WEC ENERGY GROUP, INC. - Quarter Report: 2019 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)



[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2019



[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ________________ to ___________________



Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	IRS Employer Identification No.

001-09057	WEC ENERGY GROUP, INC.	39-1391525
	(A Wisconsin Corporation) 231 West Michigan Street P. O. Box 1331 Milwaukee, WI 53201 414-221-2345

Securities registered pursuant to Section 12(b) of the Act:



Title of Each Class	Trading Symbol	Name of Each Exchange on Which Registered
Common Stock, $.01 Par Value	WEC	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes [X] No [ ]

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes [X] No [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.



	Large accelerated filer [X]		Accelerated filer [ ]
	Non-accelerated filer [ ]		Smaller reporting company [ ]
			Emerging growth company [ ]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes [ ] No [X]

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date (March 31, 2019):

Common Stock, $.01 Par Value, 315,438,398 shares outstanding

Table of Contents

WEC ENERGY GROUP, INC.

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended March 31, 2019

TABLE OF CONTENTS



				Page
	CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION			1
PART I.	FINANCIAL INFORMATION			3
ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)			3
	Condensed Consolidated Income Statements			3
	Condensed Consolidated Statements of Comprehensive Income			4
	Condensed Consolidated Balance Sheets			5
	Condensed Consolidated Statements of Cash Flows			6
	Condensed Consolidated Statements of Equity			7
	Notes to Condensed Consolidated Financial Statements			8
			Page
	Note 1	General Information	8
	Note 2	Acquisitions	8
	Note 3	Operating Revenues	9
	Note 4	Regulatory Assets and Liabilities	12
	Note 5	Property, Plant, and Equipment	13
	Note 6	Common Equity	13
	Note 7	Short-Term Debt and Lines of Credit	14
	Note 8	Long-Term Debt	14
	Note 9	Leases	14
	Note 10	Materials, Supplies, and Inventories	17
	Note 11	Income Taxes	18
	Note 12	Fair Value Measurements	18
	Note 13	Derivative Instruments	20
	Note 14	Guarantees	22
	Note 15	Employee Benefits	22
	Note 16	Goodwill	23
	Note 17	Investment in Transmission Affiliates	23
	Note 18	Segment Information	24
	Note 19	Variable Interest Entities	25
	Note 20	Commitments and Contingencies	26
	Note 21	Supplemental Cash Flow Information	30
	Note 22	Regulatory Environment	30
	Note 23	New Accounting Pronouncements	33
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			34
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			51
ITEM 4.	CONTROLS AND PROCEDURES			51
PART II.	OTHER INFORMATION			52
ITEM 1.	LEGAL PROCEEDINGS			52
ITEM 1A.	RISK FACTORS			52
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			53
ITEM 6.	EXHIBITS			53
SIGNATURE				54



03/31/2019 Form 10-Q	i	WEC Energy Group, Inc.

Table of Contents

GLOSSARY OF TERMS AND ABBREVIATIONS

The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:



Subsidiaries and Affiliates
ATC		American Transmission Company LLC
ATC Holdco		ATC Holdco LLC
Bishop Hill III		Bishop Hill Energy III LLC
Bluewater		Bluewater Natural Gas Holding, LLC
Coyote Ridge		Coyote Ridge Wind, LLC
Integrys		Integrys Holding, Inc.
MERC		Minnesota Energy Resources Corporation
MGU		Michigan Gas Utilities Corporation
NSG		North Shore Gas Company
PGL		The Peoples Gas Light and Coke Company
UMERC		Upper Michigan Energy Resources Corporation
Upstream		Upstream Wind Energy LLC
WE		Wisconsin Electric Power Company
We Power		W.E. Power, LLC
WG		Wisconsin Gas LLC
WPS		Wisconsin Public Service Corporation

Federal and State Regulatory Agencies
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
ICC		Illinois Commerce Commission
IRS		United States Internal Revenue Service
MDEQ		Michigan Department of Environmental Quality
MPSC		Michigan Public Service Commission
MPUC		Minnesota Public Utilities Commission
PSCW		Public Service Commission of Wisconsin
SEC		United States Securities and Exchange Commission
WDNR		Wisconsin Department of Natural Resources

Accounting Terms
AFUDC		Allowance for Funds Used During Construction
ASU		Accounting Standards Update
FASB		Financial Accounting Standards Board
GAAP		United States Generally Accepted Accounting Principles
LIFO		Last-In, First-Out
OPEB		Other Postretirement Employee Benefits

Environmental Terms
CAA		Clean Air Act
CO₂		Carbon Dioxide
GHG		Greenhouse Gas
NOV		Notice of Violation
WPDES		Wisconsin Pollutant Discharge Elimination System

Measurements
Dth		Dekatherm
MW		Megawatt
MWh		Megawatt-hour



03/31/2019 Form 10-Q	ii	WEC Energy Group, Inc.

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Other Terms and Abbreviations
2007 Junior Notes		WEC Energy Group, Inc.'s 2007 Junior Subordinated Notes Due 2067
ALJ		Administrative Law Judge
ERGS		Elm Road Generating Station
Exchange Act		Securities Exchange Act of 1934, as amended
FTR		Financial Transmission Rights
MISO		Midcontinent Independent System Operator, Inc.
OCPP		Oak Creek Power Plant
OC 5		Oak Creek Power Plant Unit 5
OC 6		Oak Creek Power Plant Unit 6
OC 7		Oak Creek Power Plant Unit 7
OC 8		Oak Creek Power Plant Unit 8
PIPP		Presque Isle Power Plant
QIP		Qualifying Infrastructure Plant
ROE		Return on Equity
SMP		Natural Gas System Modernization Program
SMRP		System Modernization and Reliability Project
SSR		System Support Resource
Tax Legislation		Tax Cuts and Jobs Act of 2017
Tilden		Tilden Mining Company



03/31/2019 Form 10-Q	iii	WEC Energy Group, Inc.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

In this report, we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act. Readers are cautioned not to place undue reliance on these forward-looking statements. Forward-looking statements may be identified by reference to a future period or periods or by the use of terms such as "anticipates," "believes," "could," "estimates," "expects," "forecasts," "goals," "guidance," "intends," "may," "objectives," "plans," "possible," "potential," "projects," "seeks," "should," "targets," "will," or variations of these terms.

Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of capital projects, sales and customer growth, rate actions and related filings with regulatory authorities, environmental and other regulations and associated compliance costs, legal proceedings, dividend payout ratios, effective tax rates, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, environmental matters, liquidity and capital resources, and other matters.

Forward-looking statements are subject to a number of risks and uncertainties that could cause our actual results to differ materially from those expressed or implied in the statements. These risks and uncertainties include those described in risk factors as set forth in this report and our 2018 Annual Report on Form 10-K, and those identified below:


•	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 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, as well as the recovery of the related costs through rates;

•

The impact of 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 that affect our ability to use production tax credits and investment tax credits;


•	The remaining uncertainty surrounding the Tax Legislation enacted in December 2017, including implementing regulations and IRS interpretations, the amount to be returned to our ratepayers, and any further impact on our and our subsidiaries’ credit ratings;

•

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;


•	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;


•	Increased pressure on us by investors and other stakeholder groups to take more aggressive action to reduce future 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,



03/31/2019 Form 10-Q	1	WEC Energy Group, Inc.

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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;


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


•	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 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;


•	The financial performance of ATC and its corresponding contribution to our earnings, as well as the ability of ATC and Duke-American Transmission Company to obtain the required approvals for their transmission projects;


•	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, if at all, 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 Section 404 of the Sarbanes-Oxley Act, 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 expressly disclaim any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.



03/31/2019 Form 10-Q	2	WEC Energy Group, Inc.

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WEC ENERGY GROUP, INC.



CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited)	Three Months Ended
	March 31
(in millions, except per share amounts)	2019			2018
Operating revenues	$	2,377.4		$	2,286.5

Operating expenses
Cost of sales	1,009.6			972.1
Other operation and maintenance	550.6			511.9
Depreciation and amortization	226.4			208.6
Property and revenue taxes	48.0			48.8
Total operating expenses	1,834.6			1,741.4

Operating income	542.8			545.1

Equity in earnings of transmission affiliates	36.1			32.8
Other income, net	30.9			7.5
Interest expense	124.4			106.7
Other expense	(57.4		)	(66.4		)

Income before income taxes	485.4			478.7
Income tax expense	65.0			88.3
Net income	420.4			390.4

Preferred stock dividends of subsidiary	0.3			0.3
Net income attributed to common shareholders	$	420.1		$	390.1

Earnings per share
Basic	$	1.33		$	1.24
Diluted	$	1.33		$	1.23

Weighted average common shares outstanding
Basic	315.5			315.5
Diluted	316.7			316.9

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.



03/31/2019 Form 10-Q	3	WEC Energy Group, Inc.

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WEC ENERGY GROUP, INC.



CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)	Three Months Ended
	March 31
(in millions)	2019			2018
Net income	$	420.4		$	390.4

Other comprehensive (loss) income, net of tax
Derivatives accounted for as cash flow hedges
Derivative losses, net of tax	(1.2		)	—
Reclassification of net gains to net income, net of tax	(0.3		)	(0.2		)
Cash flow hedges, net	(1.5		)	(0.2		)

Defined benefit plans
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax	0.1			1.9

Other comprehensive (loss) income, net of tax	(1.4		)	1.7

Comprehensive income	419.0			392.1

Preferred stock dividends of subsidiary	0.3			0.3
Comprehensive income attributed to common shareholders	$	418.7		$	391.8

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.



03/31/2019 Form 10-Q	4	WEC Energy Group, Inc.

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WEC ENERGY GROUP, INC.



CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts)	March 31, 2019			December 31, 2018
Assets
Current assets
Cash and cash equivalents	$	30.6		$	84.5
Accounts receivable and unbilled revenues, net of reserves of $163.2 and $149.2, respectively	1,430.1			1,280.9
Materials, supplies, and inventories	330.1			548.2
Prepayments	167.2			256.8
Other	50.3			77.2
Current assets	2,008.3			2,247.6

Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $8,589.0 and $8,636.6, respectively	22,193.3			22,000.9
Regulatory assets	4,009.8			3,805.1
Equity investment in transmission affiliates	1,670.6			1,665.3
Goodwill	3,052.8			3,052.8
Other	802.3			704.1
Long-term assets	31,728.8			31,228.2
Total assets	$	33,737.1		$	33,475.8

Liabilities and Equity
Current liabilities
Short-term debt	$	1,145.2		$	1,440.1
Current portion of long-term debt	366.0			365.0
Accounts payable	674.1			876.4
Accrued payroll and benefits	125.9			185.4
Other	578.7			464.8
Current liabilities	2,889.9			3,331.7

Long-term liabilities
Long-term debt	10,326.7			9,994.0
Deferred income taxes	3,459.9			3,388.1
Deferred revenue, net	514.5			520.4
Regulatory liabilities	4,274.3			4,251.6
Environmental remediation liabilities	631.8			616.4
Pension and OPEB obligations	418.1			422.8
Other	1,109.8			1,108.1
Long-term liabilities	20,735.1			20,301.4

Commitments and contingencies (Note 20)

Common shareholders' equity
Common stock – $0.01 par value; 325,000,000 shares authorized; 315,438,398 and 315,523,192 shares outstanding, respectively	3.2			3.2
Additional paid in capital	4,213.2			4,250.1
Retained earnings	5,772.1			5,538.2
Accumulated other comprehensive loss	(4.0		)	(2.6		)
Common shareholders' equity	9,984.5			9,788.9

Preferred stock of subsidiary	30.4			30.4
Noncontrolling interests	97.2			23.4
Total liabilities and equity	$	33,737.1		$	33,475.8

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.



03/31/2019 Form 10-Q	5	WEC Energy Group, Inc.

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WEC ENERGY GROUP, INC.



CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Three Months Ended
	March 31
(in millions)	2019			2018
Operating Activities
Net income	$	420.4		$	390.4
Reconciliation to cash provided by operating activities
Depreciation and amortization	226.4			208.6
Deferred income taxes and investment tax credits, net	17.2			17.0
Contributions and payments related to pension and OPEB plans	(4.2		)	(5.3		)
Equity income in transmission affiliates, net of distributions	(1.9		)	7.1
Change in –
Accounts receivable and unbilled revenues	(124.3		)	(60.1		)
Materials, supplies, and inventories	218.3			163.0
Other current assets	125.1			81.3
Accounts payable	(204.3		)	(170.9		)
Other current liabilities	54.6			128.6
Other, net	8.4			134.3
Net cash provided by operating activities	735.7			894.0

Investing Activities
Capital expenditures	(358.8		)	(439.6		)
Acquisition of Upstream, net of cash and restricted cash acquired of $9.2	(268.2		)	—
Capital contributions to transmission affiliates	(3.4		)	(12.8		)
Proceeds from the sale of assets	10.6			0.8
Proceeds from the sale of investments held in rabbi trust	0.1			16.5
Other, net	13.1			(0.7		)
Net cash used in investing activities	(606.6		)	(435.8		)

Financing Activities
Exercise of stock options	32.6			2.1
Purchase of common stock	(70.7		)	(15.8		)
Dividends paid on common stock	(186.2		)	(174.2		)
Issuance of long-term debt	350.0			—
Retirement of long-term debt	(13.3		)	(12.6		)
Change in short-term debt	(294.9		)	(244.3		)
Other, net	(3.6		)	(0.3		)
Net cash used in financing activities	(186.1		)	(445.1		)

Net change in cash, cash equivalents, and restricted cash	(57.0		)	13.1
Cash, cash equivalents, and restricted cash at beginning of period	146.1			58.6
Cash, cash equivalents, and restricted cash at end of period	$	89.1		$	71.7

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.



03/31/2019 Form 10-Q	6	WEC Energy Group, Inc.

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WEC ENERGY GROUP, INC.



CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited)

	WEC Energy Group Common Shareholders' Equity
(in millions, except per share amounts)	Common Stock		Additional Paid In Capital			Retained Earnings			Accumulated Other Comprehensive Loss			Total Common Shareholders' Equity			Preferred Stock of Subsidiary		Non-controlling Interests		Total Equity
Balance at December 31, 2018	$	3.2	$	4,250.1		$	5,538.2		$	(2.6	)	$	9,788.9		$	30.4	$	23.4	$	9,842.7
Net income attributed to common shareholders	—		—			420.1			—			420.1			—		—		420.1
Other comprehensive loss	—		—			—			(1.4		)	(1.4		)	—		—		(1.4		)
Common stock dividends of $0.59 per share	—		—			(186.2		)	—			(186.2		)	—		—		(186.2		)
Exercise of stock options	—		32.6			—			—			32.6			—		—		32.6
Purchase of common stock	—		(70.7		)	—			—			(70.7		)	—		—		(70.7		)
Acquisition of a noncontrolling interest	—		—			—			—			—			—		69.0		69.0
Capital contributions from noncontrolling interest	—		—			—			—			—			—		4.8		4.8
Stock-based compensation and other	—		1.2			—			—			1.2			—		—		1.2
Balance at March 31, 2019	$	3.2	$	4,213.2		$	5,772.1		$	(4.0	)	$	9,984.5		$	30.4	$	97.2	$	10,112.1



	WEC Energy Group Common Shareholders' Equity
(in millions, except per share amounts)	Common Stock		Additional Paid In Capital			Retained Earnings			Accumulated Other Comprehensive Income		Total Common Shareholders' Equity			Preferred Stock of Subsidiary		Non-controlling Interests		Total Equity
Balance at December 31, 2017	$	3.2	$	4,278.5		$	5,176.8		$	2.9	$	9,461.4		$	30.4	$	—	$	9,491.8
Net income attributed to common shareholders	—		—			390.1			—		390.1			—		—		390.1
Other comprehensive income	—		—			—			1.7		1.7			—		—		1.7
Common stock dividends of $0.5525 per share	—		—			(174.2		)	—		(174.2		)	—		—		(174.2		)
Exercise of stock options	—		2.1			—			—		2.1			—		—		2.1
Purchase of common stock	—		(15.8		)	—			—		(15.8		)	—		—		(15.8		)
Stock-based compensation and other	—		2.5			—			—		2.5			—		—		2.5
Balance at March 31, 2018	$	3.2	$	4,267.3		$	5,392.7		$	4.6	$	9,667.8		$	30.4	$	—	$	9,698.2

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.



03/31/2019 Form 10-Q	7	WEC Energy Group, Inc.

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WEC ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

March 31, 2019

NOTE 1—GENERAL INFORMATION

WEC Energy Group serves approximately 1.6 million electric customers and 2.9 million natural gas customers, and owns approximately 60% of ATC.

As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, statements of comprehensive income, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. In this report, when we refer to "the Company," "us," "we," "our," or "ours," we are referring to WEC Energy Group and all of its subsidiaries.

On our financial statements, we consolidate our majority-owned subsidiaries and reflect noncontrolling interests for the portion of entities that we do not own as a component of consolidated equity separate from the equity attributable to our shareholders. The noncontrolling interests that we reported as equity on our balance sheet as of March 31, 2019 related to the minority interests at Bishop Hill III, Coyote Ridge, and Upstream held by third parties. We completed the acquisition of an 80% membership interest in Upstream during January 2019. See Note 2, Acquisitions, for more information.

We use the equity method to account for investments in companies we do not control but over which we exercise significant influence regarding their operating and financial policies. As a result of our limited voting rights, we account for ATC and ATC Holdco as equity method investments. See Note 17, Investment in Transmission Affiliates, for more information.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2018. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three months ended March 31, 2019, are not necessarily indicative of expected results for 2019 due to seasonal variations and other factors.

In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results.

NOTE 2—ACQUISITIONS

All the acquisitions discussed below were accounted for as asset acquisitions.

Acquisition of a Wind Generation Facility in Nebraska

In January 2019, we completed the acquisition of an 80% membership interest in Upstream, a commercially operational 202.5 MW wind generating facility, for $268.2 million, which included transactions costs and is net of cash and restricted cash acquired of $9.2 million. Upstream is located in Antelope County, Nebraska and supplies energy to the Southwest Power Pool. Upstream's revenue will be substantially fixed over a 10-year period through an agreement with an unaffiliated third party. Under the Tax Legislation, our investment in Upstream qualifies for production tax credits and 100% bonus depreciation. Upstream is included in the non-utility energy infrastructure segment.

Acquisition of a Wind Generation Facility in South Dakota

In December 2018, we acquired an 80% ownership interest in Coyote Ridge, a 97.5 MW wind generating facility under construction in Brookings County, South Dakota, for $61.6 million, which included transaction costs. This wind generating facility is expected to be in service by the end of 2019. Upon completion, we expect our total investment in Coyote Ridge to be $145 million. The project has a 12-year offtake agreement with an unaffiliated third party for all of the energy produced by the facility. Under the Tax Legislation, our investment in Coyote Ridge is expected to qualify for production tax credits and 100% bonus depreciation. We are entitled to 99% of the tax benefits related to this facility for the first 11 years of commercial operation, after which we will be entitled to tax benefits equal to our ownership interest. Coyote Ridge is included in the non-utility energy infrastructure segment.



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Acquisition of a Wind Energy Generation Facility in Illinois

In August 2018, we completed the acquisition of an 80% membership interest in a commercially operational 132 MW wind generating facility located in Henry County, Illinois, known as Bishop Hill III, for $144.7 million, which included transaction costs and was net of restricted cash acquired of $4.5 million. In December 2018, we completed the acquisition of an additional 10% membership interest in Bishop Hill III, for $18.2 million. Bishop Hill III has a 22-year offtake agreement with an unaffiliated third party for all of the energy produced by the facility. Under the Tax Legislation, our investment in Bishop Hill III qualifies for production tax credits and 100% bonus depreciation. Bishop Hill III is included in the non-utility energy infrastructure segment.

Acquisition of a Wind Energy Generation Facility in Wisconsin

In April 2018, WPS, along with two unaffiliated utilities, completed the purchase of Forward Wind Energy Center, which consists of 86 wind turbines located in Wisconsin with a total capacity of 138 MW. The aggregate purchase price was $172.9 million of which WPS’s proportionate share was 44.6%, or $77.1 million. In addition, we incurred transaction costs that are recorded to a regulatory asset. Since 2008 and up until the acquisition, WPS purchased 44.6% of the facility’s energy output under a power purchase agreement.

Under a joint ownership agreement with the two other utilities, WPS is entitled to its share of generating capability and output of the facility equal to its ownership interest. WPS is also paying its ownership share of additional capital expenditures and operating expenses. Forward Wind Energy Center is included in the Wisconsin segment.

NOTE 3—OPERATING REVENUES

For more information about our significant accounting policies related to operating revenues, see Note 1(d), Operating Revenues, in our 2018 Annual Report on Form 10-K.

Disaggregation of Operating Revenues

The following tables present our operating revenues disaggregated by revenue source. We do not have any revenues associated with our electric transmission segment. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors. For our segments, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations have different expectations of service, energy and demand requirements, and are impacted by regulatory activities within their jurisdictions.



(in millions)	Wisconsin		Illinois			Other States			Total Utility Operations			Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations			WEC Energy Group Consolidated
Three Months Ended March 31, 2019
Electric	$	1,061.8	$	—		$	—		$	1,061.8		$	—	$	—	$	—		$	1,061.8
Natural gas	564.9		544.6			185.2			1,294.7			16.4		—		(14.7		)	1,296.4
Total regulated revenues	1,626.7		544.6			185.2			2,356.5			16.4		—		(14.7		)	2,358.2
Other non-utility revenues	—		0.1			4.1			4.2			13.3		1.5		(0.7		)	18.3
Total revenues from contracts with customers	1,626.7		544.7			189.3			2,360.7			29.7		1.5		(15.4		)	2,376.5
Other operating revenues	6.7		(8.2		)	(4.1		)	(5.6		)	98.1		0.2		(91.8		)	0.9
Total operating revenues	$	1,633.4	$	536.5		$	185.2		$	2,355.1		$	127.8	$	1.7	$	(107.2	)	$	2,377.4



03/31/2019 Form 10-Q	9	WEC Energy Group, Inc.

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(in millions)	Wisconsin		Illinois			Other States			Total Utility Operations			Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations			WEC Energy Group Consolidated
Three Months Ended March 31, 2018
Electric	$	1,067.7	$	—		$	—		$	1,067.7		$	—	$	—	$	—		$	1,067.7
Natural gas	518.0		507.6			172.7			1,198.3			14.9		—		(2.5		)	1,210.7
Total regulated revenues	1,585.7		507.6			172.7			2,266.0			14.9		—		(2.5		)	2,278.4
Other non-utility revenues	—		—			3.9			3.9			7.1		1.3		(0.7		)	11.6
Total revenues from contracts with customers	1,585.7		507.6			176.6			2,269.9			22.0		1.3		(3.2		)	2,290.0
Other operating revenues	3.4		(0.3		)	(6.7		)	(3.6		)	96.1		0.1		(96.1		)	(3.5		)
Total operating revenues	$	1,589.1	$	507.3		$	169.9		$	2,266.3		$	118.1	$	1.4	$	(99.3	)	$	2,286.5

Revenues from Contracts with Customers

Electric Utility Operating Revenues

The following table disaggregates electric utility operating revenues into customer class:



	Electric Utility Operating Revenues
	Three Months Ended March 31
(in millions)	2019		2018
Residential	$	406.7	$	384.3
Small commercial and industrial	333.9		330.7
Large commercial and industrial	212.3		203.9
Other	7.8		7.7
Total retail revenues	960.7		926.6
Wholesale	47.7		54.9
Resale	40.8		73.8
Steam	10.1		9.7
Other utility revenues	2.5		2.7
Total electric utility operating revenues	$	1,061.8	$	1,067.7

Natural Gas Utility Operating Revenues

The following tables disaggregate natural gas utility operating revenues into customer class:



(in millions)	Wisconsin			Illinois			Other States			Total Natural Gas Utility Operating Revenues
Three Months Ended March 31, 2019
Residential	$	383.9		$	354.0		$	125.2		$	863.1
Commercial and industrial	199.7			116.2			72.0			387.9
Total retail revenues	583.6			470.2			197.2			1,251.0
Transport	21.9			87.2			11.1			120.2
Other utility revenues *	(40.6		)	(12.8		)	(23.1		)	(76.5		)
Total natural gas utility operating revenues	$	564.9		$	544.6		$	185.2		$	1,294.7



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(in millions)	Wisconsin			Illinois			Other States			Total Natural Gas Utility Operating Revenues
Three Months Ended March 31, 2018
Residential	$	356.7		$	332.6		$	123.2		$	812.5
Commercial and industrial	187.9			109.4			64.7			362.0
Total retail revenues	544.6			442.0			187.9			1,174.5
Transport	21.0			77.7			9.9			108.6
Other utility revenues *	(47.6		)	(12.1		)	(25.1		)	(84.8		)
Total natural gas utility operating revenues	$	518.0		$	507.6		$	172.7		$	1,198.3


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

Other Non-Utility Operating Revenues

Other non-utility operating revenues consist primarily of the following:



	Three Months Ended March 31
(in millions)	2019		2018
We Power revenues	$	6.4	$	6.4
Appliance service revenues	4.1		3.9
Distributed renewable solar project revenues	1.5		1.3
Wind generation revenues	6.2		—
Other	0.1		—
Total other non-utility operating revenues	$	18.3	$	11.6

As part of the construction of the We Power electric generating units, we capitalized interest during construction, which is included in property, plant, and equipment. As allowed by the PSCW, we collected carrying costs from WE's utility customers during construction. The equity portion of these carrying costs was recorded as deferred revenue, and we continually amortize the deferred revenues over the life of the related lease term that We Power has with WE. During both the three months ended March 31, 2019 and 2018, we recorded $6.4 million of revenue related to these deferred carrying costs, which were included in the contract liability balance at the beginning of the period. This contract liability is presented as deferred revenue, net on our balance sheets.

In January 2019, we completed the acquisition of an 80% membership interest in Upstream. Upstream's revenue will be substantially fixed over a 10-year period through an agreement with an unaffiliated third party. See Note 2, Acquisitions, for more information on this acquisition. We recognize revenue as energy is produced and delivered to the customer within the production month.

Other Operating Revenues

Other operating revenues consist primarily of the following:



	Three Months Ended March 31
(in millions)	2019			2018
Alternative revenues *	$	(19.7	)	$	(16.1	)
Late payment charges	13.2			11.4
Rental revenues	7.4			1.2
Total other operating revenues	$	0.9		$	(3.5	)


*	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.



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NOTE 4—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets and liabilities were reflected on our balance sheets at March 31, 2019 and December 31, 2018. For more information on our regulatory assets and liabilities, see Note 5, Regulatory Assets and Liabilities, in our 2018 Annual Report on Form 10-K.



(in millions)	March 31, 2019		December 31, 2018
Regulatory assets
Pension and OPEB costs	$	1,173.8	$	1,193.5
Plant retirements *	1,027.9		832.3
Environmental remediation costs	697.6		687.1
Income tax related items	384.8		369.1
SSR	317.9		316.7
Asset retirement obligations	223.4		185.4
Uncollectible expense	47.6		38.7
Electric transmission costs	41.7		58.1
We Power generation	36.1		43.0
Energy efficiency programs	11.3		14.0
Other, net	75.0		117.9
Total regulatory assets	$	4,037.1	$	3,855.8

Balance sheet presentation
Other current assets	$	27.3	$	50.7
Regulatory assets	4,009.8		3,805.1
Total regulatory assets	$	4,037.1	$	3,855.8


*	On March 31, 2019, the PIPP generating units were retired by WE. See Note 5, Property, Plant, and Equipment, for more information on the retirement of the PIPP units.



(in millions)	March 31, 2019		December 31, 2018
Regulatory liabilities
Income tax related items	$	2,401.2	$	2,406.6
Removal costs	1,330.8		1,329.6
Pension and OPEB costs	235.7		238.3
Mines deferral	129.1		120.8
Energy costs refundable through rate adjustments	103.0		39.6
Decoupling	51.0		30.5
Energy efficiency programs	45.7		31.7
Earnings sharing mechanisms	29.9		30.0
Uncollectible expense	29.5		30.5
Derivatives	9.0		16.4
Other, net	13.3		14.4
Total regulatory liabilities	$	4,378.2	$	4,288.4

Balance sheet presentation
Other current liabilities	$	103.9	$	36.8
Regulatory liabilities	4,274.3		4,251.6
Total regulatory liabilities	$	4,378.2	$	4,288.4



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NOTE 5—PROPERTY, PLANT, AND EQUIPMENT

We have evaluated future plans for our older and less efficient fossil fuel generating units and have retired several plants within the Wisconsin segment. In addition, a severance liability was recorded in other current liabilities on our balance sheets related to these plant retirements.



(in millions)
Severance liability at December 31, 2018	$	15.7
Severance payments	(1.7		)
Total severance liability at March 31, 2019	$	14.0

Presque Isle Power Plant

Pursuant to MISO's April 2018 approval of the retirement of the PIPP, these units were retired on March 31, 2019. Also on March 31, 2019, UMERC's new natural gas-fired generation in the Upper Peninsula of Michigan began commercial operation. The carrying value of the PIPP units was $172.1 million at March 31, 2019. This amount included the net book value of $183.1 million, which was classified as a regulatory asset on our balance sheet. In addition, an $11.0 million cost of removal reserve related to the PIPP units remained classified as a regulatory liability at March 31, 2019. WE will amortize this regulatory asset on a straight-line basis using the composite depreciation rates approved by the PSCW before the units were retired.

NOTE 6—COMMON EQUITY

Stock-Based Compensation

During the first quarter of 2019, the Compensation Committee of our Board of Directors awarded the following stock-based compensation awards to our directors, officers, and certain other key employees:



Award Type		Number of Awards
Stock options ⁽¹⁾		476,418
Restricted shares⁽²⁾		73,571
Performance units		148,036


⁽¹⁾	Stock options awarded had a weighted-average exercise price of $68.18 and a weighted-average grant date fair value of $8.60 per option.


⁽²⁾	Restricted shares awarded had a weighted-average grant date fair value of $68.18 per share.

Restrictions

Our ability as a holding company to pay common stock dividends primarily depends on the availability of funds received from our utility subsidiaries, We Power, and ATC Holding. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans, or advances. All of our utility subsidiaries, with the exception of UMERC and MGU, are prohibited from loaning funds to us, either directly or indirectly. See Note 10, Common Equity, in our 2018 Annual Report on Form 10-K for additional information on these and other restrictions.

We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.

Common Stock Dividends

On April 18, 2019, our Board of Directors declared a quarterly cash dividend of $0.59 per share, payable on June 1, 2019, to shareholders of record on May 14, 2019.



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NOTE 7—SHORT-TERM DEBT AND LINES OF CREDIT

The following table shows our short-term borrowings and their corresponding weighted-average interest rates:



(in millions, except percentages)	March 31, 2019			December 31, 2018
Commercial paper
Amount outstanding	$	1,145.2		$	1,440.1
Weighted-average interest rate on amounts outstanding	2.75		%	2.92		%

Our average amount of commercial paper borrowings based on daily outstanding balances during the three months ended March 31, 2019, was $1,487.0 million with a weighted-average interest rate during the period of 2.81%.

The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing programs, including available capacity under these facilities:



(in millions)	Maturity	March 31, 2019
WEC Energy Group	October 2022	$	1,200.0
WE	October 2022	500.0
WPS	October 2022	400.0
WG	October 2022	350.0
PGL	October 2022	350.0
Total short-term credit capacity		$	2,800.0
Less:
Letters of credit issued inside credit facilities		$	3.0
Commercial paper outstanding		1,145.2
Available capacity under existing agreements		$	1,651.8

NOTE 8—LONG-TERM DEBT

In March 2019, we issued $350.0 million of 3.10% Senior Notes due March 8, 2022. We used the net proceeds to repay short-term debt, and for working capital and other general corporate purposes.

NOTE 9—LEASES

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which revised the previous guidance (Topic 840) regarding accounting for leases. Revisions include requiring a lessee to recognize a lease asset and a lease liability on its balance sheet for each lease, including operating leases with an initial term greater than 12 months. In addition, required quantitative and qualitative disclosures related to lease agreements were expanded.

As required, we adopted Topic 842 effective January 1, 2019. We utilized the following practical expedients, which were available under ASU 2016-02, in our adoption of the new lease guidance.


•	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.

We did not elect the practical expedient allowing entities to account for the nonlease components in lease contracts as part of the single lease component to which they were related. Instead, in accordance with Accounting Standards Codification 842-10-15-31, our policy is to account for each lease component separately from the nonlease components of the contract.

We did not elect the practical expedient to use hindsight in determining the lease term and in assessing impairment of our right of use assets. No impairment losses were included in the measurement of our right of use assets upon our adoption of Topic 842.

In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842, which is an amendment to ASU 2016-02. Land easements (also commonly referred to as rights of way) represent the right to use,



03/31/2019 Form 10-Q	14	WEC Energy Group, Inc.

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access or cross another entity's land for a specified purpose. This new guidance permits an entity to elect a transitional practical expedient, to be applied consistently, to not evaluate under Topic 842 land easements that were already in existence or had expired at the time of the entity's adoption of Topic 842. Once Topic 842 is adopted, an entity is required to apply Topic 842 prospectively to all new (or modified) land easements to determine whether the arrangement should be accounted for as a lease. We elected this practical expedient, resulting in none of our land easements being treated as leases upon our adoption of Topic 842.

In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842): Targeted Improvements, which amends ASU 2016-02 and allows entities the option to initially apply Topic 842 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, if required. We used the optional transition method to apply the new guidance as of January 1, 2019, rather than as of the earliest period presented. We did not require a cumulative-effect adjustment upon adoption of Topic 842.

Right of use assets and related lease liabilities related to our operating leases that were recorded upon adoption of Topic 842 were $49.0 million and $48.8 million, respectively. Regarding our finance lease, while the adoption of Topic 842 changed the classification of expense related to this lease on a prospective basis, it had no impact on the total amount of lease expense recorded, and did not impact the lease asset and related liability amounts recorded on our balance sheets.

Obligations Under Operating Leases

We have recorded right of use assets and lease liabilities associated with the following operating leases.


•	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, and also land leases related to several non-utility solar facilities through various months in 2033 and 2034.


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

The operating leases generally require us to pay property taxes, insurance premiums, and operating and maintenance costs associated with the leased property. Many of our leases contain options to renew past the initial term, as set forth in the lease agreement.

Obligations Under Finance Lease

In 1997, we entered into a 25-year power purchase contract with an unaffiliated independent power producer. The contract, for 236 MWs of firm capacity from a natural gas-fired cogeneration facility, includes zero minimum energy requirements. When the contract expires in 2022, we may, at our option and with proper notice, renew for another ten years, purchase the generating facility at fair market value, or allow the contract to expire. We originally recorded this leased facility and corresponding obligation on our balance sheets at the estimated fair value of the plant's electric generating facilities. Minimum lease payments are a function of the 236 MWs of firm capacity we receive from the plant and the fixed monthly capacity rate published in the lease.

Prior to our adoption of Topic 842 on January 1, 2019, we accounted for this finance lease under Topic 980-840, Regulated Operations – Leases, as follows:


•	We recorded our minimum lease payments as purchased power expense 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.

In conjunction with our adoption of Topic 842, while the timing of expense recognition related to this finance lease did not change, classification of the lease expense changed as follows:


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


•	In order to ensure 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, the amortization of the right of use assets was modified from what would typically be recorded for a finance lease under Topic 980-842.



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•	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.

Due to the timing and the amounts of the minimum lease payments, the regulatory asset increased to $78.5 million in 2009, at which time the regulatory asset began to be reduced to zero over the remaining life of the contract. The total obligation under the finance lease was $22.1 million at March 31, 2019, and will decrease to zero over the remaining life of the contract.

Amounts Recognized in the Financial Statements

The components of lease expense and supplemental cash flow information related to our leases for the quarters ended March 31 are as follows:



(in millions)	2019			2018
Finance/capital lease expense ⁽¹⁾	$	2.0		$	1.9
Operating lease expense ⁽²⁾	1.4			1.4
Short-term lease expense ⁽²⁾	—			0.1
Total lease expense	$	3.4		$	3.4

Other information

Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from finance/capital lease ⁽³⁾	$	0.9		$	1.9
Operating cash flows from operating leases	$	1.7		$	1.7
Financing cash flows from finance lease ⁽³⁾	$	1.2		$	—

Non-cash activity - right of use assets obtained in exchange for operating lease liabilities	$	49.0

Remaining lease term – finance lease	3.2 years
Weighted-average remaining lease term – operating leases	13.2 years

Discount rate – finance lease ⁽⁴⁾	15.8		%
Weighted average discount rate – operating leases ⁽⁴⁾	4.6		%

⁽¹⁾

For the quarter ended March 31, 2019, finance lease expense included amortization of right of use assets in the amount of $1.1 million (included in depreciation and amortization expense) and interest on lease liabilities of $0.9 million (included in interest expense). For the quarter ended March 31, 2018, total finance lease expense related to the long-term power purchase agreement was included in cost of sales.


⁽²⁾	Operating lease expense was included as a component of operation and maintenance for the quarters ended March 31, 2019 and 2018.


⁽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 financing lease, the rate implicit in the lease was readily determinable.

The following table summarizes our finance lease right of use asset, which was included in property, plant and equipment on our balance sheets:



(in millions)	March 31, 2019			December 31, 2018
Long-term power purchase commitment	$	140.3		$	140.3
Accumulated amortization	(122.3		)	(120.9		)
Total finance lease right of use asset/capital lease asset	$	18.0		$	19.4

Right of use assets related to operating leases were $48.2 million at March 31, 2019, and were included in other long-term assets on our balance sheets.



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Future minimum lease payments under our operating leases and our finance lease, and the present value of our net minimum lease payments as of March 31, 2019, were as follows:



(in millions)	Total Operating Leases			Power Purchase Commitment
Nine months ended December 31, 2019	$	4.5		$	6.2
2020	7.1			8.8
2021	5.1			9.4
2022	5.1			4.2
2023	5.2			—
2024	5.1			—
Thereafter	33.0			—
Total minimum lease payments	65.1			28.6
Less: Interest	(17.3		)	(6.5		)
Present value of minimum lease payments	47.8			22.1
Less: Short-term lease liabilities	(4.1		)	(5.2		)
Long-term lease liabilities	$	43.7		$	16.9

Short-term and long-term lease liabilities related to operating leases were included in other current liabilities and other long-term liabilities on the balance sheets, respectively.

At December 31, 2018, short-term and long-term liabilities under our capital lease were $4.9 million and $18.4 million, respectively. Short-term and long-term lease liabilities related to our finance/capital lease were included in current portion of long-term debt and long-term debt on the balance sheets, respectively.

Significant Judgments and Other Information

We are currently party to several easement agreements that allow us access to land we do not own for the purpose of constructing and maintaining certain electric power and natural gas equipment. The majority of payments we make related to easements relate to our wind farms. We have not classified our easements as leases because we view the entire parcel of land specified in our easement agreements to be the identified asset, not just that portion of the parcel that contains our easement. As such, we have concluded that we do not control the use of an identified asset related to our easement agreements, nor do we obtain substantially all of the economic benefits associated with these shared-use assets.

As of May 3, 2019, we have not entered into any material operating leases that have not yet commenced.

NOTE 10—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:



(in millions)	March 31, 2019		December 31, 2018
Materials and supplies	$	230.7	$	226.6
Fossil fuel	60.4		88.7
Natural gas in storage	39.0		232.9
Total	$	330.1	$	548.2

PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. At March 31, 2019, we had a temporary LIFO liquidation credit of $40.2 million recorded within other current liabilities on our balance sheet. Due to seasonality requirements, PGL and NSG expect these interim reductions in LIFO layers to be replenished by year end.

Substantially all other natural gas in storage, materials and supplies, and fossil fuel inventories are recorded using the weighted-average cost method of accounting.



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NOTE 11—INCOME TAXES

The provision for income taxes differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following:



	Three Months Ended March 31, 2019					Three Months Ended March 31, 2018
(in millions)	Amount			Effective Tax Rate		Amount			Effective Tax Rate
Statutory federal income tax	$	101.9		21.0	%	$	100.5		21.0	%
State income taxes net of federal tax benefit	31.0			6.4	%	29.9			6.2	%
Tax repairs	(29.6		)	(6.1	)%	(25.5		)	(5.3	)%
Wind production tax credits	(13.4		)	(2.8	)%	(3.8		)	(0.8	)%
Federal excess deferred tax amortization	(13.2		)	(2.7	)%	(15.5		)	(3.2	)%
Excess tax benefits – stock options	(7.2		)	(1.5	)%	(0.9		)	(0.2	)%
Other	(4.5		)	(0.9	)%	3.6			0.7	%
Total income tax expense	$	65.0		13.4	%	$	88.3		18.4	%

The effective tax rate of 13.4% for the first quarter of 2019, differs from the United States statutory federal income tax rate of 21%, primarily due to the flow through of tax repairs in connection with the Wisconsin rate settlement, wind production tax credits generated from recent acquisitions of wind generation facilities in our non-utility energy infrastructure segment, and the impact of the Tax Legislation, partially offset by state income taxes.

The effective tax rate of 18.4% for the first quarter of 2018, differs from the United States statutory federal income tax rate of 21%, primarily due to the flow through of tax repairs in connection with the Wisconsin rate settlement and the impact of the Tax Legislation, partially offset by state income taxes.

The Tax Legislation, signed into law in December 2017, required our regulated utilities to remeasure their deferred income taxes and we began to amortize the resulting excess deferred income taxes beginning in 2018 in accordance with normalization requirements (see federal excess deferred tax amortization line above). See Note 22, Regulatory Environment, for more information about the Wisconsin rate settlement.

NOTE 12—FAIR VALUE MEASUREMENTS

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).

Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

When possible, we base the valuations of our financial assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on



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quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs.

We recognize transfers between levels of the fair value hierarchy at their value as of the end of the reporting period.

The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:



	March 31, 2019
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	6.0	$	—	$	—	$	6.0
FTRs	—		—		3.1		3.1
Coal contracts	—		1.2		—		1.2
Total derivative assets	$	6.0	$	1.2	$	3.1	$	10.3

Investments held in rabbi trust	$	74.0	$	—	$	—	$	74.0

Derivative liabilities
Natural gas contracts	$	0.9	$	—	$	—	$	0.9
Coal contracts	—		0.1		—		0.1
Interest rate swaps	—		3.7		—		3.7
Total derivative liabilities	$	0.9	$	3.8	$	—	$	4.7



	December 31, 2018
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	6.3	$	1.8	$	—	$	8.1
FTRs	—		—		7.4		7.4
Coal contracts	—		0.4		—		0.4
Total derivative assets	$	6.3	$	2.2	$	7.4	$	15.9

Investments held in rabbi trust	$	65.0	$	—	$	—	$	65.0

Derivative liabilities
Natural gas contracts	$	4.7	$	0.8	$	—	$	5.5
Coal contracts	—		0.1		—		0.1
Interest rate swaps	—		2.3		—		2.3
Total derivative liabilities	$	4.7	$	3.2	$	—	$	7.9

The derivative assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices and interest rates. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy and Operating Reserves Markets.

We hold investments in the Integrys rabbi trust. These investments are restricted as they can only be withdrawn from the trust to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans. These investments are included in other long-term assets on our balance sheets. For the three months ended March 31, 2019 and 2018, the net unrealized gains (losses) included in earnings related to the investments held at the end of the period were $8.6 million and $(3.1) million, respectively.



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The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy:



	Three Months Ended March 31
(in millions)	2019			2018
Balance at the beginning of the period	$	7.4		$	4.4
Settlements	(4.3		)	(2.9		)
Balance at the end of the period	$	3.1		$	1.5

Fair Value of Financial Instruments

The following table shows the financial instruments included on our balance sheets that were not recorded at fair value:



	March 31, 2019				December 31, 2018
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock of subsidiary	$	30.4	$	28.3	$	30.4	$	28.3
Long-term debt, including current portion *	10,670.6		11,257.5		10,335.7		10,554.9


*	The carrying amount of long-term debt excludes finance and capital lease obligations of $22.1 million and $23.3 million at March 31, 2019 and December 31, 2018, respectively.

The fair values of our long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.

NOTE 13—DERIVATIVE INSTRUMENTS

We use derivatives as part of our risk management program to manage the risks associated with the price volatility of interest rates, purchased power, generation, and natural gas costs for the benefit of our customers and shareholders. Our approach is non-speculative and designed to mitigate risk. Regulated hedging programs are approved by our state regulators.

We record derivative instruments on our balance sheets as an asset or liability measured at fair value unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities.

None of our derivatives are designated as hedging instruments, with the exception of our interest rate swaps, which have been designated as cash flow hedges. The following table shows our derivative assets and derivative liabilities:



	March 31, 2019				December 31, 2018
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	5.1	$	0.9	$	7.7	$	5.3
FTRs	3.1		—		7.4		—
Coal contracts	1.0		0.1		0.2		0.1
Interest rate swaps	—		0.7		—		0.4
Total other current *	$	9.2	$	1.7	$	15.3	$	5.8

Other long-term
Natural gas contracts	$	0.9	$	—	$	0.4	$	0.2
Coal contracts	0.2		—		0.2		—
Interest rate swaps	—		3.0		—		1.9
Total other long-term *	$	1.1	$	3.0	$	0.6	$	2.1
Total	$	10.3	$	4.7	$	15.9	$	7.9


*	On our balance sheets, we classify derivative assets and liabilities as other current or other long-term based on the maturities of the underlying contracts.



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Realized gains (losses) on derivatives not designated as hedging instruments are primarily recorded in cost of sales on the income statements. Our estimated notional sales volumes and realized gains (losses) were as follows:



	Three Months Ended March 31, 2019				Three Months Ended March 31, 2018
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	56.1 Dth	$	(0.5	)	48.1 Dth	$	(5.2	)
Petroleum products contracts	— gallons	—			2.1 gallons	0.5
FTRs	8.1 MWh	2.3			8.2 MWh	3.7
Total		$	1.8			$	(1.0	)

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At March 31, 2019 and December 31, 2018, we had posted cash collateral of $3.0 million and $2.7 million, respectively, in our margin accounts. These amounts were recorded on our balance sheets in other current assets. At December 31, 2018, we had also received cash collateral of $0.2 million in our margin accounts. This amount was recorded on our balance sheet in other current liabilities. We had not received any cash collateral at March 31, 2019.

The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets:



	March 31, 2019						December 31, 2018
(in millions)	Derivative Assets			Derivative Liabilities			Derivative Assets				Derivative Liabilities
Gross amount recognized on the balance sheet	$	10.3		$	4.7		$	15.9			$	7.9
Gross amount not offset on the balance sheet	(0.9		)	(0.9		)	(4.0		)	⁽¹⁾	(4.9		)	⁽²⁾
Net amount	$	9.4		$	3.8		$	11.9			$	3.0


⁽¹⁾	Includes cash collateral received of $0.2 million.


⁽²⁾	Includes cash collateral posted of $1.1 million.

Cash Flow Hedges

Effective January 1, 2019, we adopted ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities. The amendments in this update expand the strategies that qualify for hedge accounting, amend the presentation and disclosure requirements related to hedging activities, and provide overall targeted improvements to simplify hedge accounting in certain situations. The adoption of this standard did not have a significant impact on our financial statements.

As of March 31, 2019, we had two interest rate swaps with a combined notional value of $250.0 million to hedge the variable interest rate risk associated with our 2007 Junior Notes. The swaps provide a fixed interest rate of 4.9765% on $250.0 million of the $500.0 million of outstanding 2007 Junior Notes through November 15, 2021. As these swaps qualified for cash flow hedge accounting treatment, the related gains and losses are being deferred in accumulated other comprehensive income (OCI) and are being amortized to interest expense as interest is accrued on the 2007 Junior Notes.

We previously entered into forward interest rate swap agreements to mitigate the interest rate exposure associated with the issuance of long-term debt related to the acquisition of Integrys. These swap agreements were settled in 2015, and we continue to amortize amounts out of accumulated OCI into interest expense over the periods in which the interest costs are recognized in earnings.

The table below shows the amounts related to these cash flow hedges recorded in OCI and in earnings, along with our total interest expense on the income statements:



	Three Months Ended March 31
(in millions)	2019			2018
Derivative losses recognized in OCI	$	(1.6	)	$	—
Net derivative gains reclassified from accumulated OCI to interest expense	0.4			0.6
Total interest expense line item on the income statements	124.4			106.7



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We estimate that during the next twelve months, $1.5 million will be reclassified from accumulated OCI as a reduction to interest expense.

NOTE 14—GUARANTEES

The following table shows our outstanding guarantees:



			Expiration
(in millions)	Total Amounts Committed at March 31, 2019		Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees
Guarantees supporting commodity transactions of subsidiaries ⁽¹⁾	$	7.1	$	7.1	$	—	$	—
Standby letters of credit ⁽²⁾	102.8		5.7		1.1		96.0
Surety bonds⁽³⁾	9.2		8.9		0.3		—
Other guarantees⁽⁴⁾	11.0		—		0.9		10.1
Total guarantees	$	130.1	$	21.7	$	2.3	$	106.1


⁽¹⁾	Includes $5.6 million and $1.5 million to support the business operations of Bluewater and UMERC, 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 $11.0 million related to other indemnifications, for which a liability of $10.1 million related to workers compensation coverage was recorded on our balance sheets.

NOTE 15—EMPLOYEE BENEFITS

The following tables show the components of net periodic pension and OPEB costs for our benefit plans.



	Pension Costs
	Three Months Ended March 31
(in millions)	2019			2018
Service cost	$	11.3		$	12.0
Interest cost	30.6			28.3
Expected return on plan assets	(48.7		)	(49.6		)
Loss on plan settlement	0.8			0.4
Amortization of prior service cost	0.6			0.7
Amortization of net actuarial loss	19.0			23.1
Net periodic benefit cost	$	13.6		$	14.9



	OPEB Costs
	Three Months Ended March 31
(in millions)	2019			2018
Service cost	$	4.4		$	6.2
Interest cost	6.5			7.5
Expected return on plan assets	(13.7		)	(14.9		)
Amortization of prior service credit	(3.9		)	(3.8		)
Amortization of net actuarial (gain) loss	(0.7		)	0.3
Net periodic benefit credit	$	(7.4	)	$	(4.7	)

During the three months ended March 31, 2019, we made contributions and payments of $3.6 million related to our pension plans and $0.6 million related to our OPEB plans. We expect to make contributions and payments of $8.4 million related to our pension



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plans and $6.1 million related to our OPEB plans during the remainder of 2019, dependent upon various factors affecting us, including our liquidity position and the effects of the new Tax Legislation.

NOTE 16—GOODWILL

Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. The table below shows our goodwill balances by segment for the three months ended March 31, 2019. We had no changes to the carrying amount of goodwill during the three months ended March 31, 2019.



(in millions)	Wisconsin		Illinois		Other States		Non-Utility Energy Infrastructure		Total
Goodwill balance *	$	2,104.3	$	758.7	$	183.2	$	6.6	$	3,052.8


*	We had no accumulated impairment losses related to our goodwill as of March 31, 2019.

NOTE 17—INVESTMENT IN TRANSMISSION AFFILIATES

We own approximately 60% of 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. We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. The following tables provide a reconciliation of the changes in our investments in ATC and ATC Holdco:



	Three Months Ended March 31, 2019
(in millions)	ATC		ATC Holdco			Total
Balance at beginning of period	$	1,625.3	$	40.0		$	1,665.3
Add: Earnings (loss) from equity method investment	36.5		(0.4		)	36.1
Add: Capital contributions	3.0		0.4			3.4
Less: Distributions	34.2		—			34.2
Balance at end of period	$	1,630.6	$	40.0		$	1,670.6



	Three Months Ended March 31, 2018
(in millions)	ATC		ATC Holdco			Total
Balance at beginning of period *	$	1,515.8	$	37.6		$	1,553.4
Add: Earnings (loss) from equity method investment	33.4		(0.6		)	32.8
Add: Capital contributions	12.0		0.8			12.8
Less: Other	0.1		—			0.1
Balance at end of period	$	1,561.1	$	37.8		$	1,598.9


*	Distributions of $39.9 million, received in the first quarter of 2018, were approved and recorded as a receivable from ATC in other current assets at December 31, 2017.

We pay ATC for network transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed by ATC. We are required to pay the cost of needed transmission infrastructure upgrades for new generation projects while the projects are under construction. ATC reimburses us for these costs when the new generation is placed in service.

In connection with UMERC's construction of the new natural gas-fired generation in the Upper Peninsula of Michigan, UMERC was required to pay ATC for the costs of the transmission infrastructure upgrades needed for the new generation. ATC owns these transmission assets and will reimburse UMERC for these costs in 2019, as the new generation has now been placed in service. At March 31, 2019 and December 31, 2018, the amounts to be reimbursed to UMERC related to the transmission infrastructure upgrades were $32.4 million and $29.4 million, respectively.



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The following table summarizes our significant related party transactions with ATC:



	Three Months Ended March 31
(in millions)	2019		2018
Charges to ATC for services and construction	$	4.0	$	4.6
Charges from ATC for network transmission services	87.1		84.5

Our balance sheets included the following receivables and payables for services received from or provided to ATC:



(in millions)	March 31, 2019		December 31, 2018
Accounts receivable for services provided to ATC	$	2.0	$	3.4
Accounts payable for services received from ATC	29.0		28.2

Summarized financial data for ATC is included in the following tables:



	Three Months Ended March 31
(in millions)	2019		2018
Income statement data
Operating revenues	$	177.7	$	165.4
Operating expenses	90.4		84.9
Other expense, net	28.8		27.6
Net income	$	58.5	$	52.9



(in millions)	March 31, 2019		December 31, 2018
Balance sheet data
Current assets	$	87.8	$	87.2
Noncurrent assets	5,012.7		4,928.8
Total assets	$	5,100.5	$	5,016.0

Current liabilities	$	571.1	$	640.0
Long-term debt	2,164.1		2,014.0
Other noncurrent liabilities	288.6		295.3
Shareholders' equity	2,076.7		2,066.7
Total liabilities and shareholders' equity	$	5,100.5	$	5,016.0

NOTE 18—SEGMENT INFORMATION

We use operating income to measure segment profitability and to allocate resources to our businesses. At March 31, 2019, we reported six segments, which are described below.


•	The Wisconsin segment includes the electric and natural gas utility operations of WE, WG, WPS, 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 invests 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, our 90% membership interest in Bishop Hill III, a wind generating facility located in Henry County, Illinois, our 80% membership interest in Coyote Ridge, a wind generating facility under construction in Brookings



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County, South Dakota, and our 80% membership interest in Upstream, a wind generating facility located in Antelope County, Nebraska. See Note 2, Acquisitions, for more information on Bishop Hill III, Coyote Ridge, and Upstream.


•	The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the Peoples Energy, LLC holding company, Wispark LLC, Wisvest LLC, Wisconsin Energy Capital Corporation, WEC Business Services LLC, and WPS Power Development, LLC.

All of our operations are located within the United States. The following tables show summarized financial information related to our reportable segments for the three months ended March 31, 2019 and 2018:



	Utility Operations
(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Electric Transmission		Non-Utility Energy Infrastructure		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Three Months Ended
March 31, 2019
External revenues	$	1,633.4	$	536.5	$	185.2	$	2,355.1	$	—	$	20.6	$	1.7		$	—		$	2,377.4
Intersegment revenues	—		—		—		—		—		107.2		—			(107.2		)	—
Other operation and maintenance	392.7		128.2		27.6		548.5		—		3.8		(1.0		)	(0.7		)	550.6
Depreciation and amortization	151.0		44.5		6.5		202.0		—		22.6		6.4			(4.6		)	226.4
Operating income (loss)	361.8		137.9		41.5		541.2		—		92.7		(3.9		)	(87.2		)	542.8
Equity in earnings of transmission affiliates	—		—		—		—		36.1		—		—			—			36.1
Interest expense	143.4		14.8		2.3		160.5		2.6		15.7		35.1			(89.5		)	124.4



	Utility Operations
(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Electric Transmission		Non-Utility Energy Infrastructure		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Three Months Ended
March 31, 2018
External revenues	$	1,589.1	$	507.3	$	169.9	$	2,266.3	$	—	$	18.8	$	1.4		$	—		$	2,286.5
Intersegment revenues	—		—		—		—		—		99.3		—			(99.3		)	—
Other operation and maintenance	468.5		112.2		26.6		607.3		—		1.7		(0.3		)	(96.8		)	511.9
Depreciation and amortization	135.1		40.9		6.6		182.6		—		18.3		7.7			—			208.6
Operating income (loss)	273.7		147.6		36.2		457.5		—		93.0		(5.4		)	—			545.1
Equity in earnings of transmission affiliates	—		—		—		—		32.8		—		—			—			32.8
Interest expense	49.4		12.3		2.1		63.8		—		16.1		28.0			(1.2		)	106.7

NOTE 19—VARIABLE INTEREST ENTITIES

The primary beneficiary of a variable interest entity must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in variable interest entities.

We assess our relationships with potential variable interest entities, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to power purchase agreements, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance.



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Investment in Transmission Affiliates

We own approximately 60% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. We have determined that ATC is a variable interest entity but consolidation is not required since we are not ATC's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC's economic performance. Therefore, we account for ATC as an equity method investment. The significant assets and liabilities related to ATC recorded on our balance sheets were our equity investment, amounts reimbursable for transmission infrastructure upgrades, and accounts payable. At March 31, 2019 and December 31, 2018, our equity investment was $1,630.6 million and $1,625.3 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC. In addition, the amounts to be reimbursed to UMERC by ATC for transmission infrastructure upgrades were $32.4 million and $29.4 million at March 31, 2019 and December 31, 2018, respectively. We also had $29.0 million and $28.2 million of accounts payable due to ATC at March 31, 2019 and December 31, 2018, respectively, for network transmission services.

We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. We have determined that ATC Holdco is a variable interest entity but consolidation is not required since we are not ATC Holdco's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC Holdco's economic performance. Therefore, we account for ATC Holdco as an equity method investment. The only significant asset or liability related to ATC Holdco recorded on our balance sheets at March 31, 2019 and December 31, 2018 was our equity investment of $40.0 million. Our equity investment approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.

See Note 17, Investment in Transmission Affiliates, for more information.

Power Purchase Agreement

We have a power purchase agreement that represents a variable interest. This agreement is for 236 MWs of firm capacity from a natural gas-fired cogeneration facility, and we account for it as a finance lease. The agreement includes no minimum energy requirements over the remaining term of approximately three years. We have examined the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity, and there is no residual guarantee associated with the power purchase agreement.

We have $28.6 million of required capacity payments over the remaining term of this agreement. We believe that the required capacity payments under this contract will continue to be recoverable in rates, and our maximum exposure to loss is limited to these capacity payments.

NOTE 20—COMMITMENTS AND CONTINGENCIES

We and our subsidiaries have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, environmental matters, and enforcement and litigation matters.

Unconditional Purchase Obligations

Our electric utilities have obligations to distribute and sell electricity to their customers, and our natural gas utilities have obligations to distribute and sell natural gas to their customers. The utilities expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time.

Our non-utility energy infrastructure generation facilities have obligations to distribute and sell electricity through long-term offtake agreements with their customers for all of the energy produced. These projects also enter into related easements and other agreements associated with the generating facilities.

Our minimum future commitments related to these purchase obligations as of March 31, 2019, including those of our subsidiaries, were $11,893.7 million.



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Environmental Matters

Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as sulfur dioxide, nitrogen oxide, fine particulates, mercury, and GHGs; water intake and discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.

Air Quality

National Ambient Air Quality Standards

After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, which lowered the limit for ground-level ozone, creating a more stringent standard than the 2008 National Ambient Air Quality Standards. The EPA issued final nonattainment area designations on May 1, 2018. The following counties within our service territories were designated as partial nonattainment: Door, Kenosha, Manitowoc, Northern Milwaukee/Ozaukee, and Sheboygan shorelines. The state of Wisconsin will need to develop a state implementation plan to bring these areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020. We believe we are well positioned to meet the requirements associated with the ozone standard and do not expect to incur significant costs to comply.

Mercury and Air Toxics Standards

In December 2018, the EPA proposed to revise the Supplemental Cost Finding for the mercury and air toxics standards (MATS) rule as well as the CAA required risk and technology review (RTR). The EPA was required by the United States Supreme Court to review both costs and benefits of complying with the MATS rule. After its review of costs, the EPA determined that it is not appropriate and necessary to regulate hazardous air pollutant emissions from power plants under Section 112 of the CAA. As a result, under the proposed rule, the emission standards and other requirements of the MATS rule first enacted in 2012 would remain in place. The EPA is not proposing to remove coal-and oil-fired power plants from the list of sources that are regulated under Section 112. The EPA also proposes that no revisions to MATS are warranted based on the results of the RTR. As a result, we do not expect the proposed rule to have a material impact on our financial condition or operations.

Climate Change

In August 2018, the EPA issued a proposed replacement rule for the Clean Power Plan, the Affordable Clean Energy (ACE) rule. The proposed ACE rule would require the EPA to develop emission guidelines for states to use to develop their individual state plans. The state plans would focus on reducing GHG emissions by improving the efficiency of fossil-fueled power plants.

In December 2018, the EPA proposed to revise the New Source Performance Standards for GHG emissions from new, modified, and reconstructed fossil-fueled power plants. The EPA determined that the best system of emission reduction (BSER) for new, modified, and reconstructed coal units is highly efficient generation that would be equivalent to supercritical steam conditions for larger units and subcritical steam conditions for smaller units. This proposed BSER would replace the determination from the previous rule, which identified BSER as partial carbon capture and storage.

In April 2019, we issued a climate report, which analyzes our GHG reduction goals with respect to international efforts to limit future global temperature increases to less than two degrees Celsius. We will continue to update this analysis as climate-change policies and relevant technologies evolve over time with a focus on preserving fuel diversity, lowering costs for customers, and reducing long-term GHG emissions.

Our plan is to work with our industry peers, environmental groups, public policy makers, and customers, with goals of reducing CO₂ emissions by approximately 40% and 80% below 2005 levels by 2030 and 2050, respectively. As a result of our generation reshaping plan, we have retired approximately 1,800 MW of coal generation since the beginning of 2018, consisting of the PIPP, which we retired on March 31, 2019. This plan also consisted of the 2018 retirement of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater Unit 4 generating units. See Note 5, Property, Plant, and Equipment, for more information on the retirement of the PIPP.



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We are required to report our CO₂ equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2018, we reported aggregated CO₂ equivalent emissions of 26.4 million metric tonnes to the EPA.

We are also required to report CO₂ equivalent emissions related to the natural gas that our natural gas utilities distribute and sell. For 2018, we reported aggregated CO₂ equivalent emissions of 29.4 million metric tonnes to the EPA.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act that requires the location, design, construction, and capacity of cooling water intake structures at existing power plants to reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts. The rule became effective in October 2014 and applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted under the rules governing new facilities.

The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our operating facilities, except for Weston Unit 2, satisfy the BTA requirements. Based on the March 2018 reissued WPDES permit for Weston, the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the BTA requirements based on low capacity use of the unit.

We have received a BTA determination by the WDNR, with EPA concurrence, for our intake modification at the Valley Power Plant. The WDNR made an interim BTA determination as part of the March 2018 reissued WPDES permit for Weston Units 3 and 4. We expect that the WDNR will conclude in the next permit reissuance that the existing cooling tower systems for Weston Units 3 and 4 are BTA. Although we currently believe that existing technologies at Port Washington Generating Station and OC 5 through OC 8 satisfy the BTA requirements, final determinations will not be made until discharge permits are renewed for these units. Until that time, we cannot determine what, if any, intake structure or operational modifications will be required to meet the new BTA requirements for these units.

We also have provided information to the WDNR and the MDEQ about planned unit retirements. Following discussions with the MDEQ, in January 2019, we submitted a signed certification stating that the PIPP would be retired no later than June 1, 2019. The PIPP was retired on March 31, 2019.

As a result of past capital investments completed to address 316(b) compliance at WE and WPS, we believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation.

Steam Electric Effluent Limitation Guidelines

The EPA's final steam electric effluent limitation guidelines (ELG) rule took effect in January 2016. This rule created new requirements for several types of power plant wastewaters. The two new requirements that affect WE and WPS relate to discharge limits for bottom ash transport water (BATW) and wet flue gas desulfurization (FGD) wastewater.

This rule is being litigated and various petitions challenging it were consolidated in the United States Court of Appeals for the Fifth Circuit (Fifth Circuit). In April 2017, the EPA issued an administrative stay of certain compliance deadlines while further reviewing the rule. In September 2017, the EPA issued a final rule (Postponement Rule) to postpone the earliest compliance date to November 1, 2020 for the BATW and wet FGD wastewater requirements. The latest ELG rule compliance date remains December 31, 2023 for any new wastewater treatment requirements contained in power plant discharge permits.

As a result of past capital investments completed to address ELG compliance at WE and WPS, we believe our fleet overall is well positioned to meet the regulations. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, as currently constructed, the ELG rule will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use. Due to completed generating unit retirements, we believe the only facilities that will require bottom ash system modifications are Weston Unit 3 and Oak Creek Units 7 and 8. One wastewater treatment system modification may be required for the wet FGD discharges from the six units that make up the OCPP and ERGS. Based on preliminary engineering, the estimated rule compliance cost is approximately $70 million.



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The Fifth Circuit issued a ruling in April 2019, striking down several portions of the ELG rule. The Fifth Circuit held that the legacy wastewater and combustion residual leachate provisions in the rule failed to meet the requirements of the Clean Water Act and the Administrative Procedure Act.

Land Quality

Manufactured Gas Plant Remediation

We have identified sites at which our utilities or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Our natural gas utilities are responsible for the environmental remediation of these sites, some of which are in the EPA Superfund Alternative Approach Program. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure.

In addition, we are coordinating the investigation and cleanup of some of these sites subject to the jurisdiction of the EPA under what is called a "multisite" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.

The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites.

We have established the following regulatory assets and reserves related to manufactured gas plant sites:



(in millions)	March 31, 2019		December 31, 2018
Regulatory assets	$	697.6	$	687.1
Reserves for future remediation	631.8		616.4

Consent Decrees

Wisconsin Public Service Corporation Consent Decree – Weston and Pulliam Power Plants

In November 2009, the EPA issued an NOV to WPS, which alleged violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam power plants from 1994 to 2009. WPS entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Eastern District of Wisconsin in March 2013. WPS retired Pulliam Units 7 and 8 on October 21, 2018. WPS completed the mitigation projects required and received a completeness letter from the EPA in October 2018. We plan to start the process to terminate the WPS Consent Decree in 2019.

Joint Ownership Power Plants Consent Decree – Columbia and Edgewater

In December 2009, the EPA issued an NOV to Wisconsin Power and Light, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric, WE (former co-owner of an Edgewater unit), and WPS. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. WPS, along with Wisconsin Power and Light, Madison Gas and Electric, and WE, entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013. As a result of the continued implementation of the Consent Decree related to the jointly owned Columbia and Edgewater plants, the Edgewater 4 generating unit was retired on September 28, 2018.



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Enforcement and Litigation Matters

We and our subsidiaries are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material effect on our financial condition or results of operations.

NOTE 21—SUPPLEMENTAL CASH FLOW INFORMATION



	Three Months Ended March 31
(in millions)	2019			2018
Cash (paid) for interest, net of amount capitalized	$	(66.3	)	$	(68.5	)
Cash (paid) received for income taxes, net	(0.2		)	0.3
Significant non-cash transactions:
Accounts payable related to construction costs	74.7			74.9

The statements of cash flows include our activity related to cash, cash equivalents, and restricted cash. Our restricted cash primarily consists of the cash held in the Integrys rabbi trust, which is used to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans. All assets held within the rabbi trust are restricted as they can only be withdrawn from the trust to make qualifying benefit payments. Our restricted cash also includes the restricted cash we received when we acquired Bishop Hill III and Upstream during August 2018 and January 2019, respectively. This cash is restricted as it can only be used to pay for any remaining costs associated with the construction of these wind generation facilities. See Note 2, Acquisitions, for more information on the acquisitions of Bishop Hill III and Upstream.

The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets at March 31 to the total of these amounts shown on the statements of cash flows:



(in millions)	2019		2018
Cash and cash equivalents	$	30.6	$	48.1
Restricted cash included in other current assets	2.4		—
Restricted cash included in other long term assets	56.1		23.6
Cash, cash equivalents, and restricted cash	$	89.1	$	71.7

NOTE 22—REGULATORY ENVIRONMENT

Wisconsin Electric Power Company, Wisconsin Gas LLC, and Wisconsin Public Service Corporation

2020 and 2021 Rates

In March 2019, WE, WG, and WPS filed applications with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable, effective January 1, 2020. The WE and WPS proposals are targeting effective electric rate increases of approximately $83 million (2.9%) and $49 million (4.9%), respectively, in 2020, and additional increases of $83 million (2.9%) and $49 million (4.9%), respectively, in 2021. For WE’s, WG’s, and WPS’s natural gas customers, the proposals are targeting effective rate increases of approximately $15 million (3.9%), $11 million (1.8%), and $7 million (2.4%), respectively, in 2020. WPS is proposing an additional effective natural gas rate increase of $7 million (2.4%) in 2021. The WE proposal also targets a $1 million (4.5%) effective increase in its steam rates. The proposals for WE, WG, and WPS reflect a ROE of 10.35%, 10.30%, and 10.35%, respectively. All three of these Wisconsin utilities proposed a common equity component average of 52.0% on a financial basis and proposed to continue having an earnings sharing mechanism through 2021.

The proposed increase in electric rates at WE was driven by higher transmission charges, recovery of SSR revenues that were assumed in WE's 2015 rate order but were not received, and an increase in costs associated with a purchased power agreement previously approved by the PSCW. WE's proposed electric rates reflect its request to partially offset these increases with approximately $111 million of previously deferred tax benefits from the Tax Legislation. WE's proposal also includes its request for approval to continue collecting the carrying value of the Pleasant Prairie power plant and the PIPP using the current approved composite depreciation rates, in addition to a return on the remaining carrying value of the plants.



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The proposed increase in electric rates at WPS was driven by the inclusion of WPS's SMRP, the Forward Wind Energy Center, and WPS's investments in two solar projects in rates, along with continued investments in system reliability and the recovery of various regulatory deferrals, including the deferral of the revenue requirement for ReACT™ costs above a previously authorized level. WPS's proposed electric rates reflect its request to use $40 million of previously deferred tax benefits from the Tax Legislation to partially offset these increases. WPS's proposal also includes its request for approval to continue collecting the carrying value of Pulliam units 7 and 8 and the Edgewater 4 generating unit using the current approved composite depreciation rates, in addition to a return on the remaining carrying value of the units.

The proposed increases at our Wisconsin natural gas utilities were driven by continued investment in our natural gas distribution systems. WPS’s proposed 2020 natural gas rate increase is net of approximately $7 million of previously deferred tax benefits from the Tax Legislation.

Final orders are expected from the PSCW by the end of 2019, with rates effective January 1, 2020.

2018 and 2019 Rates

During April 2017, WE, WG, and WPS filed an application with the PSCW for approval of a settlement agreement they made with several of their commercial and industrial customers regarding 2018 and 2019 base rates. In September 2017, the PSCW issued an order that approved the settlement agreement, which freezes base rates through 2019 for electric, natural gas, and steam customers of WE, WG, and WPS. Based on the PSCW order, the authorized ROE for WE, WG, and WPS remains at 10.2%, 10.3%, and 10.0%, respectively, and the current capital cost structure for all of our Wisconsin utilities will remain unchanged through 2019.

In addition to freezing base rates, the settlement agreement extends and expands the electric real-time market pricing program options for large commercial and industrial customers and mitigates the continued growth of certain escrowed costs at WE during the base rate freeze period by accelerating the recognition of certain tax benefits. WE will flow 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. While WE would typically follow the normalization accounting method and utilize the tax benefits of the deferred tax liabilities in rate-making as an offset to rate base, benefiting customers over time, the federal tax code does allow for passing these tax repair-related benefits to ratepayers much sooner using the flow through accounting method. 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.

The agreement also allows WPS to extend through 2019, the deferral for the revenue requirement of ReACT™ costs above the authorized $275.0 million level, and other deferrals related to WPS's electric real-time market pricing program and network transmission expenses. The total cost of the ReACT™ project, excluding $51 million of AFUDC, was $342 million.

Pursuant to the settlement agreement, WPS also agreed to adopt, beginning in 2018, the earnings sharing mechanism that has been in place for WE and WG since January 2016, and all three utilities agreed to keep the mechanism in place through 2019. Under this earnings sharing mechanism, if WE, WG, or WPS earns above its authorized ROE, 50% of the first 50 basis points of additional utility earnings must be shared with customers. All utility earnings above the first 50 basis points must also be shared with customers.

Wisconsin Public Service Corporation Solar Generation Projects

On May 31, 2018, WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire ownership interests in two solar projects in Wisconsin. Badger Hollow Solar Farm will be located in Iowa County, Wisconsin, and Two Creeks Solar Project will be located in Manitowoc County, Wisconsin. 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 $260 million. The PSCW approved the acquisition of these two projects in April 2019.

The Peoples Gas Light and Coke Company and North Shore Gas Company

Illinois Proceedings

In December 2015, the ICC ordered a series of stakeholder workshops to evaluate PGL's SMP. This ICC action did not impact PGL's ongoing work to modernize and maintain the safety of its natural gas distribution system, but it instead provided the ICC with an opportunity to analyze long-term elements of the program through the stakeholder workshops. The workshops were completed in March 2016. In July 2016, the ICC initiated a proceeding to review, among other things, the planning, reporting, and monitoring of



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the program, including the target end date for the program, and issued a final order in January 2018. The order did not have a significant impact on PGL's existing SMP design and execution. An appeal related to the final order was filed by the Illinois Attorney General in April 2018.

Qualifying Infrastructure Plant Rider

In July 2013, Illinois Public Act 98-0057, The Natural Gas Consumer, Safety & Reliability Act, became law. This law provides PGL with a cost recovery mechanism that allows collection, through a surcharge on customer bills, of prudently incurred costs to upgrade Illinois natural gas infrastructure. In September 2013, PGL filed with the ICC requesting the proposed rider, which was approved in January 2014.

PGL's QIP 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, 2016, and 2015 reconciliations, are still pending.

As of March 31, 2019, there can be no assurance that all costs incurred under PGL's QIP rider during the open reconciliation years will be deemed recoverable by the ICC.

Minnesota Energy Resources Corporation

2018 Minnesota Rate Case

In October 2017, MERC initiated a rate proceeding with the MPUC. In November 2017, the MPUC approved an interim rate order, effective January 1, 2018, authorizing a retail natural gas rate increase of $9.5 million (3.78%). In March 2018, to reflect changes in MERC's effective tax rate as a result of the enactment of the Tax Legislation, the MPUC approved a $2.5 million reduction in interim retail natural gas rates to $7.0 million (2.81%), effective April 1, 2018. The interim rates reflect a 9.11% ROE and a common equity component average of 50.9%.

In December 2018, the MPUC issued a final written order for MERC. The order authorized a retail natural gas rate increase of $3.1 million (1.26%). The rates reflect a 9.7% ROE and a common equity component average of 50.9%. In January 2019, the Minnesota Attorney General filed a petition for reconsideration requesting the MPUC reconsider its decision to set the ROE at 9.7%. In February 2019, this petition was denied by the MPUC. Interim rates remain in effect until final rates are implemented, which is expected to be in the second quarter of 2019. MERC’s customers will be entitled to a refund to the extent the interim rate increase exceeds the final approved rate increase. Therefore, as of March 31, 2019, we recorded a $6.7 million regulatory liability for amounts to be refunded to customers.

The final order addressed the various impacts of the Tax Legislation, including the remeasurement of deferred tax balances. All of the impacts from the Tax Legislation will be included in base rates. The order also approved MERC's continued use of its decoupling mechanism for residential customers. Effective January 1, 2019, MERC's small commercial and industrial customers will no longer be included in the decoupling mechanism.

Gas Utility Infrastructure Cost Rider

In April 2018, MERC filed an application with the MPUC to establish a rider to begin recovering approximately $12 million of capital investments and $3 million of operating and maintenance expenses related to gas utility infrastructure costs (GUIC). Minnesota law allows recovery of GUIC incurred to replace or modify natural gas facilities (including costs incurred for surveys, assessments, and other work necessary to determine the need for replacement or modification) to the extent the work is required by state, federal, or other government agencies and exceeds the costs included in base rates. In February 2019, the MPUC issued a final written order approving MERC's use of the GUIC rider to start recovering in 2019 the costs noted above. As MERC requested, the rider will be subject to an annual true-up. The GUIC rider went into effect on May 1, 2019.



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Upper Michigan Energy Resources Corporation and Michigan Gas Utilities Corporation

Tax Cuts and Jobs Act of 2017

In February 2018, the MPSC issued an order requiring Michigan utilities to make three filings related to the Tax Legislation. The first of those filings, which was filed in March 2018, prospectively addressed the impact on base rates for the change in tax expense resulting from the federal tax rate reduction from 35% to 21%. UMERC and MGU proposed providing a volumetric bill credit, subject to reconciliation and true up. In May 2018, the MPSC issued orders approving settlements that resulted in volumetric bill credits for all of UMERC's and MGU's customers effective July 1, 2018.

The second filing, which was filed in July 2018, addressed the impact on base rates for the change in tax expense resulting from the federal tax rate reduction from 35% to 21% from January 1, 2018 until July 1, 2018. UMERC and MGU proposed to return the tax savings from these months to customers via volumetric bill credits over multiple months. The MPSC issued orders approving settlements in September 2018. In accordance with the settlement orders, the savings were returned to UMERC's and MGU's customers via volumetric bill credits that were in effect from October 1, 2018 through December 31, 2018.

The third filing was filed in October 2018 and addressed the remaining impacts of the Tax Legislation on base rates – most notably the re-measurement of deferred tax balances. UMERC and MGU proposed providing a volumetric bill credit, subject to reconciliation and true up, to return these remaining impacts of the Tax Legislation to customers. The MPSC has not yet issued an order with respect to this filing.

NOTE 23—NEW ACCOUNTING PRONOUNCEMENTS

Financial Instruments Credit Losses

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. This ASU introduces a new impairment model known as the current expected credit loss model. The ASU requires a financial asset measured at amortized cost to be presented at the net amount expected to be collected. Previously, recognition of the full amount of credit losses was generally delayed until the loss was probable of occurring. We are currently assessing the effects this guidance may have on our financial statements.

Cloud Computing

In August 2018, the FASB issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. The standard allows entities who are customers in hosting arrangements that are service contracts to apply the existing internal-use software guidance to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The guidance specifies classification for capitalizing implementation costs and related amortization expense within the financial statements and requires additional disclosures. The guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019. Early adoption is permitted and can be applied either retrospectively or prospectively. We are currently evaluating the transition methods and the impact the adoption of this standard may have on our financial statements.



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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CORPORATE DEVELOPMENTS

The following discussion should be read in conjunction with the accompanying financial statements and related notes and our 2018 Annual Report on Form 10-K.

Introduction

We are a diversified holding company with natural gas and electric utility operations (serving customers in Wisconsin, Illinois, Michigan, and Minnesota), an approximately 60% equity ownership interest in American Transmission Company LLC (ATC) (a for-profit electric transmission company regulated by the 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), a 90% ownership interest in Bishop Hill III (a wind generating facility in Illinois), and an 80% ownership interest in Upstream (a wind generating facility in Nebraska).

In December 2018, WEC Energy Group acquired an 80% ownership interest in Coyote Ridge, a 97.5 MW wind farm under construction in Brookings County, South Dakota. This wind farm is expected to be in service by the end of 2019, and is included in the non-utility energy infrastructure segment. 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 will balance 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 with a goal of reducing CO₂ emissions by approximately 40% below 2005 levels by 2030 and by approximately 80% below 2005 levels by 2050. We retired approximately 1,800 MW of coal generation since the beginning of 2018, and expect to add additional natural gas-fired generating units and renewable generation, including utility-scale solar projects. Our 1,190 MW Pleasant Prairie power plant was retired in April 2018. The physical dismantlement of the Pleasant Prairie power plant will not occur immediately. It may take several years to finalize long-term plans for the site. The Edgewater 4 generating unit was retired in September 2018, the Pulliam power plant was retired in October 2018, and the Presque Isle power plant (PIPP) was retired in March 2019. See Note 5, Property, Plant, and Equipment, for information related to the PIPP retirement.

As part of our commitment to invest in zero-carbon generation, we plan to invest in utility scale solar up to 350 MW within our Wisconsin segment. Wisconsin Public Service Corporation (WPS) has partnered with an unaffiliated utility to acquire ownership interests in two proposed solar projects in Wisconsin. Badger Hollow Solar Farm will be located in Iowa County, Wisconsin, and Two Creeks Solar Project will be located in Manitowoc County, Wisconsin. 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. Commercial operation for both projects is targeted for the end of 2020.

In December 2018, Wisconsin Electric Power Company (WE) received approval from the PSCW for two renewable energy pilot programs. The Solar Now pilot is expected to add 35 MW of solar to WE's portfolio, allowing commercial and industrial customers to site utility owned solar arrays on their property. 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.

As the cost of renewable energy generation continues to decline, both the WPS solar projects and the WE pilots have become cost effective opportunities for WEC Energy Group and our customers to participate in renewable energy.



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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 being recognized in 2018 by PA Consulting Group, an independent consulting firm, as the most reliable utility in the Midwest for the eighth year in a row.

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

•

Upper Michigan Energy Resources Corporation (UMERC), our Michigan electric and natural gas utility, has completed its long-term generation solution for electric reliability in the Upper Peninsula of Michigan. The plan called for UMERC to construct and operate approximately 180 MW of natural gas-fueled generation located in the Upper Peninsula. The new generation achieved commercial operation on March 31, 2019, and is providing the region with affordable, reliable electricity that generates less emissions than the PIPP. Consistent with a written approval letter received from the Midcontinent Independent System Operator, the PIPP was retired on March 31, 2019.


•	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. WPS, WE, and Wisconsin Gas LLC 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 and improving business processes and consolidating our IT infrastructure across all of our companies. We expect these efforts to continue to drive operational efficiency and to put us in position to effectively support plans for future growth.

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.

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 almost $12.7 billion from 2019 to 2023. Specific projects are discussed in more detail below under Liquidity and Capital Resources.

From 2019 to 2023, we expect capital contributions to ATC and ATC Holdco to be approximately $250 million. ATC Holdco is a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. Capital investments at ATC and ATC Holdco will be funded utilizing these capital contributions, in addition to cash generated from operations and debt. We currently forecast that our share of ATC's and ATC Holdco's projected capital expenditures over the next five years will be $1.2 billion inside the traditional ATC footprint and $250 million outside of the traditional ATC footprint.



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Exceptional Customer Care

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

One example of how we obtain feedback from our customers is through our "We Care" calls, through which employees of our utility subsidiaries contact customers after a completed service call. Customer satisfaction is a priority, and making "We Care" calls is one of the main methods we use to gauge our performance to improve customer satisfaction.

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

THREE MONTHS ENDED MARCH 31, 2019

Consolidated Earnings

The following table compares our consolidated results for the first quarter of 2019 with the first quarter of 2018, including favorable or better, "B", and unfavorable or worse, "W", variances:



	Three Months Ended March 31
(in millions, except per share data)	2019			2018			B (W)			Change Related to Flow Through of Tax Repairs			Change Related to Adoption of New Lease Guidance (Topic 842)			Remaining Change B (W)
Wisconsin	$	361.8		$	273.7		$	88.1		$	(5.6	)	$	88.1		$	5.6
Illinois	137.9			147.6			(9.7		)	—			—			(9.7		)
Other states	41.5			36.2			5.3			—			—			5.3
Non-utility energy infrastructure	92.7			93.0			(0.3		)	—			—			(0.3		)
Corporate and other	(3.9		)	(5.4		)	1.5			—			—			1.5
Reconciling eliminations *	(87.2		)	—			(87.2		)	—			(87.2		)	—
Total operating income	542.8			545.1			(2.3		)	(5.6		)	0.9			2.4
Equity in earnings of transmission affiliates	36.1			32.8			3.3			—			—			3.3
Other income, net	30.9			7.5			23.4			—			—			23.4
Interest expense	124.4			106.7			(17.7		)	—			(0.9		)	(16.8		)
Income before income taxes	485.4			478.7			6.7			(5.6		)	—			12.3
Income tax expense	65.0			88.3			23.3			5.6			—			17.7
Preferred stock dividends of subsidiary	0.3			0.3			—			—			—			—
Net income attributed to common shareholders	$	420.1		$	390.1		$	30.0		$	—		$	—		$	30.0

Diluted earnings per share	$	1.33		$	1.23		$	0.10

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, for the first quarter of 2019, $87.2 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 lease does not impact our financial statements as all amounts associated with the lease are eliminated at the consolidated level.



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Earnings increased $30.0 million during the first quarter of 2019, compared with the same quarter in 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 ASU 2016-02, Leases (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. See Note 22, Regulatory Environment, for more information on the flow through of tax repairs and Note 9, Leases, for more information on the adoption of Topic 842.

The significant factors impacting the $30.0 million increase in earnings were:

•

A $23.4 million increase in other income, net, primarily driven by net gains on the investments held in the Integrys rabbi trust during the first quarter of 2019, compared with net losses during the same period in 2018. The increase related to the investments held in the rabbi trust was offset by higher benefits costs related to deferred compensation included in operating income. See Note 12, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.


•	A $17.7 million remaining decrease in income tax expense, primarily due to an increase in wind production tax credits generated in the first quarter of 2019, as well as the recognition of more excess tax benefits related to stock options in the first quarter of 2019.

•

A $5.6 million remaining increase in operating income at the Wisconsin segment, driven by an increase in electric and natural gas margins related to higher retail sales volumes. The higher sales volumes were primarily driven by favorable weather. This increase in margins was partially offset by the quarter-over-quarter negative impact from collections of fuel and purchased power costs compared with costs approved in rates and higher depreciation expense during the first quarter of 2019 driven by increased capital expenditures.


•	A $5.3 million increase in operating income at the other states segment, driven by higher natural gas margins as a result of colder winter weather and customer growth, as well as a favorable impact related to the retail natural gas rate increase at MERC. See Note 22, Regulatory Environment, for more information on the rate increase.

These increases in earnings were partially offset by:


•	A $16.8 million remaining increase in interest expense, driven by higher debt balances, primarily used to fund capital investments, and higher interest rates on short-term debt.


•	A $9.7 million decrease in operating income at the Illinois segment, driven by an increase in operating expenses primarily resulting from higher benefits costs and higher gas maintenance costs during the first quarter of 2019. The increase in operating expenses was partially offset by higher natural gas margins at PGL due to continued capital investment in the SMP project under its QIP rider.

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 the first quarter of 2019 and 2018 for each of our segments is presented in the “Consolidated Earnings” table above.



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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.

Wisconsin Segment Contribution to Operating Income



	Three Months Ended March 31
(in millions)	2019		2018		B (W)
Electric revenues	$	1,066.6	$	1,069.1	$	(2.5	)
Fuel and purchased power	338.8		352.3		13.5
Total electric margins	727.8		716.8		11.0

Natural gas revenues	566.8		520.0		46.8
Cost of natural gas sold	352.6		319.7		(32.9		)
Total natural gas margins	214.2		200.3		13.9

Total electric and natural gas margins	942.0		917.1		24.9

Other operation and maintenance	392.7		468.5		75.8
Depreciation and amortization	151.0		135.1		(15.9		)
Property and revenue taxes	36.5		39.8		3.3
Operating income	$	361.8	$	273.7	$	88.1

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



	Three Months Ended March 31
(in millions)	2019		2018		B (W)
Operation and maintenance not included in line items below	$	176.1	$	177.0	$	0.9
We Power ⁽¹⁾	35.9		127.2		91.3
Transmission ⁽²⁾	105.8		104.7		(1.1		)
Transmission expense related to the flow through of tax repairs ⁽³⁾	15.3		14.7		(0.6		)
Transmission expense related to Tax Legislation ⁽⁴⁾	15.2		—		(15.2		)
Regulatory amortizations and other pass through expenses ⁽⁵⁾	44.4		44.9		0.5
Total other operation and maintenance	$	392.7	$	468.5	$	75.8

⁽¹⁾

Represents costs associated with the We Power generation units, including operating and maintenance costs incurred by WE. For the first quarter of 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, for the first quarter of 2019, the $91.8 million of lease expense related to the We Power leases with WE was no longer classified within operation and maintenance, but was instead recorded as $4.6 million and $87.2 million of depreciation and amortization and interest expense, respectively, in accordance with Topic 842. The We Power lease does not impact our financial statements as all amounts associated with the lease are eliminated at the consolidated level.

During the first quarter of 2019, $30.8 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 the first quarter of 2018, $110.5 million of both lease and operating and maintenance costs were billed to or incurred by WE, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

⁽²⁾

The PSCW has approved escrow accounting for ATC and MISO network transmission expenses for our Wisconsin electric utilities. As a result, WE and WPS defer as a regulatory asset or liability, the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the first quarter of 2019 and 2018, $118.6 million and $94.3 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 22, Regulatory Environment, for more information.


⁽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.



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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.

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



	Three Months Ended March 31
	MWh (in thousands)
Electric Sales Volumes	2019	2018	B (W)
Customer Class
Residential	2,810.7	2,716.9	93.8
Small commercial and industrial *	3,181.1	3,194.3	(13.2	)
Large commercial and industrial *	3,086.8	3,113.4	(26.6	)
Other	45.0	46.2	(1.2	)
Total retail *	9,123.6	9,070.8	52.8
Wholesale	843.7	856.9	(13.2	)
Resale	1,355.5	2,443.6	(1,088.1	)
Total sales in MWh *	11,322.8	12,371.3	(1,048.5	)


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



	Three Months Ended March 31
	Therms (in millions)
Natural Gas Sales Volumes	2019	2018	B (W)
Customer Class
Residential	576.5	524.3	52.2
Commercial and industrial	338.1	316.8	21.3
Total retail	914.6	841.1	73.5
Transport	431.2	413.0	18.2
Total sales in therms	1,345.8	1,254.1	91.7



	Three Months Ended March 31
	Degree Days
Weather	2019	2018	B(W)
WE and WG ⁽¹⁾
Heating (3,271 normal)	3,483	3,225	8.0	%

WPS ⁽²⁾
Heating (3,646 normal)	3,841	3,636	5.6	%

UMERC ⁽³⁾
Heating (3,953 normal)	4,304	4,036	6.6	%


⁽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.

Electric Utility Margins

Electric utility margins at the Wisconsin segment increased $11.0 million during the first quarter of 2019, compared with the same quarter in 2018. The significant factors impacting the higher electric utility margins were:


•	A $17.7 million increase 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. We received the PSCW order in May 2018, which required WE and WPS to use 80% and 40%, respectively, of the current 2018 and 2019 tax benefits to reduce certain regulatory assets. Prior to



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receiving the order, we recorded all of the expected benefits related to the Tax Legislation as if they would be returned to customers through bill credits. This increase in margins was offset by a corresponding increase in transmission and depreciation and amortization expense, resulting in no impact on net income.


•	A $6.3 million increase related to higher retail sales volumes during the first quarter of 2019, driven by favorable weather. As measured by heating degree days, the first quarter of 2019 was 8.0% and 5.6% colder than the same quarter in 2018 in the Milwaukee area and Green Bay area, respectively.

These increases in margins were partially offset by:

•

An $11.6 million quarter-over-quarter negative impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, the margins of our electric utilities are impacted by under- or over-collections of certain fuel and purchased power costs that are less than a 2% price variance from the costs included in rates, and the remaining variance that exceeds the 2% variance is deferred.


•	A $5.0 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.

Natural Gas Utility Margins

Natural gas utility margins at the Wisconsin segment increased $13.9 million during the first quarter of 2019, compared with the same quarter in 2018. The most significant factor impacting the higher natural gas utility margins was higher sales volumes, primarily driven by colder winter weather, customer growth, and higher use per retail customer.

Operating Income

Operating income at the Wisconsin segment increased $88.1 million during the first quarter of 2019, compared with the same quarter in 2018. This increase was driven by $63.2 million of lower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes), and the $24.9 million of higher margins discussed above.

The significant factors impacting the decrease in operating expenses during the first quarter of 2019, compared with the same quarter in 2018, were:

•

A $91.8 million decrease in other operation and maintenance 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. For the first quarter of 2019, the minimum lease payments that were billed from We Power to WE were no longer classified within other operation and maintenance, but were instead recorded as a component of depreciation and amortization and interest expense in accordance with Topic 842.


•	A $14.3 million decrease in expenses across all of our plants, in part due to the retirements of the Pleasant Prairie power plant in April 2018, Edgewater Unit 4 in September 2018, and Pulliam Units 7 and 8 in October 2018. This resulted in lower maintenance and labor costs during the first quarter of 2019.

These decreases in operating expenses were partially offset by:


•	An $18.8 million increase in benefit costs, primarily related to deferred compensation.

•

A $15.9 million increase in depreciation and amortization driven by an increase in capital expenditures as we continue to execute on our capital plan, additional expense recognized related to the adoption of Topic 842, as discussed above, and an increase related to the reduction in the first quarter of 2018 of certain WPS regulatory deferrals as a result of the PSCW's May 2018 order addressing the Tax Legislation.



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•	A $15.2 million increase in transmission expense associated with the May 2018 order from the PSCW related to our required treatment of the benefits associated with the Tax Legislation, as discussed in the other operation and maintenance table above. This increase in transmission expense was offset by a corresponding increase in margins, as previously discussed.

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.



	Three Months Ended March 31
(in millions)	2019		2018		B (W)
Natural gas revenues	$	536.5	$	507.3	$	29.2
Cost of natural gas sold	219.8		201.7		(18.1		)
Total natural gas margins	316.7		305.6		11.1

Other operation and maintenance	128.2		112.2		(16.0		)
Depreciation and amortization	44.5		40.9		(3.6		)
Property and revenue taxes	6.1		4.9		(1.2		)
Operating income	$	137.9	$	147.6	$	(9.7	)

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



	Three Months Ended March 31
(in millions)	2019			2018			B (W)
Operation and maintenance not included in the line items below	$	88.0		$	73.7		$	(14.3	)
Riders *	40.5			38.5			(2.0		)
Regulatory amortizations *	(0.4		)	(0.3		)	0.1
Other	0.1			0.3			0.2
Total other operation and maintenance	$	128.2		$	112.2		$	(16.0	)


*	These riders and regulatory amortizations 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:



	Three Months Ended March 31
	Therms (in millions)
Natural Gas Sales Volumes	2019	2018	B (W)
Customer Class
Residential	449.0	428.6	20.4
Commercial and industrial	174.9	168.4	6.5
Total retail	623.9	597.0	26.9
Transport	387.9	356.6	31.3
Total sales in therms	1,011.8	953.6	58.2



	Three Months Ended March 31
	Degree Days
Weather *	2019	2018	B (W)
Heating (3,168 Normal)	3,387	3,113	8.8	%


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

Natural Gas Utility Margins

Natural gas utility margins at the Illinois segment, net of the $2.0 million impact of the riders referenced in the table above, increased $9.1 million during the first quarter of 2019, compared with the same quarter in 2018, driven by an $8.1 million 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



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SMP through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023. See Note 22, Regulatory Environment, for more information.

Operating Income

Operating income at the Illinois segment decreased $9.7 million during the first quarter of 2019, compared with the same quarter in 2018. This decrease was driven by $18.8 million of higher 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. These increases in operating expenses were partially offset by the $9.1 million increase in margins discussed above.

The significant factors impacting the increase in operating expenses during the first quarter of 2019, compared with the same quarter in 2018 were:


•	A $7.0 million increase in benefit costs, primarily related to deferred compensation.


•	A $5.1 million increase in natural gas maintenance costs, primarily due to the timing of maintenance and increased leak repairs resulting from colder than normal weather in the first quarter of 2019, compared with the same quarter in 2018.


•	A $3.6 million increase in depreciation expense, primarily driven by PGL's continued capital investment in the SMP project.

Other States Segment Contribution to Operating Income



	Three Months Ended March 31
(in millions)	2019		2018		B (W)
Natural gas revenues	$	185.2	$	169.9	$	15.3
Cost of natural gas sold	105.5		96.4		(9.1		)
Total natural gas margins	79.7		73.5		6.2

Other operation and maintenance	27.6		26.6		(1.0		)
Depreciation and amortization	6.5		6.6		0.1
Property and revenue taxes	4.1		4.1		—
Operating income	$	41.5	$	36.2	$	5.3

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



	Three Months Ended March 31
(in millions)	2019		2018		B (W)
Operation and maintenance not included in line item below	$	18.8	$	17.4	$	(1.4	)
Regulatory amortizations and other pass through expenses *	8.8		9.2		0.4
Total other operation and maintenance	$	27.6	$	26.6	$	(1.0	)


*	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 sales volumes by customer class and weather statistics:



	Three Months Ended March 31
	Therms (in millions)
Natural Gas Sales Volumes	2019	2018	B (W)
Customer Class
Residential	172.0	170.4	1.6
Commercial and industrial	111.0	103.8	7.2
Total retail	283.0	274.2	8.8
Transport	228.7	224.2	4.5
Total sales in therms	511.7	498.4	13.3



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	Three Months Ended March 31
	Degree Days
Weather *	2019	2018	B (W)
MERC
Heating (3,901 Normal)	4,382	4,085	7.3	%

MGU
Heating (3,206 Normal)	3,298	3,135	5.2	%


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

Natural Gas Utility Margins

Natural gas utility margins increased $6.2 million during the first quarter of 2019, compared to the same quarter last year. The increase was primarily driven by higher sales volumes as a result of colder winter weather and customer growth, as well as a favorable impact related to the retail natural gas rate increase at MERC. See Note 22, Regulatory Environment, for more information on the rate increase.

Operating Income

Operating income at the other states segment increased $5.3 million during the first quarter of 2019, compared to the same quarter last year. This increase was driven by the $6.2 million increase in margins discussed above, partially offset by a $0.9 million increase in operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes).

Non-Utility Energy Infrastructure Segment Contribution to Operating Income



	Three Months Ended March 31
(in millions)	2019		2018		B (W)
Operating income	$	92.7	$	93.0	$	(0.3	)

Corporate and Other Segment Contribution to Operating Income



	Three Months Ended March 31
(in millions)	2019			2018			B (W)
Operating loss	$	(3.9	)	$	(5.4	)	$	1.5

Electric Transmission Segment Operations



	Three Months Ended March 31
(in millions)	2019		2018		B (W)
Equity in earnings of transmission affiliates	$	36.1	$	32.8	$	3.3

Earnings from our ownership interests in transmission affiliates increased $3.3 million during the first quarter of 2019, compared with the same quarter in 2018, primarily due to continued capital investment by ATC.

Consolidated Other Income, Net



	Three Months Ended March 31
(in millions)	2019		2018			B (W)
AFUDC – Equity	$	4.9	$	3.3		$	1.6
Non-service components of net periodic benefit costs	8.3		7.2			1.1
Other, net	17.7		(3.0		)	20.7
Other income, net	$	30.9	$	7.5		$	23.4



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Other income, net increased $23.4 million during the first quarter of 2019, compared with the same quarter in 2018. The increase was primarily driven by net gains on the investments held in the Integrys rabbi trust during the first quarter of 2019, compared with net losses during the same period in 2018. The increase related to the investments held in the rabbi trust was offset by higher benefits costs related to deferred compensation included in operating income. See Note 12, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.

Consolidated Interest Expense



	Three Months Ended March 31
(in millions)	2019		2018		B (W)
Interest expense	$	124.4	$	106.7	$	(17.7	)

Interest expense increased $17.7 million during the first quarter of 2019, compared with the same quarter in 2018, primarily due to higher debt balances and higher interest rates. The increase in debt balances is primarily related to continued capital investments.

Consolidated Income Tax Expense



	Three Months Ended March 31
	2019		2018		B (W)
Effective tax rate	13.4	%	18.4	%	5.0	%

Our effective tax rate decreased by 5.0% when compared with the first quarter of 2018, primarily due to an increase in wind production tax credits generated in the first quarter of 2019, related to recent acquisitions of wind generation facilities in our non-utility energy infrastructure segment. Also contributing to the decrease in the effective tax rate was the recognition of more excess tax benefits related to stock options, as more options were exercised in the first quarter of 2019. See Note 11, Income Taxes, for more information.

We expect our 2019 annual effective tax rate to be between 10.5% and 11.5%, which includes an estimated 9.5% effective tax rate benefit due to the flow through of tax repairs in connection with the Wisconsin rate settlement. Excluding the impact of the tax repairs, the expected 2019 range would be between 20% and 21%.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

The following table summarizes our cash flows during the three months ended March 31:



(in millions)	2019			2018			Change in 2019 Over 2018
Cash provided by (used in):
Operating activities	$	735.7		$	894.0		$	(158.3	)
Investing activities	(606.6		)	(435.8		)	(170.8		)
Financing activities	(186.1		)	(445.1		)	259.0

Operating Activities

Net cash provided by operating activities decreased $158.3 million during the first quarter of 2019, compared with the same quarter in 2018, driven by:


•	A $200.6 million decrease in cash from higher payments for other operation and maintenance expenses. During the first quarter of 2019, our payments were higher for accounts payable, transmission, and benefits, compared with the same quarter in 2018.


•	A $51.7 million decrease in cash related primarily to the impact of the Tax Legislation, which led to lower overall collections from customers during the first quarter of 2019, compared with the same quarter in 2018.


•	A $14.8 million decrease in cash related to higher payments for environmental remediation from work completed on manufactured gas plants during the first quarter of 2019, compared with the same quarter in 2018.



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These decreases in net cash provided by operating activities were partially offset by a $125.1 million increase in cash, driven by the timing of payments for natural gas, which were lower in the first quarter of 2019. This increase in cash was also driven by higher amounts of inventory consumed during the first quarter of 2019, compared with the same quarter in 2018, to meet the requirements of our customers during the colder winter weather.

Investing Activities

Net cash used in investing activities increased $170.8 million during the first quarter of 2019, compared with the same quarter in 2018. The increase in net cash used in investing activities was driven by the acquisition of an 80% ownership interest in Upstream during 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. This increase in net cash used in investing activities was partially offset by an $80.8 million decrease in cash paid for capital expenditures during the first quarter of 2019, compared with the same quarter in 2018, which is discussed in more detail below.

Capital Expenditures

Capital expenditures by segment for the three months ended March 31 were as follows:



Reportable Segment (in millions)	2019		2018		Change in 2019 Over 2018
Wisconsin	$	232.6	$	284.1	$	(51.5	)
Illinois	101.4		114.6		(13.2		)
Other states	13.7		17.0		(3.3		)
Non-utility energy infrastructure	8.1		3.9		4.2
Corporate and other	3.0		20.0		(17.0		)
Total capital expenditures	$	358.8	$	439.6	$	(80.8	)

The decrease in cash paid for capital expenditures at the Wisconsin segment during the first quarter of 2019, compared with the same quarter in 2018, was primarily driven by the implementation of an enterprise resource planning system and various other software projects, projects at the OCPP, and upgrades to WE's electric distribution system during the first quarter of 2018. These decreases in cash paid for capital expenditures were partially offset by increased capital expenditures during the first quarter of 2019 for the construction of a new natural gas-fired generation facility in the Upper Peninsula of Michigan, 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.

The decrease in cash paid for capital expenditures at the Illinois segment during the first quarter of 2019, compared with the same quarter in 2018, was driven by the timing of payments for PGL's SMP in the first quarter of 2019.

The decrease in cash paid for capital expenditures at the corporate and other segment during the first quarter of 2019, compared with the same quarter in 2018, was primarily driven by the implementation of an enterprise resource planning system during the first quarter of 2018.

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

Financing Activities

Net cash used in financing activities decreased $259.0 million during the first quarter of 2019, compared with the same quarter in 2018, driven by:


•	A $350.0 million increase in cash due to the issuance of long-term debt during the first quarter of 2019.


•	A $30.5 million increase in cash from stock options exercised during the first quarter of 2019, compared with the same quarter in 2018.



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These increases in cash were partially offset by:


•	A $54.9 million decrease in cash due to an increase in shares of our common stock purchased during the first quarter of 2019, compared with the same quarter in 2018, to satisfy requirements of our stock-based compensation plans.


•	A $50.6 million decrease in cash related to higher net repayments of commercial paper during the first quarter of 2019, compared with the same quarter in 2018.


•	A $12.0 million decrease in cash due to higher dividends paid on our common stock during the first quarter of 2019, compared with the same quarter in 2018. In January 2019, our Board of Directors increased our quarterly dividend by $0.0375 per share (6.79%) effective with the first quarter of 2019 dividend payment.

Significant Financing Activities

For more information on our financing activities, see Note 7, Short-Term Debt and Lines of Credit, and Note 8, 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 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, WG, WPS, 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 7, Short-Term Debt and Lines of Credit, for more information about these credit facilities.

The following table shows our capitalization structure as of March 31, 2019, as well as an adjusted capitalization structure that we believe is consistent with how a majority of the rating agencies currently view our 2007 Junior Notes:



(in millions)	Actual			Adjusted
Common shareholders' equity	$	9,984.5		$	10,234.5
Preferred stock of subsidiary	30.4			30.4
Long-term debt (including current portion)	10,692.7			10,442.7
Short-term debt	1,145.2			1,145.2
Total capitalization	$	21,852.8		$	21,852.8

Total debt	$	11,837.9		$	11,587.9

Ratio of debt to total capitalization	54.2		%	53.0		%

Included in long-term debt on our balance sheet as of March 31, 2019, is $500.0 million principal amount of the 2007 Junior Notes. The adjusted presentation attributes $250.0 million of the 2007 Junior Notes to common shareholders' equity and $250.0 million to long-term debt.

The adjusted presentation of our consolidated capitalization structure is included as a complement to our capitalization structure presented in accordance with GAAP. Management evaluates and manages our capitalization structure, including our total debt to total capitalization ratio, using the GAAP calculation as adjusted by the rating agency treatment of the 2007 Junior Notes. Therefore,



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we believe the non-GAAP adjusted presentation reflecting this treatment is useful and relevant to investors in understanding how management and the rating agencies evaluate our capitalization structure.

Working Capital

As of March 31, 2019, our current liabilities exceeded our current assets by $881.6 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.

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

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)	2019		2020		2021
Wisconsin	$	1,344.9	$	1,677.5	$	1,559.1
Illinois	765.2		684.0		602.4
Other states	155.4		135.8		105.5
Non-utility energy infrastructure	424.2		418.8		242.8
Corporate and other	15.7		11.0		1.1
Total	$	2,705.4	$	2,927.1	$	2,510.9

WPS is continuing work on the SMRP. 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 $185 million between 2019 and 2021 on this project. WE, WPS, and WG will also continue to upgrade their electric and natural gas distribution systems to enhance reliability. These upgrades include the advanced metering infrastructure (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.



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As part of our commitment to invest in zero-carbon generation, we plan to invest in utility scale solar of up to 350 MW within our Wisconsin segment. WPS has partnered with an unaffiliated utility to acquire ownership interests in two proposed solar projects in Wisconsin. Badger Hollow Solar Farm will be located in Iowa County, Wisconsin, and Two Creeks Solar Project will be located in Manitowoc County, Wisconsin. 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 $260 million. Commercial operation for both projects is targeted for the end of 2020. Solar generation technology has greatly improved, has become more cost-effective, and it complements our summer demand curve.

In connection with the formation of UMERC, we entered into an agreement with Tilden under which it will purchase electric power from UMERC for 20 years, contingent upon UMERC's construction of approximately 180 MW of natural gas-fired generation in the Upper Peninsula of Michigan. The new generation began commercial operation on March 31, 2019. The estimated cost of this project is approximately $242 million ($255 million including AFUDC), 50% of which is expected to be recovered from Tilden, with the remaining 50% expected to be recovered from UMERC's other utility customers.

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 2021 is between $280 million and $300 million. See Note 22, Regulatory Environment, for more information on the SMP.

The non-utility energy infrastructure line item in the table above includes our investments in Coyote Ridge and Upstream. See Note 2, Acquisitions, for more information on these wind projects.

We expect to provide total capital contributions to ATC and ATC Holdco (not included in the above table) of approximately $185 million from 2019 through 2021.

Common Stock Dividends

Our current quarterly dividend rate is $0.59 per share, which equates to an annual dividend of $2.36 per share. For information related to our most recent common stock dividend declared, see Note 6, Common Equity.

Off-Balance Sheet Arrangements

We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit that support construction projects, commodity contracts, and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see Note 7, Short-Term Debt and Lines of Credit, Note 14, Guarantees, and Note 19, Variable Interest Entities.

Contractual Obligations

For information about our commitments, see Contractual Obligations in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Requirements in our 2018 Annual Report on Form 10-K. There were no material changes to our commitments outside the ordinary course of business during the first quarter of 2019.

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity, and capital resources. The following discussion should be read together with the information in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources in our 2018 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, competitive markets, environmental matters, critical accounting policies and estimates, and other matters.



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Market Risks and Other Significant Risks

We are exposed to market and other significant risks as a result of the nature of our businesses and the environments in which those businesses operate. These risks include, but are not limited to, the regulatory recovery risk described below. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in our 2018 Annual Report on Form 10-K for a discussion of other significant risks applicable to us.

Regulatory Recovery

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. 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.

Due to the Tax Legislation signed into law in December 2017, our regulated utilities remeasured their deferred taxes and recorded a tax benefit of $2,529 million. Our utilities have been returning the amortization of this tax benefit to ratepayers through refunds, bill credits, riders, and reductions to other regulatory assets, which we expect to continue.

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:

•

In June 2016, the PSCW approved the deferral of costs related to WPS's ReACT™ project above the originally authorized $275.0 million level through 2017. The total cost of the ReACT™ project, excluding $51 million of AFUDC, was $342 million. In September 2017, the PSCW approved an extension of this deferral through 2019 as part of a settlement agreement. WPS has requested approval for collection of these deferred costs in the rate proposal it filed with the PSCW in March 2019. See Note 22, Regulatory Environment, for more information.

•

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 March 31, 2019, we had not received any significant disallowances of the costs incurred for this project. We will be required to obtain approval for the recovery of additional costs incurred through the completion of this long-term project. WPS has requested recovery of these costs in the rate proposal it filed with the PSCW in March 2019.

•

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, 2016, and 2015 reconciliations, are still pending. As of March 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 22, Regulatory Environment, for more information regarding recent and pending rate proceedings, orders, and investigations involving our utilities, including the rate proposals our Wisconsin utilities filed with the PSCW in March 2019.

Environmental Matters

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



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Other Matters

Tax Cuts and Jobs Act of 2017

In December 2017, the Tax Legislation was signed into law. In May 2018, 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. We expect that the various remaining impacts of the Tax Legislation on our Wisconsin operations will be addressed in our pending rate case we filed with the PSCW in March 2019. In addition, the ICC approved the Variable Income Tax Adjustment Rider in Illinois, and in Minnesota, the MPUC included the various impacts of the Tax Legislation in MERC's final 2018 rate order. We are also working with the FERC to modify our formula rate tariffs for the impacts of the Tax Legislation, and we expect to receive FERC approval for the modified tariffs in 2019. See Note 22, Regulatory Environment, for more information.

American Transmission Company Allowed Return on Equity Complaints

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 October 2014, the FERC issued an order to hear the complaint on ROE and set a refund effective date retroactive to November 2013. In December 2015, the ALJ issued an initial decision recommending that ATC and all other MISO transmission owners be authorized to collect a 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 incentive adder only applies to revenues collected after January 6, 2015. In September 2016, the FERC issued an order related to this complaint affirming the use of the ROE stated in the ALJ's initial decision, effective as of the order date, on a going-forward basis. The order also required ATC to provide refunds, with interest, for the 15-month refund period from November 12, 2013, through February 11, 2015. The $28.3 million refund that ATC provided to WE and WPS for transmission costs paid during the refund period reduced the regulatory assets recorded under the PSCW-approved escrow accounting for transmission expense and resulted in a net regulatory liability for WPS.

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. In June 2016, the ALJ issued an initial decision recommending that ATC and all other MISO transmission owners be authorized to collect a base ROE of 9.7%, as well as the 0.5% incentive adder approved for MISO transmission owners. The ALJ's initial decision is not binding on the FERC and applies to revenues collected from February 12, 2015, through May 11, 2016. We are uncertain when a FERC order related to this matter will be issued.

The MISO transmission owners have filed various appeals related to several of the FERC orders with the United States Court of Appeals for the District of Columbia Circuit as well as requests for rehearing.

In November 2018, the FERC issued an order directing MISO transmission owners, including ATC, to submit briefs on a proposed change to the methodology used to calculate their base ROE. In March 2019, the FERC issued two new orders expanding its ROE inquiries to solicit comments from all potential stakeholders, including those outside of MISO. If the proposed methodology is approved, ATC’s base ROE for the period from November 12, 2013 through February 11, 2015 would be 10.28% instead of the 10.32% approved by the FERC in September 2016. The proposed methodology would also impact the second complaint filed in February 2015 and ATC’s base ROE going forward. We are uncertain when a final FERC order related to the proposed methodology will be issued.



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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes related to market risk from the disclosures presented in our 2018 Annual Report on Form 10-K. In addition to the Form 10-K disclosures, see Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in Item 2 of Part I of this report, as well as Note 12, Fair Value Measurements, Note 13, Derivative Instruments, and Note 14, Guarantees, in this report for information concerning our market risk exposures.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based upon such evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of such period, our disclosure controls and procedures are effective: (i) in recording, processing, summarizing, and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act; and (ii) to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the first quarter of 2019 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.



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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The following should be read in conjunction with Item 3. Legal Proceedings in Part I of our 2018 Annual Report on Form 10-K. See Note 20, Commitments and Contingencies, and Note 22, Regulatory Environment, in this report for more information on material legal proceedings and matters related to us and our subsidiaries.

In addition to those legal proceedings discussed in Note 20, Commitments and Contingencies, Note 22, Regulatory Environment, and below, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these additional legal proceedings cannot be predicted with certainty, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material effect on our financial statements.

Environmental Matters

Manlove Field Matter

In September 2017, the Illinois Department of Natural Resources, Office of Oil and Gas Resource Management, issued a Violation Notice (VN) to PGL related to a leak of natural gas from a well located at the PGL Manlove Gas Storage Field in December 2016. PGL quickly shut down and permanently plugged the well to contain the leak after it was discovered. The leak resulted in the migration of natural gas from the well to the Mahomet Aquifer located in central Illinois and impacted residential freshwater wells. PGL has been working with residents potentially impacted by the natural gas leak, and the Illinois state agencies to investigate and remediate the impacts of the natural gas leak to the Mahomet Aquifer. In October 2017, the Illinois Attorney General (AG) filed a complaint against PGL alleging certain violations of the Illinois Environmental Protection Act and the Oil and Gas Act. PGL entered into an interim agreed order with the State of Illinois in October 2017 whereby PGL agreed, among other things, to continue actions it was already undertaking proactively. In addition, in December 2017, the Illinois Environmental Protection Agency (IEPA) issued a VN to PGL alleging the same violations as the AG. Lastly, in January 2018, the IEPA issued a VN alleging certain violations of Illinois air emission rules arising from the construction and operation of flaring equipment at the leak site. Both of the IEPA VN matters have been referred to the AG for enforcement.

In the complaint, as is customary in these types of actions, the AG cited to the statutory penalties allowed by law. Ultimately, the pursuit of any civil penalties is at the AG’s discretion. In the event the AG wishes to consider such penalties, we believe that PGL's high level of cooperation and quick action to remedy the situation and to work with the potentially impacted homeowners would be taken into account. At this time, we believe that civil penalties, if any, will not have a material impact on our financial statements.

Presque Isle Power Plant Matter

In March 2018, the EPA issued a Finding of Violation to WE regarding alleged violations of mercury emission limits for the PIPP Units 5, 6, 8, and 9, as well as failure to conduct mercury tests on its low-emitting electric generating units once every 12 months. The EPA has advised WE that it is not pursuing this matter any further.

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors presented in our 2018 Annual Report on Form 10-K. See Item 1A. Risk Factors in Part I of our Form 10-K for a discussion of certain risk factors applicable to us.



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ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table sets forth information regarding the purchases of our equity securities made by or on behalf of us or any affiliated purchaser (as defined in Exchange Act Rule 10b-18) during the three months ended March 31, 2019:

Issuer Purchases of Equity Securities



2019	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
January 1 – January 31	39,222	$	68.10	—	$	—
February 1 – February 28	4,741	74.47		—	—
March 1 – March 31	11,567	75.90		—	—
Total *	55,530	$	70.27	—


*	All shares were surrendered by employees to satisfy tax withholding obligations upon vesting of restricted stock.

ITEM 6. EXHIBITS



Number	Exhibit
4	Instruments defining the rights of security holders, including indentures
	4.1	Securities Resolution No. 8 of WEC Energy Group, dated as of March 4, 2019, under the Indenture for Debt Securities, dated as of March 15, 1999, between WEC Energy Group and The Bank of New York Mellon Trust Company, N.A. (as successor to the First National Bank of Chicago), as Trustee. (Exhibit 4.1 to WEC Energy Group's Form 8-K filed March 8, 2019.)

31	Rule 13a-14(a) / 15d-14(a) Certifications

	31.1	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31.2	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32	Section 1350 Certifications

	32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

	32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101	Interactive Data File



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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		WEC ENERGY GROUP, INC.
		(Registrant)

		/s/ WILLIAM J. GUC
Date:	May 3, 2019	William J. Guc
		Vice President and Controller

		(Duly Authorized Officer and Chief Accounting Officer)



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