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 2021 Annual Report on Form 10-K.

Introduction

We are a diversified holding company with natural gas and electric utility operations (serving customers in Wisconsin, Illinois, Michigan, and Minnesota), an approximately 60% equity ownership interest in American Transmission Company LLC (ATC) (a for-profit electric transmission company regulated by the Federal Energy Regulatory Commission and certain state regulatory commissions), and non-utility energy infrastructure operations through W.E. Power, LLC (which owns generation assets in Wisconsin), Bluewater Natural Gas Holding, LLC (which owns underground natural gas storage facilities in Michigan), and WEC Infrastructure LLC (WECI), which holds ownership interests in several wind generating facilities.

Corporate Strategy

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

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

Creating a Sustainable Future

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

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

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

We already have retired more than 1,800 megawatts (MW) of coal-fired generation since the beginning of 2018, which included the 2019 retirement of the Presque Isle power plant as well as the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater Unit 4 generating units. Through our ESG Progress Plan, we expect to retire approximately 1,600 MW of additional fossil-fueled generation by the end of 2026, which includes the planned retirement in 2024-2025 of Oak Creek Power Plant Units 5-8 and the planned retirement in 2026 of jointly-owned Columbia Units 1-2. See Note 24, Regulatory Environment, for information on the delay of these planned retirements.


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

1,800 MW of utility-scale solar;
700 MW of battery storage; and
700 MW of wind.

In addition, we are investing in 300 MW of utility-scale solar within our Wisconsin segment. Wisconsin Public Service Corporation (WPS) partnered with an unaffiliated utility to construct two solar projects now in service in Wisconsin: Two Creeks Solar Park (Two Creeks) and Badger Hollow Solar Park I (Badger Hollow I). WPS owns 100 MW of Two Creeks and 100 MW of Badger Hollow I for a total of 200 MW. Wisconsin Electric Power Company (WE) has partnered with an unaffiliated utility to construct Badger Hollow Solar Park II, which is expected to enter commercial operation in the first half of 2023. Once constructed, WE will own 100 MW of this project.

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

100 MW of reciprocating internal combustion engine (RICE) natural gas-fueled generation;
the planned purchase of up to 200 MW of capacity in the West Riverside Energy Center — a combined-cycle natural gas plant recently completed by Alliant Energy in Wisconsin; and
the planned purchase of the Whitewater Cogeneration Facility, a natural gas-fired combined-cycle electric generating facility with a capacity of 236.5 MW.

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

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

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

We also continue to reduce methane emissions by improving our natural gas distribution system. We set a target across our natural gas distribution operations to achieve net-zero methane emissions by the end of 2030. We plan to achieve our net-zero goal through an effort that includes both continuous operational improvements and equipment upgrades, as well as the use of renewable natural gas (RNG) throughout our utility systems. In 2022, we received approval from the PSCW for our RNG pilots and we signed our first four contracts for RNG for our natural gas distribution business, which will be transporting the output of local dairy farms onto our gas distribution system. The RNG supplied will directly replace higher-emission methane from natural gas that would have entered our pipes. Our first four contracts should bring us to 90 percent of the RNG needed to achieve our 2030 goal. We expect to have RNG flowing to our distribution network by the end of 2022.

As part of our effort to look for new opportunities in sustainable energy, during 2022 we completed testing the effects of blending hydrogen, a clean generating fuel, with natural gas for one of our RICE generating units in the Upper Peninsula of Michigan. We partnered with the Electric Power Research Institute in this research that could help create another viable option for decarbonizing the economy. We are still evaluating the data; however, our initial findings indicate that all project measures exceeded our expectations. We look forward to sharing the full results with our industry and the public early next year.


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Reliability

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

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

WE and Wisconsin Gas LLC (WG) have received approval to each construct their own liquefied natural gas (LNG) facility to meet anticipated peak demand. Commercial operation of the WE and WG LNG facilities is targeted for the end of 2023 and 2024, respectively.
The Peoples Gas Light and Coke Company continues to work on its Safety Modernization Program, which primarily involves replacing old iron pipes and facilities in Chicago’s natural gas delivery system with modern polyethylene pipes to reinforce the long-term safety and reliability of the system.
Our utilities continue to upgrade their electric and natural gas distribution systems to enhance reliability.

We expect to spend approximately $3.2 billion from 2023 to 2027 on reliability related projects with continued investment over the next decade. For more details, see Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.

Operating Efficiency

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

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

Financial Discipline

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

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

Our investment focus remains in our regulated utility and non-utility energy infrastructure businesses, as well as our investment in ATC. In our non-utility energy infrastructure segment, we have acquired or agreed to acquire majority interests in eight wind parks and one solar park, with total available capacity of more than 1,800 MW. These renewable energy assets represent approximately $2.7 billion in committed investments and have long-term agreements to serve customers outside our traditional service areas. Production tax credits from these wind investments reduce our cash tax expense. See Note 2, Acquisitions, for information on recent and pending transactions.

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


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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, 2022

Consolidated Earnings

The following table compares our consolidated results for the third quarter of 2022 with the third quarter of 2021, including favorable or better, "B", and unfavorable or worse, "W", variances:


	Three Months Ended September 30
(in millions, except per share data)	2022		2021		B (W)
Wisconsin	$	194.9	$	197.5	$	(2.6)
Illinois	14.9		19.1		(4.2)
Other states	(6.1)		(2.7)		(3.4)
Electric transmission	44.5		27.8		16.7
Non-utility energy infrastructure	71.0		64.4		6.6
Corporate and other	(17.2)		(16.1)		(1.1)
Net income attributed to common shareholders	$	302.0	$	290.0	$	12.0

Diluted earnings per share	$	0.96	$	0.92	$	0.04

Earnings increased $12.0 million during the third quarter of 2022, compared with the same quarter in 2021. The significant factors impacting the $12.0 million increase in earnings were:

A $16.7 million increase in net income attributed to common shareholders at the electric transmission segment, primarily due to the impact of the D.C. Circuit Court of Appeals opinion issued in August 2022 addressing complaints related to ATC's ROE. For more information, see Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – American Transmission Company Allowed Return on Equity Complaints.
A $6.6 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by an increase in PTCs during 2022, primarily due to the Jayhawk wind park that achieved commercial operation in December


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

These increases in earnings were partially offset by:

A $4.2 million decrease in net income attributed to common shareholders at the Illinois segment, driven by an increase in natural gas distribution and maintenance costs, along with higher depreciation and amortization. These negative impacts were partially offset by higher natural gas margins due to PGL's continued capital investment in the SMP project under its QIP rider.
A $3.4 million increase in net loss attributed to common shareholders at the other states segment, driven by increases in various operating expenses, including expenses related to property and revenue taxes, natural gas operations, and customer service. An increase in interest expense, primarily due to a deferral of interest expense during 2021 that is now being amortized over a four-year period, also contributed to the higher net loss.
A $2.6 million decrease in net income attributed to common shareholders at the Wisconsin segment, driven by a decrease in electric margins related to our expected fuel recovery. This decrease was partially offset by the amortization of certain regulatory liabilities to reduce a portion of our 2022 forecasted revenue deficiencies. The amortization was approved by the PSCW in order to forego filing for 2022 base rate increases. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on our 2022 Wisconsin base rates.

Non-GAAP Financial Measures

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

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

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


	Three Months Ended September 30
(in millions)	2022		2021
Wisconsin	$	367.3	$	352.8
Illinois	36.2		40.7
Other states	(5.4)		(2.2)

Each applicable segment discussion below includes a table that provides the calculation of electric margins and natural gas margins, as applicable, along with a reconciliation to the most directly comparable GAAP measure, operating income (loss).

Wisconsin Segment Contribution to Net Income Attributed to Common Shareholders

The Wisconsin segment's contribution to net income attributed to common shareholders was $194.9 million during the third quarter of 2022, representing a $2.6 million, or 1.3%, decrease over the same quarter in 2021. The lower earnings were driven by a decrease in electric margins related to our expected fuel recovery. This decrease was partially offset by the amortization of certain regulatory liabilities to reduce a portion of our 2022 forecasted revenue deficiencies. The amortization was approved by the PSCW in order to


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forego filing for 2022 base rate increases. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on our 2022 Wisconsin base rates.


	Three Months Ended September 30
(in millions)	2022		2021		B (W)
Electric revenues	$	1,440.2	$	1,288.2	$	152.0
Fuel and purchased power	605.7		437.7		(168.0)
Total electric margins	834.5		850.5		(16.0)

Natural gas revenues	236.6		170.4		66.2
Cost of natural gas sold	144.0		87.3		(56.7)
Total natural gas margins	92.6		83.1		9.5

Total electric and natural gas margins	927.1		933.6		(6.5)

Other operation and maintenance	329.1		359.1		30.0
Depreciation and amortization	189.2		184.4		(4.8)
Property and revenue taxes	41.5		37.3		(4.2)
Operating income	367.3		352.8		14.5

Other income, net	28.8		16.5		12.3
Interest expense	137.2		137.9		0.7
Income before income taxes	258.9		231.4		27.5

Income tax expense	63.7		33.6		(30.1)
Preferred stock dividends of subsidiary	0.3		0.3		—
Net income attributed to common shareholders	$	194.9	$	197.5	$	(2.6)

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


	Three Months Ended September 30
(in millions)	2022		2021		B (W)
Operation and maintenance not included in line items below	$	164.6	$	169.4	$	4.8
Transmission (1)	107.8		127.8		20.0
Regulatory amortizations and other pass through expenses (2)	35.6		34.4		(1.2)
We Power (3)	26.5		27.5		1.0
Earnings sharing mechanisms (4)	(5.4)		—		5.4
Total other operation and maintenance	$	329.1	$	359.1	$	30.0

(1)Represents transmission expense that our electric utilities are authorized to collect in rates. The PSCW has approved escrow accounting for ATC and MISO network transmission expenses for WE and WPS. As a result, WE and WPS defer as a regulatory asset or liability, the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the third quarter of 2022 and 2021, $134.9 million and $122.7 million, respectively, of costs were billed to our electric utilities by transmission providers.

During the third quarter of 2022, WE and WPS amortized $20.3 million of the regulatory liabilities associated with their transmission escrows to offset certain 2022 revenue deficiencies, as approved by the PSCW in order to forego filing for 2022 base rate increases. This amortization drove the decrease in transmission expense during the third quarter of 2022, compared with the same quarter in 2021. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on 2022 Wisconsin base rates.

(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 2022 and 2021, $29.7 million and $20.4 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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(4)Represents amortization of a certain portion of WPS's regulatory liability associated with its 2020 earnings sharing mechanism to offset certain 2022 revenue deficiencies, as approved by the PSCW in order to forego filing for 2022 base rate increases. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on 2022 Wisconsin base rates.

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	2022	2021	B (W)
Customer Class
Residential	3,225.6	3,374.1	(148.5)
Small commercial and industrial (1)	3,481.8	3,527.7	(45.9)
Large commercial and industrial (1)	3,268.3	3,239.2	29.1
Other	29.8	31.3	(1.5)
Total retail (1)	10,005.5	10,172.3	(166.8)
Wholesale	584.9	744.0	(159.1)
Resale	1,232.5	1,270.3	(37.8)
Total sales in MWh (1)	11,822.9	12,186.6	(363.7)

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


	Three Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2022	2021	B (W)
Customer Class
Residential	68.8	56.6	12.2
Commercial and industrial	62.8	52.4	10.4
Total retail	131.6	109.0	22.6
Transportation	287.2	280.5	6.7
Total sales in therms	418.8	389.5	29.3


	Three Months Ended September 30
	Degree Days
Weather	2022	2021	B (W)
WE and WG (1)
Heating (98 Normal)	89	22	304.5	%
Cooling (591 Normal)	677	715	(5.3)	%

WPS (2)
Heating (177 Normal)	129	114	13.2	%
Cooling (388 Normal)	468	389	20.3	%

UMERC (3)
Heating (304 Normal)	253	232	9.1	%
Cooling (260 Normal)	243	270	(10.0)	%

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

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

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

Electric Revenues

Electric revenues increased $152.0 million during the third quarter of 2022, compared with the same quarter in 2021. To the extent that changes in fuel and purchased power costs are passed through to customers, the changes are offset by comparable changes in


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revenues. See the discussion of electric utility margins below for more information related to the recovery of fuel and purchased power costs and the remaining drivers of the changes in electric revenues.

Electric Utility Margins

Electric utility margins at the Wisconsin segment decreased $16.0 million during the third quarter of 2022, compared with the same quarter in 2021. The significant factors impacting the lower electric utility margins were:

A $34.4 million decrease in margins related to our expected fuel recovery, driven by higher fuel costs as well as our current fuel forecast and earnings assumptions. Under the Wisconsin fuel rules, the margins of our electric utilities are impacted by under- or over-collections of certain fuel and purchased power costs that are within a 2% price variance from the costs included in rates, and the remaining variance beyond the 2% price variance is generally deferred for future recovery or refund to customers. We will review our actual fuel costs and earnings results at the end of the year and will further adjust our expected fuel recovery accordingly.
A $12.0 million net decrease in margins related to lower sales volumes, driven by the impact of cooler weather during the third quarter of 2022, compared with the same quarter in 2021. As measured by cooling degree days, the third quarter of 2022 was 5.3% cooler than the same quarter in 2021 in the Milwaukee area.

These decreases in margins were partially offset by a $31.3 million increase in margins related to the impact of unprotected excess deferred taxes during the third quarter of 2021, which we agreed to return to customers in our PSCW-approved rate orders. This increase in margins is offset in income taxes. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on our rate order.

Natural Gas Revenues

Natural gas revenues increased $66.2 million during the third quarter of 2022, compared with the same quarter in 2021. Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues. The average per-unit cost of natural gas increased 30% during the third quarter of 2022, compared with the same quarter in 2021. The remaining drivers of changes in natural gas revenues are described in the discussion of natural gas utility margins below.

Natural Gas Utility Margins

Natural gas utility margins at the Wisconsin segment increased $9.5 million during the third quarter of 2022, compared with the same quarter in 2021. The significant factors impacting the higher natural gas utility margins were:

A $7.3 million increase in margins from higher sales volumes, driven by the continued economic recovery in Wisconsin from the COVID-19 pandemic, as well as colder weather during the third quarter of 2022, compared with the same quarter in 2021. As measured by heating degree days, the third quarter of 2022 was 304.5% and 13.2% colder than the same quarter in 2021 in the Milwaukee area and Green Bay area, respectively.
A $2.5 million increase in margins related to the amortization of a certain portion of WG's regulatory liability consisting of credit balances associated with the escrow of natural gas storage service costs from Bluewater Gas Storage, LLC. In September 2021, the PSCW issued a written order for our Wisconsin utilities approving certain accounting treatments to offset certain 2022 revenue deficiencies in order to forego filing for 2022 base rate increases. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for more information.


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

Other operating expenses at the Wisconsin segment decreased $21.0 million during the third quarter of 2022, compared with the same quarter in 2021. The significant factors impacting the decrease in operating expenses were:

A $20.0 million decrease in transmission expense driven by the amortization of a certain portion of WE's and WPS's regulatory liabilities associated with transmission escrow balances, as discussed in the notes under the other operation and maintenance table above.
A $5.4 million decrease in expense driven by the amortization of a certain portion of WPS's regulatory liability associated with its 2020 earnings sharing mechanism, as discussed in the notes under the other operation and maintenance table above.
A $4.8 million decrease in benefit costs, primarily driven by lower stock-based compensation and deferred compensation costs.
A $4.0 million decrease in expense related to 2021 charitable projects supporting our customers and the communities within our service territories.

These decreases in other operating expenses were partially offset by:

A $4.8 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan and an increase related to the We Power leases. These increases were partially offset by $2.6 million of deferred depreciation related to capital investments made by WG since it's last rate case, as approved by the PSCW in an order that allowed our Wisconsin utilities to offset certain 2022 revenue deficiencies in order to forego filing for 2022 base rate increases. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for more information.
A $4.2 million increase in property and revenue taxes, driven by higher gross receipt taxes.
A $3.2 million increase in other operating and maintenance expense related to our power plants, driven by a planned outage at OCPP and reductions in refined coal credits during the third quarter of 2022, compared with the same quarter in 2021.

Other Income, Net

Other income, net at the Wisconsin segment increased $12.3 million during the third quarter of 2022, compared with the same quarter in 2021, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 17, Employee Benefits, for more information on our benefit costs. Higher AFUDC–Equity due to continued capital investment also contributed to the increase in other income, net.

Interest Expense

Interest expense at the Wisconsin segment decreased $0.7 million during the third quarter of 2022, compared with the same quarter in 2021, primarily due to the deferral of interest expense related to capital investments made by WG since its last rate case, as approved by the PSCW in an order that allowed our Wisconsin utilities to offset certain 2022 revenue deficiencies in order to forego filing for 2022 base rate increases. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for more information. Also contributing to the decrease was lower interest expense on finance lease liabilities, primarily related to the We Power leases, as finance lease liabilities decrease each year as payments are made. These decreases were partially offset by long-term debt issuances in the fourth quarter of 2021 and third quarter of 2022, and higher average short-term debt balances along with higher interest rates.

Income Tax Expense

Income tax expense at the Wisconsin segment increased $30.1 million during the third quarter of 2022, compared with the same quarter in 2021. The increase in income tax expense was due to an approximate $31 million negative impact related to the lower quarter-over-quarter amortization of the unprotected excess deferred tax benefits from the Tax Legislation in connection with the Wisconsin rate orders approved by the PSCW, effective January 1, 2020. The impact due to the benefit from the amortization of the


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unprotected excess deferred tax benefits in 2021 from the Tax Legislation did not impact earnings as there was an offsetting impact in operating income. See Note 13, Income Taxes, for more information.

Illinois Segment Contribution to Net Income Attributed to Common Shareholders

The Illinois segment's contribution to net income attributed to common shareholders was $14.9 million during the third quarter of 2022, representing a $4.2 million, or 22.0%, decrease over the same quarter in 2021. The lower earnings were driven by an increase in natural gas distribution and maintenance costs, along with higher depreciation and amortization. These negative impacts were partially offset by higher natural gas margins due to PGL's continued capital investment in the SMP project under its QIP rider.

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)	2022		2021		B (W)
Natural gas revenues	$	230.3	$	216.2	$	14.1
Cost of natural gas sold	27.4		22.4		(5.0)
Total natural gas margins	202.9		193.8		9.1

Other operation and maintenance	100.2		91.2		(9.0)
Depreciation and amortization	57.9		55.4		(2.5)
Property and revenue taxes	8.6		6.5		(2.1)
Operating income	36.2		40.7		(4.5)

Other income, net	2.6		1.9		0.7
Interest expense	18.1		16.5		(1.6)
Income before income taxes	20.7		26.1		(5.4)

Income tax expense	5.8		7.0		1.2
Net income attributed to common shareholders	$	14.9	$	19.1	$	(4.2)

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


	Three Months Ended September 30
(in millions)	2022		2021		B (W)
Operation and maintenance not included in the line items below	$	84.9	$	76.2	$	(8.7)
Riders (1)	16.0		15.5		(0.5)
Regulatory amortizations (1)	(0.7)		(0.5)		0.2

Total other operation and maintenance	$	100.2	$	91.2	$	(9.0)

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

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


	Three Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2022	2021	B (W)
Customer Class
Residential	45.7	42.8	2.9
Commercial and industrial	23.5	24.1	(0.6)
Total retail	69.2	66.9	2.3
Transportation	93.3	87.6	5.7
Total sales in therms	162.5	154.5	8.0


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	Three Months Ended September 30
	Degree Days
Weather (1)	2022	2021	B (W)
Heating (68 Normal)	86	18	377.8	%

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

Natural Gas Revenues

Natural gas revenues increased $14.1 million during the third quarter of 2022, compared with the same quarter in 2021. Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues. The average per-unit cost of natural gas increased 18% during the third quarter of 2022, compared with the same quarter in 2021. The remaining drivers of changes in natural gas revenues are described in the discussion of margins below.

Natural Gas Utility Margins

Natural gas utility margins at the Illinois segment, net of the $0.5 million impact of the riders referenced in the table above, increased $8.6 million during the third quarter of 2022, compared with the same quarter in 2021. The increase in margins was primarily driven by:

A $6.2 million increase in revenues at PGL due to continued capital investment in the SMP project. PGL recovers the costs related to the SMP through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023. See Note 24, Regulatory Environment, for more information.
A $2.4 million increase related to fixed customer charges during the third quarter of 2022, compared with the same quarter in 2021.

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

Other operating expenses at the Illinois segment increased $13.1 million, net of the $0.5 million impact of the riders referenced in the table above, during the third quarter of 2022, compared with the same quarter in 2021. The significant factors impacting the increase in operating expenses were:

A $7.0 million increase in natural gas distribution and maintenance costs.
A $2.5 million increase in depreciation and amortization expense, primarily driven by PGL's continued capital investment in the SMP project.
A $1.9 million increase in customer service expense, primarily driven by higher call volumes.

Interest Expense

Interest expense at the Illinois segment increased $1.6 million during the third quarter of 2022, compared with the same quarter in 2021, primarily due to $225.0 million of long-term debt issuances in November 2021.

Income Tax Expense

Income tax expense at the Illinois segment decreased $1.2 million during the third quarter of 2022, compared with the same quarter in 2021, driven by a decrease in pre-tax income.


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Other States Segment Contribution to Net Income Attributed to Common Shareholders

The other states segment's net loss attributed to common shareholders was $6.1 million during the third quarter of 2022, representing a $3.4 million, or 125.9%, increase in net loss over the same quarter in 2021. The higher net loss was driven by increases in various operating expenses, including expenses related to property and revenue taxes, natural gas operations, and customer service. An increase in interest expense, primarily due to a deferral of interest expense during 2021 that is now being amortized over a four-year period, also contributed to the higher net loss.

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)	2022		2021		B (W)
Natural gas revenues	$	69.2	$	52.8	$	16.4
Cost of natural gas sold	36.6		21.6		(15.0)
Total natural gas margins	32.6		31.2		1.4

Other operation and maintenance	21.0		19.6		(1.4)
Depreciation and amortization	10.3		9.6		(0.7)
Property and revenue taxes	6.7		4.2		(2.5)
Operating loss	(5.4)		(2.2)		(3.2)

Other income, net	0.7		0.1		0.6
Interest expense	3.3		1.6		(1.7)
Loss before income taxes	(8.0)		(3.7)		(4.3)

Income tax benefit	(1.9)		(1.0)		0.9
Net loss attributed to common shareholders	$	(6.1)	$	(2.7)	$	(3.4)

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


	Three Months Ended September 30
(in millions)	2022		2021		B (W)
Operation and maintenance not included in line item below	$	18.3	$	16.3	$	(2.0)
Regulatory amortizations and other pass through expenses (1)	2.7		3.3		0.6

Total other operation and maintenance	$	21.0	$	19.6	$	(1.4)

(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:


	Three Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2022	2021	B (W)
Customer Class
Residential	15.9	16.0	(0.1)
Commercial and industrial	15.1	16.7	(1.6)
Total retail	31.0	32.7	(1.7)
Transportation	164.4	183.6	(19.2)
Total sales in therms	195.4	216.3	(20.9)


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	Three Months Ended September 30
	Degree Days
Weather (1)	2022	2021	B (W)
MERC
Heating (204 Normal)	184	120	53.3	%

MGU
Heating (112 Normal)	112	54	107.4	%

(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.

Natural Gas Revenues

Natural gas revenues increased $16.4 million during the third quarter of 2022, compared with the same quarter in 2021. Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues. The average per-unit cost of natural gas increased 88% during the third quarter of 2022, compared with the same quarter in 2021. See the discussion of natural gas utility margins below for the remaining drivers of changes in natural gas revenues.

Natural Gas Utility Margins

Natural gas utility margins increased $1.4 million during the third quarter of 2022, compared with the same quarter in 2021, primarily driven by a $0.9 million increase related to MERC's GUIC rider. The GUIC rider allows MERC to recover previously approved GUIC incurred to replace or modify natural gas facilities to the extent the work is required by state, federal, or other government agencies and exceeds the costs included in base rates.

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

Other operating expenses at the other states segment increased $4.6 million during the third quarter of 2022, compared with the same quarter in 2021. The significant factors impacting the increase in operating expenses were:

A $2.5 million increase in property and revenue taxes, driven by higher use tax at MGU.
A $1.9 million increase in natural gas operations and customer service expense, primarily driven by various operation and maintenance projects approved in MGU's rate case.

Interest Expense

Interest expense at the other states segment increased $1.7 million during the third quarter of 2022, compared with the same quarter in 2021, primarily due to the deferral of $1.2 million of interest expense in the third quarter of 2021, as approved by the MPSC to mitigate the impacts from delaying the filing of MGU's 2021 rate case. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information. This deferred interest expense is now being amortized over a four-year period as a result of MGU's approved rate increase.


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Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders


	Three Months Ended September 30
(in millions)	2022		2021		B (W)
Equity in earnings of transmission affiliates	$	63.7	$	42.3	$	21.4

Interest expense	4.9		4.8		(0.1)
Income before income taxes	58.8		37.5		21.3

Income tax expense	14.3		9.7		(4.6)
Net income attributed to common shareholders	$	44.5	$	27.8	$	16.7

Equity in Earnings of Transmission Affiliates

Equity in earnings of transmission affiliates increased $21.4 million during the third quarter of 2022, compared with the same quarter in 2021. The increase was primarily due to the impact of the D.C. Circuit Court of Appeals opinion issued in August 2022 addressing complaints related to ATC's ROE. For information on this D.C. Circuit Court of Appeals opinion, see Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – American Transmission Company Allowed Return on Equity Complaints.

Income Tax Expense

Income tax expense at the electric transmission segment increased $4.6 million during the third quarter of 2022, compared with the same quarter in 2021. The increase was primarily due to an increase in pre-tax income.

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


	Three Months Ended September 30
(in millions)	2022		2021		B (W)
Operating income	$	89.1	$	85.4	$	3.7

Interest expense	17.0		17.6		0.6
Income before income taxes	72.1		67.8		4.3

Income tax expense	1.7		5.0		3.3
Net loss attributed to noncontrolling interests	0.6		1.6		(1.0)
Net income attributed to common shareholders	$	71.0	$	64.4	$	6.6

Operating Income

Operating income at the non-utility energy infrastructure segment increased $3.7 million during the third quarter of 2022, compared with the same quarter in 2021. The increase was primarily due to a $2.7 million positive impact from a sharing arrangement with one of our Blooming Grove customers resulting from strong energy prices.

Income Tax Expense

Income tax expense at the non-utility energy infrastructure segment decreased $3.3 million during the third quarter of 2022, compared with the same quarter in 2021. The decrease was primarily due to a $3.9 million increase in PTCs in 2022, driven by the Jayhawk wind park achieving commercial operation in December 2021. This favorable change in income tax expense was partially offset by higher pre-tax earnings during the third quarter of 2022, compared with same quarter in 2021.


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


	Three Months Ended September 30
(in millions)	2022		2021		B (W)
Operating income (loss)	$	0.3	$	(1.9)	$	2.2

Other income, net	3.2		7.0		(3.8)
Interest expense	30.9		24.7		(6.2)

Loss before income taxes	(27.4)		(19.6)		(7.8)

Income tax benefit	(10.2)		(3.5)		6.7
Net loss attributed to common shareholders	$	(17.2)	$	(16.1)	$	(1.1)

Operating Income (Loss)

The corporate and other segment had operating income of $0.3 million during the third quarter of 2022, compared with an operating loss of $1.9 million during the same quarter in 2021. The $2.2 million increase was driven by higher operating income at Wispark, primarily due to a payment on a note receivable that was previously written down due to uncertainty regarding its collectibility.

Other Income, Net

Other income, net at the corporate and other segment decreased $3.8 million during the third quarter of 2022, compared with the same quarter in 2021, driven by a $3.7 million decrease in earnings from our equity method investments in technology and energy-focused investment funds.

Interest Expense

Interest expense at the corporate and other segment increased $6.2 million during the third quarter of 2022, compared with the same quarter in 2021, due to higher average short-term debt balances at the parent company along with higher interest rates.

Income Tax Benefit

The income tax benefit at the corporate and other segment increased $6.7 million during the third quarter of 2022, compared with the same quarter in 2021, driven by a $4.5 million quarter-over-quarter increase in the interim tax benefit recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate. Also contributing to the favorable change in the income tax benefit were a higher pre-tax loss and a $1.4 million increase in excess tax benefits recognized related to stock option exercises during the third quarter of 2022, compared with the same quarter in 2021.


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NINE MONTHS ENDED SEPTEMBER 30, 2022

Consolidated Earnings

The following table compares our consolidated results for the nine months ended September 30, 2022 with the nine months ended September 30, 2021, including favorable or better, "B", and unfavorable or worse, "W", variances:


	Nine Months Ended September 30
(in millions, except per share data)	2022		2021		B (W)
Wisconsin	$	631.4	$	600.3	$	31.1
Illinois	184.7		174.8		9.9
Other states	28.1		24.5		3.6
Electric transmission	101.3		82.8		18.5
Non-utility energy infrastructure	242.8		204.6		38.2
Corporate and other	(32.9)		(10.9)		(22.0)
Net income attributed to common shareholders	$	1,155.4	$	1,076.1	$	79.3

Diluted Earnings Per Share	$	3.65	$	3.40	$	0.25

Earnings increased $79.3 million during the nine months ended September 30, 2022, compared with the same period in 2021. The significant factors impacting the $79.3 million increase in earnings were:

A $38.2 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by an increase in PTCs during 2022, primarily due to the Jayhawk wind park that achieved commercial operation in December 2021, an increase in the PTC rate related to the PTC inflation adjustment issued by the IRS, and higher generation at our other wind parks. In addition, Upstream recognized revenue during 2022 related to market settlements it received from SPP in February 2021. Due to a complaint filed with the FERC, the revenue related to these settlements could not be recognized until the FERC issued an order denying the complaint in the first quarter of 2022. A positive impact from a sharing arrangement with one of our Blooming Grove customers, resulting from strong energy prices, also contributed to the increase in earnings.
A $31.1 million increase in net income attributed to common shareholders at the Wisconsin segment, driven by lower operation and maintenance expense, largely due to the amortization of certain regulatory liabilities to offset a portion of our 2022 forecasted revenue deficiencies. The amortization was approved by the PSCW in order to forego filing for 2022 base rate increases. An increase in natural gas margins related to higher retail sales volumes, as well as higher net credits from the non-service components of our net periodic pension and OPEB costs, also contributed to the increase in earnings. These increases in earnings were partially offset by a decrease in electric margins related to our expected fuel recovery and higher depreciation and amortization.
An $18.5 million increase in net income attributed to common shareholders at the electric transmission segment, primarily due to the impact of the D.C. Circuit Court of Appeals opinion issued in August 2022 addressing complaints related to ATC's ROE.
A $9.9 million increase in net income attributed to common shareholders at the Illinois segment, driven by a gain on the sale of certain real estate in Chicago, as well as higher natural gas margins due to PGL's continued capital investment in the SMP project under its QIP rider and NSG's rate increase, effective September 15, 2021. These positive impacts were partially offset by increases in various operating expenses, including expenses related to natural gas distribution and maintenance, the settlement of legal claims, charitable projects, and depreciation and amortization.

These increases in earnings were partially offset by a $22.0 million increase in net loss attributed to common shareholders at the corporate and other segment, driven by net losses from the investments held in the Integrys rabbi trust during the first nine months of 2022, compared with net gains during the same period in 2021. The gains and losses from the investments held in the rabbi trust partially offset the changes in benefit costs related to deferred compensation, which are included in other operation and maintenance expense in our operating segments. See Note 14, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust. A decrease in earnings from our equity method investments in technology and energy-focused investment funds also contributed to the higher net loss. These negative impacts were partially offset by an increase in certain income tax benefits.


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Expected 2022 Annual Effective Tax Rate

We expect our 2022 annual effective tax rate to be between 18.5% and 19.5%. 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

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance. The following table shows operating income by segment for our utility operations during the nine months ended September 30, 2022 and 2021:


	Nine Months Ended September 30
(in millions)	2022		2021
Wisconsin	$	1,174.1	$	1,072.0
Illinois	296.3		283.8
Other states	45.5		36.7


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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 $631.4 million during the nine months ended September 30, 2022, representing a $31.1 million, or 5.2%, increase over the same period in 2021. The higher earnings were driven by lower operation and maintenance expense, largely due to the amortization of certain regulatory liabilities to offset a portion of our 2022 forecasted revenue deficiencies. The amortization was approved by the PSCW in order to forego filing for 2022 base rate increases. An increase in natural gas margins related to higher retail sales volumes, as well as higher net credits from the non-service components of our net periodic pension and OPEB costs, also contributed to the increase in earnings. These increases in earnings were partially offset by a decrease in electric margins related to our expected fuel recovery and higher depreciation and amortization.


	Nine Months Ended September 30
(in millions)	2022		2021		B (W)
Electric revenues	$	3,858.7	$	3,482.0	$	376.7
Fuel and purchased power	1,485.5		1,133.2		(352.3)
Total electric margins	2,373.2		2,348.8		24.4

Natural gas revenues	1,317.8		1,015.8		302.0
Cost of natural gas sold	850.0		591.6		(258.4)
Total natural gas margins	467.8		424.2		43.6

Total electric and natural gas margins	2,841.0		2,773.0		68.0

Other operation and maintenance	979.6		1,047.1		67.5
Depreciation and amortization	564.0		540.4		(23.6)
Property and revenue taxes	123.3		113.5		(9.8)
Operating income	1,174.1		1,072.0		102.1

Other income, net	75.7		51.8		23.9
Interest expense	409.1		417.8		8.7
Income before income taxes	840.7		706.0		134.7

Income tax expense	208.4		104.8		(103.6)
Preferred stock dividends of subsidiary	0.9		0.9		—
Net income attributed to common shareholders	$	631.4	$	600.3	$	31.1

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


	Nine Months Ended September 30
(in millions)	2022		2021		B (W)
Operation and maintenance not included in line items below	$	483.3	$	472.8	$	(10.5)
Transmission (1)	323.1		383.1		60.0
Regulatory amortizations and other pass through expenses (2)	108.0		104.9		(3.1)
We Power (3)	81.4		86.3		4.9


Earnings sharing mechanisms (4)	(16.2)		—		16.2
Total other operation and maintenance	$	979.6	$	1,047.1	$	67.5

(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, 2022 and 2021, $391.5 million and $378.1 million, respectively, of costs were billed to our electric utilities by transmission providers.

During the nine months ended September 30, 2022, WE and WPS amortized $60.8 million of the regulatory liabilities associated with their transmission escrows to offset certain 2022 revenue deficiencies, as approved by the PSCW in order to forego filing for 2022 base rate increases. This amortization drove the decrease in transmission expense during the nine months ended September 30, 2022, compared with the same period in 2021.


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

(3)Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE. During the nine months ended September 30, 2022 and 2021, $80.6 million and $72.0 million, respectively, of costs were billed to or incurred by WE related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

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


	Nine Months Ended September 30
	MWh (in thousands)
Electric Sales Volumes	2022	2021	B (W)
Customer Class
Residential	8,726.7	8,838.5	(111.8)
Small commercial and industrial (1)	9,793.9	9,699.6	94.3
Large commercial and industrial (1)	9,238.8	9,365.8	(127.0)
Other	98.9	104.9	(6.0)
Total retail (1)	27,858.3	28,008.8	(150.5)
Wholesale	1,942.8	2,181.4	(238.6)
Resale	3,326.7	4,552.5	(1,225.8)
Total sales in MWh (1)	33,127.8	34,742.7	(1,614.9)

(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	2022	2021	B (W)
Customer Class
Residential	810.0	715.0	95.0
Commercial and industrial	515.4	439.0	76.4
Total retail	1,325.4	1,154.0	171.4
Transportation	1,054.8	1,018.9	35.9
Total sales in therms	2,380.2	2,172.9	207.3


	Nine Months Ended September 30
	Degree Days
Weather	2022	2021	B (W)
WE and WG (1)
Heating (4,288 Normal)	4,254	3,880	9.6	%
Cooling (762 Normal)	936	1,018	(8.1)	%

WPS (2)
Heating (4,787 Normal)	4,880	4,450	9.7	%
Cooling (532 Normal)	717	631	13.6	%

UMERC (3)
Heating (5,461 Normal)	5,824	5,115	13.9	%
Cooling (342 Normal)	358	426	(16.0)	%

(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.


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

Electric Revenues

Electric revenues increased $376.7 million during the nine months ended September 30, 2022, compared with the same period in 2021. To the extent that changes in fuel and purchased power costs are passed through to customers, the changes are offset by comparable changes in revenues. See the discussion of electric utility margins below for more information related to the recovery of fuel and purchased power costs and the remaining drivers of the changes in electric revenues.

Electric Utility Margins

Electric utility margins at the Wisconsin segment increased $24.4 million during the nine months ended September 30, 2022, compared with the same period in 2021. The significant factors impacting the higher electric utility margins were:

An $85.4 million increase in margins related to the impact of unprotected excess deferred taxes during the nine months ended September 30, 2021, which we agreed to return to customers in our PSCW-approved rate orders. This increase in margins is offset in income taxes.
A $9.4 million increase in other revenues, primarily related to third-party use of our assets.

These increases in margins were partially offset by:

A $52.8 million decrease in margins related to our expected fuel recovery, driven by higher fuel costs as well as our current fuel forecast and earnings assumptions. Under the Wisconsin fuel rules, the margins of our electric utilities are impacted by under- or over-collections of certain fuel and purchased power costs that are within a 2% price variance from the costs included in rates, and the remaining variance beyond the 2% price variance is generally deferred for future recovery or refund to customers. We will review our actual fuel costs and earnings results at the end of the year and will further adjust our expected fuel recovery accordingly.
Lower margins of $10.7 million driven by the expiration of certain wholesale contracts.
A $7.5 million net decrease in margins related to lower sales volumes, driven by the impact of cooler weather during the nine months ended September 30, 2022, compared with the same period in 2021. As measured by cooling degree days, the nine months ended September 30, 2022 were 8.1% cooler than the same period in 2021 in the Milwaukee area.

Natural Gas Revenues

Natural gas revenues increased $302.0 million during the nine months ended September 30, 2022, compared with the same period in 2021. Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues. The average per-unit cost of natural gas increased 26% during the nine months ended September 30, 2022, compared with the same period in 2021. The remaining drivers of changes in natural gas revenues are described in the discussion of natural gas utility margins below.

Natural Gas Utility Margins

Natural gas utility margins at the Wisconsin segment increased $43.6 million during the nine months ended September 30, 2022, compared with the same period in 2021. The significant factors impacting the higher natural gas utility margins were:

A $37.1 million increase in margins from higher sales volumes, primarily driven by the continued economic recovery in Wisconsin from the COVID-19 pandemic, as well as colder weather during the nine months ended September 30, 2022, compared with the same period in 2021. As measured by heating degree days, the nine months ended September 30, 2022 were 9.6% and 9.7% colder than the same period in 2021 in the Milwaukee area and Green Bay area, respectively.
A $7.4 million increase in margins related to the amortization of a certain portion of WG's regulatory liability consisting of credit balances associated with the escrow of natural gas storage service costs from Bluewater Gas Storage, LLC. In September 2021,


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the PSCW issued a written order for our Wisconsin utilities approving certain accounting treatments to offset certain 2022 revenue deficiencies in order to forego filing for 2022 base rate increases.

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

Other operating expenses at the Wisconsin segment decreased $34.1 million during the nine months ended September 30, 2022, compared with the same period in 2021. The significant factors impacting the decrease in operating expenses were:

A $60.0 million decrease in transmission expense driven by the amortization of a certain portion of WE's and WPS's regulatory liabilities associated with transmission escrow balances, as discussed in the notes under the other operation and maintenance table above.
A $16.2 million decrease in expense driven by the amortization of a certain portion of WPS's regulatory liability associated with its 2020 earnings sharing mechanism, as discussed in the notes under the other operation and maintenance table above.
A $4.9 million decrease in other operation and maintenance expense related to the We Power leases, as discussed in the notes under the other operation and maintenance table above.
A $4.0 million decrease in expense related to 2021 charitable projects supporting our customers and the communities within our service territories.
A $3.1 million decrease in expense related to a gain on land sales during the nine months ended September 30, 2022, compared with the same period in 2021.
A $3.1 million decrease in benefit costs, primarily driven by lower deferred compensation costs.

These decreases in other operating expenses were partially offset by:

A $23.6 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan and an increase related to the We Power leases. These increases were partially offset by $7.7 million of deferred depreciation related to capital investments made by WG since it's last rate case, as approved by the PSCW in an order that allowed our Wisconsin utilities to offset certain 2022 revenue deficiencies in order to forego filing for 2022 base rate increases.
A $21.9 million increase in electric and natural gas distribution expenses, primarily driven by higher costs to maintain system reliability and for storm restoration expense during the nine months ended September 30, 2022, compared with the same period in 2021.
A $9.8 million increase in property and revenue taxes, driven by higher gross receipt taxes.
A $4.5 million increase in other operating and maintenance expense related to our power plants, driven by a planned outage at the Weston power plant and reductions in refined coal credits during the nine months ended September 30, 2022, compared with the same period in 2021.

Other Income, Net

Other income, net at the Wisconsin segment increased $23.9 million during the nine months ended September 30, 2022, compared with the same period in 2021, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs.

Interest Expense

Interest expense at the Wisconsin segment decreased $8.7 million during the nine months ended September 30, 2022, compared with the same period in 2021, primarily due to the deferral of interest expense related to capital investments made by WG since its last rate case, as approved by the PSCW in an order that allowed our Wisconsin utilities to offset certain 2022 revenue deficiencies in order to forego filing for 2022 base rate increases. Also contributing to the decrease was lower interest expense on finance lease


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liabilities, primarily related to the We Power leases, as finance lease liabilities decrease each year as payments are made. These decreases were partially offset by long-term debt issuances in the fourth quarter of 2021, and higher average short-term debt balances along with higher interest rates.

Income Tax Expense

Income tax expense at the Wisconsin segment increased $103.6 million during the nine months ended September 30, 2022, compared with the same period in 2021. The increase was primarily due to an approximate $85 million negative impact related to the lower period-over-period amortization of the unprotected excess deferred tax benefits from the Tax Legislation in connection with the Wisconsin rate orders approved by the PSCW, effective January 1, 2020. The impact due to the benefit from the amortization of the unprotected excess deferred tax benefits in 2021 from the Tax Legislation did not impact earnings as there was an offsetting impact in operating income. Also contributing to the increase was higher pre-tax income in 2022.

Illinois Segment Contribution to Net Income Attributed to Common Shareholders

The Illinois segment's contribution to net income attributed to common shareholders was $184.7 million during the nine months ended September 30, 2022, representing a $9.9 million, or 5.7%, increase over the same period in 2021. The increase was driven by a gain on the sale of certain real estate in Chicago, as well as higher natural gas margins due to PGL's continued capital investment in the SMP project under its QIP rider and NSG's rate increase, effective September 15, 2021. These positive impacts were partially offset by increases in various operating expenses, including expenses related to natural gas distribution and maintenance, the settlement of legal claims, charitable projects, and depreciation and amortization.


	Nine Months Ended September 30
(in millions)	2022		2021		B (W)
Natural gas revenues	$	1,354.8	$	1,195.1	$	159.7
Cost of natural gas sold	564.0		435.0		(129.0)
Total natural gas margins	790.8		760.1		30.7

Other operation and maintenance	292.9		291.3		(1.6)
Depreciation and amortization	172.1		162.1		(10.0)
Property and revenue taxes	29.5		22.9		(6.6)
Operating income	296.3		283.8		12.5

Other income, net	11.3		5.0		6.3
Interest expense	53.8		49.6		(4.2)
Income before income taxes	253.8		239.2		14.6

Income tax expense	69.1		64.4		(4.7)
Net income attributed to common shareholders	$	184.7	$	174.8	$	9.9

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


	Nine Months Ended September 30
(in millions)	2022		2021		B (W)
Operation and maintenance not included in the line items below	$	208.7	$	211.7	$	3.0
Riders (1)	85.9		81.3		(4.6)
Regulatory amortizations (1)	(1.7)		(1.7)		—

Total other operation and maintenance	$	292.9	$	291.3	$	(1.6)

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


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


	Nine Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2022	2021	B (W)
Customer Class
Residential	620.7	572.4	48.3
Commercial and industrial	248.9	226.1	22.8
Total retail	869.6	798.5	71.1
Transportation	585.9	544.1	41.8
Total sales in therms	1,455.5	1,342.6	112.9


	Nine Months Ended September 30
	Degree Days
Weather (1)	2022	2021	B (W)
Heating (3,887 Normal)	4,017	3,673	9.4	%

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

Natural Gas Revenues

Natural gas revenues increased $159.7 million during the nine months ended September 30, 2022, compared with the same period in 2021. Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues. The average per-unit cost of natural gas increased 19% during the nine months ended September 30, 2022, compared with the same period in 2021. The remaining drivers of changes in natural gas revenues are described in the discussion of margins below.

Natural Gas Utility Margins

Natural gas utility margins at the Illinois segment, net of the $4.6 million impact of the riders referenced in the table above, increased $26.1 million during the nine months ended September 30, 2022, compared with the same period in 2021. The increase in margins was primarily driven by:

An $18.7 million increase in revenues at PGL due to continued capital investment in the SMP project. PGL recovers the costs related to the SMP through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023.
A $7.4 million increase related to the impact of the NSG rate order approved by the ICC, effective September 15, 2021, which includes the Variable Income Tax Adjustment Rider in base rates. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on the 2021 rate order.
A $3.5 million increase in the invested capital tax adjustment rider, which did not impact net income as it was offset in property and revenue taxes. The invested capital tax adjustment rider is a mechanism that allows PGL and NSG to recover or refund the difference between the cost of invested capital tax incurred and the amount collected through base rates.

These increases in natural gas utility margins were partially offset by a $3.2 million decrease related to fixed customer charges.

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

Other operating expenses at the Illinois segment increased $13.6 million, net of the $4.6 million impact of the riders referenced in the table above, during the nine months ended September 30, 2022, compared with the same period in 2021. The significant factors impacting the increase in operating expenses were:

An $11.9 million increase in natural gas distribution and maintenance costs.


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An $11.2 million increase in expenses associated with the settlement of legal claims.
A $10.0 million increase in expenses related to charitable projects supporting our customers and the communities within our service territories.
A $10.0 million increase in depreciation and amortization expense, primarily driven by PGL's continued capital investment in the SMP project.
A $7.5 million increase in benefit costs, primarily due to higher pension and stock-based compensation costs.
A $6.6 million increase in property and revenue taxes, primarily driven by an increase in the invested capital tax related to continued capital investment. This increase was offset in natural gas utility margins.
A $5.0 million increase in costs associated with maintenance at the Manlove Gas Storage Field.
A $2.6 million increase in customer service expense, primarily driven by higher call volumes.

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

Other Income, Net

Other income, net at the Illinois segment increased $6.3 million during the nine months ended September 30, 2022, compared with the same period in 2021, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 17, Employee Benefits, for more information on our benefit costs.

Interest Expense

Interest expense at the Illinois segment increased $4.2 million during the nine months ended September 30, 2022, compared with the same period in 2021, primarily due to $225.0 million of long-term debt issuances in November 2021.

Income Tax Expense

Income tax expense at the Illinois segment increased $4.7 million during the nine months ended September 30, 2022, compared with the same period in 2021, driven by an increase in pre-tax income.

Other States Segment Contribution to Net Income Attributed to Common Shareholders

The other states segment's contribution to net income attributed to common shareholders was $28.1 million during the nine months ended September 30, 2022, representing a $3.6 million, or 14.7%, increase over the same period in 2021. The increase was driven by higher natural gas margins due to a rate increase at MGU, effective January 1, 2022, and higher sales volumes during the nine months ended September 30, 2022, compared with the same period in 2021. These positive impacts were partially offset by increases in operating expenses, as well as interest expense, as discussed below.


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


	Nine Months Ended September 30
(in millions)	2022		2021		B (W)
Natural gas revenues	$	410.0	$	358.2	$	51.8
Cost of natural gas sold	249.3		215.7		(33.6)
Total natural gas margins	160.7		142.5		18.2

Other operation and maintenance	68.5		64.0		(4.5)
Depreciation and amortization	30.5		28.2		(2.3)
Property and revenue taxes	16.2		13.6		(2.6)
Operating income	45.5		36.7		8.8

Other income, net	1.8		0.6		1.2
Interest expense	9.8		4.6		(5.2)
Income before income taxes	37.5		32.7		4.8

Income tax expense	9.4		8.2		(1.2)
Net income attributed to common shareholders	$	28.1	$	24.5	$	3.6

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


	Nine Months Ended September 30
(in millions)	2022		2021		B (W)
Operation and maintenance not included in line item below	$	54.6	$	48.9	$	(5.7)
Regulatory amortizations and other pass through expenses (1)	13.9		15.1		1.2

Total other operation and maintenance	$	68.5	$	64.0	$	(4.5)

(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	2022	2021	B (W)
Customer Class
Residential	240.5	208.5	32.0
Commercial and industrial	155.9	127.5	28.4
Total retail	396.4	336.0	60.4
Transportation	590.3	588.6	1.7
Total sales in therms	986.7	924.6	62.1


	Nine Months Ended September 30
	Degree Days
Weather (1)	2022	2021	B (W)
MERC
Heating (5,118 Normal)	5,608	4,816	16.4	%

MGU
Heating (4,046 Normal)	4,142	3,878	6.8	%


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Natural Gas Revenues

Natural gas revenues increased $51.8 million during the nine months ended September 30, 2022, compared with the same period in 2021. Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues. See the discussion of natural gas utility margins below for the remaining drivers of changes in natural gas revenues.

Natural Gas Utility Margins

Natural gas utility margins increased $18.2 million during the nine months ended September 30, 2022, compared with the same period in 2021. The increase in margins was primarily driven by:

A $9.0 million increase related to the new rates at MGU that went into effect in 2022. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on the 2021 rate order.
A $6.0 million increase related to higher sales volumes due to both continued economic recovery and colder weather during the nine months ended September 30, 2022, compared with the same period in 2021.
A $1.4 million increase related to MERC CIP revenue, which was offset in operation and maintenance expense. Rebates and programs are available to residential and commercial customers of MERC through the CIP, which is funded by rate payers using the Conservation Cost Recovery Charge and the Conservation Cost Recovery Adjustment funds that are collected on their monthly billing statements.
A $1.4 million increase related to MERC's GUIC rider.

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

Other operating expenses at the other states segment increased $9.4 million during the nine months ended September 30, 2022, compared with the same period in 2021. The significant factors impacting the increase in operating expenses were:

A $4.2 million increase in natural gas operations and customer service expense, primarily driven by various operation and maintenance projects approved in MGU's rate case.
A $2.6 million increase in property and revenue taxes, driven by higher use tax at MGU.
A $2.3 million increase in depreciation and amortization related to continued capital investment.
A $1.4 million increase in operation and maintenance expense related to MERC's CIP, which has an offsetting increase in margins.

These increases in operating expenses were partially offset by a $2.5 million decrease in bad debt expense.

Other Income, Net

Other income, net at the other states segment increased $1.2 million during the nine months ended September 30, 2022, compared with the same period in 2021, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 17, Employee Benefits, for more information on our benefit costs.

Interest Expense

Interest expense at the other states segment increased $5.2 million during the nine months ended September 30, 2022, compared with the same period in 2021, primarily due to the deferral of $3.7 million of interest expense during the first nine months of 2021, as approved by the MPSC to mitigate the impacts from delaying the filing of MGU's 2021 rate case. This deferred interest expense is now being amortized over a four-year period as a result of MGU's approved rate increase.


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Income Tax Expense

Income tax expense at the other states segment increased $1.2 million during the nine months ended September 30, 2022, compared with the same period in 2021, driven by an increase in pre-tax income.

Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders


	Nine Months Ended September 30
(in millions)	2022		2021		B (W)
Equity in earnings of transmission affiliates	$	148.4	$	126.2	$	22.2

Interest expense	14.6		14.5		(0.1)
Income before income taxes	133.8		111.7		22.1

Income tax expense	32.5		28.9		(3.6)
Net income attributed to common shareholders	$	101.3	$	82.8	$	18.5

Equity in Earnings of Transmission Affiliates

Equity in earnings of transmission affiliates increased $22.2 million during the nine months ended September 30, 2022, compared with the same period in 2021. The increase was primarily due to the impact of the D.C. Circuit Court of Appeals opinion issued in August 2022 addressing complaints related to ATC's ROE. For information on this D.C. Circuit Court of Appeals opinion, see Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – American Transmission Company Allowed Return on Equity Complaints.

Income Tax Expense

Income tax expense at the electric transmission segment increased $3.6 million during the nine months ended September 30, 2022, compared with the same period in 2021, 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)	2022		2021		B (W)
Operating income	$	285.1	$	261.6	$	23.5

Interest expense	51.6		53.5		1.9
Income before income taxes	233.5		208.1		25.4

Income tax expense (benefit)	(10.5)		5.8		16.3
Net (income) loss attributed to noncontrolling interests	(1.2)		2.3		(3.5)
Net income attributed to common shareholders	$	242.8	$	204.6	$	38.2

Operating Income

Operating income at the non-utility energy infrastructure segment increased $23.5 million during the nine months ended September 30, 2022, compared with the same period in 2021. The increase was primarily due to the recognition of $15.2 million in revenue related to our Upstream wind park in the first quarter of 2022 that was associated with market settlements received from SPP in February 2021. These settlements were subject to a FERC complaint, so we were not able to recognize them as revenue until the FERC issued an order denying that complaint in the first quarter of 2022. In addition, there was an $8.8 million positive impact from a sharing arrangement with one of our Blooming Grove customers resulting from strong energy prices.


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Interest Expense

Interest expense at the non-utility energy infrastructure segment decreased $1.9 million during the nine months ended September 30, 2022, compared with the same period in 2021, primarily due to a lower principal balance as a result of the semi-annual principal payments on long-term debt.

Income Tax Expense (Benefit)

At the non-utility energy infrastructure segment, $10.5 million of income tax benefit was recorded during the nine months ended September 30, 2022, compared with $5.8 million of income tax expense recorded during the same period in 2021. The change was primarily due to a $22.4 million increase in PTCs in 2022, driven by the Jayhawk wind park that achieved commercial operation in December 2021, an increase in the PTC rate related to the PTC inflation adjustment issued by the IRS, and higher generation at our other wind parks. This favorable change in the income tax benefit was partially offset by higher pre-tax earnings during the nine months ended September 30, 2022.

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


	Nine Months Ended September 30
(in millions)	2022		2021		B (W)
Operating loss	$	(6.0)	$	(10.4)	$	4.4

Other income, net	6.2		40.7		(34.5)
Interest expense	78.1		73.5		(4.6)

Loss before income taxes	(77.9)		(43.2)		(34.7)

Income tax benefit	(45.0)		(32.3)		12.7
Net loss attributed to common shareholders	$	(32.9)	$	(10.9)	$	(22.0)

Operating Loss

The operating loss at the corporate and other segment decreased $4.4 million during the nine months ended September 30, 2022, compared with the same period in 2021, driven by higher operating income at Wispark, primarily due to a payment on a note receivable that was previously written down due to uncertainty regarding its collectibility. Higher gains on land sales also contributed to the increase in operating income at Wispark.

Other Income, Net

Other income, net at the corporate and other segment decreased $34.5 million during the nine months ended September 30, 2022, compared with the same period in 2021. The decrease was driven by a $16.5 million net loss from the investments held in the Integrys rabbi trust during the first nine months of 2022, compared with a $10.8 million net gain during the same period in 2021. The gains and losses from the investments held in the rabbi trust partially offset the changes in benefit costs related to deferred compensation, which are included in other operation and maintenance expense in our operating segments. See Note 14, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust. An $11.8 million decrease in earnings from our equity method investments in technology and energy-focused investment funds also contributed to the lower other income, net.

Interest Expense

Interest expense at the corporate and other segment increased $4.6 million during the nine months ended September 30, 2022, compared with the same period in 2021, due to higher average short-term debt balances at the parent company and higher interest rates. This increase was partially offset by lower interest rates related to long-term debt obligations that were refinanced during the fourth quarter of 2021 in order to take advantage of lower interest rates.

Income Tax Benefit

The income tax benefit at the corporate and other segment increased $12.7 million during the nine months ended September 30, 2022, compared with the same period in 2021, driven by a higher pre-tax loss. Also contributing to the increase in the income tax


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benefit was a $6.0 million increase in the interim tax benefit recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate and a $5.7 million increase in excess tax benefits recognized related to stock option exercises, during the nine months ended September 30, 2022, compared with the same period in 2021. These increases in income tax benefits were partially offset by $7.5 million of uncertain tax positions primarily recorded in the first quarter of 2021.

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)	2022		2021		Change in 2022 Over 2021
Cash provided by (used in):
Operating activities	$	2,059.5	$	2,006.7	$	52.8
Investing activities	(1,985.9)		(1,688.7)		(297.2)
Financing activities	(45.1)		(281.4)		236.3

Operating Activities

Net cash provided by operating activities increased $52.8 million during the nine months ended September 30, 2022, compared with the same period in 2021, driven by:

A $573.0 million increase in cash from higher overall collections from customers as a result of an increase in natural gas sales volumes during the nine months ended September 30, 2022, compared with the same period in 2021, driven by the continued economic recovery from the COVID-19 pandemic and colder weather. In addition, we continued to recover on the natural gas costs we under-collected from our Illinois and Minnesota customers related to the extreme weather conditions that occurred in February 2021. See Note 24, Regulatory Environment, for more information on the recovery of these natural gas costs.
A $54.7 million increase in cash due to realized gains on derivative instruments during the nine months ended September 30, 2022.

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

A $315.6 million decrease in cash from higher payments for fuel and purchased power at our plants during the nine months ended September 30, 2022, compared with the same period in 2021. Our plants incurred higher fuel costs during the nine months ended September 30, 2022, as a result of an increase in the price of natural gas.
A $198.6 million decrease in cash from higher payments for other operation and maintenance expenses. During the nine months ended September 30, 2022, our payments were higher for reliability and storm restoration, transmission, natural gas distribution and maintenance costs, benefit costs, and natural gas storage maintenance costs.
A $26.9 million decrease in cash related to higher payments for environmental remediation from work completed on former manufactured gas plant sites during the nine months ended September 30, 2022, compared with the same period in 2021.
An $18.5 million decrease in cash related to higher cash paid for income taxes, driven by higher taxable income during the nine months ended September 30, 2022, compared with the same period in 2021.
An $18.4 million decrease in cash related to higher cash paid for property and revenue taxes, driven by higher gross receipt taxes as well as an increase in the Illinois invested capital tax related to continued capital investment during the nine months ended September 30, 2022, compared with the same period in 2021.


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Investing Activities

Net cash used in investing activities increased $297.2 million during the nine months ended September 30, 2022, compared with the same period in 2021, driven by:

The acquisition of a 90% ownership interest in Thunderhead in September 2022 for $362.9 million. See Note 2, Acquisitions, for more information.
A $72.8 million increase in cash paid for capital expenditures during the nine months ended September 30, 2022, compared with the same period in 2021, which is discussed in more detail below.
Capital contributions paid to transmission affiliates of $39.4 million during the nine months ended September 30, 2022. See Note 19, Investment in Transmission Affiliates, for more information. There were no payments to transmission affiliates during the same period in 2021.
An $18.4 million increase in cash paid for ATC's construction costs during the nine months ended September 30, 2022, which will be reimbursed in the future.

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

The acquisition of a 90% ownership interest in Jayhawk in February 2021 for $119.8 million. See Note 2, Acquisitions, for more information.
A $47.4 million increase in proceeds from the sale of assets during the nine months ended September 30, 2022, compared with the same period in 2021, primarily related to the sale of real estate owned by PGL. See Note 3, Disposition, for more information.
Insurance proceeds of $41.6 million received during the nine months ended September 30, 2022 for property damage, primarily related to the PSB water damage claim. See Note 7, Property, Plant, and Equipment, for more information.

Capital Expenditures

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


Reportable Segment (in millions)	2022		2021		Change in 2022 Over 2021
Wisconsin	$	1,189.0	$	1,028.5	$	160.5
Illinois	364.7		387.9		(23.2)
Other states	69.3		64.5		4.8
Non-utility energy infrastructure	63.3		136.7		(73.4)
Corporate and other	14.4		10.3		4.1
Total capital expenditures	$	1,700.7	$	1,627.9	$	72.8

The increase in cash paid for capital expenditures at the Wisconsin segment during the nine months ended September 30, 2022, compared with the same period in 2021, was primarily driven by higher payments for capital expenditures related to Paris and other renewable energy projects, the new natural gas-fired generation being constructed at WPS's existing Weston power plant site, and WG's LNG facility. These increases were partially offset by lower capital expenditures related to upgrades to WE's and WPS's natural gas and electric distribution systems, the restoration of WE's PSB, and WPS's Crane Creek. See Note 7, Property, Plant, and Equipment, for more information on the PSB.

The decrease in cash paid for capital expenditures at the Illinois segment during the nine months ended September 30, 2022, compared with the same period in 2021, was primarily driven by lower capital expenditures related to upgrades at the Manlove Gas Storage Field, partially offset by increased capital expenditures for upgrades to PGL's natural gas distribution system.

The decrease in cash paid for capital expenditures at the non-utility energy infrastructure segment during the nine months ended September 30, 2022, compared with the same period in 2021, was primarily driven by lower capital expenditures related to the construction of Jayhawk, which went into commercial operation in December 2021. See Note 2, Acquisitions, for more information


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about Jayhawk. This decrease in cash paid for capital expenditures was partially offset by an increase in capital expenditures for wastewater treatment system modifications for We Power's ERGS units. See Note 22, Commitments and Contingencies, for more information on the wastewater treatment system modifications.

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

Financing Activities

Net cash used in financing activities decreased $236.3 million during the nine months ended September 30, 2022, compared with the same period in 2021, driven by:

A $381.2 million increase in cash due to higher issuances of long-term debt during the nine months ended September 30, 2022, compared with the same period in 2021.
A $340.0 million increase in cash due to a repayment of a 364-day term loan during the nine months ended September 30, 2021.
A $291.3 million increase in cash due to a decrease in retirements of long-term debt during the nine months ended September 30, 2022, compared with the same period in 2021.
A $26.6 million increase in cash proceeds related to stock options exercised during the nine months ended September 30, 2022, compared with the same period in 2021.

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

A $711.7 million decrease in cash due to $640.2 million of net repayments of commercial paper during the nine months ended September 30, 2022, compared with $71.5 million of net borrowings of commercial paper during the same period in 2021.
A $52.6 million decrease in cash due to an increase in common stock purchased during the nine months ended September 30, 2022, compared with the same period in 2021, to satisfy requirements of our stock-based compensation plans.
A $47.3 million decrease in cash due to higher dividends paid on our common stock during the nine months ended September 30, 2022, compared with the same period in 2021. In January 2022, our Board of Directors increased our quarterly dividend by $0.05 per share (7.4%) effective with the March 2022 dividend payment.

Significant Financing Activities

For more information on our financing activities, see Note 9, Short-Term Debt and Lines of Credit, and Note 10, 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 2021 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 22, Commitments and Contingencies.


(in millions)	2022 (1)		2023		2024
Wisconsin	$	1,910.3	$	2,530.7	$	2,432.8
Illinois	512.7		557.1		659.5
Other states	100.9		111.8		115.0
Non-utility energy infrastructure	481.5		487.0		683.8
Corporate and other	25.3		28.1		17.0
Total	$	3,030.7	$	3,714.7	$	3,908.1

(1)This includes actual capital expenditures incurred through September 30, 2022, as well as estimated capital expenditures for the remainder of the year.

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

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

We have received approval to invest in 100 MW of utility-scale solar within our Wisconsin segment. WE has partnered with an unaffiliated utility to construct a solar project, Badger Hollow II, that will be located in Iowa County, Wisconsin. Once constructed, WE will own 100 MW of this project. WE's share of the cost of this project is estimated to be approximately $151 million. Commercial operation of Badger Hollow II is targeted for the first half of 2023.
WE and WPS, along with an unaffiliated utility, received PSCW approval to acquire and construct Paris, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Kenosha County, Wisconsin and once fully constructed, WE and WPS will collectively own 180 MW of solar generation and 99 MW of battery storage of this project. WE's and WPS's combined share of the cost of this project is estimated to be approximately $390 million, with construction of the solar portion expected to be completed in 2023.
WE and WPS have received approval to accelerate capital investments in two wind parks. The investment is expected to be approximately $154 million to repower major components of Blue Sky Green Field Wind Park and Crane Creek, which are expected to be completed by the end of 2022.
In March 2021, WE and WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire and construct Darien, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Rock and Walworth counties, Wisconsin and once fully constructed, WE and WPS will collectively own 225 MW of solar generation and 68 MW of battery storage of this project. If approved, WE's and WPS's combined share of the cost of this project is estimated to be approximately $400 million, with construction of the solar portion expected to be completed in 2024.
WPS, along with an unaffiliated utility, received PSCW approval to acquire Red Barn, a utility-scale wind-powered electric generating facility. The project will be located in Grant County, Wisconsin and once constructed, WPS will own 82 MW of this project. WPS's share of the cost of this project is estimated to be approximately $160 million, with construction expected to be completed in early 2023.
In April 2021, WE and WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire the Koshkonong Solar-Battery Park, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Dane County, Wisconsin and once fully constructed, WE and WPS will collectively own 270 MW of solar


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generation and 149 MW of battery storage of this project. If approved, WE's and WPS's combined share of the cost of this project is estimated to be approximately $585 million, with construction of the solar portion expected to be completed in 2025.

WE and WPS received PSCW approval to construct 128 MWs of natural gas-fired generation at WPS's existing Weston power plant site in northern Wisconsin. The new facility will consist of seven RICE units. We estimate the cost of this project to be approximately $170 million, with construction expected to be completed in 2023.
In November 2021, WE and WPS signed an asset purchase agreement to acquire Whitewater, a commercially operational 236.5 MW dual-fueled (natural gas and low sulfur fuel oil) combined-cycle electrical generation facility in Whitewater, Wisconsin. In December 2021, WE and WPS filed an application with the PSCW for approval to acquire Whitewater. If approved, the cost of this facility will be approximately $75 million, with the transaction expected to close in early 2023.
In January 2022, WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire a portion of West Riverside's nameplate capacity. WPS is also requesting approval to assign the option to purchase part of West Riverside to WE. If approved, WPS or WE would acquire 100 MW of capacity, in the first of two potential option exercises. West Riverside is a combined-cycle natural gas plant recently completed by an unaffiliated utility in Rock County, Wisconsin. If approved, our share of the cost of this ownership interest is approximately $91 million, with the transaction expected to close in the second quarter of 2023. In addition, WPS could exercise a second option to acquire an additional 100 MW of capacity. If approved, our share of the cost of this ownership interest is approximately $90 million, with the transaction expected to close in 2024.

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

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

PGL is continuing work on the SMP, a project under which PGL is replacing approximately 2,000 miles of Chicago's aging natural gas pipeline infrastructure. PGL currently recovers these costs through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023. PGL's projected average annual investment through 2024 is between $280 million and $300 million.

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

We expect to provide total capital contributions to ATC (not included in the above table) of approximately $181 million from 2022 through 2024. We do not expect to make any contributions to ATC Holdco during that period.

Long-Term Debt

See Note 10, Long-Term Debt, for information regarding the changes in our outstanding long-term debt during the nine months ended September 30, 2022.

Common Stock Dividends

Our current quarterly dividend rate is $0.7275 per share, which equates to an annual dividend of $2.91 per share. For information related to our most recent common stock dividend declared, see Note 8, Common Equity.


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Other Significant Cash Requirements

See Note 22, Commitments and Contingencies, for information regarding our minimum future commitments related to purchase obligations for the procurement of fuel, power, and gas supply, as well as the related storage and transportation. There were no material changes to our other significant commitments outside the ordinary course of business during the nine months ended September 30, 2022.

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 9, Short-Term Debt and Lines of Credit, Note 16, Guarantees, and Note 21, Variable Interest Entities.

Sources of Cash

Liquidity

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

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

The amount, type, and timing of any financings for the remainder of 2022, 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 2021 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, 2022, our current liabilities exceeded our current assets by $598.7 million. We do not expect this to have an impact on our liquidity as we currently believe that our cash and cash equivalents, our available capacity of $1,841.8 million under existing revolving credit facilities, cash generated from ongoing operations, and access to the capital markets are adequate to meet our short-term and long-term cash requirements.

See Note 9, Short-Term Debt and Lines of Credit, for more information about our credit facilities and commercial paper.

Investments in Outside Trusts

We maintain investments in outside trusts to fund the obligation to provide pension and certain OPEB benefits to current and future retirees. These trusts had investments consisting of fixed income and equity securities that are subject to the volatility of the stock market and interest rates. For more information, see Investments in Outside Trusts in Item 7. Management's Discussion and Analysis


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of Financial Condition and Results of Operations – Liquidity and Capital Resources – Sources of Cash in our 2021 Annual Report on Form 10-K.

Capitalization Structure

The following table shows our capitalization structure as of September 30, 2022, as well as an adjusted capitalization structure that we believe is consistent with how a majority of the rating agencies currently view our 2007 Junior Notes:


(in millions)	Actual			Adjusted
Common shareholders' equity	$	11,355.5		$	11,605.5
Preferred stock of subsidiary	30.4			30.4
Long-term debt (including current portion)	15,077.9			14,827.9
Short-term debt	1,259.5			1,259.5
Total capitalization	$	27,723.3		$	27,723.3

Total debt	$	16,337.4		$	16,087.4

Ratio of debt to total capitalization	58.9		%	58.0		%

Included in long-term debt on our balance sheet as of September 30, 2022, is $500.0 million principal amount of the 2007 Junior Notes. The adjusted presentation attributes $250.0 million of the 2007 Junior Notes to common shareholders' equity and $250.0 million to long-term debt.

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

Debt Covenants

Certain of our short-term and long-term debt agreements contain financial covenants that we must satisfy, including debt to capitalization ratios and debt service coverage ratios. At September 30, 2022, we were in compliance with all such covenants related to outstanding short-term and long-term debt. We expect to be in compliance with all such debt covenants for the foreseeable future. See Note 13, Short-Term Debt and Lines of Credit, Note 14, Long-Term Debt, and Note 11, Common Equity, in our 2021 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, 2022. From time to time, we may enter into commodity contracts that could require collateral or a termination payment in the event of a credit rating change to below BBB- at S&P Global Ratings, a division of S&P Global Inc., and/or Baa3 at Moody’s Investors Service, Inc. If WE had a sub-investment grade credit rating at September 30, 2022, it could have been required to post $100 million of additional collateral or other assurances pursuant to the terms of a PPA. We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.

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

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 2021 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.

COVID-19 Pandemic

We have taken steps to mitigate the impact of the global COVID-19 pandemic. However, the extent to which the COVID-19 pandemic could continue to impact our results of operations and liquidity is largely dependent upon the ability of our customers to resume or maintain normal operations. Adverse impacts to us and our subsidiaries from a prolonged COVID-19 pandemic environment could include a decrease in revenues, increased bad debt expense, increases in past due accounts receivable balances, and access to the capital markets at unfavorable terms or rates.

We will continue to monitor COVID-19 pandemic-related developments affecting our workforce, customers, and suppliers and will implement additional actions that we determine to be necessary in order to mitigate any additional impacts. We cannot predict the full extent of the impacts of COVID-19, which will depend on, among other things, its duration through new variants, the rate and the effectiveness of both vaccinations and treatments, future regulatory and governmental actions, and the ability to maintain normal business activity.

Regulatory, Legislative, and Legal Matters

Regulatory Recovery

Our utilities account for their regulated operations in accordance with accounting guidance under the Regulated Operations Topic of the FASB Accounting Standard Codification. Regulated entities are allowed to defer certain costs that would otherwise be charged to expense if the regulated entity believes the recovery of those costs is probable. We record regulatory assets pursuant to generic and/or specific orders issued by our regulators. Recovery of the deferred costs in future rates is subject to the review and approval by those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of the deferred costs, including those referenced below, is not approved by our regulators, the costs would be charged to income in the current period. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities. As of September 30, 2022, our regulatory assets were $3,251.2 million, and our regulatory liabilities were $3,994.9 million.

In January 2014, the ICC approved PGL's use of the QIP rider as a recovery mechanism for costs incurred related to investments in QIP. This rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2022, PGL filed its 2021 reconciliation with the ICC, which, along with the 2020, 2019, 2018, 2017, and 2016 reconciliations, are still pending. As of September 30, 2022, there can be no assurance that all costs incurred under the QIP rider during the open reconciliation years will be deemed recoverable by the ICC.

See Note 24, Regulatory Environment, in this report, and Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for more information regarding recent and pending rate proceedings, orders, and investigations involving our utilities.

Petitions Before PSCW Regarding Third-Party Financed Distributed Energy Resources

In May 2022, two petitions were filed with the PSCW requesting a declaratory ruling that the owner of a third-party financed DER is not a “public utility” as defined under Wisconsin law and, therefore, is not subject to the PSCW’s jurisdiction under any statute or rule regulating public utilities. In July 2022, the PSCW granted the petitions, finding that the specific facts and circumstances merited the opening of a docket to consider whether to grant all or part of the requested declaratory ruling. The PSCW has indicated that it expects to make a decision no later than December 1, 2022.

The parties that filed the petitions provide financing to their customers for installation of DERs (including solar panels and energy storage) on the customer’s property. A DER is connected to the host customer’s utility meter and is used for the customer’s energy needs. It may also be connected to the grid for distribution. At this time we are unable to predict the outcome of these proceedings;


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however, management is currently assessing the potential for any impact to our financial condition or results of operations from a finding in favor of the petitioners.

Climate and Equitable Jobs Act

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

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

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

Uyghur Forced Labor Prevention Act

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

United States Department of Commerce Complaints

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

In February 2022, a California based company filed a petition (AD/CVD) with the DOC seeking to impose new tariffs on solar panels and cells imported from multiple countries, including Malaysia, Vietnam, Thailand, and Cambodia. While the petition is similar to the one rejected by the DOC in November 2021, there are notable differences. The group added Cambodia to the petition and is requesting that the DOC conduct a country-wide inquiry into each of the four countries. In March 2022, the DOC decided to act on the February petition and investigate the claim. A DOC decision is expected by January 2023. If the DOC determines that the petition has merit, it would be able to apply any final tariffs retroactively to November 4, 2021. If imposed, the new tariffs are expected to further disrupt the supply of solar modules to the United States, and could impact the cost and timing of our solar projects.

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


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Infrastructure Investment and Jobs Act

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

Inflation Reduction Act

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

Return on Equity Incentive for Membership in a Transmission Organization

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

American Transmission Company Allowed Return on Equity Complaints

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

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

First Return on Equity Complaint

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


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Orders Issued by the FERC

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

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

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

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

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

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

◦August 2022 Decision – Since several petitions for review were filed with the D.C. Circuit Court of Appeals concerning this ROE complaint, the D.C. Circuit Court of Appeals issued an opinion on August 9, 2022 addressing these petitions. In its August 2022 Decision, the D.C. Circuit Court of Appeals ruled the FERC failed to adequately explain why it reinstated the use of the risk premium model as part of its ROE methodology in its May 2020 Order after previously rejecting the model in its November 2019 Order. Due to this ruling, the D.C. Circuit Court of Appeals vacated the FERC’s previous orders and remanded the issue of determining an appropriate base ROE for MISO transmission owners back to the FERC for additional proceedings. As of September 30, 2022, the FERC had not provided a ruling in response to the August 2022 Decision issued by the D.C. Circuit Court of Appeals.

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

Second Return on Equity Complaint

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


09/30/2022 Form 10-Q			81			WEC Energy Group, Inc.

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Orders Issued by the FERC

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

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

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

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

Environmental Matters

See Note 22, Commitments and Contingencies, for a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change.

Market Risks and Other Significant Risks

We are exposed to market and other significant risks as a result of the nature of our businesses and the environments in which those businesses operate. These risks include, but are not limited to, the inflation and supply chain disruptions described below. In addition, there is continuing uncertainty over the impact that the ongoing conflict between Russia and Ukraine will have on the global economy, supply chains, and fuel prices. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in our 2021 Annual Report on Form 10-K for a discussion of market and other significant risks applicable to us.

Inflation and Supply Chain Disruptions

We continue to monitor the impact of inflation and supply chain disruptions. We monitor the costs of medical plans, fuel, transmission access, construction costs, regulatory and environmental compliance costs, and other costs in order to minimize inflationary effects in future years, to the extent possible, through pricing strategies, productivity improvements, and cost 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 two risk factors below that are disclosed in Part I of our 2021 Annual Report on Form 10-K.

Item 1A. Risk Factors – Risks Related to the Operation of Our Business – Our operations and corporate strategy may be adversely affected by supply chain disruptions and inflation.
Item 1A. Risk Factors – Risks Related to Economic and Market Volatility – Fluctuating commodity prices could negatively impact our electric and natural gas utility operations.

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


09/30/2022 Form 10-Q			82			WEC Energy Group, Inc.

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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 2021 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, 2022. No impairments were recorded as a result of these tests. For all of our reporting units, the fair values calculated in step one of the test were greater than their carrying values. The fair values for the reporting units were calculated using a combination of the income approach and the market approach.

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

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

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

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

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

See Note 18, Goodwill and Intangibles, for more information.

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