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 financial statements and related notes and our 2020 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 commodity prices, 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.

By the end of 2020, we were able to reduce CO2 emissions from our electric generation fleet by more than 50% below 2005 levels. As a result, we announced new goals in May 2021. We committed to a 60% reduction in carbon emissions from our electric generation fleet by 2025 and an 80% reduction 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.

In addition, we are exploring co-firing with natural gas at our ERGS coal-fired units. By the end of 2030, we expect our use of coal will account for less than 5% of the power we supply to our customers, and we believe we will be in a position to eliminate coal as an energy source by 2035.

We have already 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. As part of our ESG Progress Plan, we expect to retire approximately 1,600 MW of additional fossil-fueled generation by 2025, which includes the planned retirements in 2023-2024 of Oak Creek Power Plant Units 5-8 and the jointly-owned Columbia Units 1-2.


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In addition to retiring these older, fossil-fueled plants, we expect to invest approximately $3.5 billion from 2022-2026 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:

1,500 MW of utility-scale solar;
800 MW of battery storage; and
100 MW of wind.

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; and
the planned purchase of 200 MW of capacity in the West Riverside Energy Center — a new, combined-cycle natural gas plant recently completed by Alliant Energy in Wisconsin.

For more details, see Liquidity and Capital Resources – Capital Resources and Requirements – Capital Requirements – Significant Capital Projects.

In addition, we previously received approval from the Public Service Commission of Wisconsin (PSCW) to invest in 300 MW of utility-scale solar within our Wisconsin segment. Wisconsin Public Service Corporation (WPS) has partnered with an unaffiliated utility to construct two solar projects in Wisconsin: Two Creeks Solar Park (Two Creeks), now in service, and Badger Hollow Solar Park I (Badger Hollow I), expected to enter commercial operation in the fourth quarter of 2021. WPS owns 100 MW of Two Creeks and will own 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 that is expected to enter commercial operation in December 2022. Once constructed, WE will own 100 MW of this project.

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 20 Solar Now projects and currently has another four under construction, together totaling more than 27 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. Our initial 2030 goal called for a 30% reduction in methane emissions from a 2011 baseline. Given advancements with renewable natural gas, we set a new target across our natural gas distribution operations to achieve net-zero methane emissions by the end of 2030.

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 constructed approximately 46 miles of natural gas transmission main to increase the quantity and reliability of natural gas service in southeastern Wisconsin. This project, called the Lakeshore Lateral Project, was completed in October 2021.


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WE and Wisconsin Gas LLC (WG) each plan to construct their own liquefied natural gas (LNG) facilities to meet anticipated peak demand. Subject to PSCW approval, commercial operation of the LNG facilities is targeted for the end of 2023.
The Peoples Gas Light and Coke Company continues to work on its Natural Gas System 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.
WPS is in the final year of its System Modernization and Reliability Project, which involves modernizing parts of its electric distribution system, including burying or upgrading lines. WE, WPS, and WG also continue to upgrade their electric and natural gas distribution systems to enhance reliability.

For more details, see Liquidity and Capital Resources – Capital Resources and Requirements – Capital 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 while meeting all applicable legal and regulatory requirements.

Financial Discipline

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

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

Our investment focus remains in our regulated utility and non-utility energy infrastructure businesses, as well as our investment in ATC. In our non-utility energy infrastructure segment, we have acquired or agreed to acquire majority interests in eight wind parks, capable of providing more than 1,550 MW of carbon-free energy in total. These renewable energy assets represent more than $2.3 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 additional information on recent transactions.

We expect total capital expenditures for our regulated utility and non-utility energy infrastructure businesses to be approximately $16.4 billion from 2022 to 2026. In addition, we currently forecast that our share of ATC's projected capital expenditures over the next five years will be $1.3 billion. Specific projects included in the $17.7 billion ESG Progress Plan are discussed in more detail below under Liquidity and Capital Resources – Capital Resources and Requirements – Capital Requirements – Significant Capital Projects.

Exceptional Customer Care

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

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


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Safety

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

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

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

RESULTS OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2021

Consolidated Earnings

The following table compares our consolidated results for the third quarter of 2021 with the third quarter of 2020, including favorable or better, "B", and unfavorable or worse, "W", variances:


	Three Months Ended September 30
(in millions, except per share data)	2021		2020		B (W)
Wisconsin	$	197.5	$	187.6	$	9.9
Illinois	19.1		13.0		6.1
Other states	(2.7)		(3.3)		0.6
Electric transmission	27.8		26.3		1.5
Non-utility energy infrastructure	64.4		62.9		1.5
Corporate and other	(16.1)		(19.7)		3.6
Net income attributed to common shareholders	$	290.0	$	266.8	$	23.2

Diluted earnings per share	$	0.92	$	0.84	$	0.08

Earnings increased $23.2 million during the third quarter of 2021, compared with the same quarter in 2020. The significant factors impacting the $23.2 million increase in earnings were:

A $9.9 million increase in net income attributed to common shareholders at the Wisconsin segment, driven by lower benefit costs and an increase in electric margins due to higher retail sales volumes, including the impact of weather. The positive impact of increased rates from the Wisconsin rate orders approved by the PSCW, which includes the recognition of unprotected excess deferred tax benefits from the Tax Legislation, also drove an increase in earnings. See Note 22, Regulatory Environment, for more information on the Wisconsin rate orders. These positive impacts were partially offset by higher depreciation and amortization during the third quarter of 2021 and the negative quarter-over-quarter impact from collections of fuel and purchased power costs compared with costs approved in rates.
A $6.1 million increase in net income attributed to common shareholders at the Illinois segment, driven by lower benefit costs and higher natural gas margins due to PGL's continued capital investment in the SMP project under its QIP rider. These increases in earnings were partially offset by the impact from the change in unrecognized tax benefits recorded during the third quarter of 2020.
A $3.6 million increase in earnings from the corporate and other segment, driven by the positive quarter-over-quarter impact from charges taken at Wispark during 2020 and lower interest expense. These positive impacts were partially offset by lower net gains from investments held in the Integrys rabbi trust. The investment gains from the rabbi trust offset benefit costs related to deferred compensation, which are included in other operation and maintenance expense in our operating segments. See Note 12, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.


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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 (loss) 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 2021 and 2020:


	Three Months Ended September 30
(in millions)	2021		2020
Wisconsin	$	352.8	$	349.0
Illinois	40.7		24.5
Other states	(2.2)		(2.0)

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).


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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 $197.5 million during the third quarter of 2021, representing a $9.9 million, or 5.3%, increase over the same quarter in 2020. The higher earnings were driven by lower benefit costs and an increase in electric margins due to higher retail sales volumes, including the impact of weather. The positive impact of increased rates from the Wisconsin rate orders approved by the PSCW, which includes the recognition of unprotected excess deferred tax benefits from the Tax Legislation, also drove an increase in earnings. See Note 22, Regulatory Environment, for more information on the Wisconsin rate orders. These positive impacts were partially offset by higher depreciation and amortization during the third quarter of 2021 and the negative quarter-over-quarter impact from collections of fuel and purchased power costs compared with costs approved in rates.


	Three Months Ended September 30
(in millions)	2021		2020		B (W)
Electric revenues	$	1,288.2	$	1,215.4	$	72.8
Fuel and purchased power	437.7		374.0		(63.7)
Total electric margins	850.5		841.4		9.1

Natural gas revenues	170.4		150.9		19.5
Cost of natural gas sold	87.3		67.1		(20.2)
Total natural gas margins	83.1		83.8		(0.7)

Total electric and natural gas margins	933.6		925.2		8.4

Other operation and maintenance	359.1		363.8		4.7
Depreciation and amortization	184.4		169.7		(14.7)
Property and revenue taxes	37.3		42.7		5.4
Operating income	352.8		349.0		3.8

Other income, net	16.5		15.5		1.0
Interest expense	137.9		139.1		1.2
Income before income taxes	231.4		225.4		$	6.0

Income tax expense	33.6		37.5		3.9
Preferred stock dividends of subsidiary	0.3		0.3		—
Net income attributed to common shareholders	$	197.5	$	187.6	$	9.9

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


	Three Months Ended September 30
(in millions)	2021		2020		B (W)
Operation and maintenance not included in line items below	$	169.4	$	170.6	$	1.2
Transmission (1)	127.8		129.4		1.6
Regulatory amortizations and other pass through expenses (2)	34.4		34.5		0.1
We Power (3)	27.5		29.3		1.8

Total other operation and maintenance	$	359.1	$	363.8	$	4.7

(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 three months ended September 30, 2021 and 2020, $122.7 million and $125.0 million, respectively, of costs were billed to our electric utilities by transmission providers.

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


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(3)Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE. During the three months ended September 30, 2021 and 2020, $20.4 million and $24.1 million, respectively, of costs were billed to or incurred by WE related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

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	2021	2020	B (W)
Customer Class
Residential	3,374.1	3,364.4	9.7
Small commercial and industrial (1)	3,527.7	3,409.0	118.7
Large commercial and industrial (1)	3,239.2	3,163.5	75.7
Other	31.3	34.3	(3.0)
Total retail (1)	10,172.3	9,971.2	201.1
Wholesale	744.0	843.6	(99.6)
Resale	1,270.3	1,730.7	(460.4)
Total sales in MWh (1)	12,186.6	12,545.5	(358.9)

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


	Three Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2021	2020	B (W)
Customer Class
Residential	56.6	64.4	(7.8)
Commercial and industrial	52.4	55.3	(2.9)
Total retail	109.0	119.7	(10.7)
Transportation	280.5	264.5	16.0
Total sales in therms	389.5	384.2	5.3


	Three Months Ended September 30
	Degree Days
Weather	2021	2020	B (W)
WE and WG (1)
Heating (104 Normal)	22	103	(78.6)	%
Cooling (581 Normal)	715	708	1.0	%

WPS (2)
Heating (185 Normal)	114	198	(42.4)	%
Cooling (389 Normal)	389	471	(17.4)	%

UMERC (3)
Heating (311 Normal)	232	339	(31.6)	%
Cooling (260 Normal)	270	311	(13.2)	%

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

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

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


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Electric Utility Margins

Electric utility margins at the Wisconsin segment increased $9.1 million during the third quarter of 2021, compared with the same quarter in 2020. The significant factors impacting the higher electric utility margins were:

A $14.8 million increase in margins related to higher retail sales volumes, including the impact of weather. As measured by cooling degree days, the third quarter of 2021 was 1.0% warmer than the same quarter in 2020 in the Milwaukee area. Commercial and industrial retail sales volumes also improved during the third quarter of 2021, compared with the same quarter in 2020, due to the continued economic recovery in Wisconsin from the COVID-19 pandemic.
A $7.5 million increase in margins from other revenues, primarily related to higher revenues from third party use of our assets as well as higher late payment charges during the third quarter of 2021. Our Wisconsin utilities resumed charging late payment charges in late August 2020 after they were suspended by the PSCW beginning March 24, 2020, as a result of the COVID-19 pandemic. See Note 22, Regulatory Environment, for more information.
Securitization revenues of $3.8 million received during the third quarter of 2021 related to an environmental control charge from WE's retail electric distribution customers. We began assessing this charge in June 2021, subsequent to the issuance of the ETBs by WEPCo Environmental Trust in May 2021, in accordance with a November 2020 PSCW financing order. See Note 9, Long-Term Debt, and Note 19, Variable Interest Entities, for more information. These revenues are all offset in depreciation and amortization as well as interest expense.
A $0.6 million net increase in margins related to the impact of the Wisconsin rate orders approved by the PSCW. The positive impact of increased rates from the rate orders was partially offset by a $7.5 million negative impact related to unprotected excess deferred taxes, which we agreed to return to customers over two years and is offset in income taxes. See Note 22, Regulatory Environment, for more information.

These increases in margins were partially offset by:

A $9.8 million quarter-over-quarter negative impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, the margins of our electric utilities are impacted by under- or over-collections of certain fuel and purchased power costs that are within a 2% price variance from the costs included in rates, and the remaining variance beyond the 2% price variance is deferred for future recovery or refund to customers.
Lower margins of $9.7 million driven by a decrease in wholesale customers related to the expiration of certain wholesale contracts.

Natural Gas Utility Margins

Natural gas utility margins at the Wisconsin segment decreased $0.7 million during the third quarter of 2021, compared with the same quarter in 2020. The most significant factor impacting the lower natural gas utility margins was lower retail sales volumes, primarily driven by warmer weather during the third quarter of 2021. As measured by heating degree days, the third quarter of 2021 was 78.6% and 42.4% warmer than the same quarter in 2020 in the Milwaukee area and Green Bay area, respectively.

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

Other operating expenses at the Wisconsin segment increased $4.6 million during the third quarter of 2021, compared with the same quarter in 2020. The significant factors impacting the increase in operating expenses were:

A $14.7 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan, as well as an increase related to the We Power leases. In addition, a portion of the increase is related to securitization amortization, which is offset in revenues.
A $9.9 million increase in electric and natural gas distribution expenses, primarily driven by significant summer storms in 2021.


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A $4.0 million increase in expenses related to charitable projects supporting our customers and the communities within our service territories.

These increases in operating expenses were partially offset by a $23.1 million decrease in benefit costs, primarily due to lower stock-based compensation and deferred compensation costs.

Interest Expense

Interest expense at the Wisconsin segment decreased $1.2 million during the third quarter of 2021, compared with the same quarter in 2020, primarily due to lower interest expense on finance lease liabilities. This decrease was partially offset by interest expense on the ETBs issued by WEPCo Environmental Trust in May 2021, which is offset in revenues. See Note 19, Variable Interest Entities, for more information.

Income Tax Expense

Income tax expense at the Wisconsin segment decreased $3.9 million during the third quarter of 2021, compared with the same quarter in 2020. The decrease in income tax expense was due to an approximate $7 million positive impact related to the 2021 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 from the Tax Legislation did not impact earnings as there was an offsetting negative impact in operating income. Partially offsetting this decrease in income tax expense was an increase in pretax income. See Note 11, 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 $19.1 million during the third quarter of 2021, representing a $6.1 million, or 46.9%, increase over the same quarter in 2020. The increase was driven by lower benefit costs and higher natural gas margins due to PGL's continued capital investment in the SMP project under its QIP rider. These increases in earnings were partially offset by the impact from the change in unrecognized tax benefits recorded during the third quarter of 2020.

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)	2021		2020		B (W)
Natural gas revenues	$	216.2	$	221.9	$	(5.7)
Cost of natural gas sold	22.4		32.3		9.9
Total natural gas margins	193.8		189.6		4.2

Other operation and maintenance	91.2		109.2		18.0
Depreciation and amortization	55.4		49.9		(5.5)
Property and revenue taxes	6.5		6.0		(0.5)
Operating income	40.7		24.5		16.2

Other income, net	1.9		0.1		1.8
Interest expense	16.5		15.6		(0.9)
Income before income taxes	26.1		9.0		17.1

Income tax expense (benefit)	7.0		(4.0)		(11.0)
Net income attributed to common shareholders	$	19.1	$	13.0	$	6.1


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


	Three Months Ended September 30
(in millions)	2021		2020		B (W)
Operation and maintenance not included in the line items below	$	76.2	$	92.6	$	16.4
Riders (1)	15.5		17.2		1.7
Regulatory amortizations (1)	(0.5)		(0.6)		(0.1)

Total other operation and maintenance	$	91.2	$	109.2	$	18.0

(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	2021	2020	B (W)
Customer Class
Residential	42.8	45.9	(3.1)
Commercial and industrial	24.1	23.0	1.1
Total retail	66.9	68.9	(2.0)
Transportation	87.6	86.1	1.5
Total sales in therms	154.5	155.0	(0.5)


	Three Months Ended September 30
	Degree Days
Weather (1)	2021	2020	B (W)
Heating (73 Normal)	18	62	(71.0)	%

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

Natural Gas Utility Margins

Natural gas utility margins at the Illinois segment, net of the $1.7 million impact of the riders referenced in the table above, increased $5.9 million during the third quarter of 2021, compared with the same quarter in 2020. 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.
A $1.6 million increase in late payment charges driven by the reinstatement of late payment charges during 2021 that were suspended by the ICC in 2020 due to the COVID-19 pandemic.

This increase in natural gas utility margins was partially offset by a $3.4 million decrease in fixed charges during the third quarter of 2021, compared with the same quarter in 2020, driven by higher disconnections during the third quarter of 2021, resulting from the expiration of the moratorium on disconnections from 2020 due to a regulatory order from the ICC in response to the COVID-19 pandemic.

See Note 22, Regulatory Environment, 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 Illinois segment decreased $10.3 million, net of the impact of the riders referenced in the table above, during the third quarter of 2021, compared with the same quarter in 2020. The significant factors impacting the decrease in operating expenses were:

A $9.8 million decrease in benefit costs, primarily due to lower pension and stock-based compensation costs.
A $4.7 million decrease in natural gas distribution maintenance costs, primarily due to the timing of performing certain services.

These decreases in operating expenses were partially offset by a $5.5 million increase in depreciation expense, primarily driven by PGL's continued capital investment in the SMP project.

Other Income, Net

Other income, net at the Illinois segment increased $1.8 million during the third quarter of 2021, compared with the same quarter in 2020, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 15, Employee Benefits, for more information on our benefit costs.

Interest Expense

Interest expense at the Illinois segment increased $0.9 million during the third quarter of 2021, compared with the same quarter in 2020, primarily due to the long-term debt issuance of $200.0 million in November 2020.

Income Tax Expense (Benefit)

Income tax expense at the Illinois segment increased $11.0 million as $7.0 million of income tax expense was recorded during the third quarter of 2021, compared with $4.0 million of income tax benefit recorded during the same quarter in 2020. This increase was due to a $6.3 million change in unrecognized tax benefits in 2020 and an increase in pretax income.

Other States Segment Contribution to Net Income Attributed to Common Shareholders

The other states segment's net loss attributed to common shareholders was $2.7 million during the third quarter of 2021, representing a $0.6 million, or 18.2%, decrease in net loss attributed to common shareholders over the same quarter in 2020. The lower net loss was primarily driven by a decrease in interest expense.


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Since the majority of MGU and MERC 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)	2021		2020		B (W)
Natural gas revenues	$	52.8	$	48.3	$	4.5
Cost of natural gas sold	21.6		16.9		(4.7)
Total natural gas margins	31.2		31.4		(0.2)

Other operation and maintenance	19.6		20.4		0.8
Depreciation and amortization	9.6		8.5		(1.1)
Property and revenue taxes	4.2		4.5		0.3
Operating loss	(2.2)		(2.0)		(0.2)

Other income, net	0.1		0.2		(0.1)
Interest expense	1.6		2.7		1.1
Loss before income taxes	(3.7)		(4.5)		0.8

Income tax benefit	(1.0)		(1.2)		(0.2)
Net loss attributed to common shareholders	$	(2.7)	$	(3.3)	$	0.6

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


	Three Months Ended September 30
(in millions)	2021		2020		B (W)
Operation and maintenance not included in line item below	$	16.3	$	16.4	$	0.1
Regulatory amortizations and other pass through expenses (1)	3.3		4.0		0.7

Total other operation and maintenance	$	19.6	$	20.4	$	0.8

(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	2021	2020	B (W)
Customer Class
Residential	16.0	14.7	1.3
Commercial and industrial	16.7	14.5	2.2
Total retail	32.7	29.2	3.5
Transportation	183.6	146.8	36.8
Total sales in therms	216.3	176.0	40.3


	Three Months Ended September 30
	Degree Days
Weather (1)	2021	2020	B (W)
MERC
Heating (206 Normal)	120	243	(50.6)	%

MGU
Heating (113 Normal)	54	131	(58.8)	%

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


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Natural Gas Utility Margins

Natural gas utility margins decreased $0.2 million during the third quarter of 2021, compared to the same quarter in 2020. This was primarily driven by a $1.2 million decrease in margin 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. This decrease was partially offset by a $0.7 million increase related to higher weather normalized volumes.

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

Other operating expenses at the other states segment was flat during the third quarter of 2021, compared to the same quarter in 2020. This includes an increase of $1.1 million in depreciation and amortization related to continued capital investment, offset by a decrease of $0.8 million in operation and maintenance expense, primarily driven by lower benefits expense.

Interest Expense

Interest expense at the other states segment decreased $1.1 million during the third quarter of 2021, compared with the same quarter in 2020, primarily due to the deferral of interest expense related to capital investments made by MGU since its last rate case. See Note 22, Regulatory Environment, for more information.

Income Tax Benefit

Income tax benefit at the other states segment decreased $0.2 million during the third quarter of 2021, compared with the same quarter in 2020, driven by a lower pretax loss.

Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders


	Three Months Ended September 30
(in millions)	2021		2020		B (W)
Net income attributed to common shareholders	$	27.8	$	26.3	$	1.5

Net income attributed to common shareholders at our electric transmission segment increased $1.5 million during the third quarter of 2021, compared with the same quarter in 2020. The increase was driven by a $2.2 million increase in equity earnings from transmission affiliates, primarily due to continued capital investment by ATC.

The increase in equity earnings from transmission affiliates was partially offset by a $0.7 million increase in income tax expense during the third quarter of 2021, compared with the same quarter in 2020, driven by an increase in pretax earnings.

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


	Three Months Ended September 30
(in millions)	2021		2020		B (W)
Net income attributed to common shareholders	$	64.4	$	62.9	$	1.5

Net income attributed to common shareholders at the non-utility energy infrastructure segment increased $1.5 million during the third quarter of 2021, compared with the same quarter in 2020. The significant factor impacting the increase in net income was:

An $8.4 million decrease in income tax expense primarily due to a $6.4 million increase in PTCs generated in the third quarter of 2021, driven by our Blooming Grove and Tatanka Ridge wind parks that achieved commercial operation in December 2020 and January 2021, respectively, and lower pretax earnings.

This increase in earnings was partially offset by:

Higher operating losses of $5.6 million at our Coyote Ridge and Tatanka Ridge wind parks due primarily to transmission outages.


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A $2.6 million increase in interest expense primarily due to WECI Wind Holding I's debt issuance in December 2020.

The majority of earnings from our ownership interests in the wind parks come in the form of the wind PTCs discussed previously.

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


	Three Months Ended September 30
(in millions)	2021		2020		B (W)
Net loss attributed to common shareholders	$	(16.1)	$	(19.7)	$	3.6

The net loss attributed to common shareholders at the corporate and other segment decreased $3.6 million during the third quarter of 2021, compared with the same quarter in 2020. The significant factors impacting the lower net loss were:

A $6.6 million positive impact from operating income at Wispark during the third quarter of 2021, compared with an operating loss during the same quarter in 2020. The change was driven by the positive quarter-over-quarter impact from reductions in the carrying value of certain real estate-related note receivables during 2020 as market and other factors indicated the receivables may not be fully recoverable.
A $5.7 million decrease in interest expense, driven by the issuance of new debt in the second half of 2020 with lower interest rates than the debt retired during 2020. Also contributing to the decrease was lower interest rates on our short-term and variable-rate long-term debt.

These increases in earnings were partially offset by:

A $5.8 million decrease in other income, net, due to lower net gains from the investments held in the Integrys rabbi trust during the third quarter of 2021, compared with the same quarter in 2020. The investment gains from the rabbi trust offset benefit costs related to deferred compensation, which are included in other operation and maintenance expense in our operating segments. See Note 12, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.
A $4.3 million decrease in income tax benefits during the third quarter of 2021, compared with the same quarter in 2020, driven by a lower pretax loss, and a $2.9 million quarter-over-quarter increase in the interim tax expense recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate.

NINE MONTHS ENDED SEPTEMBER 30, 2021

Consolidated Earnings

The following table compares our consolidated results for the nine months ended September 30, 2021 with the nine months ended September 30, 2020, including favorable or better, "B", and unfavorable or worse, "W", variances:


	Nine Months Ended September 30
(in millions, except per share data)	2021		2020		B (W)
Wisconsin	$	600.3	$	564.1	$	36.2
Illinois	174.8		152.4		22.4
Other states	24.5		25.8		(1.3)
Electric transmission	82.8		84.8		(2.0)
Non-utility energy infrastructure	204.6		193.2		11.4
Corporate and other	(10.9)		(59.4)		48.5
Net income attributed to common shareholders	$	1,076.1	$	960.9	$	115.2

Diluted Earnings Per Share	$	3.40	$	3.04	$	0.36


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Earnings increased $115.2 million during the nine months ended September 30, 2021, compared with the same period in 2020. The significant factors impacting the $115.2 million increase in earnings were:

A $48.5 million increase in earnings from the corporate and other segment, driven by lower interest expense, an increase in earnings from our equity method investments in technology and energy-focused investment funds, and the positive period-over-period impact from charges taken at Wispark during 2020. A net increase in certain income tax benefits and higher net gains from investments held in the Integrys rabbi trust also contributed to the increase in earnings.
A $36.2 million increase in net income attributed to common shareholders at the Wisconsin segment, driven by an increase in electric margins due to higher retail sales volumes, including the impact of weather. Lower benefit costs and the positive impact of increased rates from the Wisconsin rate orders approved by the PSCW, which includes the recognition of unprotected excess deferred tax benefits from the Tax Legislation, also drove the increase in earnings. These positive impacts were partially offset by higher depreciation and amortization and an increase in electric and natural gas distribution expenses during the nine months ended September 30, 2021.
A $22.4 million increase in net income attributed to common shareholders at the Illinois segment, driven by higher natural gas margins due to PGL's continued capital investment in the SMP project under its QIP rider and an increase in late payment charges. Lower benefit costs also contributed to the increase in earnings. These positive impacts were partially offset by higher depreciation and amortization during the nine months ended September 30, 2021.
An $11.4 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by an increase in PTCs generated in 2021, primarily due to our Blooming Grove and Tatanka Ridge wind parks that achieved commercial operation in December 2020 and January 2021, respectively. Partially offsetting this increase were higher operating losses at the Coyote Ridge and Tatanka Ridge wind parks, primarily due to transmission outages.

Expected 2021 Annual Effective Tax Rate

We expect our 2021 annual effective tax rate to be between 13.0% and 14.0%, which includes an estimated 6.0% effective tax rate benefit due to the amortization of unprotected excess deferred taxes in connection with the 2019 Wisconsin rate orders. Excluding this estimated effective tax rate benefit, the expected 2021 range would be between 19.0% and 20.0%.

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, 2021 and 2020:


	Nine Months Ended September 30
(in millions)	2021		2020
Wisconsin	$	1,072.0	$	1,053.4
Illinois	283.8		245.6
Other states	36.7		41.4


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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 $600.3 million during the nine months ended September 30, 2021, representing a $36.2 million, or 6.4%, increase over the same period in 2020. The higher earnings were driven by an increase in electric margins due to higher retail sales volumes, including the impact of weather. Lower benefit costs and the positive impact of increased rates from the Wisconsin rate orders approved by the PSCW, which includes the recognition of unprotected excess deferred tax benefits from the Tax Legislation, also drove the increase in earnings. These positive impacts were partially offset by higher depreciation and amortization and an increase in electric and natural gas distribution expenses during the nine months ended September 30, 2021.


	Nine Months Ended September 30
(in millions)	2021		2020		B (W)
Electric revenues	$	3,482.0	$	3,251.9	$	230.1
Fuel and purchased power	1,133.2		957.2		(176.0)
Total electric margins	2,348.8		2,294.7		54.1

Natural gas revenues	1,015.8		819.5		196.3
Cost of natural gas sold	591.6		395.2		(196.4)
Total natural gas margins	424.2		424.3		(0.1)

Total electric and natural gas margins	2,773.0		2,719.0		54.0

Other operation and maintenance	1,047.1		1,044.0		(3.1)
Depreciation and amortization	540.4		502.7		(37.7)
Property and revenue taxes	113.5		118.9		5.4
Operating income	1,072.0		1,053.4		18.6

Other income, net	51.8		44.3		7.5
Interest expense	417.8		422.2		4.4
Income before income taxes	706.0		675.5		30.5

Income tax expense	104.8		110.5		5.7
Preferred stock dividends of subsidiary	0.9		0.9		—
Net income attributed to common shareholders	$	600.3	$	564.1	$	36.2

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


	Nine Months Ended September 30
(in millions)	2021		2020		B (W)
Operation and maintenance not included in line items below	$	472.8	$	462.5	$	(10.3)
Transmission (1)	383.1		388.2		5.1
Regulatory amortizations and other pass through expenses (2)	104.9		103.8		(1.1)
We Power (3)	86.3		89.5		3.2



Total other operation and maintenance	$	1,047.1	$	1,044.0	$	(3.1)

(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, 2021 and 2020, $378.1 million and $359.7 million, respectively, of costs were billed to our electric utilities by transmission providers.


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

(3)Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE. During the nine months ended September 30, 2021 and 2020, $72.0 million and $84.7 million, respectively, of costs were billed to or incurred by WE related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

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	2021	2020	B (W)
Customer Class
Residential	8,838.5	8,782.2	56.3
Small commercial and industrial (1)	9,699.6	9,299.0	400.6
Large commercial and industrial (1)	9,365.8	8,734.3	631.5
Other	104.9	113.0	(8.1)
Total retail (1)	28,008.8	26,928.5	1,080.3
Wholesale	2,181.4	2,311.4	(130.0)
Resale	4,552.5	5,152.6	(600.1)
Total sales in MWh (1)	34,742.7	34,392.5	350.2

(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	2021	2020	B (W)
Customer Class
Residential	715.0	734.2	(19.2)
Commercial and industrial	439.0	445.9	(6.9)
Total retail	1,154.0	1,180.1	(26.1)
Transportation	1,018.9	979.9	39.0
Total sales in therms	2,172.9	2,160.0	12.9


	Nine Months Ended September 30
	Degree Days
Weather	2021	2020	B (W)
WE and WG (1)
Heating (4,313 Normal)	3,880	4,023	(3.6)	%
Cooling (745 Normal)	1,018	931	9.3	%

WPS (2)
Heating (4,808 Normal)	4,450	4,644	(4.2)	%
Cooling (526 Normal)	631	656	(3.8)	%

UMERC (3)
Heating (5,475 Normal)	5,115	5,337	(4.2)	%
Cooling (340 Normal)	426	425	0.2	%

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

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

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


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Electric Utility Margins

Electric utility margins at the Wisconsin segment increased $54.1 million during the nine months ended September 30, 2021, compared with the same period in 2020. The significant factors impacting the higher electric utility margins were:

A $55.8 million increase in margins related to higher sales volumes, including the impact of weather. As measured by cooling degree days, the nine months ended September 30, 2021 were 9.3% warmer than the same period in 2020 in the Milwaukee area. Commercial and industrial retail sales volumes also improved during the nine months ended September 30, 2021, compared with the same period in 2020, due to the continued economic recovery in Wisconsin from the COVID-19 pandemic.
A $13.3 million increase in margins from other revenues, primarily related to higher late payment charges as well as higher revenues from third party use of our assets during the nine months ended September 30, 2021. Our Wisconsin utilities resumed charging late payment charges in late August 2020 after they were suspended by the PSCW beginning March 24, 2020, as a result of the COVID-19 pandemic. See Note 22, Regulatory Environment, for more information.
Securitization revenues of $4.7 million received during the nine months ended September 30, 2021 related to an environmental control charge from WE's retail electric distribution customers. We began assessing this charge in June 2021, subsequent to the issuance of the ETBs by WEPCo Environmental Trust in May 2021, in accordance with a November 2020 PSCW financing order. See Note 9, Long-Term Debt, and Note 19, Variable Interest Entities, for more information. These revenues are all offset in depreciation and amortization as well as interest expense.

These increases in margins were partially offset by:

Lower margins of $11.7 million driven by a decrease in wholesale customers related to the expiration of certain wholesale contracts.
An $8.6 million period-over-period negative impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, the margins of our electric utilities are impacted by under- or over-collections of certain fuel and purchased power costs that are within a 2% price variance from the costs included in rates, and the remaining variance beyond the 2% price variance is deferred for future recovery or refund to customers.
A $1.8 million net decrease in margins related to the impact of the Wisconsin rate orders approved by the PSCW. The positive impact of increased rates from the rate orders was more than offset by a $22.9 million negative impact related to unprotected excess deferred taxes, which we agreed to return to customers over two years and is offset in income taxes. See Note 22, Regulatory Environment, for more information.

Natural Gas Utility Margins

Natural gas utility margins at the Wisconsin segment decreased $0.1 million during the nine months ended September 30, 2021, compared with the same period in 2020, driven by a $2.8 million negative impact from lower retail sales volumes. This decrease in margins was partially offset by a $2.5 million increase from other revenues, primarily related to higher late payment charges during the nine months ended September 30, 2021, as discussed above under Electric Utility Margins.

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

Other operating expenses at the Wisconsin segment increased $35.4 million during the nine months ended September 30, 2021, compared with the same period in 2020. The significant factors impacting the increase in operating expenses were:

A $37.7 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan, as well as an increase related to the We Power leases. In addition, a portion of the increase is related to securitization amortization, which is offset in revenues.
A $13.3 million increase in electric and natural gas distribution expenses, primarily driven by significant summer storms in 2021.


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An $8.3 million increase in customer service expenses, primarily related to additional costs from an information technology project created to improve the billing, call center, and credit collection functions, as well as higher call volumes and metering costs.
A $4.0 million increase in expenses related to charitable projects supporting our customers and the communities within our service territories.
A $3.7 million increase in property and liability insurance premiums.

These increases in operating expenses were partially offset by:

A $26.0 million decrease in benefit costs, primarily due to lower stock-based compensation.
A $5.1 million decrease in transmission expense as approved in the PSCW's 2019 rate orders, which were effective January 1, 2020. See the notes under the other operation and maintenance table above for more information.

Other Income, Net

Other income, net at the Wisconsin segment increased $7.5 million during the nine months ended September 30, 2021, compared with the same period in 2020, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 15, Employee Benefits, for more information on our benefit costs.

Interest Expense

Interest expense at the Wisconsin segment decreased $4.4 million during the nine months ended September 30, 2021, compared with the same period in 2020, primarily due to lower interest expense on finance lease liabilities and lower interest rates on short-term debt. These decreases in interest expense were partially offset by the interest expense on the ETBs issued by WEPCo Environmental Trust in May 2021, which is offset in revenues.

Income Tax Expense

Income tax expense at the Wisconsin segment decreased $5.7 million during the nine months ended September 30, 2021, compared with the same period in 2020. The decrease was primarily due to an approximate $20 million positive impact related to the 2021 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 from the Tax Legislation did not impact earnings as there was an offsetting negative impact in operating income. Partially offsetting this decrease in income tax expense was an increase in pretax income and a decrease in PTCs.

Illinois Segment Contribution to Net Income Attributed to Common Shareholders

The Illinois segment's contribution to net income attributed to common shareholders was $174.8 million during the nine months ended September 30, 2021, representing a $22.4 million, or 14.7%, increase over the same period in 2020. The increase was driven by higher natural gas margins due to PGL's continued capital investment in the SMP project under its QIP rider and an increase in late payment charges. Lower benefit costs also contributed to the increase in earnings. These positive impacts were partially offset by higher depreciation and amortization during the nine months ended September 30, 2021.


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	Nine Months Ended September 30
(in millions)	2021		2020		B (W)
Natural gas revenues	$	1,195.1	$	930.7	$	264.4
Cost of natural gas sold	435.0		212.2		(222.8)
Total natural gas margins	760.1		718.5		41.6

Other operation and maintenance	291.3		306.5		15.2
Depreciation and amortization	162.1		146.0		(16.1)
Property and revenue taxes	22.9		20.4		(2.5)
Operating income	283.8		245.6		38.2

Other income, net	5.0		2.2		2.8
Interest expense	49.6		47.7		(1.9)
Income before income taxes	239.2		200.1		39.1

Income tax expense	64.4		47.7		(16.7)
Net income attributed to common shareholders	$	174.8	$	152.4	$	22.4

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


	Nine Months Ended September 30
(in millions)	2021		2020		B (W)
Operation and maintenance not included in the line items below	$	211.7	$	237.2	$	25.5
Riders (1)	81.3		71.3		(10.0)
Regulatory amortizations (1)	(1.7)		(2.0)		(0.3)

Total other operation and maintenance	$	291.3	$	306.5	$	15.2

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

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


	Nine Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2021	2020	B (W)
Customer Class
Residential	572.4	566.8	5.6
Commercial and industrial	226.1	227.5	(1.4)
Total retail	798.5	794.3	4.2
Transport	544.1	552.0	(7.9)
Total sales in therms	1,342.6	1,346.3	(3.7)


	Nine Months Ended September 30
	Degree Days
Weather (1)	2021	2020	B (W)
Heating (3,928 Normal)	3,673	3,627	1.3	%

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


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Natural Gas Utility Margins

Natural gas utility margins at the Illinois segment, net of the $10.0 million impact of the riders referenced in the table above, increased $31.6 million during the nine months ended September 30, 2021, compared with the same period in 2020. The increase in margins was primarily driven by:

A $19.1 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 $7.9 million increase in late payment charges driven by the reinstatement of late payment charges during 2021 that were suspended by the ICC in 2020 due to the COVID-19 pandemic.
A $2.5 million increase in the invested capital tax adjustment rider, which did not impact net income as it was offset in property and revenue taxes.

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

Other operating expenses at the Illinois segment decreased $6.6 million, net of the impact of the riders referenced in the table above, during the nine months ended September 30, 2021, compared with the same period in 2020. The significant factors impacting the decrease in operating expenses were:

An $18.8 million decrease in benefit costs, primarily due to lower pension and stock-based compensation costs.
A $5.4 million decrease in costs associated with the investigation and remediation of the natural gas leak at the Manlove Gas Storage Field. See Part II, Other Information, Item 1. Legal Proceedings, for more information.

These decreases in operating expenses were partially offset by:

A $16.1 million increase in depreciation expense, primarily driven by PGL's continued capital investment in the SMP project.
A $2.5 million increase in property and revenue taxes driven by an increase in the invested capital tax related to higher plant placed in service during the nine months ended September 30, 2021, compared with the same period in 2020. This increase was offset in natural gas utility margins.

Other Income, Net

Other income, net at the Illinois segment increased $2.8 million during the nine months ended September 30, 2021, compared with the same period in 2020, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs.

Interest Expense

Interest expense at the Illinois segment increased $1.9 million during the nine months ended September 30, 2021, compared with the same period in 2020, primarily due to the long-term debt issuance of $200.0 million in November 2020.

Income Tax Expense

Income tax expense at the Illinois segment increased $16.7 million during the nine months ended September 30, 2021, compared with the same period in 2020, driven by an increase in pretax income and a $6.3 million change in unrecognized tax benefits during 2020.


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Other States Segment Contribution to Net Income Attributed to Common Shareholders

The other states segment's contribution to net income attributed to common shareholders was $24.5 million during the nine months ended September 30, 2021, representing a $1.3 million, or 5.0%, decrease over the same period in 2020. The decrease was driven by higher operating expenses, including increases in depreciation and amortization and customer service expense. These increases were partially offset by decreases in interest expense and benefit costs.

Since the majority of MGU and MERC 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)	2021		2020		B (W)
Natural gas revenues	$	358.2	$	261.4	$	96.8
Cost of natural gas sold	215.7		119.9		(95.8)
Total natural gas margins	142.5		141.5		1.0

Other operation and maintenance	64.0		62.5		(1.5)
Depreciation and amortization	28.2		24.6		(3.6)
Property and revenue taxes	13.6		13.0		(0.6)
Operating income	36.7		41.4		(4.7)

Other income, net	0.6		0.5		0.1
Interest expense	4.6		7.4		2.8
Income before income taxes	32.7		34.5		(1.8)

Income tax expense	8.2		8.7		0.5
Net income attributed to common shareholders	$	24.5	$	25.8	$	(1.3)

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


	Nine Months Ended September 30
(in millions)	2021		2020		B (W)
Operation and maintenance not included in line item below	$	48.9	$	49.9	$	1.0
Regulatory amortizations and other pass through expenses (1)	15.1		12.6		(2.5)

Total other operation and maintenance	$	64.0	$	62.5	$	(1.5)

(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 sales volumes by customer class and weather statistics:


	Nine Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2021	2020	B (W)
Customer Class
Residential	208.5	210.1	(1.6)
Commercial and industrial	127.5	131.6	(4.1)
Total retail	336.0	341.7	(5.7)
Transportation	588.6	529.4	59.2
Total sales in therms	924.6	871.1	53.5


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	Nine Months Ended September 30
	Degree Days
Weather (1)	2021	2020	B (W)
MERC
Heating (5,087 Normal)	4,816	5,029	(4.2)	%

MGU
Heating (4,053 Normal)	3,878	3,897	(0.5)	%

Natural Gas Utility Margins

Natural gas utility margins increased $1.0 million during the nine months ended September 30, 2021, compared with the same period in 2020. This was driven by a $2.3 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. This increase was partially offset by a $0.6 million decrease in revenues due to lower weather normalized sales volumes and lower late payment charges.

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

Other operating expenses at the other states segment increased $5.7 million during the nine months ended September 30, 2021, compared with the same period in 2020, driven by a $3.6 million increase in depreciation and amortization related to continued capital investment. Other operation and maintenance expense also increased $1.5 million, primarily related to MERC's CIP program, which has an offsetting increase in margins. In addition, customer service expense and bad debt expense increased during the first nine months of 2021, partially offset by a decrease in operating expenses due to effective cost control.

Interest Expense

Interest expense at the other states segment decreased $2.8 million during the nine months ended September 30, 2021, compared with the same period in 2020, primarily due to the deferral of interest expense related to capital investments made by MGU since its last rate case. The decrease was partially offset by MERC and MGU's long-term debt issuances in April 2020 of $50.0 million and $60.0 million, respectively. This increase in debt balances was primarily related to continued capital investments.

Income Tax Expense

Income tax expense at the other states segment decreased $0.5 million during the nine months ended September 30, 2021, compared with the same period in 2020, driven by a decrease in pretax income.

Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders


	Nine Months Ended September 30
(in millions)	2021		2020		B (W)
Net income attributed to common shareholders	$	82.8	$	84.8	$	(2.0)

Net income attributed to common shareholders at our electric transmission segment decreased $2.0 million during the nine months ended September 30, 2021, compared with the same period in 2020. The decrease was driven by a $6.6 million decrease in equity earnings from transmission affiliates, primarily due to the impact of the FERC order issued in May 2020 addressing complaints related to ATC's ROE. The order resulted in an increase in the base ROE that ATC is allowed to collect, retroactive to November 2013, and increased our equity earnings from ATC by $14.6 million during the nine months ended September 30, 2020. For further discussion of the FERC order, see Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American


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Transmission Company Allowed Return on Equity Complaints. Continued capital investment by ATC partially offset the negative period-over-period impact from the FERC order.

The decrease in equity earnings from transmission affiliates was partially offset by a $4.5 million decrease in income tax expense during the nine months ended September 30, 2021, compared with the same period in 2020, driven by $3.3 million of uncertain tax positions recorded in the second quarter of 2020, and a decrease in pretax earnings.

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


	Nine Months Ended September 30
(in millions)	2021		2020		B (W)
Net income attributed to common shareholders	$	204.6	$	193.2	$	11.4

Net income attributed to common shareholders at the non-utility energy infrastructure segment increased $11.4 million during the nine months ended September 30, 2021, compared with the same period in 2020. The significant factors impacting the increase in net income was:

A $30.0 million decrease in income tax expense primarily due to a $24.3 million increase in PTCs generated in 2021, driven by our Blooming Grove and Tatanka Ridge wind parks that achieved commercial operation in December 2020 and January 2021, respectively, and lower pretax earnings.

This increase in earnings was partially offset by:

Higher operating losses of $14.5 million at our Coyote Ridge and Tatanka Ridge wind parks due primarily to transmission outages.
An $8.1 million increase in interest expense primarily due to WECI Wind Holding I's debt issuance in December 2020.

The majority of earnings from our ownership interests in the wind parks come in the form of the wind PTCs discussed previously.

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


	Nine Months Ended September 30
(in millions)	2021		2020		B (W)
Net loss attributed to common shareholders	$	(10.9)	$	(59.4)	$	48.5

The net loss attributed to common shareholders at the corporate and other segment decreased $48.5 million during the nine months ended September 30, 2021, compared with the same period in 2020. The significant factors impacting the lower net loss were:

A $27.4 million increase in other income, net, driven by an $18.1 million increase in earnings from our equity method investments in technology and energy-focused investment funds and $6.4 million of higher net gains from the investments held in the Integrys rabbi trust.
A $24.6 million decrease in interest expense, driven by the issuance of new debt in the second half of 2020 with lower interest rates than the debt retired during 2020. Also contributing to the decrease was lower interest rates on our short-term and variable-rate long-term debt.
A $9.6 million positive impact from operating income at Wispark during the nine months ended September 30, 2021, compared with an operating loss during the same period in 2020. The change was driven by the positive period-over-period impact from reductions in the carrying value of certain real estate-related note receivables during 2020 as market and other factors indicated these receivables may not be fully recoverable. Higher gains on the sale of land during the nine months ended September 30, 2021 also contributed to the increase in operating income.

These drivers of the lower net loss were partially offset by a $13.1 million decrease in income tax benefits during the nine months ended September 30, 2021, compared with the same period in 2020, driven by a lower pretax loss and a $5.7 million decrease in excess tax benefits recognized related to stock option exercises. These decreases in income tax benefits were partially offset by a


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$7.6 million decrease in uncertain tax positions and a $3.3 million increase in the interim tax benefit recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate, during the nine months ended September 30, 2021, compared with the same period in 2020.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

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


(in millions)	2021		2020		Change in 2021 Over 2020
Cash provided by (used in):
Operating activities	$	2,006.7	$	1,949.7	$	57.0
Investing activities	(1,688.7)		(1,563.1)		(125.6)
Financing activities	(281.4)		(407.7)		126.3

Operating Activities

Net cash provided by operating activities increased $57.0 million during the nine months ended September 30, 2021, compared with the same period in 2020, driven by:

A $233.9 million increase in cash due to higher collateral received from counterparties, driven by an increase in the fair value of our natural gas derivative assets during the nine months ended September 30, 2021, compared with the same period in 2020.
A $24.1 million increase in cash related to higher overall collections from customers as a result of an increase in sales volumes during the nine months ended September 30, 2021, compared with the same period in 2020. This increase was driven by favorable weather and continued economic recovery in Wisconsin from the COVID-19 pandemic. In addition, we continued to recover natural gas costs from our customers related to the extreme weather conditions that occurred in February 2021 in accordance with various orders from our commissions. We expect to recover the majority of these increased gas costs by the end of 2021 through our existing recovery mechanisms. See Note 22, Regulatory Environment, for more information on the recovery of these natural gas costs.
A $21.5 million increase in cash due to lower cash paid for interest during the nine months ended September 30, 2021, compared with the same period in 2020, driven by the issuance of new debt with lower interest rates than the debt that was retired, as well as lower interest rates on our short-term and variable-rate long-term debt.

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

A $158.0 million decrease in cash due to higher payments for fuel and purchased power at our plants during the nine months ended September 30, 2021, compared with the same period in 2020. Natural gas costs increased significantly throughout the central part of the country in February 2021 related to extreme weather conditions. In addition to costs related to the extreme weather conditions in February 2021, we incurred higher natural gas costs throughout the nine months ended September 30, 2021, compared with the same period in 2020 as a result of an increase in the price of natural gas. Higher coal costs also drove higher payments for fuel used at our plants.
A $67.8 million decrease in cash from higher payments for operating and maintenance expenses. During the nine months ended September 30, 2021, our payments were higher for transmission, storm restoration, and customer service.

Investing Activities

Net cash used in investing activities increased $125.6 million during the nine months ended September 30, 2021, compared with the same period in 2020, driven by:

The acquisition of a 90% ownership interest in Jayhawk in February 2021 for $119.8 million. See Note 2, Acquisitions, for more information.


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Insurance proceeds received of $22.2 million for property damage during the nine months ended September 30, 2020. See Note 6, Property, Plant, and Equipment, for more information.
A $9.2 million increase in cash paid for capital expenditures during the nine months ended September 30, 2021, compared with the same period in 2020, which is discussed in more detail below.

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

Capital contributions paid to transmission affiliates of $15.2 million during the nine months ended September 30, 2020. See Note 17, Investment in Transmission Affiliates, for more information. There were no payments to transmission affiliates during the nine months ended September 30, 2021.
An $11.8 million increase in proceeds received from the sale of assets during the nine months ended September 30, 2021, compared with the same period in 2020.

Capital Expenditures

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


Reportable Segment (in millions)	2021		2020		Change in 2021 Over 2020
Wisconsin	$	1,028.5	$	992.7	$	35.8
Illinois	387.9		494.7		(106.8)
Other states	64.5		104.7		(40.2)
Non-utility energy infrastructure	136.7		12.7		124.0
Corporate and other	10.3		13.9		(3.6)
Total capital expenditures	$	1,627.9	$	1,618.7	$	9.2

The increase in cash paid for capital expenditures at the Wisconsin segment during the nine months ended September 30, 2021, compared with the same period in 2020, was primarily driven by higher capital expenditures related to upgrades to WE's natural gas distribution system, repairs and restoration of WE's PSB driven by the significant rain event, and WPS's Crane Creek during the nine months ended September 30, 2021. See Note 6, Property, Plant, and Equipment, for more information on the PSB. These increases were partially offset by lower payments for capital expenditures related to Two Creeks, Badger Hollow I, an information technology project created to improve the billing, call center, and credit collection functions, upgrades to WG's gas distribution system, and upgrades of WPS's automated meter reading devices during the nine months ended September 30, 2021.

The decrease in cash paid for capital expenditures at the Illinois segment during the nine months ended September 30, 2021, compared with the same period in 2020, was primarily driven by lower capital expenditures related to facilities projects, upgrades at the Manlove Gas Storage Field, and upgrades to the natural gas distribution system during the nine months ended September 30, 2021.

The decrease in cash paid for capital expenditures at the other states segment during the nine months ended September 30, 2021, compared with the same period in 2020, was primarily driven by a decrease in installations of automated meter reading devices during the nine months ended September 30, 2021.

The increase in cash paid for capital expenditures at the non-utility energy infrastructure segment during the nine months ended September 30, 2021, compared with the same period in 2020, was primarily driven by the construction of Jayhawk. See Note 2, Acquisitions, for more information about Jayhawk.

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


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Financing Activities

Net cash used in financing activities decreased $126.3 million during the nine months ended September 30, 2021, compared with the same period in 2020, driven by:

A $471.3 million increase in cash due to $71.5 million of net borrowings of commercial paper during the nine months ended September 30, 2021, compared with $399.8 million of net repayments of commercial paper during the same period in 2020.
A $208.8 million increase in cash due to higher issuances of long-term debt during the nine months ended September 30, 2021, compared with the same period in 2020.
A $126.4 million increase in cash due to lower repayments of long-term debt during the nine months ended September 30, 2021, compared with the same period in 2020.
A $41.0 million increase in cash due to a decrease in the number and cost of shares of our common stock purchased during the nine months ended September 30, 2021, compared with the same period in 2020, to satisfy requirements of our stock-based compensation plans.
The acquisition of an additional 10% ownership interest in Upstream in April 2020 for $31.0 million. See Note 2, Acquisitions, for more information.

These increases in cash were partially offset by:

A $680.0 million decrease in cash due to a $340.0 million repayment of a 364-day term loan during the nine months ended September 30, 2021, compared with its issuance during the same period in 2020, to enhance our liquidity position in response to the COVID-19 pandemic.
A $42.7 million decrease in cash due to higher dividends paid on our common stock during the nine months ended September 30, 2021, compared with the same period in 2020. In January 2021, our Board of Directors increased our quarterly dividend by $0.045 per share (7.1%) effective with the March 2021 dividend payment.
A $16.8 million decrease in cash related to the number of stock options exercised during the nine months ended September 30, 2021, compared with the same period in 2020.

Significant Financing Activities

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

Capital Resources and Requirements

Capital Resources

Liquidity

We anticipate meeting our capital requirements for our existing operations through internally generated funds and short-term borrowings, supplemented by the issuance of intermediate or long-term debt securities, depending on market conditions and other factors.

We currently have access to the capital markets and have been able to generate funds both internally and externally to meet our capital requirements. Our ability to attract the necessary financial capital at reasonable terms is critical to our overall strategic plan. We currently believe that we have adequate capacity to fund our operations for the foreseeable future through our existing borrowing arrangements, access to capital markets, and internally generated cash. See Factors Affecting Results, Liquidity, and Capital Resources – Coronavirus Disease – 2019, for additional information on the impacts of the COVID-19 pandemic.

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


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facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. In March 2020, in order to enhance our liquidity position in response to the COVID-19 pandemic and the ensuing volatility in the commercial paper market, WEC Energy Group entered into a $340 million 364-day term loan, which was used to pay down commercial paper. In March 2021, we repaid the term loan using the net proceeds from the issuance of our 0.80% Senior Notes.

See Note 8, Short-Term Debt and Lines of Credit, for more information about these credit agreements and Note 9, Long-Term Debt, for more information about the issuance of our 0.80% Senior Notes.

The following table shows our capitalization structure as of September 30, 2021, 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	$	10,908.5		$	11,158.5
Preferred stock of subsidiary	30.4			30.4
Long-term debt (including current portion)	13,174.8			12,924.8
Short-term debt	1,508.9			1,508.9
Total capitalization	$	25,622.6		$	25,622.6

Total debt	$	14,683.7		$	14,433.7

Ratio of debt to total capitalization	57.3		%	56.3		%

Included in long-term debt on our balance sheet as of September 30, 2021, 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.

Working Capital

As of September 30, 2021, our current liabilities exceeded our current assets by $1.3 billion. We do not expect this to have any impact on our liquidity since we believe we have adequate back-up lines of credit in place for our ongoing operations. We also believe that we can access the capital markets to finance our construction programs and to refinance current maturities of long-term debt, if necessary.

Credit Rating Risk

We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. However, we have certain agreements in the form of commodity contracts and employee benefit plans 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. We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.

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

In September 2021, Moody's changed the rating outlook for WG to negative from stable as a result of the decision to defer its next base rate case. The change in rating outlook has not had, and we do not believe that it will have, a material impact on our ability to access capital markets. Moody's affirmed WG's ratings including its A3 senior unsecured rating and its P-2 short term rating for commercial paper. See See Note 22, Regulatory Environment, for more information on the rate case delay.


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

If we are unable to successfully take actions to manage any additional impacts from the COVID-19 pandemic, the credit rating agencies could place our or our other subsidiaries’ credit ratings on negative outlook or downgrade our or our subsidiaries' credit ratings. Any such actions by credit rating agencies may make it more difficult and costly for us and our subsidiaries to issue future debt securities and certain other types of financing and could increase borrowing costs under our and our subsidiaries’ credit facilities.

Capital Requirements

Significant Capital Projects

We have several capital projects that will require significant capital expenditures over the next three years and beyond. All projected capital requirements are subject to periodic review and may vary significantly from estimates, depending on a number of factors. These factors include environmental requirements, regulatory restraints and requirements, changes in tax laws and regulations, acquisition and development opportunities, market volatility, economic trends, and the COVID-19 pandemic. Our estimated capital expenditures and acquisitions for the next three years are as follows:


(in millions)	2021 (1)		2022		2023
Wisconsin	$	1,436.5	$	2,131.7	$	2,148.0
Illinois	531.4		573.1		586.8
Other states	104.4		119.1		103.6
Non-utility energy infrastructure	353.5		870.8		325.7
Corporate and other	19.9		22.0		17.5
Total	$	2,445.7	$	3,716.7	$	3,181.6

(1)This includes actual capital expenditures already incurred in 2021, as well as estimated capital expenditures for the remainder of the year.

WE, WPS, and WG continue to upgrade their electric and natural gas distribution systems to enhance reliability. These upgrades include 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. WPS is also continuing work on the System Modernization and Reliability Project. This project includes modernizing parts of its electric distribution system, including burying or upgrading lines. The project focuses on constructing facilities to improve the reliability of electric service WPS provides to its customers. In 2021, WPS expects to invest approximately $50 million on this project at which time it will be substantially complete.

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 200 MW of utility-scale solar within our Wisconsin segment. WPS has partnered with an unaffiliated utility to construct a solar project, Badger Hollow I, that will be located in Iowa County, Wisconsin. Once constructed, WPS will own 100 MW of this project. WPS's share of the cost of this project is estimated to be approximately $130 million. Commercial operation of Badger Hollow I is expected in the fourth quarter of 2021. 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 $130 million. Commercial operation of Badger Hollow II is targeted for December 2022.
In February 2021, WE and WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire and construct the Paris Solar-Battery Park, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Kenosha County, Wisconsin and once constructed, WE and WPS will collectively own 180 MW of solar generation and 99 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 $385 million, with construction expected to begin in 2022 and completed by the end of 2023.


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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 the Darien Solar-Battery Park, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Rock and Walworth counties, Wisconsin and once 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 expected to begin in late 2021 and completed by the end of 2023.
In March 2021, WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire the Red Barn Wind Park, 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. If approved, WPS's share of the cost of this project is estimated to be approximately $140 million, with construction expected to begin in early 2022 and completed by the end of 2022.
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 constructed, WE and WPS will collectively own 270 MW of solar 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 expected to begin in late 2022 and completed by the second quarter of 2024.
In April 2021, WE and WPS filed an application with the PSCW for 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 reciprocating internal combustion engines. If approved, we estimate the cost of this project to be approximately $170 million, with construction expected to begin in 2022 and completed in 2023.

WE constructed approximately 46 miles of natural gas transmission main to increase the quantity and reliability of natural gas service in southeastern Wisconsin. This project, which was approved by the PSCW in June 2020, was designated as the Lakeshore Lateral Project. The cost of the project was approximately $130 million. Construction for the project began in December 2020 and was completed in October 2021.

WE and WG each plan to construct its own LNG facility. Subject to PSCW approval, each facility would provide approximately one billion cubic foot 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. If approved, construction is expected to begin by the end of 2021 with commercial operation for the LNG facilities targeted for the end of 2023.

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 2023 is between $280 million and $300 million.

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

We expect to provide total capital contributions to ATC (not included in the above table) of approximately $105 million from 2021 through 2023. We do not expect to make any contributions to ATC Holdco during that period.

See Factors Affecting Results, Liquidity, and Capital Resources – Coronavirus Disease – 2019 and Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks – United States Department of Commerce Complaint, for additional information on the impacts to our capital projects as a result of the COVID-19 pandemic and the DOC complaint that could impact our solar projects, respectively.


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Common Stock Dividends

Our current quarterly dividend rate is $0.6775 per share, which equates to an annual dividend of $2.71 per share. For information related to our most recent common stock dividend declared, see Note 7, Common Equity.

Off-Balance Sheet Arrangements

We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit that support construction projects, commodity contracts, and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see Note 8, Short-Term Debt and Lines of Credit, Note 14, Guarantees, and Note 19, Variable Interest Entities.

Contractual Obligations

For information about our commitments, see Contractual Obligations in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Requirements in our 2020 Annual Report on Form 10-K. There were no material changes to our commitments outside the ordinary course of business during the nine months ended September 30, 2021.

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 2020 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.

Coronavirus Disease – 2019

The global outbreak of COVID-19 was declared a pandemic by the WHO and the CDC and has spread globally, including throughout the United States. There are still questions regarding the extent and duration of the COVID-19 pandemic itself, as well as the measures currently in place to try to contain the virus. Shelter-in-place and other orders limiting the capacity of various businesses that were in effect for our service territories have now expired. Similar orders could be adopted in the future depending on how the virus continues to mutate and spread. The effects of the COVID-19 pandemic and related government responses significantly disrupted economic activity in our service territories in 2020 and continue to impact our results in 2021.

Liquidity and Financial Markets

Upon the initial enactment of certain COVID-19 related shelter-in-place orders in early to mid-March 2020, commercial paper markets became more expensive and related terms became less flexible. In response to these signs of market instability, the Federal Reserve implemented certain measures, including a reduction in its benchmark Federal Funds rate and the establishment of various programs to restore liquidity and stability into the short-term funding markets. These measures continue to have a mitigating effect on commercial paper rates and availability. In addition, the initial disruption in the long-term debt markets as a result of the COVID-19 pandemic has subsided.

Allowance for Credit Losses

We evaluate the collectability of our accounts receivable and unbilled revenue balances considering a combination of factors. Risks identified that we do not believe are reflected in historical reserve percentages are assessed on a quarterly basis to determine whether further adjustments are required. Economic disruptions caused by the COVID-19 pandemic, including higher unemployment rates and the inability of some businesses to recover from the pandemic, have caused a higher percentage of our accounts receivable to become uncollectible. Although impacts on our results of operations related to uncollectible receivable balances are mitigated by regulatory mechanisms and certain COVID-19 specific regulatory orders we have received, the increase in past due receivables we experienced resulted in higher working capital requirements. However, with normal collection practices now


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underway in all of our service territories, our working capital position has improved in the third quarter from where we were at the end of the first and second quarters of 2021.

Our exposure to credit losses for certain regulated utility customers is mitigated by regulatory mechanisms we have in place. Specifically, rates related to all of the customers in our Illinois segment, as well as the residential rates of WE, WPS, and WG in our Wisconsin segment include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between the actual provision for credit losses and the amounts recovered in rates. In addition, we have received specific orders related to the deferral of certain costs (including credit losses) and foregone revenues related to the COVID-19 pandemic. The additional protections provided by these COVID-19 specific regulatory orders are still being assessed and will be subject to prudency reviews. See Note 22, Regulatory Environment, for more information on these orders.

Loss of Business

We saw a decrease in the consumption of electricity and natural gas by some of our commercial and industrial customers as a result of the COVID-19 pandemic. Although many of these customers have started to recover, the extent to which this decreased consumption continues to impact our results of operations and liquidity is dependent upon the duration of the COVID-19 pandemic and the ability of our customers to resume and continue normal operations.

Supply Chain and Capital Projects

We have not yet experienced a significant disruption in our supply chain as a result of the COVID-19 pandemic. However, if the pandemic significantly impacts our key suppliers’ ability to manufacture or deliver critical equipment and supplies or provide services, we could experience delays in our ability to perform certain maintenance and capital project activities.

The timing of Badger Hollow I was impacted by the COVID-19 pandemic. The parties agreed to delay the expected commercial operation date from December 2020 so that initial staffing increases could be minimized in light of state mandated COVID-19 orders. We now expect Badger Hollow I to be placed into commercial operation during the fourth quarter of 2021. We are not currently aware of any other major delays or changes related to our capital plan as a result of the COVID-19 pandemic, although we are continuing to monitor potential impacts on an ongoing basis.

Employee Safety

The health and safety of our employees during the COVID-19 pandemic is paramount and enables us to continue to provide critical services to our customers.

We are following CDC guidelines and have taken precautions with regard to employee hygiene and facility cleanliness, imposed travel limitations on our employees, provided additional employee benefits, and implemented remote-work policies where appropriate. We have an incident management team and updated our pandemic continuity plan, which includes identifying critical work groups and ensuring safe-harbor plans are in place. We have minimized the unnecessary risk of exposure to COVID-19 by implementing self-quarantine measures and have adopted additional precautionary measures for our critical work groups.

Additional protocols have been implemented for our field employees who travel to customer premises in order to protect them, our customers, and the public. We have modified our work protocols to ensure compliance with social distancing and face covering recommendations.

We continue to provide our employees with educational information regarding the COVID-19 vaccine and will be providing incentives and imposing surcharges on our medical plan to encourage employees to obtain the vaccine. We are developing return-to-the workplace strategies for those employees currently working remotely, taking into consideration factors such as any updated CDC guidelines, the Delta variant, any increases in COVID-19 cases in our service territories, and the overall level of risk to our employees and customers.

All of these safety measures have caused us to incur additional costs that, depending upon the duration of the COVID-19 pandemic, could have a material impact on our results of operations and liquidity.


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Regulatory Environment

Our utilities took actions to ensure that essential utility services were available to customers in their service territories during the COVID-19 pandemic. In addition, the PSCW, the ICC, the MPUC, and the MPSC all issued written orders regarding certain measures required in their respective jurisdictions. See Note 22, Regulatory Environment, for more information on these orders and the potential recovery of expenditures incurred as a result of the measures taken.

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 regulatory and legislative matters described below. 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 2020 Annual Report on Form 10-K for a discussion of other significant risks applicable to us.

Regulatory and Legislative Matters

Regulatory Recovery

Our utilities account for their regulated operations in accordance with accounting guidance under the Regulated Operations Topic of the FASB Accounting Standards 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.

We expect to request or have requested recovery of the costs related to the following projects discussed in recent or pending rate proceedings, orders, and investigations involving our utilities:

Prior to its acquisition by us, Integrys initiated an information technology project with the goal of improving the customer experience at its subsidiaries. Specifically, the project is expected to provide functional and technological benefits to the billing, call center, and credit collection functions. As of September 30, 2021, costs incurred for this project at PGL are still subject to approval by the ICC. WPS, NSG, MGU and MERC received approval to recover these costs in their most recent rate orders.
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 2021, PGL filed its 2020 reconciliation with the ICC, which, along with the 2019, 2018, 2017, and 2016 reconciliations, are still pending. As of September 30, 2021, 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 22, Regulatory Environment, for more information regarding recent and pending rate proceedings, orders, and investigations involving our utilities.

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 January 1, 2023, natural gas utilities will no longer be allowed to charge late payment fees to low-income residential customers. In addition, 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. Instead, utilities will be required to seek recovery of costs incurred to process credit card payments through a rate proceeding or by establishing a recovery mechanism. On October 27, 2021, PGL and NSG filed requests with the ICC for approval of a


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TPTFA rider. The proposed TPTFA rider would allow PGL and NSG to recover the costs incurred for third-party transaction fees. See Note 22, Regulatory Environment, for more information on the proposed rider.

We are currently evaluating the impact this legislation may have on our future results of operations.

United States Department of Commerce Complaint

In August 2021, a group of anonymous domestic solar manufacturers filed a petition with the DOC seeking to impose new tariffs on solar panels and cells imported from several countries, including Malaysia, Vietnam, and Thailand. The petitioners claim that Chinese solar manufacturers are shifting products to these countries to avoid the tariffs required on products imported from China. In September 2021, the DOC asked that the anonymous group amend its petition to provide more detail and asked the group to identify its members. On October 13, 2021, in its response to the DOC, the anonymous group refused and argued that identifying its members could expose them to retribution from the Chinese solar industry, which dominates the global solar supply chain for critical solar panel components. The DOC has indicated it will make its decision within 45 days of receiving the response. If imposed, the new tariffs are expected to disrupt the United States' supply of solar modules and could impact the cost and timing of our solar projects.

Environmental Matters

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

Other Matters

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, this proposal, if adopted, would reduce our after-tax equity earnings from ATC by approximately $7 million annually. The transmission costs WE and WPS are required to pay ATC after the effective date would also be reduced by this proposal.

American Transmission Company Allowed Return on Equity Complaints

On November 21, 2019, the FERC issued an order (November 2019 Order) related to the methodology used to calculate the base ROE for all MISO transmission owners, including ATC. Based on 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's modified methodology reduced the base ROE that ATC is allowed to collect on a going-forward basis, as discussed below. In response to the FERC's decision, requests for the FERC to rehear the November 2019 Order in its entirety were filed by various parties.

On May 21, 2020, the FERC issued an order (May 2020 Order) that granted in part and denied in part the requests to rehear the November 2019 Order. In the May 2020 Order, the FERC made additional revisions to its base ROE methodology, including adding the use of the risk premium model. As discussed below, the additional revisions made by the FERC increased ATC's base ROE authorized in the November 2019 Order on a going-forward basis. Various parties filed requests to rehear certain parts of the May 2020 Order with the FERC, but the FERC issued an order in response to the rehearing requests during November 2020 (November 2020 Order) that confirmed the ROE authorized in the May 2020 Order. Petitions for review of the November 2019 Order, relevant parts of the May 2020 Order, and the November 2020 Order have also been filed with the D.C. Circuit Court of Appeals.

First Return on Equity Complaint

In November 2013, a group of MISO industrial customer organizations filed a complaint with the FERC requesting to reduce the base ROE used by MISO transmission owners, including ATC, from 12.2% to 9.15%. In September 2016, the FERC issued an order requiring


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MISO transmission owners to collect a reduced base ROE of 10.32%. This order also allowed the continued collection of any previously authorized ROE incentive adders. For MISO transmission owners, a 0.5% incentive adder was approved by the FERC in January 2015. The FERC then issued the November 2019 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. The November 2019 Order further reduced the base ROE for all MISO transmission owners, including ATC, to 9.88%, effective as of September 28, 2016 and prospectively. The November 2019 Order also continued to allow the collection of previously authorized ROE incentive adders, but ATC's ROE incentive adder of 0.5% only applies to revenues collected after January 6, 2015. In response to the rehearing requests filed related to the November 2019 Order, the FERC issued another order in May 2020. This May 2020 Order increased the base ROE for all MISO transmission owners, including ATC, from the 9.88% authorized in the November 2019 Order to 10.02%, effective as of September 28, 2016 and prospectively. The May 2020 Order also allowed the continued collection of previously authorized ROE incentive adders. However, ATC's 0.5% ROE incentive adder may be eliminated going forward, as discussed above.

ATC is 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. As a result, ATC is expected to continue providing WE and WPS with net refunds related to the transmission costs they paid during the two refund periods through the end of February 2022. These refunds are being applied to WE's and WPS's PSCW-approved escrow accounting for transmission expense.

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. The FERC also addressed this second complaint in the November 2019 Order. Similar to the first complaint, the November 2019 Order stated that the base ROE of 9.88% and the collection of previously authorized ROE incentive adders, such as ATC's 0.5% adder, were 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 that refunds were not allowed for this period. In its May 2020 Order, the FERC stated the new base ROE of 10.02% and the collection of previously authorized ROE incentive adders were 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 determine that refunds were not allowed for this period. The FERC also denied the requests to rehear both the dismissal of the second complaint and the determination that no refunds are allowed for the second complaint period.

Due to the various outstanding petitions related to the November 2019 Order, May 2020 Order, and November 2020 Order, refunds could still be required for the second complaint period. Therefore, our financials continue to reflect a liability of $39.1 million, reducing our equity earnings from ATC. This liability is based on a 10.52% ROE for the second complaint period. If it is ultimately determined that a refund is required for the second 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 and WPS would be entitled to receive a portion of the refund from ATC for the benefit of their customers.

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 2020 Annual Report on Form 10-K are still current and that there have been no significant changes, except as follows:

Goodwill Impairment

We completed our annual goodwill impairment tests for all of our reporting units that carried a goodwill balance as of July 1, 2021. No impairments were recorded as a result of these tests.


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Our reporting units had the following goodwill balances at July 1, 2021:


(in millions, except percentages)	Goodwill		Percentage of Total Goodwill
Wisconsin	$	2,104.3	68.9	%
Illinois	758.7		24.9	%
Other states	183.2		6.0	%
Bluewater	6.6		0.2	%
Total goodwill	$	3,052.8	100.0	%

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 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 the 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 an equal weighting of the guideline public company method and the guideline merged and acquired company method. 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, 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 16, Goodwill and Intangibles, for more information.


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