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 2023 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 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 investment plan for efficiency, sustainability and growth, referred to as our ESG Progress Plan, provides a roadmap for us to achieve this goal. It is an aggressive plan to cut emissions, maintain superior reliability, deliver significant savings for customers, and grow our investment in the future of energy.

Throughout our strategic planning process, we take into account important developments, risks and opportunities, including new technologies, customer preferences and affordability, energy resiliency efforts, and sustainability.

Creating a Sustainable Future

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

We have announced goals to achieve reductions in carbon emissions from our electric generation fleet by 60% by the end of 2025 and by 80% by the end of 2030, both from a 2005 baseline. We expect to achieve these goals by continuing to make operating refinements, retiring less efficient generating units, and executing our capital plan. Over the longer term, the target for our generation fleet is to be net carbon neutral by 2050.

As part of our path toward these goals, we have started implementing co-firing with natural gas at the ERGS coal-fired units and plan to co-fire with natural gas at Weston Unit 4. By the end of 2030, we expect to use coal as a backup fuel only, and we believe we will be in a position to eliminate coal as an energy source by the end of 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 Presque Isle power plant, and the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater 4 generating unit. We expect to retire approximately 1,200 MWs of additional fossil-fueled generation by the end of 2031, which includes the planned retirement of OCPP Units 7 and 8, the planned retirement of the jointly-owned Columbia Units 1 and 2, and the planned retirement of Weston Unit 3. For more information on the retirement of OCPP Units 5 and 6, see Note 6, Regulatory Assets and Liabilities. See Note 7, Property, Plant, and Equipment, for more information related to planned power plant retirements.

In addition to retiring these older, fossil-fueled plants, we expect to invest approximately $9.1 billion from 2025-2029 in regulated renewable energy in Wisconsin. Our plan is to replace a portion of the retired capacity by building and owning zero-carbon-emitting renewable generation facilities that are anticipated to include the following new investments:

2,900 MWs of utility-scale solar;
900 MWs of wind; and


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565 MWs of battery storage.

We also plan on investing in a combination of natural gas-fired generation, to be owned by WE, including:

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

In May 2024, WE completed the acquisition of an additional 100 MWs of capacity in West Riverside, a combined cycle natural gas plant operated by an unaffiliated utility. See Note 2, Acquisitions, for more information.

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 28 Solar Now projects and currently has another two under construction, together 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. 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 has signed up five customers for a total of 44 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. The programs provide direct benefits to customers by removing cost barriers associated with installing EV equipment. In October 2021, subject to the receipt of any necessary regulatory approvals, we pledged to expand the EV charging network within the service territories of our electric utilities. In doing so, we joined a coalition of utility companies in a unified effort to make EV charging convenient and widely available throughout the Midwest. The coalition we joined is planning to help build and grow EV charging corridors, enabling the general public to safely and efficiently charge their vehicles.

We also continue to reduce methane emissions by improving our natural gas distribution system. We set a target across our natural gas distribution operations to achieve net-zero methane emissions by the end of 2030. We plan to achieve our net-zero goal through an effort that includes continuous operational improvements and equipment upgrades, as well as the use of 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 will directly replace higher-emission methane from natural gas that would have entered our pipes. We currently have contracts in place for 1.9 Bcf of RNG. In addition, subject to regulatory approval, we may procure RTCs.

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 Valley power plant. 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 2025.

Reliability

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


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

WE and WG have completed the construction of their respective LNG facilities. Each facility provides approximately one Bcf of natural gas supply to meet anticipated peak demand, without requiring the construction of additional interstate pipeline capacity. The WE LNG facility was commercially operational in November 2023 and the WG LNG facility was commercially operational in February 2024.
In April 2024, WE filed a request with the PSCW to construct an LNG facility with a storage capacity of two Bcf, which would be located on the OCPP site. In addition, the construction of additional LNG facilities in Wisconsin has been proposed as part of the 2025-2029 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.
Through the SMP, 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 the SMP until the ICC completes a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level. The ICC initiated the proceeding on January 31, 2024, and the proceeding is expected to last 12 months. For more information, see Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Future Illinois Proceedings.

On January 3, 2024, the ICC granted PGL a limited-scope rehearing, which was limited to the authorized spending for the completion of SMP projects that started in 2023 and the authorized spending for emergency repairs needed to ensure the safety and reliability of PGL's delivery system. On May 30, 2024, the ICC issued a written order on the rehearing. The order approved $28.5 million of additional spending for emergency work, representing a $1.6 million increase to PGL's annual revenue requirement. See Note 25, Regulatory Environment, for more information.

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

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

Operating Efficiency

We continually look for ways to optimize the operating efficiency of our company and will continue to do so under the ESG Progress Plan. For example, we are making progress on our 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 finding the best and most efficient processes.

Financial Discipline

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

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

Our planned investment focus from 2025 to 2029 is in our regulated utilities and our investment in ATC. We expect total capital expenditures for our regulated utility businesses to be approximately $24.4 billion from 2025 to 2029. In addition, we currently forecast that our share of ATC's projected capital expenditures over the next five years will be approximately $3.2 billion. Over the same period, we expect to invest approximately $0.4 billion in our non-utility energy infrastructure business on the acquisition of Hardin III. Specific projects included in the $28.0 billion ESG Progress Plan are discussed in more detail below under Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects. Also, see Note 2, Acquisitions, for information on the acquisition of Hardin III and other recent and pending transactions.


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Exceptional Customer Care

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

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

Safety

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

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

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

RESULTS OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2024

Consolidated Earnings

The following table compares our consolidated results for the third quarter of 2024 with the third quarter of 2023, including favorable or better, "B", and unfavorable or worse, "W", variances:


	Three Months Ended September 30
(in millions, except per share data)	2024		2023		B (W)
Wisconsin	$	237.8	$	243.1	$	(5.3)
Illinois	(48.6)		24.7		(73.3)
Other states	(3.7)		(6.0)		2.3
Electric transmission	31.7		29.7		2.0
Non-utility energy infrastructure	85.0		67.4		17.6
Corporate and other	(62.1)		(42.9)		(19.2)
Net income attributed to common shareholders	$	240.1	$	316.0	$	(75.9)

Diluted earnings per share	$	0.76	$	1.00	$	(0.24)

Earnings decreased $75.9 million during the third quarter of 2024, compared with the same quarter in 2023. The significant factors impacting the $75.9 million decrease in earnings were:

A $73.3 million decrease in earnings at the Illinois segment, driven by lower margins related to the impacts of the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively. SMP costs that were previously being recovered under PGL's QIP rider are now included in PGL's base rates. As base revenues are lower during the third quarter when natural gas usage is lower, this rate design change drove a decrease in third quarter 2024 earnings. See Note 25, Regulatory Environment, for more information on the rate orders. Higher operating expenses and a $25.3 million pre-tax charge to income related to the ICC's disallowance of certain capital costs in PGL's 2016 rider QIP reconciliation also contributed to the lower


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earnings. See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Regulatory Recovery and Note 25, Regulatory Environment, for more information on the ICC disallowance.

A $19.2 million increase in the net loss attributed to common shareholders at the corporate and other segment, driven by a negative impact from 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 also contributed to the increase in the net loss.
A $5.3 million decrease in net income attributed to common shareholders at the Wisconsin segment, driven by higher depreciation and amortization expense and an increase in interest expense on both short-term and long-term debt. These decreases in earnings were partially offset by an increase in margins due to higher retail sales volumes and lower income tax expense due to an increase in PTCs.

These decreases in earnings were partially offset by a $17.6 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by an increase in PTCs from our non-utility renewable generating facilities and a positive impact from We Power due to continued capital investment.

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.


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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 $237.8 million during the third quarter of 2024, representing a $5.3 million, or 2.2%, decrease over the same quarter in 2023. The decrease was driven by higher depreciation and amortization expense and an increase in interest expense on both short-term and long-term debt. These decreases in earnings were partially offset by an increase in margins due to higher retail sales volumes and lower income tax expense due to an increase in PTCs.


	Three Months Ended September 30
(in millions)	2024		2023		B (W)
Operating revenues	$	1,590.0	$	1,622.0	$	(32.0)

Operating expenses
Cost of sales (1)	495.3		549.1		53.8
Other operation and maintenance	403.5		387.1		(16.4)
Depreciation and amortization	232.4		215.3		(17.1)
Property and revenue taxes	32.8		44.4		11.6
Operating income	426.0		426.1		(0.1)

Other income, net	35.7		35.3		0.4
Interest expense	160.3		148.7		(11.6)
Income before income taxes	301.4		312.7		(11.3)

Income tax expense	63.3		69.3		6.0
Preferred stock dividends of subsidiary	0.3		0.3		—
Net income attributed to common shareholders	$	237.8	$	243.1	$	(5.3)

(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:


	Three Months Ended September 30
(in millions)	2024		2023		B (W)
Operation and maintenance not included in line items below	$	183.6	$	167.7	$	(15.9)
Transmission (1)	135.8		135.3		(0.5)
Regulatory amortizations and other pass through expenses (2)	52.5		49.2		(3.3)
We Power (3)	32.5		35.8		3.3
Earnings sharing mechanisms	(0.9)		(0.9)		—
Total other operation and maintenance	$	403.5	$	387.1	$	(16.4)

(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 2024 and 2023, $147.5 million and $136.4 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 third quarter of 2024 and 2023, $27.8 million and $26.7 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:


	Three Months Ended September 30
	MWh (in thousands)
Electric Sales Volumes	2024	2023	B (W)
Customer Class
Residential	3,270.0	3,228.3	41.7
Small commercial and industrial (1)	3,516.8	3,481.7	35.1
Large commercial and industrial (1)	3,160.4	3,171.8	(11.4)
Other	26.8	27.3	(0.5)
Total retail (1)	9,974.0	9,909.1	64.9
Wholesale	438.0	475.5	(37.5)
Resale	1,573.7	2,262.7	(689.0)
Total sales in MWh (1)	11,985.7	12,647.3	(661.6)

(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	2024	2023	B (W)
Customer Class
Residential	58.4	58.8	(0.4)
Commercial and industrial	57.3	51.4	5.9
Total retail	115.7	110.2	5.5
Transportation	267.9	263.0	4.9
Total sales in therms	383.6	373.2	10.4


	Three Months Ended September 30
	Degree Days
Weather	2024	2023	B (W)
WE and WG (1)
Heating (94 Normal)	28	32	(12.5)	%
Cooling (599 Normal)	600	676	(11.2)	%

WPS (2)
Heating (173 Normal)	54	108	(50.0)	%
Cooling (394 Normal)	452	391	15.6	%

UMERC (3)
Heating (300 Normal)	153	242	(36.8)	%
Cooling (255 Normal)	260	188	38.3	%

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

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

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


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Gross Margin GAAP and Utility Margin Non-GAAP

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


	Three Months Ended September 30
(in millions)	2024		2023		B (W)
Electric revenues	$	1,425.1	$	1,460.8	$	(35.7)
Natural gas revenues	164.9		161.2		3.7
Operating revenues	1,590.0		1,622.0		(32.0)

Operating expenses
Fuel and purchased power	(433.9)		(487.6)		53.7
Cost of natural gas sold	(61.4)		(61.5)		0.1
Other operation and maintenance (1)	(283.0)		(286.5)		3.5
Depreciation and amortization	(232.4)		(215.3)		(17.1)
Property and revenue taxes	(32.8)		(44.4)		11.6
Gross margin (GAAP)	546.5		526.7		19.8

Other operation and maintenance (1)	283.0		286.5		(3.5)
Depreciation and amortization	232.4		215.3		17.1
Property and revenue taxes	32.8		44.4		(11.6)
Utility margin (non-GAAP)	$	1,094.7	$	1,072.9	$	21.8

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

Gross margin (GAAP) at the Wisconsin segment increased $19.8 million during the third quarter of 2024, compared with the same quarter in 2023, and utility margin (non-GAAP) increased $21.8 million during the third quarter of 2024, compared with the same quarter in 2023. Both measures were driven by:

A $12.4 million increase in margins related to higher electric and natural gas retail sales volumes, including the impact of warmer summer weather in WPS's service area during the third quarter of 2024, compared with the same quarter in 2023. As measured by cooling degree days, the third quarter of 2024 was 15.6% warmer than the same quarter in 2023 in the Green Bay area.
A $4.7 million quarter-over-quarter positive impact from collections of fuel and purchased power costs. Under the Wisconsin fuel rules, the margins of our electric utilities are impacted by under- or over-collections of certain fuel and purchased power costs that are within a 2% price variance from the costs included in rates, and the remaining variance above or below the 2% is generally deferred for either future recovery from or refund to customers.
A $2.2 million increase in margins driven by the impact of the Wisconsin limited rate case re-openers approved by the PSCW, effective January 1, 2024. See Note 26, Regulatory Environment, in our 2023 Annual Report on Form 10-K, for more information on the 2024 limited rate case re-openers.

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 $17.1 million increase in depreciation and amortization expense;

This increase was partially offset by:

An $11.6 million decrease in property and revenue taxes; and
A $3.3 million decrease in other operation and maintenance expense related to the We Power leases.


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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 $21.9 million during the third quarter of 2024, compared with the same quarter in 2023. The significant factors impacting the increase in other operating expenses were:

A $17.1 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.
An $11.3 million increase in benefit costs, primarily driven by higher stock-based compensation and deferred compensation expense.
A $4.0 million increase in expenses associated with legal claims.
A $3.3 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

These increases in other operating expenses were partially offset by:

An $11.6 million decrease in property and revenue taxes driven by a favorable adjustment related to a sales tax audit at WE.
A $3.3 million decrease in other operation and maintenance expense related to the We Power leases, as discussed in the notes under the other operation and maintenance table above.

Interest Expense

Interest expense at the Wisconsin segment increased $11.6 million during the third quarter of 2024, compared with the same quarter in 2023, driven by the impact of WE's $350.0 million long-term debt issuance in May 2024 and $600.0 million long-term debt issuance in September 2024. See Note 11, Long-Term Debt, for more information. Also contributing to the increase was higher average short-term debt balances and increased average short-term debt interest rates.

Income Tax Expense

Income tax expense at the Wisconsin segment decreased $6.0 million during the third quarter of 2024, compared with the same quarter in 2023, driven by an increase in PTCs and lower pre-tax income.

Illinois Segment Contribution to Net Income Attributed to Common Shareholders

The Illinois segment's net loss attributed to common shareholders was $48.6 million during the third quarter of 2024, representing a $73.3 million decrease in earnings over the same quarter in 2023. The lower earnings were driven by a decrease in margins related to the impacts of the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively. SMP costs that were previously being recovered under PGL's QIP rider are now included in PGL's base rates. As base revenues are lower during the third quarter when natural gas usage is lower, this rate design change drove a decrease in third quarter 2024 earnings. See Note 25, Regulatory Environment, for more information on the rate orders. Higher operating expenses and a $25.3 million pre-tax charge to income related to the ICC's disallowance of certain capital costs in PGL's 2016 rider QIP reconciliation also contributed to the lower earnings. See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Regulatory Recovery and Note 25, Regulatory Environment, for more information on the ICC disallowance.


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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)	2024		2023		B (W)
Operating revenues	$	173.6	$	243.3	$	(69.7)

Operating expenses
Cost of natural gas sold	17.8		36.7		18.9
Other operation and maintenance	126.5		86.5		(40.0)
Depreciation and amortization	63.9		59.3		(4.6)
Property and revenue taxes	12.2		6.7		(5.5)
Operating income (loss)	(46.8)		54.1		(100.9)

Other income, net	1.5		1.5		—
Interest expense	22.3		22.0		(0.3)
Income (loss) before income taxes	(67.6)		33.6		(101.2)

Income tax expense (benefit)	(19.0)		8.9		27.9
Net income (loss) attributed to common shareholders	$	(48.6)	$	24.7	$	(73.3)

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


	Three Months Ended September 30
(in millions)	2024		2023		B (W)
Operation and maintenance not included in the line items below	$	87.7	$	72.8	$	(14.9)
Riders (1)	26.2		13.7		(12.5)
Regulatory amortizations (1)	0.5		—		(0.5)
Impairment related to ICC disallowance (2)	12.1		—		(12.1)

Total other operation and maintenance	$	126.5	$	86.5	$	(40.0)

(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 25, 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	2024	2023	B (W)
Customer Class
Residential	42.9	47.4	(4.5)
Commercial and industrial	21.5	21.6	(0.1)
Total retail	64.4	69.0	(4.6)
Transportation	83.0	90.0	(7.0)
Total sales in therms	147.4	159.0	(11.6)


	Three Months Ended September 30
	Degree Days
Weather (1)	2024	2023	B (W)
Heating (58 Normal)	14	19	(26.3)	%

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


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Gross Margin GAAP and Utility Margin Non-GAAP

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


	Three Months Ended September 30
(in millions)	2024		2023		B (W)
Operating revenues	$	173.6	$	243.3	$	(69.7)

Operating expenses
Cost of natural gas sold	(17.8)		(36.7)		18.9
Other operation and maintenance (1)	(59.0)		(53.1)		(5.9)
Depreciation and amortization	(63.9)		(59.3)		(4.6)
Property and revenue taxes	(12.2)		(6.7)		(5.5)
Gross margin (GAAP)	20.7		87.5		(66.8)

Other operation and maintenance (1)	59.0		53.1		5.9
Depreciation and amortization	63.9		59.3		4.6
Property and revenue taxes	12.2		6.7		5.5
Utility margin (non-GAAP)	$	155.8	$	206.6	$	(50.8)

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

Gross margin (GAAP) at the Illinois segment decreased $66.8 million during the third quarter of 2024, compared with the same quarter in 2023, and utility margin (non-GAAP) decreased $50.8 million during the third quarter of 2024, compared with the same quarter in 2023. Both measures were driven by:

A $47.6 million decrease in margins related to the impacts of the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively. PGL’s rate order includes the recovery of costs related to PGL’s SMP in base rates. Previously, these costs were being recovered under its QIP rider. As base revenues are lower during the third quarter when natural gas usage is lower, this rate design change drove a decrease in third quarter 2024 margins. See Note 25, Regulatory Environment, for more information on the rate orders.
A $12.9 million decrease in revenues driven by an ICC order received in August 2024 related to PGL's 2016 Rider QIP reconciliation prudency review, which requires 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 25, Regulatory Environment, for more information on the ICC disallowance.

These decreases in gross margin (GAAP) and utility margin (non-GAAP) were partially offset by a $12.5 million increase in revenues associated with certain riders that are offset in other operation and maintenance and therefore do not have a significant impact on net income.

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

*•*A $5.5 million increase in property and revenue taxes;

*•*A $4.6 million increase in depreciation and amortization;

*•*A $3.1 million increase in natural gas distribution and maintenance costs; and

A $3.0 million increase in customer service expense.


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

Other operating expenses at the Illinois segment increased $37.6 million, net of the $12.5 million impact of the riders referenced in the table above, during the third quarter of 2024, compared with the same quarter in 2023. The significant factors impacting the increase in other operating expenses were:

A $12.1 million impairment driven by 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 25, Regulatory Environment, for more information on the ICC disallowance.
A $5.5 million increase in property and revenue taxes, driven by an increase in the invested capital tax. This increase was related to an increase in regulatory amortizations as approved in the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively.
A $4.9 million increase in benefit costs, partially driven by higher costs related to stock-based compensation and deferred compensation.
A $4.6 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.
A $3.1 million increase in natural gas distribution and maintenance costs, primarily related to maintaining the natural gas infrastructure.
A $3.0 million increase in customer service expense primarily due to higher metering costs.

Interest Expense

Interest expense at the Illinois segment increased $0.3 million during the third quarter of 2024, compared with the same quarter in 2023, due primarily to the impact of PGL and NSG issuing long-term debt in November 2023. This increase was partially offset by lower average short-term debt balances.

Income Tax Expense (Benefit)

At the Illinois segment, $19.0 million of income tax benefit was recorded during the third quarter of 2024, compared with $8.9 million of income tax expense recorded during the same quarter in 2023. This change was driven by the recognition of a pre-tax loss in the third quarter of 2024, compared to pre-tax earnings in the third quarter of 2023.

Other States Segment Contribution to Net Income Attributed to Common Shareholders

The other states segment's net loss attributed to common shareholders was $3.7 million during the third quarter of 2024, representing a $2.3 million, or 38.3%, reduction in net loss over the same quarter in 2023. The reduction in net loss was driven by lower property and revenue taxes and an increase in margins related to higher sales volumes.


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


	Three Months Ended September 30
(in millions)	2024		2023		B (W)
Operating revenues	$	53.0	$	47.6	$	5.4

Operating expenses
Cost of natural gas sold	16.9		13.1		(3.8)
Other operation and maintenance	22.6		21.7		(0.9)
Depreciation and amortization	12.0		11.2		(0.8)
Property and revenue taxes	2.6		6.3		3.7
Operating loss	(1.1)		(4.7)		3.6

Other income, net	0.2		0.4		(0.2)
Interest expense	4.1		3.7		(0.4)
Loss before income taxes	(5.0)		(8.0)		3.0

Income tax benefit	(1.3)		(2.0)		(0.7)
Net loss attributed to common shareholders	$	(3.7)	$	(6.0)	$	2.3

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


	Three Months Ended September 30
(in millions)	2024		2023		B (W)
Operation and maintenance not included in line item below	$	20.1	$	18.6	$	(1.5)
Regulatory amortizations and other pass through expenses (1)	2.5		3.1		0.6

Total other operation and maintenance	$	22.6	$	21.7	$	(0.9)

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

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


	Three Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2024	2023	B (W)
Customer Class
Residential	16.0	15.2	0.8
Commercial and industrial	12.1	11.6	0.5
Total retail	28.1	26.8	1.3
Transportation	187.6	189.4	(1.8)
Total sales in therms	215.7	216.2	(0.5)


	Three Months Ended September 30
	Degree Days
Weather (1)	2024	2023	B (W)
MERC
Heating (198 Normal)	88	123	(28.5)	%

MGU
Heating (109 Normal)	48	93	(48.4)	%

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


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Gross Margin GAAP and Utility Margin Non-GAAP

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


	Three Months Ended September 30
(in millions)	2024		2023		B (W)
Operating revenues	$	53.0	$	47.6	$	5.4

Operating expenses
Cost of natural gas sold	(16.9)		(13.1)		(3.8)
Other operation and maintenance (1)	(14.5)		(14.3)		(0.2)
Depreciation and amortization	(12.0)		(11.2)		(0.8)
Property and revenue taxes	(2.6)		(6.3)		3.7
Gross margin (GAAP)	7.0		2.7		4.3

Other operation and maintenance (1)	14.5		14.3		0.2
Depreciation and amortization	12.0		11.2		0.8
Property and revenue taxes	2.6		6.3		(3.7)
Utility margin (non-GAAP)	$	36.1	$	34.5	$	1.6

Gross margin (GAAP) increased $4.3 million during the third quarter of 2024, compared with the same quarter in 2023, and utility margin (non-GAAP) increased $1.6 million during the third quarter of 2024, compared with the same quarter in 2023. Both measures were driven by:

A $3.1 million increase related to higher sales volumes, driven by higher retail sales.
A $0.6 million increase related to MGU's rate increase approved by the MPSC that was effective January 1, 2024. See Note 26, Regulatory Environment, in our 2023 Annual Report on Form 10-K for more information.

Partially offsetting these increases in margins was a $1.8 million decrease related to the timing of MERC's interim rates and final rates, which were approved by the MPUC in November 2023. See Note 25, Regulatory Environment, for more information.

Additionally, the larger 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 $3.7 million decrease in property and revenue taxes; partially offset by

A $0.8 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 decreased $2.0 million during the third quarter of 2024, compared with the same quarter in 2023. The significant factor impacting the decrease in operating expenses was a $3.7 million decrease in property and revenue taxes, driven by the resolution of a use tax audit at MGU. This decrease in other operating expenses was partially offset by:

A $0.8 million increase in benefit costs, partially driven by higher costs related to stock-based compensation and deferred compensation.
A $0.8 million increase in depreciation and amortization related to continued capital investment.


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Interest Expense

Interest expense at the other states segment increased $0.4 million during the third quarter of 2024, compared with the same quarter in 2023, driven by higher average short-term debt balances.

Income Tax Benefit

The income tax benefit at the other states segment decreased $0.7 million during the third quarter of 2024, compared with the same quarter in 2023, driven by lower pre-tax loss.

Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders


	Three Months Ended September 30
(in millions)	2024		2023		B (W)
Equity in earnings of transmission affiliates	$	46.7	$	44.7	$	2.0
Interest expense	4.8		5.0		0.2
Income before income taxes	41.9		39.7		2.2

Income tax expense	10.2		10.0		(0.2)
Net income attributed to common shareholders	$	31.7	$	29.7	$	2.0

Equity in Earnings of Transmission Affiliates

Equity in earnings of transmission affiliates increased $2.0 million during the third quarter of 2024, compared with the same quarter in 2023. This increase was primarily due to continued capital investment by ATC.

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


	Three Months Ended September 30
(in millions)	2024		2023		B (W)
Operating income	$	90.4	$	84.8	$	5.6

Other income, net	0.2		—		0.2
Interest expense	23.4		24.8		1.4
Income before income taxes	67.2		60.0		7.2

Income tax benefit	(16.0)		(6.7)		9.3
Net loss attributed to noncontrolling interests	1.8		0.7		1.1
Net income attributed to common shareholders	$	85.0	$	67.4	$	17.6

Operating Income

Operating income at the non-utility energy infrastructure segment increased $5.6 million during the third quarter of 2024, compared with the same quarter in 2023, which was primarily due to a $3.6 million positive impact from We Power due to continued capital investment.

In addition, WECI had a positive impact of $1.8 million driven by these items:

A $9.2 million positive impact in 2024 related to the receipt of performance payments.
A $1.8 million increase in PPA revenue resulting from increased generation driven by higher wind speeds.

These increases in operating income were partially offset by:

A $5.3 million decrease in revenue related to transmission congestion that reduced energy market prices.


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A $3.3 million increase in operation and maintenance expenses due primarily to equipment failures at several of our renewable generation facilities.
Recognition of $1.9 million in revenue related to Blooming Grove in 2023 for a capacity payment received from PJM Interconnection that was associated with a December 2022 cold weather event. The capacity payment was subject to a FERC complaint, so we recognized this as revenue in 2023 when FERC issued an order denying that complaint.

Interest Expense

Interest expense at the non-utility energy infrastructure segment decreased $1.4 million during the third quarter of 2024, compared with the same quarter in 2023, primarily due to a lower principal balance, as a result of the semi-annual principal payments on long-term debt.

Income Tax Benefit

The income tax benefit at the non-utility energy infrastructure segment increased $9.3 million during the third quarter of 2024, compared with the same quarter in 2023, due to an increase in PTCs that was related to the IRS approved PTC rate increase and higher production volumes, partially offset by higher pre-tax income.

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


	Three Months Ended September 30
(in millions)	2024		2023		B (W)
Operating loss	$	(2.4)	$	(6.6)	$	4.2

Other income, net	13.7		10.9		2.8
Interest expense	79.0		66.3		(12.7)

Loss before income taxes	(67.7)		(62.0)		(5.7)

Income tax benefit	(5.6)		(19.1)		(13.5)
Net loss attributed to common shareholders	$	(62.1)	$	(42.9)	$	(19.2)

Operating Loss

The operating loss at the corporate and other segment decreased $4.2 million during the third quarter of 2024, compared with the same quarter in 2023. The lower operating loss was driven by a $4.2 million positive impact from WBS's allocation of its net credits from the non-service components of its net periodic pension and OPEB costs. These net credits are initially recorded in other income, net, but are allocated to our operating segments as an overhead cost, which is recorded through operating expenses. As a result, this positive impact is fully offset in the other income, net line item discussed below.

Other Income, Net

Other income, net at the corporate and other segment increased $2.8 million during the third quarter of 2024, compared with the same quarter in 2023. The significant factors impacting the increase in other income, net were:

A $4.1 million increase due to $3.2 million of net gains from the investments held in the Integrys rabbi trust during the third quarter of 2024, compared with a $0.9 million net loss during the same quarter in 2023. The gains and losses from the investments held in the rabbi trust partially offset the changes in benefit costs related to deferred compensation, which are primarily included in other operation and maintenance expense in our utility segments. See Note 15, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.
A $1.9 million increase in interest income on cash balances.

These increases in other income, net were partially offset by a $4.2 million decrease driven by lower net credits from the non-service components of WBS's net periodic pension and OPEB costs. As discussed above, this negative impact was offset by lower operating


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expenses as these credits are allocated to our operating segments as an overhead cost. See Note 18, Employee Benefits, for more information on our benefit costs.

Interest Expense

Interest expense at the corporate and other segment increased $12.7 million during the third quarter of 2024, compared with the same quarter in 2023, due to the impact of long-term debt issuances by WEC Energy Group in September 2023 and May 2024. Partially offsetting these increases in interest expense were lower average short-term debt balances, the impact of Integrys' long-term debt redemption in August 2023, WEC Energy Group's long-term debt maturity in September 2023, WEC Energy Group's tender offer for its 2007 Junior Notes in January and February 2024, and WEC Energy Group's repurchase of $19.0 million of its 2007 Junior Notes in May 2024. See Note 11, Long-Term Debt, for more information.

Income Tax Benefit

The income tax benefit at the corporate and other segment decreased $13.5 million during the third quarter of 2024, compared with the same quarter in 2023. This decrease was driven by a $16.9 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 2024, compared with the same quarter in 2023, partially offset by a higher pre-tax loss.

NINE MONTHS ENDED SEPTEMBER 30, 2024

Consolidated Earnings

The following table compares our consolidated results for the nine months ended September 30, 2024 with the nine months ended September 30, 2023, including favorable or better, "B", and unfavorable or worse, "W", variances:


	Nine Months Ended September 30
(in millions, except per share data)	2024		2023		B (W)
Wisconsin	$	636.3	$	685.9	$	(49.6)
Illinois	164.6		167.9		(3.3)
Other states	35.5		30.9		4.6
Electric transmission	93.2		88.1		5.1
Non-utility energy infrastructure	272.6		241.8		30.8
Corporate and other	(128.5)		(101.4)		(27.1)
Net income attributed to common shareholders	$	1,073.7	$	1,113.2	$	(39.5)

Diluted Earnings Per Share	$	3.40	$	3.52	$	(0.12)

Earnings decreased $39.5 million during the nine months ended September 30, 2024, compared with the same period in 2023. The significant factors impacting the $39.5 million decrease in earnings were:

A $49.6 million decrease in net income attributed to common shareholders at the Wisconsin segment, driven by higher operating expenses; an increase in interest expense on both short-term and long-term debt; and a decrease in margins due to lower sales volumes, driven by the impact of unfavorable weather. An increase in depreciation and amortization expense, lower gains on the sale of land, and higher distribution expenses all contributed to the increase in operating expenses. These decreases in earnings were partially offset by a positive period-over-period impact from collections of fuel and purchased power costs and the impact of the Wisconsin rate case re-openers approved by the PSCW, effective January 1, 2024. See Note 26, Regulatory Environment, in our 2023 Annual Report on Form 10-K for more information.
A $27.1 million increase in the net loss attributed to common shareholders at the corporate and other segment, driven by higher interest expense and a negative impact from an increase in an interim income tax expense recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate. These negative impacts were partially offset by higher interest income and an increase in earnings from our equity method investments in technology and energy-focused investment funds.


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These decreases in earnings were partially offset by a $30.8 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by an increase in PTCs from our non-utility renewable generating facilities in 2024, a positive impact from We Power due to continued capital investment, and higher operating income at WECI.

Expected 2024 Annual Effective Tax Rate

We expect our 2024 annual effective tax rate to be between 12.5% and 13.5%. 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 $636.3 million during the nine months ended September 30, 2024, representing a $49.6 million, or 7.2%, decrease over the same period in 2023. The decrease in earnings was driven by higher operating expenses; an increase in interest expense on both short-term and long-term debt; and a decrease in margins due to lower sales volumes, driven by the impact of unfavorable weather. An increase in depreciation and amortization expense, lower gains on the sale of land, and higher distribution expenses all contributed to the increase in operating expenses. These decreases in earnings were partially offset by a positive period-over-period impact from collections of fuel and purchased power costs and the impact of the Wisconsin rate case re-openers approved by the PSCW, effective January 1, 2024. See Note 26, Regulatory Environment, in our 2023 Annual Report on Form 10-K for more information.


	Nine Months Ended September 30
(in millions)	2024		2023		B (W)
Operating revenues	$	4,737.0	$	5,042.8	$	(305.8)

Operating expenses
Cost of sales (1)	1,560.3		1,935.3		375.0
Other operation and maintenance	1,182.6		1,119.7		(62.9)
Depreciation and amortization	685.3		632.9		(52.4)
Property and revenue taxes	125.0		134.7		9.7
Operating income	1,183.8		1,220.2		(36.4)

Other income, net	101.4		104.8		(3.4)
Interest expense	475.4		449.4		(26.0)
Income before income taxes	809.8		875.6		(65.8)

Income tax expense	172.6		188.8		16.2
Preferred stock dividends of subsidiary	0.9		0.9		—
Net income attributed to common shareholders	$	636.3	$	685.9	$	(49.6)

(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)	2024		2023		B (W)
Operation and maintenance not included in line items below	$	518.5	$	457.0	$	(61.5)
Transmission (1)	407.3		405.0		(2.3)
Regulatory amortizations and other pass through expenses (2)	160.2		153.5		(6.7)
We Power (3)	99.2		106.8		7.6


Earnings sharing mechanisms	(2.6)		(2.6)		—
Total other operation and maintenance	$	1,182.6	$	1,119.7	$	(62.9)

(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, 2024 and 2023, $425.4 million and $391.5 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 nine months ended September 30, 2024 and 2023, $86.7 million and $89.1 million, respectively, of costs were billed to or incurred by WE related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.


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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	2024	2023	B (W)
Customer Class
Residential	8,442.8	8,394.6	48.2
Small commercial and industrial (1)	9,753.7	9,685.2	68.5
Large commercial and industrial (1)	9,026.5	9,080.0	(53.5)
Other	89.5	90.4	(0.9)
Total retail (1)	27,312.5	27,250.2	62.3
Wholesale	1,273.1	1,396.5	(123.4)
Resale	4,292.2	4,484.0	(191.8)
Total sales in MWh (1)	32,877.8	33,130.7	(252.9)

(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	2024	2023	B (W)
Customer Class
Residential	649.0	702.9	(53.9)
Commercial and industrial	425.9	457.1	(31.2)
Total retail	1,074.9	1,160.0	(85.1)
Transportation	957.7	964.0	(6.3)
Total sales in therms	2,032.6	2,124.0	(91.4)


	Nine Months Ended September 30
	Degree Days
Weather	2024	2023	B (W)
WE and WG (1)
Heating (4,267 Normal)	3,360	3,623	(7.3)	%
Cooling (775 Normal)	802	834	(3.8)	%

WPS (2)
Heating (4,786 Normal)	3,852	4,337	(11.2)	%
Cooling (547 Normal)	594	565	5.1	%

UMERC (3)
Heating (5,479 Normal)	4,644	4,998	(7.1)	%
Cooling (342 Normal)	317	296	7.1	%

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

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

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


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Gross Margin GAAP and Utility Margin Non-GAAP


	Nine Months Ended September 30
(in millions)	2024		2023		B (W)
Electric revenues	$	3,766.7	$	3,851.7	$	(85.0)
Natural gas revenues	970.3		1,191.1		(220.8)
Operating revenues	4,737.0		5,042.8		(305.8)

Operating expenses
Fuel and purchased power	(1,115.4)		(1,258.0)		142.6
Cost of natural gas sold	(444.9)		(677.3)		232.4
Other operation and maintenance (1)	(850.8)		(842.3)		(8.5)
Depreciation and amortization	(685.3)		(632.9)		(52.4)
Property and revenue taxes	(125.0)		(134.7)		9.7
Gross margin (GAAP)	1,515.6		1,497.6		18.0

Other operation and maintenance (1)	850.8		842.3		8.5
Depreciation and amortization	685.3		632.9		52.4
Property and revenue taxes	125.0		134.7		(9.7)
Utility margin (non-GAAP)	$	3,176.7	$	3,107.5	$	69.2

Gross margin (GAAP) at the Wisconsin segment increased $18.0 million during the nine months ended September 30, 2024, compared with the same period in 2023, and utility margin (non-GAAP) increased $69.2 million during the nine months ended September 30, 2024, compared with the same period in 2023. Both measures were driven by:

A $37.3 million period-over-period 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.
A $33.4 million increase in margins related to the impact of the Wisconsin limited rate case re-openers approved by the PSCW, effective January 1, 2024.

These increases in margins were partially offset by a $7.4 million decrease in margins related to lower sales volumes, driven by the impact of unfavorable weather during the nine months ended September 30, 2024, compared with the same period in 2023. As measured by heating degree days, the nine months ended September 30, 2024 were 7.3% and 11.2% warmer than the same period in 2023 in the Milwaukee area and Green Bay area, respectively. As measured by cooling degree days, the nine months ended September 30, 2024 were 3.8% warmer than the same period in 2023 in the Milwaukee area.

A $52.4 million increase in depreciation and amortization expense; and
A $15.6 million increase in electric and natural gas distribution expenses.

These increases were partially offset by:

A $9.7 million decrease in property and revenue taxes; and


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A $7.6 million decrease in other operation and maintenance expense related to the We Power leases.

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

Other operating expenses at the Wisconsin segment increased $105.6 million during the nine months ended September 30, 2024, compared with the same period in 2023. The significant factors impacting the increase in other operating expenses were:

A $52.4 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.
A $22.1 million decrease in pre-tax gains on the sales of land, primarily related to the land sale at the site of our former Pleasant Prairie power plant in 2023. See Note 3, Disposition, for more information.
A $15.6 million increase in electric and natural gas distribution expenses, primarily driven by storm restoration and higher costs to maintain the distribution systems during the nine months ended September 30, 2024, compared with the same period in 2023.
A $13.2 million increase in benefit costs, primarily driven by higher stock-based compensation and deferred compensation expense.
A $7.7 million increase in expenses associated with legal claims.
A $6.7 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

These increases in other operating expenses were partially offset by:

A $9.7 million decrease in property and revenue taxes driven by a favorable adjustment related to a sales tax audit at WE.
A $7.6 million decrease in other operation and maintenance expense related to the We Power leases, as discussed in the notes under the other operation and maintenance table above.

Other Income, Net

Other income, net at the Wisconsin segment decreased $3.4 million during the nine months ended September 30, 2024, compared with the same period in 2023, due in part to lower AFUDC-Equity driven by the WE and WG LNG facilities going into service in November 2023 and February 2024, respectively. Our continued capital investment in the Wisconsin segment partially offset the impact from the completion of these facilities.

Interest Expense

Interest expense at the Wisconsin segment increased $26.0 million during the nine months ended September 30, 2024, compared with the same period in 2023, driven by higher average short-term debt balances, higher average short-term debt interest rates, and the impact of WE's $350.0 million long-term debt issuance in May 2024 and $600.0 million long-term debt issuance in September 2024. See Note 11, Long-Term Debt, for more information.

Income Tax Expense

Income tax expense at the Wisconsin segment decreased $16.2 million during the nine months ended September 30, 2024, compared with the same period in 2023, primarily due to lower pre-tax income and higher PTCs.


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Illinois Segment Contribution to Net Income Attributed to Common Shareholders

The Illinois segment's contribution to net income attributed to common shareholders was $164.6 million during the nine months ended September 30, 2024, representing a $3.3 million, or 2.0%, decrease over the same period in 2023. The decrease was driven by higher operating expenses, a $25.3 million pre-tax charge to income related to the ICC's disallowance of certain capital costs in PGL's 2016 rider QIP reconciliation, and an increase in interest expense. These decreases in earnings were partially offset by higher margins due to the impacts of the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively. SMP costs that were previously being recovered under PGL's QIP rider are now included in PGL's base rates. As base revenues are concentrated in the winter months (first and fourth quarters) when natural gas usage is highest, this rate design change drove a large increase in the first quarter 2024 margins.


	Nine Months Ended September 30
(in millions)	2024		2023		B (W)
Operating revenues	$	1,116.4	$	1,116.5	$	(0.1)

Operating expenses
Cost of natural gas sold	254.3		316.5		62.2
Other operation and maintenance	336.1		305.5		(30.6)
Depreciation and amortization	191.1		176.3		(14.8)
Property and revenue taxes	41.9		27.8		(14.1)
Operating income	293.0		290.4		2.6

Other income, net	5.7		4.3		1.4
Interest expense	70.8		65.0		(5.8)
Income before income taxes	227.9		229.7		(1.8)

Income tax expense	63.3		61.8		(1.5)
Net income attributed to common shareholders	$	164.6	$	167.9	$	(3.3)

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


	Nine Months Ended September 30
(in millions)	2024		2023		B (W)
Operation and maintenance not included in the line items below	$	231.1	$	231.3	$	0.2
Riders (1)	90.9		74.4		(16.5)
Regulatory amortizations (1)	2.0		(0.2)		(2.2)
Impairment related to ICC disallowance (2)	12.1		—		(12.1)

Total other operation and maintenance	$	336.1	$	305.5	$	(30.6)

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

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


	Nine Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2024	2023	B (W)
Customer Class
Residential	500.7	538.4	(37.7)
Commercial and industrial	195.8	214.0	(18.2)
Total retail	696.5	752.4	(55.9)
Transportation	493.3	524.5	(31.2)
Total sales in therms	1,189.8	1,276.9	(87.1)


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	Nine Months Ended September 30
	Degree Days
Weather (1)	2024	2023	B (W)
Heating (3,859 Normal)	3,078	3,339	(7.8)	%

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

Gross Margin GAAP and Utility Margin Non-GAAP


	Nine Months Ended September 30
(in millions)	2024		2023		B (W)
Operating revenues	$	1,116.4	$	1,116.5	$	(0.1)

Operating expenses
Cost of natural gas sold	(254.3)		(316.5)		62.2
Other operation and maintenance (1)	(167.4)		(152.9)		(14.5)
Depreciation and amortization	(191.1)		(176.3)		(14.8)
Property and revenue taxes	(41.9)		(27.8)		(14.1)
Gross margin (GAAP)	461.7		443.0		18.7

Other operation and maintenance (1)	167.4		152.9		14.5
Depreciation and amortization	191.1		176.3		14.8
Property and revenue taxes	41.9		27.8		14.1
Utility margin (non-GAAP)	$	862.1	$	800.0	$	62.1

Gross margin (GAAP) at the Illinois segment increased $18.7 million during the nine months ended September 30, 2024, compared with the same period in 2023, and utility margin (non-GAAP) increased $62.1 million during the nine months ended September 30, 2024, compared with the same period in 2023. Both measures were driven by:

A $64.3 million increase in margins related to the impacts of the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively. PGL’s rate order includes the recovery of costs related to PGL’s SMP in base rates. Previously, these costs were being recovered under its QIP rider. As base revenues are concentrated in the winter months (first and fourth quarters) when natural gas usage is highest, this rate design change drove a large increase in margins during the first quarter of 2024.
A $16.5 million increase in revenues associated with certain riders that are offset in other operation and maintenance and therefore do not have a significant impact on net income.

These increases in gross margin (GAAP) and utility margin (non-GAAP) were partially offset by a $12.9 million decrease in revenues driven by an ICC order received in August 2024 related to PGL's 2016 Rider QIP reconciliation prudency review, which requires refunds to ratepayers for amounts previously collected related to the disallowance of certain capital costs.

Additionally, the smaller 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 $14.8 million increase in depreciation and amortization;
A $14.1 million increase in property and revenue taxes;
A $10.2 million increase in natural gas distribution and maintenance costs; and


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A $5.0 million increase in customer service expense.

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

Other operating expenses at the Illinois segment increased $43.0 million, net of the $16.5 million impact of the riders referenced in the table above, during the nine months ended September 30, 2024, compared with the same period in 2023. The significant factors impacting the increase in other operating expenses were:

A $14.8 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.
A $14.1 million increase in property and revenue taxes, driven by an increase in the invested capital tax. This increase was related to an increase in regulatory amortizations as approved in the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively.
A $12.1 million impairment driven by 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 $10.2 million increase in natural gas distribution and maintenance costs, primarily related to maintaining the natural gas infrastructure.
A $5.0 million increase in customer service expense primarily due to higher metering costs.
A $2.8 million increase in rate case related regulatory amortizations.

These increases in other operating expenses were partially offset by:

An $11.1 million decrease in expenses driven by an ICC order received in May 2023 related to an annual prudency review of PGL's and NSG's UEA riders, which required refunds to ratepayers starting in September 2023. See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Regulatory Recovery and Note 25, Regulatory Environment, for more information.
A $10.5 million decrease in expenses associated with the favorable settlement of a legal claim during the nine months ended September 30, 2024.

Interest Expense

Interest expense at the Illinois segment increased $5.8 million during the nine months ended September 30, 2024, compared with the same period in 2023, driven by the impact of PGL and NSG issuing long-term debt in November 2023.

Income Tax Expense

Income tax expense at the Illinois segment increased $1.5 million during the nine months ended September 30, 2024, compared with the same period in 2023, driven by a $1.3 million decrease in the amortization of the federal excess protected deferred tax benefits from the Tax Legislation. See Note 14, Income Taxes, for more information.

Other States Segment Contribution to Net Income Attributed to Common Shareholders

The other states segment's contribution to net income attributed to common shareholders was $35.5 million during the nine months ended September 30, 2024, representing a $4.6 million, or 14.9%, increase over the same period in 2023. The increase was driven by higher margins due to MGU's rate increase approved by the MPSC that was effective January 1, 2024 and MERC's final rate increase approved by the MPUC in November 2023. Lower property and revenue taxes also contributed to the increase in earnings. These positive impacts were partially offset by higher depreciation and amortization expense.


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	Nine Months Ended September 30
(in millions)	2024		2023		B (W)
Operating revenues	$	308.6	$	379.5	$	(70.9)

Operating expenses
Cost of natural gas sold	131.5		208.0		76.5
Other operation and maintenance	67.8		68.2		0.4
Depreciation and amortization	34.9		32.2		(2.7)
Property and revenue taxes	15.1		18.4		3.3
Operating income	59.3		52.7		6.6

Other income, net	0.3		0.7		(0.4)
Interest expense	12.1		12.0		(0.1)
Income before income taxes	47.5		41.4		6.1

Income tax expense	12.0		10.5		(1.5)
Net income attributed to common shareholders	$	35.5	$	30.9	$	4.6

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


	Nine Months Ended September 30
(in millions)	2024		2023		B (W)
Operation and maintenance not included in line item below	$	56.5	$	53.5	$	(3.0)
Regulatory amortizations and other pass through expenses (1)	11.3		14.7		3.4

Total other operation and maintenance	$	67.8	$	68.2	$	0.4

(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	2024	2023	B (W)
Customer Class
Residential	189.2	204.4	(15.2)
Commercial and industrial	118.8	132.4	(13.6)
Total retail	308.0	336.8	(28.8)
Transportation	612.2	587.8	24.4
Total sales in therms	920.2	924.6	(4.4)


	Nine Months Ended September 30
	Degree Days
Weather (1)	2024	2023	B (W)
MERC
Heating (5,135 Normal)	4,267	4,882	(12.6)	%

MGU
Heating (4,087 Normal)	3,259	3,579	(8.9)	%


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Gross Margin GAAP and Utility Margin Non-GAAP


	Nine Months Ended September 30
(in millions)	2024		2023		B (W)
Operating revenues	$	308.6	$	379.5	$	(70.9)

Operating expenses
Cost of natural gas sold	(131.5)		(208.0)		76.5
Other operation and maintenance (1)	(41.5)		(39.8)		(1.7)
Depreciation and amortization	(34.9)		(32.2)		(2.7)
Property and revenue taxes	(15.1)		(18.4)		3.3
Gross margin (GAAP)	85.6		81.1		4.5

Other operation and maintenance (1)	41.5		39.8		1.7
Depreciation and amortization	34.9		32.2		2.7
Property and revenue taxes	15.1		18.4		(3.3)
Utility margin (non-GAAP)	$	177.1	$	171.5	$	5.6

Gross margin (GAAP) increased $4.5 million during the nine months ended September 30, 2024, compared with the same period in 2023 and utility margin (non-GAAP) increased $5.6 million during the nine months ended September 30, 2024, compared with the same period in 2023. Both measures were driven by:

A $6.6 million increase related to MGU's rate increase approved by the MPSC that was effective January 1, 2024.
A $1.5 million increase related to MERC's final rate increase approved by the MPUC in November 2023.

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

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

*•*A $2.7 million increase in depreciation and amortization expense; and

A $1.7 million increase in natural gas operations and customer service expense; partially offset by
A $3.3 million decrease 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 other states segment decreased $1.0 million during the nine months ended September 30, 2024, compared with the same period in 2023. The significant factors impacting the decrease in operating expenses were:

A $3.3 million decrease in property and revenue taxes, driven by the resolution of a use tax audit at MGU.
A $3.0 million decrease in bad debt expense, driven by improvements in MERC's and MGU's loss rates.


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

These decreases in other operating expenses were partially offset by:

A $2.7 million increase in depreciation and amortization expense related to continued capital investment.
A $1.7 million increase in natural gas operations and customer service expense, driven by the timing of various operation and maintenance projects, primarily at MERC.
A $1.1 million increase in benefit costs, partially driven by higher costs related to stock-based compensation and deferred compensation.

Income Tax Expense

Income tax expense at the other states segment increased $1.5 million during the nine months ended September 30, 2024, compared with the same period in 2023, driven by higher pre-tax income.

Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders


	Nine Months Ended September 30
(in millions)	2024		2023		B (W)
Equity in earnings of transmission affiliates	$	138.3	$	132.1	$	6.2
Interest expense	14.5		14.6		0.1
Income before income taxes	123.8		117.5		6.3

Income tax expense	30.6		29.4		(1.2)
Net income attributed to common shareholders	$	93.2	$	88.1	$	5.1

Equity in Earnings of Transmission Affiliates

Equity in earnings of transmission affiliates increased $6.2 million during the nine months ended September 30, 2024, compared with the same period in 2023. This increase was primarily due to continued capital investment by ATC.

Income Tax Expense

Income tax expense at the electric transmission segment increased $1.2 million during the nine months ended September 30, 2024, compared with the same period in 2023, 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)	2024		2023		B (W)
Operating income	$	280.8	$	266.5	$	14.3

Other income, net	0.4		—		0.4
Interest expense	71.6		69.8		(1.8)
Income before income taxes	209.6		196.7		12.9

Income tax benefit	(59.6)		(44.2)		15.4
Net loss attributed to noncontrolling interests	3.4		0.9		2.5
Net income attributed to common shareholders	$	272.6	$	241.8	$	30.8


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Operating Income

Operating income at the non-utility energy infrastructure segment increased $14.3 million during the nine months ended September 30, 2024, compared with the same period in 2023, which was primarily due to a $9.7 million positive impact from We Power due to continued capital investment.

In addition, WECI had a positive impact of $4.2 million driven by these items:

A $24.4 million positive impact in 2024 related to the receipt of performance payments.
A $12.9 million increase in PPA revenue resulting from increased generation driven by higher wind speeds and lower energy curtailments.

These increases in operating income were partially offset by:

An $11.3 million increase in operation and maintenance expenses due primarily to equipment failures at several of our renewable generation facilities.
A $7.9 million negative impact due to transmission congestion that reduced energy market prices.
Recognition of $6.4 million in revenue related to Blooming Grove in 2023 for a capacity payment received from PJM Interconnection that was associated with a December 2022 cold weather event. The capacity payment was subject to a FERC complaint, so we recognized this as revenue in 2023 when FERC issued an order denying that complaint.
A $4.6 million decrease due to lower amounts recognized for REC sales in 2024 at Blooming Grove driven by lower contracted REC prices overall, as well as timing of REC contract execution.
A net $2.9 million negative impact on operating income due to higher depreciation in 2024, partially offset by an increase in amortization of intangible revenue contract liabilities from Sapphire Sky, a wind facility acquired in February 2023 and Samson I, a solar facility acquired in February 2023.

Interest Expense

Interest expense at the non-utility energy infrastructure segment increased $1.8 million during the nine months ended September 30, 2024, compared with the same period in 2023, primarily due to a $5.4 million increase in intercompany interest expense due to WECI’s issuance of a $430.0 million long-term intercompany note payable to WEC Energy Group in April 2023. This intercompany interest expense is offset by higher intercompany interest income at the corporate and other segment. Partially offsetting this increase, was lower interest expense due to a lower principal balance, as a result of the semi-annual principal payments on long-term debt.

Income Tax Benefit

The income tax benefit at the non-utility energy infrastructure segment increased $15.4 million during the nine months ended September 30, 2024, compared with the same period in 2023. The increase was primarily due to an increase in PTCs that was related to the IRS approved PTC rate increase and higher production volumes, partially offset by higher pre-tax earnings.


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


	Nine Months Ended September 30
(in millions)	2024		2023		B (W)
Operating loss	$	(6.1)	$	(16.1)	$	10.0

Other income, net	41.7		35.3		6.4
Interest expense	222.1		183.9		(38.2)

Loss before income taxes	(186.5)		(164.7)		(21.8)

Income tax benefit	(58.0)		(63.3)		(5.3)
Net loss attributed to common shareholders	$	(128.5)	$	(101.4)	$	(27.1)

Operating Loss

The operating loss at the corporate and other segment decreased $10.0 million during the nine months ended September 30, 2024, compared with the same period in 2023. The lower operating loss was driven by a $12.6 million positive impact from WBS's allocation of its net credits from the non-service components of its net periodic pension and OPEB costs. These net credits are initially recorded in other income, net, but are allocated to our operating segments as an overhead cost, which is recorded through operating expenses. As a result, this positive impact is fully offset in the other income, net line item discussed below. This positive impact was partially offset by a $1.7 million period-over-period decrease in gains on the sale of land and other assets at Wispark.

Other Income, Net

Other income, net at the corporate and other segment increased $6.4 million during the nine months ended September 30, 2024, compared with the same period in 2023. The significant factors impacting the increase in other income, net were:

A $9.5 million increase in interest income, driven by a $5.4 million increase in intercompany interest income from WECI due to its issuance of a $430.0 million long-term intercompany note to WEC Energy Group in April 2023. This intercompany interest income is offset by higher intercompany interest expense at our non-utility energy infrastructure segment. Higher interest income on cash balances of $2.7 million also contributed to the increase.
A $6.7 million period-over-period increase due to net earnings of $3.5 million from our equity method investments in technology and energy-focused investment funds during the nine months ended September 30, 2024, compared with net losses of $3.2 million during the same period in 2023.
A $2.6 million increase in the net gains from the investments held in the Integrys rabbi trust. The gains from the investments held in the rabbi trust partially offset the changes in benefit costs related to deferred compensation, which are primarily included in other operation and maintenance expense in our utility segments.

These increases in other income, net were partially offset by a $12.6 million decrease driven by lower net credits from the non-service components of WBS's net periodic pension and OPEB costs. As discussed above, this negative impact was offset by lower operating expenses as these credits are allocated to our operating segments as an overhead cost.

Interest Expense

Interest expense at the corporate and other segment increased $38.2 million during the nine months ended September 30, 2024, compared with the same period in 2023, due to the impact of long-term debt issuances by WEC Energy Group in April and September 2023 and May 2024, higher average short-term debt balances, and increased average short-term debt interest rates. Partially offsetting these increases in interest expense was the impact of Integrys' long-term debt redemption in August 2023, WEC Energy Group's long-term debt maturity in September 2023, WEC Energy Group's tender offer for its 2007 Junior Notes in January and February 2024, and WEC Energy Group's repurchase of $19.0 million of its 2007 Junior Notes in May 2024.


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Income Tax Benefit

The income tax benefit at the corporate and other segment decreased $5.3 million during the nine months ended September 30, 2024, compared with the same period in 2023. This decrease was driven by a $13.6 million increase in the interim tax expense recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate, partially offset by a higher pre-tax loss.

LIQUIDITY AND CAPITAL RESOURCES

Overview

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

Cash Flows

The following table summarizes our cash flows during the nine months ended September 30:


(in millions)	2024		2023		Change in 2024 Over 2023
Cash provided by (used in):
Operating activities	$	2,630.0	$	2,538.4	$	91.6
Investing activities	(2,053.2)		(2,771.7)		718.5
Financing activities	(381.0)		192.5		(573.5)

Operating Activities

Net cash provided by operating activities increased $91.6 million during the nine months ended September 30, 2024, compared with the same period in 2023, driven by:

A $230.4 million increase in cash related to $214.6 million of cash received for income taxes during the nine months ended September 30, 2024, compared with $15.8 million of cash paid for income taxes during the same period in 2023. The increase in cash received for income taxes was driven by proceeds received during the nine months ended September 30, 2024, related to 2023 and 2024 PTCs that were sold to third parties.
A $146.5 million increase in cash driven by lower amounts of collateral paid to counterparties during the nine months ended September 30, 2024, compared with same period in 2023, as well as lower realized losses on derivative instruments recognized during the nine months ended September 30, 2024, compared with the same period in 2023.

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

A $188.5 million decrease in cash from lower overall collections from customers during the nine months ended September 30, 2024, compared with the same period in 2023. This decrease was driven by a lower per-unit cost of natural gas and lower sales volumes from unfavorable weather during the nine months ended September 30, 2024, compared with the same period in 2023.
A $100.2 million decrease in cash from higher payments for interest, driven by long-term debt issuances at higher interest rates during 2023 and 2024, higher average short-term debt balances, and increased average short-term debt interest rates during the nine months ended September 30, 2024, compared with the same period in 2023.


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Investing Activities

Net cash used in investing activities decreased $718.5 million during the nine months ended September 30, 2024, compared with the same period in 2023, driven by:

The acquisition of a 90% ownership interest in Sapphire Sky in February 2023 for $442.6 million, net of cash acquired of $0.3 million.
The acquisition of an 80% ownership interest in Samson I in February 2023 for $249.4 million, net of cash acquired of $5.2 million.
The acquisition of a 90% ownership interest in Red Barn in April 2023 for $143.8 million.
The acquisition of Whitewater in January 2023 for $76.0 million.
An $18.8 million decrease in cash paid for ATC's construction costs during the nine months ended September 30, 2024, compared with the same period in 2023. These construction costs are reimbursable by ATC. See Note 20, Investment in Transmission Affiliates, for more information.

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

A $205.2 million increase in cash paid for capital expenditures during the nine months ended September 30, 2024, which is discussed in more detail below.
A $29.2 million decrease in proceeds received from the sale of assets during the nine months ended September 30, 2024, compared with the same period in 2023, driven by the sale of land at the site of our former Pleasant Prairie power plant in 2023. See Note 3, Disposition, for more information.

For more information on our acquisitions, see Note 2, Acquisitions.

Capital Expenditures

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


Reportable Segment (in millions)	2024		2023		Change in 2024 Over 2023
Wisconsin	$	1,546.6	$	1,263.5	$	283.1
Illinois	256.2		343.4		(87.2)
Other states	82.2		71.4		10.8
Non-utility energy infrastructure	33.7		33.9		(0.2)
Corporate and other	16.0		17.3		(1.3)
Total capital expenditures	$	1,934.7	$	1,729.5	$	205.2

The increase in cash paid for capital expenditures at the Wisconsin segment during the nine months ended September 30, 2024, compared with the same period in 2023, was driven by higher payments for WE's electric distribution system, increased capital expenditures for renewable energy projects at WE, WPS, and UMERC, increased capital expenditures for combustion turbines at OCPP, as well as increased capital expenditures for a project to consolidate our electric utility operations technology. These increases in capital expenditures were partially offset by decreased payments for natural gas-fired generation that was constructed at WPS's existing Weston power plant site and construction of WE's and WG's LNG facilities which were completed in November 2023 and February 2024, respectively.

The decrease in cash paid for capital expenditures at the Illinois segment during the nine months ended September 30, 2024, compared with the same period in 2023, was driven by lower payments related to PGL's natural gas distribution system, including SMP. For more information on the factors contributing to this decrease, see Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Future Illinois Proceedings.

The increase in cash paid for capital expenditures at the Other States segment during the nine months ended September 30, 2024, compared with the same period in 2023, was driven by increased payments for MGU's natural gas distribution system.


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

Financing Activities

Net cash related to financing activities decreased $573.5 million during the nine months ended September 30, 2024, compared with the same period in 2023, driven by:

A $1,326.6 million decrease in cash due to higher net repayments of commercial paper during the nine months ended September 30, 2024, compared with the same period in 2023.
A $53.1 million decrease in cash due to higher dividends paid on our common stock during the nine months ended September 30, 2024, compared with the same period in 2023. In January 2024, our Board of Directors increased our quarterly dividend by $0.055 per share (7.1%) effective with the March 2024 dividend payment.
The purchase of an additional 10% ownership interest in Samson I in January 2024 for $28.1 million.

These decreases in cash were partially offset by:

A $622.4 million increase in cash due to higher issuances of long-term debt during the nine months ended September 30, 2024, compared with the same period in 2023.
A $158.5 million increase in cash due to lower retirements of long-term debt during the nine months ended September 30, 2024, compared with the same period in 2023.
A $51.0 million increase in cash due to the issuance of common stock during the nine months ended September 30, 2024. We did not issue any common stock during the nine months ended September 30, 2023. See Note 9, Common Equity, for more information.

Other Significant Financing Activities

For more information on our other significant financing activities, see Note 10, Short-Term Debt and Lines of Credit, and Note 11, 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 2023 Annual Report on Form 10-K for additional information regarding our significant cash requirements.


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Significant Capital Projects

We have several capital projects that will require significant capital expenditures over the next three years and beyond. All projected capital requirements are subject to periodic review and may vary significantly from estimates, depending on a number of factors. These factors include environmental requirements, regulatory restraints and requirements, changes in tax laws and regulations, acquisition and development opportunities, market volatility, economic trends, supply chain disruptions, inflation, and interest rates. Our estimated capital expenditures and acquisitions for the next three years are reflected below. These amounts include anticipated expenditures for environmental compliance and certain remediation issues. For a discussion of certain environmental matters affecting us, see Note 23, Commitments and Contingencies.


(in millions)	2024 (1)		2025		2026
Wisconsin	$	2,692.6	$	4,202.4	$	4,410.7
Illinois	353.4		373.7		404.8
Other states	119.5		106.5		121.4
Non-utility energy infrastructure	953.7		437.6		23.1
Corporate and other	26.2		17.9		10.2
Total	$	4,145.4	$	5,138.1	$	4,970.2

(1)This includes actual capital expenditures incurred through September 30, 2024, as well as estimated capital expenditures for the remainder of the year.

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

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

WE and WPS, along with an unaffiliated utility, received PSCW approval to acquire and construct Paris, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Kenosha County, Wisconsin and once fully constructed, WE and WPS will collectively own 180 MWs of solar generation and 99 MWs of battery storage of this project. WE's and WPS's combined share of the cost of this project is estimated to be approximately $542 million, with construction of the solar portion and battery storage expected to be completed in 2024 and 2025, respectively.
WE and WPS, along with an unaffiliated utility, received PSCW approval to acquire and construct Darien, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Rock and Walworth counties, Wisconsin and once fully constructed, WE and WPS will collectively own 225 MWs of solar generation and 68 MWs of battery storage of this project. WE's and WPS's combined share of the cost of this project is estimated to be approximately $567 million, with construction of the solar portion and battery storage expected to be completed in 2025 and 2026, respectively.
WE and WPS, along with an unaffiliated utility, received PSCW approval to acquire Koshkonong, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Dane County, Wisconsin and once fully constructed, WE and WPS will collectively own 270 MWs of solar generation and 149 MWs of battery storage of this project. WE's and WPS's combined share of the cost of this project is estimated to be approximately $930 million, with construction of the solar portion and battery storage expected to be completed in 2026 and 2027, respectively.
In May 2024, WE completed the acquisition of an additional 100 MWs of capacity in West Riverside, a combined cycle natural gas plant operated by an unaffiliated utility in Rock County, Wisconsin, for $97.9 million.
WE and WPS plan to enhance fuel flexibility at the coal-fired ERGS units and Weston Unit 4.
In February 2024, WE and WPS, along with an unaffiliated utility, filed a request with the PSCW to acquire and construct High Noon Solar Energy Center, a utility-scale solar-powered electric generating facility with a battery energy storage system. If approved, the project will be located in Columbia County, Wisconsin and once fully constructed, WE and WPS will collectively own 270 MWs of solar generation and 149 MWs of battery storage of this project. If approved, WE and WPS's combined share of the cost of this project is estimated to be approximately $883 million, with construction of the solar portion and battery storage expected to be completed in 2027.


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UMERC received MPSC approval to acquire and construct Renegade, a utility-scale solar-powered electric generating facility. The project will be located in Delta and Marquette counties, Michigan and once fully constructed UMERC will own 100 MWs of solar generation. The cost of this project is estimated to be approximately $226 million, with construction expected to be completed by the end of 2026.
In April 2024, WE filed a request with the PSCW to build five natural gas fired combustion turbines capable of producing approximately 1,100 MWs which would be located at the existing OCPP site. If approved, the cost of this project is estimated to be approximately $1.2 billion.
In April 2024, WE filed a request with the PSCW to add seven natural gas-fired RICE units near the Paris Generating Station. The new RICE units would be fueled with natural gas and capable of producing approximately 128 MWs. If approved, the cost of this project is estimated to be approximately $280 million.
In April 2024, WE filed a request with the PSCW to construct the Rochester Lateral, which would supply additional natural gas service to the OCPP site. The natural gas lateral would be built in Kenosha, Racine, and Milwaukee counties. If approved, the cost of this project is estimated to be approximately $200 million.
In April 2024, WE filed a request with the PSCW to construct an LNG facility which would be located on the OCPP site. If approved, the facility would have a storage capacity of two Bcf and the cost of this project is estimated to be approximately $456 million.
In September 2024, WE and WPS, along with an unaffiliated utility, filed a request with the PSCW to acquire Dawn Harvest Solar Energy Center, a utility-scale solar-powered electric generating facility with a battery energy storage system. If approved, the project will be located in Rock County, Wisconsin and once fully constructed, WE and WPS will collectively own 135 MWs of solar generation and WE will own 50 MWs of battery storage of this project. If approved, WE and WPS's combined share of the cost of this project is estimated to be approximately $409 million, with construction expected to be completed in 2028.
In September 2024, WE and WPS, along with an unaffiliated utility, filed a request with the PSCW to acquire Saratoga, a utility-scale solar-powered electric generating facility with a battery energy storage system and Ursa, a utility-scale solar-powered electric generating facility. If approved, Saratoga will be located in Wood County, Wisconsin and Ursa will be located in Columbia County, Wisconsin. Once fully constructed, WE and WPS will collectively own 135 MWs of solar generation and 45 MWs of battery storage of Saratoga and 180 MWs of solar generation of Ursa. If approved, WE and WPS's combined share of the cost of Ursa is estimated to be approximately $406 million, with construction expected to be completed in 2027. If approved, WE and WPS's combined share of the cost of Saratoga is estimated to be approximately $406 million, with construction expected to be completed in 2028.
In September 2024, WE and WPS, along with an unaffiliated utility, filed a request with the PSCW to acquire and construct Badger Hollow and to acquire Whitetail, two utility-scale wind-powered electric generating facilities. If approved, Badger Hollow will be located in Iowa and Grant counties, Wisconsin and Whitetail will be located in Grant County, Wisconsin. Once fully constructed, WE and WPS will collectively own 100 MWs of wind generation of Badger Hollow and 60 MWs of wind generation of Whitetail. If approved, WE and WPS's combined share of the cost of Badger Hollow is estimated to be $320 million, with construction expected to be completed in 2027. If approved, WE and WPS's combined share of the cost of Whitetail is estimated to be approximately $200 million, with construction expected to be completed in 2027.
In October 2024, WE and WPS, along with an unaffiliated utility, filed a request with the PSCW to acquire and construct Good Oak and Gristmill, two utility-scale solar electric generating facilities. If approved, both Good Oak and Gristmill will be located in Columbia County, Wisconsin. Once fully constructed, WE and WPS will collectively own 88 MWs of solar generation of Good Oak and 60 MWs of solar generation of Gristmill. If approved, WE and WPS's combined share of the cost of Good Oak is estimated to be $194 million and the cost of Gristmill is estimated to be approximately $130 million, with construction for both projects expected to be completed in 2028.

The construction of additional LNG facilities in Wisconsin has been proposed as part of the 2025-2029 capital plan and would provide another approximately four Bcf of natural gas supply. The 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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In August 2023, the DOC issued a ruling in its investigation into whether new tariffs should be imposed on solar panels and cells imported from four southeast Asian countries. In response to a new petition in April 2024, the DOC and USITC are conducting additional investigations into the solar panels and cells from the same four southeast Asian countries. See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – United States Department of Commerce Complaint and Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Uyghur Forced Labor Prevention Act for information on the potential impacts to our solar projects as a result of the DOC ruling and related USITC investigation, and CBP actions, related to solar panels, respectively. The expected in-service dates and costs identified above already reflect some of these impacts.

During 2023, PGL continued work on the SMP, a project to replace approximately 2,000 miles of Chicago's aging natural gas pipeline infrastructure. In November 2023, the ICC ordered PGL to pause spending on the SMP until the ICC has a proceeding to determine the optimal method of pipeline replacement and a prudent investment level. The ICC initiated the proceeding on January 31, 2024, and the proceeding is expected to last twelve months. For more information, see Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Future Illinois Proceedings. The ICC granted PGL a limited-scope rehearing, which focused exclusively on the authorized spending for the completion of SMP projects that started in 2023 and the authorized spending for emergency repairs needed to ensure the safety and reliability of PGL's delivery system. On May 30, 2024, the ICC issued a written order on the rehearing that approved $28.5 million of additional spending for emergency work. See Note 25, Regulatory Environment, for more information on the SMP.

The non-utility energy infrastructure line item in the table above includes WECI's investment in Maple Flats, Delilah I, Hardin III, and the purchase of an additional 10% ownership interest in Samson I. See Note 2, Acquisitions, for more information on these projects.

We expect to provide total capital contributions to ATC (not included in the above table) of approximately $315 million from 2024 through 2026. We do not expect to make any contributions to ATC Holdco during that period. WEC's portion of the investment in MISO Tranche 1 is estimated to be approximately $580 million between 2025 and 2029. 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 11, Long-Term Debt, for information regarding the changes in our outstanding long-term debt during the nine months ended September 30, 2024.

Common Stock Dividends

Our current quarterly dividend rate is $0.835 per share, which equates to an annual dividend of $3.34 per share. For information related to our most recent common stock dividend declared, see Note 9, Common Equity.

Other Significant Cash Requirements

See Note 23, 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, 2024.

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 10, Short-Term Debt and Lines of Credit, Note 17, Guarantees, and Note 22, 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, which allows us to obtain external short-term borrowings, including commercial paper and term loans, and intermediate or long-term debt securities, as well as other types of securities. In addition, in January 2024, we started issuing common equity through a combination of our employee benefit plans and stock purchase and dividend reinvestment plan. We also anticipate issuing common equity through an at-the-market program in the future. Cash generated from operations is primarily driven by sales of electricity and natural gas to our utility customers, reduced by costs of operations. Our access to the capital markets is critical to our overall strategic plan and allows us to supplement cash flows from operations with external borrowings to manage seasonal variations, working capital needs, commodity price fluctuations, unplanned expenses, and unanticipated events. 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. In January and February 2024, pursuant to a tender offer, we purchased $122.1 million aggregate principal amount of the $500.0 million outstanding of our 2007 Junior Notes. Additionally, in May 2024, we repurchased $19.0 million aggregate principal amount of the $377.9 million outstanding of our 2007 Junior Notes for $18.7 million, plus accrued interest, with proceeds received from issuing commercial paper.

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 2024, 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 2023 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, 2024, our current liabilities exceeded our current assets by $1,390.2 million. We do not expect this to have an impact on our liquidity, as we currently believe that our cash and cash equivalents, our available capacity of $2,705.3 million 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 10, Short-Term Debt and Lines of Credit, and Note 11, Long-Term Debt, for more information about our credit facilities, commercial paper, and debt securities.

Investments in Outside Trusts

We maintain investments in outside trusts to fund the obligation to provide pension and certain OPEB benefits to current and future retirees. These trusts 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 2023 Annual Report on Form 10-K.


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Capitalization Structure

The following table shows our capitalization structure as of September 30, 2024, as well as an adjusted capitalization structure that we believe is consistent with how a majority of the rating agencies currently view our 2007 Junior Notes:


(in millions)	Actual			Adjusted
Common shareholders' equity	$	12,082.0		$	12,261.4
Preferred stock of subsidiary	30.4			30.4
Long-term debt (including current portion)	18,712.9			18,533.5
Short-term debt	597.0			597.0
Total capitalization	$	31,422.3		$	31,422.3

Total debt	$	19,309.9		$	19,130.5

Ratio of debt to total capitalization	61.5		%	60.9		%

Included in long-term debt on our balance sheet as of September 30, 2024, is $358.9 million principal amount of the 2007 Junior Notes. The adjusted presentation attributes $179.4 million of the 2007 Junior Notes to common shareholders' equity and $179.5 million to long-term debt.

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

Debt Covenants

Certain of our short-term and long-term debt agreements contain financial covenants that we must satisfy, including debt to capitalization ratios and debt service coverage ratios. At September 30, 2024, 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 2023 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, 2024. 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, 2024, it could have been required to post $103 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 June 2024, Moody's changed the rating outlook for PGL to negative from stable as a result of the November 2023 rate order and the May 2024 limited re-hearing. The change in rating outlook has not had, and we do not believe that it will have, a material impact on our ability to access capital markets. Moody's affirmed PGL's ratings including its Aa3 senior secured rating and its P-1 short term rating for commercial paper. See Note 25, Regulatory Environment, for more information on the outcome of the rate order.

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 2023 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, competitive markets, environmental matters, critical accounting policies and estimates, and other matters.

Regulatory, Legislative, and Legal Matters

Regulatory Recovery

Our utilities account for their regulated operations in accordance with accounting guidance under the Regulated Operations Topic of the FASB ASC. Regulated entities are allowed to defer certain costs that would otherwise be charged to expense if the regulated entity believes the recovery of those costs is probable. We record regulatory assets pursuant to generic and/or specific orders issued by our regulators. Recovery of the deferred costs in future rates is subject to the review and approval by those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of the deferred costs, including those referenced below, is not approved by our regulators, the costs would be charged to income in the current period. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities. See Note 6, Regulatory Assets and Liabilities, for more information on our regulatory assets and liabilities. See Note 25, Regulatory Environment, in this report, and Note 26, Regulatory Environment, in our 2023 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 June 2023, the ICC denied PGL's and NSG's application requesting a rehearing of the ICC's May 2023 order. In July 2023, PGL and NSG petitioned the Illinois Appellate Court for review of the ICC orders. Their appeal is still pending.

As of September 30, 2024, there can be no assurance that all costs incurred under the UEA rider during the open reconciliation years, which include 2019 through 2023, 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. On August 14, 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 these investments. On October 25 2024, PGL filed a petition with the Illinois Appellate Court for review of the ICC's August 14, 2024 order.

In March 2024, PGL filed its 2023 reconciliation with the ICC, which, along with the reconciliations from 2017 through 2022, is still pending. The aggregate capital costs included in the QIP rider during the open reconciliation years, which include 2017 through 2023, are approximately $2,058 million. As of September 30, 2024, there can be no assurance that all of these costs, along with any previously recognized return on these investments, will be deemed recoverable by the ICC. Further disallowances by the ICC, if any, could be material and have a material adverse impact on our results of operations.


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Illinois Proceedings

In the PGL rate order issued by the ICC in November 2023, the ICC ordered PGL to pause spending on its SMP until the ICC completes a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level. The ICC initiated the proceeding on January 31, 2024, and the proceeding is expected to last 12 months.

On March 7, 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 these proceedings 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 outcomes. See Note 25, 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.

Petition Before PSCW Regarding Third-Party Financed Distributed Energy Resources

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

In December 2022, the PSCW granted the petitioner’s request for a declaratory ruling in part, finding that the owner of the third-party financed DER at issue in the petitioner’s brief is not a public utility under Wisconsin law. The ruling was limited to the facts and circumstances of the specific project lease presented in that petition. The PSCW declined to issue the petitioner’s request for a broader declaratory ruling that the petitioner would not be regulated as a "public utility". Upon appeal, in April 2024, the Dane County Circuit Court reversed the PSCW’s decision, finding that the PSCW erroneously interpreted the definition of "public utility," and the evidence did not support its determination that the lease at issue in the petition did not involve the sale of electricity to the "public" under Wisconsin law. The case was remanded to the PSCW for further review. In June 2024 the PSCW issued an order to reopen the docket to consider modifications based upon the circuit court’s remand. On October 3, 2024, the PSCW issued an order declining to issue any declaratory ruling because the project lease originally at issue was no longer going forward. At this time we do not expect any material impact on our business operations.


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Uyghur Forced Labor Prevention Act

The CBP issued a WRO in June 2021, applicable to certain silica-based products originating from the Xinjiang Uyghur Autonomous Region of China (Xinjiang), such as polysilicon, included in the manufacturing of solar panels. In June 2022, the WRO was superseded by the implementation of the UFLPA. The UFLPA establishes a rebuttable presumption that any imports wholly or partially manufactured in Xinjiang are prohibited from entering the United States. While our suppliers were able to provide the CBP sufficient documentation to meet WRO and 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.

United States Department of Commerce Complaints

The solar panel industry continues to experience uncertainty resulting from AD and CVD investigations involving four southeast Asian countries including Malaysia, Vietnam, Thailand, and Cambodia.

In August 2023, the DOC issued a final decision regarding an AD/CVD petition filed by a California-based company alleging that Chinese manufacturers were shifting products to the four southeast Asian countries to avoid tariffs required on products imported from China and requesting that the DOC conduct a country-wide inquiry into each country. In its final decision, the DOC determined that circumvention was occurring in each of the four Southeast Asian countries noted above. Duties began to be applied to certain imports of solar cells from Malaysia, Vietnam, Thailand and Cambodia after expiration of the Biden Administration’s 24-month tariff moratorium on June 6, 2024. In addition, in response to its findings, the DOC promulgated new regulations that imposed enhanced duties in certain circumstances, including when the USITC determines there is a reasonable indication the domestic solar industry is materially or potentially injured because of imported products that violate certain fair trade laws.

In April 2024, a coalition of several U.S. producers of solar panels filed a petition with the DOC requesting new 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 implemented after the expiration of the moratorium. In May 2024, in response to the petition, the DOC initiated a new AD/CVD investigation of solar panels from the four southeast Asian countries.

In April 2024, the USITC began a preliminary investigation and, in June 2024, issued a preliminary determination that there is a reasonable indication imports of solar panels from the four Southeast Asian countries have caused injury to the U.S. solar industry. Based on the USITC’s preliminary decision, the DOC began an investigation and, on October 1, 2024 announced a preliminary affirmative determination in its CVD investigation and set preliminary duties on imports from the four southeast Asian countries. Its AD investigation is proceeding and a preliminary determination is scheduled for late 2024. If the DOC and USITC make final affirmative determinations in their investigations, the DOC may impose enhanced duties, including retroactive duties in certain circumstances. Final determinations are scheduled for early 2025.

The Biden Administration invoked the Defense Production Act to accelerate the production of solar panels in the U.S.; however, final determinations by the DOC and/or USITC may have an adverse impact on the solar industry overall. Additionally, the Biden Administration's actions did not address whether WROs applied to panels under previous complaints would be affected.

We are continuing to monitor these investigations as they progress to determine the potential impact on our business and results of operations.

Infrastructure Investment and Jobs Act

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


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Inflation Reduction Act

In August 2022, President Biden signed into law the IRA, which provides for $258 billion in energy-related provisions over a 10-year period. The provisions of the IRA are intended to, among other things, lower gasoline and electricity prices, incentivize domestic clean energy investment, manufacturing, and production, and promote reductions in carbon emissions. We believe that we and our customers can benefit from the IRA’s provisions that extend tax benefits for renewable technologies, increase or restore higher rates for PTCs, add an option to claim PTCs for solar projects, expand qualified ITC facilities to include standalone energy storage, and its provision to allow companies to transfer tax credits generated from renewable projects. Under the IRA transferability option, we entered into a sales agreement in May 2024 to sell substantially all of our 2024 PTCs to a third party. See Note 14, 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.

Return on Equity Incentive for Membership in a Transmission Organization

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

American Transmission Company Allowed Return on Equity 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 the first complaint, November 12, 2013 through February 11, 2015 and September 28, 2016 going forward.
November 2019 FERC Order – On November 21, 2019, the FERC issued another order after directing MISO transmission owners and other stakeholders to provide briefs and comments on a proposed change to the methodology for calculating base ROE. In this order, the FERC expanded its base ROE methodology to include the capital-asset pricing model in addition to the discounted cash flow model to better reflect how investors make their investment decisions. The FERC also rejected the use of the risk premium model as part of its base ROE methodology in this order. The FERC's modified methodology further reduced the base ROE for all MISO transmission owners, including ATC, to 9.88% for the period covered by the first complaint. In response to this FERC decision, requests for the FERC to rehear the November 2019 Order in its entirety were filed by various parties.


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May 2020 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 first 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 had reflected 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 first 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 will be 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. Therefore, ATC is expected to provide WE, WPS, and UMERC with refunds related to the transmission costs they paid during these two refund periods. The refunds will be 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 its reserve and the 9.98% base ROE authorized in the October 2024 FERC Order, ATC will reduce its refund liability. We expect this to increase our pre-tax equity earnings by approximately $19 million to $20 million. We are still in the process of reviewing the October 2024 FERC order for any additional impacts to us.

Environmental Matters

See Note 23, Commitments and Contingencies, for a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change.

Market Risks and Other Significant Risks

We are exposed to market and other significant risks as a result of the nature of our businesses and the environments in which those businesses operate. These risks include, but are not limited to, the inflation and supply chain disruptions described below. In addition, there is continuing uncertainty over the impact that the ongoing regional conflicts, including those in Ukraine, Israel and in other parts of the Middle East, will have on the global economy, supply chains, and fuel prices. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in our 2023 Annual Report on Form 10-K for a discussion of market and other significant risks applicable to us.


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Inflation and Supply Chain Disruptions

We continue to monitor the impact of inflation and supply chain disruptions. We monitor the costs of medical plans, fuel, transmission access, construction costs, regulatory and environmental compliance costs, and other costs in order to minimize inflationary effects in future years, to the extent possible, through pricing strategies, productivity improvements, and cost reductions. We monitor the global supply chain, and related disruptions, in order to ensure we are able to procure the necessary materials and other resources necessary to both maintain our energy services in a safe and reliable manner and to grow our infrastructure in accordance with our capital plan. For additional information concerning risks related to inflation and supply chain disruptions, see the four risk factors below that are disclosed in Part I of our 2023 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 – Fluctuating commodity 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.

Weather

Our utilities' rates are based upon estimated normal temperatures. Our electric utility margins are unfavorably sensitive to below normal temperatures during the summer cooling season and, to some extent, to above normal temperatures during the winter heating season. Our natural gas utility margins are unfavorably sensitive to above normal temperatures during the winter heating season. PGL, NSG, and MERC have decoupling mechanisms in place that help reduce the impacts of weather. Decoupling mechanisms differ by state and allow utilities to recover or refund certain differences between actual and authorized margins. A summary of actual weather information in our utilities' service territories during the three and nine months ended September 30, 2024 and 2023, as measured by degree days, can be found in Results of Operations.

Our utility operations (primarily our electric utility operations) and the operations of WECI, can be negatively impacted from storms. High wind conditions, lightning, hail, and flooding from these storms can result in downed wires and poles, as well as damage to wind and solar generation facilities and other operating equipment. This can result in us incurring significant restoration costs at our utilities and at WECI, including lost revenue to customers. Our utilities' rates include a fixed amount for expected storm restoration costs. To the extent actual storm restoration costs are above what is included in these rates, earnings at our utility operations are negatively impacted and it becomes more difficult to achieve our authorized ROEs. Similarly, restoration costs and lost revenue from storms negatively impacts operations and earnings at our non-utility WECI renewable generation facilities.

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 2023 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, 2024. 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.


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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 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, 2024, 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 19, Goodwill and Intangibles, for more information.

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