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

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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 2024 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 ATC (a for-profit electric transmission company regulated by the FERC and certain state regulatory commissions), and non-utility energy infrastructure operations through We Power (which owns generation assets in Wisconsin that it leases to WE), Bluewater (which owns underground natural gas storage facilities in Michigan), and 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 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 capital plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables and reliable, efficient natural gas-fired generation. The retirements are intended to address compliance with the EPA Clean Air rules as well as contribute to meeting our goals to reduce CO2 emissions from our electric generation. When taken together, the retirements and new investments in renewables and reliable, efficient natural gas generation should better balance our supply with our demand, while helping to address compliance and maintaining reliable, affordable energy for our customers.

In the third quarter of 2025, we made a decision to reconsider our near-term CO2 emission reduction goals due to a combination of factors, including tightened energy supply requirements in the Midwest power market and the need to serve our customers with safe, reliable, and affordable energy. However, our long-term goal to achieve net carbon neutral electric generation by 2050 remains intact. We expect to achieve this goal by continuing to make operating refinements, retiring less efficient generating units, and executing our capital plan. As part of our path toward this goal, we have started implementing co-firing with natural gas at the ERGS coal-fired units and plan to begin testing co-firing with natural gas at Weston Unit 4 in 2025. We expect to use coal only as a backup fuel by the end of 2030 and to be in a position to eliminate coal as an energy source by the end of 2032.

We have already retired nearly 2,500 MWs of fossil-fueled generation since the beginning of 2018, which includes the retirement of OCPP Units 5 and 6 in May 2024, the 2019 retirement of the PIPP, and the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater Unit 4 generating unit. We expect to retire approximately 1,200 MWs of additional coal-fired generation by the end of 2031, which includes the planned retirements of OCPP Units 7 and 8, the jointly-owned Columbia Units 1 and 2, and Weston Unit 3. See Note 6, Property, Plant, and Equipment, for more information related to planned power plant retirements.

In addition to retiring these older, fossil-fueled plants, we expect to invest approximately $9.1 billion from 2025-2029 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 investments:

2,900 MWs of utility-scale solar;
900 MWs of wind; and
565 MWs of battery storage.


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

1,100 MWs of combustion turbines to be constructed at our OCPP site (we plan on constructing a new natural gas lateral pipeline to support this generation); with
An additional 675 MWs of combustion turbines planned; and
128 MWs of RICE natural gas-fueled generation to be constructed in Kenosha County; with
An additional 114 MWs of RICE natural gas-fueled generation planned.

For more details on the projects discussed above, 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 30 Solar Now projects, totaling more than 30 MWs. The second program, the DRER pilot, is designed to allow large commercial and industrial customers to access renewable resources that WE would operate. The DRER pilot is intended to help these larger customers meet their sustainability and renewable energy goals, and could add up to 35 MWs of renewables to WE's portfolio. WE has signed up one customer under this program for 4 MWs of generation capacity. In July 2023, the PSCW approved the Renewable Pathway Pilot, the third renewable energy program. This program allows WE and WPS commercial and industrial customers to subscribe to a portion of a utility-scale Wisconsin-based renewable energy generating facility for up to 125 MWs at WE and 40 MWs at WPS. Under this program, WE and WPS have collectively signed up ten customers, for a total of approximately 52 MWs of generation capacity.

In August 2021, the PSCW approved pilot programs for WE and WPS to install and maintain EV charging equipment for customers at their homes or businesses. We proposed modifications to these pilot programs, which were approved by the PSCW and implemented on January 1, 2025. 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 focus on methane emission reductions by improving and upgrading our natural gas distribution systems, and using RNG throughout our natural gas utility systems. In 2022, we received approval from the PSCW for our RNG pilots and in 2023, we began transporting the output of local dairy farms onto our natural gas distribution systems in Wisconsin. The RNG supplied is expected to directly replace higher-emission methane from natural gas that would have entered our pipes. We currently have contracts in place for 2.1 Bcf of RNG. In light of our progress, significant uncertainty surrounding the market for renewable thermal credits, and our desire to focus on long-term GHG emissions-reduction across the enterprise, in the third quarter of 2025, we made a decision to reassess our previous, standalone goal related to methane emissions from natural gas distribution.

In December 2023, we started a pilot program with Electric Power Research Institute and CMBlu Energy, a Germany-based designer and manufacturer of an organic solid flow battery, to test this new form of long-duration energy storage on the U.S. electric grid at our VAPP. 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. We expect the pilot activities to continue throughout 2025.

Reliability

We have made significant reliability-related investments in recent years, and in accordance with our capital 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.

On July 17, 2025, the PSCW verbally approved WE's request to construct an LNG facility with a storage capacity of two Bcf, which will be located on the OCPP site. In addition, the construction of additional LNG facilities in Wisconsin has been proposed as part of our capital plan and would provide another approximately four Bcf of natural gas supply. The LNG facilities are expected to reduce the likelihood of constraints on our natural gas distribution system during the highest demand days of winter.


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PGL had been working to replace 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. In November 2023, the ICC ordered PGL to pause spending on these projects until the ICC completed a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level. The ICC subsequently granted PGL a limited-scope rehearing related to the completion of the projects that started in 2023 and emergency repairs needed to ensure the safety and reliability of the delivery system. In May 2024, the ICC issued a written order on the rehearing, approving $28.5 million of additional spending for this emergency work.

In February 2025, the ICC issued an order setting expectations for PGL's prospective replacement of its aging natural gas infrastructure. The ICC directed us to focus on replacing all cast and ductile iron pipe that has a diameter of less than 36 inches by January 1, 2035. PGL will replace this cast and ductile iron pipe through its PRP. For more information, see Note 23, Regulatory Environment, and Factors Affecting Results, Liquidity, and Capital Resources - Regulatory, Legislative, and Legal Matters - Illinois Proceedings.

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

We expect to spend approximately $4.5 billion from 2025 to 2029 on reliability related to electric distribution projects with continued investment over the next decade. For more details, see Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.

Operating Efficiency

We continually look for ways to optimize the operating efficiency of our company and will continue to do so under our capital plan. For example, we are making progress on our AMI 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 improving our business processes to find the best and most efficient processes possible. We expect these efforts to continue to drive operational efficiency and to put us in a position to effectively support plans for future growth.

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 planned investment focus from 2025 to 2029 is in our regulated utilities and our investment in ATC. We expect total capital expenditures for our regulated utility businesses to be approximately $24.4 billion from 2025 to 2029. In addition, we currently forecast that our share of ATC's projected capital expenditures over the next five years will be approximately $3.2 billion. In February 2025, we invested $406.1 million in our non-utility energy infrastructure business with the acquisition of Hardin III. Specific projects included in the $28.0 billion capital plan are discussed in more detail below under Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects. Also, see Note 2, Acquisitions, for additional information on the acquisition of Hardin III.

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.


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

Safety

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

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

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

RESULTS OF OPERATIONS

THREE MONTHS ENDED JUNE 30, 2025

Consolidated Earnings

The following table compares our consolidated results for the second quarter of 2025 with the second quarter of 2024, including favorable or better, "B", and unfavorable or worse, "W", variances:


	Three Months Ended June 30
(in millions, except per share data)	2025		2024		B (W)
Wisconsin	$	182.4	$	132.1	$	50.3
Illinois	22.6		25.7		(3.1)
Other states	3.5		0.6		2.9
Electric transmission	35.6		31.4		4.2
Non-utility energy infrastructure	82.3		93.3		(11.0)
Corporate and other	(81.0)		(71.8)		(9.2)
Net income attributed to common shareholders	$	245.4	$	211.3	$	34.1

Diluted EPS	$	0.76	$	0.67	$	0.09

Earnings increased $34.1 million during the second quarter of 2025, compared with the same quarter in 2024. The $34.1 million increase in earnings was driven by a $50.3 million increase in net income attributed to common shareholders at the Wisconsin segment, primarily due to higher margins from the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2025, and higher retail sales volumes. See Note 26, Regulatory Environment, in our 2024 Annual Report on Form 10-K, for more information on the 2025 rate orders. These positive impacts were partially offset by higher operating expenses, primarily due to increases in depreciation and amortization expense, transmission expense, and regulatory amortizations.

This increase in earnings was partially offset by:

An $11.0 million decrease in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by lower operating income at WECI. An increase in PTCs from our non-utility renewable generating facilities partially offset the lower operating income.
A $9.2 million increase in the net loss attributed to common shareholders at the corporate and other segment, driven by higher interest expense primarily due to the impact of long-term debt issuances at WEC Energy Group.


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Non-GAAP Financial Measures

The discussions below address the contribution of each of our utility segments to net income attributed to common shareholders. The discussions include financial information prepared in accordance with GAAP, as well as utility margin, which is not a measure of financial performance under GAAP. Utility margin (operating revenues less fuel and purchased power costs and cost of natural gas sold) is a non-GAAP financial measure because it excludes certain operation and maintenance expenses applicable to revenues, as well as depreciation and amortization and property and revenue taxes.

We believe that utility margin provides 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 utility margin internally when assessing the operating performance of our utility segments as these measures exclude the majority of revenue fluctuations caused by changes in these expenses. Similarly, the presentation of utility margin herein is intended to provide supplemental information for investors regarding our operating performance.

Our utility margin may not be comparable to similar measures presented by other companies. Furthermore, this measure is not intended to replace gross margin as determined in accordance with GAAP as an indicator of operating performance. Each of our three utility segment discussions below include a table that provides the calculation of both gross margin as determined in accordance with GAAP and utility margin, as well as a reconciliation between the two measures.

Wisconsin Segment Contribution to Net Income Attributed to Common Shareholders

The Wisconsin segment's contribution to net income attributed to common shareholders was $182.4 million during the second quarter of 2025, representing a $50.3 million, or 38.1%, increase over the same quarter in 2024. The increase in earnings was driven by higher margins from the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2025, and higher retail sales volumes. See Note 26, Regulatory Environment, in our 2024 Annual Report on Form 10-K, for more information on the 2025 rate orders. These positive impacts were partially offset by higher operating expenses, primarily due to increases in depreciation and amortization expense, transmission expense, and regulatory amortizations.


	Three Months Ended June 30
(in millions)	2025		2024		B (W)
Operating revenues	$	1,587.2	$	1,368.2	$	219.0

Operating expenses
Cost of sales (1)	520.2		414.0		(106.2)
Other operation and maintenance	416.0		389.2		(26.8)
Depreciation and amortization	250.2		228.3		(21.9)
Property and revenue taxes	44.5		44.9		0.4
Operating income	356.3		291.8		64.5

Other income, net	19.8		32.3		(12.5)
Interest expense	157.9		157.3		(0.6)
Income before income taxes	218.2		166.8		51.4

Income tax expense	35.5		34.4		(1.1)
Preferred stock dividends of subsidiary	0.3		0.3		—
Net income attributed to common shareholders	$	182.4	$	132.1	$	50.3

(1) Cost of sales includes fuel and purchased power and cost of natural gas sold.


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


	Three Months Ended June 30
(in millions)	2025		2024		B (W)
Operation and maintenance not included in line items below	$	177.1	$	169.5	$	(7.6)
Transmission (1)	147.0		135.7		(11.3)
Regulatory amortizations and other pass through expenses (2)	61.2		51.7		(9.5)
We Power (3)	32.5		33.1		0.6
Earnings sharing mechanisms	(1.8)		(0.8)		1.0
Total other operation and maintenance	$	416.0	$	389.2	$	(26.8)

(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 second quarter of 2025 and 2024, $159.9 million and $140.0 million, respectively, of costs were billed to our electric utilities by transmission providers.

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

(3)Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE. During the second quarter of 2025 and 2024, $32.9 million and $29.3 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.

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


	Three Months Ended June 30
	MWh (in thousands)
Electric Sales Volumes	2025	2024	B (W)
Customer Class
Residential	2,564.5	2,522.9	41.6
Small commercial and industrial (1)	3,138.7	3,118.9	19.8
Large commercial and industrial (1)	3,003.1	2,982.4	20.7
Other	24.9	26.5	(1.6)
Total retail (1)	8,731.2	8,650.7	80.5
Wholesale	417.7	402.0	15.7
Resale	1,507.1	1,322.3	184.8
Total sales in MWh (1)	10,656.0	10,375.0	281.0

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


	Three Months Ended June 30
	Therms (in millions)
Natural Gas Sales Volumes	2025	2024	B (W)
Customer Class
Residential	155.3	129.8	25.5
Commercial and industrial	109.1	91.4	17.7
Total retail	264.4	221.2	43.2
Transportation	303.1	294.0	9.1
Total sales in therms	567.5	515.2	52.3


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	Three Months Ended June 30
	Degree Days
Weather	2025	2024	B (W)
WE and WG (1)
Heating (874 Normal)	1,013	631	60.5	%
Cooling (182 Normal)	176	202	(12.9)	%

WPS (2)
Heating (919 Normal)	888	760	16.8	%
Cooling (157 Normal)	160	142	12.7	%

UMERC (3)
Heating (1,164 Normal)	1,166	1,088	7.2	%
Cooling (88 Normal)	102	57	78.9	%

(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.

Gross Margin GAAP and Utility Margin Non-GAAP

The following table summarizes our Wisconsin segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See "Non-GAAP Financial Measures" above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).


	Three Months Ended June 30
(in millions)	2025		2024		B (W)
Electric revenues	$	1,308.0	$	1,151.0	$	157.0
Natural gas revenues	279.2		217.2		62.0
Operating revenues	1,587.2		1,368.2		219.0

Operating expenses
Fuel and purchased power	(391.8)		(332.3)		(59.5)
Cost of natural gas sold	(128.4)		(81.7)		(46.7)
Other operation and maintenance (1)	(310.1)		(289.8)		(20.3)
Depreciation and amortization	(250.2)		(228.3)		(21.9)
Property and revenue taxes	(44.5)		(44.9)		0.4
Gross margin (GAAP)	462.2		391.2		71.0

Other operation and maintenance (1)	310.1		289.8		20.3
Depreciation and amortization	250.2		228.3		21.9
Property and revenue taxes	44.5		44.9		(0.4)
Utility margin (non-GAAP)	$	1,067.0	$	954.2	$	112.8

(1) Operating and maintenance expenses deemed to be directly attributable to our revenue-producing activities include plant operating and maintenance expenses related to our generating units; costs associated with the We Power generating units; and transmission, distribution and customer service expenses. These expenses are included in the above table to calculate gross margin as defined under GAAP.


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Gross margin (GAAP) at the Wisconsin segment increased $71.0 million during the second quarter of 2025, compared with the same quarter in 2024, and utility margin (non-GAAP) increased $112.8 million during the second quarter of 2025, compared with the same quarter in 2024. Both measures were driven by:

An $87.9 million increase in margins driven by the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2025. See Note 26, Regulatory Environment, in our 2024 Annual Report on Form 10-K, for more information on the 2025 rate orders.
A $19.6 million increase in margins related to higher retail sales volumes, driven by the impact of colder spring weather during the second quarter of 2025, compared with the same quarter in 2024. As measured by heating degree days, the second quarter of 2025 was 60.5% and 16.8% colder than the same quarter in 2024 in the Milwaukee area and Green Bay area, respectively.
A $3.7 million quarter-over-quarter positive impact from collections of fuel and purchased power costs. 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 above or below the 2% is generally deferred for either future recovery from or refund to customers.

Additionally, the smaller increase in gross margin (GAAP) as compared with the increase in utility margin (non-GAAP), was driven by the following items that are further described in Other Operating Expenses below:

A $21.9 million increase in depreciation and amortization expense;
An $11.3 million increase in transmission expense; and
A $6.3 million increase in electric and natural gas distribution expenses.

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

Other operating expenses at the Wisconsin segment increased $48.3 million during the second quarter of 2025, compared with the same quarter in 2024. The significant factors impacting the increase in other operating expenses were:

A $21.9 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.
An $11.3 million increase in transmission expense as approved by the PSCW in our Wisconsin rate orders, effective January 1, 2025. See the notes under the other operation and maintenance table above for more information.
A $9.5 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.
A $6.3 million increase in electric and natural gas distribution expenses, driven by higher costs to maintain the distribution systems during the second quarter of 2025, compared with the same quarter in 2024.

Other Income, Net

Other income, net at the Wisconsin segment decreased $12.5 million during the second quarter of 2025, compared with the same quarter in 2024, driven by a $21.5 million negative impact from the non-service components of our net periodic pension and OPEB costs. See Note 16, Employee Benefits, for more information on our benefit costs. This decrease was partially offset by an $8.9 million positive impact from higher AFUDC-Equity due to continued capital investment.

Interest Expense

Interest expense at the Wisconsin segment increased $0.6 million during the second quarter of 2025, compared with the same quarter in 2024, driven by the impact of WE, WPS, and WG issuing long-term debt in 2024. Partially offsetting the increase was lower


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average short-term debt balances, lower short-term debt interest rates, and higher AFUDC-Debt due to continued capital investment.

Income Tax Expense

Income tax expense at the Wisconsin segment increased $1.1 million during the second quarter of 2025, compared with the same quarter in 2024, driven by higher pre-tax income. Partially offsetting this increase was an increase in PTCs, an increase in income tax benefits associated with AFUDC-Equity, driven by continued capital investment, and the increased benefit from the flow through of tax repairs in connection with the Wisconsin rate orders approved by the PSCW, effective January 1, 2025.

Illinois Segment Contribution to Net Income Attributed to Common Shareholders

The Illinois segment's contribution to net income attributed to common shareholders was $22.6 million during the second quarter of 2025, representing a $3.1 million, or 12.1%, decrease in earnings over the same quarter in 2024. The lower earnings were driven by higher operating expenses, largely due to an increase in costs associated with maintenance at the Manlove Gas Storage Field.

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


	Three Months Ended June 30
(in millions)	2025		2024		B (W)
Operating revenues	$	270.6	$	276.8	$	(6.2)

Operating expenses
Cost of natural gas sold	29.5		41.8		12.3
Other operation and maintenance	112.4		102.6		(9.8)
Depreciation and amortization	64.8		63.7		(1.1)
Property and revenue taxes	12.8		11.6		(1.2)
Operating income	51.1		57.1		(6.0)

Other income, net	2.3		2.3		—
Interest expense	22.1		23.5		1.4
Income before income taxes	31.3		35.9		(4.6)

Income tax expense	8.7		10.2		1.5
Net income attributed to common shareholders	$	22.6	$	25.7	$	(3.1)

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


	Three Months Ended June 30
(in millions)	2025		2024		B (W)
Operation and maintenance not included in the line items below	$	78.4	$	75.3	$	(3.1)
Riders (1)	33.3		26.6		(6.7)
Regulatory amortizations (1)	0.7		0.7		—


Total other operation and maintenance	$	112.4	$	102.6	$	(9.8)

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


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


	Three Months Ended June 30
	Therms (in millions)
Natural Gas Sales Volumes	2025	2024	B (W)
Customer Class
Residential	122.6	104.3	18.3
Commercial and industrial	41.2	37.8	3.4
Total retail	163.8	142.1	21.7
Transportation	132.6	118.5	14.1
Total sales in therms	296.4	260.6	35.8


	Three Months Ended June 30
	Degree Days
Weather (1)	2025	2024	B (W)
Heating (697 Normal)	698	450	55.1	%

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

Gross Margin GAAP and Utility Margin Non-GAAP

The following table summarizes our Illinois segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See "Non-GAAP Financial Measures" above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).


	Three Months Ended June 30
(in millions)	2025		2024		B (W)
Operating revenues	$	270.6	$	276.8	$	(6.2)

Operating expenses
Cost of natural gas sold	(29.5)		(41.8)		12.3
Other operation and maintenance (1)	(63.3)		(56.1)		(7.2)
Depreciation and amortization	(64.8)		(63.7)		(1.1)
Property and revenue taxes	(12.8)		(11.6)		(1.2)
Gross margin (GAAP)	100.2		103.6		(3.4)

Other operation and maintenance (1)	63.3		56.1		7.2
Depreciation and amortization	64.8		63.7		1.1
Property and revenue taxes	12.8		11.6		1.2
Utility margin (non-GAAP)	$	241.1	$	235.0	$	6.1

(1) Operating and maintenance expenses deemed to be directly attributable to our revenue-producing activities include distribution and customer service expenses. These expenses are included in the above table to calculate gross margin as defined under GAAP.

Gross margin (GAAP) at the Illinois segment decreased $3.4 million during the second quarter of 2025, compared with the same quarter in 2024, and utility margin (non-GAAP) increased $6.1 million during the second quarter of 2025, compared with the same quarter in 2024. Both measures were impacted by a $6.7 million increase in revenues associated with certain riders that are offset in other operation and maintenance and therefore do not have a significant impact on net income.

Additionally, the decrease in gross margin (GAAP) as compared with the increase in utility margin (non-GAAP), was driven by the following items that are further described in Other Operating Expenses below:

A $4.8 million increase in costs associated with maintenance at the Manlove Gas Storage Field;

*•*A $1.5 million increase in natural gas distribution and maintenance costs;


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A $1.2 million increase in property and revenue taxes; and

*•*A $1.1 million increase in depreciation and amortization.

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

Other operating expenses at the Illinois segment increased $5.4 million, net of the $6.7 million impact of the riders referenced in the table above, during the second quarter of 2025, compared with the same quarter in 2024. The significant factors impacting the increase in other operating expenses were:

A $4.8 million increase in costs associated with maintenance at the Manlove Gas Storage Field.

*•*A $1.5 million increase in natural gas distribution and maintenance costs, primarily related to maintaining the natural gas infrastructure.

A $1.2 million increase in property and revenue taxes, driven by higher use taxes.

*•*A $1.1 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan.

These increases in operating expenses were partially offset by a $2.2 million pre-tax gain on the renegotiation of a lease contract during the second quarter of 2025.

Interest Expense

Interest expense at the Illinois segment decreased $1.4 million during the second quarter of 2025, compared with the same quarter in 2024, due to lower average short-term debt balances, lower short-term debt interest rates, and the impact of a series of PGL's first mortgage bonds maturing in November 2024.

Income Tax Expense

Income tax expense at the Illinois segment decreased $1.5 million during the second quarter of 2025, compared with the same quarter in 2024, driven by a decrease in pre-tax income.

Other States Segment Contribution to Net Income Attributed to Common Shareholders

The other states segment's net income attributed to common shareholders was $3.5 million during the second quarter of 2025, representing a $2.9 million, or 483.3%, increase over the same quarter in 2024. The increase was driven by higher margins related to positive impacts from MGU's approved rate increase that was effective January 1, 2025 and MERC's rate increase that was effective March 1, 2024.


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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 June 30
(in millions)	2025		2024		B (W)
Operating revenues	$	82.3	$	71.0	$	11.3

Operating expenses
Cost of natural gas sold	30.0		23.8		(6.2)
Other operation and maintenance	23.9		24.6		0.7
Depreciation and amortization	12.3		11.5		(0.8)
Property and revenue taxes	6.8		6.3		(0.5)
Operating income	9.3		4.8		4.5

Other income, net	0.1		0.1		—
Interest expense	4.7		4.0		(0.7)
Income before income taxes	4.7		0.9		3.8

Income tax expense	1.2		0.3		(0.9)
Net income attributed to common shareholders	$	3.5	$	0.6	$	2.9

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


	Three Months Ended June 30
(in millions)	2025		2024		B (W)
Operation and maintenance not included in line item below	$	19.2	$	18.9	$	(0.3)
Regulatory amortizations and other pass through expenses (1)	4.7		5.7		1.0

Total other operation and maintenance	$	23.9	$	24.6	$	0.7

(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 June 30
	Therms (in millions)
Natural Gas Sales Volumes	2025	2024	B (W)
Customer Class
Residential	42.1	34.9	7.2
Commercial and industrial	26.2	25.9	0.3
Total retail	68.3	60.8	7.5
Transportation	168.3	187.7	(19.4)
Total sales in therms	236.6	248.5	(11.9)


	Three Months Ended June 30
	Degree Days
Weather (1)	2025	2024	B (W)
MERC
Heating (941 Normal)	892	817	9.2	%

MGU
Heating (772 Normal)	817	524	55.9	%

(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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Gross Margin GAAP and Utility Margin Non-GAAP

The following table summarizes our other states segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See "Non-GAAP Financial Measures" above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).


	Three Months Ended June 30
(in millions)	2025		2024		B (W)
Operating revenues	$	82.3	$	71.0	$	11.3

Operating expenses
Cost of natural gas sold	(30.0)		(23.8)		(6.2)
Other operation and maintenance (1)	(15.0)		(14.8)		(0.2)
Depreciation and amortization	(12.3)		(11.5)		(0.8)
Property and revenue taxes	(6.8)		(6.3)		(0.5)
Gross margin (GAAP)	18.2		14.6		3.6

Other operation and maintenance (1)	15.0		14.8		0.2
Depreciation and amortization	12.3		11.5		0.8
Property and revenue taxes	6.8		6.3		0.5
Utility margin (non-GAAP)	$	52.3	$	47.2	$	5.1

Gross margin (GAAP) increased $3.6 million during the second quarter of 2025, compared with the same quarter in 2024, and utility margin (non-GAAP) increased $5.1 million during the second quarter of 2025, compared with the same quarter in 2024. Both measures were driven by:

A $3.2 million increase related to MGU's approved rate increase that was effective January 1, 2025, and MERC's rate increase that was effective March 1, 2024.
A $0.8 million increase related to MERC CIP revenue, which was offset in operation and maintenance expense. Rebates and programs are available to residential and commercial customers of MERC through the CIP, which is funded by rate payers using the Conservation Cost Recovery Charge and the Conservation Cost Recovery Adjustment funds that are collected on their monthly billing statements.

Additionally, the lower increase in gross margin (GAAP) as compared to the increase in utility margin (non-GAAP), was driven by a $0.8 million increase in depreciation and amortization expense that is further described in Other Operating Expenses below.

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 $0.6 million during the second quarter of 2025, compared with the same quarter in 2024. The significant factors impacting the increase in operating expenses were:

A $0.8 million increase in depreciation and amortization expense related to continued capital investment.
A $0.8 million increase in operation and maintenance expense related to MERC's CIP program, which has an offsetting increase in margins.

These increases in other operating expenses were partially offset by a $1.4 million decrease in bad debt expense, primarily due to an increase in MGU's reserve in 2024 due to aging arrears.


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Interest Expense

Interest expense at the other states segment increased $0.7 million during the second quarter of 2025, compared with the same quarter in 2024, driven by the impact of MERC issuing long-term debt in April 2025 and MGU issuing long-term debt in October 2024 and April 2025.

Income Tax Expense

Income tax expense at the other states segment increased $0.9 million during the second quarter of 2025, compared with the same quarter in 2024, driven by higher pre-tax income.

Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders


	Three Months Ended June 30
(in millions)	2025		2024		B (W)
Equity in earnings of transmission affiliates	$	51.9	$	46.8	$	5.1
Interest expense	4.9		4.9		—
Income before income taxes	47.0		41.9		5.1

Income tax expense	11.4		10.5		(0.9)
Net income attributed to common shareholders	$	35.6	$	31.4	$	4.2

Equity in Earnings of Transmission Affiliates

Equity in earnings of transmission affiliates increased $5.1 million during the second quarter of 2025, compared with the same quarter in 2024. This increase was primarily due to continued capital investment by ATC.

Income Tax Expense

Income tax expense at the electric transmission segment increased $0.9 million during the second quarter of 2025, compared with the same quarter in 2024, driven by higher pre-tax income.

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


	Three Months Ended June 30
(in millions)	2025		2024		B (W)
Operating income	$	71.5	$	95.4	$	(23.9)

Other income, net	0.7		0.2		0.5
Interest expense	31.5		24.1		(7.4)
Income before income taxes	40.7		71.5		(30.8)

Income tax benefit	(38.9)		(20.2)		18.7
Net loss attributed to noncontrolling interests	2.7		1.6		1.1
Net income attributed to common shareholders	$	82.3	$	93.3	$	(11.0)

Operating Income

Operating income at the non-utility energy infrastructure segment decreased $23.9 million during the second quarter of 2025, compared with the same quarter in 2024, driven by these items at WECI:

A $15.2 million negative impact related to the receipt of performance payments in 2024.
An $11.6 million impairment loss recorded at our Samson I and Delilah I solar facilities related to damage incurred associated with various storms. See Note 6, Property, Plant, and Equipment, for more information.


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A $5.2 million increase in operation and maintenance expenses due primarily to a higher number of equipment repairs at our renewable generation facilities.

These decreases in operating income were partially offset by a $9.1 million increase in operating income from new investments in several WECI renewable generation facilities made in late 2024 and early 2025.

Interest Expense

Interest expense at the non-utility energy infrastructure segment increased $7.4 million during the second quarter of 2025, compared with the same quarter in 2024, driven by the impact of WECI Energy Holding III issuing long-term debt in December 2024.

Income Tax Benefit

The income tax benefit at the non-utility energy infrastructure segment increased $18.7 million during the second quarter of 2025, compared with the same quarter in 2024, due to an increase in PTCs that was related to the acquisition of additional renewable generation facilities and an IRS approved PTC rate increase, partially offset by lower production volumes. Also contributing to the favorable income tax variance was lower pre-tax income.

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


	Three Months Ended June 30
(in millions)	2025		2024		B (W)
Operating loss	$	(2.5)	$	(1.4)	$	(1.1)

Other income, net	11.6		12.5		(0.9)
Interest expense	88.5		76.5		(12.0)

Loss before income taxes	(79.4)		(65.4)		(14.0)

Income tax expense	1.6		6.4		4.8
Net loss attributed to common shareholders	$	(81.0)	$	(71.8)	$	(9.2)

Interest Expense

Interest expense at the corporate and other segment increased $12.0 million during the second quarter of 2025, compared with the same quarter in 2024, due to the impact of long-term debt issuances by WEC Energy Group in June 2024, December 2024, and June 2025. Partially offsetting this increase in interest expense was lower average short-term debt balances and lower average short-term interest rates.

Income Tax Expense

Income tax expense at the corporate and other segment decreased $4.8 million during the second quarter of 2025, compared with the same quarter in 2024. This decrease was driven by a higher pre-tax loss.


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SIX MONTHS ENDED JUNE 30, 2025

Consolidated Earnings

The following table compares our consolidated results for the six months ended June 30, 2025 with the six months ended June 30, 2024, including favorable or better, "B", and unfavorable or worse, "W", variances:


	Six Months Ended June 30
(in millions, except per share data)	2025		2024		B (W)
Wisconsin	$	542.3	$	398.5	$	143.8
Illinois	200.7		213.2		(12.5)
Other states	46.6		39.2		7.4
Electric transmission	72.5		61.5		11.0
Non-utility energy infrastructure	191.1		187.6		3.5
Corporate and other	(83.6)		(66.4)		(17.2)
Net income attributed to common shareholders	$	969.6	$	833.6	$	136.0

Diluted EPS	$	3.02	$	2.64	$	0.38

Earnings increased $136.0 million during the six months ended June 30, 2025, compared with the same period in 2024. The significant factors impacting the $136.0 million increase in earnings were:

A $143.8 million increase in net income attributed to common shareholders at the Wisconsin segment, driven by higher margins from the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2025, and higher retail sales volumes. These positive impacts were partially offset by higher operating expenses, primarily due to increases in depreciation and amortization expense and transmission expense.
An $11.0 million increase in net income attributed to common shareholders at the electric transmission segment, driven by continued capital investment by ATC and a gain related to the sale of an investment at ATC Holdco in March 2025.

These increases in earnings were partially offset by:

A $17.2 million increase in the net loss attributed to common shareholders at the corporate and other segment, driven by higher interest expense and a decrease in earnings from our equity method investments in technology and energy-focused investment funds. These decreases in earnings were partially offset by a positive impact from an increase in an interim income tax benefit recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate.
A $12.5 million decrease in net income attributed to common shareholders at the Illinois segment, driven by higher operating expenses. The period-over-period impact from a favorable settlement of a legal claim during 2024 and an increase in costs associated with maintenance at the Manlove Gas Storage Field drove the higher operating expenses.

Expected 2025 Annual Effective Tax Rate

We expect our 2025 annual effective tax rate to be between 7.5% and 8.5%. Our effective tax rate calculations are revised every quarter based on the best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.

Non-GAAP Financial Measures


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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 $542.3 million during the six months ended June 30, 2025, representing a $143.8 million, or 36.1%, increase over the same period in 2024. The increase in earnings was driven by higher margins from the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2025, and higher retail sales volumes. These positive impacts were partially offset by higher operating expenses, primarily due to increases in depreciation and amortization expense and transmission expense.


	Six Months Ended June 30
(in millions)	2025		2024		B (W)
Operating revenues	$	3,647.1	$	3,147.0	$	500.1

Operating expenses
Cost of sales (1)	1,289.0		1,065.0		(224.0)
Other operation and maintenance	831.1		779.1		(52.0)
Depreciation and amortization	493.8		452.9		(40.9)
Property and revenue taxes	90.5		92.2		1.7
Operating income	942.7		757.8		184.9

Other income, net	37.4		65.7		(28.3)
Interest expense	319.7		315.1		(4.6)
Income before income taxes	660.4		508.4		152.0

Income tax expense	117.5		109.3		(8.2)
Preferred stock dividends of subsidiary	0.6		0.6		—
Net income attributed to common shareholders	$	542.3	$	398.5	$	143.8

(1) Cost of sales includes fuel and purchased power and cost of natural gas sold.

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


	Six Months Ended June 30
(in millions)	2025		2024		B (W)
Operation and maintenance not included in line items below	$	357.0	$	334.9	$	(22.1)
Transmission (1)	292.9		271.5		(21.4)
Regulatory amortizations and other pass through expenses (2)	118.8		107.7		(11.1)
We Power (3)	65.1		66.7		1.6


Earnings sharing mechanisms	(2.7)		(1.7)		1.0
Total other operation and maintenance	$	831.1	$	779.1	$	(52.0)

(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 six months ended June 30, 2025 and 2024, $308.8 million and $277.8 million, respectively, of costs were billed to our electric utilities by transmission providers.


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

(3)Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE. During the six months ended June 30, 2025 and 2024, $60.0 million and $58.8 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.

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


	Six Months Ended June 30
	MWh (in thousands)
Electric Sales Volumes	2025	2024	B (W)
Customer Class
Residential	5,361.1	5,172.8	188.3
Small commercial and industrial (1)	6,323.3	6,236.9	86.4
Large commercial and industrial (1)	5,856.6	5,866.1	(9.5)
Other	58.7	62.7	(4.0)
Total retail (1)	17,599.7	17,338.5	261.2
Wholesale	866.5	835.1	31.4
Resale	2,818.6	2,718.5	100.1
Total sales in MWh (1)	21,284.8	20,892.1	392.7

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


	Six Months Ended June 30
	Therms (in millions)
Natural Gas Sales Volumes	2025	2024	B (W)
Customer Class
Residential	703.1	590.6	112.5
Commercial and industrial	442.2	368.6	73.6
Total retail	1,145.3	959.2	186.1
Transportation	731.2	689.8	41.4
Total sales in therms	1,876.5	1,649.0	227.5


	Six Months Ended June 30
	Degree Days
Weather	2025	2024	B (W)
WE and WG (1)
Heating (4,088 Normal)	4,296	3,332	28.9	%
Cooling (182 Normal)	176	202	(12.9)	%

WPS (2)
Heating (4,518 Normal)	4,414	3,798	16.2	%
Cooling (157 Normal)	160	142	12.7	%

UMERC (3)
Heating (5,081 Normal)	5,080	4,491	13.1	%
Cooling (88 Normal)	102	57	78.9	%

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

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

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


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Gross Margin GAAP and Utility Margin Non-GAAP

The following table summarizes our Wisconsin segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See Non-GAAP Financial Measures above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).


	Six Months Ended June 30
(in millions)	2025		2024		B (W)
Electric revenues	$	2,631.6	$	2,341.6	$	290.0
Natural gas revenues	1,015.5		805.4		210.1
Operating revenues	3,647.1		3,147.0		500.1

Operating expenses
Fuel and purchased power	(782.1)		(681.5)		(100.6)
Cost of natural gas sold	(506.9)		(383.5)		(123.4)
Other operation and maintenance (1)	(604.7)		(567.8)		(36.9)
Depreciation and amortization	(493.8)		(452.9)		(40.9)
Property and revenue taxes	(90.5)		(92.2)		1.7
Gross margin (GAAP)	1,169.1		969.1		200.0

Other operation and maintenance (1)	604.7		567.8		36.9
Depreciation and amortization	493.8		452.9		40.9
Property and revenue taxes	90.5		92.2		(1.7)
Utility margin (non-GAAP)	$	2,358.1	$	2,082.0	$	276.1

Gross margin (GAAP) at the Wisconsin segment increased $200.0 million during the six months ended June 30, 2025, compared with the same period in 2024, and utility margin (non-GAAP) increased $276.1 million during the six months ended June 30, 2025, compared with the same period in 2024. Both measures were driven by:

A $198.8 million increase in margins driven by the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2025.
An $84.1 million increase in margins related to higher retail sales volumes, driven by the impact of colder weather during the six months ended June 30, 2025, compared with the same period in 2024. As measured by heating degree days, the six months ended June 30, 2025 were 28.9% and 16.2% colder than the same period in 2024 in the Milwaukee area and Green Bay area, respectively.

These increases in margins were partially offset by a $5.6 million period-over-period negative impact from collections of fuel and purchased power costs. 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 above or below the 2% is generally deferred for either future recovery from or refund to customers.

A $40.9 million increase in depreciation and amortization expense;
A $21.4 million increase in transmission expense;
A $13.0 million increase in electric and natural gas distribution expenses; and
A $5.4 million increase in other operating and maintenance related to our power plants.


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

Other operating expenses at the Wisconsin segment increased $91.2 million during the six months ended June 30, 2025, compared with the same period in 2024. The significant factors impacting the increase in other operating expenses were:

A $40.9 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.
A $21.4 million increase in transmission expense as approved by the PSCW in our Wisconsin rate orders, effective January 1, 2025. See the notes under the other operation and maintenance table above for more information.
A $13.0 million increase in electric and natural gas distribution expenses, driven by higher costs to maintain the distribution systems during the six months ended June 30, 2025, compared with the same period in 2024.
An $11.1 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.
A $5.4 million increase in other operating and maintenance related to our power plants, driven by outages at the Weston coal-fired generation facility and inspections at the Fox Energy Center natural gas-fired generation facility.

Other Income, Net

Other income, net at the Wisconsin segment decreased $28.3 million during the six months ended June 30, 2025, compared with the same period in 2024, driven by a $44.0 million negative impact from the non-service components of our net periodic pension and OPEB costs. This decrease was partially offset by a $13.3 million positive impact from higher AFUDC-Equity due to continued capital investment.

Interest Expense

Interest expense at the Wisconsin segment increased $4.6 million during the six months ended June 30, 2025, compared with the same period in 2024. The increase was primarily driven by the impact of WE, WPS, and WG issuing long-term debt in 2024. Partially offsetting the increase was lower average short-term debt balances, lower short-term debt interest rates, and higher AFUDC-Debt due to continued capital investment.

Income Tax Expense

Income tax expense at the Wisconsin segment increased $8.2 million during the six months ended June 30, 2025, compared with the same period in 2024, driven by higher pre-tax income. Partially offsetting this increase in income tax expense were higher PTCs and the increased benefit from the flow through of tax repairs in connection with the Wisconsin rate orders approved by the PSCW, effective January 1, 2025. Also reducing income tax expense were increases in the protected deferred tax benefits associated with the Tax Legislation and increases in income tax benefits associated with AFUDC-Equity, driven by continued capital investment.


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Illinois Segment Contribution to Net Income Attributed to Common Shareholders

The Illinois segment's contribution to net income attributed to common shareholders was $200.7 million during the six months ended June 30, 2025, representing a $12.5 million, or 5.9%, decrease over the same period in 2024. The decrease was driven by higher operating expenses, primarily due to the period-over-period impact from a favorable settlement of a legal claim during 2024 and an increase in costs associated with maintenance at the Manlove Gas Storage Field.


	Six Months Ended June 30
(in millions)	2025		2024		B (W)
Operating revenues	$	1,058.9	$	942.8	$	116.1

Operating expenses
Cost of natural gas sold	317.7		236.5		(81.2)
Other operation and maintenance	259.3		209.6		(49.7)
Depreciation and amortization	129.2		127.2		(2.0)
Property and revenue taxes	33.2		29.7		(3.5)
Operating income	319.5		339.8		(20.3)

Other income, net	4.4		4.2		0.2
Interest expense	45.3		48.5		3.2
Income before income taxes	278.6		295.5		(16.9)

Income tax expense	77.9		82.3		4.4
Net income attributed to common shareholders	$	200.7	$	213.2	$	(12.5)

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


	Six Months Ended June 30
(in millions)	2025		2024		B (W)
Operation and maintenance not included in the line items below	$	161.8	$	143.4	$	(18.4)
Riders (1)	96.2		64.7		(31.5)
Regulatory amortizations (1)	1.3		1.5		0.2


Total other operation and maintenance	$	259.3	$	209.6	$	(49.7)

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

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


	Six Months Ended June 30
	Therms (in millions)
Natural Gas Sales Volumes	2025	2024	B (W)
Customer Class
Residential	534.2	457.8	76.4
Commercial and industrial	194.6	174.3	20.3
Total retail	728.8	632.1	96.7
Transportation	457.4	410.3	47.1
Total sales in therms	1,186.2	1,042.4	143.8


	Six Months Ended June 30
	Degree Days
Weather (1)	2025	2024	B (W)
Heating (3,781 Normal)	3,740	3,064	22.1	%

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


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Gross Margin GAAP and Utility Margin Non-GAAP

The following table summarizes our Illinois segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See Non-GAAP Financial Measures above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).


	Six Months Ended June 30
(in millions)	2025		2024		B (W)
Operating revenues	$	1,058.9	$	942.8	$	116.1

Operating expenses
Cost of natural gas sold	(317.7)		(236.5)		(81.2)
Other operation and maintenance (1)	(121.0)		(110.1)		(10.9)
Depreciation and amortization	(129.2)		(127.2)		(2.0)
Property and revenue taxes	(33.2)		(29.7)		(3.5)
Gross margin (GAAP)	457.8		439.3		18.5

Other operation and maintenance (1)	121.0		110.1		10.9
Depreciation and amortization	129.2		127.2		2.0
Property and revenue taxes	33.2		29.7		3.5
Utility margin (non-GAAP)	$	741.2	$	706.3	$	34.9

Gross margin (GAAP) at the Illinois segment increased $18.5 million during the six months ended June 30, 2025, compared with the same period in 2024, and utility margin (non-GAAP) increased $34.9 million during the six months ended June 30, 2025, compared with the same period in 2024. Both measures were driven by:

A $31.5 million increase in revenues associated with certain riders that are offset in other operation and maintenance and therefore do not have a significant impact on net income.
A $2.2 million increase in revenues related to the impact of the NSG rate order issued by the ICC, effective February 1, 2024.

A $6.0 million increase in costs associated with maintenance at the Manlove Gas Storage Field;
A $3.7 million increase in natural gas distribution and maintenance costs;
A $3.5 million increase in property and revenue taxes; and
A $2.0 million increase in depreciation and amortization.

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

Other operating expenses at the Illinois segment increased $23.7 million, net of the $31.5 million impact of the riders referenced in the table above, during the six months ended June 30, 2025, compared with the same period in 2024. The significant factors impacting the increase in other operating expenses were:

An $11.6 million increase in expense primarily associated with the favorable settlement of a legal claim during the six months ended June 30, 2024.
A $6.0 million increase in costs associated with maintenance at the Manlove Gas Storage Field.


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A $3.7 million increase in natural gas distribution and maintenance costs, primarily related to maintaining the natural gas infrastructure.
A $3.5 million increase in property and revenue taxes, driven by an increase in property taxes and use taxes.
A $2.0 million increase in benefit costs, driven by higher stock-based compensation and deferred compensation expense.
A $2.0 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.

These increases in operating expenses were partially offset by a $2.2 million pre-tax gain on the renegotiation of a lease contract during the six months ended June 30, 2025.

Interest Expense

Interest expense at the Illinois segment decreased $3.2 million during the six months ended June 30, 2025, compared with the same period in 2024, due to lower average short-term debt balances, lower short-term debt interest rates, and the impact of a series of PGL's first mortgage bonds maturing in November 2024.

Income Tax Expense

Income tax expense at the Illinois segment decreased $4.4 million during the six months ended June 30, 2025, compared with the same period in 2024, driven by a decrease in pre-tax income.

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 $46.6 million during the six months ended June 30, 2025, representing a $7.4 million, or 18.9%, increase over the same period in 2024. The increase was driven by higher margins related to positive impacts from MGU's rate increase that was effective January 1, 2025, MERC's rate increase that was effective March 1, 2024, and an increase in retail sales volumes. These increases in earnings were partially offset by higher operating expenses.


	Six Months Ended June 30
(in millions)	2025		2024		B (W)
Operating revenues	$	309.4	$	255.6	$	53.8

Operating expenses
Cost of natural gas sold	147.6		114.6		(33.0)
Other operation and maintenance	52.6		45.2		(7.4)
Depreciation and amortization	24.5		22.9		(1.6)
Property and revenue taxes	13.3		12.5		(0.8)
Operating income	71.4		60.4		11.0

Other income, net	0.2		0.1		0.1
Interest expense	9.0		8.0		(1.0)
Income before income taxes	62.6		52.5		10.1

Income tax expense	16.0		13.3		(2.7)
Net income attributed to common shareholders	$	46.6	$	39.2	$	7.4


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


	Six Months Ended June 30
(in millions)	2025		2024		B (W)
Operation and maintenance not included in line item below	$	39.3	$	36.4	$	(2.9)
Regulatory amortizations and other pass through expenses (1)	13.3		8.8		(4.5)

Total other operation and maintenance	$	52.6	$	45.2	$	(7.4)

(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:


	Six Months Ended June 30
	Therms (in millions)
Natural Gas Sales Volumes	2025	2024	B (W)
Customer Class
Residential	201.2	173.2	28.0
Commercial and industrial	123.2	106.7	16.5
Total retail	324.4	279.9	44.5
Transportation	390.9	424.6	(33.7)
Total sales in therms	715.3	704.5	10.8


	Six Months Ended June 30
	Degree Days
Weather (1)	2025	2024	B (W)
MERC
Heating (4,854 Normal)	4,790	4,179	14.6	%

MGU
Heating (3,882 Normal)	3,823	3,211	19.1	%


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Gross Margin GAAP and Utility Margin Non-GAAP

The following table summarizes our other states segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See Non-GAAP Financial Measures above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).


	Six Months Ended June 30
(in millions)	2025		2024		B (W)
Operating revenues	$	309.4	$	255.6	$	53.8

Operating expenses
Cost of natural gas sold	(147.6)		(114.6)		(33.0)
Other operation and maintenance (1)	(29.5)		(27.0)		(2.5)
Depreciation and amortization	(24.5)		(22.9)		(1.6)
Property and revenue taxes	(13.3)		(12.5)		(0.8)
Gross margin (GAAP)	94.5		78.6		15.9

Other operation and maintenance (1)	29.5		27.0		2.5
Depreciation and amortization	24.5		22.9		1.6
Property and revenue taxes	13.3		12.5		0.8
Utility margin (non-GAAP)	$	161.8	$	141.0	$	20.8

Gross margin (GAAP) increased $15.9 million during the six months ended June 30, 2025, compared with the same period in 2024, and utility margin (non-GAAP) increased $20.8 million during the six months ended June 30, 2025, compared with the same period in 2024. Both measures were driven by:

A $7.6 million increase related to MGU's rate increase that was effective January 1, 2025, and MERC's rate increase that was effective March 1, 2024.
A $7.4 million increase related to higher sales volumes, driven by colder weather during the six months ended June 30, 2025, as compared to the same period in 2024. As measured by heating degree days, the six months ended June 30, 2025 was 14.6% and 19.1% colder than the same period in 2024 at MERC and MGU, respectively.
A $3.4 million increase related to MERC CIP revenue, which was offset in operation and maintenance expense.

Additionally, the lower increase in gross margin (GAAP) as compared to the increase in utility margin (non-GAAP), was driven by the following items that are further described in Other Operating Expenses below:

*•*A $2.5 million increase in natural gas operations and customer service expense; and

A $1.6 million increase in depreciation and amortization expense.

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

Other operating expenses at the other states segment increased $9.8 million during the six months ended June 30, 2025, compared with the same period in 2024. The significant factors impacting the increase in operating expenses were:

A $3.4 million increase in operation and maintenance expense related to MERC's CIP program, which has an offsetting increase in margins.
A $2.5 million increase in natural gas operations and customer service expense, driven by higher metering costs at MERC and MGU.


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A $1.9 million increase in bad debt expense, primarily at MERC. MERC's bad debt expense was lower in 2024 due to reserve adjustments related to improved loss rates.
A $1.6 million increase in depreciation and amortization expense related to continued capital investment.

Interest Expense

Interest expense at the other states segment increased $1.0 million during the six months ended June 30, 2025, compared with the same period in 2024, driven by the impact of MERC issuing long-term debt in April 2025 and MGU issuing long-term debt in October 2024 and April 2025.

Income Tax Expense

Income tax expense at the other states segment increased $2.7 million during the six months ended June 30, 2025, compared with the same period in 2024, driven by higher pre-tax income.

Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders


	Six Months Ended June 30
(in millions)	2025		2024		B (W)
Equity in earnings of transmission affiliates	$	105.5	$	91.6	$	13.9
Interest expense	9.7		9.7		—
Income before income taxes	95.8		81.9		13.9

Income tax expense	23.3		20.4		(2.9)
Net income attributed to common shareholders	$	72.5	$	61.5	$	11.0

Equity in Earnings of Transmission Affiliates

Equity in earnings of transmission affiliates increased $13.9 million during the six months ended June 30, 2025, compared with the same period in 2024. This increase was primarily due to continued capital investment by ATC. A $3.6 million gain related to the sale of an investment at ATC Holdco in March 2025 also contributed to the increase.

Income Tax Expense

Income tax expense at the electric transmission segment increased $2.9 million during the six months ended June 30, 2025, compared with the same period in 2024, primarily due to an increase in pre-tax income.

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


	Six Months Ended June 30
(in millions)	2025		2024		B (W)
Operating income	$	175.6	$	190.4	$	(14.8)

Other income, net	1.4		0.2		1.2
Interest expense	62.1		48.2		(13.9)
Income before income taxes	114.9		142.4		(27.5)

Income tax benefit	(74.5)		(43.6)		30.9
Net loss attributed to noncontrolling interests	1.7		1.6		0.1
Net income attributed to common shareholders	$	191.1	$	187.6	$	3.5


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Operating Income

Operating income at the non-utility energy infrastructure segment decreased $14.8 million during the six months ended June 30, 2025, compared with the same period in 2024, driven by these items at WECI:

A $15.2 million negative impact related to the receipt of performance payments in 2024.
An $11.6 million impairment loss recorded at our Samson I and Delilah I solar facilities related to damage incurred associated with various storms.
A $6.0 million increase in operation and maintenance expenses due primarily to a higher number of equipment repairs at our renewable generation facilities.

These decreases in operating income were partially offset by:

A $9.7 million increase in operating income from new investments in several WECI renewable generation facilities made in late 2024 and early 2025.
A $3.5 million increase due to higher amounts recognized for REC sales in 2025 at Blooming Grove driven by higher contracted REC prices overall, as well as timing of REC contract execution.
Recognition of $2.5 million of business interruption insurance proceeds related to storms at our Samson I solar facility.

In addition to the above items at WECI, there was a $1.6 million positive impact from We Power due to continued capital investment.

Interest Expense

Interest expense at the non-utility energy infrastructure segment increased $13.9 million during the six months ended June 30, 2025, compared with the same period in 2024, driven by the impact of WECI Energy Holding III issuing long-term debt in December 2024.

Income Tax Benefit

The income tax benefit at the non-utility energy infrastructure segment increased $30.9 million during the six months ended June 30, 2025, compared with the same period in 2024. The increase was primarily due to an increase in PTCs that was related to the acquisition of additional renewable generation facilities and an IRS approved PTC rate increase, partially offset by lower production volumes. Also contributing to the favorable income tax variance was lower pre-tax income.

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


	Six Months Ended June 30
(in millions)	2025		2024		B (W)
Operating loss	$	(4.8)	$	(3.7)	$	(1.1)

Other income, net	16.6		28.0		(11.4)
Interest expense	175.4		143.1		(32.3)

Loss before income taxes	(163.6)		(118.8)		(44.8)

Income tax benefit	(80.0)		(52.4)		27.6
Net loss attributed to common shareholders	$	(83.6)	$	(66.4)	$	(17.2)


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Other Income, Net

Other income, net at the corporate and other segment decreased $11.4 million during the six months ended June 30, 2025, compared with the same period in 2024. The significant factors impacting the decrease in other income, net were:

A $7.4 million decrease due to net losses of $4.1 million from our equity method investments in technology and energy-focused investment funds during the six months ended June 30, 2025, compared with net earnings of $3.3 million during the same period in 2024.
A $3.6 million decrease due to lower net gains from the investments held in the Integrys rabbi trust during the six months ended June 30, 2025, compared with the same period in 2024. The gains from the investments held in the rabbi trust partially offset increases in benefit costs related to certain deferred compensation, which are primarily included in other operation and maintenance expense in our utility segments.

Interest Expense

Interest expense at the corporate and other segment increased $32.3 million during the six months ended June 30, 2025, compared with the same period in 2024, primarily due to the impact of long-term debt issuances by WEC Energy Group in June 2024, December 2024, and June 2025. Partially offsetting these increases in interest expense were lower average short-term debt balances and lower average short-term interest rates.

Income Tax Benefit

The Income tax benefit at the corporate and other segment increased $27.6 million during the six months ended June 30, 2025, compared with the same period in 2024. This increase was driven by a $13.6 million increase in the interim tax benefit recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate, as well as a higher pre-tax loss.

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.

Cash Flows

The following table summarizes our cash flows during the six months ended June 30:


(in millions)	2025		2024		Change in 2025 Over 2024
Cash provided by (used in):
Operating activities	$	2,015.9	$	1,901.0	$	114.9
Investing activities	(1,972.8)		(1,250.8)		(722.0)
Financing activities	(16.1)		(512.5)		496.4

Operating Activities

Net cash provided by operating activities increased $114.9 million during the six months ended June 30, 2025, compared with the same period in 2024, driven by:

A $254.6 million increase in cash from higher overall collections from customers during the six months ended June 30, 2025, compared with the same period in 2024. This increase was driven by the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2025, a higher per-unit cost of natural gas, and higher sales volumes from colder weather during the six months ended June 30, 2025, compared with the same period in 2024.


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A $49.8 million increase in cash from lower payments for environmental remediation related to work completed on former manufactured gas plant sites during the six months ended June 30, 2025, compared with the same period in 2024.
A $34.3 million increase in cash driven by collateral received from counterparties during the six months ended June 30, 2025, compared with collateral paid to counterparties during the same period in 2024, as well as realized gains on derivative instruments recognized during the six months ended June 30, 2025, compared with realized losses on derivative instruments recognized during the same period in 2024.
A $30.1 million increase in cash from higher distributions from ATC during the six months ended June 30, 2025, compared with the same period in 2024.

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

A $164.9 million decrease in cash from higher payments for operating and maintenance expenses. During the six months ended June 30, 2025, our payments were higher due to higher transmission and electric and natural gas distribution costs, as well as the timing of payments for accounts payable.
A $51.5 million decrease in cash from higher payments for interest driven by issuances of long-term debt in 2024, partially offset by lower payments for interest due to lower average short-term debt balances and lower short-term interest rates during the six months ended June 30, 2025, compared with the same period in 2024.
A $39.6 million decrease in cash received for income taxes driven by the timing of proceeds received from the sale of PTCs to third parties during the six months ended June 30, 2025, compared with the same period in 2024. See Note 12, Income Taxes, and Note 22, Supplemental Cash Flow Information, for more information.

Investing Activities

Net cash used in investing activities increased $722.0 million during the six months ended June 30, 2025, compared with the same period in 2024, driven by:

The acquisition of a 90% ownership interest in Hardin III in February 2025 for $406.1 million, net of cash acquired of $0.2 million. See Note 2, Acquisitions, for more information.
A $392.1 million increase in cash paid for capital expenditures during the six months ended June 30, 2025, which is discussed in more detail below.
A $57.5 million increase in capital contributions paid to transmission affiliates during the six months ended June 30, 2025, compared with the same period in 2024. See Note 18, Investment in Transmission Affiliates, for more information.

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

The acquisition of an additional 13.7% ownership interest in West Riverside in May 2024 for $98.2 million. See Note 2, Acquisitions, for more information.
A $33.5 million increase in cash received from ATC during the six months ended June 30, 2025, compared with the same period in 2024, for the reimbursement of transmission infrastructure upgrades. See Note 18, Investment in Transmission Affiliates, for more information.


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Capital Expenditures

Capital expenditures by segment for the six months ended June 30 were as follows:


Reportable Segment (in millions)	2025		2024		Change in 2025 Over 2024
Wisconsin	$	1,316.4	$	886.8	$	429.6
Illinois	125.4		169.6		(44.2)
Other states	55.0		49.6		5.4
Non-utility energy infrastructure	26.0		24.7		1.3
Corporate and other	7.7		7.7		—
Total capital expenditures	$	1,530.5	$	1,138.4	$	392.1

The increase in cash paid for capital expenditures at the Wisconsin segment during the six months ended June 30, 2025, compared with the same period in 2024, was driven by an increase in capital expenditures for the following: renewable energy projects at WE, WPS, and UMERC; combustion turbines at OCPP; WE's natural gas and electric distribution systems; software to enhance productivity, collaboration, and overall efficiency across the company; and a project to consolidate our electric utility operations technology. These increases in capital expenditures were partially offset by decreased payments for construction of WG's LNG facility which was completed in February 2024.

The decrease in cash paid for capital expenditures at the Illinois segment during the six months ended June 30, 2025, compared with the same period in 2024, was driven by lower payments related to PGL's upgrade of its natural gas delivery system. For more information on the factors contributing to this decrease, see Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Illinois Proceedings.

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

Financing Activities

Net cash used in financing activities decreased $496.4 million during the six months ended June 30, 2025, compared with the same period in 2024, driven by:

A $952.4 million increase in cash due to lower net repayments of commercial paper during the six months ended June 30, 2025, compared with the same period in 2024.
A $360.6 million increase in cash due to higher issuances of common stock during the six months ended June 30, 2025, compared with the same period in 2024. See Note 7, Common Equity, for more information.
A $217.8 million increase in cash due to lower retirements of long-term debt during the six months ended June 30, 2025, compared with the same period in 2024.
The purchase of an additional 10% ownership interest in Samson I in January 2024 for $28.1 million.
A $20.0 million increase in cash related to a higher number of stock options exercised during the six months ended June 30, 2025, compared with the same period in 2024.

These decreases in cash used in financing were partially offset by:

A $1,049.2 million decrease in cash due to lower issuance of long-term debt during the six months ended June 30, 2025, compared with the same period in 2024.
A $41.5 million decrease in cash due to higher dividends paid on our common stock during the six months ended June 30, 2025, compared with the same period in 2024. In January 2025, our Board of Directors increased our quarterly dividend by $0.0575 per share (6.9%) effective with the March 2025 dividend payment.


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Other Significant Financing Activities

For more information on our other significant financing activities, see Note 7, Common Equity, 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, 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 2024 Annual Report on Form 10-K for additional information regarding our significant cash requirements.

Significant Capital Projects

We have several capital projects and acquisitions 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 21, Commitments and Contingencies.


(in millions)	2025 (1)		2026		2027
Wisconsin	$	4,202.4	$	4,410.7	$	4,873.2
Illinois	373.7		404.8		369.7
Other states	106.5		121.4		123.4
Non-utility energy infrastructure	437.6		23.1		33.8
Corporate and other	17.9		10.2		2.4
Total	$	5,138.1	$	4,970.2	$	5,402.5

(1)This includes actual capital expenditures incurred through June 30, 2025, 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, 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 natural gas-fired generation. Below are examples of projects that are proposed, currently underway, or recently completed.

WE and WPS, along with an unaffiliated utility, received PSCW approval to acquire and construct Paris, a utility-scale solar-powered electric generating facility with a battery energy storage system located in Kenosha County, Wisconsin. In December 2024, the construction of the solar portion of Paris was completed, with WE and WPS collectively owning 180 MWs of solar generation. In June 2025, the construction of the battery portion of Paris was completed, with WE and WPS collectively owning 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 $542 million.
WE and WPS, along with an unaffiliated utility, received PSCW approval to acquire and construct Darien, a utility-scale solar-powered electric generating facility with a battery energy storage system located in Rock and Walworth counties, Wisconsin. In March 2025, the construction of the solar portion of Darien was completed, with WE and WPS collectively owning 225 MWs of solar generation. WE and WPS will collectively own 68 MWs of battery storage of this project, with construction expected to be completed in 2026. WE's and WPS's combined share of the cost of this project is estimated to be approximately $567 million.
WE and WPS, along with an unaffiliated utility, received PSCW approval to acquire Koshkonong Solar 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 storage of


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this project. WE's and WPS's combined share of the cost of this project is estimated to be approximately $930 million, with construction of the solar portion and battery storage expected to be completed in 2026 and 2027, respectively.

WE and WPS plan to enhance fuel flexibility at the coal-fired ERGS units and Weston Unit 4.
WE and WPS, along with an unaffiliated utility, received PSCW approval to acquire and construct High Noon, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Columbia County, Wisconsin and once fully constructed, WE and WPS will collectively own 270 MWs of solar generation and 149 MWs of battery storage of this project. WE and WPS's combined share of the cost of this project is estimated to be approximately $883 million, with construction expected to be completed in 2027.
UMERC received MPSC approval to acquire and construct Renegade, a utility-scale solar-powered electric generating facility. The project will be located in Delta and Marquette counties, Michigan and once fully constructed, UMERC will own 100 MWs of solar generation. The cost of this project is estimated to be approximately $226 million, with construction expected to be completed in 2026.
WE received PSCW approval to build five natural gas-fired combustion turbines capable of producing approximately 1,100 MWs, which would be located at the existing OCPP site. The cost of this project is estimated to be approximately $1.2 billion, with construction expected to be completed in 2027-2028.
WE received PSCW approval to add seven natural gas-fired RICE units near the Paris Generating Station. The new RICE units would be fueled with natural gas and capable of producing approximately 128 MWs. The cost of this project is estimated to be approximately $300 million, with construction expected to be completed in 2027.
In April 2024, WE filed a request with the PSCW to construct the Rochester Lateral, which would supply additional natural gas service to the OCPP site. The natural gas lateral would be built in Kenosha, Racine, and Milwaukee counties. If approved, the cost of this project is estimated to be approximately $200 million.
WE received PSCW approval to construct an LNG facility with storage capacity of two Bcf on the OCPP site. The cost of this project is estimated to be approximately $456 million, with construction expected to be completed in 2027.
In September 2024, WE and WPS, along with an unaffiliated utility, filed a request with the PSCW to acquire Dawn Harvest Solar Energy Center, a utility-scale solar-powered electric generating facility with a battery energy storage system. If approved, the project will be located in Rock County, Wisconsin and once fully constructed, WE and WPS will collectively own 135 MWs of solar generation and WE will own 50 MWs of battery storage of this project. If approved, WE and WPS's combined share of the cost of this project is estimated to be approximately $409 million, with construction expected to be completed in 2028.
In September 2024, WE and WPS, along with an unaffiliated utility, filed a request with the PSCW to acquire Saratoga, a utility-scale solar-powered electric generating facility with a battery energy storage system and Ursa, a utility-scale solar-powered electric generating facility. If approved, Saratoga will be located in Wood County, Wisconsin and Ursa will be located in Columbia County, Wisconsin. Once fully constructed, WE and WPS will collectively own 135 MWs of solar generation and 45 MWs of battery storage of Saratoga and 180 MWs of solar generation of Ursa. If approved, WE and WPS's combined share of the cost of Ursa is estimated to be approximately $406 million, with construction expected to be completed in 2027. If approved, WE and WPS's combined share of the cost of Saratoga is estimated to be approximately $406 million, with construction expected to be completed in 2028.
In September 2024, WE and WPS, along with an unaffiliated utility, filed a request with the PSCW to acquire and construct Badger Hollow Wind and to acquire Whitetail, two utility-scale wind-powered electric generating facilities. If approved, Badger Hollow Wind will be located in Iowa and Grant counties, Wisconsin and Whitetail will be located in Grant County, Wisconsin. Once fully constructed, WE and WPS will collectively own 100 MWs of wind generation of Badger Hollow Wind and 60 MWs of wind generation of Whitetail. If approved, WE and WPS's combined share of the cost of Badger Hollow Wind is estimated to be $320 million and the cost of Whitetail is estimated to be approximately $200 million, with construction for both projects expected to be completed in 2027.
In October 2024, WE and WPS, along with an unaffiliated utility, filed a request with the PSCW to acquire and construct Good Oak and Gristmill, two utility-scale solar electric generating facilities. If approved, both Good Oak and Gristmill will be located in Columbia County, Wisconsin. Once fully constructed, WE and WPS will collectively own 88 MWs of solar generation of Good Oak


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and 60 MWs of solar generation of Gristmill. If approved, WE and WPS's combined share of the cost of Good Oak is estimated to be $194 million and the cost of Gristmill is estimated to be approximately $130 million, with construction for both projects expected to be completed in 2028.

The construction of additional LNG facilities in Wisconsin has been proposed as part of our capital plan and would provide another approximately four Bcf of natural gas supply at an estimated cost of $940 million. The facilities are expected to reduce the likelihood of constraints on our natural gas distribution system during the highest demand days of winter.

As part of our capital plan, we plan to build additional natural gas-fired combustion turbines capable of producing approximately 675 MWs at an estimated cost of $960 million. In addition, we plan to add natural gas-fired RICE units that would be capable of producing approximately 114 MWs at an estimated cost of $250 million.

In connection with several investigations it conducted, the DOC set duties on solar panels and cells imported from four southeast Asian countries. See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – United States Department of Commerce Complaints and Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Uyghur Forced Labor Prevention Act for information on the duties set by the DOC and CBP actions, respectively. The expected in-service dates and costs identified above already reflect some of these impacts.

See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Renewable Energy Legislation for potential impacts to our capital projects as a result of the OBBBA.

In accordance with the November 2023 rate order, the ICC initiated a proceeding in January 2024 to determine the optimal method and a prudent investment level for replacing aging natural gas infrastructure. On February 20, 2025, the ICC issued an order setting expectations for PGL's prospective operations. For more information on regulatory proceedings related to this matter, see Note 23, Regulatory Environment, and Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Illinois Proceedings.

The non-utility energy infrastructure line item in the table above includes WECI's investment in Hardin III, which closed in February 2025. See Note 2, Acquisitions, for more information on this project.

We expect to provide total capital contributions to ATC (not included in the above table) of approximately $445 million from 2025 through 2027. We do not expect to make any contributions to ATC Holdco during that period. WEC's portion of the investment in MISO Tranche 1 is estimated to be approximately $580 million between 2025 and 2029, a portion of which will be funded by ATC's cash from operations. Tranche 1 is part of MISO's Long Range Transmission Planning initiative to upgrade the grid so that it can reliably accommodate for the shift in generation to lower-carbon resources.

Long-Term Debt

See Note 9, Long-Term Debt, for information regarding the changes in our outstanding long-term debt during the six months ended June 30, 2025.

Common Stock Dividends

Our current quarterly dividend rate is $0.8925 per share, which equates to an annual dividend of $3.57 per share. For information related to our most recent common stock dividend declared, see Note 7, Common Equity.

Other Significant Cash Requirements

See Note 21, Commitments and Contingencies, for information regarding our minimum future commitments related to purchase obligations for the procurement of fuel, power, and natural 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 six months ended June 30, 2025.


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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 15, Guarantees, and Note 20, 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, and common equity. Accessing the capital markets allows us to obtain external short-term borrowings, including commercial paper and term loans, and issue intermediate or long-term debt securities, as well as other types of securities. In 2024, we started issuing common equity through a combination of our employee benefit plans and stock purchase and dividend reinvestment plan, as well as through an at-the-market program. 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 financing to manage seasonal variations, working capital needs, commodity price fluctuations, unplanned expenses, and unanticipated events. Subject to market conditions and other factors, we may repurchase our debt securities through open market purchases, privately negotiated transactions and/or other types of transactions.

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 2025, 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 2024 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 June 30, 2025, our current liabilities exceeded our current assets by $2,098.5 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 under our 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 7, Common Equity, Note 8, Short-Term Debt and Lines of Credit, and Note 9, Long-Term Debt, for more information about our common stock activity, 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 have investments consisting of fixed income and equity securities that are subject to the volatility of the stock 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 2024 Annual Report on Form 10-K.


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Capitalization Structure

The following table shows our capitalization structure as of June 30, 2025, as well as an adjusted capitalization structure that we believe is consistent with how a majority of the rating agencies currently view our 2024 Junior Notes:


(in millions)	Actual			Adjusted
Common shareholders' equity	$	13,223.1		$	13,598.1
Preferred stock of subsidiary	30.4			30.4
Long-term debt (including current portion)	19,360.8			18,985.8
Short-term debt	810.3			810.3
Total capitalization	$	33,424.6		$	33,424.6

Total debt	$	20,171.1		$	19,796.1

Ratio of debt to total capitalization	60.3		%	59.2		%

Included in long-term debt on our balance sheet as of June 30, 2025, was $750.0 million principal amount of WEC Energy Group's 2024 Junior Notes (2024A Junior Notes and 2024B Junior Notes, collectively) due 2055. The adjusted presentation attributes $375.0 million of the 2024 Junior Notes to common shareholders' equity and $375.0 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 2024 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 June 30, 2025, 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 11, Common Equity, Note 13, Short-Term Debt and Lines of Credit, and Note 14, Long-Term Debt, in our 2024 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 June 30, 2025. 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 June 30, 2025, it could have been required to post $106 million of additional collateral or other assurances pursuant to the terms of a PPA. We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.

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

In March 2025, Moody's changed the rating outlook for PGL to stable from negative as a result of the ICC's order in February 2025 setting expectations for PGL's replacement of aging natural gas infrastructure. Moody's affirmed PGL's ratings, including its Aa3 senior secured rating and its P-1 short term rating for commercial paper. See Note 23, Regulatory Environment, for more information.

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


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FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

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 2024 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 ASC. 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. See Note 23, Regulatory Environment, in this report, and Note 26, Regulatory Environment, in our 2024 Annual Report on Form 10-K for more information regarding recent and pending rate proceedings, orders, and investigations involving our utilities.

Uncollectible Expense Adjustment Rider

The rates of PGL and NSG include a UEA rider for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. The UEA rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency by the ICC. In May 2023, the ICC issued a written order on PGL's and NSG's 2018 UEA rider reconciliation. The order required a $15.4 million and $0.7 million refund to ratepayers at PGL and NSG, respectively. These amounts were refunded over a period of nine months, which began on September 1, 2023. In July 2023, PGL and NSG petitioned the Illinois Appellate Court for review of the ICC order. In November 2024, the Illinois Appellate Court issued an opinion affirming the ICC order and the related disallowance. PGL and NSG subsequently petitioned the Illinois Supreme Court seeking review and reversal of the May 2023 order; however, their petition was denied in March 2025.

As of June 30, 2025, there can be no assurance that all costs incurred under the UEA rider during the open reconciliation years, which include 2019 through 2024, will be deemed recoverable by the ICC. The combined annual costs of PGL and NSG included in the rider, which reflect uncollectible write-offs in excess of what is recovered in base rates, have ranged from $10 million to $40 million during these open reconciliation years. Disallowances by the ICC, if any, could be material and have a material adverse impact on our results of operations.

Qualifying Infrastructure Plant Rider

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, which was in effect until December 1, 2023, continues to be subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In August 2024, the ICC issued a final order on PGL's 2016 annual reconciliation, which included a disallowance of $14.8 million of certain capital costs. PGL recorded a pre-tax charge to income of $25.3 million during the third quarter of 2024 related to the disallowance and the previously recognized return on and of these investments. The charge was recorded on the income statement as a $12.9 million reduction in revenues for the amounts previously collected from customers, a $12.1 million increase to operating expenses for the impairment of PGL's property, plant, and equipment, and a $0.3 million increase to interest expense related to the amounts due to customers. In October 2024, PGL filed a petition with the Illinois Appellate Court for review of the ICC's August order.

PGL's QIP reconciliations from 2017 through 2023 are still pending. In July 2025, ICC staff and certain intervenors filed testimony with the ICC recommending significant disallowances in the 2017 QIP reconciliation proceeding. We believe that all costs were


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prudently incurred, but cannot predict the ultimate outcome of this matter. There is no statutory deadline by which the ICC is required to issue an order in this proceeding. The aggregate capital costs included in the rider during the open reconciliation years, along with any previously recognized return on these investments, totaled approximately $2.9 billion as of June 30, 2025. There can be no assurance that all of these costs and the previously recognized returns will be deemed recoverable by the ICC. Disallowances by the ICC, if any, could be material and have a material adverse impact on our results of operations.

Illinois Proceedings

In the PGL rate order issued by the ICC in November 2023, the ICC ordered PGL to pause spending on its projects to upgrade its natural gas delivery system until the ICC completed a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level. In accordance with the written order, the ICC initiated the proceeding in January 2024. In February 2025, the ICC issued an order setting expectations for PGL's prospective operations. The ICC directed us to focus on replacing all cast and ductile iron pipe that has a diameter under 36 inches by January 1, 2035. The ICC also indicated that failure to comply with this directive could subject us to civil penalties under Illinois statute. PGL will replace this cast and ductile iron pipe through its PRP. Costs incurred under the PRP will be evaluated for prudency by the ICC in future rate cases. In addition, the program will be overseen by a safety monitor hired by the ICC. We are evaluating the impact of this order on our operations and capital plan.

In March 2024, the ICC initiated a statewide "Future of Gas" proceeding. The goal of this proceeding is to explore the issues involved with decarbonization of the gas distribution system in Illinois and recommend any future ICC action or legislative changes needed. It includes the formal exploration and consideration of the role of natural gas in the future, including in the context of the state’s environmental and energy policy goals. The proceeding includes a broad range of stakeholders, including Illinois utilities and other interested parties. The “Future of Gas” proceeding is expected to be completed in 2026. At this time, we cannot predict the ultimate outcome of this proceeding or the resulting impact to our natural gas operations in Illinois. Future natural gas investment opportunities in Illinois could be negatively impacted depending upon the outcome.

See Note 23, Regulatory Environment, for more information regarding the November 2023 ICC rate order.

Chicago Decarbonization Efforts

The CABO was introduced at a meeting of the Chicago city council held in January 2024. If approved, this ordinance would set an indoor emissions standard that would require zero-to-low-emission energy systems in newly built commercial and residential buildings and major building additions in the city of Chicago. The proposed emission standards would effectively prohibit the use of natural gas in new buildings and homes and require electric heat and appliances. The CABO would not impact existing homes and businesses. In addition, certain buildings and equipment, such as hospitals, commercial kitchens, and back-up generators, would be exempt from the new emission limits.

In response to the CABO, a resolution was also introduced that would require the formation of a working group comprised of various subject matter experts to analyze the costs of converting buildings from natural gas to electricity, the costs for additional electric generation capacity needed for future building conversions, and the impact of shifting natural gas system costs from new construction to existing buildings if electrification measures are adopted. If the resolution is passed, this analysis would need to be completed prior to the adoption of any decarbonization initiatives, such as the CABO.

If approved by the city council, the CABO is expected to become effective one year after the approval date. PGL's future natural gas operations could be materially adversely impacted if the CABO is passed.

Uyghur Forced Labor Prevention Act

In June 2022, the CBP implemented the UFLPA, which establishes a rebuttable presumption that certain silica-based products wholly or partially manufactured in the Xinjiang Uyghur Autonomous Region of China, such as polysilicon included in the manufacturing of solar panels, are prohibited from entering the United States. While our suppliers have been able to provide the CBP sufficient documentation to meet the UFLPA compliance requirements, and we expect the same will be true for subsequent projects, 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 whether we will experience any further impacts to the timing and cost of solar projects included in our long-term capital plan.


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In January 2025, the Department of Homeland Security announced the addition of several more Chinese businesses to the UFLPA, including five solar supply chain providers. We are working to avoid doing business with these companies and remain in compliance with the UFLPA.

United States Department of Commerce Complaints

In August 2023, the DOC issued a final decision regarding an AD/CVD petition filed by a California-based company finding that Chinese manufacturers were shifting products to four Southeast Asian countries to avoid tariffs required on products imported from China. The DOC applied duties to certain imports of solar cells from Malaysia, Vietnam, Thailand and Cambodia, starting on June 6, 2024. In addition, in response to its findings, the DOC promulgated new regulations that imposed enhanced duties in certain circumstances, including when the USITC determines there is a reasonable indication the domestic solar industry is materially or potentially injured because of imported products that violate certain fair trade laws.

In April 2024, a coalition of several U.S. producers of solar panels filed a new petition with the DOC requesting tariffs on imports from the same four Southeast Asian countries. The group alleged that some Chinese companies had moved their solar operations to avoid penalties. In response to the petition, the DOC and USITC initiated new AD/CVD investigations of solar panels from the four Southeast Asian countries to determine whether there was a reasonable indication imports of such solar panels were causing injury to the U.S. solar industry. Based on the USITC’s preliminary affirmative determination, the DOC began AD/CVD investigations and, in the fall of 2024, announced preliminary affirmative determinations and set preliminary duties on imports from the four Southeast Asian countries. In April 2025, the DOC announced its final affirmative determinations in its AD/CVD investigations, increasing the preliminary tariff rates, in some cases significantly. These increased rates became effective and enforceable in May 2025 upon the USITC’s final affirmative determination. As a result of these duties, the cost and availability of solar panels in the U.S. has been impacted and the U.S. solar industry overall has experienced higher costs of materials as well as delays. Some of these impacts have already been reflected in the estimated cost and in-service dates for certain of our solar projects.

On July 17, 2025, a coalition of trade groups filed new AD/CVD petitions with the USITC and the DOC, asking for investigations into alleged illegal trade practices by largely Chinese-owned manufacturers operating in Laos and Indonesia, as well as companies headquartered in India. Affirmative findings could cause further strain on the solar panel industry. We are monitoring the status of these petitions.

Renewable Energy Legislation

Infrastructure Investment and Jobs Act and Inflation Reduction Act

In November 2021, the Infrastructure Investment and Jobs Act was signed into law and provides for approximately $1.2 trillion of federal spending over a five year period, including approximately $85 billion for investments in power, utilities, and renewables infrastructure across the United States. We believe that funding from this Act would support the work we are doing to reduce GHG emissions, increase EV charging, and strengthen and protect the energy grid. Funding in the Act could also help to expand emerging technologies, like hydrogen and carbon management, as we continue the transition to a clean energy future to the benefit of our customers, the communities we serve, and our company.

In August 2022, the IRA was signed into law and 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.

Under the IRA transferability option, we entered into agreements in October 2024 and April 2025 to sell the majority of the PTCs we generated in 2025 and 2026, respectively, to third parties. In May 2025, we entered into an agreement to sell the majority of our remaining unsold PTCs we generated in 2024 to a third party. See Note 12, Income Taxes, for more information about the impact of these sales. 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.


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In January 2025, pursuant to an executive order issued by the current presidential administration, disbursement of funds under these two Acts was paused until agency heads can determine whether grants, loans, contracts, and other disbursements are consistent with the current administration's energy policy. Agency heads must consult with the Office of Management and Budget and the National Economic Council prior to any funding being disbursed. The new policy encourages use of domestic energy sources including oil, natural gas, coal, hydropower, biofuels, critical minerals, and nuclear, promotes consumer choice of goods and appliances, aims to boost American workers and businesses, eliminates the EV mandate, and limits regulations that apply to the energy industry. The pause could disrupt funding, temporarily or permanently, for infrastructure projects already in progress, may cause project delays and cancellations, may impact continuing payment obligations for downstream contractors and suppliers, and may cause legal and contractual claims. The executive order did not impact the IRA's provisions for tax credits and the transferability option.

One Big Beautiful Bill Act

On July 4, 2025, the OBBBA was signed into law, enacting significant modifications to clean-energy tax credits previously provided under the IRA. The OBBBA provides companies the ability to earn solar and wind tax credits at current credit rates if construction of projects begins by July 4, 2026, and the projects are placed in-service within four years after beginning construction. However, wind and solar projects that begin construction more than one year after enactment of the OBBBA must be placed in service by December 31, 2027 to qualify for PTCs and ITCs. In addition, wind and solar projects that begin construction after December 31, 2025 must also satisfy prohibited foreign entity material assistance requirements. The phase out of PTCs and ITCs does not apply to energy storage, hydroelectric facilities, nuclear, or any other zero emission technology. The OBBBA preserves the ability to transfer tax credits, with the exception of transfers to a prohibited foreign entity. On July 7, 2025, an executive order was issued by the presidential administration directing the Secretary of the Treasury to strictly enforce the termination of PTCs and ITCs for wind and solar facilities and to issue updated guidance within 45 days to clarify and tighten the beginning of construction rules for energy projects, as directed in the OBBBA. We continue to assess the potential impacts of the OBBBA and the related executive order.

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 $8 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 LLC Allowed Return on Equity Complaint

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 a complaint was 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 ROE complaint section 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.


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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.

September 2016 FERC 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 this complaint, November 12, 2013 through February 11, 2015 and September 28, 2016 going forward.
November 2019 FERC 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 complaint. In response to this FERC decision, requests for the FERC to rehear the November 2019 Order in its entirety were filed by various parties.
May 2020 FERC 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 complaint. Various parties then filed requests to rehear certain parts of the May 2020 Order with the FERC.
November 2020 FERC 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 for FERC Orders Issued Prior to October 2024 – Due to the base ROE changes resulting from the FERC orders issued prior to October 2024, 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 these periods. The refunds were applied to WE's and WPS's PSCW-approved escrow accounting for transmission expense.
August 2022 D.C. Circuit Court of Appeals Opinion – 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 Opinion, 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 a result, ATC recorded a reserve for potential refunds based on a 9.88% base ROE.
October 2024 FERC Order – In response to the August 2022 D.C. Circuit Court of Appeals Opinion, the FERC issued an order on October 17, 2024. The FERC’s October 2024 Order removed the risk premium model from the base ROE methodology and required MISO transmission owners, including ATC, to adopt a 9.98% base ROE for the period covered by the complaint.
Refunds for FERC Order Issued in October 2024 – Prior to the October 2024 FERC order, the base ROE for MISO transmission owners was 10.02% based on the November 2020 FERC order. Since the October 2024 FERC order changed the base ROE to 9.98%, ATC is providing additional 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 October 17, 2024. As a result, WE, WPS, and UMERC are receiving refunds from ATC related to the transmission costs they paid during these two refund periods. The refunds are being applied to WE’s and WPS’s PSCW-approved escrow accounting for transmission expense.

Due to the change between the 9.88% base ROE originally reflected in ATC's reserve and the 9.98% base ROE authorized in the October 2024 FERC Order, ATC reduced its refund liability, which increased our pre-tax equity earnings, by $20.1 million during the fourth quarter of 2024.


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March 2025 FERC Order – In response to rehearing requests filed concerning the October 2024 FERC Order, the FERC issued an order on March 25, 2025 that reaffirmed the October 2024 FERC Order in its entirety. Appeals related to the October 2024 FERC Order are still pending before the D.C. Circuit Court of Appeals.

Environmental Matters

See Note 21, 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 risks described below. In addition, there is continuing uncertainty over the impact that the ongoing regional conflicts, including those in Ukraine, Israel and in other parts of the Middle East, will ultimately 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 2024 Annual Report on Form 10-K for a discussion of market and other significant risks applicable to us.

Changes to United States Trade Policy (Tariff Activity)

The U.S. continues to implement changes to its international trade policy including changes to tariffs, port fees and other policies relating to exports from and imports into the United States. In response to these changes, foreign governments are also adjusting their trade policies, including the imposition of additional tariffs. There remains significant uncertainty as to the ultimate scope of the U.S. and foreign trade policies. Both the U.S. and foreign trade policy changes could increase the cost of materials or disrupt supply chains, which could impact our ability to repair or maintain our infrastructure; the timing, cost or completion of our infrastructure projects; and/or our ability to execute our capital plan. In addition, these changes, including any impact they may have to economic conditions, could lead to reduced energy demand by our customers. Consequently, these policy changes could have a material adverse effect on our business, results of operations and financial condition.

Inflation and Supply Chain Disruptions

We continue to monitor the impact of inflation and supply chain disruptions. We monitor the costs of medical plans, fuel, transmission access, construction costs, regulatory and environmental compliance costs, and other costs in order to minimize inflationary effects in future years, to the extent possible, through pricing strategies, productivity improvements, and cost reductions. We monitor the global supply chain, and related disruptions, in order to ensure we are able to procure the 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 four risk factors below that are disclosed in Part I of our 2024 Annual Report on Form 10-K.

Item 1A. Risk Factors – Risks Related to the Operation of Our Business – Public health crises, including epidemics and pandemics, could adversely affect our business functions, financial condition, liquidity, and results of operations.
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 – The fluctuation in demand for certain commodities and their respective prices could negatively impact our operations.

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


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