Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CORPORATE DEVELOPMENTS

The following discussion should be read in conjunction with the accompanying unaudited financial statements and related notes and our 2022 Annual Report on Form 10-K.

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 that it leases to Wisconsin Electric Power Company (WE)), 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.

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.

We have 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 1,900 MWs 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. Through our ESG Progress Plan, we expect to retire approximately 1,500 MWs 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 by June 2026 of jointly-owned Columbia Units 1-2.

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 MWs of utility-scale solar;

• 700 MWs of battery storage; and

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• 700 MWs of wind.

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

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

• the planned purchase of up to 200 MWs 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 MWs 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 25 Solar Now projects and currently has another four under construction, together totaling more than 30 MWs. 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, and was adjusted down from 150 MWs to up to 35 MWs of renewables that could be added 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 natural gas 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 systems. 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 one Bcf of RNG planned to enter our systems, and we expect to have RNG flowing 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 for 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. The results of this testing were recently shared by EPRI and in various industry presentations.

We are planning a pilot program for the fourth-quarter of 2023 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.

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 anticipated 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.

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 MWs. 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

THREE MONTHS ENDED MARCH 31, 2023

Consolidated Earnings

The following table compares our consolidated results for the first quarter of 2023 with the first quarter of 2022, including favorable or better, "B", and unfavorable or worse, "W", variances:

						Three Months Ended March 31
(in millions, except per share data)						2023						2022						B (W)
Wisconsin						$	257.2					$	288.1					$	(30.9)
Illinois						113.1						113.4						(0.3)
Other states						33.2						31.5						1.7
Electric transmission						29.3						27.8						1.5
Non-utility energy infrastructure						88.5						91.5						(3.0)
Corporate and other						(13.8)						13.6						(27.4)
Net income attributed to common shareholders						$	507.5					$	565.9					$	(58.4)
Diluted earnings per share						$	1.61					$	1.79					$	(0.18)

Earnings decreased $58.4 million during the first quarter of 2023, compared with the same quarter in 2022. The significant factors impacting the $58.4 million decrease in earnings were:

• A $30.9 million decrease in net income attributed to common shareholders at the Wisconsin segment, driven by increases in various operating expenses, including expenses related to transmission, depreciation and amortization, and regulatory amortizations. A decrease in electric and natural gas margins due to lower sales volumes, driven by warmer winter weather during the first quarter of 2023, compared with the same quarter in 2022, and a negative quarter-over-quarter impact from collections of fuel and purchased power costs, also contributed to the lower earnings. These negative impacts were partially offset by an increase in electric and natural gas margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2023. See Note 26, Regulatory Environment, in our 2022 Annual Report on Form 10-K for more information on the 2023 rate orders.

• A $13.8 million net loss attributed to common shareholders at the corporate and other segment during the first quarter of 2023, compared with $13.6 million of net income during the same quarter in 2022. The decrease in earnings was driven by higher interest expense and lower earnings from our equity method investments in technology and energy-focused investment funds. These negative impacts were partially offset by net gains from the investments held in the Integrys rabbi trust during the first quarter of 2023, compared with net losses during the same quarter in 2022. 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 primarily included in other operation and maintenance expense in our utility segments. See Note 12, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.

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Expected 2023 Annual Effective Tax Rate

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.

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 the first quarter of 2023 and 2022:

						Three Months Ended March 31
(in millions)						2023						2022
Wisconsin						$	441.8					$	497.7
Illinois						175.4						168.2
Other states						48.3						44.6

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 was $257.2 million during the first quarter of 2023, representing a $30.9 million, or 10.7%, decrease over the same quarter in 2022. The lower earnings were driven by increases in various operating expenses, including expenses related to transmission, depreciation and amortization, and regulatory amortizations. A decrease in electric and natural gas margins due to lower sales volumes, driven by warmer winter weather during the first quarter of 2023, compared with the same quarter in 2022, and a negative quarter-over-quarter impact from collections of fuel and purchased power costs, also contributed to the lower earnings. These negative impacts were partially offset by an increase in electric and natural gas margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2023. See Note 26, Regulatory Environment, in our 2022 Annual Report on Form 10-K for more information on the 2023 rate orders.

						Three Months Ended March 31
(in millions)						2023						2022						B (W)
Electric revenues						$	1,208.9					$	1,193.0					$	15.9
Fuel and purchased power						411.7						406.9						(4.8)
Total electric margins						797.2						786.1						11.1
Natural gas revenues						787.4						749.3						38.1
Cost of natural gas sold						508.6						496.8						(11.8)
Total natural gas margins						278.8						252.5						26.3
Total electric and natural gas margins						1,076.0						1,038.6						37.4
Other operation and maintenance						380.8						312.6						(68.2)
Depreciation and amortization						207.3						187.1						(20.2)
Property and revenue taxes						46.1						41.2						(4.9)
Operating income						441.8						497.7						(55.9)
Other income, net						32.2						22.4						9.8
Interest expense						150.6						136.3						(14.3)
Income before income taxes						323.4						383.8						(60.4)
Income tax expense						65.9						95.4						29.5
Preferred stock dividends of subsidiary						0.3						0.3						—
Net income attributed to common shareholders						$	257.2					$	288.1					$	(30.9)

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

						Three Months Ended March 31
(in millions)						2023						2022						B (W)
Operation and maintenance not included in line items below						$	155.0					$	146.7					$	(8.3)
Transmission (1)						138.1						107.9						(30.2)
Regulatory amortizations and other pass through expenses (2)						53.1						35.8						(17.3)
We Power (3)						35.5						27.6						(7.9)
Earnings sharing mechanisms (4)						(0.9)						(5.4)						(4.5)
Total other operation and maintenance						$	380.8					$	312.6					$	(68.2)

(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 the first quarter of 2023 and 2022, $127.3 million and $126.5 million, respectively, of costs were billed to our electric utilities by transmission providers.

(2)Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on net income. Effective January 1, 2023, the PSCW approved escrow accounting for pension and OPEB costs as well as certain costs associated with our jointly-owned Columbia plant. As a result, our Wisconsin utilities defer as a regulatory asset or liability, the difference between these actual costs and those included in rates until recovery or refund is authorized in a future rate proceeding.

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(3)Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE. During the first quarter of 2023 and 2022, $26.6 million and $24.8 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)The first quarter 2022 amortization represented amortization of 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, in our 2022 Annual Report on Form 10-K for more information.

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

						Three Months Ended March 31
						MWh (in thousands)
Electric Sales Volumes						2023						2022						B (W)
Customer Class
Residential						2,679.4						2,844.0						(164.6)
Small commercial and industrial (1)						3,095.1						3,205.6						(110.5)
Large commercial and industrial (1)						2,908.3						2,982.1						(73.8)
Other						37.5						40.2						(2.7)
Total retail (1)						8,720.3						9,071.9						(351.6)
Wholesale						474.5						718.5						(244.0)
Resale						1,259.0						1,238.8						20.2
Total sales in MWh (1)						10,453.8						11,029.2						(575.4)

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

						Three Months Ended March 31
						Therms (in millions)
Natural Gas Sales Volumes						2023						2022						B (W)
Customer Class
Residential						493.9						565.3						(71.4)
Commercial and industrial						298.5						346.2						(47.7)
Total retail						792.4						911.5						(119.1)
Transportation						408.8						446.6						(37.8)
Total sales in therms						1,201.2						1,358.1						(156.9)

						Three Months Ended March 31
						Degree Days
Weather						2023						2022						B (W)
WE and WG (1)
Heating (3,283 Normal)						2,833						3,325						(14.8)		%
WPS (2)
Heating (3,667 Normal)						3,356						3,843						(12.7)		%
UMERC (3)
Heating (3,990 Normal)						3,638						4,339						(16.2)		%

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

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

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

Electric Revenues

Electric revenues increased $15.9 million during the first quarter of 2023, compared with the same quarter in 2022. To the extent that changes in fuel and purchased power costs are passed through to customers, the changes are offset by comparable changes in

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revenues. See the discussion of electric utility margins below for more information related to the 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 $11.1 million during the first quarter of 2023, compared with the same quarter in 2022. The significant factor impacting the higher electric utility margins was an $81.5 million increase in margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2023. See Note 26, Regulatory Environment, in our 2022 Annual Report on Form 10-K for more information on the 2023 rate orders.

This increase in margins was partially offset by:

• A $31.0 million quarter-over-quarter 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.

• A $26.6 million decrease in margins related to lower sales volumes, driven by the impact of warmer winter weather during the first quarter of 2023, compared with the same quarter in 2022. As measured by heating degree days, the first quarter of 2023 was 14.8% and 12.7% warmer than the same quarter in 2022 in the Milwaukee area and Green Bay area, respectively.

• Lower margins of $7.1 million driven by the expiration of a wholesale contract.

• A $5.1 million decrease in other revenues, primarily related to a FERC order in January 2023 that eliminated reactive power compensation MISO was required to pay to generators, including our electric utilities.

Natural Gas Revenues

Natural gas revenues increased $38.1 million during the first quarter of 2023, compared with the same quarter in 2022. 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 18% during the first quarter of 2023, compared with the same quarter in 2022. 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 $26.3 million during the first quarter of 2023, compared with the same quarter in 2022. The most significant factor impacting the higher natural gas utility margins was a $55.7 million increase in margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2023. This increase in margins was partially offset by a $27.7 million decrease in margins from lower sales volumes, driven by warmer winter weather during the first quarter of 2023, compared with the same quarter in 2022.

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

Other operating expenses at the Wisconsin segment increased $93.3 million during the first quarter of 2023, compared with the same quarter in 2022. The significant factors impacting the increase in operating expenses were:

• A $30.2 million increase in transmission expense as approved in the PSCW's 2023 rate orders, effective January 1, 2023. See the notes under the other operation and maintenance table above for more information.

• A $20.2 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan.

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• A $17.3 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

• A $7.9 million increase 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 $5.2 million increase in other operating and maintenance related to our power plants, driven by increased maintenance, including a planned outage at the Weston power plant, and operating costs associated with Whitewater, which was purchased in January 2023.

• A $5.0 million increase in benefit costs, primarily driven by higher medical and deferred compensation costs.

• A $4.9 million increase in property and revenue taxes, driven by higher gross receipt taxes during the first quarter of 2023.

• A $4.5 million increase in expense driven by amortization during the first quarter of 2022 of a certain portion of WPS's regulatory liability associated with its 2020 earnings sharing mechanism, as discussed in the notes under the other operation and maintenance table above.

Other Income, Net

Other income, net at the Wisconsin segment increased $9.8 million during the first quarter of 2023, compared with the same quarter in 2022, driven by higher AFUDC–Equity due to continued capital investment.

Interest Expense

Interest expense at the Wisconsin segment increased $14.3 million during the first quarter of 2023, compared with the same quarter in 2022, primarily due to WE and WPS issuing long-term debt during the third and fourth quarters of 2022, respectively, and higher short-term debt interest rates. Also contributing to the increase was the deferral in the first quarter of 2022 of $2.0 million 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 2022 base rate increases. This deferred interest expense is now being amortized over a two-year period. See Note 26, Regulatory Environment, in our 2022 Annual Report on Form 10-K for more information. These increases were partially offset by higher AFUDC–Debt due to continued capital investment.

Income Tax Expense

Income tax expense at the Wisconsin segment decreased $29.5 million during the first quarter of 2023, compared with the same quarter in 2022. The decrease in income tax expense was due to lower pre-tax income and a $10.0 million increase in PTCs.

Illinois Segment Contribution to Net Income Attributed to Common Shareholders

The Illinois segment's contribution to net income attributed to common shareholders was $113.1 million during the first quarter of 2023, representing a $0.3 million, or 0.3%, decrease over the same quarter in 2022. The lower earnings were driven by an increase in interest expense, lower net credits from the non-service components of our net periodic pension and OPEB costs, and higher operating expenses. These negative impacts were partially offset by higher natural gas margins, driven by PGL's continued capital investment in the SMP project under its QIP rider.

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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.

						Three Months Ended March 31
(in millions)						2023						2022						B (W)
Natural gas revenues						$	599.7					$	682.1					$	(82.4)
Cost of natural gas sold						239.2						331.0						91.8
Total natural gas margins						360.5						351.1						9.4
Other operation and maintenance						113.7						113.6						(0.1)
Depreciation and amortization						58.5						56.8						(1.7)
Property and revenue taxes						12.9						12.5						(0.4)
Operating income						175.4						168.2						7.2
Other income, net						1.3						5.0						(3.7)
Interest expense						21.6						17.7						(3.9)
Income before income taxes						155.1						155.5						(0.4)
Income tax expense						42.0						42.1						0.1
Net income attributed to common shareholders						$	113.1					$	113.4					$	(0.3)

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

						Three Months Ended March 31
(in millions)						2023						2022						B (W)
Operation and maintenance not included in the line items below						$	70.7					$	70.5					$	(0.2)
Riders (1)						43.2						43.5						0.3
Regulatory amortizations (1)						(0.2)						(0.4)						(0.2)
Total other operation and maintenance						$	113.7					$	113.6					$	(0.1)

(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:

						Three Months Ended March 31
						Therms (in millions)
Natural Gas Sales Volumes						2023						2022						B (W)
Customer Class
Residential						373.9						429.8						(55.9)
Commercial and industrial						151.1						172.9						(21.8)
Total retail						525.0						602.7						(77.7)
Transportation						306.1						358.7						(52.6)
Total sales in therms						831.1						961.4						(130.3)

						Three Months Ended March 31
						Degree Days
Weather (1)						2023						2022						B (W)
Heating (3,119 Normal)						2,719						3,209						(15.3)		%

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

Natural Gas Revenues

Natural gas revenues decreased $82.4 million during the first quarter of 2023, compared with the same quarter in 2022. 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 decreased 17% during the first quarter of 2023, compared with the same quarter in 2022. The remaining drivers of changes in natural gas revenues are described in the discussion of margins below.

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Natural Gas Utility Margins

Natural gas utility margins at the Illinois segment, net of the $0.3 million impact of the riders referenced in the table above, increased $9.7 million during the first quarter of 2023, compared with the same quarter in 2022. The increase in margins was primarily driven by:

• A $6.2 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. See Note 22, Regulatory Environment, for more information.

• A $2.5 million increase related to late payment charges during the first quarter of 2023, compared with the same quarter in 2022.

• A $1.5 million increase related to fixed customer charges during the first quarter of 2023, compared with the same quarter in 2022.

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

Other operating expenses at the Illinois segment increased $2.5 million, net of the $0.3 million impact of the riders referenced in the table above, during the first quarter of 2023, compared with the same quarter in 2022. The significant factors impacting the increase in operating expenses were:

• A $3.5 million pre-tax gain on the sale of certain real estate in Chicago during the first quarter in 2022.

• A $1.7 million increase in depreciation and amortization expense, primarily driven by PGL's continued capital investment in the SMP project.

These increases in operating expenses were partially offset by a $2.7 million decrease in natural gas distribution and maintenance costs, primarily related to work on the natural gas infrastructure.

Other Income, Net

Other income, net at the Illinois segment decreased $3.7 million during the first quarter of 2023, compared with the same quarter in 2022, driven by lower net credits from the non-service components of our net periodic pension and OPEB costs. See Note 15, Employee Benefits, for more information on our benefit costs.

Interest Expense

Interest expense at the Illinois segment increased $3.9 million during the first quarter of 2023, compared with the same quarter in 2022, primarily due to increased short-term debt interest rates and PGL issuing long-term debt in December 2022.

Other States Segment Contribution to Net Income Attributed to Common Shareholders

The other states segment's contribution to net income attributed to common shareholders was $33.2 million during the first quarter of 2023, representing a $1.7 million, or 5.4%, increase over the same quarter in 2022. The increase in earnings was driven by higher natural gas margins due to an interim rate increase at MERC, effective January 1, 2023. This positive impact was partially offset by a decrease in natural gas margins due to lower sales volumes and an increase in property taxes.

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

						Three Months Ended March 31
(in millions)						2023						2022						B (W)
Natural gas revenues						$	250.0					$	240.9					$	9.1
Cost of natural gas sold						159.2						156.9						(2.3)
Total natural gas margins						90.8						84.0						6.8
Other operation and maintenance						24.7						24.6						(0.1)
Depreciation and amortization						10.4						10.0						(0.4)
Property and revenue taxes						7.4						4.8						(2.6)
Operating income						48.3						44.6						3.7
Other income, net						0.3						0.6						(0.3)
Interest expense						4.2						3.3						(0.9)
Income before income taxes						44.4						41.9						2.5
Income tax expense						11.2						10.4						(0.8)
Net income attributed to common shareholders						$	33.2					$	31.5					$	1.7

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

						Three Months Ended March 31
(in millions)						2023						2022						B (W)
Operation and maintenance not included in line item below						$	16.5					$	17.4					$	0.9
Regulatory amortizations and other pass through expenses (1)						8.2						7.2						(1.0)
Total other operation and maintenance						$	24.7					$	24.6					$	(0.1)

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

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

						Three Months Ended March 31
						Therms (in millions)
Natural Gas Sales Volumes						2023						2022						B (W)
Customer Class
Residential						145.6						172.0						(26.4)
Commercial and industrial						92.8						103.0						(10.2)
Total retail						238.4						275.0						(36.6)
Transportation						219.6						261.0						(41.4)
Total sales in therms						458.0						536.0						(78.0)

						Three Months Ended March 31
						Degree Days
Weather (1)						2023						2022						B (W)
MERC
Heating (3,958 Normal)						3,882						4,312						(10.0)		%
MGU
Heating (3,188 Normal)						2,738						3,234						(15.3)		%

(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 service territories.

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Natural Gas Revenues

Natural gas revenues increased $9.1 million during the first quarter of 2023, compared with the same quarter in 2022. 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 17% during the first quarter of 2023, compared with the same quarter in 2022. See the discussion of natural gas utility margins below for the remaining drivers of changes in natural gas revenues.

Natural Gas Utility Margins

Natural gas utility margins increased $6.8 million during the first quarter of 2023, compared with the same quarter in 2022. The significant factors impacting the increase in natural gas utility margins were:

• A $9.0 million increase related to an interim rate increase at MERC that was effective January 1, 2023. See Note 22, Regulatory Environment, for more information about the pending rate case.

• A $0.9 million increase in revenues related to late payment charges.

These increases in natural gas utility margins were partially offset by a $3.8 million decrease related to lower sales volumes, primarily driven by warmer weather during the first quarter of 2023, compared with the same quarter in 2022.

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 $3.1 million during the first quarter of 2023, compared with the same quarter in 2022. The significant factors impacting the increase in operating expenses were:

• A $2.6 million increase in property and revenue taxes, driven by higher property taxes at MERC.

• A $1.1 million increase in bad debt expense.

Interest Expense

Interest expense at the other states segment increased $0.9 million during the first quarter of 2023, compared with the same quarter in 2022, primarily due to higher short-term debt interest rates.

Income Tax Expense

Income tax expense at the other states segment increased $0.8 million during the first quarter of 2023, compared with the same quarter in 2022, driven by an increase in pre-tax income.

Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders

						Three Months Ended March 31
(in millions)						2023						2022						B (W)
Equity in earnings of transmission affiliates						$	43.8					$	41.7					$	2.1
Other expense						—						(0.1)						0.1
Interest expense						4.8						4.9						0.1
Income before income taxes						39.0						36.7						2.3
Income tax expense						9.7						8.9						(0.8)
Net income attributed to common shareholders						$	29.3					$	27.8					$	1.5

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Equity in Earnings of Transmission Affiliates

Equity in earnings of transmission affiliates increased $2.1 million during the first quarter of 2023, compared with the same quarter in 2022. This increase was primarily due to continued capital investment by ATC.

Income Tax Expense

Income tax expense at the electric transmission segment increased $0.8 million during the first quarter of 2023, compared with the same quarter in 2022, driven by an increase in pre-tax income.

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

						Three Months Ended March 31
(in millions)						2023						2022						B (W)
Operating income						$	90.4					$	105.6					$	(15.2)
Interest expense						19.9						17.2						(2.7)
Income before income taxes						70.5						88.4						(17.9)
Income tax benefit						(17.8)						(4.9)						12.9
Net (income) loss attributed to noncontrolling interests						0.2						(1.8)						2.0
Net income attributed to common shareholders						$	88.5					$	91.5					$	(3.0)

Operating Income

Operating income at the non-utility energy infrastructure segment decreased $15.2 million during the first quarter of 2023, compared with the same quarter in 2022. The decrease was primarily due to the recognition of $15.2 million in revenue related to our Upstream wind park in the first quarter of 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 FERC issued an order denying that complaint in the first quarter of 2022.

Interest Expense

Interest expense at the non-utility energy infrastructure segment increased $2.7 million during the first quarter of 2023, compared with the same quarter in 2022, primarily due to WEC Infrastructure Wind Holding II LLC issuing long-term debt in December 2022.

Income Tax Benefit

The income tax benefit at the non-utility energy infrastructure segment increased $12.9 million during the first quarter of 2023, compared with the same quarter in 2022. The increase was primarily due to an $8.6 million increase in PTCs in 2023, driven by the acquisition of three additional renewable generation facilities in the second half of 2022 and the first quarter of 2023, which are discussed further in Note 2, Acquisitions. Also contributing to the favorable income tax variance were lower pre-tax earnings during the first quarter of 2023, compared with the same quarter in 2022.

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

						Three Months Ended March 31
(in millions)						2023						2022						B (W)
Operating loss						$	(3.6)					$	(0.5)					$	(3.1)
Other income, net						8.5						11.9						(3.4)
Interest expense						55.6						22.6						(33.0)
Loss before income taxes						(50.7)						(11.2)						(39.5)
Income tax benefit						(36.9)						(24.8)						12.1
Net income (loss) attributed to common shareholders						$	(13.8)					$	13.6					$	(27.4)

Operating Loss

The operating loss at the corporate and other segment increased $3.1 million during the first quarter of 2023, compared with the same quarter in 2022, driven by a $3.3 million decrease in operating income at Wispark, primarily due to lower gains related to the sale of land and other assets.

Other Income, Net

Other income, net at the corporate and other segment decreased $3.4 million during the first quarter of 2023, compared with the same quarter in 2022. The decrease was driven by a $3.1 million net loss from our equity method investments in technology and energy-focused investment funds during the first quarter of 2023, compared with $11.3 million of net earnings during the same quarter in 2022. This decrease in other income, net was partially offset by a $4.0 million net gain from the investments held in the Integrys rabbi trust during the first quarter of 2023, compared with a $4.6 million net loss during the same quarter in 2022. 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 primarily included in other operation and maintenance expense in our utility segments. See Note 12, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.

Interest Expense

Interest expense at the corporate and other segment increased $33.0 million during the first quarter of 2023, compared with the same quarter in 2022, due to long-term debt issuances in September 2022 and January 2023 and higher short-term debt interest rates.

Income Tax Benefit

The income tax benefit at the corporate and other segment increased $12.1 million during the first quarter of 2023, compared with the same quarter in 2022, driven by a higher pre-tax loss and a $2.1 million quarter-over-quarter increase in the interim tax benefit recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate. These increases in income tax benefit were partially offset by a $2.6 million decrease in excess tax benefits recognized related to stock option exercises during the first quarter of 2023, compared with the same quarter in 2022.

LIQUIDITY AND CAPITAL RESOURCES

Overview

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

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Cash Flows

The following table summarizes our cash flows during the three months ended March 31:

(in millions)						2023						2022						Change in 2023 Over 2022
Cash provided by (used in):
Operating activities						$	796.1					$	1,076.8					$	(280.7)
Investing activities						(1,267.9)						(338.2)						(929.7)
Financing activities						417.6						(706.5)						1,124.1

Operating Activities

Net cash provided by operating activities decreased $280.7 million during the first quarter of 2023, compared with the same quarter in 2022, driven by:

• A $363.8 million decrease in cash driven by higher collateral paid to counterparties during the first quarter of 2023, compared with collateral received from counterparties during the same quarter in 2022, as well as realized losses on derivative instruments recognized during the first quarter of 2023, compared with realized gains recognized during the first quarter of 2022.

• A $74.2 million decrease in cash from higher payments for other operation and maintenance expenses. During the first quarter of 2023, our payments were higher for charitable projects accrued for at the end of 2022 and benefit costs, as well as due to the timing of payments for accounts payable.

• A $39.2 million decrease in cash from higher payments for interest, driven by the issuance of long-term debt during the third quarter of 2022, and higher short-term debt interest rates during the first quarter of 2023, compared with the same quarter in 2022.

These decreases in net cash provided by operating activities were partially offset by a $203.2 million increase in cash from higher overall collections from customers during the first quarter of 2023, compared with the same quarter in 2022. This increase was driven by the Wisconsin rate orders approved by the PSCW, effective January 1, 2023, an increase in the per-unit cost of natural gas during the first quarter of 2023, and continued recovery on the natural gas costs we under-collected from our Minnesota customers related to the extreme weather conditions that occurred in February 2021. See Note 26, Regulatory Environment, in our 2022 Annual Report on Form 10-K for more information on the 2023 rate orders.

Investing Activities

Net cash used in investing activities increased $929.7 million during the first quarter of 2023, compared with the same quarter in 2022, driven by:

• The acquisition of a 90% ownership interest in Sapphire Sky in February 2023 for $442.6 million, net of cash acquired of $0.3 million. See Note 2, Acquisitions, for more information.

• The acquisition of an 80% ownership interest in Samson I in February 2023 for $249.4 million, net of cash acquired of $5.2 million. See Note 2, Acquisitions, for more information.

• A $115.9 million increase in cash paid for capital expenditures during the first quarter of 2023, which is discussed in more detail below.

• The acquisition of Whitewater in January 2023 for $76.0 million. See Note 2, Acquisitions, for more information.

• Insurance proceeds of $41.0 million received during the first quarter of 2022 for property damage, primarily related to the Public Service Building water damage claim.

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Capital Expenditures

Capital expenditures by segment for the three months ended March 31 were as follows:

Reportable Segment (in millions)						2023						2022						Change in 2023 Over 2022
Wisconsin						$	375.0					$	254.8					$	120.2
Illinois						90.8						98.6						(7.8)
Other states						14.9						11.5						3.4
Non-utility energy infrastructure						12.6						15.9						(3.3)
Corporate and other						6.1						2.7						3.4
Total capital expenditures						$	499.4					$	383.5					$	115.9

The increase in cash paid for capital expenditures at the Wisconsin segment during the first quarter of 2023, compared with the same quarter of 2022, was driven by higher payments related to the new natural gas-fired generation being constructed at WPS's existing Weston power plant site, upgrades to WE's electric and natural gas distribution systems, and the construction of WG's LNG facility.

The decrease in cash paid for capital expenditures at the Illinois segment during the first quarter of 2023, compared with the same quarter of 2022, was driven by lower payments related to PGL's AMI program.

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

Financing Activities

Net cash related to financing activities increased $1,124.1 million during the first quarter of 2023, compared with the same quarter in 2022, driven by:

• A $1,100.0 million increase in cash due to issuances of long-term debt during the first quarter of 2023. We did not issue any long-term debt during the first quarter of 2022.

• A $62.5 million increase in cash due to lower net repayments of commercial paper during the first quarter of 2023, compared with the same quarter in 2022.

• A $16.5 million increase in cash due to a decrease in common stock purchased during the first quarter of 2023, compared with the same quarter in 2022, to satisfy requirements of our stock-based compensation plans.

These increases in cash were partially offset by:

• A $19.8 million decrease in cash due to higher retirements of long-term debt during the first quarter of 2023, compared with the same quarter in 2022.

• A $16.5 million decrease in cash due to higher dividends paid on our common stock during the first quarter of 2023, compared with the same quarter in 2022. In January 2023, our Board of Directors increased our quarterly dividend by $0.0525 per share (7.2%) effective with the March 2023 dividend payment.

• A $10.9 million decrease in cash proceeds related to stock options exercised during the first quarter of 2023, compared with the same quarter in 2022.

Significant Financing Activities

For more information on our financing activities, see Note 8, Short-Term Debt and Lines of Credit, and Note 9, 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,

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and the funding of our ongoing operations. See the discussion below and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Cash Requirements in our 2022 Annual Report on Form 10-K for additional information regarding our significant cash requirements.

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 20, Commitments and Contingencies.

(in millions)						2023 (1)						2024						2025
Wisconsin						$	2,530.7					$	2,432.8					$	2,445.5
Illinois						557.1						659.5						614.0
Other states						111.8						115.0						104.7
Non-utility energy infrastructure						747.0						683.8						217.2
Corporate and other						28.1						17.0						2.7
Total						$	3,974.7					$	3,908.1					$	3,384.1

(1)This includes actual capital expenditures incurred through March 31, 2023, as well as estimated capital expenditures for the remainder of the year.

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 MWs 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 MWs 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 Solar-Battery Park, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Kenosha County, Wisconsin and once fully constructed, WE and WPS will collectively own 180 MWs of solar generation and 99 MWs 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 Solar-Battery Park, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Rock and Walworth counties, Wisconsin and once fully constructed, WE and WPS will collectively own 225 MWs of solar generation and 68 MWs 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.

• In April 2023, WPS, along with an unaffiliated utility, completed the acquisition of Red Barn, a commercially operational utility-scale wind-powered electric generating facility. The project is located in Grant County, Wisconsin and WPS owns 82 MWs of this project. WPS's share of the cost of this project was approximately $160 million.

• WE and WPS, along with an unaffiliated utility, received PSCW 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 MWs of solar generation and 149 MWs of battery

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storage of this project. 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.

• In January 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 $76.0 million.

• In February 2023, WPS, along with an unaffiliated utility, received PSCW approval to acquire a portion of West Riverside's nameplate capacity. WPS also received approval to assign the option to purchase part of West Riverside to WE. WE will acquire 100 MWs 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. WE's share of the cost of this ownership interest is expected to be approximately $102 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 MWs of capacity. If approved, our share of the cost of this ownership interest is approximately $100 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 Complaint 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 is 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.

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

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

Long-Term Debt

See Note 9, Long-Term Debt, for information regarding the changes in our outstanding long-term debt during the three months ended March 31, 2023.

Common Stock Dividends

Our current quarterly dividend rate is $0.78 per share, which equates to an annual dividend of $3.12 per share. For information related to our most recent common stock dividend declared, see Note 7, Common Equity.

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Other Significant Cash Requirements

See Note 20, Commitments and Contingencies, for information regarding our minimum future commitments related to purchase obligations for the procurement of fuel, power, and gas supply, as well as the related storage and transportation. There were no material changes to our other significant commitments outside the ordinary course of business during the three months ended March 31, 2023.

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 8, Short-Term Debt and Lines of Credit, Note 14, Guarantees, and Note 19, 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 for the remainder of 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 in our 2022 Annual Report on Form 10-K.

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, WEC Energy Group, 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 March 31, 2023, our current liabilities exceeded our current assets by $927.3 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 $1,839.6 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 8, Short-Term Debt and Lines of Credit and Note 9, Long-Term Debt, for more information about our credit facilities, commercial paper, 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. These trusts had investments consisting of fixed income and equity securities that are subject to the volatility of the stock

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market and interest rates. For more information, see Investments in Outside Trusts in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Sources of Cash in our 2022 Annual Report on Form 10-K.

Capitalization Structure

The following table shows our capitalization structure as of March 31, 2023, as well as an adjusted capitalization structure that we believe is consistent with how a majority of the rating agencies currently view our 2007 Junior Notes:

(in millions)						Actual						Adjusted
Common shareholders' equity						$	11,636.6					$	11,886.6
Preferred stock of subsidiary						30.4						30.4
Long-term debt (including current portion)						16,635.5						16,385.5
Short-term debt						1,261.2						1,261.2
Total capitalization						$	29,563.7					$	29,563.7
Total debt						$	17,896.7					$	17,646.7
Ratio of debt to total capitalization						60.5		%				59.7		%

Included in long-term debt on our balance sheet as of March 31, 2023, 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 March 31, 2023, 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, in our 2022 Annual Report on Form 10-K, for more information regarding our debt covenants.

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 March 31, 2023. 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 March 31, 2023, 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.

On May 2, 2023, S&P Global Inc. affirmed WEC Energy Group’s ratings and revised its outlook to negative from stable, citing weakening financial measures. The ratings outlooks on our utilities remain stable. We do not believe the change in ratings outlook at WEC Energy Group will have a material impact on our ability to access capital markets.

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

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity, and capital resources. This discussion should be read together with the information in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources in our 2022 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, competitive markets, environmental matters, critical accounting policies and estimates, and other matters.

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 Accounting Standard Codification. 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 5, Regulatory Assets and Liabilities, for more information on our regulatory assets and liabilities.

In January 2014, the ICC approved PGL's use of the QIP rider as a recovery mechanism for costs incurred related to investments in QIP. This rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2023, PGL filed its 2022 reconciliation with the ICC, which, along with the reconciliations from 2016 through 2021, are still pending. As of March 31, 2023, 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 22, Regulatory Environment, in this report, and Note 26, Regulatory Environment, in our 2022 Annual Report on Form 10-K 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 recent petition by several utilities to reopen or rehear the case expired without action by the PSCW. The second petition is also currently being considered. Although the finding in the first petition was limited to the specific facts and circumstances of the lease presented in that petition, similar findings or a broader policy position could adversely impact our business operations.

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Climate and Equitable Jobs Act

On September 15, 2021, the state of Illinois signed into law the Climate and Equitable Jobs Act. This 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.

In accordance with the new legislation, effective January 1, 2023, natural gas utilities are no longer allowed to charge late payment fees to certain 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, long-term impact the UFLPA will have on the overall supply of solar panels into the United States and the related long-term impact to timing and cost of solar projects included in our capital plan. However, we are seeing some delays in the release of solar panels by the CBP, which are having an impact on the timing of certain of our solar projects.

United States Department of Commerce Complaints

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. The petitioners claimed that Chinese solar manufacturers are shifting products to these countries to avoid the tariffs required on products imported from China 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 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. If the DOC makes a final determination, which is currently expected in the second quarter of 2023, that such circumvention is occurring it would be able to apply any final tariffs retroactively to November 4, 2021. If imposed, the new tariffs could further disrupt the supply of solar modules to the United States, and could impact the cost and timing of our solar projects.

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

Infrastructure Investment and Jobs Act

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

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Inflation Reduction Act

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

Return on Equity Incentive for Membership in a Transmission Organization

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

American Transmission Company Allowed Return on Equity Complaints

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

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

First Return on Equity Complaint

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

• Orders Issued by the FERC

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

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

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

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

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

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

◦August 2022 Decision – Since several petitions for review were filed with the D.C. Circuit Court of Appeals concerning this ROE complaint, the D.C. Circuit Court of Appeals issued an opinion on August 9, 2022 addressing these petitions. In its August 2022 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 March 31, 2023, 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.

Environmental Matters

See Note 20, Commitments and Contingencies, for a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change.

Market Risks and Other Significant Risks

We are exposed to market and other significant risks as a result of the nature of our businesses and the environments in which those businesses operate. These risks include, but are not limited to, the inflation and supply chain disruptions described below. In addition, there is continuing uncertainty over the impact that the ongoing conflict between Russia and Ukraine will have on the global economy, supply chains, and fuel prices. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in our 2022 Annual Report on Form 10-K for a discussion of market and other significant risks applicable to us.

Inflation and Supply Chain Disruptions

We continue to monitor the impact of inflation and supply chain disruptions. We monitor the costs of medical plans, fuel, transmission access, construction costs, regulatory and environmental compliance costs, and other costs in order to minimize inflationary effects in future years, to the extent possible, through pricing strategies, productivity improvements, and cost

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reductions. We monitor the global supply chain, and related disruptions, in order to ensure we are able to procure the necessary materials and other resources necessary to both maintain our energy services in a safe and reliable manner and to grow our infrastructure in accordance with our capital plan. For additional information concerning risks related to inflation and supply chain disruptions, see the three risk factors below that are disclosed in Part I of our 2022 Annual Report on Form 10-K.

• 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.

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