WEC ENERGY GROUP, INC. (WEC) FY 2022 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 renewable generating facilities.

Corporate Strategy

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

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

Creating a Sustainable Future

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

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

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

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

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

•1,900 MW of utility-scale solar;

•700 MW of battery storage; and

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•700 MW of wind.

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

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

•the planned purchase of up to 200 MW of capacity in the West Riverside Energy Center – a combined cycle natural gas plant recently completed by Alliant Energy in Wisconsin.

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

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

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

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

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

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

Reliability

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

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

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

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

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

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

Operating Efficiency

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

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

Financial Discipline

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

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

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

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

Exceptional Customer Care

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

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

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Safety

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

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

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

RESULTS OF OPERATIONS

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

Consolidated Earnings

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

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

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

•A $45.2 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by an increase in PTCs during 2022, primarily due to the Jayhawk wind park that achieved commercial operation in December 2021, higher generation at our other wind parks, and an increase in the PTC rate related to the PTC inflation adjustment issued by the IRS. In addition, Upstream recognized revenue during 2022 related to market settlements it received from SPP in February 2021. Due to a complaint filed with the FERC, the revenue related to these settlements could not be recognized until the FERC issued an order denying the complaint in the first quarter of 2022. A positive impact from a sharing

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arrangement with one of our Blooming Grove customers, resulting from strong energy prices, also contributed to the increase in earnings.

•A $23.2 million increase in net income attributed to common shareholders at the electric transmission segment, primarily due to the impact of the D.C. Circuit Court of Appeals opinion issued in August 2022 addressing complaints related to ATC's ROE and the year-over-year impact of a goodwill impairment recorded during the fourth quarter of 2021.

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

Non-GAAP Financial Measures

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

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

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance. The following table shows operating income by segment for our utility operations during years ended December 31, 2022 and 2021:

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

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 2022 and 2021, $516.7 million and $503.6 million, respectively, of costs were billed to our electric utilities by transmission providers.

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

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

(3)    Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE. During 2022 and 2021, $121.7 million and $113.1 million, respectively, of costs were billed to or incurred by WE related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

(4)    Represents operation and maintenance associated with the earnings mechanisms we have in place. In 2022, also includes $21.6 million of amortization related to a certain portion of WPS's regulatory liability associated with its 2020 earnings sharing mechanism to offset certain 2022 revenue deficiencies, as approved by the PSCW in order to forego filing for 2022 base rate increases. See Note 26, Regulatory Environment, for more information.

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

(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.

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Electric Revenues

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

Electric Utility Margins

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

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

•A $9.6 million increase in other revenues, primarily related to third-party use of our assets.

These increases in margins were partially offset by:

•A $50.8 million year-over-year negative impact from collections of fuel and purchased power costs compared with costs collected in rates. Under the Wisconsin fuel rules, the margins of our electric utilities are impacted by under- or over-collections of certain fuel and purchased power costs that are within a 2% price variance from the costs included in rates, and the remaining variance beyond the 2% price variance is generally deferred for future recovery or refund to customers. As a result of the higher fuel costs in both 2021 and 2022, WPS was unable to defer a portion of its under-collected fuel and purchased power costs due to earning an ROE in excess of the PSCW authorized amount.

•Lower margins of $14.9 million driven by the expiration of certain wholesale contracts.

•An $8.4 million net decrease in margins related to lower sales volumes, driven by the impact of cooler weather during the 2022 cooling season, compared with 2021. As measured by cooling degree days, 2022 was 11.0% cooler than 2021 in the Milwaukee area.

Natural Gas Revenues

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

Natural Gas Utility Margins

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

•A $59.7 million increase in margins from higher sales volumes, driven by the continued economic recovery in Wisconsin from the COVID-19 pandemic, as well as colder weather during the 2022 heating season, compared with 2021. As measured by heating degree days, 2022 was 11.1% and 9.7% colder than 2021 in the Milwaukee area and Green Bay area, respectively.

•A $9.9 million increase in margins related to the amortization of a certain portion of WG's regulatory liability consisting of credit balances associated with the escrow of natural gas storage service costs from Bluewater Gas Storage. In September 2021, the PSCW issued a written order for our Wisconsin utilities approving certain accounting treatments to offset certain 2022 revenue deficiencies in order to forego filing for 2022 base rate increases. See Note 26, Regulatory Environment, for more information.

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

•An $80.2 million decrease in transmission expense driven by the amortization of a certain portion of WE's and WPS's regulatory liabilities associated with transmission escrow balances, as discussed in the notes under the other operation and maintenance table above.

•A $19.3 million decrease in expense related to the earnings sharing mechanisms in place at our Wisconsin utilities, as discussed in the notes under the other operation and maintenance table above. See Note 26, Regulatory Environment, for more information.

•A $14.5 million decrease in other operation and maintenance expense due to increases to certain regulatory assets resulting from decisions included in the December 2022 Wisconsin rate orders.

•An $8.6 million decrease in other operation and maintenance expense during 2022, compared with 2021, related to certain COVID-19 expenditures.

•A $6.8 million decrease in other operation and maintenance expense related to the We Power leases, as discussed in the notes under the other operation and maintenance table above.

•A $3.1 million decrease in other operating and maintenance expense related to our power plants, driven by increases to certain plant-related regulatory assets resulting from decisions included in the December 2022 Wisconsin rate orders. This decrease in expense was partially offset by increased maintenance at our plants, including a planned outage at the Weston power plant, and reductions in refined coal credits during 2022, compared with 2021.

•A $2.8 million decrease in expense related to higher gains on land sales during 2022, compared with 2021.

•A $2.4 million decrease in expense related to charitable projects supporting our customers and the communities within our service territories.

These decreases in other operating expenses were partially offset by:

•A $31.7 million increase in property and revenue taxes, driven by higher gross receipt and property taxes.

•A $29.3 million increase in electric and natural gas distribution expenses, primarily driven by higher costs to manage system reliability, for storm restoration, and for overall maintenance of our distribution system during 2022.

•A $27.8 million net increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan and an increase related to the We Power leases. These increases were partially offset by $10.2 million of deferred depreciation related to capital investments made by WG since it's last rate case, as approved by the PSCW in an order that allowed our Wisconsin utilities to offset certain 2022 revenue deficiencies in order to forego filing for 2022 base rate increases.

•A $3.9 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

Other Income, Net

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

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Interest Expense

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

Income Tax Expense

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

Illinois Segment Contribution to Net Income Attributed to Common Shareholders

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

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.

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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:

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

Natural Gas Revenues

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

Natural Gas Utility Margins

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

•A $24.9 million increase in revenues at PGL due to continued capital investment in the SMP project. PGL recovers the costs related to the SMP through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023. For information on the QIP rider and PGL's plan to recover these costs after 2023, see Note 26, Regulatory Environment.

•An $8.0 million increase related to the impact of the NSG rate order approved by the ICC, effective September 15, 2021, which includes the Variable Income Tax Adjustment Rider in base rates. The Variable Income Tax Adjustment Rider recovers or refunds changes in actual income tax expense resulting from changes in income tax rates and amortization of deferred taxes, which differ from amounts included in rates. See Note 26, Regulatory Environment, for more information on NSG's rate order.

•A $5.0 million increase in the invested capital tax adjustment rider, which did not impact net income as it was offset in property and revenue taxes. The invested capital tax adjustment rider is a mechanism that allows PGL and NSG to recover or refund the difference between the cost of invested capital tax incurred and the amount collected through base rates.

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

•A $22.4 million increase in expenses related to charitable projects supporting our customers and the communities within our service territories.

•A $12.8 million increase in depreciation and amortization, primarily driven by PGL's continued capital investment in the SMP project.

•A $12.7 million increase in natural gas distribution and maintenance costs, primarily related to maintaining the natural gas infrastructure, including costs associated with PGL's gas storage field.

•An $11.4 million increase in expenses associated with the settlement of legal claims.

•A $9.8 million increase in benefit costs, primarily due to higher pension and stock-based compensation costs.

•A $7.4 million increase in property and revenue taxes, primarily driven by an increase in the invested capital tax related to continued capital investment. This increase was offset in natural gas utility margins.

•A $6.9 million increase in customer service expense, primarily driven by higher call volumes.

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

Other Income, Net

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

Interest Expense

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

Income Tax Expense

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

Other States Segment Contribution to Net Income Attributed to Common Shareholders

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

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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:

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

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

(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.

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Natural Gas Revenues

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

Natural Gas Utility Margins

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

•A $13.0 million increase related to the new rates at MGU that went into effect in 2022. See Note 26, Regulatory Environment, for more information.

•A $9.3 million increase related to higher sales volumes due to both continued economic recovery and colder weather during 2022, compared with 2021.

•A $2.6 million increase related to MERC's GUIC rider, which was in place through December 31, 2022. The GUIC rider allowed MERC to recover previously approved GUIC incurred to replace or modify natural gas facilities to the extent the work is required by state, federal, or other government agencies and exceeds the costs included in base rates.

•A $1.2 million increase related to MERC CIP revenue, which was offset in operation and maintenance expense. Rebates and programs are available to residential and commercial customers of MERC through the CIP, which is funded by rate payers using the Conservation Cost Recovery Charge and the Conservation Cost Recovery Adjustment funds that are collected on their monthly billing statements.

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

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

•A $7.9 million increase in natural gas operations and customer service expense, primarily driven by various operation and maintenance projects approved in MGU's rate case and an increase in costs related to safety and reliability programs at MERC.

•A $4.5 million increase in property and revenue taxes, driven by higher use tax at MGU.

•A $2.8 million increase in depreciation and amortization related to continued capital investment.

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

Other Income, Net

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

Interest Expense

Interest expense at the other states segment increased $7.7 million during 2022, compared with 2021, driven primarily by the deferral of $4.9 million of interest expense during 2021, as approved by the MPSC to mitigate the impacts from delaying the filing of

MGU's 2021 rate case. See Note 26, Regulatory Environment, for additional information. This deferred interest expense is now being amortized over a four-year period as a result of MGU's approved rate increase.

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Income Tax Expense

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

Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders

Equity in Earnings of Transmission Affiliates

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

•A $20.5 million increase in equity earnings due to the impact of a D.C. Circuit Court of Appeals opinion issued in August 2022 addressing complaints related to ATC's ROE. For information on this D.C. Circuit Court of Appeals opinion, see Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – American Transmission Company Allowed Return on Equity Complaints.

•An $8.5 million increase in equity earnings related to a goodwill impairment recorded during the fourth quarter of 2021 by ATC Holdco, which was formed to invest in transmission-related projects outside of ATC's traditional footprint.

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

Income Tax Expense

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

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

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Operating Income

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

•A $15.2 million positive impact from recognition of revenue related to our Upstream wind park in 2022 that was associated with market settlements received from SPP in February 2021. These settlements were subject to a FERC complaint, so we were not able to recognize them as revenue until the FERC issued an order denying that complaint in 2022.

•A $13.4 million positive impact from a sharing arrangement with one of our Blooming Grove customers resulting from strong energy prices.

These increases in operating income were partially offset by:

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

Interest Expense

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

Income Tax Expense (Benefit)

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

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

Operating Loss

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

Other Income, Net

Other income, net at the corporate and other segment decreased $37.1 million during 2022, compared with 2021. The decrease was driven by a $12.6 million net loss from the investments held in the Integrys rabbi trust during 2022, compared with an $18.6 million net gain during 2021. The gains and losses from the investments held in the rabbi trust partially offset the changes in benefit costs related to deferred compensation, which are included in other operation and maintenance expense in our operating segments. See

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Note 17, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust. An $11.9 million decrease in earnings from our equity method investments in technology and energy-focused investment funds also contributed to the lower other income, net.

Interest Expense

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

Loss on Debt Extinguishment

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

Income Tax Benefit

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

LIQUIDITY AND CAPITAL RESOURCES

Overview

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

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

Cash Flows

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

Operating Activities

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

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

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•A $51.2 million increase in cash related to a decrease in contributions and payments related to pension and OPEB plans during 2022, compared with 2021.

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

•A $461.3 million decrease in cash from higher payments for fuel and purchased power at our plants during 2022, compared with 2021. Our plants incurred higher fuel costs throughout 2022 as a result of an increase in the price of natural gas.

•A $174.3 million decrease in cash from higher payments for operating and maintenance expenses. During 2022, our payments were higher for reliability and storm restoration, transmission, benefit costs, natural gas distribution and maintenance costs, natural gas storage costs, and customer service.

•A $28.3 million decrease in cash related to higher payments for property and revenue taxes, driven by higher gross receipt taxes, property taxes, and an increase in the Illinois invested capital tax during 2022, compared with 2021.

•An $18.6 million decrease in cash related to higher cash paid for income taxes, driven by higher taxable income during 2022, compared with 2021.

•A $12.8 million decrease in cash related to higher payments for environmental remediation related to work completed on former manufactured gas plant sites during 2022, compared with 2021.

•A $12.6 million decrease in cash related to lower distributions from ATC during 2022, compared with 2021.

•An $11.4 million decrease in cash related to higher payments for interest related to increases in long-term and short-term debt interest rates during 2022, compared with 2021.

Investing Activities

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

•The acquisition of a 90% ownership interest in Thunderhead in September 2022 for $382.0 million. See Note 2, Acquisitions, for more information.

•A $62.1 million increase in cash paid for capital expenditures during 2022, compared with 2021, which is discussed in more detail below.

•Capital contributions paid to transmission affiliates of $45.5 million during 2022. See Note 21, Investment in Transmission Affiliates, for more information. There were no payments to transmission affiliates during 2021.

•The purchase of spectrum frequencies for $19.2 million during 2022. See Note 10, Goodwill and Intangibles, for more information.

•A $17.8 million increase in cash paid for ATC's construction costs during 2022, compared with 2021, which will be reimbursed in the future. See Note 21, Investment in Transmission Affiliates, for more information.

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

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

•A $47.1 million increase in proceeds from the sale of assets during 2022, compared with 2021, primarily related to the sale of real estate owned by PGL. See Note 3, Dispositions, for more information.

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

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

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

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

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

Financing Activities

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

•A $1,168.3 million increase in cash due to a decrease in retirements of long-term debt during 2022, compared with 2021.

•A $340.0 million increase in cash due to a repayment of a 364-day term loan during 2021.

•A $51.6 million increase in cash due to a decrease in payments for debt extinguishment and issuance costs during 2022, compared with 2021.

•A $17.9 million increase in cash received from the exercise of stock options during 2022, compared with 2021.

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

•A $711.8 million decrease in cash due to $252.6 million of net repayments of commercial paper during 2022, compared with $459.2 million of net borrowings of commercial paper during 2021.

•A $384.5 million decrease in cash due to lower issuances of long-term debt during 2022, compared with the same period in 2021.

•A $63.1 million decrease in cash due to higher dividends paid on our common stock during 2022, compared with 2021. In January 2022, our Board of Directors increased our quarterly dividend by $0.05 per share (7.4%) effective with the March 2022 dividend payment.

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•A $36.1 million decrease in cash due to an increase in common stock purchased during 2022, compared with 2021, to satisfy requirements of our stock-based compensation plans.

Significant Financing Activities

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

Cash Requirements

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

Significant Capital Projects

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

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

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

•We have received approval to invest in 100 MW of utility-scale solar within our Wisconsin segment. WE has partnered with an unaffiliated utility to construct a solar project, Badger Hollow II, that will be located in Iowa County, Wisconsin. Once constructed, WE will own 100 MW of this project. WE's share of the cost of this project is estimated to be approximately $151 million. Commercial operation of Badger Hollow II is targeted for 2023.

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

•WE and WPS, along with an unaffiliated utility, received PSCW approval to acquire and construct Darien, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Rock and Walworth counties, Wisconsin and once fully constructed, WE and WPS will collectively own 225 MW of solar generation and 68 MW of battery storage of this project. WE's and WPS's combined share of the cost of this project is estimated to be approximately $400 million, with construction of the solar portion expected to be completed in 2024.

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•WPS, along with an unaffiliated utility, received PSCW approval to acquire Red Barn, a utility-scale wind-powered electric generating facility. The project will be located in Grant County, Wisconsin and once constructed, WPS will own 82 MW of this project. WPS's share of the cost of this project is estimated to be approximately $160 million, with construction expected to be completed in the first half of 2023.

•In April 2021, WE and WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire the Koshkonong Solar-Battery Park, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Dane County, Wisconsin and once fully constructed, WE and WPS will collectively own 270 MW of solar generation and 149 MW of battery storage of this project. If approved, WE's and WPS's combined share of the cost of this project is estimated to be approximately $585 million, with construction of the solar portion expected to be completed in 2025.

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

•Effective January 1, 2023, WE and WPS completed the acquisition of Whitewater, a commercially operational 236.5 MW dual fueled (natural gas and low sulfur fuel oil) combined cycle electrical generation facility in Whitewater, Wisconsin. The cost of this facility was approximately $75.0 million, which includes transaction costs and working capital. See Note 15, Leases, for more information.

•In January 2022, WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire a portion of West Riverside's nameplate capacity. WPS is also requesting approval to assign the option to purchase part of West Riverside to WE. If approved, WPS or WE would acquire 100 MW of capacity, in the first of two potential option exercises. West Riverside is a combined cycle natural gas plant recently completed by an unaffiliated utility in Rock County, Wisconsin. If approved, our share of the cost of this ownership interest is approximately $91 million, with the transaction expected to close in the second quarter of 2023. In addition, WPS could exercise a second option to acquire an additional 100 MW of capacity. If approved, our share of the cost of this ownership interest is expected to be approximately $90 million, with the transaction expected to close in 2024.

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

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

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

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

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

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Long-Term Debt

A significant amount of cash is required to retire and pay interest on our long-term debt obligations. See Note 14, Long-Term Debt, for more information on our outstanding long-term debt, including a schedule of our long-term debt maturities over the next five years. The following table summarizes our required interest payments on long-term debt (excluding finance lease obligations) as of December 31, 2022:

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

Common Stock Dividends

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

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

Other Significant Cash Requirements

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

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.

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

We make contributions to our pension and OPEB plans based upon various factors affecting us, including our liquidity position and tax law changes. See Note 20, Employee Benefits, for our expected contributions in 2023 and our expected pension and OPEB payments for the next 10 years. We expect the majority of these future pension and OPEB payments to be paid from our outside trusts. See Sources of Cash–Investments in Outside Trusts below for more information.

In addition to the above, our balance sheet at December 31, 2022 included various other liabilities that, due to the nature of the liabilities, the amount and timing of future payments cannot be determined with certainty. These liabilities include AROs, liabilities

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for the remediation of manufactured gas plant sites, and liabilities related to the accounting treatment for uncertainty in income taxes. For additional information on these liabilities, see Note 9, Asset Retirement Obligations, Note 24, Commitments and Contingencies, and Note 16, Income Taxes, respectively.

Off-Balance Sheet Arrangements

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

Sources of Cash

Liquidity

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

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

The amount, type, and timing of any financings in 2023, as well as in subsequent years, will be contingent on investment opportunities and our cash requirements and will depend upon prevailing market conditions, regulatory approvals for certain subsidiaries, and other factors. Our regulated utilities plan to maintain capital structures consistent with those approved by their respective regulators. 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, 2022, our current liabilities exceeded our current assets by $1,423.3 million. We do not expect this to have an impact on our liquidity as we currently believe that our cash and cash equivalents, our available capacity of $1,454.2 million under existing revolving credit facilities, cash generated from ongoing operations, and access to the capital markets are adequate to meet our short-term and long-term cash requirements.

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

Investments in Outside Trusts

We maintain investments in outside trusts to fund the obligation to provide pension and certain OPEB benefits to current and future retirees. As of December 31, 2022, these trusts had investments of approximately $3.5 billion, consisting of fixed income and equity securities, that are subject to the volatility of the stock market and interest rates. The performance of existing plan assets, long-term discount rates, changes in assumptions, and other factors could affect our future contributions to the plans, our financial position if our accumulated benefit obligation exceeds the fair value of the plan assets, and future results of operations related to changes in pension and OPEB expense and the assumed rate of return. For additional information, see Note 20, Employee Benefits.

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Capitalization Structure

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

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

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

Debt Covenants

Certain of our short-term and long-term debt agreements contain financial covenants that we must satisfy, including debt to capitalization ratios and debt service coverage ratios. At December 31, 2022, we were in compliance with all such covenants related to outstanding short-term and long-term debt. We expect to be in compliance with all such debt covenants for the foreseeable future. See Note 13, Short-Term Debt and Lines of Credit, Note 14, Long-Term Debt, and Note 11, Common Equity, for more information.

Credit Rating Risk

Cash collateral postings and prepayments made with external parties, including postings related to exchange-traded contracts, and cash collateral posted by external parties were immaterial as of December 31, 2022. From time to time, we may enter into commodity contracts that could require collateral or a termination payment in the event of a credit rating change to below BBB- at S&P Global Ratings, a division of S&P Global Inc., and/or Baa3 at Moody’s Investors Service, Inc. If WE had a sub-investment grade credit rating at December 31, 2022, it could have been required to post $100 million of additional collateral or other assurances pursuant to the terms of a PPA. We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.

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

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

Subject to other factors affecting the credit markets as a whole, we believe our current ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, these security ratings reflect the views of the rating agency only. An

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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

Competitive Markets

Electric Utility Industry

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

Wisconsin

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

Michigan

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

Natural Gas Utility Industry

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

Wisconsin

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

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

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

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Illinois

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

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

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

Minnesota

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

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

Michigan

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

Regulatory, Legislative, and Legal Matters

Regulatory Recovery

Our utilities account for their regulated operations in accordance with accounting guidance under the Regulated Operations Topic of the FASB ASC. Our rates are determined by various regulatory commissions. 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. See Note 6, Regulatory Assets and Liabilities, for more information on our regulatory assets and liabilities.

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

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

Petitions Before PSCW Regarding Third-Party Financed Distributed Energy Resources

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

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

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

Climate and Equitable Jobs Act

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

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

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

Uyghur Forced Labor Prevention Act

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

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United States Department of Commerce Complaints

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

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

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

Infrastructure Investment and Jobs Act

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

Inflation Reduction Act

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

Return on Equity Incentive for Membership in a Transmission Organization

The FERC currently allows transmission utilities, including ATC, to increase their ROE by 50 basis points as an incentive for membership in a transmission organization, such as MISO. This incentive was established to stimulate infrastructure development and to support the evolving electric grid. However, a Notice of Proposed Rulemaking was issued by the FERC on April 15, 2021

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proposing to limit the 50 basis point increase in ROE to only be available to transmission utilities initially joining a transmission organization for the first three years of membership. If this proposal becomes a final rule, ATC would be required to submit, within 30 days of the final rule's effective date, a compliance filing eliminating the 50 basis point incentive from its tariff. As a result, we estimate that this proposal, if adopted, would reduce our future after-tax equity earnings from ATC by approximately $7 million annually on a prospective basis. The transmission costs WE, WPS, and UMERC are required to pay ATC after the effective date would also be reduced by this proposal.

American Transmission Company Allowed Return on Equity Complaints

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

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

First Return on Equity Complaint

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

•Orders Issued by the FERC

◦September 2016 Order – On September 28, 2016, the FERC issued an order reducing the base ROE for MISO transmission owners to 10.32% for the period covered by the first complaint, November 12, 2013 through February 11, 2015 and September 28, 2016 going forward.

◦November 2019 Order – On November 21, 2019, the FERC issued another order after directing MISO transmission owners and other stakeholders to provide briefs and comments on a proposed change to the methodology for calculating base ROE. In this order, the FERC expanded its base ROE methodology to include the capital-asset pricing model in addition to the discounted cash flow model to better reflect how investors make their investment decisions. The FERC also rejected the use of the risk premium model as part of its base ROE methodology in this order. The FERC's modified methodology further reduced the base ROE for all MISO transmission owners, including ATC, to 9.88% for the period covered by the first complaint. In response to this FERC decision, requests for the FERC to rehear the November 2019 Order in its entirety were filed by various parties.

◦May 2020 Order – On May 21, 2020, the FERC issued an order that granted in part and denied in part the requests to rehear the November 2019 Order. In this May 2020 Order, the FERC made additional revisions to its base ROE methodology, including reinstating the use of the risk premium model. The additional revisions made by the FERC increased the base ROE for all MISO transmission owners, including ATC, from the 9.88% authorized in the November 2019 Order to 10.02% for the period covered by the first complaint. Various parties then filed requests to rehear certain parts of the May 2020 Order with the FERC.

◦November 2020 Order – In response to the rehearing requests filed concerning certain parts of the May 2020 Order, the FERC issued an order in November 2020 that confirmed the ROE previously authorized in its May 2020 Order.

◦Refunds – Due to the base ROE changes resulting from these FERC orders, ATC was required to provide refunds, with interest, for the 15-month refund period from November 12, 2013 through February 11, 2015 and for the period from September 28, 2016 through November 19, 2020. In January 2022, ATC completed providing WE, WPS, and UMERC with the net refunds related to the transmission costs they paid during the period covered by the first complaint. The refunds were applied to WE's and WPS's PSCW-approved escrow accounting for transmission expense.

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•Opinion Issued by the D.C. Circuit Court of Appeals

◦August 2022 Decision – Since several petitions for review were filed with the D.C. Circuit Court of Appeals concerning this ROE complaint, the D.C. Circuit Court of Appeals issued an opinion on August 9, 2022 addressing these petitions. In its August 2022 Decision, the D.C. Circuit Court of Appeals ruled the FERC failed to adequately explain why it reinstated the use of the risk premium model as part of its ROE methodology in its May 2020 Order after previously rejecting the model in its November 2019 Order. Due to this ruling, the D.C. Circuit Court of Appeals vacated the FERC’s previous orders and remanded the issue of determining an appropriate base ROE for MISO transmission owners back to the FERC for additional proceedings. As of December 31, 2022, the FERC had not provided a ruling in response to the August 2022 Decision issued by the D.C. Circuit Court of Appeals.

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

Second Return on Equity Complaint

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

•Orders Issued by the FERC

◦November 2019 Order – Similar to the first complaint, the November 2019 Order stated the newly calculated base ROE of 9.88% was also reasonable for the period covered by the second complaint, February 12, 2015 through May 10, 2016. However, in the November 2019 Order, the FERC relied on certain provisions of the Federal Power Act to dismiss the second complaint and to determine refunds were not allowed for this period.

◦May 2020 Order – In its May 2020 Order, the FERC stated the newly calculated base ROE of 10.02% was also reasonable for the period covered by the second complaint. However, the FERC relied on the same provisions of the Federal Power Act to again dismiss the complaint and to determine refunds were not allowed for this period. In addition, the FERC denied in its May 2020 Order the requests to rehear both the dismissal of the second complaint and the determination that no refunds are allowed for the second complaint period.

•Opinion Issued by the D.C. Circuit Court of Appeals

◦August 2022 Decision - The August 2022 Decision issued by the D.C. Circuit Court of Appeals affirmed both the FERC’s dismissal of the second complaint and the FERC’s finding that no refunds are allowed for the second complaint period. Therefore, during the third quarter of 2022, we reduced the liability previously recorded for the potential refunds related to the second complaint period by $39.1 million, which increased our equity earnings from ATC.

Environmental Matters

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

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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 generally allow them to recover or refund all or a portion of the changes in prudently incurred fuel, natural gas, and purchased power costs from rate case-approved amounts. 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 2022 and 2021, as measured by degree days, can be found in Results of Operations.

Interest Rates

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

Based on the variable rate debt outstanding at December 31, 2022 and 2021, a hypothetical increase in market interest rates of one percentage point would have increased annual interest expense by $21.4 million and $24.0 million in 2022 and 2021, respectively. This sensitivity analysis was performed assuming a constant level of variable rate debt during the period and an immediate increase in interest rates, with no other changes for the remainder of the period.

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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. The financial risks associated with investment returns are mitigated at our Wisconsin utilities through the requirement that WE, WPS, and WG implement escrow accounting treatment for pension and OPEB costs in 2023 and 2024, as required by the December 2022 rate order issued by the PSCW. We also believe that the financial risks associated with investment returns would be partially mitigated at our other utilities through future rate actions by regulators. See Note 26, Regulatory Environment, for more information on 2023 and 2024 rates at our Wisconsin utilities.

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

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 the three risk factors below.

•Item 1A. Risk Factors – Risks Related to the Operation of Our Business – Our operations and corporate strategy may be adversely affected by supply chain disruptions and inflation.

•Item 1A. Risk Factors – Risks Related to the Operation of Our Business – We are actively involved with multiple significant capital projects, which are subject to a number of risks and uncertainties that could adversely affect project costs and completion of construction projects.

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

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For additional information concerning other risk factors, including market risks, see the Cautionary Statement Regarding Forward-Looking Information at the beginning of this report 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 judgments that could have a material impact on our financial statements and related disclosures. Judgments regarding future events may include the likelihood of success of particular projects, legal and regulatory challenges, and anticipated recovery of costs. Actual results may differ significantly from estimated amounts based on varying assumptions.

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

Regulatory Accounting

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

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

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

Goodwill

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

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

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

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

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

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

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

Long-Lived Assets

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

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

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

Pension and Other Postretirement Employee Benefits

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

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

Pension and OPEB plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity and fixed income market returns, as well as changes in general interest rates, may result in increased or decreased benefit costs in future periods. Changes in benefit costs are mitigated at our Wisconsin utilities through the requirement that WE, WPS, and WG implement escrow accounting treatment for pension and OPEB costs in 2023 and 2024, as required by the December 2022 rate orders issued by the PSCW. See Note 26, Regulatory Environment, for more information on 2023 and 2024 rates at our Wisconsin utilities. We believe that changes to benefit costs at our other utilities would be recovered or refunded through the ratemaking process.

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

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

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

We establish our expected return on assets based on consideration of historical and projected asset class returns, as well as the target allocations of the benefit trust portfolios. The assumed long-term rate of return on pension plan assets was 6.88% in 2022 and 2021, and 6.87% in 2020. The actual rate of return on pension plan assets, net of fees, was (14.03)%, 9.5%, and 12.65%, in 2022, 2021, and 2020, respectively.

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

Unbilled Revenues

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

Unbilled revenues are estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses, and applicable customer rates. Energy demand for the unbilled period or changes in rate mix due to fluctuations in usage patterns of customer classes could impact the accuracy of the unbilled revenue estimate. Total unbilled utility revenues were $663.1 million and $531.7 million as of December 31, 2022 and 2021, respectively. The changes in unbilled revenues are primarily due to changes in the cost of natural gas, weather, and customer rates.

Income Tax Expense

Significant management judgment is required in determining our provision for income taxes, deferred income tax assets and liabilities, the liability for unrecognized tax benefits, and any valuation allowance recorded against deferred income tax assets. The assumptions involved are supported by historical data, reasonable projections, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. Significant changes in these assumptions could have a material impact on our

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financial condition and results of operations. See Note 1(q), Income Taxes, and Note 16, Income Taxes, for a discussion of accounting for income taxes.

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

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

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