WEC Energy (WEC) 10-Q 3 May 19 2019 Q1 Quarterly report Financial data

DOCUMENT AND ENTITY INFORMATION

DOCUMENT AND ENTITY INFORMATION	3 Months Ended
	Mar. 31, 2019shares
Document Entity Information [Abstract]
Entity registrant name	WEC Energy Group, Inc.
Entity central index key	0000783325
Current fiscal year end date	--12-31
Entity filer category	Large Accelerated Filer
Document type	10-Q
Document period end date	Mar. 31, 2019
Document fiscal year focus	2019
Document fiscal period focus	Q1
Amendment flag	false
Entity common stock, shares outstanding	315,438,398
Emerging growth company	false
Small company	false

CONDENSED CONSOLIDATED INCOME S

CONDENSED CONSOLIDATED INCOME STATEMENTS - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Income Statement [Abstract]
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	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	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 (in dollars per share)	$ 1.33	$ 1.24
Diluted (in dollars per share)	$ 1.33	$ 1.23
Weighted average common shares outstanding
Basic (in shares)	315.5	315.5
Diluted (in shares)	316.7	316.9

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Statement of Other Comprehensive Income [Abstract]
Net income	$ 420.4	$ 390.4
Derivatives accounted for as cash flow hedges
Derivative losses, net of tax	(1.2)	0
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	392.1
Preferred stock dividends of subsidiary	0.3	0.3
Comprehensive income attributed to common shareholders	$ 418.7	$ 391.8

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
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
Current liabilities
Short-term debt	1,145.2	1,440.1
Current portion of long-term debt	366	365
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
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)	(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

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Accounts receivable and accrued unbilled revenues, reserves	$ 163.2	$ 149.2
Property, plant, and equipment, accumulated depreciation	$ 8,589	$ 8,636.6
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	325,000,000	325,000,000
Common stock, shares outstanding	315,438,398	315,523,192

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 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
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
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
Investing Activities
Capital expenditures	(358.8)	(439.6)
Acquisition of Upstream, net of cash and restricted cash acquired of $9.2	(268.2)	0
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)	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

CONDENSED CONSOLIDATED STATEM_3

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Statement of Cash Flows [Abstract]
Cash and restricted cash acquired	$ 9.2	$ 0

CONDENSED CONSOLIDATED STATEM_4

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Millions	Total	Total Common Shareholders' Equity	Common Stock	Additional Paid In Capital	Retained Earnings	Accumulated Other Comprehensive Income	Preferred Stock of Subsidiary	Noncontrolling Interest
Balance at Dec. 31, 2017	$ 9,491.8	$ 9,461.4	$ 3.2	$ 4,278.5	$ 5,176.8	$ 2.9	$ 30.4	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributed to common shareholders	390.1	390.1	0	0	390.1	0	0	0
Other comprehensive income (loss)	1.7	1.7	0	0	0	1.7	0	0
Common stock dividends	(174.2)	(174.2)	0	0	(174.2)	0	0	0
Exercise of stock options	2.1	2.1	0	2.1	0	0	0	0
Purchase of common stock	(15.8)	(15.8)	0	(15.8)	0	0	0	0
Stock-based compensation and other	2.5	2.5	0	2.5	0	0	0	0
Balance at Mar. 31, 2018	9,698.2	9,667.8	3.2	4,267.3	5,392.7	4.6	30.4	0
Balance at Dec. 31, 2018	9,842.7	9,788.9	3.2	4,250.1	5,538.2	(2.6)	30.4	23.4
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributed to common shareholders	420.1	420.1	0	0	420.1	0	0	0
Other comprehensive income (loss)	(1.4)	(1.4)	0	0	0	(1.4)	0	0
Common stock dividends	(186.2)	(186.2)	0	0	(186.2)	0	0	0
Exercise of stock options	32.6	32.6	0	32.6	0	0	0	0
Purchase of common stock	(70.7)	(70.7)	0	(70.7)	0	0	0	0
Acquisition of a noncontrolling interest	69	0	0	0	0	0	0	69
Capital contributions from noncontrolling interest	4.8	0	0	0	0	0	0	4.8
Stock-based compensation and other	1.2	1.2	0	1.2	0	0	0	0
Balance at Mar. 31, 2019	$ 10,112.1	$ 9,984.5	$ 3.2	$ 4,213.2	$ 5,772.1	$ (4)	$ 30.4	$ 97.2

CONDENSED CONSOLIDATED STATEM_5

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Parentheticals) - $ / shares	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Statement of Stockholders' Equity [Abstract]
Quarterly cash dividend declared (in dollars per share)	$ 0.59	$ 0.5525

GENERAL INFORMATION

GENERAL INFORMATION	3 Months Ended
	Mar. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
GENERAL INFORMATION	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, w e 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, an d Upstream held by third parties. W e 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.

ACQUISITIONS

ACQUISITIONS	3 Months Ended
	Mar. 31, 2019
Business Combinations [Abstract]
ACQUISITIONS	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. 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.

OPERATING REVENUES

OPERATING REVENUES	3 Months Ended
	Mar. 31, 2019
Revenue from Contract with Customer [Abstract]
OPERATING REVENUES	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 (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 (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.

REGULATORY ASSETS AND LIABILITI

REGULATORY ASSETS AND LIABILITIES	3 Months Ended
	Mar. 31, 2019
Regulatory Assets and Liabilities Disclosure [Abstract]
REGULATORY ASSETS AND LIABILITIES	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

PROPERTY, PLANT, AND EQUIPMENT

PROPERTY, PLANT, AND EQUIPMENT	3 Months Ended
	Mar. 31, 2019
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT, AND EQUIPMENT	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.

COMMON EQUITY

COMMON EQUITY	3 Months Ended
	Mar. 31, 2019
Equity [Abstract]
COMMON EQUITY	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.

SHORT-TERM DEBT AND LINES OF CR

SHORT-TERM DEBT AND LINES OF CREDIT	3 Months Ended
	Mar. 31, 2019
Short-term Debt [Abstract]
SHORT-TERM DEBT AND LINES OF CREDIT	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

LONG-TERM DEBT

LONG-TERM DEBT	3 Months Ended
	Mar. 31, 2019
Long-term Debt, Unclassified [Abstract]
Long-Term Debt	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.

LEASES

LEASES	3 Months Ended
	Mar. 31, 2019
Leases [Abstract]
LEASES	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, 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. • 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. 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.

MATERIALS, SUPPLIES, AND INVENT

MATERIALS, SUPPLIES, AND INVENTORIES	3 Months Ended
	Mar. 31, 2019
Inventory Disclosure [Abstract]
MATERIALS, SUPPLIES, AND INVENTORIES	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.

INCOME TAXES

INCOME TAXES	3 Months Ended
	Mar. 31, 2019
Income Tax Disclosure [Abstract]
INCOME TAXES	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.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	3 Months Ended
	Mar. 31, 2019
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	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 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. 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.

DERIVATIVE INSTRUMENTS

DERIVATIVE INSTRUMENTS	3 Months Ended
	Mar. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS	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. 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 We estimate that during the next twelve months, $1.5 million will be reclassified from accumulated OCI as a reduction to interest expense.

GUARANTEES

GUARANTEES	3 Months Ended
	Mar. 31, 2019
Guarantees [Abstract]
GUARANTEES	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.

EMPLOYEE BENEFITS

EMPLOYEE BENEFITS	3 Months Ended
	Mar. 31, 2019
Retirement Benefits [Abstract]
EMPLOYEE BENEFITS	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 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.

GOODWILL

GOODWILL	3 Months Ended
	Mar. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
GOODWILL	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 .

INVESTMENT IN TRANSMISSION AFFI

INVESTMENT IN TRANSMISSION AFFILIATES	3 Months Ended
	Mar. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
INVESTMENT IN TRANSMISSION AFFILIATES	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. 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

SEGMENT INFORMATION

SEGMENT INFORMATION	3 Months Ended
	Mar. 31, 2019
Segment Reporting [Abstract]
SEGMENT INFORMATION	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 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

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	3 Months Ended
	Mar. 31, 2019
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Determination Methodology and Factors [Abstract]
VARIABLE INTEREST ENTITIES	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. 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.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	3 Months Ended
	Mar. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	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 . 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 CO 2 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. We are required to report our CO 2 equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2018, we reported aggregated CO 2 equivalent emissions of 26.4 million metric tonnes to the EPA. We are also required to report CO 2 equivalent emissions related to the natural gas that our natural gas utilities distribute and sell. For 2018, we reported aggregated CO 2 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 . 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. 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.

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	3 Months Ended
	Mar. 31, 2019
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	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

REGULATORY ENVIRONMENT

REGULATORY ENVIRONMENT	3 Months Ended
	Mar. 31, 2019
Regulated Operations [Abstract]
REGULATORY ENVIRONMENT	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. 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 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. 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.

NEW ACCOUNTING PRONOUNCEMENTS

NEW ACCOUNTING PRONOUNCEMENTS	3 Months Ended
	Mar. 31, 2019
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
NEW ACCOUNTING PRONOUNCEMENTS	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.

GENERAL INFORMATION (Policies)

GENERAL INFORMATION (Policies)	3 Months Ended
	Mar. 31, 2019
Accounting Policies [Abstract]
Consolidation	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, w e 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, an d Upstream held by third parties. W e completed the acquisition of an 80% membership interest in Upstream during January 2019. See Note 2, Acquisitions, for more information
Basis of Accounting	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.
Leases	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. 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.
Fair Value Measurement	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 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.
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.
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.
Other non-utility revenues
Disaggregation of Operating Revenues
Revenue Recognition	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.

OPERATING REVENUES (Tables)

OPERATING REVENUES (Tables)	3 Months Ended
	Mar. 31, 2019
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	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 (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
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	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
Revenues from contracts with customers | Natural gas
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	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 (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.
Revenues from contracts with customers | Other non-utility revenues
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	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
Other operating revenues
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	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.

REGULATORY ASSETS AND LIABILI_2

REGULATORY ASSETS AND LIABILITIES (Tables)	3 Months Ended
	Mar. 31, 2019
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of regulatory assets	(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.
Schedule of regulatory liabilities	(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

PROPERTY, PLANT, AND EQUIPMENT

PROPERTY, PLANT, AND EQUIPMENT (Tables)	3 Months Ended
	Mar. 31, 2019
Restructuring cost and reserve
Schedule of changes to our severance liability	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

COMMON EQUITY (Tables)

COMMON EQUITY (Tables)	3 Months Ended
	Mar. 31, 2019
Equity [Abstract]
Schedule of stock-based compensation awards granted	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.

SHORT-TERM DEBT AND LINES OF _2

SHORT-TERM DEBT AND LINES OF CREDIT (Tables)	3 Months Ended
	Mar. 31, 2019
Short-term Debt [Abstract]
Schedule of short-term borrowings and weighted-average interest rates	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 %
Schedule of revolving credit facilities and remaining available capacity	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

LEASES (Tables)

LEASES (Tables)	3 Months Ended
	Mar. 31, 2019
Leases [Abstract]
Schedule of lease expense and supplemental cash flow information for leases	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.
Schedule of finance lease right of use asset	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
Schedule of future minimum lease payments for operating and finance leases	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

MATERIALS, SUPPLIES, AND INVE_2

MATERIALS, SUPPLIES, AND INVENTORIES (Tables)	3 Months Ended
	Mar. 31, 2019
Inventory Disclosure [Abstract]
Schedule of Inventory	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

INCOME TAXES (Tables)

INCOME TAXES (Tables)	3 Months Ended
	Mar. 31, 2019
Income Tax Disclosure [Abstract]
Schedule of Effective Income Tax Rate Reconciliation	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 %

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	3 Months Ended
	Mar. 31, 2019
Fair Value Disclosures [Abstract]
Fair value of assets and liabilities measured on a recurring basis, categorized by level within the fair value hierarchy	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
Reconciliation of changes in fair value of items categorized as level 3 measurements	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
Schedule of carrying value and estimated fair value of financial instruments not recorded at fair value	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.

DERIVATIVE INSTRUMENTS (Tables)

DERIVATIVE INSTRUMENTS (Tables)	3 Months Ended
	Mar. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative assets and derivative liabilities	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.
Estimated notional volumes and realized gain (losses)	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 )
Offsetting assets and liabilities	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 .
Amounts related to cash flow hedges recorded in OCI and 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

GUARANTEES (Tables)

GUARANTEES (Tables)	3 Months Ended
	Mar. 31, 2019
Guarantees [Abstract]
Schedule of outstanding 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.

EMPLOYEE BENEFITS (Tables)

EMPLOYEE BENEFITS (Tables)	3 Months Ended
	Mar. 31, 2019
Retirement Benefits [Abstract]
Schedule of net benefit costs	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 )

GOODWILL (Tables)

GOODWILL (Tables)	3 Months Ended
	Mar. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of changes to our goodwill balances by segment	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 .

INVESTMENT IN TRANSMISSION AF_2

INVESTMENT IN TRANSMISSION AFFILIATES (Tables)	3 Months Ended
	Mar. 31, 2019
Investment in transmission affiliates
Schedule of changes to our investments in transmission affiliates	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.
ATC
Investment in transmission affiliates
Schedule of significant transactions with ATC	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
Schedule of receivables and payables with ATC	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
Schedule of summarized income statement data for ATC	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
Schedule of summarized balance sheet data for ATC	(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

SEGMENT INFORMATION (Tables)

SEGMENT INFORMATION (Tables)	3 Months Ended
	Mar. 31, 2019
Segment Reporting [Abstract]
Financial information of reportable segments	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

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	3 Months Ended
	Mar. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Schedule of regulatory assets and reserves related to manufactured gas plant 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

SUPPLEMENTAL CASH FLOW INFORM_2

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	3 Months Ended
	Mar. 31, 2019
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
Schedule of 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
Reconciliation of cash and cash equivalents and restricted cash	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

GENERAL INFORMATION - GENERAL (

GENERAL INFORMATION - GENERAL (Details) customer in Millions	Mar. 31, 2019customer
Electric
Product information [Line Items]
Number Of Customers	1.6
Natural gas
Product information [Line Items]
Number Of Customers	2.9

GENERAL INFORMATION - INVESTMEN

GENERAL INFORMATION - INVESTMENTS (Details)	Mar. 31, 2019
ATC
Schedule of Investments [Line Items]
Equity method investment, ownership interest (as a percent)	60.00%
Upstream
Schedule of Investments [Line Items]
WEC's ownership interest in Upstream Wind Energy Center	80.00%

ACQUISITIONS - UPSTREAM ACQUISI

ACQUISITIONS - UPSTREAM ACQUISITION (Details) - Upstream $ in Millions	3 Months Ended
	Mar. 31, 2019USD ($)MW
Business Acquisition [Line Items]
WEC's ownership interest in Upstream Wind Energy Center	80.00%
Capacity of Upstream Wind Energy Center | MW	202.5
Acquisition purchase price	$ 268.2
Cash and restricted cash acquired	$ 9.2
Number of years Upstream will receive fixed payment	10 years
Bonus depreciation percentage	100.00%

ACQUISITIONS ACQUISITIONS - COY

ACQUISITIONS ACQUISITIONS - COYOTE RIDGE (Details) - Coyote Ridge Wind $ in Millions	1 Months Ended	3 Months Ended
	Dec. 31, 2018USD ($)MW	Mar. 31, 2019USD ($)Years
Business Acquisition [Line Items]
WEC's ownership interest in Coyote Ridge Wind, LLC	80.00%
Capacity of Coyote Ridge | MW	97.5
Acquisition purchase price	$ 61.6
Duration of offtake agreement for the sale of energy produced	12 years
Total expected investment		$ 145
Bonus depreciation percentage		100.00%
Percent of tax benefits entitled to		99.00%
Years Entitled to 99 Percent of Tax Benefits | Years		11

ACQUISITIONS - BISHOP HILL III

ACQUISITIONS - BISHOP HILL III (Details) $ in Millions	1 Months Ended
	Aug. 31, 2018USD ($)MW	Mar. 31, 2019	Dec. 31, 2018USD ($)
Business Acquisition [Line Items]
WEC's ownership interest in Bishop Hill III Wind Energy Center		80.00%
Bishop Hill III Wind Energy Center
Business Acquisition [Line Items]
Capacity of Bishop Hill III Wind Energy Center | MW	132
Acquisition purchase price	$ 144.7		$ 18.2
Restricted cash acquired	$ 4.5
Additional Ownership Interest in Bishop Hill III Wind Energy Center			10.00%
Duration of offtake agreement for the sale of energy produced	22 years
Bonus depreciation percentage		100.00%

ACQUISITIONS - FORWARD WIND ENE

ACQUISITIONS - FORWARD WIND ENERGY CENTER (Details) - Forward Wind Energy Center Acquisition $ in Millions	1 Months Ended	3 Months Ended
	Apr. 30, 2018wind_turbinesutilityMW	Mar. 31, 2019USD ($)
Business Acquisition [Line Items]
Number of utilities along with WPS that entered in an agreement to purchase Forward Wind Energy Center | utility	2
Number of wind turbines at Forward Wind Energy Center | wind_turbines	86
Capacity of Foward Wind Energy Center | MW	138
Purchase price | $		$ 172.9
WPS
Business Acquisition [Line Items]
Number of utilities along with WPS that entered in an agreement to purchase Forward Wind Energy Center | utility	2
Purchase price | $		$ 77.1
WPS's share of Forward Wind Energy Center's purchase price	44.60%
Percentage of Forward Wind Energy Center's output purchased by WPS	44.60%

OPERATING REVENUES - DISAGGREGA

OPERATING REVENUES - DISAGGREGATION OF OPERATING REVENUES BY SEGMENT (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Disaggregation of Operating Revenues
Operating revenues	$ 2,377.4	$ 2,286.5
Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	2,376.5	2,290
Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	0.9	(3.5)
Total utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	2,358.2	2,278.4
Electric | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,061.8	1,067.7
Natural gas | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,296.4	1,210.7
Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,294.7	1,198.3
Other non-utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	18.3	11.6
Total Utility Operations
Disaggregation of Operating Revenues
Operating revenues	2,355.1	2,266.3
Total Utility Operations | Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	(5.6)	(3.6)
Total Utility Operations | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	2,360.7	2,269.9
Total Utility Operations | Total utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	2,356.5	2,266
Total Utility Operations | Electric | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,061.8	1,067.7
Total Utility Operations | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,294.7	1,198.3
Total Utility Operations | Other non-utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	4.2	3.9
Wisconsin
Disaggregation of Operating Revenues
Operating revenues	1,633.4	1,589.1
Wisconsin | Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	6.7	3.4
Wisconsin | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,626.7	1,585.7
Wisconsin | Total utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,626.7	1,585.7
Wisconsin | Electric | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,061.8	1,067.7
Wisconsin | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	564.9	518
Wisconsin | Other non-utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0
Illinois
Disaggregation of Operating Revenues
Operating revenues	536.5	507.3
Illinois | Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	(8.2)	(0.3)
Illinois | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	544.7	507.6
Illinois | Total utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	544.6	507.6
Illinois | Electric | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0
Illinois | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	544.6	507.6
Illinois | Other non-utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0.1	0
Other States
Disaggregation of Operating Revenues
Operating revenues	185.2	169.9
Other States | Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	(4.1)	(6.7)
Other States | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	189.3	176.6
Other States | Total utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	185.2	172.7
Other States | Electric | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0
Other States | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	185.2	172.7
Other States | Other non-utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	4.1	3.9
Non-Utility Energy Infrastructure
Disaggregation of Operating Revenues
Operating revenues	127.8	118.1
Non-Utility Energy Infrastructure | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	29.7	22
Non-Utility Energy Infrastructure | Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	98.1	96.1
Non-Utility Energy Infrastructure | Total utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	16.4	14.9
Non-Utility Energy Infrastructure | Electric | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0
Non-Utility Energy Infrastructure | Natural gas | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	16.4	14.9
Non-Utility Energy Infrastructure | Other non-utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	13.3	7.1
Corporate and Other
Disaggregation of Operating Revenues
Operating revenues	1.7	1.4
Corporate and Other | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1.5	1.3
Corporate and Other | Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	0.2	0.1
Corporate and Other | Total utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0
Corporate and Other | Electric | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0
Corporate and Other | Natural gas | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0
Corporate and Other | Other non-utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1.5	1.3
Reconciling Eliminations
Disaggregation of Operating Revenues
Operating revenues	(107.2)	(99.3)
Reconciling Eliminations | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	(15.4)	(3.2)
Reconciling Eliminations | Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	(91.8)	(96.1)
Reconciling Eliminations | Total utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	(14.7)	(2.5)
Reconciling Eliminations | Electric | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0
Reconciling Eliminations | Natural gas | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	(14.7)	(2.5)
Reconciling Eliminations | Other non-utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ (0.7)	$ (0.7)

OPERATING REVENUES - DISAGGRE_2

OPERATING REVENUES - DISAGGREGATION OF ELECTRIC UTILITY OPERATING REVENUES BY CUSTOMER CLASS (Details) - Revenues from contracts with customers - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 2,376.5	$ 2,290
Electric
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,061.8	1,067.7
Wisconsin | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,626.7	1,585.7
Wisconsin | Electric | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,061.8	1,067.7
Wisconsin | Electric | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	960.7	926.6
Wisconsin | Electric | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	406.7	384.3
Wisconsin | Electric | Transferred over time | Small commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	333.9	330.7
Wisconsin | Electric | Transferred over time | Large commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	212.3	203.9
Wisconsin | Electric | Transferred over time | Other
Disaggregation of Operating Revenues
Revenues from contracts with customers	7.8	7.7
Wisconsin | Electric | Transferred over time | Wholesale
Disaggregation of Operating Revenues
Revenues from contracts with customers	47.7	54.9
Wisconsin | Electric | Transferred over time | Resale
Disaggregation of Operating Revenues
Revenues from contracts with customers	40.8	73.8
Wisconsin | Electric | Transferred over time | Steam
Disaggregation of Operating Revenues
Revenues from contracts with customers	10.1	9.7
Wisconsin | Electric | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 2.5	$ 2.7

OPERATING REVENUES - DISAGGRE_3

OPERATING REVENUES - DISAGGREGATION OF NATURAL GAS UTILITY OPERATING REVENUES BY CUSTOMER CLASS (Details) - Revenues from contracts with customers - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 2,376.5	$ 2,290
Natural gas
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,296.4	1,210.7
Natural gas | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,294.7	1,198.3
Natural gas | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,251	1,174.5
Natural gas | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	863.1	812.5
Natural gas | Transferred over time | Commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	387.9	362
Natural gas | Transferred over time | Transport
Disaggregation of Operating Revenues
Revenues from contracts with customers	120.2	108.6
Total Utility Operations | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	2,360.7	2,269.9
Total Utility Operations | Natural gas | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,294.7	1,198.3
Total Utility Operations | Natural gas | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	(76.5)	(84.8)
Wisconsin | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,626.7	1,585.7
Wisconsin | Natural gas | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	564.9	518
Wisconsin | Natural gas | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	583.6	544.6
Wisconsin | Natural gas | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	383.9	356.7
Wisconsin | Natural gas | Transferred over time | Commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	199.7	187.9
Wisconsin | Natural gas | Transferred over time | Transport
Disaggregation of Operating Revenues
Revenues from contracts with customers	21.9	21
Wisconsin | Natural gas | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	(40.6)	(47.6)
Illinois | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	544.7	507.6
Illinois | Natural gas | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	544.6	507.6
Illinois | Natural gas | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	470.2	442
Illinois | Natural gas | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	354	332.6
Illinois | Natural gas | Transferred over time | Commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	116.2	109.4
Illinois | Natural gas | Transferred over time | Transport
Disaggregation of Operating Revenues
Revenues from contracts with customers	87.2	77.7
Illinois | Natural gas | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	(12.8)	(12.1)
Other States | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	189.3	176.6
Other States | Natural gas | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	185.2	172.7
Other States | Natural gas | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	197.2	187.9
Other States | Natural gas | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	125.2	123.2
Other States | Natural gas | Transferred over time | Commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	72	64.7
Other States | Natural gas | Transferred over time | Transport
Disaggregation of Operating Revenues
Revenues from contracts with customers	11.1	9.9
Other States | Natural gas | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ (23.1)	$ (25.1)

OPERATING REVENUES - OTHER NON-

OPERATING REVENUES - OTHER NON-UTILITY OPERATING REVENUES (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
We Power revenues
Disaggregation of Operating Revenues
Revenues amortized from deferred revenue during the period	$ 6.4	$ 6.4
Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	2,376.5	2,290
Other non-utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	18.3	11.6
Other non-utility revenues | Revenues from contracts with customers | We Power revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	6.4	6.4
Other non-utility revenues | Revenues from contracts with customers | Distributed renewable solar project revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	1.5	1.3
Other non-utility revenues | Revenues from contracts with customers | Wind generation revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	6.2	0
Other non-utility revenues | Revenues from contracts with customers | Other
Disaggregation of Operating Revenues
Revenues from contracts with customers	0.1	0
Transferred over time | Other non-utility revenues | Revenues from contracts with customers | Appliance service repairs
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 4.1	$ 3.9
Upstream
Disaggregation of Operating Revenues
WEC's ownership interest in Upstream Wind Energy Center	80.00%
Number of years Upstream will receive fixed payment	10 years

OPERATING REVENUES - OTHER OPER

OPERATING REVENUES - OTHER OPERATING REVENUES (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Disaggregation of Operating Revenues
Operating revenues	$ 2,377.4	$ 2,286.5
Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	0.9	(3.5)
Other operating revenues | Alternative revenues
Disaggregation of Operating Revenues
Operating revenues	(19.7)	(16.1)
Other operating revenues | Late payment charges
Disaggregation of Operating Revenues
Operating revenues	13.2	11.4
Other operating revenues | Rental revenues
Disaggregation of Operating Revenues
Operating revenues	$ 7.4	$ 1.2

REGULATORY ASSETS AND LIABILI_3

REGULATORY ASSETS AND LIABILITIES - REGULATORY ASSETS (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Regulatory assets
Current assets	$ 27.3	$ 50.7
Regulatory assets	4,009.8	3,805.1
Total regulatory assets	4,037.1	3,855.8
Pension and OPEB costs
Regulatory assets
Total regulatory assets	1,173.8	1,193.5
Plant retirements
Regulatory assets
Total regulatory assets	1,027.9	832.3
Environmental remediation costs
Regulatory assets
Total regulatory assets	697.6	687.1
Income tax related items
Regulatory assets
Total regulatory assets	384.8	369.1
System support resource
Regulatory assets
Total regulatory assets	317.9	316.7
Asset retirement obligations
Regulatory assets
Total regulatory assets	223.4	185.4
Uncollectible expense
Regulatory assets
Total regulatory assets	47.6	38.7
Electric transmission costs
Regulatory assets
Total regulatory assets	41.7	58.1
We Power generation
Regulatory assets
Total regulatory assets	36.1	43
Energy efficiency programs
Regulatory assets
Total regulatory assets	11.3	14
Other, net
Regulatory assets
Total regulatory assets	$ 75	$ 117.9

REGULATORY ASSETS AND LIABILI_4

REGULATORY ASSETS AND LIABILITIES - REGULATORY LIABILITIES (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Regulatory liabilities
Current liabilities	$ 103.9	$ 36.8
Regulatory liabilities	4,274.3	4,251.6
Total regulatory liabilities	4,378.2	4,288.4
Income tax related items
Regulatory liabilities
Total regulatory liabilities	2,401.2	2,406.6
Removal costs
Regulatory liabilities
Total regulatory liabilities	1,330.8	1,329.6
Pension and OPEB costs
Regulatory liabilities
Total regulatory liabilities	235.7	238.3
Mines deferral
Regulatory liabilities
Total regulatory liabilities	129.1	120.8
Energy costs refundable through rate adjustments
Regulatory liabilities
Total regulatory liabilities	103	39.6
Decoupling
Regulatory liabilities
Total regulatory liabilities	51	30.5
Energy efficiency programs
Regulatory liabilities
Total regulatory liabilities	45.7	31.7
Earnings sharing mechanisms
Regulatory liabilities
Total regulatory liabilities	29.9	30
Uncollectible expense
Regulatory liabilities
Total regulatory liabilities	29.5	30.5
Derivatives
Regulatory liabilities
Total regulatory liabilities	9	16.4
Other, net
Regulatory liabilities
Total regulatory liabilities	$ 13.3	$ 14.4

PROPERTY, PLANT, AND EQUIPMEN_2

PROPERTY, PLANT, AND EQUIPMENT (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Property, plant, and equipment
Net book value of plant classified as a regulatory asset	$ 4,037.1	$ 3,855.8
Cost of removal reserve classified as a regulatory liability	4,378.2	$ 4,288.4
Presque Isle power plant
Property, plant, and equipment
Plant to be retired, at carrying value	172.1
Net book value of plant classified as a regulatory asset	183.1
Cost of removal reserve classified as a regulatory liability	11
Wisconsin
Changes to severance liability
Severance liability, balance at beginning of period	15.7
Severance payments	(1.7)
Severance liability, balance at end of period	$ 14

COMMON EQUITY - STOCK-BASED COM

COMMON EQUITY - STOCK-BASED COMPENSATION AWARDS GRANTED (Details)	3 Months Ended
	Mar. 31, 2019$ / sharesshares
Stock options
Stock-based Compensation
Stock options granted | shares	476,418
Stock options granted, weighted average exercise price | $ / shares	$ 68.18
Stock options granted, weighted-average grant date fair value | $ / shares	$ 8.60
Restricted shares
Stock-based Compensation
Awards granted | shares	73,571
Restricted shares granted, weighted-average grant date fair value | $ / shares	$ 68.18
Performance units
Stock-based Compensation
Awards granted | shares	148,036

COMMON EQUITY - COMMON STOCK DI

COMMON EQUITY - COMMON STOCK DIVIDENDS (Details) - $ / shares	3 Months Ended
	Jun. 30, 2019	Mar. 31, 2019	Mar. 31, 2018
Dividends Payable
Quarterly cash dividend declared (in dollars per share)		$ 0.59	$ 0.5525
Subsequent event
Dividends Payable
Quarterly cash dividend declared (in dollars per share)	$ 0.59

SHORT-TERM DEBT AND LINES OF _3

SHORT-TERM DEBT AND LINES OF CREDIT - SHORT-TERM BORROWINGS (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Short-term borrowings
Commercial paper outstanding	$ 1,145.2	$ 1,440.1
Commercial paper
Short-term borrowings
Commercial paper outstanding	$ 1,145.2	$ 1,440.1
Weighted-average interest rate on amounts outstanding	2.75%	2.92%
Average amount outstanding during the period	$ 1,487
Weighted-average interest rate during the period	2.81%

SHORT-TERM DEBT AND LINES OF _4

SHORT-TERM DEBT AND LINES OF CREDIT - REVOLVING CREDIT FACILITIES (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Revolving credit facilities
Short-term credit capacity	$ 2,800
Letters of credit issued inside credit facilities	3
Commercial paper outstanding	1,145.2	$ 1,440.1
Available capacity under existing agreements	1,651.8
WEC Energy Group | Credit facility maturing during October 2022
Revolving credit facilities
Short-term credit capacity	1,200
WE | Credit facility maturing during October 2022
Revolving credit facilities
Short-term credit capacity	500
WPS | Credit facility maturing during October 2022
Revolving credit facilities
Short-term credit capacity	400
WG | Credit facility maturing during October 2022
Revolving credit facilities
Short-term credit capacity	350
PGL | Credit facility maturing during October 2022
Revolving credit facilities
Short-term credit capacity	$ 350

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details) - WEC Energy Group - WEC Senior Notes due 2022 $ in Millions	3 Months Ended
	Mar. 31, 2019USD ($)
Debt Instrument [Line Items]
Proceeds from Issuance of Debt	$ 350
Debt instrument stated interest rate percentage	3.10%

LEASES - ADOPTION OF ASU 2016-0

LEASES - ADOPTION OF ASU 2016-02 (Details) $ in Millions	1 Months Ended
	Jan. 31, 2019USD ($)	Mar. 31, 2019USD ($)	Jan. 01, 2019USD ($)land_easement
Leases [Abstract]
Impairment losses recorded upon adoption of ASU 2016-02	$ 0
Number of land easements treated as leases upon adoption of ASU 2016-02 | land_easement			0
Operating lease right of use assets		$ 48.2	$ 49
Operating lease liabilities		$ 47.8	$ 48.8
Finance lease expense impact of adoption of ASU 2016-02	$ 0

LEASES - OBLIGATIONS UNDER FINA

LEASES - OBLIGATIONS UNDER FINANCE LEASE (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019USD ($)MW	Dec. 31, 2009USD ($)
Leases [Abstract]
Power purchase contract period	25 years
Firm capacity from power purchase contract (in megawatts) | MW	236
Minimum energy requirements over remaining term of power purchase contract (in megawatts) | MW	0
Power purchase contract renewal period	10 years
Maximum regulatory asset for power purchase contract		$ 78.5
Regulatory asset at end of life of power purchase contract	$ 0
Finance lease obligation	22.1
Finance lease obligation at end of life of power purchase contract	$ 0

LEASES - LEASE EXPENSE AND SUPP

LEASES - LEASE EXPENSE AND SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Lease expense
Operating lease expense	$ 1.4	$ 1.4
Short-term lease expense	0	0.1
Lease expense	3.4	3.4
Amortization of finance lease right of use assets	1.1
Interest on finance lease liabilities	0.9
Other information
Operating cash flows from finance/capital lease	0.9	1.9
Operating cash flows from operating leases	1.7	1.7
Financing cash flows from finance lease	1.2	0
Noncash activity - right of use assets obtained in exchange for new operating lease liabilities	$ 49
Remaining lease term - finance lease	3 years 2 months
Weighted average remaining lease term - operating leases	13 years 2 months
Discount rate - finance lease	15.80%
Weighted average discount rate - operating leases	4.60%
Finance and capital leases
Lease expense
Lease expense	$ 2	$ 1.9

LEASES - RIGHT OF USE ASSETS (D

LEASES - RIGHT OF USE ASSETS (Details) - USD ($) $ in Millions	Mar. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Right of use assets
Operating lease right of use assets	$ 48.2	$ 49
Finance lease
Right of use assets
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		$ 19.4

LEASES - FUTURE MINIMUM LEASE P

LEASES - FUTURE MINIMUM LEASE PAYMENTS (Details) - USD ($) $ in Millions	Mar. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Total operating leases
Nine months ended December 31, 2019	$ 4.5
2020	7.1
2021	5.1
2022	5.1
2023	5.2
2024	5.1
Thereafter	33
Total minimum lease payments	65.1
Less: interest	(17.3)
Present value of minimum lease payments	47.8	$ 48.8
Less: short-term lease liabilities	(4.1)
Long-term lease liabilities	43.7
Power purchase commitment
Nine months ended December 31, 2019	6.2
2020	8.8
2021	9.4
2022	4.2
2023	0
2024	0
Thereafter	0
Total minimum lease payments	28.6
Less: interest	(6.5)
Present value of minimum lease payments	22.1
Less: short-term lease liabilities	(5.2)
Long-term lease liabilities	$ 16.9
Capital lease
Short-term liabilities under capital lease			$ 4.9
Long-term liabilities under capital lease			$ 18.4

MATERIALS, SUPPLIES, AND INVE_3

MATERIALS, SUPPLIES, AND INVENTORIES (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Energy Related Inventory
Materials and supplies	$ 230.7	$ 226.6
Fossil fuel	60.4	88.7
Natural gas in storage	39	232.9
Total	330.1	$ 548.2
LIFO Method Related Items
LIFO liquidation credit	$ 40.2

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Effective Income Tax Rate Reconciliation, Amount
Statutory federal income tax, amount	$ 101.9	$ 100.5
State income taxes net of federal tax benefit, amount	31	29.9
Tax repairs, amount	(29.6)	(25.5)
Wind production tax credit, amount	(13.4)	(3.8)
Federal excess deferred tax amortization, amount	(13.2)	(15.5)
Excess tax benefits-stock options, amount	(7.2)	(0.9)
Other, amount	(4.5)	3.6
Total income tax expense, amount	$ 65	$ 88.3
Effective Income Tax Rate Reconciliation, Percent
Statutory federal income tax, percentage	21.00%	21.00%
State income taxes net of federal tax benefit, percentage	6.40%	6.20%
Tax repairs, percentage	(6.10%)	(5.30%)
Wind production tax credits, percent	(2.80%)	(0.80%)
Federal excess deferred tax amortization, percentage	(2.70%)	(3.20%)
Excess tax benefits-stock options, percent	(1.50%)	(0.20%)
Other, percentage	(0.90%)	0.70%
Total income tax expense, percentage	13.40%	18.40%

FAIR VALUE MEASUREMENTS - ASSET

FAIR VALUE MEASUREMENTS - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Assets
Derivative asset	$ 10.3	$ 15.9
Liabilities
Derivative liability	4.7	7.9
Fair value measurements on a recurring basis
Assets
Derivative asset	10.3	15.9
Investments held in rabbi trust	74	65
Liabilities
Derivative liability	4.7	7.9
Fair value measurements on a recurring basis | Level 1
Assets
Derivative asset	6	6.3
Investments held in rabbi trust	74	65
Liabilities
Derivative liability	0.9	4.7
Fair value measurements on a recurring basis | Level 2
Assets
Derivative asset	1.2	2.2
Investments held in rabbi trust	0	0
Liabilities
Derivative liability	3.8	3.2
Fair value measurements on a recurring basis | Level 3
Assets
Derivative asset	3.1	7.4
Investments held in rabbi trust	0	0
Liabilities
Derivative liability	0	0
Fair value measurements on a recurring basis | Natural gas contracts
Assets
Derivative asset	6	8.1
Liabilities
Derivative liability	0.9	5.5
Fair value measurements on a recurring basis | Natural gas contracts | Level 1
Assets
Derivative asset	6	6.3
Liabilities
Derivative liability	0.9	4.7
Fair value measurements on a recurring basis | Natural gas contracts | Level 2
Assets
Derivative asset	0	1.8
Liabilities
Derivative liability	0	0.8
Fair value measurements on a recurring basis | Natural gas contracts | Level 3
Assets
Derivative asset	0	0
Liabilities
Derivative liability	0	0
Fair value measurements on a recurring basis | FTRs
Assets
Derivative asset	3.1	7.4
Fair value measurements on a recurring basis | FTRs | Level 1
Assets
Derivative asset	0	0
Fair value measurements on a recurring basis | FTRs | Level 2
Assets
Derivative asset	0	0
Fair value measurements on a recurring basis | FTRs | Level 3
Assets
Derivative asset	3.1	7.4
Fair value measurements on a recurring basis | Coal contracts
Assets
Derivative asset	1.2	0.4
Liabilities
Derivative liability	0.1	0.1
Fair value measurements on a recurring basis | Coal contracts | Level 1
Assets
Derivative asset	0	0
Liabilities
Derivative liability	0	0
Fair value measurements on a recurring basis | Coal contracts | Level 2
Assets
Derivative asset	1.2	0.4
Liabilities
Derivative liability	0.1	0.1
Fair value measurements on a recurring basis | Coal contracts | Level 3
Assets
Derivative asset	0	0
Liabilities
Derivative liability	0	0
Fair value measurements on a recurring basis | Interest rate swaps
Liabilities
Derivative liability	3.7	2.3
Fair value measurements on a recurring basis | Interest rate swaps | Level 1
Liabilities
Derivative liability	0	0
Fair value measurements on a recurring basis | Interest rate swaps | Level 2
Liabilities
Derivative liability	3.7	2.3
Fair value measurements on a recurring basis | Interest rate swaps | Level 3
Liabilities
Derivative liability	$ 0	$ 0

FAIR VALUE MEASUREMENTS - UNREA

FAIR VALUE MEASUREMENTS - UNREALIZED GAIN (LOSS) ON INVESTMENTS (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Fair Value Disclosures [Abstract]
Net unrealized gains (losses) included in earnings related to investments held in rabbi trust	$ 8.6	$ (3.1)

FAIR VALUE MEASUREMENTS - LEVEL

FAIR VALUE MEASUREMENTS - LEVEL 3 RECONCILIATION (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Balance at the beginning of the period	$ 7.4	$ 4.4
Settlements	(4.3)	(2.9)
Balance at the end of period	$ 3.1	$ 1.5

FAIR VALUE MEASUREMENTS - FINAN

FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Financial Instruments
Preferred stock	$ 30.4	$ 30.4
Finance lease obligation	22.1
Carrying Amount
Financial Instruments
Preferred stock	30.4	30.4
Long-term debt, including current portion	10,670.6	10,335.7
Capital lease obligations		23.3
Finance lease obligation	22.1
Fair Value
Financial Instruments
Preferred stock	28.3	28.3
Long-term debt, including current portion	$ 11,257.5	$ 10,554.9

DERIVATIVE INSTRUMENTS - DERIVA

DERIVATIVE INSTRUMENTS - DERIVATIVE ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Derivative Asset
Other current derivative assets	$ 9.2	$ 15.3
Other long-term derivative assets	1.1	0.6
Derivative asset	10.3	15.9
Derivative Liability
Other current derivative liabilities	1.7	5.8
Other long-term derivative liabilities	3	2.1
Derivative liability	4.7	7.9
Natural gas contracts
Derivative Asset
Other current derivative assets	5.1	7.7
Other long-term derivative assets	0.9	0.4
Derivative Liability
Other current derivative liabilities	0.9	5.3
Other long-term derivative liabilities	0	0.2
FTRs
Derivative Asset
Other current derivative assets	3.1	7.4
Derivative Liability
Other current derivative liabilities	0	0
Coal contracts
Derivative Asset
Other current derivative assets	1	0.2
Other long-term derivative assets	0.2	0.2
Derivative Liability
Other current derivative liabilities	0.1	0.1
Other long-term derivative liabilities	0	0
Interest rate swaps
Derivative Asset
Other current derivative assets	0	0
Other long-term derivative assets	0	0
Derivative Liability
Other current derivative liabilities	0.7	0.4
Other long-term derivative liabilities	$ 3	$ 1.9

DERIVATIVE INSTRUMENTS - GAINS

DERIVATIVE INSTRUMENTS - GAINS (LOSSES) AND NOTIONAL VOLUMES (Details) gal in Millions, MWh in Millions, MMBTU in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2019USD ($)MMBTUMWhgal	Mar. 31, 2018USD ($)MMBTUMWhgal
Realized Gain (Loss) on Derivatives, Net
Gains (Losses)	$ 1.8	$ (1)
Natural gas contracts
Realized Gain (Loss) on Derivatives, Net
Gains (Losses)	$ (0.5)	$ (5.2)
Notional Sales Volumes
Notional sales volumes | MMBTU	56.1	48.1
Petroleum products contracts
Realized Gain (Loss) on Derivatives, Net
Gains (Losses)	$ 0	$ 0.5
Notional Sales Volumes
Notional sales volumes (gallons) | gal	0	2.1
FTRs
Realized Gain (Loss) on Derivatives, Net
Gains (Losses)	$ 2.3	$ 3.7
Notional Sales Volumes
Notional sales volumes | MWh	8.1	8.2

DERIVATIVE INSTRUMENTS - BALANC

DERIVATIVE INSTRUMENTS - BALANCE SHEET OFFSETTING (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Cash collateral
Cash collateral in margin account	$ 3	$ 2.7
Cash collateral received in margin account		0.2
Offsetting Derivative Assets
Gross amount recognized on the balance sheet	10.3	15.9
Gross amount not offset on the balance sheet	(0.9)	(4)
Net amount	9.4	11.9
Collateral received		0.2
Offsetting Derivative Liabilities
Gross amount recognized on the balance sheet	4.7	7.9
Gross amount not offset on the balance sheet	(0.9)	(4.9)
Net amount	$ 3.8	3
Collateral posted		$ 1.1

DERIVATIVE INSTRUMENTS - CASH F

DERIVATIVE INSTRUMENTS - CASH FLOW HEDGES (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019USD ($)number_of_interest_rate_swaps	Mar. 31, 2018USD ($)
Derivative [Line Items]
Interest expense	$ 124.4	$ 106.7
Interest rate swaps
Derivative [Line Items]
Amount to be reclassified from accumulated OCI to interest expense	1.5
WEC Energy Group | WEC 2007 Junior Notes due 2067
Derivative [Line Items]
Long-term debt outstanding	$ 500
WEC Energy Group | Interest rate swaps
Derivative [Line Items]
Number of interest rate swaps executed | number_of_interest_rate_swaps	2
Interest rate swap notional value	$ 250
Interest rate swap fixed interest rate	4.9765%
Derivative losses recognized in OCI	$ (1.6)	0
Net derivative gains reclassified from accumulated OCI to interest expense	$ 0.4	$ 0.6

GUARANTEES (Details)

GUARANTEES (Details) $ in Millions	Mar. 31, 2019USD ($)
Guarantees
Total guarantees	$ 130.1
Guarantees expiring in less than 1 year	21.7
Guarantees expiring within 1 to 3 years	2.3
Guarantees with expiration over 3 years	106.1
Guarantees supporting commodity transactions of subsidiaries
Guarantees
Total guarantees	7.1
Guarantees expiring in less than 1 year	7.1
Guarantees expiring within 1 to 3 years	0
Guarantees with expiration over 3 years	0
Standby letters of credit
Guarantees
Total guarantees	102.8
Guarantees expiring in less than 1 year	5.7
Guarantees expiring within 1 to 3 years	1.1
Guarantees with expiration over 3 years	96
Surety bonds
Guarantees
Total guarantees	9.2
Guarantees expiring in less than 1 year	8.9
Guarantees expiring within 1 to 3 years	0.3
Guarantees with expiration over 3 years	0
Other guarantees
Guarantees
Total guarantees	11
Guarantees expiring in less than 1 year	0
Guarantees expiring within 1 to 3 years	0.9
Guarantees with expiration over 3 years	10.1
Other indemnifications
Guarantees
Total guarantees	11
Liability related to workers compensation coverage	10.1
Bluewater | Guarantees supporting commodity transactions of subsidiaries
Guarantees
Total guarantees	5.6
UMERC | Guarantees supporting commodity transactions of subsidiaries
Guarantees
Total guarantees	$ 1.5

EMPLOYEE BENEFITS-COSTS AND CON

EMPLOYEE BENEFITS-COSTS AND CONTRIBUTIONS (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Components of net periodic benefit cost
Contributions and payments related to pension and OPEB plans	$ 4.2	$ 5.3
Pension Costs
Components of net periodic benefit cost
Service cost	11.3	12
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 (credit) cost	0.6	0.7
Amortization of net actuarial loss	19	23.1
Net periodic benefit (credit) cost	13.6	14.9
Contributions and payments related to pension and OPEB plans	3.6
Estimated future employer contributions for the remainder of the year	8.4
Other Postretirement Benefit Costs
Components of net periodic benefit cost
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) cost	(3.9)	(3.8)
Amortization of net actuarial loss	(0.7)	0.3
Net periodic benefit (credit) cost	(7.4)	$ (4.7)
Contributions and payments related to pension and OPEB plans	0.6
Estimated future employer contributions for the remainder of the year	$ 6.1

GOODWILL (Details)

GOODWILL (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019USD ($)
Goodwill
Changes to the carrying amount of goodwill	$ 0
Changes to our goodwill balances by segment
Goodwill balance by segment	3,052.8
Accumulated impairment losses	0
Wisconsin
Changes to our goodwill balances by segment
Goodwill balance by segment	2,104.3
Illinois
Changes to our goodwill balances by segment
Goodwill balance by segment	758.7
Other States
Changes to our goodwill balances by segment
Goodwill balance by segment	183.2
Non-Utility Energy Infrastructure
Changes to our goodwill balances by segment
Goodwill balance by segment	$ 6.6

INVESTMENT IN TRANSMISSION AF_3

INVESTMENT IN TRANSMISSION AFFILIATES - CHANGES TO INVESTMENTS (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2017
Changes to investments in transmission affiliates
Investment in transmission affiliates, balance at beginning of period	$ 1,665.3	$ 1,553.4
Add: Earnings (loss) from equity method investment	36.1	32.8
Add: Capital contributions	3.4	12.8
Less: Distributions	34.2
Less: Other		0.1
Investment in transmission affiliates, balance at end of period	$ 1,670.6	1,598.9
ATC
Investment in transmission affiliates
Equity method investment, ownership interest (as a percent)	60.00%
Changes to investments in transmission affiliates
Investment in transmission affiliates, balance at beginning of period	$ 1,625.3	1,515.8
Add: Earnings (loss) from equity method investment	36.5	33.4
Add: Capital contributions	3	12
Less: Distributions	34.2
Less: Other		0.1
Investment in transmission affiliates, balance at end of period	$ 1,630.6	1,561.1
Dividends receivable from ATC			$ 39.9
ATC Holdco
Investment in transmission affiliates
Equity method investment, ownership interest (as a percent)	75.00%
Changes to investments in transmission affiliates
Investment in transmission affiliates, balance at beginning of period	$ 40	37.6
Add: Earnings (loss) from equity method investment	(0.4)	(0.6)
Add: Capital contributions	0.4	0.8
Less: Distributions	0
Less: Other		0
Investment in transmission affiliates, balance at end of period	$ 40	$ 37.8

INVESTMENT IN TRANSMISSION AF_4

INVESTMENT IN TRANSMISSION AFFILIATES - RELATED PARTY TRANSACTIONS (Details) - ATC - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Investment in transmission affiliates
Construction costs to be reimbursed to UMERC	$ 32.4		$ 29.4
Charges to ATC for services and construction	4	$ 4.6
Charges from ATC for network transmission services	$ 87.1	$ 84.5

INVESTMENT IN TRANSMISSION AF_5

INVESTMENT IN TRANSMISSION AFFILIATES - RELATED PARTY TRANSACTIONS BALANCE SHEET INFORMATION (Details) - ATC - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Investment in transmission affiliates
Accounts receivable for services provided to ATC	$ 2	$ 3.4
Accounts payable for services received from ATC	$ 29	$ 28.2

INVESTMENT IN TRANSMISSION AF_6

INVESTMENT IN TRANSMISSION AFFILIATES - SUMMARIZED FINANCIAL DATA (Details) - ATC - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 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
Balance sheet data
Current assets	87.8		$ 87.2
Noncurrent assets	5,012.7		4,928.8
Total assets	5,100.5		5,016
Current liabilities	571.1		640
Long-term debt	2,164.1		2,014
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

SEGMENT INFORMATION (Details)

SEGMENT INFORMATION (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019USD ($)segment	Mar. 31, 2018USD ($)
Segment information
Number of reportable segments | segment	6
WEC's ownership interest in Bishop Hill III Wind Energy Center	80.00%
Operating revenues	$ 2,377.4	$ 2,286.5
Other operation and maintenance	550.6	511.9
Depreciation and amortization	226.4	208.6
Operating income (loss)	542.8	545.1
Equity in earnings of transmission affiliates	36.1	32.8
Interest expense	124.4	106.7
Wisconsin
Segment information
Operating revenues	1,633.4	1,589.1
Illinois
Segment information
Operating revenues	536.5	507.3
Other States
Segment information
Operating revenues	185.2	169.9
Electric Transmission
Segment information
Other operation and maintenance	0	0
Depreciation and amortization	0	0
Operating income (loss)	0	0
Equity in earnings of transmission affiliates	36.1	32.8
Interest expense	$ 2.6	0
Non-Utility Energy Infrastructure
Segment information
Natural gas storage needs provided to Wisconsin utilities	33.00%
Operating revenues	$ 127.8	118.1
Other operation and maintenance	3.8	1.7
Depreciation and amortization	22.6	18.3
Operating income (loss)	92.7	93
Equity in earnings of transmission affiliates	0	0
Interest expense	15.7	16.1
Corporate and Other
Segment information
Operating revenues	1.7	1.4
Other operation and maintenance	(1)	(0.3)
Depreciation and amortization	6.4	7.7
Operating income (loss)	(3.9)	(5.4)
Equity in earnings of transmission affiliates	0	0
Interest expense	35.1	28
Reconciling Eliminations
Segment information
Other operation and maintenance	(0.7)	(96.8)
Depreciation and amortization	(4.6)	0
Operating income (loss)	(87.2)	0
Equity in earnings of transmission affiliates	0	0
Interest expense	$ (89.5)	(1.2)
ATC | Electric Transmission
Segment information
Equity method investment, ownership interest (as a percent)	60.00%
ATC Holdco
Segment information
Equity method investment, ownership interest (as a percent)	75.00%
Equity in earnings of transmission affiliates	$ (0.4)	(0.6)
ATC Holdco | Electric Transmission
Segment information
Equity method investment, ownership interest (as a percent)	75.00%
Bishop Hill III Wind Energy Center | Non-Utility Energy Infrastructure
Segment information
WEC's ownership interest in Bishop Hill III Wind Energy Center	90.00%
Coyote Ridge Wind | Non-Utility Energy Infrastructure
Segment information
WEC's ownership interest in Coyote Ridge Wind, LLC	80.00%
Upstream
Segment information
WEC's ownership interest in Upstream Wind Energy Center	80.00%
Upstream | Non-Utility Energy Infrastructure
Segment information
WEC's ownership interest in Upstream Wind Energy Center	80.00%
Total utility revenues
Segment information
Other operation and maintenance	$ 548.5	607.3
Depreciation and amortization	202	182.6
Operating income (loss)	541.2	457.5
Equity in earnings of transmission affiliates	0	0
Interest expense	160.5	63.8
Total utility revenues | Wisconsin
Segment information
Other operation and maintenance	392.7	468.5
Depreciation and amortization	151	135.1
Operating income (loss)	361.8	273.7
Equity in earnings of transmission affiliates	0	0
Interest expense	143.4	49.4
Total utility revenues | Illinois
Segment information
Other operation and maintenance	128.2	112.2
Depreciation and amortization	44.5	40.9
Operating income (loss)	137.9	147.6
Equity in earnings of transmission affiliates	0	0
Interest expense	14.8	12.3
Total utility revenues | Other States
Segment information
Other operation and maintenance	27.6	26.6
Depreciation and amortization	6.5	6.6
Operating income (loss)	41.5	36.2
Equity in earnings of transmission affiliates	0	0
Interest expense	2.3	2.1
External Revenues
Segment information
Operating revenues	2,377.4	2,286.5
External Revenues | Electric Transmission
Segment information
Operating revenues	0	0
External Revenues | Non-Utility Energy Infrastructure
Segment information
Operating revenues	20.6	18.8
External Revenues | Corporate and Other
Segment information
Operating revenues	1.7	1.4
External Revenues | Reconciling Eliminations
Segment information
Operating revenues	0	0
External Revenues | Total utility revenues
Segment information
Operating revenues	2,355.1	2,266.3
External Revenues | Total utility revenues | Wisconsin
Segment information
Operating revenues	1,633.4	1,589.1
External Revenues | Total utility revenues | Illinois
Segment information
Operating revenues	536.5	507.3
External Revenues | Total utility revenues | Other States
Segment information
Operating revenues	185.2	169.9
Intersegment Transactions [Member]
Segment information
Operating revenues	0	0
Intersegment Transactions [Member] | Electric Transmission
Segment information
Operating revenues	0	0
Intersegment Transactions [Member] | Non-Utility Energy Infrastructure
Segment information
Operating revenues	107.2	99.3
Intersegment Transactions [Member] | Corporate and Other
Segment information
Operating revenues	0	0
Intersegment Transactions [Member] | Reconciling Eliminations
Segment information
Operating revenues	(107.2)	(99.3)
Intersegment Transactions [Member] | Total utility revenues
Segment information
Operating revenues	0	0
Intersegment Transactions [Member] | Total utility revenues | Wisconsin
Segment information
Operating revenues	0	0
Intersegment Transactions [Member] | Total utility revenues | Illinois
Segment information
Operating revenues	0	0
Intersegment Transactions [Member] | Total utility revenues | Other States
Segment information
Operating revenues	$ 0	$ 0

VARIABLE INTEREST ENTITIES (Det

VARIABLE INTEREST ENTITIES (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019USD ($)MW	Dec. 31, 2018USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Variable interest entities
Equity investment	$ 1,670.6	$ 1,665.3	$ 1,598.9	$ 1,553.4
Firm capacity from purchased power agreement (in megawatts) | MW	236
Minimum energy requirements over remaining term of purchased power agreement (in megawatts) | MW	0
ATC
Variable interest entities
Ownership interest (as a percent)	60.00%
Equity investment	$ 1,630.6	1,625.3
Construction costs to be reimbursed to UMERC	32.4	29.4
Accounts payable due to ATC	$ 29	$ 28.2
ATC Holdco
Variable interest entities
Ownership interest (as a percent)	75.00%
Equity investment	$ 40
Purchased power agreement
Variable interest entities
Firm capacity from purchased power agreement (in megawatts) | MW	236
Minimum energy requirements over remaining term of purchased power agreement (in megawatts) | MW	0
Remaining term of purchased power agreement (in years)	3 years
Residual guarantee associated with purchased power agreement	$ 0
Required payments over remaining term of purchased power agreement	$ 28.6

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Millions	Mar. 31, 2019USD ($)
Minimum future commitments for purchase obligations
Purchase obligations	$ 11,893.7

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) T in Millions, $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2019USD ($)generating_unitschangedegreecelsiusMW	Dec. 31, 2018USD ($)T
Manufactured gas plant remediation
Regulatory assets	$ 4,037.1	$ 3,855.8
Environmental remediation costs
Manufactured gas plant remediation
Regulatory assets	$ 697.6	$ 687.1
Mercury and Air Toxics Standards
Air quality
Revisions to Mercury and Air Toxics Standards | change	0
Climate Change | Electric
Air quality
Company goal for percentage of carbon dioxide emissions reduction	40.00%
Long-term company goal for percentage of carbon dioxide emissions reduction by 2050	80.00%
Capacity of coal generation retired since the beginning of 2018 | MW	1,800
Carbon dioxide emissions | T		26.4
Climate Change | Electric | Maximum
Air quality
Global temperature increases limit | degreecelsius	2
Climate Change | Natural gas
Air quality
Carbon dioxide emissions | T		29.4
Steam Electric Effluent Limitation Guidelines | Electric
Water quality
Number of generating units of OCPP and ERGS | generating_units	6
Expected cost to achieve required emissions reductions	$ 70
Manufactured Gas Plant Remediation | Natural gas
Manufactured gas plant remediation
Reserves for future remediation	631.8	$ 616.4
Manufactured Gas Plant Remediation | Natural gas | Environmental remediation costs
Manufactured gas plant remediation
Regulatory assets	$ 697.6	$ 687.1

SUPPLEMENTAL CASH FLOW INFORM_3

SUPPLEMENTAL CASH FLOW INFORMATION - SUPPLEMENTAL INFORMATION (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Supplemental cash flow information
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

SUPPLEMENTAL CASH FLOW INFORM_4

SUPPLEMENTAL CASH FLOW INFORMATION - RECONCILIATION OF CASH AND CASH EQUIVALENTS AND RESTRICTED CASH (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2017
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
Cash and cash equivalents	$ 30.6	$ 84.5	$ 48.1
Restricted cash included in other current assets	2.4		0
Restricted cash included in other long term assets	56.1		23.6
Cash, cash equivalents, and restricted cash	$ 89.1	$ 146.1	$ 71.7	$ 58.6

REGULATORY ENVIRONMENT (Details

REGULATORY ENVIRONMENT (Details) $ in Millions	1 Months Ended							3 Months Ended
	Mar. 31, 2019USD ($)Assurancecompany	Dec. 31, 2018USD ($)	Apr. 30, 2018USD ($)	Mar. 31, 2018USD ($)	Feb. 28, 2018Filings	Nov. 30, 2017USD ($)	Sep. 30, 2017USD ($)utility	Mar. 31, 2019USD ($)Assurance	Mar. 31, 2018USD ($)	May 31, 2018USD ($)solar_projectsMW
Regulatory environment
Capital investments related to gas utility infrastructure								$ 358.8	$ 439.6
Operation and maintenance expenses related to gas utility infrastructure								550.6	$ 511.9
WE | Public Service Commission of Wisconsin (PSCW) | 2020 rates | Electric rates
Regulatory environment
Requested rate increase	$ 83
Requested rate increase (as a percent)	2.90%
WE | Public Service Commission of Wisconsin (PSCW) | 2020 rates | Natural gas rates
Regulatory environment
Requested rate increase	$ 15
Requested rate increase (as a percent)	3.90%
WE | Public Service Commission of Wisconsin (PSCW) | 2020 rates | Steam rates
Regulatory environment
Requested rate increase	$ 1
Requested rate increase (as a percent)	4.50%
WE | Public Service Commission of Wisconsin (PSCW) | 2021 rates | Electric rates
Regulatory environment
Requested rate increase	$ 83
Requested rate increase (as a percent)	2.90%
WE | Public Service Commission of Wisconsin (PSCW) | 2020 and 2021 rates
Regulatory environment
Requested return on equity (as a percent)	10.35%
WE | Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates
Regulatory environment
Approved return on equity (as a percent)							10.20%
Income statement impact of flow through of repair-related deferred tax liabilities								$ 0
WG | Public Service Commission of Wisconsin (PSCW) | 2020 rates | Natural gas rates
Regulatory environment
Requested rate increase	$ 11
Requested rate increase (as a percent)	1.80%
WG | Public Service Commission of Wisconsin (PSCW) | 2020 and 2021 rates
Regulatory environment
Requested return on equity (as a percent)	10.30%
WG | Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates
Regulatory environment
Approved return on equity (as a percent)							10.30%
WPS | Public Service Commission of Wisconsin (PSCW) | Badger Hollow Solar Farm and Two Creeks Solar Project
Regulatory environment
Number of solar projects for which approval has been requested | solar_projects										2
Total output of two solar projects owned by WPS (in megawatts) | MW										200
WPS share of cost for certain solar projects										$ 260
WPS | Public Service Commission of Wisconsin (PSCW) | Two Creeks Solar Project
Regulatory environment
Solar project output owned by WPS (in megawatts) | MW										100
WPS | Public Service Commission of Wisconsin (PSCW) | Badger Hollow Solar Farm
Regulatory environment
Solar project output owned by WPS (in megawatts) | MW										100
WPS | Public Service Commission of Wisconsin (PSCW) | 2020 rates | Electric rates
Regulatory environment
Requested rate increase	$ 49
Requested rate increase (as a percent)	4.90%
WPS | Public Service Commission of Wisconsin (PSCW) | 2020 rates | Natural gas rates
Regulatory environment
Requested rate increase	$ 7
Requested rate increase (as a percent)	2.40%
WPS | Public Service Commission of Wisconsin (PSCW) | 2021 rates | Electric rates
Regulatory environment
Requested rate increase	$ 49
Requested rate increase (as a percent)	4.90%
WPS | Public Service Commission of Wisconsin (PSCW) | 2021 rates | Natural gas rates
Regulatory environment
Requested rate increase	$ 7
Requested rate increase (as a percent)	2.40%
WPS | Public Service Commission of Wisconsin (PSCW) | 2020 and 2021 rates
Regulatory environment
Requested return on equity (as a percent)	10.35%
WPS | Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates
Regulatory environment
Approved return on equity (as a percent)							10.00%
Authorized revenue requirement for the ReACT project							$ 275
AFUDC							51
Estimated cost of the ReACT project, excluding AFUDC							$ 342
WE, WG, and WPS | Public Service Commission of Wisconsin (PSCW) | 2020 and 2021 rates
Regulatory environment
Number of companies filing rate increase request | company	3
Requested common equity component average (as a percent)	52.00%
WE, WG, and WPS | Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates
Regulatory environment
Number of utilities with earnings sharing mechanism | utility							3
Percentage of first 50 basis points of additional utility earnings shared with customers							50.00%
Return on equity in excess of authorized amount (as a percent)							0.50%
PGL | Illinois Commerce Commission (ICC)
Regulatory environment
Amount of assurance that PGL's QIP rider costs will be recoverable | Assurance	0							0
MERC | Minnesota Public Utilities Commission (MPUC) | Gas utility infrastructure costs
Regulatory environment
Capital investments related to gas utility infrastructure			$ 12
Operation and maintenance expenses related to gas utility infrastructure			$ 3
MERC | Minnesota Public Utilities Commission (MPUC) | 2018 rates | Natural gas rates
Regulatory environment
Change in regulatory liabilities								$ 6.7
Approved return on equity (as a percent)		9.70%
Interim rate increase				$ 7		$ 9.5
Interim rate increase (as a percent)				2.81%		3.78%
Interim rate reduction				$ 2.5
Interim rates return on equity (as a percent)				9.11%
Interim rates common equity component average (as a percent)				50.90%
Approved rate increase		$ 3.1
Approved rate increase (as a percent)		1.26%
Approved common equity component average (as a percent)		50.90%
MGU and UMERC | Michigan Public Service Commission (MPSC)
Regulatory environment
Number of filings required related to the Tax Cuts and Jobs Act of 2017 | Filings					3
Tax Cuts and Jobs Act of 2017 | WE | Public Service Commission of Wisconsin (PSCW) | 2020 and 2021 rates | Electric rates
Regulatory environment
Change in regulatory liabilities	$ 111
Tax Cuts and Jobs Act of 2017 | WPS | Public Service Commission of Wisconsin (PSCW) | 2020 rates | Natural gas rates
Regulatory environment
Change in regulatory liabilities	7
Tax Cuts and Jobs Act of 2017 | WPS | Public Service Commission of Wisconsin (PSCW) | 2020 and 2021 rates | Electric rates
Regulatory environment
Change in regulatory liabilities	$ 40