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 at Weston Unit 4. 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 900 MWs of additional coal-fired generation by the end of 2031, which includes the planned retirements of OCPP Units 7 and 8 and Weston Unit 3. In conjunction with our new capital plan, we and the other co-owners of Columbia Units 1 and 2 currently plan to continue coal operations at these units through at least 2029, and continue to evaluate the conversion of both units to natural gas. See Note 6, Property, Plant, and Equipment, for more information related to Columbia Units 1 and 2 and our planned power plant retirements.

In addition to retiring these older, fossil-fueled plants, we expect to invest approximately $11.6 billion from 2026 to 2030 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:

3,700 MWs of utility-scale solar;
1,780 MWs of battery storage; and


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555 MWs of wind.

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

3,300 MWs of CTs (we plan on constructing a new natural gas lateral pipeline to support the CTs planned at our OCPP site); and
180 MWs of RICE natural gas-fueled generation.

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 collectively have 16 active contracts, for a total of approximately 47 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 RTCs, 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 into 2026.

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.

The PSCW 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. In February 2025, the ICC issued an order setting expectations for PGL's prospective retirement of its aging natural gas infrastructure. The ICC directed us to focus on retiring all cast and ductile iron pipe that has a diameter of less than 36 inches by January 1, 2035. PGL will retire 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 capital plan includes $2.2 billion of investments in battery energy storage systems from 2026 to 2030, which are intended to capture excess power and release it during peak demand or when power is limited due to weather or other unexpected disruptions.
Our utilities continue to upgrade their electric and natural gas distribution systems to enhance reliability and storm hardening.

We expect to spend approximately $4.7 billion from 2026 to 2030 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 2026 to 2030 is in our regulated utilities and our investment in ATC. We expect total capital expenditures for our regulated utility businesses to be approximately $32.4 billion from 2026 to 2030. In addition, we currently forecast that our share of ATC's projected capital expenditures over the next five years will be approximately $4.1 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 $36.5 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.

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


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Safety

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

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

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

RESULTS OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2025

Consolidated Earnings

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


	Three Months Ended September 30
(in millions, except per share data)	2025		2024		B (W)
Wisconsin	$	281.3	$	237.8	$	43.5
Illinois	(30.5)		(48.6)		18.1
Other states	(8.9)		(3.7)		(5.2)
Electric transmission	37.3		31.7		5.6
Non-utility energy infrastructure	87.9		85.0		2.9
Corporate and other	(95.8)		(62.1)		(33.7)
Net income attributed to common shareholders	$	271.3	$	240.1	$	31.2

Diluted EPS	$	0.83	$	0.76	$	0.07

Earnings increased $31.2 million during the third quarter of 2025, compared with the same quarter in 2024. The $31.2 million increase in earnings was driven by:

A $43.5 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, higher retail sales volumes, and an increase in certain income tax benefits. 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 an increase in depreciation and amortization expense, higher costs related to our power plants, and an increase in property and revenue taxes.
An $18.1 million decrease in the net loss attributed to common shareholders at the Illinois segment, driven by the positive quarter-over-quarter impact of the $25.3 million pre-tax charge to income recorded in the third quarter of 2024 related to the ICC's disallowance of certain capital costs in PGL's 2016 rider QIP reconciliation. See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Regulatory Recovery and Note 23, Regulatory Environment, for more information on the ICC disallowance.

These increases in earnings were partially offset by a $33.7 million increase in the net loss attributed to common shareholders at the corporate and other segment, driven by an increase in an interim income tax expense recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate. Higher interest expense and a net loss from our equity


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method investments in technology and energy-focused investment funds also contributed to the increase in the net loss attributed to common shareholders.

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 $281.3 million during the third quarter of 2025, representing a $43.5 million, or 18.3%, 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, higher retail sales volumes, and an increase in certain income tax benefits. 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 an increase in depreciation and amortization expense, higher costs related to our power plants, and an increase in property and revenue taxes.


	Three Months Ended September 30
(in millions)	2025		2024		B (W)
Operating revenues	$	1,791.6	$	1,590.0	$	201.6

Operating expenses
Cost of sales (1)	578.2		495.3		(82.9)
Other operation and maintenance	443.7		403.5		(40.2)
Depreciation and amortization	255.7		232.4		(23.3)
Property and revenue taxes	44.5		32.8		(11.7)
Operating income	469.5		426.0		43.5

Other income, net	25.0		35.7		(10.7)
Interest expense	158.9		160.3		1.4
Income before income taxes	335.6		301.4		34.2

Income tax expense	54.0		63.3		9.3
Preferred stock dividends of subsidiary	0.3		0.3		—
Net income attributed to common shareholders	$	281.3	$	237.8	$	43.5

(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 September 30
(in millions)	2025		2024		B (W)
Operation and maintenance not included in line items below	$	214.7	$	183.6	$	(31.1)
Transmission (1)	146.2		135.8		(10.4)
Regulatory amortizations and other pass through expenses (2)	51.7		52.5		0.8
We Power (3)	31.9		32.5		0.6
Earnings sharing mechanisms	(0.8)		(0.9)		(0.1)
Total other operation and maintenance	$	443.7	$	403.5	$	(40.2)

(1)Represents transmission expense that our electric utilities are authorized to collect in rates. The PSCW has approved escrow accounting for ATC and MISO network transmission expenses for WE and WPS. As a result, WE and WPS defer as a regulatory asset or liability, the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the third quarter of 2025 and 2024, $157.9 million and $147.5 million, respectively, of costs were billed to our electric utilities by transmission providers.

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

(3)Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE. During the third quarter of 2025 and 2024, $29.0 million and $27.8 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:


	Three Months Ended September 30
	MWh (in thousands)
Electric Sales Volumes	2025	2024	B (W)
Customer Class
Residential	3,339.2	3,270.0	69.2
Small commercial and industrial (1)	3,555.8	3,516.8	39.0
Large commercial and industrial (1)	3,239.0	3,160.4	78.6
Other	25.5	26.8	(1.3)
Total retail (1)	10,159.5	9,974.0	185.5
Wholesale	476.1	438.0	38.1
Resale	1,667.8	1,573.7	94.1
Total sales in MWh (1)	12,303.4	11,985.7	317.7

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


	Three Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2025	2024	B (W)
Customer Class
Residential	58.5	58.4	0.1
Commercial and industrial	60.7	57.3	3.4
Total retail	119.2	115.7	3.5
Transportation	274.2	267.9	6.3
Total sales in therms	393.4	383.6	9.8


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	Three Months Ended September 30
	Degree Days
Weather (1)	2025	2024	B (W)
WE and WG
Heating (88 Normal)	68	28	142.9	%
Cooling (525 Normal)	574	600	(4.3)	%

WPS
Heating (165 Normal)	163	54	201.9	%
Cooling (415 Normal)	469	452	3.8	%

UMERC
Heating (290 Normal)	261	153	70.6	%
Cooling (262 Normal)	270	260	3.8	%

(1)Normal degree days are based on a 20-year moving average of monthly temperature readings from National Oceanic and Atmospheric Administration weather stations within each company's respective service territories.

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 September 30
(in millions)	2025		2024		B (W)
Electric revenues	$	1,611.0	$	1,425.1	$	185.9
Natural gas revenues	180.6		164.9		15.7
Operating revenues	1,791.6		1,590.0		201.6

Operating expenses
Fuel and purchased power	(502.4)		(433.9)		(68.5)
Cost of natural gas sold	(75.8)		(61.4)		(14.4)
Other operation and maintenance (1)	(315.5)		(283.0)		(32.5)
Depreciation and amortization	(255.7)		(232.4)		(23.3)
Property and revenue taxes	(44.5)		(32.8)		(11.7)
Gross margin (GAAP)	597.7		546.5		51.2

Other operation and maintenance (1)	315.5		283.0		32.5
Depreciation and amortization	255.7		232.4		23.3
Property and revenue taxes	44.5		32.8		11.7
Utility margin (non-GAAP)	$	1,213.4	$	1,094.7	$	118.7

(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.

Gross margin (GAAP) at the Wisconsin segment increased $51.2 million during the third quarter of 2025, compared with the same quarter in 2024, and utility margin (non-GAAP) increased $118.7 million during the third quarter of 2025, compared with the same quarter in 2024. Both measures were driven by:

A $97.8 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 $12.6 million increase in margins related to higher sales volumes, including the impact of weather during the third quarter of 2025, compared with the same quarter in 2024.


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A $4.9 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 $23.3 million increase in depreciation and amortization expense;
A $15.4 million increase in other operating and maintenance related to our power plants;
An $11.7 million increase in property and revenues taxes;
A $10.4 million increase in transmission expense; and
A $6.6 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 $75.2 million during the third quarter of 2025, compared with the same quarter in 2024. The significant factors impacting the increase in other operating expenses were:

A $23.3 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.
A $15.4 million increase in other operating and maintenance related to our power plants, partially driven by renewable generation facilities placed in service during 2025 and the fourth quarter of 2024.
An $11.7 million increase in property and revenue taxes during the third quarter of 2025, compared with the same quarter in 2024, driven by a favorable 2024 adjustment related to a sales tax audit.
A $10.4 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 $6.6 million increase in electric and natural gas distribution expenses, driven by higher costs to maintain the distribution systems during the third quarter of 2025, compared with the same quarter in 2024.
A $6.6 million increase in benefits expenses, driven by higher compensation costs.

Other Income, Net

Other income, net at the Wisconsin segment decreased $10.7 million during the third quarter of 2025, compared with the same quarter in 2024, driven by a $19.7 million negative impact from the non-service components of our net periodic pension and OPEB costs. In accordance with our December 2024 PSCW rate orders, in 2025, we began amortizing our pension and OPEB costs that were previously deferred under escrow accounting. During the third quarter of 2025, we amortized $12.1 million of the previously deferred non-service costs as we are now collecting these costs in rates. See Note 16, Employee Benefits, for more information on our benefit costs. This decrease in other income, net was partially offset by a $9.1 million positive impact from higher AFUDC-Equity due to continued capital investment.


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Interest Expense

Interest expense at the Wisconsin segment decreased $1.4 million during the third quarter of 2025, compared with the same quarter in 2024, due to higher AFUDC-Debt due to continued capital investment, lower average short-term debt balances, and lower average short-term debt interest rates. Partially offsetting these decreases were the impact of WE, WPS, WG, and UMERC issuing long-term debt.

Income Tax Expense

Income tax expense at the Wisconsin segment decreased $9.3 million during the third quarter of 2025, compared with the same quarter in 2024, driven by:

A $6.2 million increase in the benefit from the flow through of tax repairs in connection with the Wisconsin rate orders approved by the PSCW, effective January 1, 2025;
A $4.9 million increase in PTCs; and
A $3.7 million increase in income tax benefits associated with AFUDC-Equity, driven by continued capital investment.

Partially offsetting these decreases in income tax expense was higher pre-tax income.

Illinois Segment Contribution to Net Income Attributed to Common Shareholders

The Illinois segment's net loss attributed to common shareholders was $30.5 million during the third quarter of 2025, representing an $18.1 million, or 37.2%, reduction in net loss over the same quarter in 2024. The lower net loss was driven by the positive quarter-over-quarter impact of the $25.3 million pre-tax charge to income recorded in the third quarter of 2024 related to the ICC's disallowance of certain capital costs in PGL's 2016 rider QIP reconciliation. See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Regulatory Recovery and Note 23, Regulatory Environment, for more information on the ICC disallowance.

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 September 30
(in millions)	2025		2024		B (W)
Operating revenues	$	183.5	$	173.6	$	9.9

Operating expenses
Cost of natural gas sold	21.4		17.8		(3.6)
Other operation and maintenance	108.0		126.5		18.5
Depreciation and amortization	65.0		63.9		(1.1)
Property and revenue taxes	11.4		12.2		0.8
Operating loss	(22.3)		(46.8)		24.5

Other income, net	2.1		1.5		0.6
Interest expense	21.8		22.3		0.5
Loss before income taxes	(42.0)		(67.6)		25.6

Income tax benefit	(11.5)		(19.0)		(7.5)
Net loss attributed to common shareholders	$	(30.5)	$	(48.6)	$	18.1


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


	Three Months Ended September 30
(in millions)	2025		2024		B (W)
Operation and maintenance not included in the line items below	$	87.6	$	87.7	$	0.1
Riders (1)	19.6		26.2		6.6
Regulatory amortizations (1)	0.8		0.5		(0.3)
Impairment related to ICC disallowance (2)	—		12.1		12.1

Total other operation and maintenance	$	108.0	$	126.5	$	18.5

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

(2)See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Regulatory Recovery and Note 23, Regulatory Environment, for more information on the ICC disallowance.

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


	Three Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2025	2024	B (W)
Customer Class
Residential	43.3	42.9	0.4
Commercial and industrial	20.8	21.5	(0.7)
Total retail	64.1	64.4	(0.3)
Transportation	82.4	83.0	(0.6)
Total sales in therms	146.5	147.4	(0.9)


	Three Months Ended September 30
	Degree Days
Weather (1)	2025	2024	B (W)
Heating (50 Normal)	34	14	142.9	%

(1)Normal heating degree days are based on a 12-year moving average of monthly temperature readings from National Oceanic and Atmospheric Administration weather stations throughout our Illinois service territories.


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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).


	Three Months Ended September 30
(in millions)	2025		2024		B (W)
Operating revenues	$	183.5	$	173.6	$	9.9

Operating expenses
Cost of natural gas sold	(21.4)		(17.8)		(3.6)
Other operation and maintenance (1)	(58.9)		(59.0)		0.1
Depreciation and amortization	(65.0)		(63.9)		(1.1)
Property and revenue taxes	(11.4)		(12.2)		0.8
Gross margin (GAAP)	26.8		20.7		6.1

Other operation and maintenance (1)	58.9		59.0		(0.1)
Depreciation and amortization	65.0		63.9		1.1
Property and revenue taxes	11.4		12.2		(0.8)
Utility margin (non-GAAP)	$	162.1	$	155.8	$	6.3

(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 increased $6.1 million during the third quarter of 2025, compared with the same quarter in 2024, and utility margin (non-GAAP) increased $6.3 million during the third quarter of 2025, compared with the same quarter in 2024.

Both measures were impacted by a $12.9 million increase in revenues driven by a disallowance recorded in 2024 related to an ICC order received in August 2024 related to PGL's 2016 Rider QIP reconciliation prudency review, which required refunds to ratepayers for amounts previously collected related to the disallowance of certain capital costs. See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Regulatory Recovery and Note 23, Regulatory Environment, for more information on the ICC disallowance. This increase in gross margin (GAAP) and utility margin (non-GAAP) was partially offset by a $6.6 million decrease 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.

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

Other operating expenses at the Illinois segment decreased $11.6 million, net of the $6.6 million impact of the riders referenced in the table above, during the third quarter of 2025, compared with the same quarter in 2024. The significant factors impacting the decrease in other operating expenses were:

A $12.1 million impairment recorded in 2024 related to an ICC order received in August 2024 related to the 2016 annual prudency review of PGL's 2016 Rider QIP, which included a disallowance of certain capital costs. See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Regulatory Recovery and Note 23, Regulatory Environment, for more information on the ICC disallowance.

*•*A $2.0 million decrease in natural gas distribution and maintenance costs, primarily related to maintaining the natural gas infrastructure.

These decreases in other operating expenses were partially offset by a $2.1 million increase in benefits expenses, driven by higher compensation costs.


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Interest Expense

Interest expense at the Illinois segment decreased $0.5 million during the third quarter of 2025, compared with the same quarter in 2024, driven by the impact of a series of PGL's first mortgage bonds maturing in November 2024.

Income Tax Benefit

The income tax benefit at the Illinois segment decreased $7.5 million during the third quarter of 2025, compared with the same quarter in 2024, driven by a decrease in pre-tax loss.

Other States Segment Contribution to Net Income Attributed to Common Shareholders

The other states segment's net loss attributed to common shareholders was $8.9 million during the third quarter of 2025, representing a $5.2 million, or 140.5%, increase in net loss over the same quarter in 2024. The higher net loss was driven by an increase in property and revenue taxes and higher interest expense.

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 September 30
(in millions)	2025		2024		B (W)
Operating revenues	$	53.0	$	53.0	$	—

Operating expenses
Cost of natural gas sold	17.5		16.9		(0.6)
Other operation and maintenance	23.6		22.6		(1.0)
Depreciation and amortization	12.5		12.0		(0.5)
Property and revenue taxes	6.6		2.6		(4.0)
Operating loss	(7.2)		(1.1)		(6.1)

Other income, net	0.1		0.2		(0.1)
Interest expense	5.0		4.1		(0.9)
Loss before income taxes	(12.1)		(5.0)		(7.1)

Income tax benefit	(3.2)		(1.3)		1.9
Net loss attributed to common shareholders	$	(8.9)	$	(3.7)	$	(5.2)

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


	Three Months Ended September 30
(in millions)	2025		2024		B (W)
Operation and maintenance not included in line item below	$	21.4	$	20.1	$	(1.3)
Regulatory amortizations and other pass through expenses (1)	2.2		2.5		0.3

Total other operation and maintenance	$	23.6	$	22.6	$	(1.0)

(1)Regulatory amortizations and other pass through expenses 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 September 30
	Therms (in millions)
Natural Gas Sales Volumes	2025	2024	B (W)
Customer Class
Residential	16.8	16.0	0.8
Commercial and industrial	15.4	12.1	3.3
Total retail	32.2	28.1	4.1
Transportation	159.8	187.6	(27.8)
Total sales in therms	192.0	215.7	(23.7)


	Three Months Ended September 30
	Degree Days
Weather (1)	2025	2024	B (W)
MERC
Heating (189 Normal)	148	88	68.2	%

MGU
Heating (115 Normal)	92	48	91.7	%

(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 temperature readings from National Oceanic and Atmospheric Administration weather stations throughout their respective service territories.

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 September 30
(in millions)	2025		2024		B (W)
Operating revenues	$	53.0	$	53.0	$	—

Operating expenses
Cost of natural gas sold	(17.5)		(16.9)		(0.6)
Other operation and maintenance (1)	(15.0)		(14.5)		(0.5)
Depreciation and amortization	(12.5)		(12.0)		(0.5)
Property and revenue taxes	(6.6)		(2.6)		(4.0)
Gross margin (GAAP)	1.4		7.0		(5.6)

Other operation and maintenance (1)	15.0		14.5		0.5
Depreciation and amortization	12.5		12.0		0.5
Property and revenue taxes	6.6		2.6		4.0
Utility margin (non-GAAP)	$	35.5	$	36.1	$	(0.6)

Gross margin (GAAP) decreased $5.6 million during the third quarter of 2025, compared with the same quarter in 2024, and utility margin (non-GAAP) decreased $0.6 million during the third quarter of 2025, compared with the same quarter in 2024. The larger decrease in gross margin (GAAP) as compared to the decrease in utility margin (non-GAAP), was driven by a $4.0 million increase in property and revenue taxes that is further described in Other Operating Expenses below.


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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 other states segment increased $5.5 million during the third quarter of 2025, compared with the same quarter in 2024. The significant factors impacting the increase in operating expenses were:

A $4.0 million increase in property and revenue taxes, driven by the quarter-over-quarter impact from a positive resolution of a use tax audit at MGU during the third quarter of 2024.

*•*A $0.5 million increase in benefits expenses, driven by higher compensation costs.

Interest Expense

Interest expense at the other states segment increased $0.9 million during the third 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. This increase was partially offset by lower average short-term debt interest rates.

Income Tax Benefit

The income tax benefit at the other states segment increased $1.9 million during the third quarter of 2025, compared with the same quarter in 2024, driven by higher pre-tax loss.

Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders


	Three Months Ended September 30
(in millions)	2025		2024		B (W)
Equity in earnings of transmission affiliates	$	54.8	$	46.7	$	8.1
Interest expense	4.8		4.8		—
Income before income taxes	50.0		41.9		8.1

Income tax expense	12.7		10.2		(2.5)
Net income attributed to common shareholders	$	37.3	$	31.7	$	5.6

Equity in Earnings of Transmission Affiliates

Equity in earnings of transmission affiliates increased $8.1 million during the third 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 $2.5 million during the third quarter of 2025, compared with the same quarter in 2024, driven by higher pre-tax income.


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


	Three Months Ended September 30
(in millions)	2025		2024		B (W)
Operating income	$	92.0	$	90.4	$	1.6

Other income, net	0.8		0.2		0.6
Interest expense	30.5		23.4		(7.1)
Income before income taxes	62.3		67.2		(4.9)

Income tax benefit	(24.2)		(16.0)		8.2
Net loss attributed to noncontrolling interests	1.4		1.8		(0.4)
Net income attributed to common shareholders	$	87.9	$	85.0	$	2.9

Operating Income

Operating income at the non-utility energy infrastructure segment increased $1.6 million during the third quarter of 2025, compared with the same quarter in 2024, driven by a $15.2 million increase in operating income from new investments in several WECI renewable generation facilities made in late 2024 and early 2025.

This increase in operating income was partially offset by:

A $5.3 million impairment loss recorded at Samson I, Delilah I, and Thunderhead related to storm damage. See Note 6, Property, Plant, and Equipment, for more information on the Samson I and Delilah I storm damage.
A $4.3 million increase in operation and maintenance expenses due primarily to a higher number of equipment repairs at our renewable generation facilities.
A $3.0 million decrease in PPA revenue resulting from lower generation driven primarily by lower wind speeds.

Interest Expense

Interest expense at the non-utility energy infrastructure segment increased $7.1 million during the third 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 $8.2 million during the third 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, 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 September 30
(in millions)	2025		2024		B (W)
Operating loss	$	(2.0)	$	(2.4)	$	0.4

Other income, net	3.7		13.7		(10.0)
Interest expense	90.9		79.0		(11.9)

Loss before income taxes	(89.2)		(67.7)		(21.5)

Income tax expense (benefit)	6.6		(5.6)		(12.2)
Net loss attributed to common shareholders	$	(95.8)	$	(62.1)	$	(33.7)


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Other Income, Net

Other income, net at the corporate and other segment decreased $10.0 million during the third quarter of 2025, compared with the same quarter in 2024, driven by an $8.7 million net loss from our equity method investments in technology and energy-focused investment funds during the third quarter of 2025, compared with net earnings of $0.3 million during the same quarter in 2024.

Interest Expense

Interest expense at the corporate and other segment increased $11.9 million during the third quarter of 2025, compared with the same quarter in 2024, primarily due to the impact of long-term debt issuances by WEC Energy Group in December 2024 and June 2025.

Income Tax Expense (Benefit)

At the corporate and other segment, $6.6 million of income tax expense was recorded during the third quarter of 2025, compared with $5.6 million of income tax benefit recorded during the same quarter in 2024. This change was driven by:

A $16.1 million increase in the interim tax expense recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate during the third quarter of 2025, compared with the same quarter in 2024; and
A $3.2 million favorable resolution of a prior period tax audit during the third quarter of 2024.

Partially offsetting these changes was an increase in pre-tax loss.

NINE MONTHS ENDED SEPTEMBER 30, 2025

Consolidated Earnings

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


	Nine Months Ended September 30
(in millions, except per share data)	2025		2024		B (W)
Wisconsin	$	823.6	$	636.3	$	187.3
Illinois	170.2		164.6		5.6
Other states	37.7		35.5		2.2
Electric transmission	109.8		93.2		16.6
Non-utility energy infrastructure	279.0		272.6		6.4
Corporate and other	(179.4)		(128.5)		(50.9)
Net income attributed to common shareholders	$	1,240.9	$	1,073.7	$	167.2

Diluted EPS	$	3.85	$	3.40	$	0.45

Earnings increased $167.2 million during the nine months ended September 30, 2025, compared with the same period in 2024. The significant factors impacting the $167.2 million increase in earnings were:

A $187.3 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, higher retail sales volumes, and an increase in certain income tax benefits. These positive impacts were partially offset by higher operating expenses, largely due to increases in depreciation and amortization expense, transmission expense, and costs related to our power plants, as well as lower other income, driven by a negative impact from the non-service components of our net periodic pension and OPEB costs.
A $16.6 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.


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These increases in earnings were partially offset by a $50.9 million increase in the net loss attributed to common shareholders at the corporate and other segment, driven by higher interest expense and a net loss from our equity method investments in technology and energy-focused investment funds.

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 $823.6 million during the nine months ended September 30, 2025, representing a $187.3 million, or 29.4%, 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, higher retail sales volumes, and an increase in certain income tax benefits. These positive impacts were partially offset by higher operating expenses, largely due to increases in depreciation and amortization expense, transmission expense, and costs related to our power plants, as well as lower other income, driven by a negative impact from the non-service components of our net periodic pension and OPEB costs.


	Nine Months Ended September 30
(in millions)	2025		2024		B (W)
Operating revenues	$	5,438.7	$	4,737.0	$	701.7

Operating expenses
Cost of sales (1)	1,867.2		1,560.3		(306.9)
Other operation and maintenance	1,274.8		1,182.6		(92.2)
Depreciation and amortization	749.5		685.3		(64.2)
Property and revenue taxes	135.0		125.0		(10.0)
Operating income	1,412.2		1,183.8		228.4

Other income, net	62.4		101.4		(39.0)
Interest expense	478.6		475.4		(3.2)
Income before income taxes	996.0		809.8		186.2

Income tax expense	171.5		172.6		1.1
Preferred stock dividends of subsidiary	0.9		0.9		—
Net income attributed to common shareholders	$	823.6	$	636.3	$	187.3

(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:


	Nine Months Ended September 30
(in millions)	2025		2024		B (W)
Operation and maintenance not included in line items below	$	571.7	$	518.5	$	(53.2)
Transmission (1)	439.1		407.3		(31.8)
Regulatory amortizations and other pass through expenses (2)	170.5		160.2		(10.3)
We Power (3)	97.0		99.2		2.2


Earnings sharing mechanisms	(3.5)		(2.6)		0.9
Total other operation and maintenance	$	1,274.8	$	1,182.6	$	(92.2)

(1)Represents transmission expense that our electric utilities are authorized to collect in rates. The PSCW has approved escrow accounting for ATC and MISO network transmission expenses for WE and WPS. As a result, WE and WPS defer as a regulatory asset or liability, the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the nine months ended September 30, 2025 and 2024, $466.7 million and $425.4 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 nine months ended September 30, 2025 and 2024, $88.9 million and $86.7 million, respectively, of costs were billed to or incurred by WE related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.


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


	Nine Months Ended September 30
	MWh (in thousands)
Electric Sales Volumes	2025	2024	B (W)
Customer Class
Residential	8,700.3	8,442.8	257.5
Small commercial and industrial (1)	9,879.1	9,753.7	125.4
Large commercial and industrial (1)	9,095.6	9,026.5	69.1
Other	84.2	89.5	(5.3)
Total retail (1)	27,759.2	27,312.5	446.7
Wholesale	1,342.6	1,273.1	69.5
Resale	4,486.4	4,292.2	194.2
Total sales in MWh (1)	33,588.2	32,877.8	710.4

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


	Nine Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2025	2024	B (W)
Customer Class
Residential	761.6	649.0	112.6
Commercial and industrial	502.9	425.9	77.0
Total retail	1,264.5	1,074.9	189.6
Transportation	1,005.4	957.7	47.7
Total sales in therms	2,269.9	2,032.6	237.3


	Nine Months Ended September 30
	Degree Days
Weather (1)	2025	2024	B (W)
WE and WG
Heating (4,176 Normal)	4,364	3,360	29.9	%
Cooling (707 Normal)	750	802	(6.5)	%

WPS
Heating (4,683 Normal)	4,577	3,852	18.8	%
Cooling (572 Normal)	629	594	5.9	%

UMERC
Heating (5,371 Normal)	5,341	4,644	15.0	%
Cooling (350 Normal)	372	317	17.4	%

(1)Normal degree days are based on a 20-year moving average of monthly temperature readings from the National Oceanic and Atmospheric Administration weather stations within each company's respective service territories.


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Gross Margin GAAP and Utility Margin Non-GAAP


	Nine Months Ended September 30
(in millions)	2025		2024		B (W)
Electric revenues	$	4,242.6	$	3,766.7	$	475.9
Natural gas revenues	1,196.1		970.3		225.8
Operating revenues	5,438.7		4,737.0		701.7

Operating expenses
Fuel and purchased power	(1,284.5)		(1,115.4)		(169.1)
Cost of natural gas sold	(582.7)		(444.9)		(137.8)
Other operation and maintenance (1)	(920.2)		(850.8)		(69.4)
Depreciation and amortization	(749.5)		(685.3)		(64.2)
Property and revenue taxes	(135.0)		(125.0)		(10.0)
Gross margin (GAAP)	1,766.8		1,515.6		251.2

Other operation and maintenance (1)	920.2		850.8		69.4
Depreciation and amortization	749.5		685.3		64.2
Property and revenue taxes	135.0		125.0		10.0
Utility margin (non-GAAP)	$	3,571.5	$	3,176.7	$	394.8

Gross margin (GAAP) at the Wisconsin segment increased $251.2 million during the nine months ended September 30, 2025, compared with the same period in 2024, and utility margin (non-GAAP) increased $394.8 million during the nine months ended September 30, 2025, compared with the same period in 2024. Both measures were driven by:

A $295.1 million increase in margins driven by the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2025.
A $96.6 million increase in margins related to higher sales volumes, driven by the impact of colder weather during the nine months ended September 30, 2025, compared with the same period in 2024. As measured by heating degree days, the nine months ended September 30, 2025 were 29.9% and 18.8% colder than the same period in 2024 in the combined WE and WG service area and the WPS service area, respectively. As measured by cooling degree days, the nine months ended September 30, 2025 were 5.9% warmer than the same period in 2024 in the WPS service area.

A $64.2 million increase in depreciation and amortization expense;
A $31.8 million increase in transmission expense;
A $20.4 million increase in other operating and maintenance related to our power plants;
A $19.3 million increase in electric and natural gas distribution expenses; and
A $10.0 million increase in property and revenues taxes.


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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 $166.4 million during the nine months ended September 30, 2025, compared with the same period in 2024. The significant factors impacting the increase in other operating expenses were:

A $64.2 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.
A $31.8 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 $20.4 million increase in other operating and maintenance related to our power plants, driven by outages at certain of our generation facilities, inspections at the Fox Energy Center natural gas-fired generation facility, and renewable generation facilities placed in service during 2025 and the fourth quarter of 2024.
A $19.3 million increase in electric and natural gas distribution expenses, driven by higher costs to maintain the distribution systems during the nine months ended September 30, 2025, compared with the same period in 2024.
A $10.3 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.
A $10.0 million increase in property and revenue taxes during the nine months ended September 30, 2025, compared with the same period in 2024, driven by a favorable 2024 adjustment related to a sales tax audit.
An $8.2 million increase in benefits expenses, driven by higher compensation costs.

Other Income, Net

Other income, net at the Wisconsin segment decreased $39.0 million during the nine months ended September 30, 2025, compared with the same period in 2024, driven by a $63.7 million negative impact from the non-service components of our net periodic pension and OPEB costs. In accordance with our December 2024 PSCW rate orders, in 2025, we began amortizing our pension and OPEB costs that were previously deferred under escrow accounting. During the nine months ended September 30, 2025, we amortized $36.3 million of the previously deferred non-service costs as we are now collecting these costs in rates. This decrease in other income, net was partially offset by a $22.3 million positive impact from higher AFUDC-Equity due to continued capital investment.

Interest Expense

Interest expense at the Wisconsin segment increased $3.2 million during the nine months ended September 30, 2025, compared with the same period in 2024. The increase was primarily driven by the impact of WE, WPS, WG, and UMERC issuing long-term debt. Partially offsetting the increase was lower average short-term debt balances, lower average short-term debt interest rates, and higher AFUDC-Debt due to continued capital investment.

Income Tax Expense

Income tax expense at the Wisconsin segment decreased $1.1 million during the nine months ended September 30, 2025, compared with the same period in 2024. This decrease was driven by:

A $19.7 million increase in PTCs;
A $16.4 million increase in the benefit from the flow through of tax repairs in connection with the Wisconsin rate orders approved by the PSCW, effective January 1, 2025;
A $6.8 million increase in the income tax benefits associated with AFUDC-Equity, driven by continued capital investment; and


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A $5.8 million increase in the deferred tax benefits associated with the Tax Legislation.

Substantially offsetting these decreases in income tax expense was higher pre-tax income.

Illinois Segment Contribution to Net Income Attributed to Common Shareholders

The Illinois segment's contribution to net income attributed to common shareholders was $170.2 million during the nine months ended September 30, 2025, representing a $5.6 million, or 3.4%, increase over the same period in 2024. The increase was driven by the positive period-over-period impact of the $25.3 million pre-tax charge to income recorded in the third quarter of 2024 related to the ICC's disallowance of certain capital costs in PGL's 2016 rider QIP reconciliation. This positive impact was partially offset by higher operating expenses, driven by the period-over-period impact from a favorable settlement of a legal claim during 2024, higher benefit costs, and an increase in maintenance costs related to the Manlove Gas Storage Field and our natural gas infrastructure.


	Nine Months Ended September 30
(in millions)	2025		2024		B (W)
Operating revenues	$	1,242.4	$	1,116.4	$	126.0

Operating expenses
Cost of natural gas sold	339.1		254.3		(84.8)
Other operation and maintenance	367.3		336.1		(31.2)
Depreciation and amortization	194.2		191.1		(3.1)
Property and revenue taxes	44.6		41.9		(2.7)
Operating income	297.2		293.0		4.2

Other income, net	6.5		5.7		0.8
Interest expense	67.1		70.8		3.7
Income before income taxes	236.6		227.9		8.7

Income tax expense	66.4		63.3		(3.1)
Net income attributed to common shareholders	$	170.2	$	164.6	$	5.6

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


	Nine Months Ended September 30
(in millions)	2025		2024		B (W)
Operation and maintenance not included in the line items below	$	249.4	$	231.1	$	(18.3)
Riders (1)	115.8		90.9		(24.9)
Regulatory amortizations (1)	2.1		2.0		(0.1)
Impairment related to ICC disallowance (2)	—		12.1		12.1

Total other operation and maintenance	$	367.3	$	336.1	$	(31.2)

(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:


	Nine Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2025	2024	B (W)
Customer Class
Residential	577.5	500.7	76.8
Commercial and industrial	215.4	195.8	19.6
Total retail	792.9	696.5	96.4
Transportation	539.8	493.3	46.5
Total sales in therms	1,332.7	1,189.8	142.9


	Nine Months Ended September 30
	Degree Days
Weather (1)	2025	2024	B (W)
Heating (3,831 Normal)	3,774	3,078	22.6	%

Gross Margin GAAP and Utility Margin Non-GAAP


	Nine Months Ended September 30
(in millions)	2025		2024		B (W)
Operating revenues	$	1,242.4	$	1,116.4	$	126.0

Operating expenses
Cost of natural gas sold	(339.1)		(254.3)		(84.8)
Other operation and maintenance (1)	(179.9)		(167.4)		(12.5)
Depreciation and amortization	(194.2)		(191.1)		(3.1)
Property and revenue taxes	(44.6)		(41.9)		(2.7)
Gross margin (GAAP)	484.6		461.7		22.9

Other operation and maintenance (1)	179.9		167.4		12.5
Depreciation and amortization	194.2		191.1		3.1
Property and revenue taxes	44.6		41.9		2.7
Utility margin (non-GAAP)	$	903.3	$	862.1	$	41.2

Gross margin (GAAP) at the Illinois segment increased $22.9 million during the nine months ended September 30, 2025, compared with the same period in 2024, and utility margin (non-GAAP) increased $41.2 million during the nine months ended September 30, 2025, compared with the same period in 2024. Both measures were driven by:

A $24.9 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 $12.9 million increase in revenues driven by a disallowance recorded in 2024 related to an ICC order received in August 2024 related to PGL's 2016 Rider QIP reconciliation prudency review, which required refunds to ratepayers for amounts previously collected related to the disallowance of certain capital costs.
A $2.2 million increase in revenues related to the impact of the NSG rate order issued by the ICC, effective February 1, 2024.


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A $4.1 million increase in costs associated with maintenance at the Manlove Gas Storage Field;
A $4.1 million increase in natural gas distribution and maintenance costs;
A $3.1 million increase in depreciation and amortization expense; and
A $2.7 million increase in property and revenue taxes.

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

Other operating expenses at the Illinois segment increased $12.1 million, net of the $24.9 million impact of the riders referenced in the table above, during the nine months ended September 30, 2025, compared with the same period in 2024. The significant factors impacting the increase in other operating expenses were:

A $10.3 million increase in expense primarily associated with the favorable settlement of a legal claim during the nine months ended September 30, 2024.
A $4.1 million increase in benefits expenses, driven by higher compensation costs.
A $4.1 million increase in costs associated with maintenance at the Manlove Gas Storage Field.
A $4.1 million increase in natural gas distribution and maintenance costs, primarily related to maintaining the natural gas infrastructure.
A $3.1 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.
A $2.7 million increase in property and revenue taxes, driven by an increase in property and use taxes.

These increases in operating expenses were partially offset by:

A $12.1 million impairment recorded in 2024 related to an ICC order received in August 2024 related to the 2016 annual prudency review of PGL's 2016 Rider QIP, which included a disallowance of certain capital costs.
A $2.7 million pre-tax gain on the renegotiation of a lease contract during the nine months ended September 30, 2025.

Interest Expense

Interest expense at the Illinois segment decreased $3.7 million during the nine months ended September 30, 2025, compared with the same period in 2024, due to lower average short-term debt balances, lower average 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 increased $3.1 million during the nine months ended September 30, 2025, compared with the same period in 2024, driven by an increase in pre-tax income.


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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 $37.7 million during the nine months ended September 30, 2025, representing a $2.2 million, or 6.2%, 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.


	Nine Months Ended September 30
(in millions)	2025		2024		B (W)
Operating revenues	$	362.4	$	308.6	$	53.8

Operating expenses
Cost of natural gas sold	165.1		131.5		(33.6)
Other operation and maintenance	76.2		67.8		(8.4)
Depreciation and amortization	37.0		34.9		(2.1)
Property and revenue taxes	19.9		15.1		(4.8)
Operating income	64.2		59.3		4.9

Other income, net	0.3		0.3		—
Interest expense	14.0		12.1		(1.9)
Income before income taxes	50.5		47.5		3.0

Income tax expense	12.8		12.0		(0.8)
Net income attributed to common shareholders	$	37.7	$	35.5	$	2.2

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


	Nine Months Ended September 30
(in millions)	2025		2024		B (W)
Operation and maintenance not included in line item below	$	60.7	$	56.5	$	(4.2)
Regulatory amortizations and other pass through expenses (1)	15.5		11.3		(4.2)

Total other operation and maintenance	$	76.2	$	67.8	$	(8.4)

(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:


	Nine Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2025	2024	B (W)
Customer Class
Residential	218.0	189.2	28.8
Commercial and industrial	138.6	118.8	19.8
Total retail	356.6	308.0	48.6
Transportation	550.7	612.2	(61.5)
Total sales in therms	907.3	920.2	(12.9)


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	Nine Months Ended September 30
	Degree Days
Weather (1)	2025	2024	B (W)
MERC
Heating (5,043 Normal)	4,938	4,267	15.7	%

MGU
Heating (3,997 Normal)	3,915	3,259	20.1	%

Gross Margin GAAP and Utility Margin Non-GAAP


	Nine Months Ended September 30
(in millions)	2025		2024		B (W)
Operating revenues	$	362.4	$	308.6	$	53.8

Operating expenses
Cost of natural gas sold	(165.1)		(131.5)		(33.6)
Other operation and maintenance (1)	(44.4)		(41.5)		(2.9)
Depreciation and amortization	(37.0)		(34.9)		(2.1)
Property and revenue taxes	(19.9)		(15.1)		(4.8)
Gross margin (GAAP)	96.0		85.6		10.4

Other operation and maintenance (1)	44.4		41.5		2.9
Depreciation and amortization	37.0		34.9		2.1
Property and revenue taxes	19.9		15.1		4.8
Utility margin (non-GAAP)	$	197.3	$	177.1	$	20.2

Gross margin (GAAP) increased $10.4 million during the nine months ended September 30, 2025, compared with the same period in 2024, and utility margin (non-GAAP) increased $20.2 million during the nine months ended September 30, 2025, compared with the same period in 2024. Both measures were driven by:

An $8.4 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 $5.2 million increase related to higher sales volumes, driven by colder weather during the nine months ended September 30, 2025, as compared to the same period in 2024. As measured by heating degree days, the nine months ended September 30, 2025, was 15.7% and 20.1% colder than the same period in 2024 at MERC and MGU, respectively.
A $3.9 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 ratepayers using the Conservation Cost Recovery Charge and the Conservation Cost Recovery Adjustment funds that are collected on their monthly billing statements.
A $1.5 million increase related to MGU's energy optimization program, which provides rebates, incentives, and energy efficiency

education to customers.


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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 $4.8 million increase in property and revenue taxes;
A $2.9 million increase in natural gas operations and customer service expense; and
A $2.1 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 $15.3 million during the nine months ended September 30, 2025, compared with the same period in 2024. The significant factors impacting the increase in operating expenses were:

A $4.8 million increase in property and revenue taxes, driven by the period-over-period impact from a positive resolution of a use tax audit at MGU during 2024.
A $3.9 million increase in operation and maintenance expense related to MERC's CIP program, which has an offsetting increase in margins.
A $2.9 million increase in natural gas operations and customer service expense, driven by higher metering costs at MERC and MGU.
A $2.1 million increase in depreciation and amortization expense related to continued capital investment.
A $1.4 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.

Interest Expense

Interest expense at the other states segment increased $1.9 million during the nine months ended September 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 $0.8 million during the nine months ended September 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


	Nine Months Ended September 30
(in millions)	2025		2024		B (W)
Equity in earnings of transmission affiliates	$	160.3	$	138.3	$	22.0
Interest expense	14.5		14.5		—
Income before income taxes	145.8		123.8		22.0

Income tax expense	36.0		30.6		(5.4)
Net income attributed to common shareholders	$	109.8	$	93.2	$	16.6

Equity in Earnings of Transmission Affiliates

Equity in earnings of transmission affiliates increased $22.0 million during the nine months ended September 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.


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Income Tax Expense

Income tax expense at the electric transmission segment increased $5.4 million during the nine months ended September 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


	Nine Months Ended September 30
(in millions)	2025		2024		B (W)
Operating income	$	267.6	$	280.8	$	(13.2)

Other income, net	2.2		0.4		1.8
Interest expense	92.6		71.6		(21.0)
Income before income taxes	177.2		209.6		(32.4)

Income tax benefit	(98.7)		(59.6)		39.1
Net loss attributed to noncontrolling interests	3.1		3.4		(0.3)
Net income attributed to common shareholders	$	279.0	$	272.6	$	6.4

Operating Income

Operating income at the non-utility energy infrastructure segment decreased $13.2 million during the nine months ended September 30, 2025, compared with the same period in 2024, driven by these items at WECI:

A $16.9 million impairment loss recorded at Samson I, Delilah I, and Thunderhead related to storm damage.
A $15.4 million net negative impact related to the receipt of lower performance payments in 2025.
An $8.7 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 $24.9 million increase in operating income from new investments in several WECI renewable generation facilities made in late 2024 and early 2025.

In addition to the above items at WECI, there was a $2.1 million positive impact from We Power due to continued capital investment.

Interest Expense

Interest expense at the non-utility energy infrastructure segment increased $21.0 million during the nine months ended September 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 $39.1 million during the nine months ended September 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.


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


	Nine Months Ended September 30
(in millions)	2025		2024		B (W)
Operating loss	$	(6.8)	$	(6.1)	$	(0.7)

Other income, net	20.3		41.7		(21.4)
Interest expense	266.3		222.1		(44.2)

Loss before income taxes	(252.8)		(186.5)		(66.3)

Income tax benefit	(73.4)		(58.0)		15.4
Net loss attributed to common shareholders	$	(179.4)	$	(128.5)	$	(50.9)

Other Income, Net

Other income, net at the corporate and other segment decreased $21.4 million during the nine months ended September 30, 2025, compared with the same period in 2024. The significant factors impacting the decrease in other income, net were:

A $16.4 million decrease due to a $12.8 million net loss from our equity method investments in technology and energy-focused investment funds during the nine months ended September 30, 2025, compared with net earnings of $3.6 million during the same period in 2024.
A $3.4 million decrease due to lower net gains from the investments held in the Integrys rabbi trust during the nine months ended September 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 $44.2 million during the nine months ended September 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 $15.4 million during the nine months ended September 30, 2025, compared with the same period in 2024. This increase was driven by:

Higher pre-tax loss.
A $3.7 million increase in excess tax benefits recognized related to stock option exercises.

These increases in the income tax benefit were partially offset by:

A $3.2 million favorable resolution of a prior period tax audit during the nine months ended September 30, 2024; and
A $2.5 million increase in the interim tax expense recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate during the nine months ended September 30, 2025, compared with the same period in 2024.


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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 nine months ended September 30:


(in millions)	2025		2024		Change in 2025 Over 2024
Cash provided by (used in):
Operating activities	$	2,954.8	$	2,630.0	$	324.8
Investing activities	(3,570.5)		(2,053.2)		(1,517.3)
Financing activities	691.2		(381.0)		1,072.2

Operating Activities

Net cash provided by operating activities increased $324.8 million during the nine months ended September 30, 2025, compared with the same period in 2024, driven by:

A $368.9 million increase in cash from higher overall collections from customers during the nine months ended September 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 nine months ended September 30, 2025, compared with the same period in 2024.
A $50.8 million increase in cash from lower payments for environmental remediation related to work completed on former manufactured gas plant sites during the nine months ended September 30, 2025, compared with the same period in 2024.
A $33.8 million increase in cash from higher distributions from ATC during the nine months ended September 30, 2025, compared with the same period in 2024.

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

A $97.6 million decrease in cash from higher payments for operating and maintenance expenses. During the nine months ended September 30, 2025, our payments were higher due to increased transmission costs, operating and maintenance costs related to our plants, electric and natural gas distribution costs, and benefit expenses.
A $22.3 million decrease in cash from higher payments for interest driven by issuances of long-term debt in 2024 and 2025, partially offset by lower payments for interest due to lower average short-term debt balances and lower short-term interest rates during the nine months ended September 30, 2025, compared with the same period in 2024.

Investing Activities

Net cash used in investing activities increased $1,517.3 million during the nine months ended September 30, 2025, compared with the same period in 2024, driven by:

A $1,160.4 million increase in cash paid for capital expenditures during the nine months ended September 30, 2025, which is discussed in more detail below.
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.


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A $96.9 million increase in capital contributions paid to transmission affiliates during the nine months ended September 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 $97.9 million. See Note 2, Acquisitions, for more information.
A $33.5 million increase in cash received from ATC during the nine months ended September 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.

Capital Expenditures

Capital expenditures by segment for the nine months ended September 30 were as follows:


Reportable Segment (in millions)	2025		2024		Change in 2025 Over 2024
Wisconsin	$	2,692.4	$	1,546.6	$	1,145.8
Illinois	219.3		256.2		(36.9)
Other states	84.5		82.2		2.3
Non-utility energy infrastructure	84.3		33.7		50.6
Corporate and other	14.6		16.0		(1.4)
Total capital expenditures	$	3,095.1	$	1,934.7	$	1,160.4

The increase in cash paid for capital expenditures at the Wisconsin segment during the nine months ended September 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; CTs at OCPP; WE's electric and natural gas distribution systems; and software to enhance productivity, collaboration, and overall efficiency across the company. These increases in capital expenditures were partially offset by decreased payments for construction of WPS's service center completed in October 2024 and WG's LNG facility completed in February 2024.

The decrease in cash paid for capital expenditures at the Illinois segment during the nine months ended September 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. This decrease in capital expenditures was partially offset by increased capital expenditures at Manlove Gas Storage Field.

The increase in cash paid for capital expenditures at the non-utility energy infrastructure segment during the nine months ended September 30, 2025, compared with the same period in 2024, was driven by an increase in capital expenditures related to new generator units at Port Washington Generating Station.

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

Financing Activities

Net cash related to financing activities increased $1,072.2 million during the nine months ended September 30, 2025, compared with the same period in 2024, driven by:

A $1,566.5 million increase in cash due to $141.7 million of net borrowings of commercial paper during the nine months ended September 30, 2025, compared with $1,424.8 million of net repayments of commercial paper during the same period in 2024.
A $695.6 million increase in cash due to higher issuances of common stock during the nine months ended September 30, 2025, compared with the same period in 2024. See Note 7, Common Equity, for more information.
The purchase of an additional 10% ownership interest in Samson I in January 2024 for $28.1 million.


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A $24.2 million increase in cash related to a higher number of stock options exercised during the nine months ended September 30, 2025, compared with the same period in 2024.

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

A $727.8 million decrease in cash due to lower issuances of long-term debt during the nine months ended September 30, 2025, compared with the same period in 2024.
A $448.4 million decrease in cash due to increased retirements of long-term debt during the nine months ended September 30, 2025, compared with the same period in 2024.
A $66.2 million decrease in cash due to higher dividends paid on our common stock during the nine months ended September 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.

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	$	3,815.0	$	4,223.0	$	5,952.5
Illinois	323.6		566.6		738.4
Other states	116.4		115.0		110.5
Non-utility energy infrastructure	484.1		98.2		132.5
Corporate and other	23.0		15.3		15.6
Total	$	4,762.1	$	5,018.1	$	6,949.5

(1)This includes actual capital expenditures incurred through September 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.


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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.


Project	Ownership Interest	Source	Share of Generation	Share of Estimated Costs	Date of Expected Commercial Operation
Paris Solar-Battery Park	90%	Solar/Battery	180 MW/99 MW	$532 million	December 2024 Solar June 2025 Battery (2)
Darien Solar-Battery Park	90%	Solar/Battery	225 MW/68 MW	$560 million	March 2025 Solar (2) 2026 Battery
Koshkonong Solar Park	90%	Solar/Battery	270 MW/149 MW	$930 million	2026 Solar 2027 Battery
Renegade	100%	Solar	100 MW	$226 million	2026
Badger Hollow Wind Energy Generation Facility (1)	90%	Wind	100 MW	$320 million	2027
High Noon	90%	Solar/Battery	270 MW/149 MW	$883 million	2027
OCPP	100%	LNG (2 Bcf)	N/A	$456 million	2027
Paris RICE Generation	100%	RICE	128 MW	$300 million	2027
Rochester Lateral	100%	Gas Lateral	N/A	$200 million	2027
Ursa Solar Electric Generation Facility (1)	90%	Solar	180 MW	$406 million	2027
Whitetail Energy Generation Facility (1)	90%	Wind	60 MW	$200 million	2027
OCPP	100%	CTs	1,100 MW	$1.2 billion	2027-2028
Dawn Harvest Solar Energy Center (1)	90% Solar 100% Battery	Solar/Battery	135 MW/50 MW	$409 million	2028
ERGS Fuel Flexibility (1)	83.34%	Add Gas Capability	N/A	$132 million	2028

Fox Solar (1)	90%	Solar	90 MW	$238 million	2028
Good Oak Solar Generation Facility (1)	90%	Solar	88 MW	$194 million	2028
Gristmill Solar Generation Facility (1)	90%	Solar	60 MW	$130 million	2028
PWGS Turbine Upgrade (1)	100%	Combined Cycle Gas Turbine	100 MW	$227 million	2028
Saratoga Solar Electric Generation and BESS Facility (1)	90%	Solar/Battery	135 MW/45 MW	$406 million	2028
Sinissippi Solar (1)	100%	Solar	100 MW	$277 million	2028
Superior Solar (1)	90%	Solar	135 MW	$354 million	2028
Whitewater Solar Electric Generation Facility (1)	100%	Solar	180 MW	$411 million	2028
Akron Solar (1)	90%	Solar	180 MW	$461 million	2029
Dawn Break Solar and BESS Facility (1)	90%	Solar/Battery	162 MW/162 MW	$697 million	2029
Emerald Bluffs Solar (1)	90%	Solar	203 MW	$510 million	2029

(1) Pending approval by the PSCW.

(2) Commercial operation achieved for Paris Solar-Battery Park and Darien Solar Park.

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 $1 billion. The facilities are expected to reduce the likelihood of constraints on our natural gas distribution system during the highest demand days of winter.

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.


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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. In February, 2025, the ICC issued an order setting expectations for PGL's prospective retirement of its aging natural gas infrastructure. The ICC directed us to focus on retiring all cast and ductile iron pipe that has a diameter of less than 36 inches by January 1, 2035. PGL is working on retiring this cast and ductile iron pipe through its PRP. PGL's projected investment is estimated to be approximately $500 million from 2025 through 2027. 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 $645 million from 2026 through 2028. 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 $700 million between 2026 and 2030, 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 nine months ended September 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 nine months ended September 30, 2025.

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.


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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 September 30, 2025, our current liabilities exceeded our current assets by $2,535.0 million. We do not expect this to have an impact on our liquidity, as we currently believe that 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 September 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	$	13,568.4		$	13,943.4
Preferred stock of subsidiary	30.4			30.4
Long-term debt (including current portion)	19,564.7			19,189.7
Short-term debt	1,260.6			1,260.6
Total capitalization	$	34,424.1		$	34,424.1

Total debt	$	20,825.3		$	20,450.3

Ratio of debt to total capitalization	60.5		%	59.4		%

Included in long-term debt on our balance sheet as of September 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 September 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 September 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 September 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 retirement 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 and regulatory 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 September 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 prudently incurred, but cannot predict the ultimate outcome of this matter. There is no statutory deadline by which the ICC is


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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 September 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 retiring 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 retire 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 expect to initiate a general rate case proceeding in early 2026, which we anticipate will provide further regulatory clarity before we significantly increase our spend associated PRP.

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 2025, the Department of Homeland Security announced the addition of more Chinese businesses to the UFLPA, including several 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

Starting on June 6, 2024, the DOC began applying duties to certain imports of solar cells from Malaysia, Vietnam, Thailand and Cambodia, with the potential for enhanced duties in certain circumstances, based on final findings by both the DOC and the USITC in their AD/CVD investigations that Chinese manufacturers were shifting products to those four Southeast Asian countries to avoid tariffs required on products imported from China.

In April 2024, a coalition of several U.S. producers of solar panels filed a new petition 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 imposed in the first investigation. In April 2025, the DOC reached final affirmative determinations, increasing 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.

In August 2025, in response to another petition filed by a coalition of trade groups, the DOC and USITC initiated new AD/CVD investigations based on the coalition’s claims that Chinese-owned manufacturers in Laos and Indonesia, as well as India-headquartered companies, are benefiting from illegal subsidies and selling solar products below cost in the US. Affirmative findings in these investigations 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, April 2025, and September 2025 to sell the majority of the PTCs and ITCs we generated, or expect to generate, 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.

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


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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.

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. In August 2025, the U.S. Treasury Department released IRS Notice 2025-42, implementing new beginning of construction safe harbor rules that became effective September 2, 2025. The capital plan for 2026 through 2030 reflects the impacts of OBBBA, including the revised beginning of construction rules.

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.

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


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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.

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


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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.

Critical Accounting Policies and Estimates

We have reviewed our critical accounting policies and considered whether any new critical accounting estimates or other significant changes to our accounting policies require additional disclosures. We have found that the disclosures made in our 2024 Annual Report on Form 10-K are still current and that there have been no significant changes, except as follows:

Goodwill

We completed our annual goodwill impairment tests for all of our reporting units that carried a goodwill balance as of July 1, 2025. No impairments were recorded as a result of these tests. For all of our reporting units, the fair values calculated in step one of the test were greater than their carrying values. The fair values for the reporting units were calculated using a combination of the income approach and the market approach.

For the income approach, we used internal forecasts to project cash flows. Any forecast contains a degree of uncertainty, and changes in these cash flows could significantly increase or decrease the calculated fair value of a reporting unit. For our reporting


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units that are regulated, a fair recovery of and return on costs prudently incurred to serve customers is assumed. An unfavorable outcome in a rate case could cause the fair values of our reporting units to decrease.

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

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

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

For all of our reporting units that carried a goodwill balance at July 1, 2025, the fair value exceeded its carrying value by over 50%. Based on these results, our reporting units are not at risk of failing step one of the goodwill impairment test.

See Note 17, Goodwill and Intangibles, for more information.


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