which the officer was selected.

Gale E. Klappa. Age 70.
WEC Energy Group — Executive Chairman since February 2019. Chairman of the Board and Chief Executive Officer from October 2017 to February 2019, and from May 2004 to May 2016. Non-Executive Chairman of the Board from May 2016 to October 2017. President from April 2003 to August 2013. Director since December 2003.
WE — Director since January 2018, and from December 2003 to May 2016. Chairman of the Board from January 2018 to February 2019, and from May 2004 to May 2016. Chief Executive Officer from January 2018 to February 2019, and from August 2003 to May 2016. President from April 2003 to June 2015.

J. Kevin Fletcher. Age 62.
WEC Energy Group — Director and Chief Executive Officer since February 2019. President since October 2018.
WE — Chairman of the Board and Chief Executive Officer since February 2019. Director since June 2015. President from May 2016 to November 2018. Executive Vice President - Customer Service and Operations from June 2015 to April 2016.

Robert M. Garvin.   Age 54.
WEC Energy Group — Executive Vice President - External Affairs since June 2015.
WE — Executive Vice President - External Affairs since June 2015.

William J. Guc.   Age 51.
WEC Energy Group — Controller since October 2015. Vice President since June 2015.
WE — Vice President and Controller since October 2015.

Margaret C. Kelsey. Age 56.
WEC Energy Group — Executive Vice President, Corporate Secretary and General Counsel since January 2018. Executive Vice President from September 2017 to January 2018.
WE — Executive Vice President, Corporate Secretary and General Counsel since January 2018. Director since January 2018.
Modine Manufacturing Company – General Counsel, Corporate Secretary, and Vice President - Legal from April 2008 to August 2017. Vice President - Corporate Communications from April 2014 to August 2017. Modine Manufacturing Company is a manufacturer of thermal management systems and components.

Daniel P. Krueger.   Age 55.
WEC Energy Group — Executive Vice President - WEC Infrastructure since January 2019. Executive Vice President from November 2018 to January 2019.
WE — Senior Vice President - Wholesale Energy and Fuels from June 2015 to November 2018.

Scott J. Lauber.   Age 55.
WEC Energy Group — Senior Executive Vice President and Chief Operating Officer since June 2020. Senior Executive Vice President and Chief Financial Officer from October 2019 to June 2020. Senior Executive Vice President, Chief Financial Officer and Treasurer from February 2019 to October 2019. Executive Vice President, Chief Financial Officer and Treasurer from October 2018 to February 2019. Executive Vice President and Chief Financial Officer from April 2016 to October 2018. Vice President and Treasurer from February 2013 to March 2016.
WE — Executive Vice President since June 2020. Executive Vice President and Chief Financial Officer from October 2019 to June 2020, and from April 2016 to October 2018. Executive Vice President, Chief Financial Officer and Treasurer from October 2018 to October 2019. Vice President and Treasurer from February 2013 to March 2016. Director since April 2016.

Xia Liu.   Age 51.
WEC Energy Group — Executive Vice President and Chief Financial Officer since June 2020.
WE — Executive Vice President and Chief Financial Officer since June 2020. Director since June 2020.
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CenterPoint Energy, Inc. — Senior Advisor from April 2020 to May 2020. Executive Vice President and Chief Financial Officer from April 2019 to April 2020. CenterPoint Energy, Inc. is a public utility holding company whose operating subsidiaries provide electric and natural gas service to customers in parts of the South and Midwest.
Georgia Power Company — Executive Vice President, Chief Financial Officer and Treasurer from October 2017 to April 2019. Georgia Power Company is a utility subsidiary of The Southern Company that provides electric service to customers throughout Georgia.
Gulf Power Company — Vice President, Chief Financial Officer and Treasurer from July 2015 to October 2017. Gulf Power Company, previously a utility subsidiary of The Southern Company, serves customers in northwest Florida.

Charles R. Matthews.   Age 64.
PELLC — President since June 2015.
PGL — Director, President, and Chief Executive Officer since June 2015.
NSG — Director, President, and Chief Executive Officer since June 2015.

Tom Metcalfe.   Age 53.
WE — President since November 2018. Executive Vice President - Generation from April 2016 to November 2018. Senior Vice President - Power Generation from January 2014 to March 2016. Director since January 2018.

Anthony L. Reese.   Age 39.
WEC Energy Group — Vice President and Treasurer since October 2019.
WE — Vice President and Treasurer since October 2019.
Controller - Illinois from September 2015 to September 2019.

Mary Beth Straka.   Age 56.
WEC Energy Group — Senior Vice President - Corporate Communications and Investor Relations since June 2015.

Certain executive officers also hold officer and/or director positions at WEC Energy Group's other significant subsidiaries.

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PART II

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

Number of Common Shareholders

As of January 31, 2021, based upon the number of WEC Energy Group shareholder accounts (including accounts in our stock purchase and dividend reinvestment plan), we had approximately 42,000 registered shareholders.

Common Stock Listing and Trading

Our common stock is listed on the New York Stock Exchange under the ticker symbol "WEC."

Common Stock Dividends of WEC Energy Group

We review our dividend policy on a regular basis. Subject to any regulatory restrictions or other limitations on the payment of dividends, future dividends will be at the discretion of the Board of Directors and will depend upon, among other factors, earnings, financial condition, and other requirements. For more information on our dividends, including restrictions on the ability of our subsidiaries to pay us dividends, see Note 11, Common Equity.

ITEM 6. SELECTED FINANCIAL DATA

WEC ENERGY GROUP, INC.
COMPARATIVE FINANCIAL DATA AND OTHER STATISTICS
As of or for Year Ended December 31
(in millions, except per share information) 2020 2019 2018
2017 (1)
2016
Operating revenues $ 7,241.7  $ 7,523.1  $ 7,679.5  $ 7,648.5  $ 7,472.3 
Net income attributed to common shareholders 1,199.9  1,134.0  1,059.3  1,203.7  939.0 
Total assets 37,028.1  34,951.8  33,475.8  31,590.5  30,123.2 
Preferred stock of subsidiary 30.4  30.4  30.4  30.4  30.4 
Long-term debt (excluding current portion) 11,728.1  11,211.0  9,994.0  8,746.6  9,158.2 
Weighted average common shares outstanding
Basic 315.4  315.4  315.5  315.6  315.6 
Diluted 316.5  316.7  316.9  317.2  316.9 
Earnings per share
Basic $ 3.80  $ 3.60  $ 3.36  $ 3.81  $ 2.98 
Diluted $ 3.79  $ 3.58  $ 3.34  $ 3.79  $ 2.96 
Dividends per share of common stock $ 2.53  $ 2.36  $ 2.21  $ 2.08  $ 1.98 

(1)    Includes a $206.7 million increase in net income attributed to common shareholders related to a re-measurement of our deferred taxes as a result of the Tax Legislation.

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ITEM 7. 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 FERC and certain state regulatory commissions), and non-utility energy infrastructure operations through We Power (which owns generation assets in Wisconsin), Bluewater (which owns underground natural gas storage facilities in Michigan), and WEC Infrastructure LLC (WECI), which holds ownership interests in several wind generating facilities.

Corporate Strategy

Our goal is to continue to build and sustain long-term value for our shareholders and customers by focusing on the fundamentals of our business: environmental stewardship; reliability; operating efficiency; financial discipline; exceptional customer care; and safety. Our 2021-2025 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 commodity prices, 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 the construction of zero-carbon-emitting renewable generation 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 2019, we met and surpassed our original goal to reduce CO2 emissions by 40% below 2005 levels. In July 2020, we announced new goals to reduce CO2 emissions from our electric generation by 70% below 2005 levels by 2030 and to be net carbon neutral by 2050. We added a near-term goal in November 2020 to reduce CO2 emissions by 55% below 2005 levels by 2025.

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. As part of our ESG Progress Plan, we expect to retire approximately 1,800 MW of additional fossil-fueled generation by 2025.

In addition to retiring these older, fossil-fueled plants, we expect to invest approximately $2 billion from 2021-2025 in low-cost renewable energy in Wisconsin. Our plan is to replace a portion of the retired capacity by building and owning a combination of clean, natural gas-fired generation and zero-carbon-emitting renewable generation facilities that are anticipated to include the following new investments:

800 MW of utility-scale solar;
600 MW of battery storage;
100 MW of wind;
100 MW of reciprocating internal combustion engine (RICE) natural gas-fueled generation; and
the planned purchase of 200 MW of capacity in the West Riverside Energy Center – a new, combined-cycle natural gas plant recently completed by Alliant Energy in Wisconsin.

These new investments discussed above are in addition to the renewable projects currently underway.
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We have received approval to invest in 300 MW of utility-scale solar within our Wisconsin segment. Wisconsin Public Service Corporation (WPS) has partnered with an unaffiliated utility to construct two solar projects in Wisconsin: Two Creeks Solar Park, now in service, and Badger Hollow Solar Park I, targeted for completion in the second quarter of 2021. WPS owns 100 MW of Two Creeks and will own 100 MW of Badger Hollow I for a total of 200 MW. Wisconsin Electric Power Company (WE) has partnered with an unaffiliated utility to construct Badger Hollow Solar Park II that is expected to enter commercial operation in December 2022. Once constructed, WE will own 100 MW of this project.

In December 2018, WE received approval from the Public Service Commission of Wisconsin (PSCW) for two renewable energy pilot programs. The Solar Now pilot is expected to add 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 13 Solar Now projects and currently has another five under construction, together totaling more than 15 MW. The second program, the Dedicated Renewable Energy Resource pilot, would allow large commercial and industrial customers to access renewable resources that WE would operate, adding up to 150 MW of renewables to WE's portfolio, and helping these larger customers meet their sustainability and renewable energy goals.

We also have a goal to decrease the rate of methane emissions from the natural gas distribution lines in our networks by 30% per mile by the year 2030 from a 2011 baseline. We were over halfway toward meeting that goal at the end of 2019.

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 and distribution networks to further improve reliability. Our investments, coupled with our commitment to operating efficiency and customer care, resulted in We Energies being recognized in 2020 by PA Consulting Group, an independent consulting firm, for superior reliability of its electric delivery network. This was the 10th consecutive year that We Energies has been named the most reliable utility in the Midwest.

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

WE is constructing approximately 46 miles of natural gas transmission main to increase the quantity and reliability of natural gas service in southeastern Wisconsin. This project, called the Lakeshore Lateral Project, is expected to be completed by the end of 2021.

WE and Wisconsin Gas LLC (WG) each plan to construct their own liquefied natural gas (LNG) facility to meet anticipated peak demand. Subject to PSCW approval, commercial operation of the LNG facilities is targeted for the end of 2023.

The Peoples Gas Light and Coke Company continues to work on its Natural Gas System 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.

WPS continues work on its System Modernization and Reliability Project, which involves modernizing parts of its electric distribution system, including burying or upgrading lines. WE, WPS, and WG also continue to upgrade their electric and natural gas distribution systems to enhance reliability.

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

Operating Efficiency

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

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

Financial Discipline

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

We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plants, equipment, and entire business units, that are no longer strategic to operations, are not performing as intended, or have an unacceptable risk profile. See Note 3, Dispositions, for information on the sale of certain WPS Power Development, LLC solar power generation facilities.

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 six wind parks, capable of providing more than 1,000 MW of carbon-free energy in total. These renewable energy assets represent more than $1.6 billion in committed investments and have long-term agreements to serve customers outside our traditional service areas. Production tax credits from these wind investments reduce our cash tax expense. We also project that these investments will generate higher returns than our regulated business. See Note 2, Acquisitions, for additional information on these transactions.

We expect total capital expenditures for our regulated utility and non-utility energy infrastructure businesses to be approximately $15.0 billion from 2021 to 2025. In addition, we currently forecast that our share of ATC's projected capital expenditures over the next five years will be $1.1 billion. Specific projects included in the $16.1 billion ESG Progress Plan are discussed in more detail below under Liquidity and Capital Resources.

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

Across the organization, we monitor the integrity of our networks and conduct comprehensive incident response planning to enhance the safety of our operations.

Under our "Target Zero" mission, we have an ultimate goal of zero incidents, accidents, and injuries. We also set goals around injury-prevention activities that raise awareness and facilitate conversations about employee safety. 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.

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RESULTS OF OPERATIONS
Consolidated Earnings

The following table compares our consolidated results, including favorable or better, "B", and unfavorable or worse, "W", variances:
Year Ended December 31 2020 vs. 2019 2019 vs. 2018
(in millions, except per share data) 2020 2019 2018 B (W) B (W)
Wisconsin $ 690.4  $ 649.9  $ 617.0  $ 40.5  $ 32.9 
Illinois 203.5  170.3  147.1  33.2  23.2 
Other states 39.0  43.2  44.1  (4.2) (0.9)
Electric transmission 112.6  87.4  82.8  25.2  4.6 
Non-utility energy infrastructure 260.8  246.0