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.

In August 2019, WECI signed an agreement to acquire an 80% ownership interest in Thunderhead Wind Energy LLC, a 300 MW wind generating facility under construction in Antelope and Wheeler counties in Nebraska. In January 2020, WECI signed an agreement to acquire an 80% ownership interest in Blooming Grove Wind Energy Center LLC, a 250 MW wind generating facility under construction in McLean County, Illinois. See Note 2, Acquisitions, for more information.

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: reliability; operating efficiency; financial discipline; customer care; and safety.

Reshaping Our Generation Fleet

The planned reshaping of our generation fleet balances reliability and customer cost with environmental stewardship. Taken as a whole, this plan should reduce costs to customers, preserve fuel diversity, and lower carbon emissions. Generation reshaping includes retiring older fossil fuel generation units, building state-of-the-art natural gas generation, and investing in cost-effective zero-carbon generation. In 2019, we met and exceeded our 2030 goal of reducing CO2 emissions by 40% below 2005 levels, and are re-evaluating our longer-term CO2 reduction goals. We have already retired more than 1,800 MW of coal-fired generation since the beginning of 2018, and expect to continue adding natural gas-fired generating units and renewable generation, including utility-scale solar projects. The plan included the March 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, Property, Plant, and Equipment, for more information related to these power plant retirements.

As part of our commitment to invest in zero-carbon generation, we have either filed for or 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. Badger Hollow Solar Farm I is located in Iowa County, Wisconsin, and the Two Creeks Solar Project is located in Manitowoc County, Wisconsin. Once constructed, WPS will own 100 MW of the output of each project for a total of 200 MW. The Public Service Commission of Wisconsin (PSCW) approved the acquisition of these two projects in April 2019. Construction began at the Two Creeks Solar Project and the Badger Hollow Solar Farm I in August 2019 and October 2019, respectively. Commercial operation of both projects is targeted for the end of 2020. Wisconsin Electric Power Company (WE) has partnered with an unaffiliated utility to acquire an ownership interest in a proposed solar project, Badger Hollow Solar Farm II, that will be located in Iowa County, Wisconsin. At its meeting on February 20, 2020, the PSCW approved the acquisition of this project. The approval is still subject to WE's receipt and review of a final written order from the PSCW. Once constructed, WE will own 100 MW of the output of this project. Commercial operation of Badger Hollow Solar Farm II is targeted for the end of 2021.

In December 2018, WE received approval from the 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 government entities, as well as commercial and industrial customers to site utility owned solar arrays on their property. Under this program, in 2019, WE constructed 5 MW of solar generation and expects to construct more than double that amount in 2020. 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 allowing these larger customers to meet their sustainability and renewable energy goals.

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As the cost of renewable energy generation continues to decline, these utility-scale solar projects and the WE pilot programs have become cost effective opportunities for WEC Energy Group and our customers to participate in renewable energy.

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

Reliability

We have made significant reliability-related investments in recent years, and plan 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 and WPS being recognized by PA Consulting Group, an independent consulting firm, for superior reliability of their electric delivery networks. This is the ninth consecutive year that We Energies has been named the most reliable utility in the Midwest and the first time WPS has been recognized.

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

•WE and Wisconsin Gas LLC (WG) each plan to construct their own LNG facility. Subject to PSCW approval, each facility would provide approximately one billion cubic feet of natural gas supply to meet anticipated peak demand without requiring the construction of additional interstate pipeline capacity. These facilities are expected to reduce the likelihood of constraints on WE's and WG's natural gas systems during the highest demand days of winter. 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 cast and ductile 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. The project focuses on constructing facilities to improve the reliability of electric service WPS provides to its customers. WE, WPS, and WG also continue to upgrade their electric and natural gas distribution systems to enhance reliability.

Operating Efficiency

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

We continue to focus on integrating resources of all our businesses and finding the best and most efficient processes while meeting all applicable legal and regulatory requirements. We also strive to provide the best value to our customers and shareholders by embracing constructive change, leveraging capabilities and expertise, and using creative solutions to meet or exceed our customers' expectations.

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 2, Acquisitions, for information about our acquisitions of portions of wind energy generation facilities in Wisconsin, Illinois, Nebraska, and South Dakota.
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•See Note 3, Dispositions, for information on recent dispositions. In the first quarter of 2017, we sold substantially all of the remaining assets of Bostco LLC, and, in October 2018, Bostco was dissolved. In 2019, we sold 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. We expect total capital expenditures for our regulated utility and non-utility energy infrastructure businesses to be approximately $13.7 billion from 2020 to 2024. Specific projects are discussed in more detail below under Liquidity and Capital Resources.

From 2020 to 2024, we expect capital contributions to ATC to be approximately $150 million. Capital investments at ATC will be funded utilizing these capital contributions, in addition to cash generated by ATC from operations and debt. We currently forecast that our share of ATC's projected capital expenditures over the next five years will be $1.3 billion.

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 embracing constructive change, demonstrating personal responsibility for results, leveraging our capabilities and expertise, and using creative solutions to meet or exceed our customers’ expectations.

Safety

We have a long-standing commitment to both workplace and public safety, and 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.

RESULTS OF OPERATIONS

The following discussion and analysis of our Results of Operations includes comparisons of our results for the year ended December 31, 2019 with the year ended December 31, 2018. For a similar discussion that compares our results for the year ended December 31, 2018 with the year ended December 31, 2017, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations in Part II of our 2018 Annual Report on Form 10-K.

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Consolidated Earnings

The following table compares our consolidated results for the year ended December 31, 2019 with the year ended December 31, 2018, including favorable or better, "B", and unfavorable or worse, "W", variances:

Year Ended December 31
(in millions, except per share data)20192018B (W)Change Related to Flow Through of Tax RepairsChange Related to Adoption of New Lease Guidance (Topic 842)Remaining Change B (W)
Wisconsin$1,189.6$800.2$389.4$(3.1)$350.9$41.6
Illinois291.9255.836.1——36.1
Other states65.368.8(3.5)——(3.5)
Non-utility energy infrastructure366.6365.80.8——0.8
Corporate and other(34.4)(22.2)(12.2)——(12.2)
Reconciling eliminations *(347.6)—(347.6)—(347.6)—
Total operating income1,531.41,468.463.0(3.1)3.362.8
Equity in earnings of transmission affiliates127.6136.7(9.1)——(9.1)
Other income, net102.270.331.9——31.9
Interest expense501.5445.1(56.4)—(3.3)(53.1)
Income before income taxes1,259.71,230.329.4(3.1)—32.5
Income tax expense125.0169.844.83.1—41.7
Preferred stock dividends of subsidiary1.21.2————
Net loss attributed to noncontrolling interests0.5—0.5——0.5
Net income attributed to common shareholders$1,134.0$1,059.3$74.7$—$—$74.7
Diluted earnings per share$3.58$3.34$0.24
*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, during 2019, $347.6 million of minimum lease payments that were billed from We Power to WE were no longer classified within operation and maintenance, but were instead recorded as 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.

Earnings increased $74.7 million during 2019, compared with 2018. The table above shows the income statement impacts associated with the flow through of tax repairs beginning January 1, 2018 and the adoption of Topic 842, effective January 1, 2019. As shown in the table above, the changes related to these items had no impact on net income attributed to common shareholders.

The significant factors impacting the $74.7 million increase in earnings were:

•A $41.7 million remaining decrease in income tax expense, primarily due to an increase in wind production tax credits related to acquisitions of ownership interests in wind generation facilities in our non-utility energy infrastructure segment and the impact of the 2018 PSCW order regarding the benefits associated with the Tax Legislation. The impacts from the 2018 PSCW order related to the Tax Legislation were offset in operating income at the Wisconsin segment. See Note 2, Acquisitions, for more information on the acquisitions in our non-utility energy infrastructure segment.
•A $41.6 million remaining increase in operating income 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; higher depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan; and the impact from the PSCW's 2018 order addressing the Tax Legislation, which was offset in income tax expense.
•A $36.1 million increase in operating income at the Illinois segment. The increase was driven by higher natural gas margins at PGL due to continued capital investment in the SMP project under its QIP rider.
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•A $31.9 million increase in other income, net, driven by net gains from investments held in the Integrys rabbi trust during 2019, compared with net losses during 2018. These investment gains partially offset benefits costs related to deferred compensation, which are included in other operation and maintenance expense. See Note 16, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust. Also contributing to the increase was higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 19, Employee Benefits, for more information on our benefit costs.

These increases in earnings were partially offset by:

•A $53.1 million remaining increase in interest expense, driven by higher long-term debt balances, primarily used to fund capital investments.
•A $12.2 million increase in operating loss at the corporate and other segment, primarily driven by the transfer of assets from WBS, our centralized services company, 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 operating loss was a gain recorded in the third quarter of 2018 that related to the sale of a legacy business.
•A $9.1 million decrease in earnings from our ownership interests in transmission affiliates, driven by the impact of a FERC order issued in November 2019 that addressed complaints related to ATC's allowed ROE. Increased earnings from continued capital investment partially offset the negative impact from the FERC order.

Non-GAAP Financial Measures

The discussions below address the operating income contribution of each of our segments and 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 our segment operating performance. Operating income for each of the last two fiscal years for each of our segments is presented in the “Consolidated Earnings” table above.

Each applicable segment operating income discussion below includes a table that provides the calculation of electric margins and natural gas margins, as applicable, along with a reconciliation to segment operating income.

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Wisconsin Segment Contribution to Operating Income

Year Ended December 31
(in millions)20192018B (W)
Electric revenues$4,317.6$4,438.9$(121.3)
Fuel and purchased power1,341.91,418.176.2
Total electric margins2,975.73,020.8(45.1)
Natural gas revenues1,329.51,355.8(26.3)
Cost of natural gas sold748.0792.144.1
Total natural gas margins581.5563.717.8
Total electric and natural gas margins3,557.23,584.5(27.3)
Other operation and maintenance1,591.32,076.1484.8
Depreciation and amortization617.0546.6(70.4)
Property and revenue taxes159.3161.62.3
Operating income$1,189.6$800.2$389.4

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

Year Ended December 31
(in millions)20192018B (W)
Operation and maintenance not included in line items below$670.7$769.5$98.8
We Power (1)140.9506.9366.0
Transmission (2)418.1420.72.6
Transmission expense related to the flow through of tax repairs (3)67.277.810.6
Transmission expense related to Tax Legislation (4)65.367.72.4
Regulatory amortizations and other pass through expenses (5)160.6159.1(1.5)
Earnings sharing mechanisms (6)61.567.56.0
Other7.06.9(0.1)
Total other operation and maintenance$1,591.3$2,076.1$484.8
(1)Represents costs associated with the We Power generation units, including operating and maintenance costs incurred 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, during 2019, $363.3 million of lease expense related to the We Power leases with WE was no longer classified within other operation and maintenance, but was instead recorded as $15.8 million and $347.5 million of depreciation and amortization and interest expense, respectively, 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 2019, $134.8 million of operating and maintenance 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. During 2018, $485.3 million of both lease and operating and maintenance 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.

(2)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 differences between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During 2019 and 2018, $486.7 million and $438.2 million, respectively, of costs were billed to our electric utilities by transmission providers.
(3)Represents additional transmission expense 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. See Note 25, Regulatory Environment, for more information. The decrease in transmission expense associated with the flow through of tax benefits is offset in income taxes.
(4)Represents additional transmission expense 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. See Note 25, Regulatory Environment, for more information.
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(5)Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income.
(6)See Note 25, 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)
Electric Sales Volumes20192018B (W)
Customer class
Residential10,918.611,195.0(276.4)
Small commercial and industrial *12,861.013,186.7(325.7)
Large commercial and industrial *12,601.612,946.5(344.9)
Other164.8169.0(4.2)
Total retail *36,546.037,497.2(951.2)
Wholesale3,314.33,612.7(298.4)
Resale6,006.06,019.3(13.3)
**Total sales in MWh ***45,866.347,129.2(1,262.9)
*Includes distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.
Year Ended December 31
Therms (in millions)
Natural Gas Sales Volumes20192018B (W)
Customer class
Residential1,195.61,131.164.5
Commercial and industrial740.9733.17.8
Total retail1,936.51,864.272.3
Transport1,426.11,411.514.6
Total sales in therms3,362.63,275.786.9
Year Ended December 31
Degree Days
Weather20192018B (W)
WE and WG (1)
Heating (6,556 normal)6,8356,6852.2%
Cooling (739 normal)727929(21.7)%
WPS (2)
Heating (7,381 normal)7,7237,5542.2%
Cooling (514 normal)504678(25.7)%
UMERC (3)
Heating (8,382 normal)8,9718,6114.2%
Cooling (333 normal)284478(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.
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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 25, 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 15, Income Taxes, and Note 25, 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 generation solution 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 generation solution is being recovered from Tilden under this new agreement.
•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 generation solution in the Upper Peninsula of Michigan on March 31, 2019. UMERC previously met its market obligations through power purchase agreements.

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.

Operating Income

Operating income at the Wisconsin segment increased $389.4 million during 2019, compared with 2018. This increase was driven by $416.7 million of lower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes), partially offset by the $27.3 million net decrease in margins discussed above.

The utility 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 resulting from the adoption of the new lease guidance. As discussed in the other operation and maintenance table above, the adoption of Topic 842, effective January 1, 2019, required WE to change the income statement classification of its lease payments related to the We Power leases. During 2019, the minimum lease payments that were billed from We Power to WE were no longer classified within other operation and
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maintenance, but were instead recorded as a component of depreciation and amortization and interest expense in accordance with Topic 842.

•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 6, Property, Plant, and Equipment, for more information on the plant retirements. See Note 25, Regulatory Environment, for more information on the Wisconsin rate orders.
•A $10.6 million decrease in transmission expense in 2019 related to the flow through of tax repairs, as discussed in 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 25, 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, an increase related to the reduction of certain regulatory assets as a result of the PSCW's May 2018 order addressing the Tax legislation and offset in electric margins above, and additional expense recognized related to the adoption of Topic 842, as discussed in the notes under the other operation and maintenance table above.
•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.

Illinois Segment Contribution to Operating Income

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

Year Ended December 31
(in millions)20192018B (W)
Natural gas revenues$1,357.1$1,400.0$(42.9)
Cost of natural gas sold401.4480.579.1
Total natural gas margins955.7919.536.2
Other operation and maintenance461.1472.311.2
Depreciation and amortization181.3170.3(11.0)
Property and revenue taxes21.421.1(0.3)
Operating income$291.9$255.8$36.1

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

Year Ended December 31
(in millions)20192018B (W)
Operation and maintenance not included in the line items below$362.2$372.9$10.7
Riders *97.595.3(2.2)
Regulatory amortizations *(1.5)(1.4)0.1
Other2.95.52.6
Total other operation and maintenance$461.1$472.3$11.2
*These riders and regulatory amortizations are substantially offset in margins and therefore do not have a significant impact on operating income.
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The following tables provide information on delivered volumes by customer class and weather statistics:

Therms (in millions)
Natural Gas Sales Volumes20192018B (W)
Customer Class
Residential904.8896.28.6
Commercial and industrial368.6358.310.3
Total retail1,273.41,254.518.9
Transport896.6905.1(8.5)
Total sales in therms2,170.02,159.610.4
Degree Days
**Weather ***20192018B (W)
Heating (6,122 normal)6,4796,3272.4%
*Normal heating degree days are based on a 12-year moving average of monthly temperatures from Chicago's O'Hare Airport.

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 an increase in revenue at PGL due to continued capital investment in the SMP project under its QIP rider. 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 25, Regulatory Environment, for more information.

Operating Income

Operating income at the Illinois segment increased $36.1 million during 2019, compared with 2018. This increase was driven by the $34.0 million net increase in margins discussed above, as well as $2.1 million of lower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes), net of the impact of the riders referenced in the table above.

The significant factor impacting the decrease in operating expenses during 2019, compared with 2018, was a $23.2 million decrease in natural gas maintenance costs related to our Illinois utilities’ distribution systems.

This decrease in 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.
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Other States Segment Contribution to Operating Income

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

Year Ended December 31
(in millions)20192018B (W)
Natural gas revenues$426.0$438.2$(12.2)
Cost of natural gas sold217.5232.815.3
Total natural gas margins208.5205.43.1
Other operation and maintenance98.5101.02.5
Depreciation and amortization27.524.1(3.4)
Property and revenue taxes17.211.5(5.7)
Operating income$65.3$68.8$(3.5)

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

Year Ended December 31
(in millions)20192018B (W)
Operation and maintenance not included in line items below$76.4$76.1$(0.3)
Regulatory amortizations and other pass through expenses *22.024.82.8
Other0.10.1—
Total other operation and maintenance$98.5$101.0$2.5
*Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income.

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

Therms (in millions)
Natural Gas Sales Volumes20192018B (W)
Customer Class
Residential345.2336.19.1
Commercial and industrial238.2218.519.7
Total retail583.4554.628.8
Transport777.1738.738.4
Total sales in therms1,360.51,293.367.2
Degree Days
Weather *20192018B (W)
MERC
Heating (7,934 normal)8,7288,4902.8%
MGU
Heating (6,245 normal)6,3476,368(0.3)%
*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.

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, as well as capital investment in natural gas utility infrastructure. MERC began recognizing revenue under its new GUIC rider in the second quarter of 2019. The GUIC rider allows MERC to recover previously

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approved GUIC that were incurred to replace or modify natural gas facilities to the extent the work was required by state, federal, or other government agencies and exceed the costs included in base rates. 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 15, Income Taxes, and Note 25, Regulatory Environment, for more information.

Operating Income

Operating income at the other states segment decreased $3.5 million during 2019, compared with 2018. The decrease was driven by a $6.6 million increase in operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes) partially offset by the increase in margins discussed above. 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. 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.

Non-Utility Energy Infrastructure Segment Contribution to Operating Income

Year Ended December 31
(in millions)20192018B (W)
Operating income$366.6$365.8$0.8

2019 Compared with 2018

Operating income at the non-utility energy infrastructure segment increased $0.8 million during 2019, compared with 2018. Operating income at We Power increased $4.8 million, driven by higher revenues in connection with capital additions to the plants We Power owns and leases to WE. Higher operating income at We Power was partially offset by operating losses at the Upstream and Bishop Hill III wind generation facilities. The majority of earnings from our ownership interests in wind generation facilities come in the form of wind production tax credits, and are recognized as an offset to income tax expense. For more information on Upstream and Bishop Hill III, see Note 2, Acquisitions.

Corporate and Other Segment Contribution to Operating Income

Year Ended December 31
(in millions)20192018B (W)
Operating loss$(34.4)$(22.2)$(12.2)

2019 Compared with 2018

The operating loss at the corporate and other segment increased $12.2 million during 2019, compared with 2018, primarily driven by the transfer of assets from WBS, our centralized services company, 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 operating loss was a gain recorded in the third quarter of 2018 that related to a previous sale of a legacy business.

Electric Transmission Segment Operations

Year Ended December 31
(in millions)20192018B (W)
Equity in earnings of transmission affiliates$127.6$136.7$(9.1)

2019 Compared with 2018

Earnings from our electric transmission segment operations, primarily related to our investment in ATC, decreased $9.1 million during 2019, compared with 2018. A $19.3 million decrease in ATC's earnings was the result of a FERC order issued in November 2019 that addressed complaints related to ATC's allowed ROE. Increased earnings from continued capital investment partially offset the negative impact from the FERC order.

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Consolidated Other Income, Net

Year Ended December 31
(in millions)20192018B (W)
AFUDC – Equity$14.4$15.2$(0.8)
Non-service components of net periodic benefit costs36.226.010.2
Gains (losses) from investments held in rabbi trust21.2(1.8)23.0
Other, net30.430.9(0.5)
Other income, net$102.2$70.3$31.9

2019 Compared with 2018

Other income, net increased $31.9 million during 2019, compared with 2018. An increase of $23.0 million was due to net gains from investments held in the Integrys rabbi trust during 2019, compared with net losses during 2018. These investment gains partially offset benefits costs related to deferred compensation, which are included in other operation and maintenance expense. See Note 16, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust. Also contributing to the increase was $10.2 million of higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 19, Employee Benefits, for more information on our benefit costs.

Consolidated Interest Expense

Year Ended December 31
(in millions)20192018B(W)
Interest expense$501.5$445.1$(56.4)

2019 Compared with 2018

Interest expense increased $56.4 million during 2019, compared with 2018. The increase was primarily due to higher long-term debt balances. This increase in debt balances was primarily related to continued capital investments.

Consolidated Income Tax Expense

Year Ended December 31
20192018B (W)
Effective tax rate9.9%13.8%3.9%

2019 Compared with 2018

Our effective tax rate was 9.9% in 2019, compared to 13.8% in 2018. The 3.9% decrease in the effective tax rate was primarily due to an increase in wind production tax credits related to acquisitions of ownership interests in wind generation facilities in our non-utility energy infrastructure segment, the impact of the 2018 PSCW order regarding the benefits associated with the Tax Legislation, and the increased benefit from the flow through of tax repairs in connection with the 2017 Wisconsin rate settlement. The impacts from the 2018 PSCW order related to the Tax Legislation and the flow through of tax repairs were offset in operating income at the Wisconsin segment. See Note 2, Acquisitions, Note 15, Income Taxes, and Note 25, Regulatory Environment, for more information.

We expect our 2020 annual effective tax rate to be between 16% and 17%, which includes an estimated 4% 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 2020 range would be between 20% and 21%.

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, 2019 with the year ended December 31, 2018. For a similar discussion that compares our cash flows for the year ended December 31, 2018 with the year ended December 31, 2017, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources in Part II of our 2018 Annual Report on Form 10-K.

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Cash Flows

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

(in millions)20192018Change in 2019 Over 2018
Cash provided by (used in):
Operating activities$2,345.5$2,445.5$(100.0)
Investing activities(2,494.9)(2,384.4)(110.5)
Financing activities85.626.459.2

Operating Activities

2019 Compared with 2018

Net cash provided by operating activities decreased $100.0 million during 2019, compared with 2018, driven by:

•A $116.0 million decrease in cash due to higher collateral requirements in 2019, compared with 2018, driven by funding for both open natural gas contracts and settled natural gas contracts. See Note 17, Derivative Instruments, for more information.
•A $44.4 million decrease in cash due to an increase in payments for interest related to higher long-term debt balances during 2019, compared with 2018.
•A $40.5 million decrease in cash from higher payments for other operation and maintenance expense. During 2019, our payments were higher for transmission, benefits, and storm restoration, compared with 2018.
•A $25.6 million decrease in cash related to higher payments for environmental remediation from work completed on former manufactured gas plant sites during 2019, compared with 2018.

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

•A $74.0 million increase in cash primarily related to lower payments for natural gas and for fuel and purchased power. Lower payments for natural gas were due to a 14.5% decrease in the average per-unit cost of natural gas sold during 2019, compared with 2018. Lower payments for fuel and purchased power were due to the retirements of the Pleasant Prairie power plant in April 2018, Edgewater Unit 4 in September 2018, Pulliam Units 7 and 8 in October 2018, and the PIPP in March 2019.
•A $41.2 million net increase in cash related to $24.9 million of cash received for income taxes during 2019, compared with $16.3 million of cash paid for income taxes during 2018. This increase in cash was primarily due to alternative minimum tax credits that were refunded to us during 2019.
•An $11.7 million increase in cash related to a decrease in contributions and payments related to pension and OPEB plans during 2019, compared with 2018.

Investing Activities

2019 Compared with 2018

Net cash used in investing activities increased $110.5 million during 2019, compared with 2018, driven 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 $145.1 million increase in cash paid for capital expenditures during 2019, compared with 2018, which is discussed in more detail below.
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•A $53.4 million net decrease in restricted cash during 2019, compared with 2018, due to a $118.4 million decrease in the proceeds received from the sale of investments held in the Integrys rabbi trust, partially offset by a $65.0 million decrease in the purchase of investments held in the rabbi trust.

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

•The acquisition of Bishop Hill III during 2018 for $162.9 million, which is net of restricted cash acquired of $4.5 million. See Note 2, Acquisitions, for more information.
•The acquisition of Forward Wind Energy Center in April 2018 for $77.1 million. See Note 2, Acquisitions, for more information.
•The acquisition of an 80% ownership interest in Coyote Ridge during December 2018 for $61.4 million. See Note 2, Acquisitions, for more information.
•A $32.4 million increase in cash related to a reimbursement received from ATC for construction costs during 2019. See Note 20, Investment in Transmission Affiliates, for more information.
•A $25.5 million increase in proceeds received from the sale of assets and businesses, primarily related to the sale of four PDL solar power generation facilities during 2019, compared with 2018. See Note 3, Dispositions, for more information.

Capital Expenditures

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

Reportable Segment (in millions)20192018Change in 2019 Over 2018
Wisconsin$1,378.6$1,389.0$(10.4)
Illinois624.9547.177.8
Other states109.1103.65.5
Non-utility energy infrastructure121.736.385.4
Corporate and other26.539.7(13.2)
Total capital expenditures$2,260.8$2,115.7$145.1

2019 Compared with 2018

The decrease in cash paid for capital expenditures at the Wisconsin segment during 2019, compared with 2018, was primarily driven by the construction of the new natural gas-fired generation facility in the Upper Peninsula of Michigan, projects at the OCPP, the implementation of an ERP system, our AMI program and various other software projects, a natural gas lateral project at WPS's Fox Energy Center, and upgrades to WE's electric distribution system during 2018. These decreases in cash paid for capital expenditures were partially offset by increased capital expenditures related to WPS's Two Creeks project, upgrades to WPS's natural gas distribution system, and an information technology project created to improve WE's and WG's billing, call center, and credit collection functions during 2019.

The increase in cash paid for capital expenditures at the Illinois segment during 2019, compared with 2018, was driven by an increase in facilities projects at PGL, partially offset by a decrease in AMI expenditures at NSG during 2019.

The increase in cash paid for capital expenditures at the non-utility energy infrastructure segment during 2019, compared with 2018, was primarily driven by the construction of Coyote Ridge. See Note 2, Acquisitions, for more information.

The decrease in cash paid for capital expenditures at the corporate and other segment during 2019, compared with 2018, was primarily driven by the implementation of a new ERP system during the first quarter of 2018.

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

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Financing Activities

2019 Compared with 2018

Net cash provided by financing activities increased $59.2 million during 2019, compared with 2018, driven by:

•A $593.2 million increase in cash related to lower long-term debt repayments during 2019, compared with 2018.
•A $155.0 million increase in cash due to higher issuances of long-term debt during 2019, compared with 2018.
•A $37.9 million increase in cash from stock options exercised during 2019, compared with 2018.

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

•A $604.8 million decrease in cash related to higher net repayments of commercial paper during 2019, compared with 2018.
•A $67.7 million decrease in cash due to an increase in the number and cost of shares of our common stock purchased during 2019, compared with 2018, to satisfy requirements of our stock-based compensation plans.
•A $47.2 million decrease in cash due to higher dividends paid on our common stock during 2019, compared with 2018. In January 2019, our Board of Directors increased our quarterly dividend by $0.0375 per share (6.8%) effective with the first quarter of 2019 dividend payment.

Significant Financing Activities

For more information on our financing activities, see Note 12, Short-Term Debt and Lines of Credit, and Note 13, 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.

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. See Note 12, Short-Term Debt and Lines of Credit, for more information about these credit facilities.

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The following table shows our capitalization structure as of December 31, 2019 and 2018, 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:

20192018
(in millions)ActualAdjustedActualAdjusted
Common shareholders' equity$10,113.4$10,363.4$9,788.9$10,038.9
Preferred stock of subsidiary30.430.430.430.4
Long-term debt (including current portion)11,904.211,654.210,359.010,109.0
Short-term debt830.8830.81,440.11,440.1
Total capitalization$22,878.8$22,878.8$21,618.4$21,618.4
Total debt$12,735.0$12,485.0$11,799.1$11,549.1
Ratio of debt to total capitalization55.7%54.6%54.6%53.4%

Included in long-term debt on our balance sheets as of December 31, 2019 and 2018, is $500.0 million principal amount of 2007 Junior Notes. The adjusted presentation attributes $250.0 million of the 2007 Junior Notes to common 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 13, Long-Term Debt.

As described in Note 10, 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, 2019, 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 12, Short-Term Debt and Lines of Credit, and Note 13, Long-Term Debt, for more information.

Working Capital

As of December 31, 2019, our current liabilities exceeded our current assets by $1,089.1 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 and/or Baa3 at Moody's Investors Service. We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.

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

In November 2019, Moody's downgraded the ratings of WG senior unsecured debt to A3 from A2 and WG commercial paper to P-2 from P-1. The change in ratings has not had, and we do not believe that it will have, a material impact on our ability to access capital. Moody's changed the rating outlook for WG to stable from negative.

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

If we are unable to successfully take actions to manage any additional adverse impacts of the Tax Legislation, or if additional interpretations, regulations, amendments or technical corrections exacerbate the adverse impacts of the Tax Legislation, the legislation could result in credit rating agencies placing our or our subsidiaries’ credit ratings on negative outlook or additional downgrading of our or our subsidiaries' credit ratings. Any such actions by credit rating agencies may make it more difficult and costly for us and our subsidiaries to issue future debt securities and certain other types of financing and could increase borrowing costs under our and our subsidiaries’ credit facilities.

Capital Requirements

Contractual Obligations

We have the following contractual obligations and other commercial commitments as of December 31, 2019:

Payments Due by Period (1)
(in millions)TotalLess Than 1 Year1-3 Years3-5 YearsMore Than 5 Years
Long-term debt obligations (2)$20,753.7$1,170.2$2,595.1$1,426.1$15,562.3
Finance lease obligations (3)102.79.315.41.876.2
Operating lease obligations (4)56.26.89.69.730.1
Energy and transportation purchase obligations (5)11,570.01,231.12,152.91,667.56,518.5
Purchase orders (6)886.0463.3250.285.187.4
Pension and OPEB funding obligations (7)39.612.527.1——
Total contractual obligations$33,408.2$2,893.2$5,050.3$3,190.2$22,274.5
(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, 2019.
(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 14, Leases, for more information.
(4)Operating lease obligations for office space, land, and rail car leases. See Note 14, 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 Two Creeks and Badger Hollow I.
(7)Obligations for pension and OPEB plans cannot reasonably be estimated beyond 2022.

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 15, Income Taxes.

The table above also does not reflect estimated future payments related to the manufactured gas plant remediation liability of $589.2 million at December 31, 2019, as the amount and timing of payments are uncertain. We expect to incur costs annually to remediate these sites. See Note 23, Commitments and Contingencies, for more information about environmental liabilities.

AROs in the amount of $483.5 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 8, Asset Retirement Obligations, for more information.

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

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, impacts from the Tax Legislation, additional changes in tax laws and regulations, acquisition and development opportunities, market volatility, and economic trends. Our estimated capital expenditures and acquisitions for the next three years are as follows:

(in millions)202020212022
Wisconsin$1,482.0$1,881.1$1,630.5
Illinois779.0619.4586.7
Other states117.4111.687.4
Non-utility energy infrastructure852.5159.7393.0
Corporate and other24.622.72.7
Total$3,255.5$2,794.5$2,700.3

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. WPS expects to invest approximately $100 million between 2020 and 2022 on this project.

As part of our commitment to invest in zero-carbon generation, we have either filed for or 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. Badger Hollow I is located in Iowa County, Wisconsin, and Two Creeks is located in Manitowoc County, Wisconsin. Once constructed, WPS will own 100 MW of the output of each project for a total of 200 MW. WPS's share of the cost of both projects is estimated to be $256 million. Construction began at Two Creeks and Badger Hollow I in August 2019 and October 2019, respectively. Commercial operation of both projects is targeted for the end of 2020. WE has partnered with an unaffiliated utility to acquire an ownership interest in a proposed solar project, Badger Hollow II, that will be located in Iowa County, Wisconsin. At its meeting on February 20, 2020, the PSCW approved the acquisition of this project. The approval is still subject to WE's receipt and review of a final written order from the PSCW. Once constructed, WE will own 100 MW of the output 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 the end of 2021. Solar generation technology has greatly improved, has become more cost-effective, and it complements our summer demand curve.

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

PGL is continuing work on the SMP, a project under which PGL is replacing approximately 2,000 miles of Chicago's aging natural gas pipeline infrastructure. PGL currently recovers these costs through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023. PGL's projected average annual investment through 2022 is between $280 million and $300 million. See Note 25, 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 and Blooming Grove. See Note 2, Acquisitions, for more information on these wind projects.

We expect to provide total capital contributions to ATC (not included in the above table) of approximately $90 million from 2020 through 2022. We do not expect to make any contributions to ATC Holdco during that period.

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Common Stock Matters

For information related to our common stock matters, see Note 10, Common Equity.

On January 16, 2020, our Board of Directors increased our quarterly dividend to $0.6325 per share effective with the first quarter of 2020 dividend payment, an increase of 7.2%. This equates to an annual dividend of $2.53 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 $3.9 billion as of December 31, 2019. These trusts hold investments that are subject to the volatility of the stock market and interest rates. We contributed $65.9 million and $77.6 million to our pension and OPEB plans in 2019 and 2018, 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 19, 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 12, Short-Term Debt and Lines of Credit, Note 18, Guarantees, and Note 22, Variable Interest Entities.

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

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.

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 specific orders or by a generic order 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. In general, our regulatory assets are recovered over a period of between one to twenty years. 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, 2019, our regulatory assets were $3,527.6 million, and our regulatory liabilities were $4,080.4 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 15, Income Taxes, and Note 25, Regulatory Environment, for more information.

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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, 2019, we had not received any significant disallowances of the costs incurred for this project. WPS received approval to recover these costs in the rate order it received from the PSCW in December 2019. See Note 25, Regulatory Environment, for more information.
•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 2019, PGL filed its 2018 reconciliation with the ICC, which, along with the 2017 and 2016 reconciliations, are still pending. In July 2019, the ICC approved a settlement of the 2015 reconciliation, which includes a rate base reduction of $7.0 million and a $7.3 million refund to ratepayers. As of December 31, 2019, all amounts had been refunded to customers. As of December 31, 2019, 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 25, 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 1(d), Operating Revenues, for more information on riders and other mechanisms that allow for cost recovery or refund of uncollectible expense.

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 2019 and 2018, 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.

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Based on the variable rate debt outstanding at December 31, 2019, and December 31, 2018, a hypothetical increase in market interest rates of one percentage point would have increased annual interest expense by $10.8 million and $16.9 million in 2019 and 2018, 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, 2019Expected Return on Assets in 2020
Pension trust funds$3,007.06.87%
OPEB trust funds$879.67.00%

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.

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

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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, 2019, Michigan law limited customer choice to 10% of an electric utility's Michigan retail load, but this cap could potentially be reduced in future years due to the December 2016 passage of Michigan Act 341. Based on current law, our iron ore mine customer, Tilden, is exempt from the 10% cap. 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 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.

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 rates 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.

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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 customers (formerly WPS’s Michigan 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 23, Commitments and Contingencies, for a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change.

Other Matters

Tax Cuts and Jobs Act of 2017

In December 2017, the Tax Legislation was signed into law. In 2018 and 2019, 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 our recent rate orders issued by the PSCW in December 2019. 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.

In July 2019, the FERC approved WPS's revised formula rate tariff, which incorporated the impacts of the Tax Legislation. We are also working with the FERC to modify WE's formula rate tariff for the impacts of the Tax Legislation, and we expect to receive FERC approval for WE's modified tariff in 2020. See Note 25, Regulatory Environment, for more information.

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 has 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 will reduce the base ROE that ATC is allowed to collect on a going-forward basis, as discussed below. Various parties have requested a rehearing by the FERC of the November 2019 Order in its entirety.

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

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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 addition, 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 21, 2019. As a result, ATC will provide WE and WPS with refunds related to the transmission costs they paid during the two refund periods, and these refunds will be 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 its 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. Refunds could still be required, however, for the second complaint period depending on the outcome of numerous rehearing requests filed with the FERC. Therefore, our financials continue to reflect a liability of $41.9 million resulting in reduced equity earnings from ATC. This liability reflects a 10.38% 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.

Bonus Depreciation Provisions

Bonus depreciation is an additional amount of first-year tax deductible depreciation that is awarded above what would normally be available. The bonus depreciation deduction available for public utility property subject to rate-making by a government entity or public utility commission was modified by the Tax Legislation. Based on the provisions of the Tax Legislation, bonus depreciation can no longer be deducted for public utility property acquired and placed in service after December 31, 2017. The provisions of the Tax Legislation regarding the repeal of bonus depreciation do not apply to some of our non-utility investments.

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.

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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, 2019, we had $3,527.6 million in regulatory assets and $4,080.4 million in regulatory liabilities. See Note 5, 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, 2019. 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 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 each 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, 2019:

(in millions, except percentages)GoodwillPercentage of Total Goodwill
Wisconsin$2,104.368.9%
Illinois758.724.9%
Other states183.26.0%
Bluewater6.60.2%
Total goodwill$3,052.8100.0%

See Note 9, Goodwill, 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

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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.

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 Pleasant Prairie power plant. WE will collect a full return of and on all but $100 million of the net book value of the Pleasant Prairie power plant. In accordance with its PSCW rate order received in December 2019, WE will seek a financing order from the PSCW to securitize the remaining $100 million. See Note 6, Property, Plant, and Equipment, and Note 25, Regulatory Environment, for more information on our retired generating units, including various approvals we received from the FERC and the PSCW.

Pension and Other Postretirement Employee Benefits

The costs of providing non-contributory defined pension benefits and OPEB, described in Note 19, 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 AssumptionImpact on Projected Benefit ObligationImpact on 2019 Pension Cost
Discount rate(0.5)$206.6$17.4
Discount rate0.5(178.2)(10.6)
Rate of return on plan assets(0.5)N/A13.3
Rate of return on plan assets0.5N/A(13.3)
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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 AssumptionImpact on Postretirement Benefit ObligationImpact on 2019 Postretirement Benefit Cost
Discount rate(0.5)$35.3$3.8
Discount rate0.5(30.6)(3.8)
Health care cost trend rate(0.5)(18.6)(4.5)
Health care cost trend rate0.521.35.1
Rate of return on plan assets(0.5)N/A3.8
Rate of return on plan assets0.5N/A(3.8)

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 7.12% in 2019 and 2018, and 7.11% in 2017. The actual rate of return on pension plan assets, net of fees, was 18.89%, (4.30)%, and 13.74%, in 2019, 2018, and 2017, 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 19, 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 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 2019 of approximately $7.4 billion included accrued utility revenues of $478.8 million as of December 31, 2019.

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

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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(o), Income Taxes, and Note 15, Income Taxes, for a discussion of accounting for income taxes.

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