Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CORPORATE DEVELOPMENTS

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 FERC and certain state regulatory commissions), and non-utility energy infrastructure operations through We Power (which owns generation assets in Wisconsin), Bluewater (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 2021-2025 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 the construction of zero-carbon-emitting renewable generation and clean natural gas-fired generation. When taken together, the retirements and new investments should better balance our supply with our demand, while maintaining reliable, affordable energy for our customers. The retirements will contribute to meeting our goals to reduce carbon dioxide (CO2) emissions from our electric generation.

In 2019, we met and surpassed our original goal to reduce CO2 emissions by 40% below 2005 levels. In July 2020, we announced new goals to reduce CO2 emissions from our electric generation by 70% below 2005 levels by 2030 and to be net carbon neutral by 2050. We added a near-term goal in November 2020 to reduce CO2 emissions by 55% below 2005 levels by 2025.

We already have retired more than 1,800 megawatts (MW) of coal-fired generation since the beginning of 2018, which included the 2019 retirement of the Presque Isle power plant as well as the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater Unit 4 generating units. See Note 6, Regulatory Assets and Liabilities, for more information related to these power plant retirements. As part of our ESG Progress Plan, we expect to retire approximately 1,800 MW of additional fossil-fueled generation by 2025.

In addition to retiring these older, fossil-fueled plants, we expect to invest approximately $2 billion from 2021-2025 in low-cost renewable energy in Wisconsin. Our plan is to replace a portion of the retired capacity by building and owning a combination of clean, natural gas-fired generation and zero-carbon-emitting renewable generation facilities that are anticipated to include the following new investments:

800 MW of utility-scale solar;
600 MW of battery storage;
100 MW of wind;
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.

These new investments discussed above are in addition to the renewable projects currently underway.


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We have received approval 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, now in service, and Badger Hollow Solar Park I, targeted for completion in the second 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 Public Service Commission of Wisconsin (PSCW) for two renewable energy pilot programs. The Solar Now pilot is expected to add 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 13 Solar Now projects and currently has another five under construction, together totaling more than 15 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.

We also have a goal to decrease the rate of methane emissions from the natural gas distribution lines in our networks by 30% per mile by the year 2030 from a 2011 baseline. We were over halfway toward meeting that goal at the end of 2019.

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 and distribution networks to further improve reliability. Our investments, coupled with our commitment to operating efficiency and customer care, resulted in We Energies being recognized in 2020 by PA Consulting Group, an independent consulting firm, for superior reliability of its electric delivery network. This was the 10th consecutive year that We Energies has been named the most reliable utility in the Midwest.

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

WE is constructing 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, is expected to be completed by the end of 2021.
WE and Wisconsin Gas LLC (WG) each plan to construct their own liquefied natural gas (LNG) facility 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 continues work on 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.


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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. See Note 3, Dispositions, for information on the sale of certain WPS Power Development, LLC solar power generation facilities.

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 six wind parks, capable of providing more than 1,000 MW of carbon-free energy in total. These renewable energy assets represent more than $1.6 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. We also project that these investments will generate higher returns than our regulated business. See Note 2, Acquisitions, for additional information on these transactions.

We expect total capital expenditures for our regulated utility and non-utility energy infrastructure businesses to be approximately $15.0 billion from 2021 to 2025. In addition, we currently forecast that our share of ATC's projected capital expenditures over the next five years will be $1.1 billion. Specific projects included in the $16.1 billion ESG Progress Plan are discussed in more detail below under Liquidity and Capital Resources.

Exceptional Customer Care

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

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

Safety

Across the organization, we monitor the integrity of our networks and conduct comprehensive incident response planning to enhance the safety of our operations.

Under our "Target Zero" mission, we have an ultimate goal of zero incidents, accidents, and injuries. We also set goals around injury-prevention activities that raise awareness and facilitate conversations about employee safety. 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.


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RESULTS OF OPERATIONS

Consolidated Earnings

The following table compares our consolidated results, including favorable or better, "B", and unfavorable or worse, "W", variances:


	Year Ended December 31						2020 vs. 2019		2019 vs. 2018
(in millions, except per share data)	2020		2019		2018		B (W)		B (W)
Wisconsin	$	690.4	$	649.9	$	617.0	$	40.5	$	32.9
Illinois	203.5		170.3		147.1		33.2		23.2
Other states	39.0		43.2		44.1		(4.2)		(0.9)
Electric transmission	112.6		87.4		82.8		25.2		4.6
Non-utility energy infrastructure	260.8		246.0		228.4		14.8		17.6
Corporate and other	(106.4)		(62.8)		(60.1)		(43.6)		(2.7)
Net income attributed to common shareholders	$	1,199.9	$	1,134.0	$	1,059.3	$	65.9	$	74.7

Diluted earnings per share	$	3.79	$	3.58	$	3.34	$	0.21	$	0.24

2020 Compared with 2019

Earnings increased $65.9 million during 2020, compared with 2019. The significant factors impacting the $65.9 million increase in earnings were:

A $40.5 million increase in net income attributed to common shareholders at the Wisconsin segment. The increase was driven by the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2020, lower operation and maintenance expense, and a positive impact from collections of fuel and purchased power costs. Lower electric and natural gas distribution expenses, a decrease in expense related to the earnings sharing mechanisms in place at our Wisconsin utilities, and lower benefit costs all contributed to the lower operation and maintenance expense. These positive impacts were partially offset by higher depreciation and amortization and the impact of lower retail sales volumes. The lower sales volumes were driven by impacts from the COVID-19 pandemic and warmer winter weather during 2020.
A $33.2 million increase in net income attributed to common shareholders at the Illinois segment, driven by lower operation and maintenance expense and PGL's continued capital investment in the SMP project under its QIP rider. Lower natural gas distribution maintenance costs, lower customer service expenses, and lower benefit costs drove the decrease in operation and maintenance expense during 2020.
A $25.2 million increase in net income attributed to common shareholders at our electric transmission segment, driven by higher equity earnings from transmission affiliates. The higher equity earnings were primarily due to the impacts of FERC orders issued in November 2019 and May 2020 addressing complaints related to ATC's ROE. For further discussion of the FERC orders, see Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints. Continued capital investment by ATC also contributed to the higher equity earnings from transmission affiliates.
A $14.8 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, primarily due to lower income tax expense in 2020 driven by wind PTCs generated by our Coyote Ridge wind park that achieved commercial operation in December 2019. See Note 2, Acquisitions, and Note 16, Income Taxes, for more information.

Partially offsetting these increases in earnings was a $43.6 million increase in the net loss attributed to common shareholders at the corporate and other segment, driven by make-whole premiums related to the early extinguishment of debt during 2020. A higher net operating loss at Wispark, lower net gains from the investments held in the rabbi trust, and a change in unrecognized tax benefits also contributed to the increase in the net loss. These negative impacts were partially offset by lower interest expense. The gains from the investments held in the rabbi trust partially offset benefits costs related to deferred compensation, which are included in our operating segments. See Note 17, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.


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2019 Compared with 2018

Earnings increased $74.7 million during 2019, compared with 2018. The significant factors impacting the $74.7 million increase in earnings were:

A $32.9 million increase in net income attributed to common shareholders at the Wisconsin segment. The increase was driven by lower operation and maintenance expense related to our power plants, which primarily resulted from lower maintenance and labor costs associated with our 2019 and 2018 plant retirements and increases to certain plant-related regulatory assets resulting from decisions included in the December 2019 Wisconsin rate orders. The positive impact from lower operation and maintenance expense was partially offset by a decrease in electric margins related to lower retail sales volumes, primarily driven by cooler summer weather during 2019 compared with 2018, and higher depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.
A $23.2 million increase in net income attributed to common shareholders at the Illinois segment, driven by PGL's continued capital investment in the SMP project under its QIP rider.
A $17.6 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by an increase in wind PTCs recognized on the three wind parks acquired in 2018 and 2019.
A $4.6 million increase in net income attributed to common shareholders at our electric transmission segment, driven by lower income tax expense. The decrease in income tax expense was driven by a tax basis adjustment related to the remeasurement of deferred income taxes in 2018 and a change in the tax rates at the segment level resulting from the transfer of ownership in the ATC investment between our subsidiaries. The decrease in income tax expense related to the change in tax rates was offset in the corporate and other segment and, as a result, had no effect on consolidated net income. The positive impact from lower income taxes was partially offset by higher interest expense in 2019, due to debt issuances at ATC Holding in September 2019 and December 2018, and lower equity earnings from our investment in ATC as a result of a FERC order issued in November 2019 that addressed complaints related to ATC's allowed ROE.

Partially offsetting these increases in earnings was a $2.7 million increase in the net loss attributed to common shareholders at the corporate and other segment. The increase in the net loss was driven by higher interest expense in 2019, primarily related to continued capital investments across our segments, and higher net operating losses, primarily at WBS, our centralized services company. WBS transferred assets to our regulated utilities in 2018, and as a result of these transfers, the return on these assets is now recognized within our regulated utility operations. These negative impacts were substantially offset by net gains from investments held in the Integrys rabbi trust during 2019, compared with net losses during 2018.

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 margin (electric revenues less fuel and purchased power costs) and natural gas margin (natural gas revenues less cost of natural gas sold) are non-GAAP financial measures because they exclude other operation and maintenance expense, depreciation and amortization, and property and revenue taxes.

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

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance. 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.


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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 for the year ended December 31, 2020 was $690.4 million, representing a $40.5 million, or 6.2%, increase over the prior year. The increase was driven by the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2020, lower operation and maintenance expense, and a positive impact from collections of fuel and purchased power costs. Lower electric and natural gas distribution expenses, a decrease in expense related to the earnings sharing mechanisms in place at our Wisconsin utilities, and lower benefit costs all contributed to the lower operation and maintenance expense. These increases were partially offset by higher depreciation and amortization and the impact of lower retail sales volumes. The lower sales volumes were driven by impacts from the COVID-19 pandemic and warmer winter weather during 2020.


	Year Ended December 31						2020 vs. 2019		2019 vs. 2018
(in millions)	2020		2019		2018		B (W)		B (W)
Electric revenues	$	4,274.0	$	4,317.6	$	4,438.9	$	(43.6)	$	(121.3)
Fuel and purchased power	1,238.1		1,341.9		1,418.1		103.8		76.2
Total electric margins	3,035.9		2,975.7		3,020.8		60.2		(45.1)

Natural gas revenues	1,199.5		1,329.5		1,355.8		(130.0)		(26.3)
Cost of natural gas sold	595.2		748.0		792.1		152.8		44.1
Total natural gas margins	604.3		581.5		563.7		22.8		17.8

Total electric and natural gas margins	3,640.2		3,557.2		3,584.5		83.0		(27.3)

Other operation and maintenance	1,476.7		1,591.3		2,076.1		114.6		484.8
Depreciation and amortization	674.5		617.0		546.6		(57.5)		(70.4)
Property and revenue taxes	156.2		159.3		161.6		3.1		2.3
Operating income	1,332.8		1,189.6		800.2		143.2		389.4

Other income, net	52.8		68.7		65.4		(15.9)		3.3
Interest expense	561.3		572.0		200.7		10.7		(371.3)
Income before income taxes	824.3		686.3		664.9		138.0		21.4

Income tax expense	132.7		35.2		46.7		(97.5)		11.5
Preferred stock dividends of subsidiary	1.2		1.2		1.2		—		—
Net income attributed to common shareholders	$	690.4	$	649.9	$	617.0	$	40.5	$	32.9

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


	Year Ended December 31						2020 vs. 2019		2019 vs. 2018
(in millions)	2020		2019		2018		B (W)		B (W)
Operation and maintenance not included in line items below	$	673.5	$	670.7	$	769.5	$	(2.8)	$	98.8
Transmission (1)	518.0		418.1		420.7		(99.9)		2.6
Regulatory amortizations and other pass through expenses (2)	138.6		160.6		159.1		22.0		(1.5)
We Power (3)	119.3		140.9		506.9		21.6		366.0
Transmission expense related to the flow through of tax repairs (4)	—		67.2		77.8		67.2		10.6
Transmission expense related to Tax Legislation (5)	—		65.3		67.7		65.3		2.4
Earnings sharing mechanisms (6)	21.6		61.5		67.5		39.9		6.0
Other	5.7		7.0		6.9		1.3		(0.1)
Total other operation and maintenance	$	1,476.7	$	1,591.3	$	2,076.1	$	114.6	$	484.8

(1) Represents transmission expense that we are authorized to collect in rates, in accordance with the PSCW's approval of escrow accounting for ATC and MISO network transmission expenses for our Wisconsin electric utilities. 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 2020, 2019, and 2018, $481.8 million, $486.7 million, and $438.2 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 2018, the amount also included the lease payments that were billed from We Power to WE and then recovered in WE's rates. We adopted ASU 2016-02, Leases (Topic 842), effective January 1, 2019, which revised the previous guidance regarding the accounting for leases. As a result of this adoption, starting in 2019, lease expense related to the We Power leases with WE was no longer classified within other operation and maintenance, but was instead recorded as depreciation and amortization and interest expense, in accordance with Topic 842. The We Power leases do not impact our financial statements as all amounts associated with the leases are eliminated at the consolidated level.

During 2020, 2019, and 2018, $115.1 million, $134.8 million, and $485.3 million, respectively, of costs were billed to or incurred by WE related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

(4) Represents additional transmission expense recorded in 2019 and 2018 associated with WE's flow through of tax benefits of its repair-related deferred tax liabilities starting in 2018 in accordance with a settlement agreement with the PSCW, to maintain certain regulatory asset balances at their December 31, 2017 levels. This decrease in expenses was offset in income taxes. Since WE's transmission regulatory asset was eliminated at December 31, 2019, there were no tax benefits used in 2020.

(5) Represents additional transmission expense recorded in 2019 and 2018 associated with the May 2018 PSCW order requiring WE to use 80% of its current 2018 tax benefit, including the amortization associated with the revaluation of deferred taxes, to reduce its transmission regulatory asset balance. Since WE's transmission regulatory asset was eliminated at December 31, 2019, there were no tax benefits used in 2020.

(6) See Note 26, Regulatory Environment, for more information about our earnings sharing mechanisms.

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


	Year Ended December 31
	MWh (in thousands)			2020 vs. 2019	2019 vs. 2018
Electric Sales Volumes	2020	2019	2018	B (W)	B (W)
Customer class
Residential	11,523.8	10,918.6	11,195.0	605.2	(276.4)
Small commercial and industrial (1)	12,250.0	12,861.0	13,186.7	(611.0)	(325.7)
Large commercial and industrial (1)	11,661.8	12,601.6	12,946.5	(939.8)	(344.9)
Other	158.7	164.8	169.0	(6.1)	(4.2)
Total retail (1)	35,594.3	36,546.0	37,497.2	(951.7)	(951.2)
Wholesale	3,088.4	3,314.3	3,612.7	(225.9)	(298.4)
Resale	6,189.9	6,006.0	6,019.3	183.9	(13.3)
Total sales in MWh (1)	44,872.6	45,866.3	47,129.2	(993.7)	(1,262.9)

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


	Year Ended December 31
	Therms (in millions)			2020 vs. 2019	2019 vs. 2018
Natural Gas Sales Volumes	2020	2019	2018	B (W)	B (W)
Customer class
Residential	1,090.8	1,195.6	1,131.1	(104.8)	64.5
Commercial and industrial	656.7	740.9	733.1	(84.2)	7.8
Total retail	1,747.5	1,936.5	1,864.2	(189.0)	72.3
Transport	1,357.7	1,426.1	1,411.5	(68.4)	14.6
Total sales in therms	3,105.2	3,362.6	3,275.7	(257.4)	86.9


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	Year Ended December 31
	Degree Days			2020 vs. 2019		2019 vs. 2018
Weather	2020	2019	2018	B (W)		B (W)
WE and WG (1)
Heating (6,618 normal)	6,092	6,835	6,685	(10.9)	%	2.2	%
Cooling (737 normal)	938	727	929	29.0	%	(21.7)	%

WPS (2)
Heating (7,450 normal)	7,139	7,723	7,554	(7.6)	%	2.2	%
Cooling (515 normal)	660	504	678	31.0	%	(25.7)	%

UMERC (3)
Heating (8,464 normal)	8,189	8,971	8,611	(8.7)	%	4.2	%
Cooling (330 normal)	425	284	478	49.6	%	(40.6)	%

(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.

2020 Compared with 2019

Electric Utility Margins

Electric utility margins at the Wisconsin segment increased $60.2 million during 2020, compared with 2019. The significant factors impacting the higher electric utility margins were:

A $101.8 million increase in margins associated with the 2019 negative impact of WE's flow through of tax benefits of its repair-related deferred tax liabilities, in accordance with a settlement agreement with the PSCW to maintain certain regulatory assets at their December 31, 2017 levels. These tax benefits were no longer in effect for 2020. This increase in margins was offset in income taxes. See Note 26, Regulatory Environment, for more information.
An $8.2 million year-over-year positive 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.

These increases in margins were partially offset by:

A $26.5 million decrease in margins from other revenues, primarily related to lower revenues from third party use of our assets.
A $9.9 million net decrease in margins related to lower sales volumes, including the impact of weather. We recognized a $24.7 million net reduction in margins related to lower retail sales volumes driven by the COVID-19 pandemic. Sales volumes for our commercial and industrial customers decreased, primarily related to business interruptions and closings, while residential sales volumes increased. These changes in volumes were both driven, in large part, by a shelter-in-place order for the state of Wisconsin, which was in effect from March 25, 2020 through April 24, 2020, as well as the continued impacts of the COVID-19 pandemic. This net decrease in margins was partially offset by a $14.8 million increase in margins related to warmer summer weather. As measured by cooling degree days, 2020 was 29.0% and 31.0% warmer than 2019 in the Milwaukee and Green Bay areas, respectively.
A $5.6 million net decrease in margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2020. This decrease in margins includes a $73.9 million negative impact related to unprotected excess deferred taxes, which we agreed to return to customers and is offset in income taxes.


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Natural Gas Utility Margins

Natural gas utility margins at the Wisconsin segment increased $22.8 million during 2020, compared with 2019. The most significant factor impacting the higher natural gas utility margins was a $53.6 million increase related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2020. This increase in margins includes a $3.1 million negative impact related to unprotected excess deferred taxes, which we agreed to return to customers and is offset in income taxes.

This increase in margins was partially offset by a $35.9 million reduction in margins related to lower sales volumes, driven primarily by warmer winter weather during 2020. As measured by heating degree days, 2020 was 10.9% and 7.6% warmer than 2019 in the Milwaukee and Green Bay areas, respectively. In addition to the weather impact, the decrease in sales volumes for our commercial and industrial customers was also driven by business interruptions and closings related to, in large part, the shelter-in-place order issued by the state of Wisconsin, as well as the continued impacts of the COVID-19 pandemic.

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

Other operating expenses at the Wisconsin segment decreased $60.2 million during 2020, compared with 2019. The significant factors impacting the decrease in operating expenses were:

A $67.2 million decrease in transmission expense related to the flow through of tax repairs during 2019, as discussed in the notes under the other operation and maintenance table above. This decrease in transmission expense was offset in income taxes.
A $65.3 million decrease in transmission expense associated with the May 2018 order from the PSCW related to our required treatment of the tax benefits associated with the Tax Legislation, as discussed in the notes under the other operation and maintenance table above. This decrease in transmission expense was offset by a corresponding decrease in margins.
A $43.2 million decrease in electric and natural gas distribution expenses, driven by lower maintenance and storm restoration expense, as well as our focus on operating efficiency.
A $39.9 million decrease in expense related to the earnings sharing mechanisms in place at our Wisconsin utilities. See Note 26, Regulatory Environment, for more information.
A $25.6 million decrease in benefit costs, primarily due to lower deferred compensation costs, stock-based compensation, and medical costs.
A $22.0 million decrease in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.
A $21.6 million decrease in other operation and maintenance expense related to the We Power leases, as discussed in the notes under the other operation and maintenance table above.

These decreases in operating expenses were partially offset by:

A $99.9 million increase 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.
A $57.5 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.
A $46.0 million net increase in other operation and maintenance expense related to our power plants, driven by changes to certain plant-related regulatory assets resulting from decisions included in the December 2019 Wisconsin rate orders. See Note 26, Regulatory Environment, for more information on the Wisconsin rate orders. These increases were partially offset by a decrease in other operation and maintenance expense at our plants, driven by the retirement of PIPP in March 2019 and reduced operation of the OCPP.
Costs incurred of $12.5 million related to facility damage resulting from a significant rain event in May 2020. See Note 7, Property, Plant, and Equipment, for more information on the significant rain event.


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Other Income, Net

Other income, net at the Wisconsin segment decreased $15.9 million during 2020, compared with 2019. The decrease was primarily driven by the impact from the 2019 deferral of costs that were offset in other income statement line items and had no impact on net income attributed to common shareholders. Partially offsetting this decrease was higher AFUDC–Equity due to continued capital investment.

Interest Expense

Interest expense at the Wisconsin segment decreased $10.7 million during 2020, compared with 2019, primarily due to lower interest rates on short-term debt and lower interest expense on finance lease liabilities. This decrease was partially offset by long-term debt issuances of $750.0 million during the second half of 2019.

Income Tax Expense

Income tax expense at the Wisconsin segment increased $97.5 million during 2020, compared with 2019. The increase was primarily due to the $169.0 million benefit from the flow through of tax repairs during 2019 in connection with the 2017 Wisconsin rate settlement and an increase in pretax income. Partially offsetting these increases was a $77.0 million positive impact related to the 2020 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 impacts due to the benefit from the flow through of tax repairs and the amortization of the unprotected excess deferred tax benefits from the Tax Legislation did not impact earnings as they were offset in operating income. See Note 16, Income Taxes, and Note 26, Regulatory Environment, for more information.

2019 Compared with 2018

Electric Utility Margins

Electric utility margins at the Wisconsin segment decreased $45.1 million during 2019, compared with 2018. The significant factors impacting the lower electric utility margins were:

A $54.1 million decrease related to lower sales volumes, primarily driven by cooler summer weather during 2019 compared with 2018. As measured by cooling degree days, 2019 was 21.7% and 25.7% cooler than 2018 in the Milwaukee and Green Bay areas, respectively.
A $13.7 million decrease in margins associated with WE's flow through of tax benefits of its repair-related deferred tax liabilities starting in 2018 in accordance with a settlement agreement with the PSCW to maintain certain regulatory assets at their December 31, 2017 levels. This decrease in margins was offset in income taxes. See Note 26, Regulatory Environment, for more information.
A $6.8 million decrease in margins related to savings from the Tax Legislation that we are required to return to customers through bill credits or reductions in other regulatory assets. This decrease in margins did not impact net income as it was offset by the net impact of a $22.0 million decrease in income taxes and a $15.2 million increase in depreciation and amortization expense. We received the PSCW order in May 2018, which required WPS to use 40% of its 2018 and 2019 tax benefits associated with the Tax Legislation to reduce certain regulatory assets. See Note 16, Income Taxes, and Note 26, Regulatory Environment, for more information.

These decreases in margins were partially offset by:

A $16.3 million increase in margins related to the iron ore mine located in the Upper Peninsula of Michigan. Prior to the transfer of the mine as a full requirements customer of WE to UMERC as of April 1, 2019, the margin from the mine was being deferred for the benefit of Wisconsin retail electric customers, as ordered by the PSCW. On March 31, 2019 when the new natural gas-fired generation in the Upper Peninsula began commercial operation, a new 20 year agreement with Tilden became effective under which Tilden began purchasing electric power from UMERC. Half of the cost of the natural gas-fired generation is being recovered from Tilden under this agreement.


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A $5.3 million increase in margins related to a net decrease in fuel and purchased power costs driven by the commercial operation of UMERC's new natural gas-fired generation in the Upper Peninsula of Michigan on March 31, 2019. UMERC previously met its market obligations through PPAs.

Natural Gas Utility Margins

Natural gas utility margins at the Wisconsin segment increased $17.8 million during 2019, compared with 2018. The most significant factor impacting the higher natural gas utility margins was higher sales volumes, due in part to colder winter weather, customer growth, and higher use per residential customer during 2019, compared with 2018. As measured by heating degree days, 2019 was 2.2% colder than 2018 in the Milwaukee and Green Bay areas.

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

Other operating expenses at the Wisconsin segment decreased $416.7 million during 2019, compared with 2018. The Wisconsin segment experienced lower overall operating expenses related to efficiencies and effective cost control. The other significant factors impacting the decrease in operating expenses during 2019, compared with 2018, were:

A $363.3 million decrease in other operation and maintenance expense related to the We Power leases, as discussed in the notes under the other operation and maintenance table above.
A $107.6 million decrease in other operation and maintenance expense related to our power plants, driven by lower maintenance and labor costs associated with our 2019 and 2018 plant retirements, and increases to certain plant-related regulatory assets resulting from decisions included in the December 2019 Wisconsin rate orders. Plant retirements included the March 2019 retirement of the PIPP as well as the 2018 retirements of the Pleasant Prairie power plant, Edgewater Unit 4, and Pulliam Units 7 and 8. See Note 7, Property, Plant, and Equipment, for more information on the plant retirements. See Note 26, Regulatory Environment, for more information on the Wisconsin rate orders.
A $10.6 million decrease in transmission expense related to the flow through of tax repairs during 2019, as discussed in the notes under the other operation and maintenance table above. This decrease in transmission expense was offset in income taxes.
A $6.0 million decrease in expense related to the earnings sharing mechanisms in place at our Wisconsin utilities. See Note 26, Regulatory Environment, for more information.

These decreases in operating expenses were partially offset by:

A $70.4 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.
A $16.4 million increase in storm restoration expense during 2019.
A $16.3 million net increase in benefit costs, primarily related to higher deferred compensation costs during 2019.

Other Income, Net

Other income, net at the Wisconsin segment increased $3.3 million during 2019, compared with 2018, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 20, Employee Benefits, for more information on our benefit costs.

Interest Expense

Interest expense at the Wisconsin segment increased $371.3 million during 2019, compared with 2018, primarily due to the adoption of ASU 2016-02, Leases (Topic 842). Effective January 1, 2019, minimum lease payments were no longer classified within cost of sales or other operation and maintenance, but were instead recorded as a component of depreciation and amortization and interest expense in accordance with Topic 842. As a result of the adoption, for the year ended December 31, 2019, $350.9 million of minimum lease payments were recorded as interest expense on finance lease liabilities. The remaining increase was driven by long-term debt issuances of $700.0 million during the fourth quarter of 2018 and $750.0 million during the second half of 2019.


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Income Tax Expense

Income tax expense at the Wisconsin segment decreased $11.5 million during 2019, compared with 2018. The decrease was driven by a $22.0 million positive impact from the 2018 PSCW order addressing the benefits associated with the Tax Legislation and a $3.1 million increase in the benefit from the flow through of tax repairs in connection with the 2017 Wisconsin rate settlement. These items did not impact earnings as they were offset in operating income. Partially offsetting these decreases to income tax expense was an increase in pretax income.

Illinois Segment Contribution to Net Income Attributed to Common Shareholders

The Illinois segment's contribution to net income attributed to common shareholders for the year ended December 31, 2020 was $203.5 million, representing a $33.2 million, or 19.5%, increase over the prior year. The increase was driven by lower operation and maintenance expense and PGL's continued capital investment in the SMP project under its QIP rider. Lower natural gas distribution maintenance costs, lower customer service expenses, and lower benefit costs drove the decrease in operation and maintenance expense during 2020.

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


	Year Ended December 31						2020 vs. 2019		2019 vs. 2018
(in millions)	2020		2019		2018		B (W)		B (W)
Natural gas revenues	$	1,321.9	$	1,357.1	$	1,400.0	$	(35.2)	$	(42.9)
Cost of natural gas sold	330.9		401.4		480.5		70.5		79.1
Total natural gas margins	991.0		955.7		919.5		35.3		36.2

Other operation and maintenance	435.4		461.1		472.3		25.7		11.2
Depreciation and amortization	196.7		181.3		170.3		(15.4)		(11.0)
Property and revenue taxes	28.1		21.4		21.1		(6.7)		(0.3)
Operating income	330.8		291.9		255.8		38.9		36.1

Other income (expense), net	2.3		(2.4)		(5.7)		4.7		3.3
Interest expense	63.5		59.0		51.2		(4.5)		(7.8)
Income before income taxes	269.6		230.5		198.9		39.1		31.6

Income tax expense	66.1		60.2		51.8		(5.9)		(8.4)


Net income attributed to common shareholders	$	203.5	$	170.3	$	147.1	$	33.2	$	23.2

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


	Year Ended December 31						2020 vs. 2019		2019 vs. 2018
(in millions)	2020		2019		2018		B (W)		B (W)
Operation and maintenance not included in the line items below	$	332.1	$	362.2	$	372.9	$	30.1	$	10.7
Riders (1)	101.4		97.5		95.3		(3.9)		(2.2)
Regulatory amortizations (1)	(2.6)		(1.5)		(1.4)		1.1		0.1
Other	4.5		2.9		5.5		(1.6)		2.6
Total other operation and maintenance	$	435.4	$	461.1	$	472.3	$	25.7	$	11.2

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


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


	Year Ended December 31
	Therms (in millions)			2020 vs. 2019	2019 vs. 2018
Natural Gas Sales Volumes	2020	2019	2018	B (W)	B (W)
Customer Class
Residential	832.6	904.8	896.2	(72.2)	8.6
Commercial and industrial	326.1	368.6	358.3	(42.5)	10.3
Total retail	1,158.7	1,273.4	1,254.5	(114.7)	18.9
Transport	785.7	896.6	905.1	(110.9)	(8.5)
Total sales in therms	1,944.4	2,170.0	2,159.6	(225.6)	10.4


	Year Ended December 31
	Degree Days			2020 vs. 2019		2019 vs. 2018
Weather (1)	2020	2019	2018	B (W)		B (W)
Heating (6,195 normal)	5,597	6,479	6,327	(13.6)	%	2.4	%

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

2020 Compared with 2019

Natural Gas Utility Margins

Natural gas utility margins at the Illinois segment, net of the $3.9 million impact of the riders referenced in the table above, increased $31.4 million during 2020, compared with 2019. The increase in margins was primarily driven by higher revenues at PGL due to continued capital investment in the SMP project. PGL currently recovers the costs related to the SMP through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023. See Note 26, Regulatory Environment, for more information.

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

Other operating expenses at the Illinois segment decreased $7.5 million, net of the impact of the riders referenced in the table above, during 2020, compared with 2019. The significant factors impacting the decrease in operating expenses were:

A $13.6 million decrease in natural gas distribution maintenance costs, which reflects the benefit of warmer than normal winter weather in 2020 and the timing of performing certain services.
A $7.1 million decrease in benefit costs, primarily due to lower deferred compensation costs, pension settlement costs, severance costs, and stock-based compensation.
A $6.5 million decrease in customer service expenses, primarily due to lower call volumes and metering costs.

These decreases in operating expenses were partially offset by:

A $15.4 million increase in depreciation expense, primarily driven by PGL's continued capital investment in the SMP project.
A $6.7 million increase in property and revenue taxes driven by a $3.0 million increase in property taxes and a $2.9 million increase in the invested capital tax related to higher plant placed in service during 2020, compared to 2019.

Other Income (Expense), Net

The Illinois segment had other income, net of $2.3 million during 2020, compared with $2.4 million of other expense, net in 2019. The $4.7 million year-over-year increase in other income was driven by net credits from the non-service components of our net periodic pension and OPEB costs in 2020, compared with net expenses in 2019. See Note 20, Employee Benefits, for more information on our benefit costs.


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Interest Expense

Interest expense at the Illinois segment increased $4.5 million during 2020, compared with 2019, primarily due to higher long-term debt balances. This increase in debt balances was primarily related to continued capital investments and was partially offset by lower interest rates on short-term debt.

Income Tax Expense

Income tax expense at the Illinois segment increased $5.9 million during 2020, compared with 2019, driven by an increase in pretax income, partially offset by a $6.3 million change in unrecognized tax benefits in 2020. See Note 16, Income Taxes, for more information.

2019 Compared with 2018

Natural Gas Utility Margins

Natural gas utility margins at the Illinois segment, net of the $2.2 million impact of the riders referenced in the table above, increased $34.0 million during 2019, compared with 2018. The increase was primarily driven by higher revenues at PGL due to continued capital investment in the SMP project. PGL currently recovers the costs related to the SMP through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023. See Note 26, Regulatory Environment, for more information.

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

Other operating expenses at the Illinois segment decreased $2.1 million, net of the impact of the riders referenced in the table above, during 2019, compared with 2018. The significant factor impacting the decrease in operating expenses was a $23.2 million decrease in natural gas maintenance costs related to our Illinois utilities’ distribution systems.

This decrease in other operating expenses was partially offset by:

An $11.0 million increase in depreciation and amortization, primarily driven by PGL's continued capital investment in the SMP project.
An $8.4 million increase in benefit costs, primarily related to higher deferred compensation costs in 2019.

Other Expense, Net

Other expense, net at the Illinois segment decreased $3.3 million during 2019, compared with 2018, driven by lower costs from the non-service components of our net periodic pension and OPEB costs.

Interest Expense

Interest expense at the Illinois segment increased $7.8 million during 2019, compared with 2018, driven by higher long-term debt balances. This increase in debt balances was primarily related to continued capital investments.

Income Tax Expense

Income tax expense at the Illinois segment increased $8.4 million during 2019, compared with 2018, driven by an increase in pretax income.


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Other States Segment Contribution to Net Income Attributed to Common Shareholders

The other states segment's contribution to net income attributed to common shareholders for the year ended December 31, 2020 was $39.0 million, representing a $4.2 million, or 9.7%, decrease over the prior year. The decrease was driven by lower natural gas margins due to the negative impact warmer winter weather and COVID-19 had on 2020 sales volumes, as well as an increase in depreciation and amortization. These decreases in net income were partially offset by lower operating expense in 2020 due to effective cost control.

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


	Year Ended December 31						2020 vs. 2019		2019 vs. 2018
(in millions)	2020		2019		2018		B (W)		B (W)
Natural gas revenues	$	384.1	$	426.0	$	438.2	$	(41.9)	$	(12.2)
Cost of natural gas sold	184.8		217.5		232.8		32.7		15.3
Total natural gas margins	199.3		208.5		205.4		(9.2)		3.1

Other operation and maintenance	87.0		98.5		101.0		11.5		2.5
Depreciation and amortization	33.5		27.5		24.1		(6.0)		(3.4)
Property and revenue taxes	17.2		17.2		11.5		—		(5.7)
Operating income	61.6		65.3		68.8		(3.7)		(3.5)

Other income (expense), net	0.7		—		(0.1)		0.7		0.1
Interest expense	10.2		8.5		8.7		(1.7)		0.2
Income before income taxes	52.1		56.8		60.0		(4.7)		(3.2)

Income tax expense	13.1		13.6		15.9		0.5		2.3
Net income attributed to common shareholders	$	39.0	$	43.2	$	44.1	$	(4.2)	$	(0.9)

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


	Year Ended December 31						2020 vs. 2019		2019 vs. 2018
(in millions)	2020		2019		2018		B (W)		B (W)
Operation and maintenance not included in line items below	$	67.9	$	76.4	$	76.1	$	8.5	$	(0.3)
Regulatory amortizations and other pass through expenses (1)	18.9		22.0		24.8		3.1		2.8
Other	0.2		0.1		0.1		(0.1)		—
Total other operation and maintenance	$	87.0	$	98.5	$	101.0	$	11.5	$	2.5

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

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


	Year Ended December 31
	Therms (in millions)			2020 vs. 2019	2019 vs. 2018
Natural Gas Sales Volumes	2020	2019	2018	B (W)	B (W)
Customer Class
Residential	309.6	345.2	336.1	(35.6)	9.1
Commercial and industrial	200.5	238.2	218.5	(37.7)	19.7
Total retail	510.1	583.4	554.6	(73.3)	28.8
Transport	728.5	777.1	738.7	(48.6)	38.4
Total sales in therms	1,238.6	1,360.5	1,293.3	(121.9)	67.2


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	Year Ended December 31
	Degree Days			2020 vs. 2019		2019 vs. 2018
Weather (1)	2020	2019	2018	B (W)		B (W)
MERC
Heating (8,030 normal)	7,896	8,728	8,490	(9.5)	%	2.8	%

MGU
Heating (6,259 normal)	5,952	6,347	6,368	(6.2)	%	(0.3)	%

(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 territories.

2020 Compared with 2019

Natural Gas Utility Margins

Natural gas utility margins decreased $9.2 million during 2020, compared with 2019. The decrease was primarily driven by lower sales volumes as a result of warmer than normal winter weather in 2020 and impacts of the COVID-19 pandemic, partially offset by an increase in revenues related to MERC's GUIC rider. The GUIC rider allows MERC to recover previously approved GUIC that were 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. MERC began recognizing revenue under the GUIC rider in the second quarter of 2019.

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

Other operating expenses at the other states segment decreased $5.5 million during 2020, compared with 2019. The decrease in operating expenses was driven by effective cost control, partially offset by an increase in depreciation and amortization.

Interest Expense

Interest expense at the other states segment increased $1.7 million during 2020, compared with 2019, primarily due to 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 2020, compared with 2019, related to a decrease in pretax income.

2019 Compared with 2018

Natural Gas Utility Margins

Natural gas utility margins increased $3.1 million during 2019, compared with 2018. The increase was primarily driven by higher sales volumes as a result of colder weather and customer growth, capital investment in natural gas utility infrastructure, and MERC recognizing revenue under the GUIC rider. These increases were partially offset by volumetric bill credits MGU is required to provide customers under a MPUC order addressing the effects of the Tax Legislation to return tax savings from the ruling. See Note 16, Income Taxes, and Note 26, Regulatory Environment, for more information.

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 $6.6 million during 2019, compared with 2018. The increase in operating expenses was partially driven by lower property and revenue taxes in 2018 resulting from a favorable judgment that MERC received related to a property tax matter. Because property taxes were under-recovered from rate payers in prior years, MERC received $4.8 million of the judgment, with the remaining amount being passed back to customers through the property tax tracker.


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The increase was also driven by a $2.1 million positive impact on 2018 depreciation and amortization expense from a depreciation study approved by the MPUC in the second quarter of 2018. These rates were effective retroactively to January 2017.

Income Tax Expense

Income tax expense at the other states segment decreased $2.3 million during 2019, compared with 2018, related to a decrease in pretax income.

Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders


	Year Ended December 31						2020 vs. 2019		2019 vs. 2018
(in millions)	2020		2019		2018		B (W)		B (W)
Net income attributed to common shareholders	$	112.6	$	87.4	$	82.8	$	25.2	$	4.6

2020 Compared with 2019

Net income attributed to common shareholders at our electric transmission segment increased $25.2 million during 2020, compared with 2019, driven by a $48.2 million increase in equity earnings from transmission affiliates, primarily due to the impacts of FERC orders issued in November 2019 and May 2020 addressing complaints related to ATC's ROE. The FERC order issued in November 2019 reduced the base ROE that ATC was allowed to collect, which resulted in a $19.3 million decrease in ATC's earnings during 2019. The FERC order issued in May 2020 made additional revisions to the methodology used to calculate the base ROE, which resulted in an increase in the base ROE that ATC is allowed to collect, retroactive to November 2013, and increased ATC's earnings by $14.6 million during 2020. For further discussion of the FERC orders, see Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints. Continued capital investment by ATC also contributed to the higher equity earnings.

The increase in equity earnings from transmission affiliates was partially offset by:

A $16.6 million increase in income tax expense during 2020, compared with 2019, driven by a $10.9 million negative impact related to an increase in pretax income and changes in amortization of federal excess deferred income taxes.
A $6.3 million increase in interest expense, due to ATC Holding's issuance of $235.0 million of long-term debt in September 2019.

2019 Compared with 2018

Net income attributed to common shareholders at our electric transmission segment increased $4.6 million during 2019, compared with 2018, driven by a $26.6 million decrease in income tax expense. The decrease in income tax expense was driven by a $12.3 million tax basis adjustment related to the remeasurement of deferred income taxes in 2018 and a $6.1 million favorable impact of lower pretax income in 2019. Also contributing to the decrease was a $7.8 million decrease related to the change in the tax rates at the segment level resulting from the transfer of ownership in the ATC investment between our subsidiaries. The decrease in income tax expense related to the change in tax rates was offset in the corporate and other segment and, as a result, had no effect on consolidated net income attributed to common shareholders.

The increase in earnings from lower income tax expense was partially offset by:

A $12.8 million increase in interest expense, due to ATC Holding's issuance of $235.0 million and $240.0 million of long-term debt in September 2019 and December 2018, respectively.
A $9.1 million decrease in equity earnings from transmission affiliates, primarily related to the FERC order issued in November 2019 that addressed complaints related to ATC's allowed ROE, which resulted in a $19.3 million decrease in ATC's earnings. Increased earnings from continued capital investment partially offset the negative impact from the FERC order.

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


	Year Ended December 31						2020 vs. 2019		2019 vs. 2018
(in millions)	2020		2019		2018		B (W)		B (W)
Net income attributed to common shareholders	$	260.8	$	246.0	$	228.4	$	14.8	$	17.6


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2020 Compared with 2019

Net income attributed to common shareholders increased $14.8 million during 2020, compared with 2019, primarily related to a $15.2 million decrease in income tax expense during 2020, compared to 2019, driven by wind PTCs generated by our Coyote Ridge wind park that achieved commercial operation in December 2019. See Note 2, Acquisitions, and Note 16, Income Taxes, for more information.

2019 Compared with 2018

Net income attributed to common shareholders increased $17.6 million, primarily related to a $14.0 million decrease in income tax expense during 2019, compared to 2018, driven by wind PTCs recognized on the three wind parks acquired in 2018 and 2019. Also contributing to the increase in earnings was a $4.8 million increase in operating income at We Power, driven by higher revenues in connection with capital additions to the plants We Power owns and leases to WE. Partially offsetting these increases were $2.4 million of operating losses at the Upstream and Bishop Hill III wind parks. 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


	Year Ended December 31						2020 vs. 2019		2019 vs. 2018
(in millions)	2020		2019		2018		B (W)		B (W)
Net loss attributed to common shareholders	$	(106.4)	$	(62.8)	$	(60.1)	$	(43.6)	$	(2.7)

2020 Compared with 2019

The net loss attributed to common shareholders at the corporate and other segment increased $43.6 million during 2020, compared with 2019. The significant factors impacting the higher net loss were:

A $38.4 million loss related to the payment of make-whole premiums during 2020 due to the redemption of $1,030.0 million of long-term debt prior to maturity.
A $9.0 million higher net operating loss at Wispark, driven by reductions in the carrying value of certain real estate-related investments during 2020 as market and other factors indicated the assets may not be fully recoverable.
An $8.5 million decrease in other income, net due to lower net gains from investments held in the Integrys rabbi trust during 2020. These investment gains partially offset benefits costs related to deferred compensation, which are included in other operation and maintenance expense in our operating segments. See Note 17, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.
A $5.2 million decrease in interest income from subsidiaries in our operating segments. The decrease was driven by lower interest income from UMERC, as UMERC used the proceeds from its long-term debt issuance in August 2019 to redeem its outstanding long-term debt with WEC Energy Group.

These increases in the net loss attributed to common shareholders were partially offset by:

A $16.9 million decrease in interest expense, driven by the issuance of new debt in 2020 with lower interest rates than the debt retired during the year. Also contributing to the decrease was lower interest rates on our short-term and variable-rate long-term debt.
A $1.4 million increase in income tax benefits, driven by an $11.6 million favorable impact from a higher pre-tax loss. This increase in income tax benefits was offset by an $8.2 million change in unrecognized tax benefits during 2020, compared with 2019, and a $3.5 million decrease in excess tax benefits recognized related to stock option exercises during 2020, compared to 2019. See Note 16, Income Taxes, for more information.


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2019 Compared with 2018

The net loss attributed to common shareholders at the corporate and other segment increased $2.7 million during 2019, compared with 2018. The significant factors impacting the higher net loss were:

A $15.1 million increase in interest expense, primarily driven by higher long-term debt balances in 2019. The increase in debt balances was primarily related to continued capital investments across our segments.
A $12.2 million increase in the net operating loss, driven by a transfer of assets from WBS to our regulated utilities in 2018. As a result of these transfers, the return on these assets is now recognized within our regulated utility operations. Also contributing to the increase in the net operating loss was a gain recorded in 2018 that related to a previous sale of a legacy business.
A $1.2 million decrease in income tax benefits, driven by a $7.8 million benefit related to the change in the tax rates at the segment level resulting from the transfer of ownership of the ATC investment between our subsidiaries. This decrease was offset in the electric transmission segment and, as a result, had no effect on consolidated net income attributed to common shareholders. Also contributing to the decrease was $2.3 million related to year-over-year changes associated with state net operating losses. These decreases in income tax benefits were substantially offset by a $9.9 million increase in excess tax benefits recognized related to stock option exercises during 2019, compared to 2018.

These increases in the net loss attributed to common shareholders were largely offset by a $23.0 million increase in other income, net due to net gains from investments held in the Integrys rabbi trust during 2019, compared with net losses during 2018.

LIQUIDITY AND CAPITAL RESOURCES

The following discussion and analysis of our Liquidity and Capital Resources includes comparisons of our cash flows for the year ended December 31, 2020 with the year ended December 31, 2019. For a similar discussion that compares our cash flows for the year ended December 31, 2019 with the year ended December 31, 2018, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources in Part II of our 2019 Annual Report on Form 10-K.

Cash Flows

The following table summarizes our cash flows during the years ended December 31:


(in millions)	2020		2019		Change in 2020 Over 2019
Cash provided by (used in):
Operating activities	$	2,196.0	$	2,345.5	$	(149.5)
Investing activities	(2,806.8)		(2,494.9)		(311.9)
Financing activities	601.1		85.6		515.5

Operating Activities

2020 Compared with 2019

Net cash provided by operating activities decreased $149.5 million during 2020, compared with 2019, driven by:

A $209.3 million decrease in cash related to lower overall collections from customers, primarily due to business interruptions and closings during the COVID-19 pandemic and a moratorium on disconnections causing an increase in past due balances, as well as lower sales volumes driven by warmer winter weather during 2020, compared with 2019.
A $52.8 million net decrease in cash related to $27.9 million of cash paid for income taxes during 2020, compared with $24.9 million of cash received for income taxes during 2019. This decrease in cash was primarily due to alternative minimum tax credits that were refunded to us during 2019.
A $47.3 million decrease in cash related to an increase in contributions and payments related to pension and OPEB plans during 2020, compared with 2019.


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

A $109.0 million increase in cash related to lower payments for fuel used at our plants during 2020, compared with 2019, driven by lower natural gas costs. The average per-unit cost of natural gas decreased 9.7% during during 2020, compared with 2019. Lower fuel costs were also driven by lower sales volumes due to warmer winter weather during 2020 as well as business interruptions and closings during the COVID-19 pandemic.
A $33.5 million increase in cash due to lower collateral requirements, driven by an increase in the fair value of our natural gas derivative assets during 2020, compared with 2019.
A $22.8 million increase in cash due to higher distributions from ATC during 2020, compared with 2019.

Investing Activities

2020 Compared with 2019

Net cash used in investing activities increased $311.9 million during 2020, compared with 2019, driven by:

The acquisition of a 90% ownership interest in Blooming Grove in December 2020 for $364.6 million, which is net of restricted cash acquired of $24.1 million. See Note 2, Acquisitions, for more information.
The acquisition of an 85% ownership interest in Tatanka Ridge in December 2020 for $239.9 million. See Note 2, Acquisitions, for more information.
A $31.3 million decrease in cash related to lower reimbursements from ATC for construction costs during 2020, compared with 2019. See Note 21, Investment in Transmission Affiliates, for more information.
A $17.3 million decrease in proceeds received from the sale of assets and businesses during 2020, compared with 2019. See Note 3, Dispositions, for more information.

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

The acquisition of an 80% ownership interest in Upstream in January 2019 for $268.2 million, which is net of cash and restricted cash acquired of $9.2 million. See Note 2, Acquisitions, for more information.
A $31.4 million increase in cash related to lower capital contributions to transmission affiliates during 2020, compared with 2019. See Note 21, Investment in Transmission Affiliates, for more information.
A $23.2 million increase in cash related to insurance proceeds received for property damage during 2020. See Note 7, Property, Plant, and Equipment, for more information.
A $22.0 million decrease in cash paid for capital expenditures during 2020, compared with 2019, which is discussed in more detail below.
An $18.2 million net increase in restricted cash during 2020, compared with 2019, due to a $56.0 million increase in the proceeds received from the sale of investments held in the Integrys rabbi trust, partially offset by $37.8 million in purchases of investments held in the rabbi trust in 2020.


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Capital Expenditures

Capital expenditures by segment for the years ended December 31 were as follows:


Reportable Segment (in millions)	2020		2019		Change in 2020 Over 2019
Wisconsin	$	1,382.4	$	1,378.6	$	3.8
Illinois	652.7		624.9		27.8
Other states	144.3		109.1		35.2
Non-utility energy infrastructure	26.3		121.7		(95.4)
Corporate and other	33.1		26.5		6.6
Total capital expenditures	$	2,238.8	$	2,260.8	$	(22.0)

2020 Compared with 2019

The increase in cash paid for capital expenditures at the Wisconsin segment during 2020, compared with 2019, was primarily driven by an increase in capital expenditures related to Badger Hollow I, Badger Hollow II, the Solar Now program, and upgrades to WE's natural gas distribution system during 2020. These increases in cash paid for capital expenditures were partially offset by decreased capital expenditures related to Two Creeks, the construction of UMERC's natural gas-fired generation facilities in the Upper Peninsula of Michigan, upgrades to WG's natural gas distribution system, upgrades of automated meter reading devices, and various other software projects during 2020, compared with 2019.

The increase in cash paid for capital expenditures at the Illinois segment during 2020, compared with 2019, was driven by upgrades of automated meter reading devices, a higher number of meter replacements, and upgrades at the Manlove Gas Storage Field during 2020. These increases in cash paid for capital expenditures were partially offset by decreased capital expenditures on facilities projects in 2020.

The increase in cash paid for capital expenditures at the other states segment during 2020, compared with 2019, was primarily driven by MERC and MGU's installation of automated meter reading devices and a higher number of meter replacements during 2020. These increases in cash paid for capital expenditures were partially offset by decreased capital expenditures related to an expansion of MERC's gas distribution system during 2019.

The decrease in cash paid for capital expenditures at the non-utility energy infrastructure segment during 2020, compared with 2019, was primarily driven by the construction of Coyote Ridge, most of which occurred in 2019 subsequent to its acquisition, and projects completed at the ERGS during 2019. See Note 2, Acquisitions, for more information. These decreases in cash paid for capital expenditures were partially offset by an increase in capital expenditures related to a compressor project for Bluewater during 2020.

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

Financing Activities

2020 Compared with 2019

Net cash provided by financing activities increased $515.5 million during 2020, compared with 2019, driven by:

A $1,215.4 million increase in cash due to $606.1 million of net borrowings of commercial paper during 2020, compared with $609.3 million of net repayments of commercial paper during 2019.
A $478.6 million increase in cash due to higher issuances of long-term debt during 2020, compared with 2019.
A $340.0 million increase in cash due to the issuance of a 364-day term loan during 2020, to enhance our liquidity position in response to the COVID-19 pandemic. See Factors Affecting Results, Liquidity, and Capital Resources – Coronavirus Disease – 2019, for additional information.
A $40.9 million increase in cash due to a decrease in the number and cost of shares of our common stock purchased during 2020, compared with 2019, to satisfy requirements of our stock-based compensation plans.


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

A $1,406.9 million decrease in cash related to higher long-term debt repayments during 2020, compared with 2019.
A $53.5 million decrease in cash due to higher dividends paid on our common stock during 2020, compared with 2019. In January 2020, our Board of Directors increased our quarterly dividend by $0.0425 per share (7.2%) effective with the March 2020 dividend payment.
A $43.3 million decrease in cash due to the payment of make-whole premiums related to debt redemptions and higher issuance costs during 2020, compared with 2019.
The acquisition of an additional 10% ownership interest in Upstream in April 2020 for $31.0 million. See Note 2, Acquisitions, for more information.
A $23.2 million decrease in cash from stock options exercised during 2020, compared with 2019.

Significant Financing Activities

For more information on our financing activities, see Note 13, Short-Term Debt and Lines of Credit, and Note 14, 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 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. We expect to have sufficient liquidity to repay the term loan upon its maturity in March 2021. See Note 13, Short-Term Debt and Lines of Credit, for more information about these credit agreements.


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The following table shows our capitalization structure as of December 31, 2020 and 2019, 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:


	2020						2019
(in millions)	Actual			Adjusted			Actual			Adjusted
Common shareholders' equity	$	10,469.7		$	10,719.7		$	10,113.4		$	10,363.4
Preferred stock of subsidiary	30.4			30.4			30.4			30.4
Long-term debt (including current portion)	12,513.9			12,263.9			11,904.2			11,654.2
Short-term debt	1,776.9			1,776.9			830.8			830.8
Total capitalization	$	24,790.9		$	24,790.9		$	22,878.8		$	22,878.8

Total debt	$	14,290.8		$	14,040.8		$	12,735.0		$	12,485.0

Ratio of debt to total capitalization	57.6		%	56.6		%	55.7		%	54.6		%

Included in long-term debt on our balance sheets as of December 31, 2020 and 2019, 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.

For a summary of the interest rates, maturity, and amounts of long-term debt outstanding on a consolidated basis, see Note 14, Long-Term Debt.

As described in Note 11, Common Equity, certain restrictions exist on the ability of our subsidiaries to transfer funds to us. We do not expect these restrictions to have any material effect on our operations or ability to meet our cash obligations.

At December 31, 2020, we were in compliance with all covenants related to outstanding short-term and long-term debt. We expect to be in compliance with all such debt covenants for the foreseeable future. See Note 13, Short-Term Debt and Lines of Credit, and Note 14, Long-Term Debt, for more information.

Working Capital

As of December 31, 2020, our current liabilities exceeded our current assets by $2,065.1 million. 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.

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


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If we are unable to successfully take actions to continue to manage any impact from the COVID-19 pandemic, the credit rating agencies could place our or our 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.

See Factors Affecting Results, Liquidity, and Capital Resources – Coronavirus Disease – 2019, for additional information.

Capital Requirements

Contractual Obligations

We have the following contractual obligations and other commercial commitments as of December 31, 2020:


	Payments Due by Period (1)
(in millions)	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
Long-term debt obligations (2)	$	20,566.7	$	1,238.8	$	1,731.3	$	2,591.2	$	15,005.4
Finance lease obligations (3)	151.1		10.6		7.0		3.2		130.3
Operating lease obligations (4)	46.0		4.5		8.9		8.1		24.5
Energy and transportation purchase obligations (5)	10,979.4		1,179.6		2,127.1		1,613.6		6,059.1
Purchase orders (6)	849.2		430.6		280.3		67.8		70.5
Pension and OPEB funding obligations (7)	43.4		13.7		29.7		—		—

Total contractual obligations	$	32,635.8	$	2,877.8	$	4,184.3	$	4,283.9	$	21,289.8

(1) The amounts included in the table are calculated using current market prices, forward curves, and other estimates.

(2) Principal and interest payments on long-term debt (excluding finance lease obligations). The interest due on our variable rate debt is based on the interest rates that were in effect on December 31, 2020.

(3) Finance lease obligations for power purchase commitments and land leases related to solar projects. This amount does not include We Power leases to WE which are eliminated upon consolidation. See Note 15, Leases, for more information.

(4) Operating lease obligations for office space, land, and rail car leases. See Note 15, Leases, for more information.

(5) Energy and transportation purchase obligations under various contracts for the procurement of fuel, power, gas supply, and associated transportation related to utility and non-utility operations.

(6) Purchase obligations related to normal business operations, information technology, and other services. Also includes construction obligations related to Badger Hollow I and Badger Hollow II.

(7) Obligations for pension and OPEB plans cannot reasonably be estimated beyond 2023.

The table above does not include liabilities related to the accounting treatment for uncertainty in income taxes because we are not able to make a reasonably reliable estimate as to the amount and period of related future payments at this time. For additional information regarding these liabilities, refer to Note 16, Income Taxes.

The table above also does not reflect estimated future payments related to the manufactured gas plant remediation liability of $532.9 million at December 31, 2020, as the amount and timing of payments are uncertain. We expect to incur costs annually to remediate these sites. See Note 24, Commitments and Contingencies, for more information about environmental liabilities.

AROs in the amount of $513.5 million are not included in the above table. Settlement of these liabilities cannot be determined with certainty, but we believe the majority of these liabilities will be settled in more than five years. See Note 9, Asset Retirement Obligations, for more information.

Obligations for utility operations have historically been included as part of the rate-making process and therefore are generally recoverable from customers.


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Significant Capital Projects

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


(in millions)	2021		2022		2023
Wisconsin	$	1,763.4	$	1,844.6	$	2,070.2
Illinois	573.9		581.8		660.9
Other states	98.4		106.8		92.5
Non-utility energy infrastructure	640.0		504.9		434.1
Corporate and other	17.1		10.1		3.7
Total	$	3,092.8	$	3,048.2	$	3,261.4

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, and battery storage. Below are examples of renewable projects that are proposed or currently underway.

We have received approval to invest in 300 MW of utility-scale solar within our Wisconsin segment. WPS has partnered with an unaffiliated utility to construct two solar projects in Wisconsin. Two Creeks is located in Manitowoc County, Wisconsin, and Badger Hollow I is located in Iowa County, Wisconsin. WPS owns 100 MW of Two Creeks, which achieved commercial operation in November 2020, and will own 100 MW of Badger Hollow I for a total of 200 MW. Commercial operation is targeted for the second quarter of 2021 for Badger Hollow I. WPS's share of the cost of both projects is estimated to be approximately $260 million. 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 $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 features 200 MW of solar generation and 110 MW of battery storage. The joint applicants propose that WE would acquire a 75% ownership interest, WPS would acquire a 15% ownership interest, and the unaffiliated utility would acquire the remaining 10% ownership interest. If approved, WE and WPS' 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.
In February 2021, WE and WPS filed an application with the PSCW for approval to accelerate up to approximately $154 million in capital investments in BSGF and CCWP, to repower major components. Both projects are expected to be completed by the end of 2022.

WE is constructing 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 in a written order by the PSCW in June 2020, has been designated as the Lakeshore Lateral Project. The cost of the project is estimated to be between $174 and $180 million. Construction for the project began in December 2020, and the project is expected to be completed by the end of 2021.

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


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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 2022 is between $280 million and $300 million. See Note 26, Regulatory Environment, for more information on the SMP.

The non-utility energy infrastructure segment line item in the table above includes WECI's planned investment in Thunderhead. See Note 2, Acquisitions, for more information on this wind project.

We expect to provide total capital contributions to ATC (not included in the above table) of approximately $45 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, for information on the impacts to our capital projects as a result of the COVID-19 pandemic.

Common Stock Matters

For information related to our common stock matters, see Note 11, Common Equity.

On January 21, 2021, our Board of Directors increased our quarterly dividend to $0.6775 per share effective with the first quarter of 2021 dividend payment, an increase of 7.1%. This equates to an annual dividend of $2.71 per share. In addition, the Board of Directors affirmed our dividend policy that continues to target a dividend payout ratio of 65-70% of earnings.

Investments in Outside Trusts

We use outside trusts to fund our pension and certain OPEB obligations. These trusts had investments of approximately $4.2 billion as of December 31, 2020. These trusts hold investments that are subject to the volatility of the stock market and interest rates. We contributed $113.2 million and $65.9 million to our pension and OPEB plans in 2020 and 2019, respectively. Future contributions to the plans will be dependent upon many factors, including the performance of existing plan assets and long-term discount rates. For additional information, see Note 20, Employee Benefits.

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 13, Short-Term Debt and Lines of Credit, Note 19, Guarantees, and Note 23, Variable Interest Entities.

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

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 is still considerable uncertainty 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, such as travel bans and restrictions, quarantines, limitations on business operations, and the timing of widespread availability of the vaccines. Although the shelter-in-place orders that were in effect for our service territories have expired, other orders limiting the capacity of various businesses have been adopted in some jurisdictions. In addition, similar or more restrictive orders could be adopted in the future depending on how the virus continues to spread and/or mutate. The effects of the COVID-19 pandemic and related government responses have significantly disrupted economic activity in our service territories. See Item 1A. Risk Factors for more information on our risks related to the COVID-19 pandemic.


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Liquidity and Financial Markets

Volatility and uncertainty in the financial markets and global economy have impacted us in a number of ways. 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 have had 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.

In response to the factors discussed above, we have taken several steps to enhance our liquidity position. In March 2020, we entered into a $340 million, 364-day term loan, which was used to pay down commercial paper. Also, while not directly related to COVID-19, we have completed several long-term debt offerings and refinancings in 2020 in order to finance capital investment in accordance with our long-term capital plan and also to take advantage of the low interest rate environment. See Note 14, Long-Term Debt, for more information on recent borrowing activity.

Our overall liquidity position remains strong. As of December 31, 2020, we had approximately $1.4 billion available under our credit facilities, providing sufficient backing for our commercial paper program.

Pensions and Other Benefits

Our pension and OPEB plans were well funded at December 31, 2020, with total plan assets exceeding total benefit obligations by $273.9 million. There has been significant volatility in global capital markets during the COVID-19 pandemic, although the market losses seen during the early stages of the pandemic in the first quarter of 2020 reversed course throughout the remainder of the year in response to government stimulus and relief efforts and the gradual reopening of businesses. During the year ended December 31, 2020, we recognized a $451.2 million increase in the value of long-term investments held in our pension and OPEB plan trusts as gains recognized during the last three quarters of 2020 more than offset first quarter losses.

We could still see earnings volatility associated with certain other benefit plans that we maintain, primarily related to performance units that we grant to certain employees, and our deferred compensation plans. Certain of the liabilities associated with the deferred compensation plans are indexed to mutual funds and our common stock, and the liabilities associated with outstanding performance units are indexed to our common stock. These liabilities are marked to fair value through earnings each period, with earnings increasing as market prices decrease. Earnings volatility associated with our deferred compensation plans is partially mitigated by investments we hold in a rabbi trust.

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, could cause a higher percentage of 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 have experienced has resulted in higher working capital requirements. At December 31, 2020, accounts receivables, net of reserves for credit losses, that were greater than 90 days past due, totaled $122.8 million, a $38.6 million increase compared to December 31, 2019.

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 26, Regulatory Environment, for more information on these orders.


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Loss of Business

We have seen a decrease in the consumption of electricity and natural gas by some of our commercial and industrial customers as they continue to experience lower demand for their products and services as a result of the COVID-19 pandemic. Many businesses in our service territories still are not operating at full capacity. The extent to which this decrease in consumption will 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 has been impacted by the COVID-19 pandemic. The parties agreed to delay the expected commercial operation date from December 2020 to the second quarter of 2021 so that initial staffing increases could be minimized in light of state mandated COVID-19 orders. 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 activated 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.

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

Regulatory Environment

Our utilities have taken actions to ensure that essential utility services are available to customers in their service territories during the COVID-19 pandemic. In addition, the PSCW, the ICC, the MPUC, and the MPSC have all issued written orders regarding certain measures required in their respective jurisdictions. See Note 26, Regulatory Environment, for more information on these orders and the potential recovery of expenditures incurred as a result of the measures being 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, described in further detail below, include but are not limited to:

Regulatory Recovery

Our utilities account for their regulated operations in accordance with accounting guidance under the Regulated Operations Topic of the FASB ASC. Our rates are determined by various regulatory commissions. See Item 1. Business – E. Regulation for more information on these commissions.


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Regulated entities are allowed to defer certain costs that would otherwise be charged to expense if the regulated entity believes the recovery of those costs is probable. We record regulatory assets pursuant to generic and/or specific orders issued by our regulators. Recovery of the deferred costs in future rates is subject to the review and approval by those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of the deferred costs, including those referenced below, is not approved by our regulators, the costs would be charged to income in the current period. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities. As of December 31, 2020, our regulatory assets were $3,544.1 million, and our regulatory liabilities were $3,979.1 million.

Due to the Tax Legislation, our regulated utilities remeasured their deferred taxes and recorded a tax benefit of $2,529 million. Our utilities have been returning this tax benefit to ratepayers through refunds, bill credits, riders, and reductions to other regulatory assets, which we expect to continue. See Note 16, Income Taxes, and Note 26, Regulatory Environment, for more information.

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 December 31, 2020, we had not received any significant disallowances of the costs incurred for this project. WPS and MERC received approval to recover these costs in their most recent rate orders; however, the costs incurred for this project in our other regulatory jurisdictions are still subject to approval by the applicable regulators.
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 2020, PGL filed its 2019 reconciliation with the ICC, which, along with the 2018, 2017, and 2016 reconciliations, are still pending. As of December 31, 2020, 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 26, Regulatory Environment, for more information regarding recent and pending rate proceedings, orders, and investigations involving our utilities.

Commodity Costs

In the normal course of providing energy, we are subject to market fluctuations in the costs of coal, natural gas, purchased power, and fuel oil used in the delivery of coal. We manage our fuel and natural gas supply costs through a portfolio of short and long-term procurement contracts with various suppliers for the purchase of coal, natural gas, and fuel oil. In addition, we manage the risk of price volatility through natural gas and electric hedging programs.

Embedded within our utilities' rates are amounts to recover fuel, natural gas, and purchased power costs. Our utilities have recovery mechanisms in place that allow them to recover or refund all or a portion of the changes in prudently incurred fuel, natural gas, and purchased power costs from rate case-approved amounts. See Item 1. Business – E. Regulation for more information on these mechanisms.

Higher commodity costs can increase our working capital requirements, result in higher gross receipts taxes, and lead to increased energy efficiency investments by our customers to reduce utility usage and/or fuel substitution. Higher commodity costs combined with slower economic conditions also expose us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills. See Note 5, Credit Losses, for more information on riders and other mechanisms that allow for cost recovery or refund of uncollectible expense.

Due to the cold temperatures, wind, snow and ice throughout the central part of the country during February 2021, the cost of gas purchased for our natural gas utility customers was temporarily driven higher than our normal winter weather expectations. In aggregate, we estimate that the total increase was between $300 million and $350 million as of February 25, 2021. All of our utilities have regulatory mechanisms in place for recovering all prudently incurred gas costs. In addition, we have adequate liquidity and access to capital markets to manage any short-term increase in working capital resulting from the lag in recovery. For information on the GCRMs, see Note 1(d), Operating Revenues.


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Weather

Our utilities' rates are based upon estimated normal temperatures. Our electric utility margins are unfavorably sensitive to below normal temperatures during the summer cooling season and, to some extent, to above normal temperatures during the winter heating season. Our natural gas utility margins are unfavorably sensitive to above normal temperatures during the winter heating season. PGL, NSG, and MERC have decoupling mechanisms in place that help reduce the impacts of weather. Decoupling mechanisms differ by state and allow utilities to recover or refund certain differences between actual and authorized margins. A summary of actual weather information in our utilities' service territories during 2020 and 2019, as measured by degree days, may be found in Results of Operations.

Interest Rates

We are exposed to interest rate risk resulting from our short-term and long-term borrowings and projected near-term debt financing needs. We manage exposure to interest rate risk by limiting the amount of our variable rate obligations and continually monitoring the effects of market changes on interest rates. When it is advantageous to do so, we enter into long-term fixed rate debt. We may also enter into derivative financial instruments, such as swaps, to mitigate interest rate exposure.

Based on the variable rate debt outstanding at December 31, 2020 and December 31, 2019, a hypothetical increase in market interest rates of one percentage point would have increased annual interest expense by $20.3 million and $10.8 million in 2020 and 2019, respectively. This sensitivity analysis was performed assuming a constant level of variable rate debt during the period and an immediate increase in interest rates, with no other changes for the remainder of the period.

Marketable Securities Return

We use various trusts to fund our pension and OPEB obligations. These trusts invest in debt and equity securities. Changes in the market prices of these assets can affect future pension and OPEB expenses. Additionally, future contributions can also be affected by the investment returns on trust fund assets. We believe that the financial risks associated with investment returns would be partially mitigated through future rate actions by our various utility regulators.

The fair value of our trust fund assets and expected long-term returns were approximately:


(in millions)	As of December 31, 2020		Expected Return on Assets in 2021
Pension trust funds	$	3,225.0	6.87	%
OPEB trust funds	$	951.4	7.00	%

Fiduciary oversight of the pension and OPEB trust fund investments is the responsibility of an Investment Trust Policy Committee. The Committee works with external actuaries and investment consultants on an ongoing basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target asset allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. The targeted asset allocations are intended to reduce risk, provide long-term financial stability for the plans, and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments. Investment strategies utilize a wide diversification of asset types and qualified external investment managers.

We consult with our investment advisors on an annual basis to help us forecast expected long-term returns on plan assets by reviewing actual historical returns and calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the funds.

Economic Conditions

We have electric and natural gas utility operations that serve customers in Wisconsin, Illinois, Minnesota, and Michigan. As such, we are exposed to market risks in the regional Midwest economy. In addition, any economic downturn or disruption of national or international markets could adversely affect the financial condition of our customers and demand for their products, which could affect their demand for our products.


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Inflation

We continue to monitor the impact of inflation, especially with respect to the costs of medical plans, fuel, transmission access, construction costs, and regulatory and environmental compliance in order to minimize its effects in future years through pricing strategies, productivity improvements, and cost reductions. We do not believe the impact of general inflation will have a material impact on our future results of operations.

For additional information concerning risk factors, including market risks, see the Cautionary Statement Regarding Forward-Looking Information at the beginning of this report and Item 1A. Risk Factors.

Competitive Markets

Electric Utility Industry

The FERC supports large RTOs, which directly impacts the structure of the wholesale electric market. Due to the FERC's support of RTOs, MISO uses the MISO Energy Markets to carry out its operations, including the use of LMP to value electric transmission congestion and losses. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant and adverse financial impact on us. It is uncertain when, if at all, retail choice might be implemented in Wisconsin. However, Michigan has adopted a limited retail choice program.

Wisconsin

Electric utility revenues in Wisconsin are regulated by the PSCW. The PSCW continues to maintain the position that the question of whether to implement electric retail competition in Wisconsin should ultimately be decided by the Wisconsin legislature. No such legislation has been introduced in Wisconsin to date.

Michigan

Under Michigan law, our retail customers may choose an alternative electric supplier to provide power supply service. As a result, some of our small retail customers have switched to an alternative electric supplier. At December 31, 2020, Michigan law limited customer choice to 10% of an electric utility's Michigan retail load. Our iron ore mine customer, Tilden, is exempt from this 10% cap based on current law, but Tilden is required under a long-term agreement to purchase electric power from UMERC through March 2039. In addition, certain load increases by facilities already using an alternative electric supplier can still be serviced by their alternative electric supplier, when various conditions exist, even if the cap has already been met. When a customer switches to an alternative electric supplier, we continue to provide distribution and customer service functions for the customer.

Natural Gas Utility Industry

We offer natural gas transportation services to our customers that elect to purchase natural gas directly from a third-party supplier. Since these transportation customers continue to use our distribution systems to transport natural gas to their facilities, we earn distribution revenues from them. As such, the loss of revenue associated with the cost of natural gas that our transportation customers purchase from third-party suppliers has little impact on our net income, as it is substantially offset by an equal reduction to natural gas costs.

Wisconsin

Our Wisconsin utilities offer both natural gas transportation service and interruptible natural gas sales to enable customers to better manage their energy costs. Customers continue to switch between firm system supply, interruptible system supply, and transportation service each year as the economics and service options change. Due to the PSCW's previous proceedings on natural gas industry regulation in a competitive environment, the PSCW currently provides all Wisconsin customer classes with competitive markets the option to choose a third-party natural gas supplier. All of our Wisconsin customer classes have competitive market choices and, therefore, can purchase natural gas directly from either a third-party supplier or their local natural gas utility. Since third-party suppliers can be used in Wisconsin, the PSCW has also adopted standards for transactions between a utility and its natural gas marketing affiliates. We are currently unable to predict the impact, if any, of potential future industry restructuring on our results of operations or financial position.


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Illinois

Absent extraordinary circumstances, potential competitors are not allowed to construct competing natural gas distribution systems in the service territories for PGL and NSG. A charter from the state of Illinois gives PGL the right to provide natural gas distribution service in the city of Chicago as a public utility. Further, the "first in the field" and public interest standards limit the ability of potential competitors to operate in an existing utility service territory. In addition, we believe it would be impractical to construct competing duplicate distribution facilities due to the high cost of installation.

Since 2002, PGL and NSG have, under ICC-approved tariffs, provided their customers with the option to choose a third-party natural gas supplier. There are no state laws requiring PGL and NSG to make this choice option available to customers, but since this option is currently provided to our Illinois customers under tariff, we would need ICC approval to eliminate it.

An interstate pipeline may seek to provide transportation service directly to our Illinois end users, which would bypass our natural gas transportation service. However, PGL and NSG have bypass tariffs approved by the ICC, which allow them to negotiate rates with customers that are potential bypass candidates to help ensure that such customers continue to use their transportation service.

Minnesota

Natural gas utilities in the state of Minnesota do not have exclusive franchise service territories and, as a matter of law and policy, natural gas utilities may compete for new customers. However, natural gas utilities have customarily avoided competing for existing customers of other utilities, as there would be duplicative utility facilities and/or increased costs to customers. If this approach were to change, it could lead to a greater level of competition amongst utilities to obtain customers.

MERC offers both natural gas transportation service and interruptible natural gas sales to enable customers to better manage their energy costs. Customers continue to switch between firm system supply, interruptible system supply, and transportation service each year as the economics and service options change. MERC has provided its commercial and industrial customers with the option to choose a third-party natural gas supplier since 2006. We are not required by the MPUC or state law to make this choice option available to customers, but since this option is currently provided to our Minnesota commercial and industrial customers, we would need MPUC approval to eliminate it.

Michigan

The option to choose a third-party natural gas supplier has been provided to UMERC’s natural gas customers (formerly WPS’s Michigan natural gas customers) since the late 1990s and MGU's customers since 2005. We are not required by the MPSC or state law to make this choice option available to customers, but since this option is currently provided to our Michigan customers, we would need MPSC approval to eliminate it.

Environmental Matters

See Note 24, 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

Tax Cuts and Jobs Act of 2017

In December 2017, the Tax Legislation was signed into law. During 2018, 2019, and 2020, the PSCW and the MPSC issued written orders regarding how to refund certain tax savings from the Tax Legislation to our ratepayers in Wisconsin and Michigan, respectively. The various remaining impacts of the Tax Legislation on our Wisconsin operations were addressed in the rate orders issued by the PSCW in December 2019. The MPSC also approved a settlement in May 2018 with Tilden that addressed all base rate impacts of the Tax Legislation, and the FERC approved the revised formula rate tariffs for WPS and WE that incorporated the impacts on the Tax Legislation in July 2019 and August 2020, respectively. In addition, the ICC approved the VITA in Illinois during April 2018, and, in Minnesota, the MPUC included the various impacts of the Tax Legislation in MERC's final 2018 rate order. See Note 26, Regulatory Environment, for more information on the state commissions' responses to the Tax Legislation.


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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 MISO transmission owners to collect a reduced base ROE of 10.32%, as well as the 0.5% incentive adder approved by the FERC in January 2015 for MISO transmission owners. 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 the 0.5% ROE incentive adder, which 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 the 0.5% ROE incentive adder.

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 refunds related to the transmission costs they paid during the two refund periods through the end of September 2021. 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 0.5% incentive 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 0.5% incentive adder 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.


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Critical Accounting Policies and Estimates

Preparation of financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges, and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions. In addition, the financial and operating environment may also have a significant effect, not only on the operation of our business, but on our results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied have not changed.

The following is a list of accounting policies that are most significant to the portrayal of our financial condition and results of operations and that require management's most difficult, subjective, or complex judgments.

Regulatory Accounting

Our utility operations follow the guidance under the Regulated Operations Topic of the FASB ASC (Topic 980). Our financial statements reflect the effects of the rate-making principles followed by the various jurisdictions regulating us. Certain items that would otherwise be immediately recognized as revenues and expenses are deferred as regulatory assets and regulatory liabilities for future recovery or refund to customers, as authorized by our regulators.

Future recovery of regulatory assets, including the timeliness of recovery and our ability to earn a reasonable return, is not assured and is generally subject to review by regulators in rate proceedings for matters such as prudence and reasonableness. Once approved, the regulatory assets and liabilities are amortized into earnings over the rate recovery or refund period. If recovery or refund of costs is not approved or is no longer considered probable, these regulatory assets or liabilities are recognized in current period earnings. Management regularly assesses whether these regulatory assets and liabilities are probable of future recovery or refund by considering factors such as changes in the regulatory environment, earnings from our electric and natural gas utility operations, and the status of any pending or potential deregulation legislation.

The application of the Regulated Operations Topic of the FASB ASC would be discontinued if all or a separable portion of our utility operations no longer met the criteria for application. Our regulatory assets and liabilities would be written off to income as an unusual or infrequently occurring item in the period in which discontinuation occurred. As of December 31, 2020, we had $3,544.1 million in regulatory assets and $3,979.1 million in regulatory liabilities. See Note 6, Regulatory Assets and Liabilities, for more information.

Goodwill

We completed our annual goodwill impairment tests for all of our reporting units that carried a goodwill balance as of July 1, 2020. No impairments were recorded as a result of these tests. For all of our reporting units, the fair values calculated in step one of the test were greater than their carrying values. The fair values for the reporting units were calculated using a combination of the income approach and the market approach.

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

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

For the market approach, we used 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


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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.

Our reporting units had the following goodwill balances at July 1, 2020:


(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	%
Non-utility energy infrastructure	6.6		0.2	%
Total goodwill	$	3,052.8	100.0	%

See Note 10, Goodwill and Intangibles, for more information.

Long-Lived Assets

In accordance with ASC 980-360, Regulated Operations – Property, Plant, and Equipment, we periodically assess the recoverability of certain long-lived assets when events or changes in circumstances indicate that the carrying amount of those long-lived assets may not be recoverable. Examples of events or changes in circumstances include, but are not limited to, a significant decrease in the market price, a significant change in use, adverse legal factors or a change in business climate, operating or cash flow losses, or an expectation that the asset might be sold. These assessments require significant assumptions and judgments by management. Long-lived assets that would be subject to an impairment assessment would generally include any assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future, and assets within nonregulated operations that are proposed to be sold or are currently generating operating losses.

In accordance with ASC 980-360, when it becomes probable that a generating unit will be retired before the end of its useful life, we assess whether the generating unit meets the criteria for abandonment accounting. Generating units that are considered probable of abandonment are expected to cease operations in the near term, significantly before the end of their original estimated useful lives. As a result, the remaining net book value of these assets can be significant. If a generating unit meets applicable criteria to be considered probable of abandonment, and the unit has been abandoned, we assess the likelihood of recovery of the remaining net book value of that generating unit at the end of each reporting period. If it becomes probable that regulators will disallow full recovery or a return on the remaining net book value of a generating unit that is either abandoned or probable of being abandoned, an impairment loss may be required. An impairment loss would be recorded if the remaining net book value of the generating unit is greater than the present value of the amount expected to be recovered from ratepayers.

The Pleasant Prairie power plant, Pulliam Units 7 and 8, and the jointly-owned Edgewater 4 generating unit were retired during 2018. PIPP was retired during 2019. Effective with the rate orders issued by the PSCW in December 2019, WE and WPS received approval to collect a return of and on the entire net book value of the retired generating units, excluding the Pleasant Prairie power plant. WE will collect a full return of the net book value of the Pleasant Prairie power plant, and a return on all but $100 million of the net book value. In accordance with its PSCW rate order received in December 2019, WE filed an application with the PSCW on July 20, 2020 requesting a financing order to securitize the remaining $100 million of the Pleasant Prairie power plant's book value related to certain environmental controls, plus the carrying costs accrued on the $100 million during the securitization process and related fees. On November 17, 2020, the PSCW issued a written order approving the application. See Note 6, Regulatory Assets and Liabilities, and Note 26, Regulatory Environment, for more information on our retired generating units, including various approvals we received from the FERC and the PSCW.


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Pension and Other Postretirement Employee Benefits

The costs of providing non-contributory defined pension benefits and OPEB, described in Note 20, Employee Benefits, are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.

Pension and OPEB costs are impacted by actual employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans, and earnings on plan assets. Pension and OPEB costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, mortality and discount rates, and expected health care cost trends. Changes made to the plan provisions may also impact current and future pension and OPEB costs.

Pension and OPEB plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity and fixed income market returns, as well as changes in general interest rates, may result in increased or decreased benefit costs in future periods. We believe that such changes in costs would be recovered or refunded at our utilities through the rate-making process.

The following table shows how a given change in certain actuarial assumptions would impact the projected benefit obligation and the reported net periodic pension cost. Each factor below reflects an evaluation of the change based on a change in that assumption only.


Actuarial Assumption (in millions, except percentages)	Percentage-Point Change in Assumption	Impact on Projected Benefit Obligation		Impact on 2020 Pension Cost
Discount rate	(0.5)	$	232.2	$	21.7
Discount rate	0.5	(198.7)		(17.8)
Rate of return on plan assets	(0.5)	N/A		13.7
Rate of return on plan assets	0.5	N/A		(13.7)

The following table shows how a given change in certain actuarial assumptions would impact the accumulated OPEB obligation and the reported net periodic OPEB cost. Each factor below reflects an evaluation of the change based on a change in that assumption only.


Actuarial Assumption (in millions, except percentages)	Percentage-Point Change in Assumption	Impact on Postretirement Benefit Obligation		Impact on 2020 Postretirement Benefit Cost
Discount rate	(0.5)	$	36.0	$	3.9
Discount rate	0.5	(31.2)		(3.3)
Health care cost trend rate	(0.5)	(18.8)		(4.1)
Health care cost trend rate	0.5	21.6		4.7
Rate of return on plan assets	(0.5)	N/A		4.3
Rate of return on plan assets	0.5	N/A		(4.3)

The discount rates are selected based on hypothetical bond portfolios consisting of noncallable, high-quality corporate bonds across the full maturity spectrum. From the hypothetical bond portfolios, a single rate is determined that equates the market value of the bonds purchased to the discounted value of the plans' expected future benefit payments.

We establish our expected return on assets based on consideration of historical and projected asset class returns, as well as the target allocations of the benefit trust portfolios. The assumed long-term rate of return on pension plan assets was 6.87% in 2020, and 7.12% in 2019 and 2018. The actual rate of return on pension plan assets, net of fees, was 12.65%, 18.89%, and (4.30)%, in 2020, 2019, and 2018, respectively.

In selecting assumed health care cost trend rates, past performance and forecasts of health care costs are considered. For more information on health care cost trend rates and a table showing future payments that we expect to make for our pension and OPEB, see Note 20, Employee Benefits.

Unbilled Revenues

We record utility operating revenues when energy is delivered to our customers. However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month. At the


2020 Form 10-K			76			WEC Energy Group, Inc.

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end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated. This unbilled revenue is estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses, and applicable customer rates. Significant fluctuations in energy demand for the unbilled period or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. Total utility operating revenues during 2020 of approximately $7.2 billion included unbilled utility revenues of $499.5 million as of December 31, 2020.

Income Tax Expense

We are required to estimate income taxes for each of the jurisdictions in which we operate as part of the process of preparing consolidated financial statements. This process involves estimating current income tax liabilities together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for income tax and accounting purposes. These differences result in deferred income tax assets and liabilities, which are included within our balance sheets. We also assess the likelihood that our deferred income tax assets will be recovered through future taxable income. To the extent we believe that realization is not likely, we establish a valuation allowance, which is offset by an adjustment to income tax expense in our income statements.

Uncertainty associated with the application of tax statutes and regulations and the outcomes of tax audits and appeals requires that judgments and estimates be made in the accrual process and in the calculation of effective tax rates. Only income tax benefits that meet the "more likely than not" recognition threshold may be recognized or continue to be recognized. Unrecognized tax benefits are re-evaluated quarterly and changes are recorded based on new information, including the issuance of relevant guidance by the courts or tax authorities and developments occurring in the examinations of our tax returns.

Significant management judgment is required in determining our provision for income taxes, deferred income tax assets and liabilities, the liability for unrecognized tax benefits, and any valuation allowance recorded against deferred income tax assets. The assumptions involved are supported by historical data, reasonable projections, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. Significant changes in these assumptions could have a material impact on our financial condition and results of operations. See Note 1(q), Income Taxes, and Note 16, Income Taxes, for a discussion of accounting for income taxes.

We expect our 2021 annual effective tax rate to be between 13% and 14%, which includes an estimated 6% 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% and 20%.

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