WEC ENERGY GROUP, INC. (WEC) FY 2021 MD&A

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 Federal Energy Regulatory Commission and certain state regulatory commissions), and non-utility energy infrastructure operations through W.E. Power LLC (which owns generation assets in Wisconsin), Bluewater Natural Gas Holding LLC (which owns underground natural gas storage facilities in Michigan), and WEC Infrastructure LLC (WECI), which holds ownership interests in several wind generating facilities.

Corporate Strategy

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

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

Creating a Sustainable Future

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

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

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

We already have retired more than 1,800 megawatts (MW) of coal-fired generation since the beginning of 2018, which included the 2019 retirement of the Presque Isle power plant as well as the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater Unit 4 generating units. See Note 6, Regulatory Assets and Liabilities, for more information related to these power plant retirements. Through our ESG Progress Plan, we expect to retire approximately 1,600 MW of additional fossil-fueled generation by 2025, which includes the planned retirements in 2023-2024 of Oak Creek Power Plant Units 5-8 and the jointly-owned Columbia Units 1-2.

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

•1,400 MW of utility-scale solar;

•800 MW of battery storage; and

•100 MW of wind.

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

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

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

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

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

In addition, we previously received approval from the Public Service Commission of Wisconsin (PSCW) 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 now in service in Wisconsin: Two Creeks Solar Park (Two Creeks) and Badger Hollow Solar Park I (Badger Hollow I). WPS owns 100 MW of Two Creeks and 100 MW of Badger Hollow I for a total of 200 MW. Wisconsin Electric Power Company (WE) has partnered with an unaffiliated utility to construct Badger Hollow Solar Park II, which is expected to enter commercial operation in the first quarter of 2023. Once constructed, WE will own 100 MW of this project.

In December 2018, WE received approval from the PSCW for two renewable energy pilot programs. The Solar Now pilot is expected to add a total of 35 MW of solar generation to WE's portfolio, allowing non-profit and governmental entities, as well as commercial and industrial customers, to site utility owned solar arrays on their property. Under this program, WE has energized 21 Solar Now projects and currently has another three under construction, together totaling more than 27 MW. The second program, the Dedicated Renewable Energy Resource pilot, would allow large commercial and industrial customers to access renewable resources that WE would operate, adding up to 150 MW of renewables to WE's portfolio, and helping these larger customers meet their sustainability and renewable energy goals.

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

We also continue to reduce methane emissions by improving our natural gas distribution system. We set a target across our natural gas distribution operations to achieve net-zero methane emissions by the end of 2030. We plan to achieve our net-zero goal through an effort that includes both continuous operational improvements and equipment upgrades, as well as the use of renewable natural gas (RNG) throughout our utility systems. We recently signed our first contract for RNG for our natural gas distribution business, which will be transporting the output of a local dairy farm onto our gas distribution system. The RNG supplied will directly replace higher-emission methane from natural gas that would have entered our pipes. This one contract represents 25 percent of our 2030 goal for methane reduction. We expect to have RNG flowing to our distribution network by the end of 2022.

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

Reliability

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

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

•WE constructed 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, was completed in October 2021.

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

•The Peoples Gas Light and Coke Company continues to work on its Safety Modernization Program, which primarily involves replacing old iron pipes and facilities in Chicago’s natural gas delivery system with modern polyethylene pipes to reinforce the long-term safety and reliability of the system.

•WPS completed its work in late 2021 on its System Modernization and Reliability Project, which involved 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 – Cash Requirements – Significant Capital Projects.

Operating Efficiency

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

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

Financial Discipline

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

We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plants, equipment, and entire business units, that are no longer strategic to operations, are not performing as intended, or have an unacceptable risk profile. See Note 3, Dispositions, for information on the sale of certain WPS Power Development, LLC solar power generation facilities. See Note 2, Acquisitions, for information on our acquisition of Whitewater.

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

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

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Exceptional Customer Care

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

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

Safety

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

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

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

RESULTS OF OPERATIONS

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

Consolidated Earnings

The following table compares our consolidated results for the year ended December 31, 2021 with the year ended December 31, 2020, including favorable or better, "B", and unfavorable or worse, "W", variances:

Earnings increased $100.4 million during 2021, compared with 2020. The significant factors impacting the $100.4 million increase in earnings were:

•A $55.9 million decrease in the net loss attributed to common shareholders at the corporate and other segment, driven by lower interest expense, an increase in earnings from our equity method investments in technology and energy-focused investment funds, and the positive year-over-year impact from charges taken at Wispark during 2020. Higher net gains from investments held in the Integrys rabbi trust also contributed to the lower net loss. The investment gains from the rabbi trust offset higher

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benefit costs related to deferred compensation, which are included in other operation and maintenance expense in our operating segments. See Note 17, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.

•A $19.5 million increase in net income attributed to common shareholders at the Illinois segment, driven by higher natural gas margins due to PGL's continued capital investment in the SMP project under its QIP rider and an increase in late payment charges. Lower benefit costs also contributed to the increase in earnings. These positive impacts were partially offset by higher depreciation expense and an increase in natural gas distribution and maintenance costs during 2021.

•An $18.4 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by an increase in PTCs generated in 2021, primarily due to our Blooming Grove and Tatanka Ridge wind parks that achieved commercial operation in December 2020 and January 2021, respectively. See Note 2, Acquisitions, and Note 16, Income Taxes, for more information. Partially offsetting this increase were operating losses at the Coyote Ridge and Tatanka Ridge wind parks related to congestion on the electricity grid due, in part, to several transmission outages in 2021. Higher interest expense due to WECI Wind Holding I's debt issuance in December 2020 also partially offset the positive impact from the increase in PTCs.

•A $16.1 million increase in net income attributed to common shareholders at the Wisconsin segment, driven by an increase in electric margins due to higher retail sales volumes, including the impact of weather. Also contributing to the increase were lower benefit costs and the positive impact of increased rates from the Wisconsin rate orders approved by the PSCW, which excludes all impacts related to the recognition of unprotected excess deferred tax benefits from the Tax Legislation as they had no impact on earnings. These positive impacts were partially offset by higher depreciation and amortization and the negative year-over-year impact from fuel and purchased power costs.

Non-GAAP Financial Measures

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

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

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance. The following table shows operating income by segment for our utility operations during years ended December 31, 2021 and 2020:

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

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Wisconsin Segment Contribution to Net Income Attributed to Common Shareholders

The Wisconsin segment's contribution to net income attributed to common shareholders for the year ended December 31, 2021 was $706.5 million, representing a $16.1 million, or 2.3%, increase over the prior year. The higher earnings were driven by an increase in electric margins due to higher retail sales volumes, including the impact of weather. Also contributing to the increase were lower benefit costs and the positive impact of increased rates from the Wisconsin rate orders approved by the PSCW, which excludes all impacts related to the recognition of unprotected excess deferred tax benefits from the Tax Legislation as they had no impact on earnings. These positive impacts were partially offset by higher depreciation and amortization and the negative year-over-year impact from fuel and purchased power costs.

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

(1)    Represents transmission expense that our electric utilities are authorized to collect in rates. The PSCW has approved escrow accounting for ATC and MISO network transmission expenses for WE and WPS. As a result, WE and WPS defer as a regulatory asset or liability, the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During 2021 and 2020, $503.6 million and $481.8 million, respectively, of costs were billed to our electric utilities by transmission providers.

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

(3)    Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE. During 2021 and 2020, $113.1 million and $115.1 million, respectively, of costs were billed to or incurred by WE related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

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(4)    See Note 26, Regulatory Environment, for more information about our earnings sharing mechanisms.

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

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

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

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

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

Electric Revenues

Electric revenues increased $264.6 million during 2021, compared with 2020. To the extent that changes in fuel and purchased power costs are passed through to customers, the changes are offset by comparable changes in revenues. See the discussion of electric utility margins below for more information related to recovery of fuel and purchased power costs and the remaining drivers of the changes in electric revenues.

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Electric Utility Margins

Electric utility margins at the Wisconsin segment increased $14.5 million during 2021, compared with 2020. Margins did not change significantly from the PSCW-approved Wisconsin rate orders as the positive impact of increased rates was more than offset by a $27.6 million negative impact related to unprotected excess deferred taxes, which we agreed to return to customers over two years and is offset in income taxes. See Note 26, Regulatory Environment, for more information.

The significant factors impacting the higher electric utility margins were:

•A $50.0 million increase in margins related to higher retail sales volumes, including the impact of weather. Commercial and industrial retail sales volumes improved during 2021, compared with 2020, primarily due to the continued economic recovery in Wisconsin from the COVID-19 pandemic.

•A $19.4 million increase in margins from other revenues, primarily related to higher revenues from third party use of our assets as well as higher late payment charges during 2021. Our Wisconsin utilities resumed charging late payment charges in late August 2020 after they were suspended by the PSCW beginning March 24, 2020, as a result of the COVID-19 pandemic. See Note 26, Regulatory Environment, for more information.

•Securitization revenues of $7.7 million received during 2021 related to an environmental control charge from WE's retail electric distribution customers. We began assessing this charge in June 2021, subsequent to the issuance of the ETBs by WEPCo Environmental Trust in May 2021, in accordance with a November 2020 PSCW financing order. See Note 14, Long-Term Debt, and Note 23, Variable Interest Entities, for more information. These revenues are offset in depreciation and amortization as well as interest expense.

•A $4.1 million increase in margins related to the iron ore mine located in the Upper Peninsula of Michigan. The mine temporarily ceased operations for the second quarter of 2020 as a result of the COVID-19 pandemic.

These increases in margins were partially offset by:

•A $43.3 million year-over-year negative impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, the margins of our electric utilities are impacted by under- or over-collections of certain fuel and purchased power costs that are within a 2% price variance from the costs included in rates, and the remaining variance beyond the 2% price variance is generally deferred for future recovery or refund to customers. In 2021, WPS was unable to defer its portion of the under-collected fuel and purchased power costs due to earning an ROE in excess of the PSCW authorized amount.

•Lower margins of $23.9 million driven by a decrease in wholesale customers related to the expiration of certain wholesale contracts.

Natural Gas Revenues

Natural gas revenues increased $298.9 million during 2021, compared with 2020. Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues. The average per-unit cost of natural gas increased 53.6% during 2021, compared with 2020. The remaining drivers of changes in natural gas revenues are described in the discussion of natural gas utility margins below.

Natural Gas Utility Margins

Natural gas utility margins at the Wisconsin segment decreased $12.4 million during 2021, compared with 2020. The most significant factor impacting the lower natural gas utility margins was a $15.4 million decrease from lower retail sales volumes, including the impact of weather. This decrease in margins was partially offset by a $3.1 million increase from other revenues, primarily related to higher late payment charges during 2021, compared with 2020, as discussed above under Electric Utility Margins.

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

Other operating expenses at the Wisconsin segment increased $25.6 million during 2021, compared with 2020. The significant factors impacting the increase in other operating expenses were:

•A $52.4 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan as well as an increase related to the We Power leases. In addition, a portion of the increase is related to securitization amortization, which is offset in revenues.

•A $26.2 million increase in electric and natural gas distribution expenses, primarily driven by significant storms in 2021.

•A $15.3 million increase in expenses related to charitable projects supporting our customers and the communities within our service territories.

•An $11.2 million increase in customer service expenses, primarily related to additional costs from an information technology project created to improve the billing, call center, and credit collection functions, as well as higher call volumes and metering costs.

These increases in other operating expenses were partially offset by:

•A $21.9 million net decrease in operating expense related to our power plants, primarily driven by reduced costs at the OCPP.

•A $19.6 million decrease in benefit costs, primarily due to lower stock-based compensation.

•A $15.8 million decrease in expense related to the earnings sharing mechanisms in place at our Wisconsin utilities. See Note 26, Regulatory Environment, for more information.

•A $12.5 million decrease in costs incurred related to facility damage to our PSB resulting from a significant rain event in May 2020. See Note 7, Property, Plant, and Equipment, for more information on the significant rain event.

•A $6.9 million decrease in transmission expense driven by a decrease in electric wholesale customers related to the expiration of certain wholesale contracts.

Other Income, Net

Other income, net at the Wisconsin segment increased $21.1 million during 2021, compared with 2020, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 20, Employee Benefits, for more information on our benefit costs.

Interest Expense

Interest expense at the Wisconsin segment decreased $5.7 million during 2021, compared with 2020, driven by lower interest expense on finance lease liabilities, primarily related to the We Power leases, as finance lease liabilities decrease each year as payments are made. Lower interest expense on short-term debt was also a contributor as commercial paper rates were lower in 2021 compared to 2020. These decreases in interest expense were partially offset by interest expense on the ETBs issued by WEPCo Environmental Trust in May 2021, which is offset in revenues.

Income Tax Expense

Income tax expense at the Wisconsin segment decreased $12.8 million during 2021, compared with 2020. The decrease was primarily due to an approximate $27.6 million positive impact related to the 2021 amortization of the unprotected excess deferred tax benefits from the Tax Legislation in connection with the Wisconsin rate orders approved by the PSCW, effective January 1, 2020. The impact due to the benefit from the amortization of the unprotected excess deferred tax benefits from the Tax Legislation did not impact earnings as there was an offsetting negative impact in operating income. Partially offsetting this decrease in income tax

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expense was a decrease in PTCs and an increase in pretax income. See Note 16, Income Taxes, and Note 26, Regulatory Environment, for more information.

Illinois Segment Contribution to Net Income Attributed to Common Shareholders

The Illinois segment's contribution to net income attributed to common shareholders for the year ended December 31, 2021 was $223.0 million, representing a $19.5 million, or 9.6%, increase over the prior year. The increase was driven by higher natural gas margins due to PGL's continued capital investment in the SMP project under its QIP rider and an increase in late payment charges. Lower benefit costs also contributed to the increase in earnings. These positive impacts were partially offset by higher depreciation expense and an increase in natural gas distribution and maintenance costs during 2021.

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

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

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

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

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

Natural Gas Revenues

Natural gas revenues increased $350.9 million during 2021, compared with 2020. Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues. The average per-unit cost of natural gas sold increased 95.5% during 2021, compared with 2020. The remaining drivers of changes in natural gas revenues are described in the discussion of margins below.

Natural Gas Utility Margins

Natural gas utility margins at the Illinois segment, net of the $10.7 million impact of the riders referenced in the table above, increased $42.7 million during 2021, compared with 2020. The increase in margins was primarily driven by:

•A $25.5 million increase in revenues at PGL due to continued capital investment in the SMP project. PGL recovers the costs related to the SMP through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023.

•A $7.5 million increase in late payment charges driven by the reinstatement of late payment charges during 2021 that were suspended by the ICC in 2020 due to the COVID-19 pandemic.

•A $3.6 million increase in the invested capital tax adjustment rider related to higher plant placed in service during 2021 compared with 2020, which did not impact net income as it was offset in property and revenue taxes. The invested capital tax adjustment rider is a mechanism that allows PGL and NSG to recover (or refund) the difference between the cost of invested capital tax incurred and the amount collected through base rates.

•A $3.1 million increase related to the collection of fixed charges driven by the expiration of the moratorium on disconnections during 2020 due to a regulatory order from the ICC in response to the COVID-19 pandemic.

•A $1.9 million increase related to the impact of the NSG rate order approved by the ICC, effective September 15, 2021.

See Note 26, Regulatory Environment, for more information.

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

Other operating expenses at the Illinois segment increased $11.9 million, net of the impact of the riders referenced in the table above, during 2021, compared with 2020. The significant factors impacting the increase in operating expenses were:

•A $21.4 million increase in depreciation expense, primarily driven by PGL's continued capital investment in the SMP project.

•A $16.4 million increase in natural gas distribution and maintenance costs, primarily related to maintaining the natural gas infrastructure, including costs associated with maintenance at our gas storage field.

These increases in operating expenses were partially offset by:

•A $23.1 million decrease in benefit costs, primarily due to lower costs related to pension, stock-based compensation, and severance.

•A $2.8 million decrease in costs associated with the investigation and remediation of the natural gas leak at the Manlove Gas Storage Field. See Part I, Item 3. Legal Proceedings, for more information.

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Other Income, Net

Other income, net at the Illinois segment increased $5.0 million during 2021, compared with 2020, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 20, Employee Benefits, for more information on our benefit costs.

Interest Expense

Interest expense at the Illinois segment increased $3.1 million during 2021, compared with 2020, driven by higher long-term debt balances related to incremental borrowings in both 2021 and 2020, primarily related to additional capital investment.

Income Tax Expense

Income tax expense at the Illinois segment increased $13.2 million during 2021, compared with 2020, driven by an increase in pretax income and a $5.0 million decrease in unrecognized tax benefits compared with 2020. See Note 16, Income Taxes, for more information.

Other States Segment Contribution to Net Income Attributed to Common Shareholders

The other states segment's contribution to net income attributed to common shareholders for the year ended December 31, 2021 was $35.8 million, representing a $3.2 million, or 8.2%, decrease over the prior year. The decrease was driven by higher operating expenses due to depreciation and amortization, and higher operation and maintenance expense, primarily related to the February 2021 cold weather event. These decreases in net income were partially offset by lower interest expense in 2021 due to the deferral of interest expense related to capital investments made by MGU since its last rate case. See Note 26, Regulatory Environment, for more information.

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

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

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

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

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

Natural Gas Revenues

Natural gas revenues increased $134.9 million during 2021, compared with 2020. Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues. The average per-unit cost of natural gas sold increased 83.8% during 2021, compared with 2020. The remaining drivers of changes in natural gas revenues are described in the discussion of margins below.

Natural Gas Utility Margins

Natural gas utility margins increased $0.4 million during 2021, compared with 2020. This was primarily driven by a $3.7 million increase related to MERC CIP revenue, which was offset in operation and maintenance expense. Rebates and programs are available to residential and commercial customers of MERC through the CIP, which is funded by rate payers using the Conservation Cost Recovery Charge and the Conservation Cost Recovery Adjustment funds that are collected on their monthly billing statements. This increase was partially offset by a $1.9 million decrease related to lower sales volumes and a $1.0 million decrease associated with lower revenues related to MERC's GUIC rider. The GUIC rider allows MERC to recover previously approved GUIC incurred to replace or modify natural gas facilities to the extent the work is required by state, federal, or other government agencies and exceeds the costs included in base rates.

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

Other operating expenses at the other states segment increased $9.6 million during 2021, compared with 2020. The significant factors impacting the increase in operating expenses were:

•A $4.6 million increase in depreciation and amortization related to continued capital investment.

•A $3.7 million increase in operation and maintenance expense due to MERC's CIP program, which has an offsetting increase in margins.

•A $3.0 million increase in operation and maintenance expense related to the February 2021 cold weather event.

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These increases in operating expenses were partially offset by:

•A $1.9 million decrease in operation and maintenance expense related to effective cost control.

•A $1.8 million decrease in operation and maintenance expense due to MERC's GUIC rider, primarily related to having fewer expenditures in 2021 compared to 2020, which is mostly offset in margins.

Interest Expense

Interest expense at the other states segment decreased $4.0 million during 2021, compared with 2020, driven by the deferral of interest expense related to capital investments made by MGU since its last rate case, as approved by the MPSC. The decrease was partially offset by long term debt issuances in 2020 and 2021, primarily related to continued capital investment. See Note 26, Regulatory Environment, for more information on the MPSC order that allowed MGU to defer interest expense related to certain capital expenditures.

Income Tax Expense

Income tax expense at the other states segment decreased $1.6 million during 2021, compared with 2020, driven by a decrease in pretax income.

Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders

Equity in Earnings of Transmission Affiliates

Equity in earnings of transmission affiliates decreased $17.7 million during 2021, compared with 2020, driven by:

•A $14.6 million decrease in equity earnings related to the impact of the FERC order issued in May 2020 addressing complaints related to ATC's ROE. The order resulted in an increase in the base ROE that ATC is allowed to collect, retroactive to November 2013, which was recorded in 2020. For further discussion of this FERC order, see Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – American Transmission Company Allowed Return on Equity Complaints.

•A $12.2 million decrease in equity earnings related to a goodwill impairment recorded by ATC Holdco, which was formed to invest in transmission-related projects outside of ATC's traditional footprint.

Continued capital investment by ATC partially offset the negative year-over-year impact on equity earnings related to the 2020 FERC order and the goodwill impairment recorded at ATC Holdco.

Income Tax Expense

Income tax expense at the electric transmission segment decreased $11.4 million during 2021, compared with 2020, driven by a $6.6 million positive impact of uncertain tax positions in 2021 that were recorded in 2020 and a $4.7 million positive impact related to a decrease in pretax income.

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

Operating Income

Operating income at the non-utility energy infrastructure segment decreased $16.0 million during 2021, compared with 2020. The decrease was primarily driven by an aggregate of $21.9 million of higher operating losses at our Coyote Ridge wind park and 2021 operating losses at our Tatanka Ridge wind park related to congestion on the electricity grid due, in part, to several transmission outages in 2021. This decrease was partially offset by higher operating income of $6.6 million at our Blooming Grove wind park that achieved commercial operation in December 2020.

Interest Expense

Interest expense at the non-utility energy infrastructure segment increased $10.2 million during 2021, compared with 2020, primarily due to WECI Wind Holding I's debt issuance in December 2020.

Income Tax Expense

Income tax expense at the non-utility energy infrastructure segment decreased $41.6 million during 2021, compared with 2020, primarily due to a $34.0 million increase in PTCs generated in 2021, driven by our Blooming Grove and Tatanka Ridge wind parks that achieved commercial operation in December 2020 and January 2021, respectively, and lower pretax earnings.

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

Operating Loss

The operating loss at the corporate and other segment decreased $21.9 million during 2021, compared with 2020, driven by:

•A $17.2 million positive impact from the change in operating income at Wispark. The change was driven by reductions in the carrying value of certain real estate-related assets during 2020, which did not reoccur in 2021, resulting in a positive year-over-year variance.

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•A $4.7 million positive impact due to a pre-tax loss recorded in 2020 on the sale of a portfolio of residential solar facilities owned by PDL. The sale resulted in an after-tax gain; however, the gain related to the recognition of deferred ITCs, which were included as a reduction of income tax expense on our income statement. See Note 3, Dispositions, for more information on the sale.

Other Income, Net

Other income, net at the corporate and other segment increased $27.3 million during 2021, compared with 2020, driven by a $17.6 million increase in earnings from our equity method investments in technology and energy-focused investment funds. Higher net gains from the investments held in the Integrys rabbi trust of $5.9 million also contributed to the increase. The gains from the investments held in the rabbi trust partially offset higher benefits costs related to deferred compensation, which are included in other operation and maintenance expense in our operating segments. See Note 17, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.

Interest Expense

Interest expense at the corporate and other segment decreased $31.2 million during 2021, compared with 2020, as we opportunistically refinanced long-term debt obligations in both 2021 and 2020 in order to take advantage of lower interest rates. Lower interest expense on short-term debt was also a contributor as commercial paper rates were lower in 2021 compared to 2020.

Loss on Debt Extinguishment

The loss on debt extinguishment decreased $2.1 million, driven by a decrease in make whole payments associated with refinancing debt obligations prior to maturity in 2021, compared to 2020.

Income Tax Benefit

The income tax benefit at the corporate and other segment decreased $26.6 million during 2021, compared with 2020, driven by a lower pretax loss. Also contributing to the decrease in the income tax benefit were a $9.1 million decrease in excess tax benefits recognized on stock option exercises and a $6.5 million negative impact from the recognition in 2020 of previously deferred ITCs related to the sale of PDL's residential solar facilities. See Note 3, Dispositions, for more information on the sale of residential solar facilities. These decreases in the income tax benefit were partially offset by an $11.8 million change in unrecognized tax benefits during 2021, compared with 2020. See Note 16, Income Taxes, for more information.

LIQUIDITY AND CAPITAL RESOURCES

Overview

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

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

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Cash Flows

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

Operating Activities

Net cash provided by operating activities decreased $163.3 million during 2021, compared with 2020. The increase in cash earnings was more than offset by working capital requirements, primarily related to higher natural gas prices, as discussed in more detail below.

The significant factors impacting the decrease in net cash provided by operating activities include:

•A $240.0 million decrease in cash related to higher payments for fuel and purchased power at our plants during 2021, compared with 2020. We incurred higher natural gas costs throughout 2021, compared with 2020, as a result of an increase in the price of natural gas. Increased coal costs also drove higher payments for fuel used at our plants.

•A $221.7 million decrease in cash from higher payments for operating and maintenance expenses. During 2021, our payments were higher for storm restoration, transmission, electric and natural gas distribution and maintenance, charitable projects, and customer service.

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

•A $208.8 million increase in cash due to realized gains on derivative instruments as well as higher collateral received from counterparties during 2021, both driven by higher natural gas prices.

•A $46.9 million increase in cash related to a decrease in contributions and payments related to pension and OPEB plans during 2021, compared with 2020.

•A $30.7 million increase in cash related to higher overall collections from customers as a result of an increase in sales volumes during 2021, compared with 2020. This increase was driven by favorable weather and the continued economic recovery in Wisconsin from the COVID-19 pandemic. In addition, we continued to recover natural gas costs from our customers related to the extreme weather conditions that occurred in February 2021 in accordance with various orders from our commissions. See Note 26, Regulatory Environment, for more information on the recovery of these natural gas costs.

Investing Activities

Net cash used in investing activities decreased $495.0 million during 2021, compared with 2020, driven by:

•The acquisition of a 90% ownership interest in Blooming Grove in December 2020 for $364.6 million, which is net of restricted cash acquired of $24.1 million. See Note 2, Acquisitions, for more information.

•The acquisition of an 85% ownership interest in Tatanka Ridge in December 2020 for $239.9 million. See Note 2, Acquisitions, for more information.

•Capital contributions paid to transmission affiliates of $21.2 million during 2020. See Note 21, Investment in Transmission Affiliates, for more information. There were no payments to transmission affiliates during 2021.

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

•The acquisition of a 90% ownership interest in Jayhawk in February 2021 for $119.9 million. See Note 2, Acquisitions, for more information.

•Insurance proceeds received of $23.2 million for property damage during 2020, primarily driven by proceeds received for the PSB claim. See Note 7, Property, Plant, and Equipment, for more information.

•A $14.0 million increase in cash paid for capital expenditures during 2021, compared with 2020, which is discussed in more detail below.

Capital Expenditures

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

The increase in cash paid for capital expenditures at the Wisconsin segment during 2021, compared with 2020, was primarily driven by higher capital expenditures related to upgrades to WE's natural gas distribution system, repairs and restoration of WE's PSB as a result of the significant rain event in May 2020, and construction activity at Crane Creek, Badger Hollow II, and the LNG facilities during 2021. See Note 7, Property, Plant, and Equipment, for more information on the PSB. These increases were partially offset by lower payments for capital expenditures related to Badger Hollow I, Two Creeks, an information technology project created to improve the billing, call center, and credit collection functions, upgrades of WPS's automated meter reading devices, and upgrades to WG's gas distribution system during 2021.

The decrease in cash paid for capital expenditures at the Illinois segment during 2021, compared with 2020, was primarily driven by lower payments for capital expenditures related to facilities projects, upgrades at the Manlove Gas Storage Field, and upgrades to the natural gas distribution system during 2021.

The decrease in cash paid for capital expenditures at the other states segment during 2021, compared with 2020, was primarily driven by a decrease in installations of automated meter reading devices during 2021.

The increase in cash paid for capital expenditures at the non-utility energy infrastructure segment during 2021, compared with 2020, was primarily driven by the construction of Jayhawk, which was acquired in February 2021 and became commercially operational in December 2021. See Note 2, Acquisitions, for more information.

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

Financing Activities

Net cash provided by financing activities decreased $307.1 million during 2021, compared with 2020, driven by:

•A $680.0 million decrease in cash due to a $340.0 million repayment of a 364-day term loan during 2021, compared with its issuance during 2020, to enhance our liquidity position in response to the COVID-19 pandemic.

•A $146.9 million decrease in cash due to lower net borrowings of commercial paper during 2021, compared with 2020.

•A $56.8 million decrease in cash due to higher dividends paid on our common stock during 2021, compared with 2020. In January 2021, our Board of Directors increased our quarterly dividend by $0.045 per share (7.1%) effective with the March 2021 dividend payment.

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•A $28.1 million decrease in cash from fewer stock options exercised during 2021, compared with 2020.

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

•A $506.6 million increase in cash related to lower long-term debt repayments during 2021, compared with 2020.

•A $66.1 million increase in cash due to a decrease in the number and cost of shares of our common stock purchased during 2021, compared with 2020, to satisfy requirements of our stock-based compensation plans.

•The acquisition of an additional 10% ownership interest in Upstream in April 2020 for $31.0 million. See Note 2, Acquisitions, for more information.

Significant Financing Activities

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

Cash Requirements

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

Significant Capital Projects

We have several capital projects that will require significant capital expenditures over the next three years and beyond. All projected capital requirements are subject to periodic review and may vary significantly from estimates, depending on a number of factors. These factors include environmental requirements, regulatory restraints and requirements, changes in tax laws and regulations, acquisition and development opportunities, market volatility, economic trends, supply chain disruptions, the COVID-19 pandemic, inflation, and interest rates. Our estimated capital expenditures and acquisitions for the next three years are reflected below. These amounts include anticipated expenditures for environmental compliance and certain remediation issues. For a discussion of certain environmental matters affecting us, see Note 24, Commitments and Contingencies.

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

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

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

•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 once constructed, WE and WPS will collectively own

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180 MW of solar generation and 99 MW of battery storage of this project. If approved, WE's and WPS's combined share of the cost of this project is estimated to be approximately $385 million, with construction expected to be completed by the end of 2023.

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

•In March 2021, WE and WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire and construct the Darien Solar-Battery Park, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Rock and Walworth counties, Wisconsin and once constructed, WE and WPS will collectively own 225 MW of solar generation and 68 MW of battery storage of this project. If approved, WE's and WPS's combined share of the cost of this project is estimated to be approximately $400 million, with construction expected to be completed by the end of 2023.

•WPS, along with an unaffiliated utility, received PSCW approval to acquire the Red Barn Wind Park, a utility-scale wind-powered electric generating facility. The project will be located in Grant County, Wisconsin and once constructed, WPS will own 82 MW of this project. WPS's share of the cost of this project is estimated to be $150 million, with construction expected to be completed by the end of 2022.

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

•In April 2021, WE and WPS filed an application with the PSCW for approval to construct 128 MW of natural gas-fired generation at WPS's existing Weston power plant site in northern Wisconsin. The new facility will consist of seven reciprocating internal combustion engines. If approved, we estimate the cost of this project to be approximately $170 million, with construction expected to be completed by the end of 2023.

•In November 2021, WE and WPS signed an asset purchase agreement to acquire Whitewater, a commercially operational 236.5 MW dual fueled (natural gas and low sulfur fuel oil) combined cycle electrical generation facility in Whitewater, Wisconsin. In December 2021, WE and WPS filed an application with the PSCW for approval to acquire Whitewater. If approved, the cost of this facility will be $72.7 million, with the transaction expected to close in January 2023. See Note 15, Leases, for more information.

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

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

PGL is continuing work on the SMP, a project under which PGL is replacing approximately 2,000 miles of Chicago's aging natural gas pipeline infrastructure. PGL currently recovers these costs through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023. PGL's projected average annual investment through 2024 is between $280 million and $300 million. See Note 26, Regulatory Environment, for more information on the SMP.

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

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

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

Long-Term Debt

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

(1)    The interest due on our variable rate debt is based on the interest rates that were in effect on December 31, 2021.

Common Stock Dividends

On January 20, 2022, our Board of Directors increased our quarterly dividend to $0.7275 per share effective with the first quarter of 2022 dividend payment, an increase of 7.4%. This equates to an annual dividend of $2.91 per share. In addition, the Board of Directors affirmed our dividend policy that continues to target a dividend payout ratio of 65-70% of earnings.

We have been paying consecutive quarterly dividends dating back to 1942 and expect to continue paying quarterly cash dividends in the future. Any payment of future dividends is subject to approval by our Board of Directors and is dependent upon future earnings, capital requirements, and financial and other business conditions. In addition, our ability as a holding company to pay common stock dividends primarily depends on the availability of funds received from our subsidiaries. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans, or advances. We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future. See Note 11, Common Equity, for more information related to these restrictions and our other common stock matters.

Other Significant Cash Requirements

Our utility and non-utility operations have purchase obligations under various contracts for the procurement of fuel, power, and gas supply, as well as the related storage and transportation. These costs are a significant component of funding our ongoing operations. See Note 24, Commitments and Contingencies, for more information, including our minimum future commitments related to these purchase obligations.

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

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

We make contributions to our pension and OPEB plans based upon various factors affecting us, including our liquidity position and tax law changes. See Note 20, Employee Benefits, for our expected contributions in 2022 and our expected pension and OPEB payments for the next 10 years. We expect the majority of these future pension and OPEB payments to be paid from our outside trusts. See Sources of Cash–Investments in Outside Trusts below for more information.

In addition to the above, our balance sheet at December 31, 2021 included various other liabilities that, due to the nature of the liabilities, the amount and timing of future payments cannot be determined with certainty. These liabilities include AROs, liabilities for the remediation of manufactured gas plant sites, and liabilities related to the accounting treatment for uncertainty in income taxes. For additional information on these liabilities, see Note 9, Asset Retirement Obligations, Note 24, Commitments and Contingencies, and Note 16, Income Taxes, respectively.

Off-Balance Sheet Arrangements

We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit that support construction projects, commodity contracts, and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see Note 13, Short-Term Debt and Lines of Credit, Note 19, Guarantees, and Note 23, Variable Interest Entities.

Sources of Cash

Liquidity

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

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

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

The amount, type, and timing of any financings in 2022, as well as in subsequent years, will be contingent on investment opportunities and our cash requirements and will depend upon prevailing market conditions, regulatory approvals for certain subsidiaries, and other factors. Our regulated utilities plan to maintain capital structures consistent with those approved by their respective regulators. For more information on our utilities approved capital structures, see Item 1. Business – E. Regulation.

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

At December 31, 2021, our current liabilities exceeded our current assets by $1,096.3 million. We do not expect this to have an impact on our liquidity as we currently believe that our cash and cash equivalents, our available capacity of $1,201.6 million under

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existing revolving credit facilities, cash generated from ongoing operations, and access to the capital markets are adequate to meet our short-term and long-term cash requirements.

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

Investments in Outside Trusts

We maintain investments in outside trusts to fund the obligation to provide pension and certain OPEB benefits to current and future retirees. As of December 31, 2021, these trusts had investments of approximately $4.3 billion, consisting of fixed income and equity securities, that are subject to the volatility of the stock market and interest rates. The performance of existing plan assets, long-term discount rates, changes in assumptions, and other factors could affect our future contributions to the plans, our financial position if our accumulated benefit obligation exceeds the fair value of the plan assets, and future results of operations related to changes in pension and OPEB expense and the assumed rate of return. For additional information, see Note 20, Employee Benefits.

Capitalization Structure

The following table shows our capitalization structure as of December 31, 2021 and 2020, as well as an adjusted capitalization structure that we believe is consistent with how a majority of the rating agencies currently view our 2007 Junior Notes:

Included in long-term debt on our balance sheets as of December 31, 2021 and 2020, is $500.0 million principal amount of the 2007 Junior Notes. The adjusted presentation attributes $250.0 million of the 2007 Junior Notes to common shareholders' equity and $250.0 million to long-term debt.

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

Debt Covenants

At December 31, 2021, we were in compliance with all covenants related to outstanding short-term and long-term debt. We expect to be in compliance with all such debt covenants for the foreseeable future. See Note 13, Short-Term Debt and Lines of Credit, Note 14, Long-Term Debt, and Note 11, Common Equity, for more information.

Credit Rating Risk

Cash collateral postings and prepayments made with external parties, including postings related to exchange-traded contracts, and cash collateral posted by external parties were immaterial as of December 31, 2021. From time to time, we may enter into commodity contracts that could require collateral or a termination payment in the event of a credit rating change to below BBB- at S&P Global Ratings, a division of S&P Global Inc., and/or Baa3 at Moody’s Investors Service, Inc. If WE had a sub-investment grade credit rating at December 31, 2021, it could have been required to post $100 million of additional collateral or other assurances

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pursuant to the terms of a PPA. We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.

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

In September 2021, Moody's changed the rating outlook for WG to negative from stable as a result of the decision to defer its next base rate case to 2022. The change in rating outlook has not had, and we do not believe that it will have, a material impact on our ability to access capital markets. Moody's affirmed WG's ratings including its A3 senior unsecured rating and its P-2 short term rating for commercial paper. See Note 26, Regulatory Environment, for more information on the rate case delay.

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

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

Coronavirus Disease – 2019

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

Liquidity and Financial Markets

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

Allowance for Credit Losses

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

Our exposure to credit losses for certain regulated utility customers is mitigated by regulatory mechanisms we have in place. Specifically, rates related to all of the customers in our Illinois segment, as well as the residential rates of WE, WPS, and WG in our Wisconsin segment include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between the actual provision for credit losses and the amounts recovered in rates. In addition, we have received specific orders related to the deferral of certain costs (including credit losses) and foregone revenues related to the COVID-19 pandemic. The additional protections provided by these COVID-19 specific regulatory orders are still being assessed and will be subject to prudency reviews. See Note 26, Regulatory Environment, for more information on these orders.

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Loss of Business

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

Employee Safety

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

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

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

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

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

Competitive Markets

Electric Utility Industry

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

Wisconsin

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

Michigan

Michigan has adopted a limited retail choice program. Under Michigan law, our retail customers may choose an alternative electric supplier to provide power supply service. As a result, some of our small retail customers have switched to an alternative electric supplier. At December 31, 2021, Michigan law limited customer choice to 10% of an electric utility's Michigan retail load. Our iron ore mine customer, Tilden, is exempt from this 10% cap based on current law, but Tilden is required under a long-term agreement to purchase electric power from UMERC through March 2039. In addition, certain load increases by facilities already using an

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alternative electric supplier can still be serviced by their alternative electric supplier, when various conditions exist, even if the cap has already been met. When a customer switches to an alternative electric supplier, we continue to provide distribution and customer service functions for the customer.

Natural Gas Utility Industry

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

Wisconsin

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

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

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

Illinois

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

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

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

Minnesota

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

MERC offers both natural gas transportation service and interruptible natural gas sales to enable customers to better manage their energy costs. Customers continue to switch between firm system supply, interruptible system supply, and transportation service each year as the economics and service options change. MERC has provided its commercial and industrial customers with the option to choose a third-party natural gas supplier since 2006. We are not required by the MPUC or state law to make this choice option available to customers, but since this option is currently provided to our Minnesota commercial and industrial customers, we would need MPUC approval to eliminate it.

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Michigan

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

Regulatory, Legislative, and Legal Matters

Regulatory Recovery

Our utilities account for their regulated operations in accordance with accounting guidance under the Regulated Operations Topic of the FASB ASC. Our rates are determined by various regulatory commissions. See Item 1. Business – E. Regulation for more information on these commissions.

Regulated entities are allowed to defer certain costs that would otherwise be charged to expense if the regulated entity believes the recovery of those costs is probable. We record regulatory assets pursuant to generic and/or specific orders issued by our regulators. Recovery of the deferred costs in future rates is subject to the review and approval by those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of the deferred costs, including those referenced below, is not approved by our regulators, the costs would be charged to income in the current period. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities. As of December 31, 2021, our regulatory assets were $3,367.1 million, and our regulatory liabilities were $3,960.3 million.

We expect to request or have requested recovery of the costs related to the following projects discussed in recent or pending rate proceedings, orders, and investigations involving our utilities:

•Prior to its acquisition by us, Integrys initiated an information technology project with the goal of improving the customer experience at its subsidiaries. Specifically, the project is expected to provide functional and technological benefits to the billing, call center, and credit collection functions. As of December 31, 2021, costs incurred for this project at PGL are still subject to approval by the ICC. WPS, NSG, MGU and MERC received approval to recover these costs in their most recent rate orders.

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

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

Climate and Equitable Jobs Act

On September 15, 2021, the state of Illinois signed into law the Climate and Equitable Jobs Act. This new legislation includes, among other things, a path for Illinois to move towards 100% clean energy, expanded commitments to energy efficiency and renewable energy, additional consumer protections, and expanded ethics reform. The provisions in this legislation with the potential to have the most significant financial impact on PGL and NSG relate to the new consumer protection requirements. Effective January 1, 2023, natural gas utilities will no longer be allowed to charge late payment fees to low-income residential customers. In addition, effective September 15, 2021, the new legislation prohibits utilities from charging customers a fee when they elect to pay for service with a credit card. Instead, utilities will be required to seek recovery of costs incurred to process credit card payments through a rate proceeding or by establishing a recovery mechanism. On December 16, 2021, the ICC approved the use of a TPTFA rider for PGL. The TPTFA rider will allow PGL to recover the costs incurred for third-party transaction fees, effective December 27, 2021. See Note 26, Regulatory Environment, for more information on the rider. NSG recovers costs related to these third-party transaction fees through its recently established base rates.

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We continue to evaluate the impact this legislation may have on our future results of operations.

Withhold Release Order Related to Silica-Based Products

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

United States Department of Commerce Complaint

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

Infrastructure Investment and Jobs Act

In November 2021, President Biden signed into law the Infrastructure Investment and Jobs Act, which provides for approximately $1.2 trillion of federal spending over the next five years, including approximately $85 billion for investments in power, utilities, and renewables infrastructure across the United States. We expect funding from this Act will support the work we are doing to reduce GHG emissions, increase EV charging, and strengthen and protect the energy grid. Funding in the Act should also help to expand emerging technologies, like hydrogen and carbon management, as we continue the transition to a clean energy future. We believe the Infrastructure Investment and Jobs Act will accelerate investment in projects that will help us meet our net zero emission goals to the benefit of our customers, the communities we serve, and our company.

Return on Equity Incentive for Membership in a Transmission Organization

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

American Transmission Company Allowed Return on Equity Complaints

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

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

First Return on Equity Complaint

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

ATC is required to provide refunds, with interest, for the 15-month refund period from November 12, 2013 through February 11, 2015 and for the period from September 28, 2016 through November 19, 2020. As a result, ATC is expected to continue providing WE and WPS with net refunds related to the transmission costs they paid during the two refund periods through the end of February 2022. These refunds are being applied to WE's and WPS's PSCW-approved escrow accounting for transmission expense.

Second Return on Equity Complaint

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

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

Environmental Matters

See Note 24, Commitments and Contingencies, for a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change.

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Market Risks and Other Significant Risks

We are exposed to market and other significant risks as a result of the nature of our businesses and the environments in which those businesses operate. These risks, described in further detail below, include but are not limited to:

Commodity Costs

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

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

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

Due to the cold temperatures, wind, snow and ice throughout the central part of the country during February 2021, the cost of gas purchased for our natural gas utility customers was temporarily driven higher than our normal winter weather expectations. As a result of this extreme weather event, we requested approval for the recovery of an additional $322 million of natural gas costs across our service territories, above what was either set as a benchmark in our respective GCRMs or included in rates. See Note 26, Regulatory Environment, for more information on our recovery efforts associated with these costs.

Weather

Our utilities' rates are based upon estimated normal temperatures. Our electric utility margins are unfavorably sensitive to below normal temperatures during the summer cooling season and, to some extent, to above normal temperatures during the winter heating season. Our natural gas utility margins are unfavorably sensitive to above normal temperatures during the winter heating season. PGL, NSG, and MERC have decoupling mechanisms in place that help reduce the impacts of weather. Decoupling mechanisms differ by state and allow utilities to recover or refund certain differences between actual and authorized margins. A summary of actual weather information in our utilities' service territories during 2021 and 2020, as measured by degree days, can be found in Results of Operations.

Interest Rates

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

Based on the variable rate debt outstanding at December 31, 2021 and 2020, a hypothetical increase in market interest rates of one percentage point would have increased annual interest expense by $24.0 million and $20.3 million in 2021 and 2020, respectively. This sensitivity analysis was performed assuming a constant level of variable rate debt during the period and an immediate increase in interest rates, with no other changes for the remainder of the period.

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Marketable Securities Return

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

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

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

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

Economic Conditions

We have electric and natural gas utility operations that serve customers in Wisconsin, Illinois, Minnesota, and Michigan. As such, we are exposed to market risks in the regional Midwest economy. In addition, any economic downturn or disruption of national or international markets could adversely affect the financial condition of our customers and demand for their products, which could affect their demand for our products.

Inflation and Supply Chain Disruptions

We continue to monitor the impact of inflation and supply chain disruptions. We monitor the costs of medical plans, fuel, transmission access, construction costs, regulatory and environmental compliance costs, and other costs in order to minimize inflationary effects in future years, to the extent possible, through pricing strategies, productivity improvements, and cost reductions. We monitor the global supply chain, and related disruptions, in order to ensure we are able to procure the necessary materials and other resources necessary to both maintain our energy services in a safe and reliable manner and to grow our infrastructure in accordance with our capital plan. For additional information concerning risks related to inflation and supply chain disruptions, see Item 1A. Risk Factors – Risks Related to the Operation of Our Business – Our operations and corporate strategy may be adversely affected by supply chain disruptions and inflation.

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

Critical Accounting Policies and Estimates

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

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

Regulatory Accounting

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

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

The application of the Regulated Operations Topic of the FASB ASC would be discontinued if all or a separable portion of our utility operations no longer met the criteria for application. Our regulatory assets and liabilities would be written off to income as an unusual or infrequently occurring item in the period in which discontinuation occurred. As of December 31, 2021, we had $3,367.1 million in regulatory assets and $3,960.3 million in regulatory liabilities. See Note 6, Regulatory Assets and Liabilities, for more information.

Goodwill

We completed our annual goodwill impairment tests for all of our reporting units that carried a goodwill balance as of July 1, 2021. No impairments were recorded as a result of these tests. For all of our reporting units, the fair values calculated in step one of the test were greater than their carrying values. The fair values for the reporting units were calculated using a combination of the income approach and the market approach.

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

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

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

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

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

See Note 10, Goodwill and Intangibles, for more information.

Long-Lived Assets

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

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

See Note 7, Property, Plant, and Equipment, for more information on our generating units probable of being retired. See Note 6, Regulatory Assets and Liabilities, and Note 26, Regulatory Environment, for more information on our retired generating units, including various approvals we received from the FERC and the PSCW.

Pension and Other Postretirement Employee Benefits

The costs of providing non-contributory defined pension benefits and OPEB, described in Note 20, Employee Benefits, are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.

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

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

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

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

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

We establish our expected return on assets based on consideration of historical and projected asset class returns, as well as the target allocations of the benefit trust portfolios. The assumed long-term rate of return on pension plan assets was 6.88%, 6.87%, and 7.12% in 2021, 2020, and 2019, respectively. The actual rate of return on pension plan assets, net of fees, was 9.5%, 12.65%, and 18.89%, in 2021, 2020, and 2019, respectively.

In selecting assumed health care cost trend rates, past performance and forecasts of health care costs are considered. For more information on health care cost trend rates and a table showing future payments that we expect to make for our pension and OPEB, see Note 20, Employee Benefits.

Unbilled Revenues

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

Unbilled revenues are estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses, and applicable customer rates. Energy demand for the unbilled period or changes in rate mix due to fluctuations in usage patterns of customer classes could impact the accuracy of the unbilled revenue estimate. Total unbilled utility revenues were $531.7 million and $499.5 million as of December 31, 2021 and 2020, respectively. The changes in unbilled revenues are primarily due to changes in the cost of natural gas, weather, and customer rates.

Income Tax Expense

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

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

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

We expect our 2022 annual effective tax rate to be between 18.5% and 19.5%. Our effective tax rate calculations are revised every quarter based on the best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.