WEC ENERGY GROUP, INC. - Annual Report: 2019 (Form 10-K)

---

---

---

---

---

---

---

•	Factors affecting utility operations such as catastrophic weather-related damage, environmental incidents, unplanned facility outages and repairs and maintenance, and electric transmission or natural gas pipeline system constraints;

•	Factors affecting the demand for electricity and natural gas, including political developments, unusual weather, changes in economic conditions, customer growth and declines, commodity prices, energy conservation efforts, and continued adoption of distributed generation by customers;

•	The timing, resolution, and impact of rate cases and negotiations, including recovery of deferred and current costs and the ability to earn a reasonable return on investment, and other regulatory decisions impacting our regulated operations;

•

The impact of recent and future federal, state, and local legislative and/or regulatory changes, including changes in rate-setting policies or procedures, deregulation and restructuring of the electric and/or natural gas utility industries, transmission or distribution system operation, the approval process for new construction, reliability standards, pipeline integrity and safety standards, allocation of energy assistance, energy efficiency mandates, and tax laws, including the Tax Legislation as well as those that affect our ability to use production tax credits and investment tax credits;

•

Federal and state legislative and regulatory changes relating to the environment, including climate change and other environmental regulations impacting generation facilities and renewable energy standards, the enforcement of these laws and regulations, changes in the interpretation of regulations or permit conditions by regulatory agencies, and the recovery of associated remediation and compliance costs;

•	The ability to obtain and retain customers, including wholesale customers, due to increased competition in our electric and natural gas markets from retail choice and alternative electric suppliers, and continued industry consolidation;

•	The timely completion of capital projects within budgets and the ability to recover the related costs through rates;

•	Factors affecting the implementation of our generation reshaping plan, including related regulatory decisions, the cost of materials, supplies, and labor, and the feasibility of competing projects;

•	The financial and operational feasibility of taking more aggressive action to further reduce GHG emissions in order to limit future global temperature increases;

•

The risks associated with changing commodity prices, particularly natural gas and electricity, and the availability of sources of fossil fuel, natural gas, purchased power, materials needed to operate environmental controls at our electric generating facilities, or water supply due to high demand, shortages, transportation problems, nonperformance by electric energy or natural gas suppliers under existing power purchase or natural gas supply contracts, or other developments;

---

•	Changes in credit ratings, interest rates, and our ability to access the capital markets, caused by volatility in the global credit markets, our capitalization structure, and market perceptions of the utility industry, us, or any of our subsidiaries;

•	Changes in the method of determining LIBOR or the replacement of LIBOR with an alternative reference rate;

•	Costs and effects of litigation, administrative proceedings, investigations, settlements, claims, and inquiries;

•

The direct or indirect effect on our business resulting from terrorist attacks and cyber security intrusions, as well as the threat of such incidents, including the failure to maintain the security of personally identifiable information, the associated costs to protect our utility assets, technology systems, and personal information, and the costs to notify affected persons to mitigate their information security concerns and to comply with state notification laws;

•	Restrictions imposed by various financing arrangements and regulatory requirements on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans or advances, that could prevent us from paying our common stock dividends, taxes, and other expenses, and meeting our debt obligations;

•	The risk of financial loss, including increases in bad debt expense, associated with the inability of our customers, counterparties, and affiliates to meet their obligations;

•	Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading markets and fuel suppliers and transporters;

•	The financial performance of ATC and its corresponding contribution to our earnings;

•	The investment performance of our employee benefit plan assets, as well as unanticipated changes in related actuarial assumptions, which could impact future funding requirements;

•	Factors affecting the employee workforce, including loss of key personnel, internal restructuring, work stoppages, and collective bargaining agreements and negotiations with union employees;

•	Advances in technology, and related legislation or regulation supporting the use of that technology, that result in competitive disadvantages and create the potential for impairment of existing assets;

•	The risk associated with the values of goodwill and other intangible assets and their possible impairment;

•	Potential business strategies to acquire and dispose of assets or businesses, which cannot be assured to be completed timely or within budgets, and legislative or regulatory restrictions or caps on non-utility acquisitions, investments or projects, including the State of Wisconsin's public utility holding company law;

•	The timing and outcome of any audits, disputes, and other proceedings related to taxes;

•	The ability to maintain effective internal controls in accordance with SOX, while both integrating and continuing to consolidate our enterprise systems;

•	The effect of accounting pronouncements issued periodically by standard-setting bodies; and

•	Other considerations disclosed elsewhere herein and in other reports we file with the SEC or in other publicly disseminated written documents.

---

•	WE generates and distributes electric energy to customers located in southeastern Wisconsin (including the metropolitan Milwaukee area), east central Wisconsin, and northern Wisconsin. WE also served an iron ore mine customer, Tilden, in the Upper Peninsula of Michigan, through March 31, 2019 when Tilden became a customer of UMERC.

•	WPS generates and distributes electric energy to customers located in northeastern and central Wisconsin.

•	UMERC generates and distributes electric energy to customers located in the Upper Peninsula of Michigan. UMERC began generating electricity when its new natural gas-fired generation achieved commercial operation on March 31, 2019.

---

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

(2)	Includes SSR revenues, amounts collected from (refunded to) customers for certain fuel and purchased power costs that exceed a 2% price variance from costs included in rates, and other revenues, partially offset by revenues from Tilden that were addressed in WE's December 2019 Wisconsin rate order.

---

---

(1)	The values included in the estimate assume a natural gas price based on the February 2020 NYMEX.

(2)	Includes hydroelectric, biomass, and wind generation.

---

•

In April 2019, WPS, along with an unaffiliated utility, received approval from the PSCW to acquire ownership interests in two utility-scale 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. 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.

•

In August 2019, WE, along with an unaffiliated utility, filed an application with the PSCW for approval 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. Commercial operation of Badger Hollow II is targeted for the end of 2021.

---

---

*	Includes amounts refunded to customers for purchased gas adjustment costs.

---

---

---

---

---

---

(1)	In February 2020, WECI signed an agreement to acquire an additional 10% ownership interest in Upstream.

(2)	Coyote Ridge achieved commercial operation on December 20, 2019.

---

---

*

Tilden, an iron-ore mine in the Upper Peninsula of Michigan, was a customer of WE through March 31, 2019. Tilden became a customer of UMERC when UMERC's new natural gas-fired generation in the Upper Peninsula began commercial operation. As a result, WE no longer has any retail customers in Michigan and its retail electric rates were not regulated by the MPSC after March 31, 2019. See Note 25, Regulatory Environment, for more information on the formation of UMERC.

---

---

---

*	A three year contract was ratified between MGU and the Union Steelworkers of America, Local 12295, on January 11, 2020.

---

---

---

---

---

•

Fluctuations in customer growth and general economic conditions in our service areas. Customer growth and energy use can be negatively impacted by population declines as well as economic factors in our service territories, including workforce reductions, stagnant wage growth, changing levels of support from state and local government for economic development, business closings, and reductions in the level of business investment. Our electric and natural gas utilities are impacted by economic cycles and the competitiveness of the commercial and industrial customers we serve. Any economic downturn, disruption of financial markets, or reduced incentives by state government for economic development could adversely affect the financial condition of our customers and demand for their products or services. These risks could directly influence the demand for electricity and natural gas as well as the need for additional power generation and generating facilities. We could also be exposed to greater risks of accounts receivable write-offs if customers are unable to pay their bills.

•

Weather conditions. Demand for electricity is greater in the summer and winter months when cooling and heating is necessary. In addition, demand for natural gas peaks in the winter heating season. As a result, our overall results may fluctuate substantially on a seasonal basis. In addition, milder temperatures during the summer cooling season and during the winter heating season may result in lower revenues and net income.

•

Our customers' continued focus on energy conservation. Our customers' use of electricity and natural gas has decreased as a result of continued individual conservation efforts, including the use of more energy efficient technologies. Customers could also voluntarily reduce their consumption of energy in response to decreases in their disposable income and increases in energy prices. Conservation of energy can be influenced by certain federal and state programs that are intended to influence how consumers use energy. For example, several states, including Wisconsin and Michigan, have adopted energy efficiency targets to reduce energy consumption by certain dates.

---

---

---

•	A rating downgrade;

•	An economic downturn or uncertainty;

•	Prevailing market conditions and rules;

•	Concerns over foreign economic conditions;

•	Changes in tax policy;

•	Changes in investment criteria of institutional investors;

•	War or the threat of war;

•	The overall health and view of the utility and financial institution industries; and

•	Changes in the method of determining LIBOR or the replacement of LIBOR with an alternative reference rate.

---

•	Increase borrowing costs under certain existing credit facilities;

•	Require the payment of higher interest rates in future financings and possibly reduce the pool of creditors;

•	Decrease funding sources by limiting our or our subsidiaries' access to the commercial paper market;

•	Limit the availability of adequate credit support for our subsidiaries' operations; and

•	Trigger collateral requirements in various contracts.

•	Higher working capital requirements, particularly related to natural gas inventory, accounts receivable, and cash collateral postings;

•	Reduced profitability to the extent that lower revenues, increased bad debt, and interest expense are not recovered through rates;

•	Higher rates charged to our customers, which could impact our competitive position;

•	Reduced demand for energy, which could impact revenues and operating expenses; and

•	Shutting down of generation facilities if the cost of generation exceeds the market price for electricity.

---

---

---

(1)

Capacity for our electric generation facilities is based on rated capacity, which is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. Values are primarily based on the net dependable expected capacity ratings for summer 2020 established by tests and may change slightly from year to year. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand.

(2)	These facilities are jointly owned by WPS and various other utilities. The capacity indicated for each of these units is equal to WPS's portion of total plant capacity based on its percent of ownership.

•	Wisconsin Power and Light Company, an unaffiliated utility, operates the Columbia units. WPS holds a 27.6% ownership interest in Columbia. See Note 7, Jointly Owned Utility Facilities, for more information on the anticipated decrease in WPS's ownership interest in the Columbia unit.

•	WPS operates the Weston 4 facility and holds a 70.0% ownership interest in this facility. Dairyland Power Cooperative, an unaffiliated energy cooperative, holds the remaining 30.0% interest.

---

(3)	This facility is jointly owned by We Power and two other unaffiliated entities. Our share of capacity is equal to We Power's ownership interest of 83.34%.

(4)	These facilities are part of the Company's non-utility energy infrastructure segment. See B. Non-Utility Energy Infrastructure Segment below.

(5)	All of our hydroelectric facilities follow FERC guidelines and/or regulations.

(6)	WRPC owns and operates the Castle Rock and Petenwell units. WPS holds a 50.0% ownership interest in WRPC and is entitled to 50.0% of the total capacity at Castle Rock and Petenwell. WPS's share of capacity for Castle Rock and Petenwell is 6.8 MW and 10.2 MW, respectively.

(7)	WE has a biomass power plant that uses wood waste and wood shavings to produce electric power as well as steam to support the paper mill's operations. Fuel for the power plant is supplied by both the paper mill and through contracts with biomass suppliers. The plant also has the ability to burn natural gas if wood waste and wood shavings are not available.

(8)	WPS, along with two other unaffiliated utilities, owns Forward Wind Energy Center, which consists of 86 wind turbines located in Wisconsin with a total capacity of 138 MW. WPS is entitled to its share of generating capability and output of the facility equal to its ownership interest of 44.6%. See Note 2, Acquisitions, for more information on the Forward Wind Energy Center acquisition.

•	Approximately 49,500 miles of natural gas distribution mains,

•	Approximately 1,200 miles of natural gas transmission mains,

•	Approximately 2.3 million natural gas lateral services,

•	Approximately 510 natural gas distribution and transmission gate stations,

•	Approximately 68.2 billion cubic feet of working gas capacities in underground natural gas storage fields:

◦	Bluewater, 26.5 billion cubic feet of fields located in southeastern Michigan,

◦	Manlove, a 38.8 billion-cubic-foot field located in central Illinois,

◦	Partello, a 2.9 billion-cubic-foot field located in southern Michigan,

•	A 2.0 billion-cubic-foot LNG plant located in central Illinois,

•	A peak-shaving facility that can store the equivalent of approximately 80 MDth in liquefied petroleum gas located in Illinois,

•	Peak propane air systems providing approximately 2,960 Dth per day, and

•	LNG storage plants with a total send-out capability of 73,600 Dth per day.

---

(1)	Nameplate capacity is the amount of energy a turbine should produce at optimal wind speeds.

(2)	In January 2019, WECI completed the acquisition of an 80% ownership interest in Upstream. In February 2020, WECI agreed to acquire an additional 10% ownership interest in Upstream. See Note 2, Acquisitions, for more information.

(3)	In August 2018, WECI completed the acquisition of an 80% ownership interest in Bishop Hill III. In December 2018, WECI acquired an additional 10% ownership interest in this wind farm. See Note 2, Acquisitions, for more information.

(4)	In December 2018, WECI completed the acquisition of an 80% ownership interest in Coyote Ridge, which achieved commercial operation in December 2019. See Note 2, Acquisitions, for more information.

---

---

•	WEC Energy Group — Executive Chairman since February 2019. Chairman of the Board and Chief Executive Officer from October 2017 to February 2019, and from May 2004 to May 2016. Non-Executive Chairman of the Board from May 2016 to October 2017. Director since December 2003. President from April 2003 to August 2013.

•	WE — Director since January 2018, and from December 2003 to May 2016. Chairman of the Board from January 2018 to February 2019, and from May 2004 to May 2016. Chief Executive Officer from January 2018 to February 2019, and from August 2003 to May 2016. President from August 2003 to June 2015.

•	WEC Energy Group — Director and Chief Executive Officer since February 2019. President since October 2018.

•	WE — Chairman of the Board and Chief Executive Officer since February 2019. Director since June 2015. President from May 2016 to November 2018. Executive Vice President - Customer Service and Operations from June 2015 to April 2016. Senior Vice President - Customer Operations from October 2011 to June 2015.

•	WEC Energy Group — Executive Vice President - External Affairs since June 2015. Senior Vice President - External Affairs from April 2011 to June 2015.

•	WE — Executive Vice President - External Affairs since June 2015. Senior Vice President - External Affairs from April 2011 to June 2015.

•	WEC Energy Group — Controller since October 2015. Vice President since June 2015.

•	WE — Vice President and Controller since October 2015.

•	Integrys Energy Group — Vice President and Treasurer from December 2010 to June 2015.

•	WEC Energy Group — Executive Vice President, Corporate Secretary and General Counsel since January 2018. Executive Vice President from September 2017 to January 2018.

•	WE — Executive Vice President, Corporate Secretary and General Counsel since January 2018. Director since January 2018.

•	Modine Manufacturing Company – General Counsel, Corporate Secretary, and Vice President - Legal from April 2008 to August 2017. Vice President - Corporate Communications from April 2014 to August 2017.

•	WEC Energy Group — Executive Vice President - WEC Infrastructure since November 2018.

•	WE — Senior Vice President - Wholesale Energy and Fuels from June 2015 to January 2019. Vice President from May 2014 to June 2015.

•	WEC Energy Group — Senior Executive Vice President since March 2018. Executive Vice President from May 2004 to January 2013.

•	WE — Executive Vice President from May 2004 to January 2013.

•

WEC Energy Group — Senior Executive Vice President and Chief Financial Officer since October 2019. Senior Executive Vice President, Chief Financial Officer and Treasurer from February 2019 to October 2019. Executive Vice President, Chief Financial Officer and Treasurer from October 2018 to February 2019. Executive Vice President and Chief Financial Officer from April 2016 to October 2018. Vice President and Treasurer from February 2013 to March 2016.

•	WE — Executive Vice President and Chief Financial Officer since October 2019, and from April 2016 to October 2018. Director since April 2016. Executive Vice President, Chief Financial Officer and Treasurer from October 2018 to October 2019. Vice President and Treasurer from February 2013 to March 2016.

---

•	PELLC — President since June 2015.

•	PGL — Director, President, and Chief Executive Officer since June 2015.

•	NSG — Director, President, and Chief Executive Officer since June 2015.

•	WE — Senior Vice President - Wholesale Energy and Fuels from January 2012 to June 2015.

•	WE — President since November 2018. Director since January 2018. Executive Vice President - Generation from April 2016 to November 2018. Senior Vice President - Power Generation from January 2014 to March 2016.

•	WEC Energy Group — Vice President and Treasurer since October 2019.

•	WE — Vice President and Treasurer since October 2019.

•	Controller - Illinois from September 2015 to September 2019. Manager - Financial Planning and Analysis from May 2011 to September 2015.

•	WEC Energy Group — Senior Vice President - Corporate Communications and Investor Relations since June 2015.

•	WE — Senior Vice President - Corporate Communications and Investor Relations from June 1 to June 28, 2015.

•	Barclays — Vice President of Equity Research Power and Utilities Group from September 2008 to May 2015.

*	On January 31, 2020, Mr. Kuester informed the Company of his intent to retire in 2020.

---

(1)	Includes a $206.7 million increase in net income attributed to common shareholders related to a re-measurement of our deferred taxes as a result of the Tax Legislation. See Note 15, Income Taxes, for more information.

(2)	Includes the impact of the Integrys acquisition for the last two quarters of 2015.

---

---

•

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.

•	See Note 2, Acquisitions, for information about our acquisitions of portions of wind energy generation facilities in Wisconsin, Illinois, Nebraska, and South Dakota.

---

•	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.

---

*

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.

•

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.

---

•

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.

•	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.

---

(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.

(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.

---

(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.

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

(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.

---

•	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.

•

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.

•

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

---

•

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.

•

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.

*	These riders and regulatory amortizations are substantially offset in margins and therefore do not have a significant impact on operating income.

---

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

•	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.

---

*	Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income.

*	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.

---

---

---

•	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.

•

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.

•	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.

---

•	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.

•	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.

---

•	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.

•	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.

---

---

(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.

---

---

---

•

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.

---

---

---

---

---

---

---

---

---

---

•	We tested the effectiveness of management’s controls over regulatory assets and liabilities, including management’s controls over the identification of costs recorded as regulatory assets and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates.

•

We inquired of Company management and read: (1) relevant regulatory orders issued by the Commissions for the Company and other public utilities in each respective state, (2) company filings, (3) filings made by intervenors and (4) other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedence of the Commissions’ treatment of similar costs under similar circumstances.

•	For regulatory matters in process, we inspected the Company’s filings with the Commissions and the filings with the Commissions by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.

•	We obtained management’s analysis regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

•	We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

---

---

---

---

---

---

---

•	Wisconsin segment – Consists of WE, WPS, and WG, which are engaged primarily in the generation of electricity and the distribution of electricity and natural gas in Wisconsin; and UMERC, which generates electricity and distributes electricity and natural gas to customers located in the Upper Peninsula of Michigan.

•	Illinois segment – Consists of PGL and NSG, which are engaged primarily in the distribution of natural gas in Illinois.

•	Other states segment – Consists of MERC and MGU, which are engaged primarily in the distribution of natural gas in Minnesota and Michigan, respectively.

•	Electric transmission segment – Consists of our approximate 60% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions, and our approximate 75% ownership interest in ATC Holdco, which invests in transmission-related projects outside of ATC's traditional footprint.

•

Non-utility energy infrastructure segment – Consists of We Power, which is principally engaged in the ownership of electric power generating facilities for long-term lease to WE, and Bluewater, which owns underground natural gas storage facilities in Michigan. WECI, which holds our ownership interests in several wind generating facilities, is also included in this segment. See Note 2, Acquisitions, for more information on Bluewater and the WECI wind generating facilities.

•

Corporate and other segment – Consists of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Bostco, Wisvest, WECC, WBS, and PDL. In the first quarter of 2017, we sold substantially all of the remaining assets of Bostco, and, in October 2018, Bostco was dissolved. In 2019, we sold certain PDL solar power generating facilities. See Note 3, Dispositions, for more information on these sales.

---

---

---

•	The rates of PGL, NSG, and MERC include decoupling mechanisms. These mechanisms differ by state and allow the utilities to recover or refund the differences between actual and authorized margins for certain customer classes. See Note 25, Regulatory Environment, for more information.

•	MERC’s rates include a conservation improvement program rider, which includes a financial incentive for meeting energy savings goals.

•

WE and WPS provide wholesale electric service to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.

---

*	The 2018 rate reflects the impact of a new depreciation study approved by the MPUC in May 2018. The rates approved were effective retroactive to January 2017. An approximate $1.4 million reduction in depreciation expense was recorded in 2018 related to this depreciation study.

---

---

---

---

•	We did not reassess whether any expired or existing contracts were leases or contained leases.

•	We did not reassess the lease classification for any expired or existing leases (that is, all leases that were classified as operating leases in accordance with Topic 840 continue to be classified as operating leases, and all leases that were classified as capital leases in accordance with Topic 840 are classified as finance leases).

•	We did not reassess the accounting for initial direct costs for any existing leases.

---

---

---

*	Includes $8.1 million of restricted cash.

---

*	Represents restricted cash.

---

---

---

*	Includes amounts collected from (refunded to) customers for purchased gas adjustment costs.

---

*	Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to decoupling mechanisms and wholesale true-ups, as discussed in Note 1(d), Operating Revenues.

(1)	Based on prior and current rate treatment, we believe it is probable that our utilities will continue to recover from customers the regulatory assets in this table. In accordance with GAAP, our regulatory assets do not include the allowance for ROE that is capitalized for regulatory purposes. This allowance was $24.3 million and $18.2 million at December 31, 2019 and 2018, respectively.

(2)	As of December 31, 2019, we had $175.1 million of regulatory assets not earning a return, $29.1 million of regulatory assets earning a return based on short-term interest rates, and $151.5 million of regulatory assets earning a return based on long-term interest rates. The regulatory

---

(3)	Primarily represents the unrecognized future pension and OPEB costs related to our defined benefit pension and OPEB plans. We are authorized recovery of these regulatory assets over the average remaining service life of each plan.

(4)	In accordance with the rate orders issued by the PSCW in December 2019, amounts previously collected from customers for the future removal of our recently retired plants were used to reduce our unrecovered plant balances during December 2019. Any additional removal costs that we incur will increase our plant retirement regulatory assets.

(5)	As of December 31, 2019, we had made cash expenditures of $96.3 million related to these environmental remediation costs. The remaining $589.2 million represents our estimated future cash expenditures.

(6)	For information on the flow through of tax repairs and the regulatory treatment of the impacts of the Tax Legislation in our various jurisdictions, see Note 25, Regulatory Environment.

(7)	As a result of the rate order WE received from the PSCW in December 2019, the regulatory liability related to its mines deferral was offset against its SSR regulatory asset during December 2019. The rate order also authorized recovery of WE's SSR regulatory asset over a 15-year period that began on January 1, 2020.

(8)	Represents amounts recoverable from customers related to our uncollectible expense tracking mechanisms and riders. These mechanisms allow us to recover or refund the difference between actual uncollectible write-offs and the amounts recovered in rates.

(9)	Represents amounts recoverable from customers related to WE's costs of the generating units leased from We Power, including subsequent capital additions.

(1)	For information on the regulatory treatment of the impacts of the Tax Legislation in our various jurisdictions, see Note 25, Regulatory Environment.

(2)	Represents amounts collected from customers to cover the future cost of property, plant, and equipment removals that are not legally required. Legal obligations related to the removal of property, plant, and equipment are recorded as AROs. See Note 8, Asset Retirement Obligations, for more information on our legal obligations.

(3)	Primarily represents the unrecognized future pension and OPEB benefits related to our defined benefit pension and OPEB plans. We will amortize these regulatory liabilities into net periodic benefit cost over the average remaining service life of each plan.

---

(4)	Represents an over-collection of energy costs that will be refunded to customers in the future. When the rates we charge to customers include energy costs that are higher than our actual energy costs, any over-collection outside of the allowable energy cost price variance is refunded to customers.

(5)

Based on orders received from the PSCW, WE was required to apply the refunds due to customers from its earnings sharing mechanism to its electric transmission escrow through 2019. As a result, $38.6 million of WE's earnings sharing refunds were reflected in its electric transmission regulatory liability at December 31, 2019, and $37.2 million of WE's earnings sharing refunds were netted against its electric transmission regulatory asset at December 31, 2018.

(6)	Represents amounts refundable to customers related to our uncollectible expense tracking mechanisms and riders. These mechanisms allow us to recover or refund the difference between actual uncollectible write-offs and the amounts recovered in rates.

(7)	Represents amounts refundable to customers related to programs at the utilities designed to meet energy efficiency standards.

(8)	Represents the deferral of revenues less the associated cost of sales related to Tilden, which were not included in the PSCW's 2015 rate order. As a result of the rate order WE received from the PSCW in December 2019, this regulatory liability was offset against WE's SSR regulatory asset during December 2019.

---

---

(1)

Capacity for our electric generation facilities is based on rated capacity, which is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. Values are primarily based on the net dependable expected capacity ratings for summer 2020 established by tests and may change slightly from year to year. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand.

(2)

Columbia Energy Center is jointly owned by Wisconsin Power and Light, Madison Gas and Electric, and WPS. In October 2016, Wisconsin Power and Light received an order from the PSCW approving amendments to the Columbia Energy Center joint operating agreement between the parties allowing WPS and Madison Gas and Electric to forgo certain capital expenditures at the Columbia Energy Center. As a result, Wisconsin Power and Light will incur these capital expenditures in exchange for a proportional increase in its ownership share of the Columbia Energy Center. Based upon the additional capital expenditures Wisconsin Power and Light expects to incur through June 1, 2020, WPS's ownership interest would decrease to 27.5%.

---

(1)

AROs increased $40.1 million in 2019, primarily due to new natural gas distribution lines being placed into service at PGL. Also in 2019, AROs increased $10.7 million as a result of AROs being recorded for the legal requirement to dismantle, at retirement, the wind generation projects known as Upstream and Coyote Ridge. See Note 2, Acquisitions, for more information on Upstream and Coyote Ridge. AROs decreased $7.3 million due to revisions made to estimated cash flows for the abatement of asbestos at WE.

(2)

AROs decreased $127.3 million in 2018 due to revisions made to estimated cash flows primarily for changes in the cost to retire natural gas distribution pipe at PGL. Also in 2018, AROs increased $10.7 million as a result of revisions made to estimated cash flows for the abatement of asbestos at WPS's Pulliam power plant, and a $10.9 million ARO was recorded for the legal requirement to dismantle, at retirement, the wind generation projects known as Forward Wind Energy Center and Bishop Hill III. See Note 2, Acquisitions, for more information on Forward Wind Energy Center and Bishop Hill III.

(1)	See Note 2, Acquisitions, for more information on the acquisition of Bluewater.

(2)	We had no accumulated impairment losses related to our goodwill as of December 31, 2019.

---

---

---

---

---

(1)

In connection with our outstanding 2007 Junior Notes, we executed an RCC, which we amended on June 29, 2015, for the benefit of persons that buy, hold, or sell a specified series of our long-term indebtedness (covered debt). Our 6.20% Senior Notes due April 1, 2033 have been designated as the covered debt under the RCC. The RCC provides that we may not redeem, defease, or purchase, and that our subsidiaries may not purchase, any 2007 Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, we have received a specified amount of proceeds from the sale of qualifying securities.

(2)	Variable interest rate reset quarterly. The rates were 4.02% and 4.73% as of December 31, 2019 and 2018, respectively. On July 12, 2018 we executed two interest rate swaps that provided a fixed rate of 4.9765% on $250.0 million of the outstanding notes. The effective rates of 4.50% and 4.85% as of December 31, 2019 and 2018, respectively, were blended rates of the variable and fixed portions.

(3)	Effective August 2023, Integrys's $400.0 million of 2013 6.00% Junior Subordinated Notes due 2073 will bear interest at the three-month LIBOR plus 322 basis points and will reset quarterly.

(4)	PGL's First Mortgage Bonds are subject to the terms and conditions of PGL's First Mortgage Indenture dated January 2, 1926, as supplemented. Under the terms of the Indenture, substantially all property owned by PGL is pledged as collateral for these outstanding debt securities.

(5)	NSG's First Mortgage Bonds are subject to the terms and conditions of NSG's First Mortgage Indenture dated April 1, 1955, as supplemented. Under the terms of the Indenture, substantially all property owned by NSG is pledged as collateral for these outstanding debt securities.

(6)	The long-term debt of Bluewater and We Power's subsidiaries amortizes on a mortgage-style basis.

---

(7)	We Power's subsidiaries' senior notes are secured by a collateral assignment of the leases between We Power's subsidiaries and WE related to PWGS and ERGS, as applicable.

(8)	The amount of long-term debt on our balance sheets includes finance/capital lease obligations of $45.9 million and $23.3 million at December 31, 2019 and 2018, respectively.

---

*	Maturity dates listed as semi-annually and monthly are associated with debt that amortizes on a mortgage-style basis.

•	Leases of office space, primarily related to several floors we are leasing in the Aon Center office building in Chicago, Illinois, though April 2029.

•	Land we are leasing related to our Rothschild biomass plant through June 2051.

•	Rail cars we are leasing to transport coal to various generating facilities through February 2021.

---

•	We recorded our minimum lease payments as purchased power expense in cost of sales on our income statement.

•	We recorded the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under finance lease accounting rules as a deferred regulatory asset on our balance sheets.

•	Effective January 1, 2019, the minimum lease payments under the power purchase contract were no longer classified within cost of sales in our income statements, but were instead recorded as a component of depreciation and amortization and interest expense in accordance with Topic 980-842, Regulated Operations – Leases.

•	In accordance with Topic 980-842, the timing of lease expense did not change for this finance lease upon adoption of Topic 842, and still resembled the expense recognition pattern of an operating lease, as the amortization of the right of use assets was modified from what would typically be recorded for a finance lease under Topic 842.

•	We continue to record the difference between the minimum lease payments and the sum of imputed interest and unadjusted amortization costs calculated under the finance lease accounting rules as a deferred regulatory asset on our balance sheets.

---

(1)

For the year ended December 31, 2019, finance lease expense included amortization of right of use assets in the amount of $4.9 million (included in depreciation and amortization expense) and interest on lease liabilities of $3.3 million (included in interest expense). For the years ended December 31, 2018 and 2017, total capital lease expense related to the long-term power purchase agreement was included in cost of sales.

(2)	Operating and short-term lease expense were included as a component of operation and maintenance for the years ended December 31, 2019, 2018, and 2017.

(3)	Prior to our adoption of Topic 842 on January 1, 2019, all cash flows related to the finance lease were recorded as a component of operating cash flows.

(4)

Because our operating leases do not provide an implicit rate of return, we used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments for our operating leases. For our power purchase agreement that meets the definition of a finance lease, the rate implicit in the lease was readily determinable. For our solar land leases that are finance leases, we used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments.

---

---

(1)

In accordance with a settlement agreement with the PSCW, WE flowed through the tax benefit of its repair related deferred tax liabilities in 2018 and 2019, to maintain certain regulatory asset balances at their December 31, 2017 levels. The flow through treatment of the repair related deferred tax liabilities offsets the negative income statement impact of holding the regulatory assets level, resulting in no change to net income. See Note 25, Regulatory Environment, for more information about the impact of the Tax Legislation and the Wisconsin rate order.

(2)	In 2017, the net impact of tax reform in the amount of $206.7 million is represented in both the Federal tax reform and State income taxes net of federal tax benefit lines above.

---

---

---

---

*	The carrying amount of long-term debt excludes finance and capital lease obligations of $45.9 million and $23.3 million at December 31, 2019 and 2018, respectively.

---

(1)	Includes cash collateral posted of $20.0 million.

(2)	Includes cash collateral received of $0.2 million.

(3)	Includes cash collateral posted of $1.1 million.

---

(1)	Consists of $4.0 million, $6.2 million, and $21.2 million to support the business operations of UMERC, Bluewater, and WECI, respectively.

(2)	At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets.

(3)	Primarily for workers compensation self-insurance programs and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets.

(4)	Consists of $11.7 million related to other indemnifications, for which a liability of $10.8 million related to workers compensation coverage was recorded on our balance sheets.

---

---

(1)	Amounts related to the nonregulated entities are included in accumulated other comprehensive loss.

(2)	Amounts related to the utilities and WBS are recorded as net regulatory assets or liabilities.

---

---

*	This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries.

*	This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries.

---

*

In November 2019, the FERC issued an order that addressed the complaints related to ATC's allowed ROE. Due to the numerous rehearing requests filed related to this order, our financials continue to include a $41.9 million liability for potential future refunds that ATC may be required to provide, resulting in reduced equity earnings from ATC. This liability reflects a 10.38% ROE for all periods covered by the complaints.

---

(1)	Distributions of $35.2 million, received in the first quarter of 2017, were approved and recorded as a receivable from ATC in other current assets at December 31, 2016.

(2)	Of this amount, $39.9 million was recorded as a receivable from ATC in other current assets at December 31, 2017.

(1)	In connection with WPS's construction of its two new solar projects, Badger Hollow I and Two Creeks, WPS was required to initially fund the construction of the transmission infrastructure upgrades needed for the new generation. ATC owns these transmission assets and will reimburse WPS for these costs after the new generation has been placed in service.

(2)	In connection with UMERC's construction of the new natural gas-fired generation in the Upper Peninsula of Michigan, UMERC was required to initially fund the construction of the transmission infrastructure upgrades owned by ATC that were needed for the new generation. In the second quarter of 2019, ATC fully reimbursed UMERC for these costs.

---

•	The Wisconsin segment includes the electric and natural gas utility operations of WE, WPS, WG, and UMERC.

•	The Illinois segment includes the natural gas utility and non-utility operations of PGL and NSG.

•	The other states segment includes the natural gas utility and non-utility operations of MERC and MGU.

•

The electric transmission segment includes our approximate 60% ownership interest in ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects, and our approximate 75% ownership interest in ATC Holdco, which was formed to invest in transmission-related projects outside of ATC's traditional footprint.

•	The non-utility energy infrastructure segment includes:

◦	We Power, which owns and leases generating facilities to WE,

◦	Bluewater, which owns underground natural gas storage facilities in Michigan that provide approximately one-third of the current storage needs for our Wisconsin natural gas utilities, and

◦	WECI, which holds our ownership interests in the following wind generating facilities:

▪	90% ownership interest in Bishop Hill III, located in Henry County, Illinois,

▪	80% ownership interest in Coyote Ridge, located in Brookings County, South Dakota, and

▪	80% ownership interest in Upstream, located in Antelope County, Nebraska.

•

The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Bostco, Wisvest, WECC, WBS, and PDL. In the first quarter of 2017, we sold substantially all of the remaining assets of Bostco, and, in October 2018, Bostco was dissolved. In 2019, we sold certain PDL solar power generating facilities. See Note 3, Dispositions, for more information on these sales.

---

*	Total assets at December 31, 2019 reflect an elimination of $1,896.7 million for all lease activity between We Power and WE.

*	Total assets at December 31, 2018 reflect an elimination of $1,968.5 million for all lease activity between We Power and WE.

---

*	Total assets at December 31, 2017 reflect an elimination of $2,038.1 million for all lease activity between We Power and WE.

---

•	the development of additional sources of renewable electric energy supply;

•	the addition of improvements for water quality matters such as treatment technologies to meet regulatory discharge limits and improvements to our cooling water intake systems;

•	the addition of emission control equipment to existing facilities to comply with ambient air quality standards and federal clean air rules;

---

•	the protection of wetlands and waterways, threatened and endangered species, and cultural resources associated with utility construction projects;

•	the retirement of older coal-fired power plants and conversion to modern, efficient, natural gas generation, super-critical pulverized coal generation, and/or replacement with renewable generation;

•	the beneficial use of ash and other products from coal-fired and biomass generating units; and

•	the remediation of former manufactured gas plant sites.

---

---

---

*	See Note 3, Dispositions, for more information on this sale.

---

---

(1)

Amounts are net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impact. The WE and WPS rate orders reflect the majority of the unprotected deferred tax benefits from the Tax Legislation being amortized over two years. For WE, approximately $65 million of tax benefits will be amortized in each of 2020 and 2021. For WPS, approximately $11 million of tax benefits are being amortized in 2020 and approximately $39 million will be amortized in 2021. The unprotected deferred tax benefits related to the unrecovered balances of WE's recently retired plants and its SSR regulatory asset are being used to reduce the related regulatory asset. Unprotected deferred tax benefits by their nature are eligible to be returned to customers in a manner and timeline determined to be appropriate by our regulators.

(2)	The WPS rate order is net of $21 million of refunds related to its 2018 earnings sharing mechanism. These refunds will be made to customers evenly over two years, with half being returned in 2020 and the remainder in 2021.

(3)

The WE amount includes certain deferred tax expense from the Tax Legislation, and the WPS and WG amounts are net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impact. The rate orders for all three gas utilities reflect all of the unprotected deferred tax expense and benefits from the Tax Legislation being amortized evenly over four years. For WE, approximately $5 million of previously deferred tax expense will be amortized each year. For WPS and WG, approximately $5 million and $3 million, respectively, of previously deferred tax benefits will be amortized each year. Unprotected deferred tax expense and benefits by their nature are eligible to be recovered from or returned to customers in a manner and timeline determined to be appropriate by our regulators.

---

---

---

---

*	Earnings per share for the individual quarters may not total the year ended earnings per share amount because of changes to the average number of shares outstanding and changes in incremental issuable shares throughout the year.

---

---

*	Includes shares available for future issuance under our Omnibus Stock Incentive Plan, all of which could be granted as awards of stock options, stock appreciation rights, performance units, restricted stock, or other stock based awards.

---

---

---

---

---

---

---

---

---

---

---

---

---

---

(1)	Net of recoveries.

(2)	Represents amounts written off to the reserve, net of adjustments to regulatory assets.

---

---