WEC Energy (WEC) 10-Q 7 May 20 2020 Q1 Quarterly report Financial data

COVER PAGE

COVER PAGE	3 Months Ended
	Mar. 31, 2020shares
Cover [Abstract]
Document type	10-Q
Document Quarterly Report	true
Document period end date	Mar. 31, 2020
Document Transition Report	false
Entity File Number	001-09057
Entity registrant name	WEC ENERGY GROUP, INC.
Entity Tax Identification Number	39-1391525
Entity Incorporation, State or Country Code	WI
Entity Address, Address Line One	231 West Michigan Street
Entity Address, Address Line Two	P.O. Box 1331
Entity Address, City or Town	Milwaukee
Entity Address, State or Province	WI
Entity Address, Postal Zip Code	53201
City Area Code	414
Local Phone Number	221-2345
Title of 12(b) Security	Common Stock, $.01 Par Value
Trading Symbol	WEC
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity filer category	Large Accelerated Filer
Small company	false
Emerging growth company	false
Entity Shell Company	false
Entity common stock, shares outstanding	315,434,531
Entity central index key	0000783325
Current fiscal year end date	--12-31
Document fiscal year focus	2020
Document fiscal period focus	Q1
Amendment flag	false

CONDENSED CONSOLIDATED INCOME S

CONDENSED CONSOLIDATED INCOME STATEMENTS - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Income Statement [Abstract]
Operating revenues	$ 2,108.6	$ 2,377.4
Operating expenses
Cost of sales	734.7	1,009.6
Other operation and maintenance	455.7	550.6
Depreciation and amortization	239.1	226.4
Property and revenue taxes	52.5	48
Total operating expenses	1,482	1,834.6
Operating income	626.6	542.8
Equity in earnings of transmission affiliates	39.8	36.1
Other income, net	5.6	30.9
Interest expense	129.4	124.4
Other expense	(84)	(57.4)
Income before income taxes	542.6	485.4
Income tax expense	90	65
Net income	452.6	420.4
Preferred stock dividends of subsidiary	0.3	0.3
Net loss attributed to noncontrolling interests	0.2	0
Net income attributed to common shareholders	$ 452.5	$ 420.1
Earnings per share
Basic (in dollars per share)	$ 1.43	$ 1.33
Diluted (in dollars per share)	$ 1.43	$ 1.33
Weighted average common shares outstanding
Basic (in shares)	315.4	315.5
Diluted (in shares)	316.7	316.7

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Statement of Other Comprehensive Income [Abstract]
Net income	$ 452.6	$ 420.4
Derivatives accounted for as cash flow hedges
Net derivative losses, net of tax benefits of $(1.3) and $(0.4), respectively	(3.4)	(1.2)
Reclassification of net loss (gains) to net income, net of tax	0.1	(0.3)
Cash flow hedges, net	(3.3)	(1.5)
Defined benefit plans
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax	0.3	0.1
Other comprehensive loss, net of tax	(3)	(1.4)
Comprehensive income	449.6	419
Preferred stock dividends of subsidiary	0.3	0.3
Comprehensive loss attributed to noncontrolling interests	0.2	0
Comprehensive income attributed to common shareholders	$ 449.5	$ 418.7

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Statement of Comprehensive Income [Abstract]
Net derivative losses, net of tax benefits of $(1.3) and $(0.4), respectively	$ (1.3)	$ (0.4)

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Current assets
Cash and cash equivalents	$ 15.4	$ 37.5
Accounts receivable and unbilled revenues, net of reserves of $164.8 and $140.0, respectively	1,176.9	1,176.5
Materials, supplies, and inventories	391.1	549.8
Prepayments	200	261.8
Other	61.9	68
Current assets	1,845.3	2,093.6
Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $9,042.3 and $8,878.7, respectively	23,797.1	23,620.1
Regulatory assets	3,566.1	3,506.7
Equity investment in transmission affiliates	1,717.7	1,720.8
Goodwill	3,052.8	3,052.8
Other	853.2	957.8
Long-term assets	32,986.9	32,858.2
Total assets	34,832.2	34,951.8
Current liabilities
Short-term Debt	827.2	830.8
Current portion of long-term debt	694.3	693.2
Accounts payable	597.9	908.1
Accrued payroll and benefits	128.6	199.8
Amounts refundable to customers	155.8	87.6
Other	443.9	463.2
Current liabilities	2,847.7	3,182.7
Long-term liabilities
Long-term debt	11,194.7	11,211
Deferred income taxes	3,870	3,769.3
Deferred revenue, net	428.5	497.1
Regulatory liabilities	3,987.1	3,992.8
Environmental remediation liabilities	589.4	589.2
Pension and OPEB obligations	324.2	326.2
Other	1,106	1,128.9
Long-term liabilities	21,499.9	21,514.5
Commitments and contingencies (Note 19)
Common shareholders' equity
Common stock – $0.01 par value; 325,000,000 shares authorized; 315,434,531 shares outstanding	3.2	3.2
Additional paid in capital	4,167.3	4,186.6
Retained earnings	6,180.7	5,927.7
Accumulated other comprehensive loss	(7.1)	(4.1)
Common shareholders' equity	10,344.1	10,113.4
Preferred stock of subsidiary	30.4	30.4
Noncontrolling interests	110.1	110.8
Total liabilities and equity	$ 34,832.2	$ 34,951.8

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Statement of Financial Position [Abstract]
Accounts receivable and unbilled revenues, reserves	$ 164.8	$ 140
Property, plant, and equipment, accumulated depreciation	$ 9,042.3	$ 8,878.7
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	315,434,531	315,434,531

CONDENSED CONSOLIDATED STATEM_3

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Operating activities
Net income	$ 452.6	$ 420.4
Reconciliation to cash provided by operating activities
Depreciation and amortization	239.1	226.4
Deferred income taxes and investment tax credits, net	92.1	17.2
Contributions and payments related to pension and OPEB plans	(3.7)	(4.2)
Change in –
Accounts receivable and unbilled revenues	(3.5)	(124.3)
Materials, supplies, and inventories	158.7	218.3
Other current assets	65.4	125.1
Accounts payable	(250.1)	(204.3)
Other current liabilities	(27.7)	54.6
Other, net	(32.4)	6.5
Net cash provided by operating activities	690.5	735.7
Investing activities
Capital expenditures	(496.1)	(358.8)
Acquisition of Upstream, net of cash and restricted cash acquired of $9.2	0	(268.2)
Capital contributions to transmission affiliates	(3)	(3.4)
Proceeds from the sale of assets	1.3	10.6
Proceeds from the sale of investments held in rabbi trust	17	0.1
Proceeds from cash surrender value of life insurance	8.3	8.5
Other, net	9.5	4.6
Net cash used in investing activities	(463)	(606.6)
Financing activities
Exercise of stock options	16	32.6
Purchase of common stock	(40.4)	(70.7)
Dividends paid on common stock	(199.5)	(186.2)
Issuance of long-term debt	0	350
Retirement of long-term debt	(14)	(13.3)
Issuance of short-term loan	340	0
Change in other short-term debt	(343.6)	(294.9)
Other, net	(2.6)	(3.6)
Net cash used in financing activities	(244.1)	(186.1)
Net change in cash, cash equivalents, and restricted cash	(16.6)	(57)
Cash, cash equivalents, and restricted cash at beginning of period	82.3	146.1
Cash, cash equivalents, and restricted cash at end of period	$ 65.7	$ 89.1

CONDENSED CONSOLIDATED STATEM_4

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) $ in Millions	3 Months Ended
	Mar. 31, 2019USD ($)
Upstream
Statement of cash flows
Cash and restricted cash acquired	$ 9.2

CONDENSED CONSOLIDATED STATEM_5

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 interests
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
Statements of equity
Net income attributed to common shareholders	420.1	420.1	0	0	420.1	0	0	0
Net loss attributed to noncontrolling interests	0
Other comprehensive 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
Balance at Dec. 31, 2019	10,254.6	10,113.4	3.2	4,186.6	5,927.7	(4.1)	30.4	110.8
Statements of equity
Net income attributed to common shareholders	452.5	452.5	0	0	452.5	0	0	0
Net loss attributed to noncontrolling interests	(0.2)	0	0	0	0	0	0	(0.2)
Other comprehensive loss	(3)	(3)	0	0	0	(3)	0	0
Common stock dividends	(199.5)	(199.5)	0	0	(199.5)	0	0	0
Exercise of stock options	16	16	0	16	0	0	0	0
Purchase of common stock	(40.4)	(40.4)	0	(40.4)	0	0	0	0
Distributions to noncontrolling interests	(0.5)	0	0	0	0	0	0	(0.5)
Stock-based compensation and other	5.1	5.1	0	5.1	0	0	0	0
Balance at Mar. 31, 2020	$ 10,484.6	$ 10,344.1	$ 3.2	$ 4,167.3	$ 6,180.7	$ (7.1)	$ 30.4	$ 110.1

CONDENSED CONSOLIDATED STATEM_6

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Parenthetical) - $ / shares	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Statement of Stockholders' Equity [Abstract]
Common stock dividend declared (in dollars per share)	$ 0.6325	$ 0.59

GENERAL INFORMATION

GENERAL INFORMATION	3 Months Ended
	Mar. 31, 2020
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, we consolidate our majority-owned subsidiaries and reflect noncontrolling interests for the portion of entities that we do not own as a component of consolidated equity separate from the equity attributable to our shareholders. The noncontrolling interests that we reported as equity on our balance sheets related to the minority interests at Bishop Hill III, Coyote Ridge, and Upstream held by third parties. See Note 2, Acquisitions, for more information on Upstream. 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 16, 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, 2019 . 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 , 2020 , are not necessarily indicative of expected results for 2020 due to seasonal variations and other factors, including the potential effects from the COVID-19 pandemic. 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, 2020
Business Combinations [Abstract]
ACQUISITIONS	ACQUISITIONS On January 1, 2018, we adopted ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (ASU 2017-01). The amendments in this update clarify the definition of a business and provide guidance on evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 also clarifies that transaction costs are capitalized in an asset acquisition but expensed in a business combination. Acquisition of Wind Generation Facilities in Nebraska In August 2019, WECI signed an agreement to acquire an 80% ownership interest in Thunderhead, a 300 MW wind generating facility under construction in Antelope and Wheeler counties in Nebraska, for a total investment of approximately $338 million . In February 2020, WECI agreed to acquire an additional 10% ownership interest in Thunderhead for $43 million . The project has an offtake agreement with an unaffiliated third party for all of the energy to be produced by the facility for 12 years . Under the Tax Legislation, WECI's investment in Thunderhead is expected to qualify for production tax credits and 100% bonus depreciation. The transaction was approved by FERC in April 2020 and commercial operation is expected to begin at the end of 2020, at which time the transaction is expected to close. Thunderhead will be included in the non-utility energy infrastructure segment. In January 2019, WECI completed the acquisition of an 80% ownership interest in Upstream, a commercially operational 202.5 MW wind generating facility, for $268.2 million , which included transaction costs and is net of cash and restricted cash acquired of $9.2 million . In April 2020, WECI completed the acquisition of an additional 10% ownership interest in Upstream for $31 million . Upstream is located in Antelope County, Nebraska and supplies energy to the Southwest Power Pool. Upstream's revenue will be substantially fixed over 10 years through an agreement with an unaffiliated third party. Under the Tax Legislation, WECI's investment in Upstream qualifies for production tax credits and 100% bonus depreciation. Upstream is included in the non-utility energy infrastructure segment. The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition of the initial 80% ownership interest in Upstream. (in millions) Current assets $ 1.5 Net property, plant, and equipment 341.6 Other long-term assets * 22.9 Current liabilities (4.6 ) Long-term liabilities (15.0 ) Noncontrolling interest (69.0 ) Total purchase price $ 277.4 * Includes $8.1 million of restricted cash. Acquisition of a Wind Energy Generation Facility in Illinois In January 2020, WECI signed an agreement to acquire an 80% ownership interest in Blooming Grove, a 250 MW wind generating facility under construction in McLean County, Illinois, for a total investment of approximately $345 million . In February 2020, WECI agreed to acquire an additional 10% ownership interest in Blooming Grove for $44 million . Blooming Grove has long-term offtake agreements for all the energy produced with affiliates of two investment grade multinational companies. Under the Tax Legislation, WECI's investment in Blooming Grove is expected to qualify for production tax credits and 100% bonus depreciation. The transaction is subject to FERC approval and commercial operation is expected to begin by the end of 2020, at which time the transaction is expected to close. In addition to the customary covenants and closing conditions contained in the agreement, if Blooming Grove does not achieve commercial operation by the end of 2020 and any related potential adverse consequences are not otherwise mitigated, we may terminate the agreement in our sole discretion. Blooming Grove will be included in the non-utility energy infrastructure segment.

OPERATING REVENUES

OPERATING REVENUES	3 Months Ended
	Mar. 31, 2020
Revenue from Contract with Customer [Abstract]
OPERATING REVENUES	OPERATING REVENUES For more information about our operating revenues, see Note 1(d), Operating Revenues, in our 2019 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, which includes investments accounted for using the equity method. 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 can be impacted differently 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, 2020 Electric $ 1,034.6 $ — $ — $ 1,034.6 $ — $ — $ — $ 1,034.6 Natural gas 458.9 433.6 139.8 1,032.3 14.5 — (14.1 ) 1,032.7 Total regulated revenues 1,493.5 433.6 139.8 2,066.9 14.5 — (14.1 ) 2,067.3 Other non-utility revenues — — 4.4 4.4 16.4 0.4 (1.6 ) 19.6 Total revenues from contracts with customers 1,493.5 433.6 144.2 2,071.3 30.9 0.4 (15.7 ) 2,086.9 Other operating revenues 5.4 14.0 2.2 21.6 98.7 0.1 (98.7 ) 21.7 Total operating revenues $ 1,498.9 $ 447.6 $ 146.4 $ 2,092.9 $ 129.6 $ 0.5 $ (114.4 ) $ 2,108.6 (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 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) 2020 2019 Residential $ 404.9 $ 406.7 Small commercial and industrial 323.6 333.9 Large commercial and industrial 194.6 212.3 Other 7.3 7.8 Total retail revenues 930.4 960.7 Wholesale 42.1 47.7 Resale 45.2 40.8 Steam 8.4 10.1 Other utility revenues 8.5 2.5 Total electric utility operating revenues $ 1,034.6 $ 1,061.8 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, 2020 Residential $ 313.1 $ 282.9 $ 95.3 $ 691.3 Commercial and industrial 151.3 91.4 51.7 294.4 Total retail revenues 464.4 374.3 147.0 985.7 Transport 24.1 72.7 10.5 107.3 Other utility revenues * (29.6 ) (13.4 ) (17.7 ) (60.7 ) Total natural gas utility operating revenues $ 458.9 $ 433.6 $ 139.8 $ 1,032.3 (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 * Includes amounts refunded to customers for purchased gas adjustment costs. Other Natural Gas Operating Revenues We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment. Bluewater has entered into long-term service agreements for natural gas storage services with WE, WPS, and WG, and provides service to several unaffiliated customers. All amounts associated with services from affiliates have been eliminated at the consolidated level. Other Non-Utility Operating Revenues Other non-utility operating revenues consist primarily of the following: Three Months Ended March 31 (in millions) 2020 2019 Wind generation revenues $ 9.3 $ 6.2 We Power revenues * 5.5 6.4 Appliance service revenues 4.4 4.1 Distributed renewable solar project revenues 0.4 1.5 Other — 0.1 Total other non-utility operating revenues $ 19.6 $ 18.3 * 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 these 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 carrying costs to revenues over the life of the related lease term that We Power has with WE. During the three months ended March 31 , 2020 and 2019, we recorded $5.5 million and $6.4 million , respectively, of revenues 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. Other Operating Revenues Other operating revenues consist primarily of the following: Three Months Ended March 31 (in millions) 2020 2019 Late payment charges $ 12.1 $ 13.2 Alternative revenues * 8.5 (19.7 ) Other 1.1 7.4 Total other operating revenues $ 21.7 $ 0.9 * 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, wholesale true-ups, and conservation improvement rider true-ups, as discussed in Note 1(d), Operating Revenues, in our 2019 Annual Report on Form 10-K.

CREDIT LOSSES

CREDIT LOSSES	3 Months Ended
	Mar. 31, 2020
Credit Loss [Abstract]
CREDIT LOSSES	CREDIT LOSSES Effective January 1, 2020, we adopted FASB ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, using the modified retrospective transition method. This ASU amends the impairment model to utilize an expected loss methodology in place of the incurred loss methodology for financial instruments, including trade receivables. The amendment requires entities to consider a broader range of information to estimate expected credit losses, which may result in earlier recognition of loss. The cumulative effect of adopting this standard was not significant to our financial statements. Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are primarily generated from the sale of electricity and natural gas by our regulated utility operations. Credit losses associated with our utility operations are analyzed at the reportable segment level as we believe contract terms, political and economic risks, and the regulatory environment are similar at this level as our reportable segments are generally based on the geographic location of the underlying utility operations. We have an accounts receivable and unbilled revenue balance associated with our non-utility energy infrastructure segment, related to the sale of electricity from our majority-owned wind generating facilities through agreements with several large high credit quality counterparties. At the corporate and other segment, the accounts receivable and unbilled revenue balance is related to the remaining PDL residential solar business. We evaluate the collectability of our accounts receivable and unbilled revenue balances considering a combination of factors. For some of our larger customers and also in circumstances where we become aware of a specific customer's inability to meet its financial obligations to us, we record a specific allowance for credit losses against amounts due in order to reduce the net recognized receivable to the amount we reasonably believe will be collected. For all other customers, we use the accounts receivable aging method to calculate an allowance for credit losses. Using this method, we classify accounts receivable into different aging buckets and calculate a reserve percentage for each aging bucket based upon historical loss rates. The calculated reserve percentages are updated on at least an annual basis, in order to ensure recent macroeconomic, political, and regulatory trends are captured in the calculation, to the extent possible. Risks identified that we do not believe are reflected in the calculated reserve percentages, are assessed on a quarterly basis to determine whether further adjustments are required. At March 31, 2020, we recorded a $2.7 million increase to our allowance for credit losses specific to the economic risks associated with the COVID-19 pandemic, which continues to evolve. We will continue to monitor the economic impacts of COVID-19 and the resulting effect that these impacts may have on the ability of our customers to pay their energy bills. We monitor our ongoing credit exposure through active review of counterparty accounts receivable balances against contract terms and due dates. Our activities include timely account reconciliation, dispute resolution and payment confirmation. To the extent possible, we work with customers with past due balances to negotiate payment plans, but will disconnect customers for non-payment as allowed by our regulators if necessary, and employ collection agencies and legal counsel to pursue recovery of defaulted receivables. For our larger customers, detailed credit review procedures may be performed in advance of any sales being made. We sometimes require letters of credit, parental guarantees, prepayments or other forms of credit assurance from our larger customers to mitigate credit risk. See Note 21, Regulatory Environment , for information on certain regulatory actions that are being taken for the purpose of ensuring that essential utility services are available to our customers during the COVID-19 pandemic. We have included a table below that shows our gross third-party receivable balances and the related allowance for credit losses at March 31, 2020 by reportable segment. (in millions) Wisconsin Illinois Other States Total Utility Operations Non-Utility Energy Infrastructure Corporate and Other WEC Energy Group Consolidated Accounts receivable and unbilled revenues $ 849.1 $ 404.7 $ 79.2 $ 1,333.0 $ 5.8 $ 2.9 $ 1,341.7 Allowance for credit losses 67.7 93.1 3.9 164.7 — 0.1 164.8 Accounts receivable and unbilled revenues, net $ 781.4 $ 311.6 $ 75.3 $ 1,168.3 $ 5.8 $ 2.8 $ 1,176.9 Total accounts receivable, net – past due greater than 90 days* $ 57.7 $ 35.9 $ 3.9 $ 97.5 $ — $ — $ 97.5 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms* 95.7 % 100.0 % — % 93.4 % — % — % 93.4 % * Our exposure to credit losses for certain regulated utility customers is mitigated by regulatory mechanisms we have in place. Specifically, rates related to all of the customers in our Illinois segment, as well as the residential rates of WE, WG, and WPS in our Wisconsin segment include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between the actual provision for credit losses and the amounts recovered in rates. As a result, at March 31, 2020 , $684.6 million , or 58.2% , of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. In addition, in a March 24, 2020 order, the PSCW authorized the deferral of credit losses at WE, WG, and WPS for commercial and industrial customers, to the extent these losses exceed the amount included in rates, as a result of the COVID-19 pandemic and the actions WE, WG, and WPS have been required to take to ensure essential utility services are available to customers during the public health emergency. Furthermore, pursuant to an April 15, 2020 order addressing certain impacts of the COVID-19 pandemic, the MPSC authorized all Michigan utilities to defer, for potential future recovery, uncollectible expense incurred on or after March 24, 2020 that exceeds the amounts being recovered in rates. The additional protections related to our March 31, 2020 accounts receivable and unbilled revenue balances provided by these orders are still being assessed and are not reflected in the percentages in the above table or related note. See Note 21, Regulatory Environment , for more information. A rollforward of the allowance for credit losses by reportable segment is included below: (in millions) Wisconsin Illinois Other States Total Utility Operations Corporate and Other WEC Energy Group Consolidated Balance at December 31, 2019 $ 59.9 $ 75.9 $ 4.1 $ 139.9 $ 0.1 $ 140.0 Provision for credit losses 13.7 14.4 0.7 28.8 — 28.8 Provision for credit losses deferred for future recovery or refund 3.3 29.5 — 32.8 — 32.8 Write-offs charged against the allowance (19.7 ) (31.6 ) (1.3 ) (52.6 ) — (52.6 ) Recoveries of amounts previously written off 10.5 4.9 0.4 15.8 — 15.8 Balance at March 31, 2020 $ 67.7 $ 93.1 $ 3.9 $ 164.7 $ 0.1 $ 164.8 The increase in the allowance for credit losses at our Wisconsin and Illinois reportable segments was driven by an increase in past due accounts receivable balances from December 31, 2019 to March 31, 2020. This is a trend we generally see over the winter moratorium months, when we are not allowed to disconnect customer service as a result of non-payment. In Wisconsin, the winter moratorium begins on November 1 and ends on April 15, and in Illinois the winter moratorium begins on December 1 and ends on March 31. However, as a result of the COVID-19 pandemic, we are still unable to disconnect any of our Wisconsin and Illinois customers, and have also agreed not to disconnect certain of our regulated utility customers in the other states segment. See Note 21, Regulatory Environment , for more information.

REGULATORY ASSETS AND LIABILITI

REGULATORY ASSETS AND LIABILITIES	3 Months Ended
	Mar. 31, 2020
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, 2020 and December 31, 2019 . For more information on our regulatory assets and liabilities, see Note 5, Regulatory Assets and Liabilities, in our 2019 Annual Report on Form 10-K. (in millions) March 31, 2020 December 31, 2019 Regulatory assets Pension and OPEB costs $ 1,042.5 $ 1,066.6 Plant retirements 851.5 856.4 Environmental remediation costs 686.4 685.5 Income tax related items 457.6 457.8 Asset retirement obligations 188.8 137.5 SSR 140.5 151.5 Uncollectible expense 83.4 52.2 Derivatives 31.8 33.8 We Power generation 18.7 25.8 Other, net 77.6 60.5 Total regulatory assets $ 3,578.8 $ 3,527.6 Balance sheet presentation Other current assets $ 12.7 $ 20.9 Regulatory assets 3,566.1 3,506.7 Total regulatory assets $ 3,578.8 $ 3,527.6 (in millions) March 31, 2020 December 31, 2019 Regulatory liabilities Income tax related items $ 2,222.9 $ 2,248.8 Removal costs 1,195.0 1,181.5 Pension and OPEB benefits 349.5 354.9 Energy costs refundable through rate adjustments 162.2 89.8 Electric transmission costs 51.0 42.2 Earnings sharing mechanisms 40.6 43.5 Uncollectible expense 39.0 39.1 Energy efficiency programs 35.6 30.7 Decoupling 35.0 36.8 Other, net 12.1 13.1 Total regulatory liabilities $ 4,142.9 $ 4,080.4 Balance sheet presentation Amounts refundable to customers $ 155.8 $ 87.6 Regulatory liabilities 3,987.1 3,992.8 Total regulatory liabilities $ 4,142.9 $ 4,080.4

COMMON EQUITY

COMMON EQUITY	3 Months Ended
	Mar. 31, 2020
Equity [Abstract]
COMMON EQUITY	COMMON EQUITY Stock-Based Compensation During the first quarter of 2020 , 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) 512,139 Restricted shares (2) 84,540 Performance units 140,455 (1) Stock options awarded had a weighted-average exercise price of $91.49 and a weighted-average grant date fair value of $10.82 per option. (2) Restricted shares awarded had a weighted-average grant date fair value of $91.49 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, ATC Holding LLC, which holds our ownership interest in ATC, and WECI. 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 2019 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 16, 2020, our Board of Directors declared a quarterly cash dividend of $0.6325 per share, payable on June 1, 2020, to shareholders of record on May 14, 2020.

SHORT-TERM DEBT AND LINES OF CR

SHORT-TERM DEBT AND LINES OF CREDIT	3 Months Ended
	Mar. 31, 2020
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, 2020 December 31, 2019 Commercial paper Amount outstanding $ 487.2 $ 830.8 Weighted-average interest rate on amounts outstanding 3.03 % 2.00 % Term loan Amount outstanding $ 340.0 $ — Weighted-average interest rate on amounts outstanding 2.12 % n/a Our average amount of commercial paper borrowings based on daily outstanding balances during the three months ended March 31, 2020 was $843.8 million with a weighted-average interest rate during the period of 1.88% . In order to enhance our liquidity position in response to the COVID-19 pandemic, in March 2020, WEC Energy Group entered into a $340 million 364 -day term loan that will mature on March 29, 2021. The proceeds from this term loan were used to pay down commercial paper. The information in the table below relates to our term loan agreement and our revolving credit facilities used to support our commercial paper borrowing programs, including available capacity under these credit agreements: (in millions) Maturity March 31, 2020 Term loan agreement (WEC Energy Group) March 2021 $ 340.0 Revolving credit facility (WEC Energy Group) October 2022 1,200.0 Revolving credit facility (WE) October 2022 500.0 Revolving credit facility (WPS) October 2022 400.0 Revolving credit facility (WG) October 2022 350.0 Revolving credit facility (PGL) October 2022 350.0 Total short-term credit capacity $ 3,140.0 Less: Letters of credit issued inside credit facilities $ 2.3 Term loan outstanding 340.0 Commercial paper outstanding 487.2 Available capacity under existing credit agreements $ 2,310.5

LONG-TERM DEBT

LONG-TERM DEBT	3 Months Ended
	Mar. 31, 2020
Long-term Debt, Unclassified [Abstract]
Long-Term Debt	LONG-TERM DEBT Minnesota Energy Resources Corporation In April 2020, MERC issued $50.0 million of 2.69% Senior Notes due May 1, 2025, and used the net proceeds to repay intercompany short-term debt to its parent, Integrys, and for general corporate purposes, including capital expenditures. Michigan Gas Utilities Corporation In April 2020, MGU issued $60.0 million of 2.69% Senior Notes due May 1, 2025, and used the net proceeds to repay intercompany short-term debt to its parent, Integrys, and for general corporate purposes, including capital expenditures.

MATERIALS, SUPPLIES, AND INVENT

MATERIALS, SUPPLIES, AND INVENTORIES	3 Months Ended
	Mar. 31, 2020
Inventory Disclosure [Abstract]
MATERIALS, SUPPLIES, AND INVENTORIES	MATERIALS, SUPPLIES, AND INVENTORIES Our inventory consisted of: (in millions) March 31, 2020 December 31, 2019 Materials and supplies 230.7 234.2 Fossil fuel 92.5 87.9 Natural gas in storage 67.9 227.7 Total $ 391.1 $ 549.8 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, 2020 , we had a temporary LIFO liquidation debit of $11.3 million recorded within other current assets 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 materials and supplies, fossil fuel inventories, and natural gas in storage are recorded using the weighted-average cost method of accounting.

INCOME TAXES

INCOME TAXES	3 Months Ended
	Mar. 31, 2020
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, 2020 Three Months Ended March 31, 2019 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 113.9 21.0 % $ 101.9 21.0 % State income taxes net of federal tax benefit 34.0 6.3 % 31.0 6.4 % Federal excess deferred tax amortization – Wisconsin unprotected (22.1 ) (4.1 )% — — % Wind production tax credits (18.4 ) (3.4 )% (13.4 ) (2.8 )% Federal excess deferred tax amortization (13.0 ) (2.4 )% (13.2 ) (2.7 )% Excess tax benefits – stock options (4.9 ) (0.9 )% (7.2 ) (1.5 )% Tax repairs 1.5 0.3 % (29.6 ) (6.1 )% Other (1.0 ) (0.2 )% (4.5 ) (0.9 )% Total income tax expense $ 90.0 16.6 % $ 65.0 13.4 % The effective tax rate of 16.6% for the first quarter of 2020 differs from the United States statutory federal income tax rate of 21% , primarily due to the recognition of certain deferred tax benefits created as a result of the Tax Legislation. In accordance with the rate order received from the PSCW in December 2019, our Wisconsin utilities are amortizing the unprotected deferred tax benefits over periods ranging from two years to four years , to reduce near-term rate impacts to their customers. In addition, wind production tax credits generated from acquisitions of ownership interests in wind generation facilities in our non-utility energy infrastructure segment and the impact of the benefits associated with the Tax Legislation, as discussed in more detail below, drove a decrease in the effective tax rate, which was partially offset by state income taxes. 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 2017 Wisconsin rate settlement, wind production tax credits generated from acquisitions of ownership interests in wind generation facilities in our non-utility energy infrastructure segment and the impact of the benefits associated with the Tax Legislation, as discussed in more detail below, 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 21, Regulatory Environment, for more information .

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	3 Months Ended
	Mar. 31, 2020
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 price 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 derivative 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. 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, 2020 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 3.9 $ 0.7 $ — $ 4.6 FTRs — — 0.9 0.9 Coal contracts — 0.3 — 0.3 Total derivative assets $ 3.9 $ 1.0 $ 0.9 $ 5.8 Investments held in rabbi trust $ 54.9 $ — $ — $ 54.9 Derivative liabilities Natural gas contracts $ 22.7 $ — $ — $ 22.7 Coal contracts — 0.1 — 0.1 Interest rate swaps — 10.0 — 10.0 Total derivative liabilities $ 22.7 $ 10.1 $ — $ 32.8 December 31, 2019 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 1.4 $ 2.0 $ — $ 3.4 FTRs — — 3.1 3.1 Coal contracts — 0.4 — 0.4 Total derivative assets $ 1.4 $ 2.4 $ 3.1 $ 6.9 Investments held in rabbi trust $ 85.3 $ — $ — $ 85.3 Derivative liabilities Natural gas contracts $ 21.4 $ 1.3 $ — $ 22.7 Coal contracts — 0.2 — 0.2 Interest rate swaps — 6.0 — 6.0 Total derivative liabilities $ 21.4 $ 7.5 $ — $ 28.9 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. During the three months ended March 31, 2020 , we recorded $14.2 million of net unrealized losses in earnings related to the investments held at the end of the period, compared with $8.6 million of net unrealized gains recorded during the same quarter in 2019 . The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended March 31 (in millions) 2020 2019 Balance at the beginning of the period $ 3.1 $ 7.4 Settlements (2.2 ) (4.3 ) Balance at the end of the period $ 0.9 $ 3.1 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, 2020 December 31, 2019 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock of subsidiary $ 30.4 $ 28.3 $ 30.4 $ 29.5 Long-term debt, including current portion * 11,844.8 12,920.8 11,858.3 13,035.9 * The carrying amount of long-term debt excludes finance lease obligations of $44.2 million and $45.9 million at March 31, 2020 and December 31, 2019 , 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, 2020
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, along with their classification on our balance sheets. March 31, 2020 December 31, 2019 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 3.0 $ 22.7 $ 3.4 $ 21.8 FTRs 0.9 — 3.1 — Coal contracts 0.2 0.1 0.2 0.2 Interest rate swaps — 5.1 — 2.8 Total other current * 4.1 27.9 6.7 24.8 Other long-term Natural gas contracts 1.6 — — 0.9 Coal contracts 0.1 — 0.2 — Interest rate swaps — 4.9 — 3.2 Total other long-term * 1.7 4.9 0.2 4.1 Total $ 5.8 $ 32.8 $ 6.9 $ 28.9 * 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, 2020 Three Months Ended March 31, 2019 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 58.4 Dth $ (24.7 ) 56.1 Dth $ (0.5 ) FTRs 7.2 MWh 1.4 8.1 MWh 2.3 Total $ (23.3 ) $ 1.8 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, 2020 and December 31, 2019 , we had posted cash collateral of $28.8 million and $34.4 million , respectively, in our margin accounts. These amounts were recorded on our balance sheets in other current assets. The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: March 31, 2020 December 31, 2019 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 5.8 $ 32.8 $ 6.9 $ 28.9 Gross amount not offset on the balance sheet (3.9 ) (22.7 ) (1) (1.4 ) (21.4 ) (2) Net amount $ 1.9 $ 10.1 $ 5.5 $ 7.5 (1) Includes cash collateral posted of $18.8 million . (2) Includes cash collateral posted of $20.0 million . Cash Flow Hedges As of March 31, 2020 , 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 loss 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 other comprehensive loss 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 other comprehensive loss and in earnings, along with our total interest expense on the income statements: Three Months Ended March 31 (in millions) 2020 2019 Derivative losses recognized in other comprehensive loss $ (4.7 ) $ (1.6 ) Net derivative gains (losses) reclassified from accumulated other comprehensive loss to interest expense (0.1 ) 0.4 Total interest expense line item on the income statements 129.4 124.4 We estimate that during the next twelve months $3.5 million will be reclassified from accumulated other comprehensive loss as an increase to interest expense.

GUARANTEES

GUARANTEES	3 Months Ended
	Mar. 31, 2020
Guarantees [Abstract]
GUARANTEES	GUARANTEES The following table shows our outstanding guarantees: Expiration (in millions) Total Amounts Committed at March 31, 2020 Less Than 1 Year 1 to 3 Years Over 3 Years Guarantees Guarantees supporting transactions of subsidiaries (1) $ 31.6 $ 9.2 $ 0.2 $ 22.2 Standby letters of credit (2) 95.5 1.2 0.2 94.1 Surety bonds (3) 9.9 9.9 — — Other guarantees (4) 12.1 0.9 — 11.2 Total guarantees $ 149.1 $ 21.2 $ 0.4 $ 127.5 (1) Consists of $4.2 million , $6.2 million , and $21.2 million to support the business operations of UMERC, Bluewater, and WECI, respectively. (2) At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets. (3) Primarily for workers compensation self-insurance programs and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets. (4) Consists of $12.1 million related to other indemnifications, for which a liability of $11.2 million related to workers compensation coverage was recorded on our balance sheets.

EMPLOYEE BENEFITS

EMPLOYEE BENEFITS	3 Months Ended
	Mar. 31, 2020
Retirement Benefits [Abstract]
EMPLOYEE BENEFITS	EMPLOYEE BENEFITS The following tables show the components of net periodic benefit cost (credit) for our benefit plans. Pension Benefits Three Months Ended March 31 (in millions) 2020 2019 Service cost $ 13.1 $ 11.3 Interest cost 26.1 30.6 Expected return on plan assets (47.9 ) (48.7 ) Loss on plan settlement 0.3 0.8 Amortization of prior service cost 0.4 0.6 Amortization of net actuarial loss 24.2 19.0 Net periodic benefit cost $ 16.2 $ 13.6 OPEB Benefits Three Months Ended March 31 (in millions) 2020 2019 Service cost $ 4.1 $ 4.4 Interest cost 4.7 6.5 Expected return on plan assets (15.1 ) (13.7 ) Amortization of prior service credit (3.7 ) (3.9 ) Amortization of net actuarial gain (5.4 ) (0.7 ) Net periodic benefit credit $ (15.4 ) $ (7.4 ) During the three months ended March 31, 2020 , we made contributions and payments of $3.5 million related to our pension plans and $0.2 million related to our OPEB plans. We expect to make contributions and payments of $8.0 million related to our pension plans and $0.8 million related to our OPEB plans during the remainder of 2020 , dependent upon various factors affecting us, including our liquidity position and the continued effects of the Tax Legislation.

GOODWILL

GOODWILL	3 Months Ended
	Mar. 31, 2020
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 at March 31, 2020 . We had no changes to the carrying amount of goodwill during the three months ended March 31, 2020 . (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, 2020 .

INVESTMENT IN TRANSMISSION AFFI

INVESTMENT IN TRANSMISSION AFFILIATES	3 Months Ended
	Mar. 31, 2020
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, 2020 (in millions) ATC ATC Holdco Total Balance at beginning of period $ 1,684.7 $ 36.1 $ 1,720.8 Add: Earnings from equity method investment 39.6 0.2 39.8 Add: Capital contributions 3.0 — 3.0 Less: Distributions 40.6 — 40.6 Less: Return of capital — 5.3 5.3 Balance at end of period $ 1,686.7 $ 31.0 $ 1,717.7 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 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. The following table summarizes our significant related party transactions with ATC: Three Months Ended March 31 (in millions) 2020 2019 Charges to ATC for services and construction $ 6.0 $ 4.0 Charges from ATC for network transmission services 86.9 87.1 Our balance sheets included the following receivables and payables for services received from or provided to ATC: (in millions) March 31, 2020 December 31, 2019 Accounts receivable for services provided to ATC $ 2.6 $ 3.5 Accounts payable for services received from ATC 29.3 29.0 Amounts due from ATC for transmission infrastructure upgrades * 2.3 2.8 * In connection with WPS's construction of its two new solar projects, Badger Hollow I and Two Creeks, WPS was required to initially fund the construction of the transmission infrastructure upgrades needed for the new generation. ATC owns these transmission assets and will reimburse WPS for these costs after the new generation has been placed in service. Summarized financial data for ATC is included in the tables below: Three Months Ended March 31 (in millions) 2020 2019 Income statement data Operating revenues $ 186.8 $ 177.7 Operating expenses 95.2 90.4 Other expense, net 28.5 28.8 Net income $ 63.1 $ 58.5 (in millions) March 31, 2020 December 31, 2019 Balance sheet data Current assets $ 82.4 $ 84.7 Noncurrent assets 5,283.2 5,244.2 Total assets $ 5,365.6 $ 5,328.9 Current liabilities $ 526.3 $ 502.6 Long-term debt 2,313.0 2,312.8 Other noncurrent liabilities 307.9 298.9 Shareholders' equity 2,218.4 2,214.6 Total liabilities and shareholders' equity $ 5,365.6 $ 5,328.9

SEGMENT INFORMATION

SEGMENT INFORMATION	3 Months Ended
	Mar. 31, 2020
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, 2020 , we reported six segments, which are described below. • The Wisconsin segment includes the electric and natural gas utility operations of WE, WPS, WG, and UMERC. • The Illinois segment includes the natural gas utility and non-utility operations of PGL and NSG. • The other states segment includes the natural gas utility and non-utility operations of MERC and MGU. • The electric transmission segment includes our approximate 60% ownership interest in ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects, and our approximate 75% ownership interest in ATC Holdco, which was formed to invest in transmission-related projects outside of ATC's traditional footprint. • The non-utility energy infrastructure segment includes: ◦ We Power, which owns and leases generating facilities to WE, ◦ Bluewater, which owns underground natural gas storage facilities in Michigan that provide approximately one-third of the current storage needs for our Wisconsin natural gas utilities, and ◦ WECI, which holds our ownership interests in the following wind generating facilities: ▪ 90% ownership interest in Bishop Hill III, located in Henry County, Illinois, ▪ 80% ownership interest in Coyote Ridge, located in Brookings County, South Dakota, and ▪ 80% ownership interest in Upstream, located in Antelope County, Nebraska. See Note 2, Acquisitions, for more information on 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 PDL. 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 , 2020 and 2019 : 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, 2020 External revenues $ 1,498.9 $ 447.6 $ 146.4 $ 2,092.9 $ — $ 15.2 $ 0.5 $ — $ 2,108.6 Intersegment revenues — — — — — 114.4 — (114.4 ) — Other operation and maintenance 330.8 104.1 21.7 456.6 — 5.2 (1.6 ) (4.5 ) 455.7 Depreciation and amortization 165.4 47.5 7.8 220.7 — 24.5 6.1 (12.2 ) 239.1 Operating income (loss) 426.8 161.6 37.4 625.8 — 91.5 (4.2 ) (86.5 ) 626.6 Equity in earnings of transmission affiliates — — — — 39.8 — — — 39.8 Interest expense 143.1 16.0 2.2 161.3 4.8 15.3 35.1 (87.1 ) 129.4 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, 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

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	3 Months Ended
	Mar. 31, 2020
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. At March 31, 2020 and December 31, 2019 , our equity investment in ATC was $1,686.7 million and $1,684.7 million , respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC. 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. At March 31, 2020 and December 31, 2019 , our equity investment in ATC Holdco was $31.0 million and $36.1 million , respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco. See Note 16, Investment in Transmission Affiliates, for more information , including any significant assets and liabilities related to ATC and ATC Holdco recorded on our balance sheets. 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 two 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 $20.2 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, 2020
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. The wind generation facilities that are part of our non-utility energy infrastructure segment 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, 2020 , including those of our subsidiaries, were approximately $11.2 billion . 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; management 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 in April 2018. The following counties within our service territories were designated as partial nonattainment: Door, Kenosha, Manitowoc, Northern Milwaukee/Ozaukee, and Sheboygan shorelines. This re-designation was challenged in the D.C. Circuit Court of Appeals in Clean Wisconsin et al. v. U.S. Environmental Protection Agency. Petitioners in that case have argued that additional portions of Milwaukee, Waukesha, Ozaukee, and Washington Counties (among others) should be designated as nonattainment for ozone. In November 2019, the D.C. Circuit Court of Appeals heard oral arguments for that case. A decision is expected later in 2020, and we expect that any subsequent EPA re-designation, if necessary, would take place in 2021. 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. The State of Wisconsin is currently working with stakeholders, including us, in developing regulations for inclusion in the state implementation plan required by the rule. Mercury and Air Toxics Standards In December 2018, the EPA proposed to revise the Supplemental Cost Finding for the MATS rule as well as the CAA required 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 The ACE rule became effective in September 2019. This rule provides existing coal-fired generating units with standards for achieving GHG emission reductions. The rule was finalized in conjunction with two other separate and distinct rulemakings, (1) the repeal of the Clean Power Plan, and (2) revised implementing regulations for ACE, ongoing emissions guidelines, and all future emission guidelines for existing sources issued under CAA section 111(d). Every state's plan to implement ACE is required to focus on reducing GHG emissions by improving the efficiency of fossil-fueled power plants. The rule is being litigated in challenges brought in the D.C. Circuit Court of Appeals by 22 states (including Illinois, Michigan, Minnesota, and Wisconsin), local governments, and certain nongovernmental organizations. Final briefs in this litigation are scheduled to be filed in August 2020, with oral arguments expected to follow. The Wisconsin Department of Natural Resources is working with state utilities and has begun the process of developing the implementation plan with respect to the ACE rule. 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 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. The EPA has reviewed comments and intends to take final action on the proposed rule later in 2020. 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 evaluate potential GHG reduction pathways as climate change policies and relevant technologies evolve over time. We continue to evaluate opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute toward long-term GHG emissions reductions. Our current plan is to continue to work with our industry peers, environmental groups, public policy makers, and customers, with goals of reducing CO 2 emissions. In 2019, we met and exceeded our 2030 goal of reducing CO 2 emissions by 40% below 2005 levels, and are re-evaluating our longer-term CO 2 reduction goals. As a result of our generation reshaping plan, we retired approximately 1,800 MW of coal generation since the beginning of 2018, including the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater Unit 4 generating units as well as the March 2019 retirement of the PIPP. We also have a goal to decrease the rate of methane emissions from the natural gas distribution lines in our network by 30% per mile by the year 2030 from a 2011 baseline. We were over half way toward meeting that goal at the end of 2019. 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 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. We have received BTA determinations for OC 5 through OC 8, Weston Units 2, 3, and 4, and Valley power plant. Although we currently believe that existing technology at the Port Washington Generating Station satisfies the BTA requirements, final determinations will not be made until the discharge permit is renewed for this facility, which is expected to be in 2021. Until that time, we cannot determine what, if any, intake structure or operational modifications will be required to meet the new BTA requirements for this facility. As a result of past capital investments completed to address Section 316(b) compliance at WE and WPS, we believe our fleet overall is well positioned to meet the regulation and do not expect to incur significant costs to comply with this regulation. Steam Electric Effluent Limitation Guidelines The EPA's final 2015 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 BATW and wet FGD wastewater. As a result of past capital investments at WE and WPS, we believe our fleet is well positioned to meet the existing ELG regulations. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. There will, however, need to be modifications to the BATW systems at Weston Unit 3 and OC 7 and OC 8. Also, 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, we estimate that compliance with the current rule will require $60 million in capital costs. The ELG requirements for BATW and wet FGD systems are currently being re-evaluated by the EPA. 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 while it reconsiders the ELG rule. The Postponement Rule left unchanged the latest ELG rule compliance date of December 31, 2023. In November 2019, the EPA Administrator signed the proposed ELG Reconsideration Rule to revise the treatment technology requirements related to BATW and wet FGD wastewaters at existing facilities. The EPA also proposed a provision that exempts facility owners from the new BATW and wet FGD requirements if a generating unit is retired by December 31, 2028. We expect the rule to be finalized in late 2020. In the meantime, we are currently evaluating what impact, if any, the proposed rule would have on our estimated compliance cost. 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 for manufactured gas plant sites: (in millions) March 31, 2020 December 31, 2019 Regulatory assets $ 686.4 $ 685.5 Reserves for future environmental remediation 589.4 589.2 Consent Decrees Wisconsin Public Service Corporation – 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. With the retirement of Pulliam Units 7 and 8 in October 2018, WPS completed the mitigation projects required by the Consent Decree and received a completeness letter from the EPA in October 2018. We plan to request termination of the WPS Consent Decree during 2020. Joint Ownership Power Plants – 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 in September 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, 2020
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) 2020 2019 Cash paid for interest, net of amount capitalized $ 85.8 $ 66.3 Cash paid (received) for income taxes, net (11.2 ) 0.2 Significant non-cash investing and financing transactions: Accounts payable related to construction costs 102.5 74.7 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 WECI acquired ownership interests in 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 acquisition of Upstream. The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets to the total of these amounts shown on the statements of cash flows: (in millions) March 31, 2020 December 31, 2019 Cash and cash equivalents $ 15.4 $ 37.5 Restricted cash included in other long term assets 50.3 44.8 Cash, cash equivalents, and restricted cash $ 65.7 $ 82.3

REGULATORY ENVIRONMENT

REGULATORY ENVIRONMENT	3 Months Ended
	Mar. 31, 2020
Regulated Operations [Abstract]
REGULATORY ENVIRONMENT	REGULATORY ENVIRONMENT Coronavirus Disease – 2019 The global outbreak of COVID-19 was declared a pandemic by the WHO and the CDC. COVID-19 has spread globally, including throughout the United States and, in turn, our service territories. Each of the states in which our regulated utilities operate has declared a public health emergency and has issued shelter-in-place orders in response to the COVID-19 pandemic. In addition, we have received written orders from the PSCW, the ICC, and the MPSC regarding certain actions to be taken for purposes of ensuring that essential utility services are available to customers in Wisconsin, Illinois, and Michigan, respectively. A summary of these orders is included below. Wisconsin On March 24, 2020, the PSCW issued two orders in response to COVID-19. The first order requires all public utilities in the state of Wisconsin, including WE, WPS, and WG, to temporarily suspend disconnections, the assessment of late fees, and deposit requirements for all customer classes. In addition, it requires utilities to reconnect customers that were previously disconnected, offer deferred payment arrangements to all customers, and streamline the application process for customers applying for utility service. The order will remain in effect during the public health emergency and until further notice from the PSCW. In the second order, the PSCW authorized Wisconsin utilities to defer expenditures and certain foregone revenues resulting from compliance with the first order, and expenditures as otherwise incurred to ensure safe, reliable, and affordable access to utility services during the declared public health emergency. The PSCW has affirmed that this authorization for deferral includes the incremental increase in uncollectible expense above what is currently being recovered in rates. As WE, WPS, and WG already have a cost recovery mechanism in place to recover uncollectible expense for residential customers, this new deferral will only impact the recovery of uncollectible expense for their commercial and industrial customers. The PSCW will review the recoverability and examine the prudency of any deferred amounts in future rate proceedings. As of March 31, 2020, our Wisconsin utilities had not recorded any deferrals related to the COVID-19 pandemic. A limited number of expenditures have been identified, and we anticipate amounts will be deferred in the second quarter of 2020. WE, WPS, and WG have begun to experience foregone revenues related to their inability to charge late fees as a result of the PSCW order, and will continue to evaluate future incremental costs and foregone revenues for potential recovery as they arise. Illinois On March 18, 2020, the ICC issued an order to all Illinois utilities, including PGL and NSG, requiring, among other things, a moratorium on disconnections of utility service and a suspension of late fees and penalties during the declared public health emergency. The moratorium on disconnections and the suspension of late fees and penalties applies to all utility customer classes and will remain in effect until May 1, 2020, or until the Illinois governor announces the end of the COVID-19 public health emergency, whichever is later. To ensure that customers will continue to receive utility services for a period of time after the public health emergency ends, utilities in Illinois will also be required to temporarily enact more flexible credit and collections procedures for a period of no less than six months after the moratorium is lifted. PGL and NSG filed their proposed flexible credit and collection procedures with the ICC on March 27, 2020. As required in the ICC order, PGL and NSG are tracking foregone late fees and expenses resulting from the measures they are taking in response to the COVID-19 public health emergency, including, but not limited to, the measures required by the ICC's order. PGL and NSG have requested that the ICC allow them to defer these expenses. Michigan On April 15, 2020, the MPSC issued an order requiring Michigan utilities, including MGU and UMERC, to put certain minimum protections in place during the COVID-19 pandemic. The minimum protections required by the order include the suspension of disconnections, late payment fees, deposits, and reconnection fees for certain vulnerable customers. In addition, utilities are required to extend access to and flexibility of payment plans to customers financially impacted by COVID-19. The MPSC authorized all Michigan utilities to defer, for potential future recovery, uncollectible expense incurred on or after March 24, 2020 that exceeds the amounts being recovered in rates. The MPSC is evaluating whether additional COVID-19-related expenses or certain foregone revenues should also be deferred by Michigan utilities. As required in the MPSC order, MGU and UMERC filed responses with the MPSC on April 20, 2020 affirming the actions they are taking to protect customers during the declared public health emergency. The actions being taken by MGU and UMERC provide protections to more customers than required by the MPSC order. These actions include suspending disconnections for all residential customers, suspending the assessment of late fees, as well as restoring electric and natural gas service for all customers on a payment plan, waiving deposit requirements for new service, and enhancing payment plan options for all customers. Wisconsin Electric Power Company, Wisconsin Public Service Corporation, and Wisconsin Gas LLC 2020 and 2021 Rates In March 2019, WE, WPS, and WG filed applications with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable, effective January 1, 2020. In August 2019, all three utilities filed applications with the PSCW for approval of settlement agreements entered into with certain intervenors to resolve several outstanding issues in each utility's respective rate case. In December 2019, the PSCW issued written orders that approved the settlement agreements without material modification and addressed the remaining outstanding issues that were not included in the settlement agreements. The new rates became effective January 1, 2020. The final orders reflect the following: WE WPS WG 2020 Effective rate increase (decrease) Electric (1) (2) $ 15.3 million / 0.5% $ 15.8 million / 1.6% N/A Gas (3) $ 10.4 million / 2.8% $ 4.3 million / 1.4% $ (1.5 ) million / (0.2)% Steam $ 1.9 million / 8.6% N/A N/A ROE 10.0% 10.0% 10.2% Common equity component average on a financial basis 52.5% 52.5% 52.5% (1) Amounts are net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impact. The WE and WPS rate orders reflect the majority of the unprotected deferred tax benefits from the Tax Legislation being amortized over two years . For WE, approximately $65 million of tax benefits will be amortized in each of 2020 and 2021. For WPS, approximately $11 million of tax benefits are being amortized in 2020 and approximately $39 million will be amortized in 2021. The unprotected deferred tax benefits related to the unrecovered balances of WE's recently retired plants and its SSR regulatory asset are being used to reduce the related regulatory asset. Unprotected deferred tax benefits by their nature are eligible to be returned to customers in a manner and timeline determined to be appropriate by our regulators. (2) The WPS rate order is net of $21 million of refunds related to its 2018 earnings sharing mechanism. These refunds will be made to customers evenly over two years , with half being returned in 2020 and the remainder in 2021. (3) The WE amount includes certain deferred tax expense from the Tax Legislation, and the WPS and WG amounts are net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impact. The rate orders for all three gas utilities reflect all of the unprotected deferred tax expense and benefits from the Tax Legislation being amortized evenly over four years . For WE, approximately $5 million of previously deferred tax expense will be amortized each year. For WPS and WG, approximately $5 million and $3 million , respectively, of previously deferred tax benefits will be amortized each year. Unprotected deferred tax expense and benefits by their nature are eligible to be recovered from or returned to customers in a manner and timeline determined to be appropriate by our regulators. In accordance with its rate order, WE will seek a financing order from the PSCW to securitize $100 million of Pleasant Prairie power plant's book value, plus the carrying costs accrued on the $100 million during the securitization process and related fees. The securitization will reduce the carrying costs for the $100 million , benefiting customers. The WPS rate order allows WPS to collect the previously deferred revenue requirement for ReACT™ costs above the authorized $275.0 million level. The total cost of the ReACT™ project was $342 million . This regulatory asset will be collected from customers over eight years . All three Wisconsin utilities will continue having an earnings sharing mechanism through 2021. The earnings sharing mechanism was modified from its previous structure to one that is consistent with other Wisconsin investor-owned utilities. Under the new earnings sharing mechanism, if the utility earns above its authorized ROE: (i) the utility retains 100.0% of earnings for the first 25 basis points above the authorized ROE; (ii) 50.0% of the next 50 basis points is refunded to customers; and (iii) 100.0% of any remaining excess earnings is refunded to customers. In addition, the rate orders also require WE, WPS, and WG to maintain residential and small commercial electric and natural gas customer fixed charges at previously authorized rates and to maintain the status quo for WE's and WPS's electric market-based rate programs for large industrial customers through 2021. 2018 and 2019 Rates During April 2017, WE, WPS, and WG 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 froze base rates through 2019 for electric, natural gas, and steam customers of WE, WPS, and WG. Based on the PSCW order, the authorized ROE for WE, WPS, and WG remained at 10.2% , 10.0% , and 10.3% , respectively, and the capital cost structure for all of our Wisconsin utilities remained unchanged through 2019. In addition to freezing base rates, the settlement agreement extended and expanded the electric real-time market pricing program options for large commercial and industrial customers and mitigated the continued growth of certain escrowed costs at WE during the base rate freeze period by accelerating the recognition of certain tax benefits. WE was flowing 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 offset the negative income statement impact of holding the regulatory assets level, resulting in no change to net income. The agreement also allowed 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. Pursuant to the settlement agreement, WPS also agreed to adopt, beginning in 2018, the earnings sharing mechanism that had 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, WPS, or WG earned above its authorized ROE, 50% of the first 50 basis points of additional utility earnings were required to be refunded to customers. All utility earnings above the first 50 basis points were also required to be refunded to customers. Liquefied Natural Gas Facilities In November 2019, WE and WG filed a joint application with the PSCW requesting approval for each company to construct its own LNG facility. If approved, each facility would provide one billion cubic feet of natural gas supply to meet peak demand without requiring the construction of additional interstate pipeline capacity. These facilities are expected to reduce the likelihood of constraints on WE's and WG's natural gas systems during the highest demand days of winter. The total cost of both projects is estimated to be approximately $370 million , with approximately half being invested by each utility. Commercial operation of the LNG facilities is targeted for the end of 2023. Solar Generation Projects In August 2019, WE, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire an ownership interest in a proposed solar project, Badger Hollow II, that will be located in Iowa County, Wisconsin. Once constructed, WE will own 100 MW of the output of this project. WE's share of the cost of this project is estimated to be $130 million . The PSCW issued a written order approving the acquisition of this project on March 6, 2020. The Peoples Gas Light and Coke Company and North Shore Gas Company 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 2020, PGL filed its 2019 reconciliation with the ICC, which, along with the 2018, 2017, and 2016 reconciliations, are still pending. As of March 31, 2020 , 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. Michigan Gas Utilities Corporation 2021 Rate Application On February 3, 2020, MGU provided notification to the MPSC of its intent to file an application requesting an increase to MGU's natural gas rates to be effective January 1, 2021. However, MGU has decided that it will not be filing a rate case during the COVID-19 pandemic and will re-evaluate the timing of the rate filing at a later date.

NEW ACCOUNTING PRONOUNCEMENTS

NEW ACCOUNTING PRONOUNCEMENTS	3 Months Ended
	Mar. 31, 2020
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
NEW ACCOUNTING PRONOUNCEMENTS	NEW ACCOUNTING PRONOUNCEMENTS 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 adoption of ASU 2018-15, effective January 1, 2020, did not have a significant impact on our financial statements and related disclosures. Disclosure Requirements for Defined Benefit Plans In August 2018, the FASB issued ASU 2018-14, Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans. The pronouncement modifies the disclosure requirements for defined benefit pension and OPEB plans. The guidance removes disclosures that are no longer considered cost beneficial, clarifies the specific requirements of disclosures and adds disclosure requirements identified as relevant. The modifications affect annual period disclosures and must be applied on a retrospective basis to all periods presented. The guidance will be effective for annual reporting periods ending after December 15, 2020, with early adoption permitted. We are currently evaluating the effects of this pronouncement on the notes to our financial statements. Simplifying the Accounting for Income Taxes In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes. The new standard removes certain exceptions for performing intraperiod allocation and calculating income taxes in interim periods and also adds guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. The guidance will be effective for annual and interim periods beginning after December 15, 2020. We will adopt the new standard effective January 1, 2021, and do not expect the adoption to have a material impact on our financial statements and related disclosures. Reference Rate Reform In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments apply only to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. The amendments are effective for all entities as of March 12, 2020 through December 31, 2022. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

GENERAL INFORMATION (Policies)

GENERAL INFORMATION (Policies)	3 Months Ended
	Mar. 31, 2020
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, we consolidate our majority-owned subsidiaries and reflect noncontrolling interests for the portion of entities that we do not own as a component of consolidated equity separate from the equity attributable to our shareholders. The noncontrolling interests that we reported as equity on our balance sheets related to the minority interests at Bishop Hill III, Coyote Ridge, and Upstream held by third parties.
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, 2019 . 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 , 2020 , are not necessarily indicative of expected results for 2020 due to seasonal variations and other factors, including the potential effects from the COVID-19 pandemic. In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results.
Credit losses	Effective January 1, 2020, we adopted FASB ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, using the modified retrospective transition method. This ASU amends the impairment model to utilize an expected loss methodology in place of the incurred loss methodology for financial instruments, including trade receivables. The amendment requires entities to consider a broader range of information to estimate expected credit losses, which may result in earlier recognition of loss. The cumulative effect of adopting this standard was not significant to our financial statements. Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are primarily generated from the sale of electricity and natural gas by our regulated utility operations. Credit losses associated with our utility operations are analyzed at the reportable segment level as we believe contract terms, political and economic risks, and the regulatory environment are similar at this level as our reportable segments are generally based on the geographic location of the underlying utility operations. We have an accounts receivable and unbilled revenue balance associated with our non-utility energy infrastructure segment, related to the sale of electricity from our majority-owned wind generating facilities through agreements with several large high credit quality counterparties. At the corporate and other segment, the accounts receivable and unbilled revenue balance is related to the remaining PDL residential solar business. We evaluate the collectability of our accounts receivable and unbilled revenue balances considering a combination of factors. For some of our larger customers and also in circumstances where we become aware of a specific customer's inability to meet its financial obligations to us, we record a specific allowance for credit losses against amounts due in order to reduce the net recognized receivable to the amount we reasonably believe will be collected. For all other customers, we use the accounts receivable aging method to calculate an allowance for credit losses. Using this method, we classify accounts receivable into different aging buckets and calculate a reserve percentage for each aging bucket based upon historical loss rates. The calculated reserve percentages are updated on at least an annual basis, in order to ensure recent macroeconomic, political, and regulatory trends are captured in the calculation, to the extent possible. Risks identified that we do not believe are reflected in the calculated reserve percentages, are assessed on a quarterly basis to determine whether further adjustments are required. At March 31, 2020, we recorded a $2.7 million increase to our allowance for credit losses specific to the economic risks associated with the COVID-19 pandemic, which continues to evolve. We will continue to monitor the economic impacts of COVID-19 and the resulting effect that these impacts may have on the ability of our customers to pay their energy bills.
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 price 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 derivative 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.
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	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 adoption of ASU 2018-15, effective January 1, 2020, did not have a significant impact on our financial statements and related disclosures. Disclosure Requirements for Defined Benefit Plans In August 2018, the FASB issued ASU 2018-14, Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans. The pronouncement modifies the disclosure requirements for defined benefit pension and OPEB plans. The guidance removes disclosures that are no longer considered cost beneficial, clarifies the specific requirements of disclosures and adds disclosure requirements identified as relevant. The modifications affect annual period disclosures and must be applied on a retrospective basis to all periods presented. The guidance will be effective for annual reporting periods ending after December 15, 2020, with early adoption permitted. We are currently evaluating the effects of this pronouncement on the notes to our financial statements. Simplifying the Accounting for Income Taxes In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes. The new standard removes certain exceptions for performing intraperiod allocation and calculating income taxes in interim periods and also adds guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. The guidance will be effective for annual and interim periods beginning after December 15, 2020. We will adopt the new standard effective January 1, 2021, and do not expect the adoption to have a material impact on our financial statements and related disclosures. Reference Rate Reform In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments apply only to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. The amendments are effective for all entities as of March 12, 2020 through December 31, 2022. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.
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 these 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 carrying costs to revenues over the life of the related lease term that We Power has with WE.

ACQUISITIONS (Tables)

ACQUISITIONS (Tables)	12 Months Ended
	Dec. 31, 2019
WECI | Upstream
Business Acquisition [Line Items]
Allocation of purchase price	The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition of the initial 80% ownership interest in Upstream. (in millions) Current assets $ 1.5 Net property, plant, and equipment 341.6 Other long-term assets * 22.9 Current liabilities (4.6 ) Long-term liabilities (15.0 ) Noncontrolling interest (69.0 ) Total purchase price $ 277.4 * Includes $8.1 million of restricted cash.

OPERATING REVENUES (Tables)

OPERATING REVENUES (Tables)	3 Months Ended
	Mar. 31, 2020
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, which includes investments accounted for using the equity method. 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 can be impacted differently 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, 2020 Electric $ 1,034.6 $ — $ — $ 1,034.6 $ — $ — $ — $ 1,034.6 Natural gas 458.9 433.6 139.8 1,032.3 14.5 — (14.1 ) 1,032.7 Total regulated revenues 1,493.5 433.6 139.8 2,066.9 14.5 — (14.1 ) 2,067.3 Other non-utility revenues — — 4.4 4.4 16.4 0.4 (1.6 ) 19.6 Total revenues from contracts with customers 1,493.5 433.6 144.2 2,071.3 30.9 0.4 (15.7 ) 2,086.9 Other operating revenues 5.4 14.0 2.2 21.6 98.7 0.1 (98.7 ) 21.7 Total operating revenues $ 1,498.9 $ 447.6 $ 146.4 $ 2,092.9 $ 129.6 $ 0.5 $ (114.4 ) $ 2,108.6 (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
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) 2020 2019 Residential $ 404.9 $ 406.7 Small commercial and industrial 323.6 333.9 Large commercial and industrial 194.6 212.3 Other 7.3 7.8 Total retail revenues 930.4 960.7 Wholesale 42.1 47.7 Resale 45.2 40.8 Steam 8.4 10.1 Other utility revenues 8.5 2.5 Total electric utility operating revenues $ 1,034.6 $ 1,061.8
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, 2020 Residential $ 313.1 $ 282.9 $ 95.3 $ 691.3 Commercial and industrial 151.3 91.4 51.7 294.4 Total retail revenues 464.4 374.3 147.0 985.7 Transport 24.1 72.7 10.5 107.3 Other utility revenues * (29.6 ) (13.4 ) (17.7 ) (60.7 ) Total natural gas utility operating revenues $ 458.9 $ 433.6 $ 139.8 $ 1,032.3 (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 * 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) 2020 2019 Wind generation revenues $ 9.3 $ 6.2 We Power revenues * 5.5 6.4 Appliance service revenues 4.4 4.1 Distributed renewable solar project revenues 0.4 1.5 Other — 0.1 Total other non-utility operating revenues $ 19.6 $ 18.3 * 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 these 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 carrying costs to revenues over the life of the related lease term that We Power has with WE. During the three months ended March 31 , 2020 and 2019, we recorded $5.5 million and $6.4 million , respectively, of revenues 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.
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) 2020 2019 Late payment charges $ 12.1 $ 13.2 Alternative revenues * 8.5 (19.7 ) Other 1.1 7.4 Total other operating revenues $ 21.7 $ 0.9 * 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, wholesale true-ups, and conservation improvement rider true-ups, as discussed in Note 1(d), Operating Revenues, in our 2019 Annual Report on Form 10-K.

CREDIT LOSSES (Tables)

CREDIT LOSSES (Tables)	3 Months Ended
	Mar. 31, 2020
Credit Loss [Abstract]
Schedule of gross receivables and related allowances for credit losses	We have included a table below that shows our gross third-party receivable balances and the related allowance for credit losses at March 31, 2020 by reportable segment. (in millions) Wisconsin Illinois Other States Total Utility Operations Non-Utility Energy Infrastructure Corporate and Other WEC Energy Group Consolidated Accounts receivable and unbilled revenues $ 849.1 $ 404.7 $ 79.2 $ 1,333.0 $ 5.8 $ 2.9 $ 1,341.7 Allowance for credit losses 67.7 93.1 3.9 164.7 — 0.1 164.8 Accounts receivable and unbilled revenues, net $ 781.4 $ 311.6 $ 75.3 $ 1,168.3 $ 5.8 $ 2.8 $ 1,176.9 Total accounts receivable, net – past due greater than 90 days* $ 57.7 $ 35.9 $ 3.9 $ 97.5 $ — $ — $ 97.5 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms* 95.7 % 100.0 % — % 93.4 % — % — % 93.4 % * Our exposure to credit losses for certain regulated utility customers is mitigated by regulatory mechanisms we have in place. Specifically, rates related to all of the customers in our Illinois segment, as well as the residential rates of WE, WG, and WPS in our Wisconsin segment include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between the actual provision for credit losses and the amounts recovered in rates. As a result, at March 31, 2020 , $684.6 million , or 58.2% , of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. In addition, in a March 24, 2020 order, the PSCW authorized the deferral of credit losses at WE, WG, and WPS for commercial and industrial customers, to the extent these losses exceed the amount included in rates, as a result of the COVID-19 pandemic and the actions WE, WG, and WPS have been required to take to ensure essential utility services are available to customers during the public health emergency. Furthermore, pursuant to an April 15, 2020 order addressing certain impacts of the COVID-19 pandemic, the MPSC authorized all Michigan utilities to defer, for potential future recovery, uncollectible expense incurred on or after March 24, 2020 that exceeds the amounts being recovered in rates. The additional protections related to our March 31, 2020 accounts receivable and unbilled revenue balances provided by these orders are still being assessed and are not reflected in the percentages in the above table or related note. See Note 21, Regulatory Environment , for more information.
Rollforward of the allowances for credit losses by reportable segment	A rollforward of the allowance for credit losses by reportable segment is included below: (in millions) Wisconsin Illinois Other States Total Utility Operations Corporate and Other WEC Energy Group Consolidated Balance at December 31, 2019 $ 59.9 $ 75.9 $ 4.1 $ 139.9 $ 0.1 $ 140.0 Provision for credit losses 13.7 14.4 0.7 28.8 — 28.8 Provision for credit losses deferred for future recovery or refund 3.3 29.5 — 32.8 — 32.8 Write-offs charged against the allowance (19.7 ) (31.6 ) (1.3 ) (52.6 ) — (52.6 ) Recoveries of amounts previously written off 10.5 4.9 0.4 15.8 — 15.8 Balance at March 31, 2020 $ 67.7 $ 93.1 $ 3.9 $ 164.7 $ 0.1 $ 164.8

REGULATORY ASSETS AND LIABILI_2

REGULATORY ASSETS AND LIABILITIES (Tables)	3 Months Ended
	Mar. 31, 2020
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of regulatory assets	(in millions) March 31, 2020 December 31, 2019 Regulatory assets Pension and OPEB costs $ 1,042.5 $ 1,066.6 Plant retirements 851.5 856.4 Environmental remediation costs 686.4 685.5 Income tax related items 457.6 457.8 Asset retirement obligations 188.8 137.5 SSR 140.5 151.5 Uncollectible expense 83.4 52.2 Derivatives 31.8 33.8 We Power generation 18.7 25.8 Other, net 77.6 60.5 Total regulatory assets $ 3,578.8 $ 3,527.6 Balance sheet presentation Other current assets $ 12.7 $ 20.9 Regulatory assets 3,566.1 3,506.7 Total regulatory assets $ 3,578.8 $ 3,527.6
Schedule of regulatory liabilities	(in millions) March 31, 2020 December 31, 2019 Regulatory liabilities Income tax related items $ 2,222.9 $ 2,248.8 Removal costs 1,195.0 1,181.5 Pension and OPEB benefits 349.5 354.9 Energy costs refundable through rate adjustments 162.2 89.8 Electric transmission costs 51.0 42.2 Earnings sharing mechanisms 40.6 43.5 Uncollectible expense 39.0 39.1 Energy efficiency programs 35.6 30.7 Decoupling 35.0 36.8 Other, net 12.1 13.1 Total regulatory liabilities $ 4,142.9 $ 4,080.4 Balance sheet presentation Amounts refundable to customers $ 155.8 $ 87.6 Regulatory liabilities 3,987.1 3,992.8 Total regulatory liabilities $ 4,142.9 $ 4,080.4

COMMON EQUITY (Tables)

COMMON EQUITY (Tables)	3 Months Ended
	Mar. 31, 2020
Equity [Abstract]
Schedule of stock-based compensation awards granted	During the first quarter of 2020 , 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) 512,139 Restricted shares (2) 84,540 Performance units 140,455 (1) Stock options awarded had a weighted-average exercise price of $91.49 and a weighted-average grant date fair value of $10.82 per option. (2) Restricted shares awarded had a weighted-average grant date fair value of $91.49 per share.

SHORT-TERM DEBT AND LINES OF _2

SHORT-TERM DEBT AND LINES OF CREDIT (Tables)	3 Months Ended
	Mar. 31, 2020
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, 2020 December 31, 2019 Commercial paper Amount outstanding $ 487.2 $ 830.8 Weighted-average interest rate on amounts outstanding 3.03 % 2.00 % Term loan Amount outstanding $ 340.0 $ — Weighted-average interest rate on amounts outstanding 2.12 % n/a
Schedule of credit agreements and remaining available capacity	The information in the table below relates to our term loan agreement and our revolving credit facilities used to support our commercial paper borrowing programs, including available capacity under these credit agreements: (in millions) Maturity March 31, 2020 Term loan agreement (WEC Energy Group) March 2021 $ 340.0 Revolving credit facility (WEC Energy Group) October 2022 1,200.0 Revolving credit facility (WE) October 2022 500.0 Revolving credit facility (WPS) October 2022 400.0 Revolving credit facility (WG) October 2022 350.0 Revolving credit facility (PGL) October 2022 350.0 Total short-term credit capacity $ 3,140.0 Less: Letters of credit issued inside credit facilities $ 2.3 Term loan outstanding 340.0 Commercial paper outstanding 487.2 Available capacity under existing credit agreements $ 2,310.5

MATERIALS, SUPPLIES, AND INVE_2

MATERIALS, SUPPLIES, AND INVENTORIES (Tables)	3 Months Ended
	Mar. 31, 2020
Inventory Disclosure [Abstract]
Schedule of inventory	Our inventory consisted of: (in millions) March 31, 2020 December 31, 2019 Materials and supplies 230.7 234.2 Fossil fuel 92.5 87.9 Natural gas in storage 67.9 227.7 Total $ 391.1 $ 549.8

INCOME TAXES (Tables)

INCOME TAXES (Tables)	3 Months Ended
	Mar. 31, 2020
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, 2020 Three Months Ended March 31, 2019 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 113.9 21.0 % $ 101.9 21.0 % State income taxes net of federal tax benefit 34.0 6.3 % 31.0 6.4 % Federal excess deferred tax amortization – Wisconsin unprotected (22.1 ) (4.1 )% — — % Wind production tax credits (18.4 ) (3.4 )% (13.4 ) (2.8 )% Federal excess deferred tax amortization (13.0 ) (2.4 )% (13.2 ) (2.7 )% Excess tax benefits – stock options (4.9 ) (0.9 )% (7.2 ) (1.5 )% Tax repairs 1.5 0.3 % (29.6 ) (6.1 )% Other (1.0 ) (0.2 )% (4.5 ) (0.9 )% Total income tax expense $ 90.0 16.6 % $ 65.0 13.4 %

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	3 Months Ended
	Mar. 31, 2020
Fair Value Disclosures [Abstract]
Schedule of 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, 2020 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 3.9 $ 0.7 $ — $ 4.6 FTRs — — 0.9 0.9 Coal contracts — 0.3 — 0.3 Total derivative assets $ 3.9 $ 1.0 $ 0.9 $ 5.8 Investments held in rabbi trust $ 54.9 $ — $ — $ 54.9 Derivative liabilities Natural gas contracts $ 22.7 $ — $ — $ 22.7 Coal contracts — 0.1 — 0.1 Interest rate swaps — 10.0 — 10.0 Total derivative liabilities $ 22.7 $ 10.1 $ — $ 32.8 December 31, 2019 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 1.4 $ 2.0 $ — $ 3.4 FTRs — — 3.1 3.1 Coal contracts — 0.4 — 0.4 Total derivative assets $ 1.4 $ 2.4 $ 3.1 $ 6.9 Investments held in rabbi trust $ 85.3 $ — $ — $ 85.3 Derivative liabilities Natural gas contracts $ 21.4 $ 1.3 $ — $ 22.7 Coal contracts — 0.2 — 0.2 Interest rate swaps — 6.0 — 6.0 Total derivative liabilities $ 21.4 $ 7.5 $ — $ 28.9
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) 2020 2019 Balance at the beginning of the period $ 3.1 $ 7.4 Settlements (2.2 ) (4.3 ) Balance at the end of the period $ 0.9 $ 3.1
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, 2020 December 31, 2019 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock of subsidiary $ 30.4 $ 28.3 $ 30.4 $ 29.5 Long-term debt, including current portion * 11,844.8 12,920.8 11,858.3 13,035.9 * The carrying amount of long-term debt excludes finance lease obligations of $44.2 million and $45.9 million at March 31, 2020 and December 31, 2019 , respectively.

DERIVATIVE INSTRUMENTS (Tables)

DERIVATIVE INSTRUMENTS (Tables)	3 Months Ended
	Mar. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of derivative assets and liabilities	The following table shows our derivative assets and derivative liabilities, along with their classification on our balance sheets. March 31, 2020 December 31, 2019 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 3.0 $ 22.7 $ 3.4 $ 21.8 FTRs 0.9 — 3.1 — Coal contracts 0.2 0.1 0.2 0.2 Interest rate swaps — 5.1 — 2.8 Total other current * 4.1 27.9 6.7 24.8 Other long-term Natural gas contracts 1.6 — — 0.9 Coal contracts 0.1 — 0.2 — Interest rate swaps — 4.9 — 3.2 Total other long-term * 1.7 4.9 0.2 4.1 Total $ 5.8 $ 32.8 $ 6.9 $ 28.9 * 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.
Schedule of estimated notional sales volumes and realized gains (losses)	Our estimated notional sales volumes and realized gains (losses) were as follows: Three Months Ended March 31, 2020 Three Months Ended March 31, 2019 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 58.4 Dth $ (24.7 ) 56.1 Dth $ (0.5 ) FTRs 7.2 MWh 1.4 8.1 MWh 2.3 Total $ (23.3 ) $ 1.8
Schedule of net derivative instruments	The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: March 31, 2020 December 31, 2019 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 5.8 $ 32.8 $ 6.9 $ 28.9 Gross amount not offset on the balance sheet (3.9 ) (22.7 ) (1) (1.4 ) (21.4 ) (2) Net amount $ 1.9 $ 10.1 $ 5.5 $ 7.5 (1) Includes cash collateral posted of $18.8 million . (2) Includes cash collateral posted of $20.0 million .
Schedule of cash flow hedges recorded in other comprehensive loss and earnings	The table below shows the amounts related to these cash flow hedges recorded in other comprehensive loss and in earnings, along with our total interest expense on the income statements: Three Months Ended March 31 (in millions) 2020 2019 Derivative losses recognized in other comprehensive loss $ (4.7 ) $ (1.6 ) Net derivative gains (losses) reclassified from accumulated other comprehensive loss to interest expense (0.1 ) 0.4 Total interest expense line item on the income statements 129.4 124.4

GUARANTEES (Tables)

GUARANTEES (Tables)	3 Months Ended
	Mar. 31, 2020
Guarantees [Abstract]
Schedule of outstanding guarantees	The following table shows our outstanding guarantees: Expiration (in millions) Total Amounts Committed at March 31, 2020 Less Than 1 Year 1 to 3 Years Over 3 Years Guarantees Guarantees supporting transactions of subsidiaries (1) $ 31.6 $ 9.2 $ 0.2 $ 22.2 Standby letters of credit (2) 95.5 1.2 0.2 94.1 Surety bonds (3) 9.9 9.9 — — Other guarantees (4) 12.1 0.9 — 11.2 Total guarantees $ 149.1 $ 21.2 $ 0.4 $ 127.5 (1) Consists of $4.2 million , $6.2 million , and $21.2 million to support the business operations of UMERC, Bluewater, and WECI, respectively. (2) At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets. (3) Primarily for workers compensation self-insurance programs and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets. (4) Consists of $12.1 million related to other indemnifications, for which a liability of $11.2 million related to workers compensation coverage was recorded on our balance sheets.

EMPLOYEE BENEFITS (Tables)

EMPLOYEE BENEFITS (Tables)	3 Months Ended
	Mar. 31, 2020
Retirement Benefits [Abstract]
Schedule of net benefit cost (credit)	The following tables show the components of net periodic benefit cost (credit) for our benefit plans. Pension Benefits Three Months Ended March 31 (in millions) 2020 2019 Service cost $ 13.1 $ 11.3 Interest cost 26.1 30.6 Expected return on plan assets (47.9 ) (48.7 ) Loss on plan settlement 0.3 0.8 Amortization of prior service cost 0.4 0.6 Amortization of net actuarial loss 24.2 19.0 Net periodic benefit cost $ 16.2 $ 13.6 OPEB Benefits Three Months Ended March 31 (in millions) 2020 2019 Service cost $ 4.1 $ 4.4 Interest cost 4.7 6.5 Expected return on plan assets (15.1 ) (13.7 ) Amortization of prior service credit (3.7 ) (3.9 ) Amortization of net actuarial gain (5.4 ) (0.7 ) Net periodic benefit credit $ (15.4 ) $ (7.4 )

GOODWILL (Tables)

GOODWILL (Tables)	3 Months Ended
	Mar. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of changes to our goodwill balances by segment	The table below shows our goodwill balances by segment at March 31, 2020 . We had no changes to the carrying amount of goodwill during the three months ended March 31, 2020 . (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, 2020 .

INVESTMENT IN TRANSMISSION AF_2

INVESTMENT IN TRANSMISSION AFFILIATES (Tables)	3 Months Ended
	Mar. 31, 2020
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, 2020 (in millions) ATC ATC Holdco Total Balance at beginning of period $ 1,684.7 $ 36.1 $ 1,720.8 Add: Earnings from equity method investment 39.6 0.2 39.8 Add: Capital contributions 3.0 — 3.0 Less: Distributions 40.6 — 40.6 Less: Return of capital — 5.3 5.3 Balance at end of period $ 1,686.7 $ 31.0 $ 1,717.7 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
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) 2020 2019 Charges to ATC for services and construction $ 6.0 $ 4.0 Charges from ATC for network transmission services 86.9 87.1
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, 2020 December 31, 2019 Accounts receivable for services provided to ATC $ 2.6 $ 3.5 Accounts payable for services received from ATC 29.3 29.0 Amounts due from ATC for transmission infrastructure upgrades * 2.3 2.8 * In connection with WPS's construction of its two new solar projects, Badger Hollow I and Two Creeks, WPS was required to initially fund the construction of the transmission infrastructure upgrades needed for the new generation. ATC owns these transmission assets and will reimburse WPS for these costs after the new generation has been placed in service.
Schedule of summarized income statement data for ATC	Summarized financial data for ATC is included in the tables below: Three Months Ended March 31 (in millions) 2020 2019 Income statement data Operating revenues $ 186.8 $ 177.7 Operating expenses 95.2 90.4 Other expense, net 28.5 28.8 Net income $ 63.1 $ 58.5
Schedule of summarized balance sheet data for ATC	(in millions) March 31, 2020 December 31, 2019 Balance sheet data Current assets $ 82.4 $ 84.7 Noncurrent assets 5,283.2 5,244.2 Total assets $ 5,365.6 $ 5,328.9 Current liabilities $ 526.3 $ 502.6 Long-term debt 2,313.0 2,312.8 Other noncurrent liabilities 307.9 298.9 Shareholders' equity 2,218.4 2,214.6 Total liabilities and shareholders' equity $ 5,365.6 $ 5,328.9

SEGMENT INFORMATION (Tables)

SEGMENT INFORMATION (Tables)	3 Months Ended
	Mar. 31, 2020
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 , 2020 and 2019 : 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, 2020 External revenues $ 1,498.9 $ 447.6 $ 146.4 $ 2,092.9 $ — $ 15.2 $ 0.5 $ — $ 2,108.6 Intersegment revenues — — — — — 114.4 — (114.4 ) — Other operation and maintenance 330.8 104.1 21.7 456.6 — 5.2 (1.6 ) (4.5 ) 455.7 Depreciation and amortization 165.4 47.5 7.8 220.7 — 24.5 6.1 (12.2 ) 239.1 Operating income (loss) 426.8 161.6 37.4 625.8 — 91.5 (4.2 ) (86.5 ) 626.6 Equity in earnings of transmission affiliates — — — — 39.8 — — — 39.8 Interest expense 143.1 16.0 2.2 161.3 4.8 15.3 35.1 (87.1 ) 129.4 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, 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

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	3 Months Ended
	Mar. 31, 2020
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 for manufactured gas plant sites: (in millions) March 31, 2020 December 31, 2019 Regulatory assets $ 686.4 $ 685.5 Reserves for future environmental remediation 589.4 589.2

SUPPLEMENTAL CASH FLOW INFORM_2

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	3 Months Ended
	Mar. 31, 2020
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
Schedule of supplemental cash flow information	Three Months Ended March 31 (in millions) 2020 2019 Cash paid for interest, net of amount capitalized $ 85.8 $ 66.3 Cash paid (received) for income taxes, net (11.2 ) 0.2 Significant non-cash investing and financing transactions: Accounts payable related to construction costs 102.5 74.7
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 to the total of these amounts shown on the statements of cash flows: (in millions) March 31, 2020 December 31, 2019 Cash and cash equivalents $ 15.4 $ 37.5 Restricted cash included in other long term assets 50.3 44.8 Cash, cash equivalents, and restricted cash $ 65.7 $ 82.3

REGULATORY ENVIRONMENT (Tables)

REGULATORY ENVIRONMENT (Tables)	3 Months Ended
	Mar. 31, 2020
Regulated Operations [Abstract]
Schedule of decisions in regulatory proceedings	The final orders reflect the following: WE WPS WG 2020 Effective rate increase (decrease) Electric (1) (2) $ 15.3 million / 0.5% $ 15.8 million / 1.6% N/A Gas (3) $ 10.4 million / 2.8% $ 4.3 million / 1.4% $ (1.5 ) million / (0.2)% Steam $ 1.9 million / 8.6% N/A N/A ROE 10.0% 10.0% 10.2% Common equity component average on a financial basis 52.5% 52.5% 52.5% (1) Amounts are net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impact. The WE and WPS rate orders reflect the majority of the unprotected deferred tax benefits from the Tax Legislation being amortized over two years . For WE, approximately $65 million of tax benefits will be amortized in each of 2020 and 2021. For WPS, approximately $11 million of tax benefits are being amortized in 2020 and approximately $39 million will be amortized in 2021. The unprotected deferred tax benefits related to the unrecovered balances of WE's recently retired plants and its SSR regulatory asset are being used to reduce the related regulatory asset. Unprotected deferred tax benefits by their nature are eligible to be returned to customers in a manner and timeline determined to be appropriate by our regulators. (2) The WPS rate order is net of $21 million of refunds related to its 2018 earnings sharing mechanism. These refunds will be made to customers evenly over two years , with half being returned in 2020 and the remainder in 2021. (3) The WE amount includes certain deferred tax expense from the Tax Legislation, and the WPS and WG amounts are net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impact. The rate orders for all three gas utilities reflect all of the unprotected deferred tax expense and benefits from the Tax Legislation being amortized evenly over four years . For WE, approximately $5 million of previously deferred tax expense will be amortized each year. For WPS and WG, approximately $5 million and $3 million , respectively, of previously deferred tax benefits will be amortized each year. Unprotected deferred tax expense and benefits by their nature are eligible to be recovered from or returned to customers in a manner and timeline determined to be appropriate by our regulators.

GENERAL INFORMATION - GENERAL (

GENERAL INFORMATION - GENERAL (Details) customer in Millions	Mar. 31, 2020customer
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, 2020
ATC
Schedule of Investments [Line Items]
Equity method investment, ownership interest (as a percent)	60.00%

ACQUISITIONS - THUNDERHEAD (Det

ACQUISITIONS - THUNDERHEAD (Details) - Thunderhead - WECI $ in Millions	1 Months Ended
	Aug. 31, 2019USD ($)MW	Feb. 19, 2020USD ($)
Business Acquisition [Line Items]
Ownership interest of wind generating facility acquired	80.00%
Capacity of generation unit | MW	300
Acquisition purchase price | $	$ 338	$ 43
Additional ownership interest acquired		10.00%
Duration of offtake agreement for the sale of energy produced	12 years
Bonus depreciation percentage	100.00%

ACQUISITIONS - UPSTREAM (Detail

ACQUISITIONS - UPSTREAM (Details) - Upstream - WECI $ in Millions	1 Months Ended
	Jan. 31, 2019USD ($)MW	Apr. 30, 2020USD ($)
Business Acquisition [Line Items]
Ownership interest of wind generating facility acquired	80.00%
Capacity of generation unit | 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%
Allocation of the purchase price
Current assets	$ 1.5
Net property, plant, and equipment	341.6
Other long-term assets	22.9
Current liabilities	(4.6)
Long-term liabilities	(15)
Noncontrolling interest	(69)
Total purchase price	277.4
Restricted cash	$ 8.1
Subsequent event
Business Acquisition [Line Items]
Acquisition purchase price		$ 31
Additional ownership interest acquired		10.00%

ACQUISITIONS - BLOOMING GROVE (

ACQUISITIONS - BLOOMING GROVE (Details) - Blooming Grove - WECI $ in Millions	Feb. 19, 2020USD ($)	Jan. 27, 2020USD ($)MW
Business Acquisition [Line Items]
Ownership interest of wind generating facility acquired		80.00%
Capacity of generation unit | MW		250
Acquisition purchase price | $	$ 44	$ 345
Additional ownership interest acquired	10.00%
Bonus depreciation percentage		100.00%

OPERATING REVENUES - DISAGGREGA

OPERATING REVENUES - DISAGGREGATION OF OPERATING REVENUES BY SEGMENT (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Disaggregation of Operating Revenues
Operating revenues	$ 2,108.6	$ 2,377.4
Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	2,086.9	2,376.5
Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	21.7	0.9
Total utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	2,067.3	2,358.2
Electric | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,034.6	1,061.8
Natural gas | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,032.7	1,296.4
Other non-utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	19.6	18.3
Total Utility Operations
Disaggregation of Operating Revenues
Operating revenues	2,092.9	2,355.1
Total Utility Operations | Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	21.6	(5.6)
Total Utility Operations | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	2,071.3	2,360.7
Total Utility Operations | Total utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	2,066.9	2,356.5
Total Utility Operations | Electric | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,034.6	1,061.8
Total Utility Operations | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,032.3	1,294.7
Total Utility Operations | Other non-utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	4.4	4.2
Wisconsin
Disaggregation of Operating Revenues
Operating revenues	1,498.9	1,633.4
Wisconsin | Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	5.4	6.7
Wisconsin | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,493.5	1,626.7
Wisconsin | Total utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,493.5	1,626.7
Wisconsin | Electric | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,034.6	1,061.8
Wisconsin | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	458.9	564.9
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	447.6	536.5
Illinois | Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	14	(8.2)
Illinois | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	433.6	544.7
Illinois | Total utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	433.6	544.6
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	433.6	544.6
Illinois | Other non-utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0.1
Other States
Disaggregation of Operating Revenues
Operating revenues	146.4	185.2
Other States | Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	2.2	(4.1)
Other States | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	144.2	189.3
Other States | Total utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	139.8	185.2
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	139.8	185.2
Other States | Other non-utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	4.4	4.1
Non-Utility Energy Infrastructure
Disaggregation of Operating Revenues
Operating revenues	129.6	127.8
Non-Utility Energy Infrastructure | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	30.9	29.7
Non-Utility Energy Infrastructure | Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	98.7	98.1
Non-Utility Energy Infrastructure | Total utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	14.5	16.4
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	14.5	16.4
Non-Utility Energy Infrastructure | Other non-utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	16.4	13.3
Corporate and Other
Disaggregation of Operating Revenues
Operating revenues	0.5	1.7
Corporate and Other | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0.4	1.5
Corporate and Other | Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	0.1	0.2
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	0.4	1.5
Reconciling Eliminations
Disaggregation of Operating Revenues
Operating revenues	(114.4)	(107.2)
Reconciling Eliminations | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	(15.7)	(15.4)
Reconciling Eliminations | Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	(98.7)	(91.8)
Reconciling Eliminations | Total utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	(14.1)	(14.7)
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	(14.1)	(14.7)
Reconciling Eliminations | Other non-utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ (1.6)	$ (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, 2020	Mar. 31, 2019
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 2,086.9	$ 2,376.5
Electric
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,034.6	1,061.8
Wisconsin | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,493.5	1,626.7
Wisconsin | Electric | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,034.6	1,061.8
Wisconsin | Electric | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	930.4	960.7
Wisconsin | Electric | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	404.9	406.7
Wisconsin | Electric | Transferred over time | Small commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	323.6	333.9
Wisconsin | Electric | Transferred over time | Large commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	194.6	212.3
Wisconsin | Electric | Transferred over time | Other
Disaggregation of Operating Revenues
Revenues from contracts with customers	7.3	7.8
Wisconsin | Electric | Transferred over time | Wholesale
Disaggregation of Operating Revenues
Revenues from contracts with customers	42.1	47.7
Wisconsin | Electric | Transferred over time | Resale
Disaggregation of Operating Revenues
Revenues from contracts with customers	45.2	40.8
Wisconsin | Electric | Transferred over time | Steam
Disaggregation of Operating Revenues
Revenues from contracts with customers	8.4	10.1
Wisconsin | Electric | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 8.5	$ 2.5

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, 2020	Mar. 31, 2019
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 2,086.9	$ 2,376.5
Natural gas
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,032.7	1,296.4
Total Utility Operations | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	2,071.3	2,360.7
Total Utility Operations | Natural gas | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,032.3	1,294.7
Total Utility Operations | Natural gas | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	985.7	1,251
Total Utility Operations | Natural gas | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	691.3	863.1
Total Utility Operations | Natural gas | Transferred over time | Commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	294.4	387.9
Total Utility Operations | Natural gas | Transferred over time | Transport
Disaggregation of Operating Revenues
Revenues from contracts with customers	107.3	120.2
Total Utility Operations | Natural gas | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	(60.7)	(76.5)
Wisconsin | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,493.5	1,626.7
Wisconsin | Natural gas | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	458.9	564.9
Wisconsin | Natural gas | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	464.4	583.6
Wisconsin | Natural gas | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	313.1	383.9
Wisconsin | Natural gas | Transferred over time | Commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	151.3	199.7
Wisconsin | Natural gas | Transferred over time | Transport
Disaggregation of Operating Revenues
Revenues from contracts with customers	24.1	21.9
Wisconsin | Natural gas | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	(29.6)	(40.6)
Illinois | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	433.6	544.7
Illinois | Natural gas | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	433.6	544.6
Illinois | Natural gas | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	374.3	470.2
Illinois | Natural gas | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	282.9	354
Illinois | Natural gas | Transferred over time | Commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	91.4	116.2
Illinois | Natural gas | Transferred over time | Transport
Disaggregation of Operating Revenues
Revenues from contracts with customers	72.7	87.2
Illinois | Natural gas | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	(13.4)	(12.8)
Other States | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	144.2	189.3
Other States | Natural gas | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	139.8	185.2
Other States | Natural gas | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	147	197.2
Other States | Natural gas | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	95.3	125.2
Other States | Natural gas | Transferred over time | Commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	51.7	72
Other States | Natural gas | Transferred over time | Transport
Disaggregation of Operating Revenues
Revenues from contracts with customers	10.5	11.1
Other States | Natural gas | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ (17.7)	$ (23.1)

OPERATING REVENUES - OTHER NON-

OPERATING REVENUES - OTHER NON-UTILITY OPERATING REVENUES (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
We Power revenues
Disaggregation of Operating Revenues
Revenues amortized from deferred revenue during the period	$ 5.5	$ 6.4
Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	2,086.9	2,376.5
Other non-utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	19.6	18.3
Other non-utility revenues | Revenues from contracts with customers | We Power revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	5.5	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	0.4	1.5
Other non-utility revenues | Revenues from contracts with customers | Other
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0.1
Transferred over time | Other non-utility revenues | Revenues from contracts with customers | Wind generation revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	9.3	6.2
Transferred over time | Other non-utility revenues | Revenues from contracts with customers | Appliance service repairs
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 4.4	$ 4.1

OPERATING REVENUES - OTHER OPER

OPERATING REVENUES - OTHER OPERATING REVENUES (Details) - Other operating revenues - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Disaggregation of Operating Revenues
Other operating revenues	$ 21.7	$ 0.9
Late payment charges
Disaggregation of Operating Revenues
Other operating revenues	12.1	13.2
Alternative revenues
Disaggregation of Operating Revenues
Other operating revenues	8.5	(19.7)
Other
Disaggregation of Operating Revenues
Other operating revenues	$ 1.1	$ 7.4

CREDIT LOSSES - GROSS RECEIVABL

CREDIT LOSSES - GROSS RECEIVABLES AND RELATED ALLOWANCES (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Dec. 31, 2019
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable and unbilled revenues	$ 1,341.7
Allowance for credit losses	164.8	$ 140
Accounts receivable and unbilled revenues, net	1,176.9
Total accounts receivable, net - past due greater than 90 days	$ 97.5
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms	93.40%
Amount of net accounts receivable with regulatory protections	$ 684.6
Percent of net accounts receivable with regulatory protections	58.20%
Wisconsin
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable and unbilled revenues	$ 849.1
Allowance for credit losses	67.7	59.9
Accounts receivable and unbilled revenues, net	781.4
Total accounts receivable, net - past due greater than 90 days	$ 57.7
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms	95.70%
Illinois
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable and unbilled revenues	$ 404.7
Allowance for credit losses	93.1	75.9
Accounts receivable and unbilled revenues, net	311.6
Total accounts receivable, net - past due greater than 90 days	$ 35.9
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms	100.00%
Other States
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable and unbilled revenues	$ 79.2
Allowance for credit losses	3.9	4.1
Accounts receivable and unbilled revenues, net	75.3
Total accounts receivable, net - past due greater than 90 days	$ 3.9
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms	0.00%
Total Utility Operations
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable and unbilled revenues	$ 1,333
Allowance for credit losses	164.7	139.9
Accounts receivable and unbilled revenues, net	1,168.3
Total accounts receivable, net - past due greater than 90 days	$ 97.5
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms	93.40%
Non-Utility Energy Infrastructure
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable and unbilled revenues	$ 5.8
Allowance for credit losses	0
Accounts receivable and unbilled revenues, net	5.8
Total accounts receivable, net - past due greater than 90 days	$ 0
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms	0.00%
Corporate and Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable and unbilled revenues	$ 2.9
Allowance for credit losses	0.1	$ 0.1
Accounts receivable and unbilled revenues, net	2.8
Total accounts receivable, net - past due greater than 90 days	$ 0
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms	0.00%
COVID-19
Accounts, Notes, Loans and Financing Receivable [Line Items]
Increase in allowance for credit loss	$ 2.7

CREDIT LOSSES - ROLLFORWARD OF

CREDIT LOSSES - ROLLFORWARD OF ALLOWANCES (Details) $ in Millions	3 Months Ended
	Mar. 31, 2020USD ($)
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at December 31, 2019	$ 140
Provision for credit losses	28.8
Provision for credit losses deferred for future recovery or refund	32.8
Write-offs charged against the allowance	(52.6)
Recovery of amounts previously written off	15.8
Balance at March 31, 2020	164.8
Wisconsin
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at December 31, 2019	59.9
Provision for credit losses	13.7
Provision for credit losses deferred for future recovery or refund	3.3
Write-offs charged against the allowance	(19.7)
Recovery of amounts previously written off	10.5
Balance at March 31, 2020	67.7
Illinois
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at December 31, 2019	75.9
Provision for credit losses	14.4
Provision for credit losses deferred for future recovery or refund	29.5
Write-offs charged against the allowance	(31.6)
Recovery of amounts previously written off	4.9
Balance at March 31, 2020	93.1
Other States
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at December 31, 2019	4.1
Provision for credit losses	0.7
Provision for credit losses deferred for future recovery or refund	0
Write-offs charged against the allowance	(1.3)
Recovery of amounts previously written off	0.4
Balance at March 31, 2020	3.9
Total Utility Operations
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at December 31, 2019	139.9
Provision for credit losses	28.8
Provision for credit losses deferred for future recovery or refund	32.8
Write-offs charged against the allowance	(52.6)
Recovery of amounts previously written off	15.8
Balance at March 31, 2020	164.7
Corporate and Other
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at December 31, 2019	0.1
Provision for credit losses	0
Provision for credit losses deferred for future recovery or refund	0
Write-offs charged against the allowance	0
Recovery of amounts previously written off	0
Balance at March 31, 2020	$ 0.1

REGULATORY ASSETS AND LIABILI_3

REGULATORY ASSETS AND LIABILITIES - REGULATORY ASSETS (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Regulatory assets
Other current assets	$ 12.7	$ 20.9
Regulatory assets	3,566.1	3,506.7
Total regulatory assets	3,578.8	3,527.6
Pension and OPEB costs
Regulatory assets
Total regulatory assets	1,042.5	1,066.6
Plant retirements
Regulatory assets
Total regulatory assets	851.5	856.4
Environmental remediation costs
Regulatory assets
Total regulatory assets	686.4	685.5
Income tax related items
Regulatory assets
Total regulatory assets	457.6	457.8
Asset retirement obligations
Regulatory assets
Total regulatory assets	188.8	137.5
SSR
Regulatory assets
Total regulatory assets	140.5	151.5
Uncollectible expense
Regulatory assets
Total regulatory assets	83.4	52.2
Derivatives
Regulatory assets
Total regulatory assets	31.8	33.8
We Power generation
Regulatory assets
Total regulatory assets	18.7	25.8
Other, net
Regulatory assets
Total regulatory assets	$ 77.6	$ 60.5

REGULATORY ASSETS AND LIABILI_4

REGULATORY ASSETS AND LIABILITIES - REGULATORY LIABILITIES (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Regulatory liabilities
Amounts refundable to customers	$ 155.8	$ 87.6
Regulatory liabilities	3,987.1	3,992.8
Total regulatory liabilities	4,142.9	4,080.4
Income tax related items
Regulatory liabilities
Total regulatory liabilities	2,222.9	2,248.8
Removal costs
Regulatory liabilities
Total regulatory liabilities	1,195	1,181.5
Pension and OPEB benefits
Regulatory liabilities
Total regulatory liabilities	349.5	354.9
Energy costs refundable through rate adjustments
Regulatory liabilities
Total regulatory liabilities	162.2	89.8
Electric transmission costs
Regulatory liabilities
Total regulatory liabilities	51	42.2
Earnings sharing mechanisms
Regulatory liabilities
Total regulatory liabilities	40.6	43.5
Uncollectible expense
Regulatory liabilities
Total regulatory liabilities	39	39.1
Energy efficiency programs
Regulatory liabilities
Total regulatory liabilities	35.6	30.7
Decoupling
Regulatory liabilities
Total regulatory liabilities	35	36.8
Other, net
Regulatory liabilities
Total regulatory liabilities	$ 12.1	$ 13.1

COMMON EQUITY - STOCK-BASED COM

COMMON EQUITY - STOCK-BASED COMPENSATION AWARDS GRANTED (Details)	3 Months Ended
	Mar. 31, 2020$ / sharesshares
Stock options
Stock-based compensation
Stock options granted | shares	512,139
Stock options granted, weighted average exercise price | $ / shares	$ 91.49
Stock options granted, weighted-average grant date fair value | $ / shares	$ 10.82
Restricted shares
Stock-based compensation
Awards granted | shares	84,540
Restricted shares granted, weighted-average grant date fair value | $ / shares	$ 91.49
Performance units
Stock-based compensation
Awards granted | shares	140,455

COMMON EQUITY - COMMON STOCK DI

COMMON EQUITY - COMMON STOCK DIVIDENDS (Details) - $ / shares	3 Months Ended
	Jun. 30, 2020	Mar. 31, 2020	Mar. 31, 2019
Dividends payable
Quarterly cash dividend declared (in dollars per share)		$ 0.6325	$ 0.59
Subsequent event
Dividends payable
Quarterly cash dividend declared (in dollars per share)	$ 0.6325

SHORT-TERM DEBT AND LINES OF _3

SHORT-TERM DEBT AND LINES OF CREDIT - SHORT-TERM BORROWINGS (Details) - USD ($) $ in Millions	Mar. 30, 2020	Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2019
Short-term borrowings
Issuance of term loan		$ 340	$ 0
Commercial paper
Short-term borrowings
Commercial paper outstanding		$ 487.2		$ 830.8
Weighted-average interest rate on amounts outstanding		3.03%		2.00%
Average amount outstanding during the period		$ 843.8
Weighted-average interest rate during the period		1.88%
Term loan
Short-term borrowings
Term loan outstanding		$ 340		$ 0
Weighted-average interest rate on amounts outstanding		2.12%
Issuance of term loan	$ 340
Length of term loan	364 days

SHORT-TERM DEBT AND LINES OF _4

SHORT-TERM DEBT AND LINES OF CREDIT - REVOLVING CREDIT FACILITIES (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Revolving credit facilities
Short-term credit capacity	$ 3,140
Letters of credit issued inside credit facilities	2.3
Available capacity under existing credit facility	2,310.5
Term loan
Revolving credit facilities
Term loan outstanding	340	$ 0
Commercial paper
Revolving credit facilities
Commercial paper outstanding	487.2	$ 830.8
WE | Credit facility maturing October 2022
Revolving credit facilities
Short-term credit capacity	500
WPS | Credit facility maturing October 2022
Revolving credit facilities
Short-term credit capacity	400
WG | Credit facility maturing October 2022
Revolving credit facilities
Short-term credit capacity	350
PGL | Credit facility maturing October 2022
Revolving credit facilities
Short-term credit capacity	350
WEC Energy Group | Term loan agreement maturing March 2021
Revolving credit facilities
Short-term credit capacity	340
WEC Energy Group | Credit facility maturing October 2022
Revolving credit facilities
Short-term credit capacity	$ 1,200

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details) - Subsequent event $ in Millions	Apr. 29, 2020USD ($)
MERC | MERC Senior Notes 2.69% due May 1, 2025
Debt Instrument [Line Items]
Proceeds from Issuance of Debt	$ 50
Debt instrument stated interest rate percentage	2.69%
MGU | MGU Senior Notes 2.69% due May 1, 2025
Debt Instrument [Line Items]
Proceeds from Issuance of Debt	$ 60
Debt instrument stated interest rate percentage	2.69%

MATERIALS, SUPPLIES, AND INVE_3

MATERIALS, SUPPLIES, AND INVENTORIES (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Energy Related Inventory
Materials and supplies	$ 230.7	$ 234.2
Fossil fuel	92.5	87.9
Natural gas in storage	67.9	227.7
Total	391.1	$ 549.8
LIFO Method Related Items
LIFO liquidation debit	$ 11.3

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Effective Income Tax Rate Reconciliation, Amount
Statutory federal income tax, amount	$ 113.9	$ 101.9
State income taxes net of federal tax benefit, amount	34	31
Federal excess deferred tax amortization - Wisconsin unprotected, amount	(22.1)	0
Wind production tax credits, amount	(18.4)	(13.4)
Federal excess deferred tax amortization, amount	(13)	(13.2)
Excess tax benefits-stock options, amount	(4.9)	(7.2)
Tax repairs, amount	1.5	(29.6)
Other, amount	(1)	(4.5)
Total income tax expense, amount	$ 90	$ 65
Effective Income Tax Rate Reconciliation, Percent
Statutory federal income tax, percentage	21.00%	21.00%
State income taxes net of federal tax benefit, percentage	6.30%	6.40%
Federal excess deferred tax amortization - Wisconsin unprotected, percentage	(4.10%)	0.00%
Wind production tax credits, percentage	(3.40%)	(2.80%)
Federal excess deferred tax amortization, percentage	(2.40%)	(2.70%)
Excess tax benefits-stock options, percentage	(0.90%)	(1.50%)
Tax repairs, percentage	0.30%	(6.10%)
Other, percentage	(0.20%)	(0.90%)
Total income tax expense, percentage	16.60%	13.40%

INCOME TAXES - WI 2020 and 2021

INCOME TAXES - WI 2020 and 2021 RATES (Details) - Tax Cuts and Jobs Act of 2017 - Public Service Commission of Wisconsin (PSCW) - 2020 and 2021 rates	1 Months Ended
	Dec. 31, 2019
Electric rates
Income Taxes [Line Items]
Amortization period	2 years
Natural gas rates
Income Taxes [Line Items]
Amortization period	4 years

FAIR VALUE MEASUREMENTS - ASSET

FAIR VALUE MEASUREMENTS - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Assets
Derivative assets	$ 5.8	$ 6.9
Liabilities
Derivative liabilities	32.8	28.9
Fair value measurements on a recurring basis
Assets
Derivative assets	5.8	6.9
Investments held in rabbi trust	54.9	85.3
Liabilities
Derivative liabilities	32.8	28.9
Fair value measurements on a recurring basis | Level 1
Assets
Derivative assets	3.9	1.4
Investments held in rabbi trust	54.9	85.3
Liabilities
Derivative liabilities	22.7	21.4
Fair value measurements on a recurring basis | Level 2
Assets
Derivative assets	1	2.4
Investments held in rabbi trust	0	0
Liabilities
Derivative liabilities	10.1	7.5
Fair value measurements on a recurring basis | Level 3
Assets
Derivative assets	0.9	3.1
Investments held in rabbi trust	0	0
Liabilities
Derivative liabilities	0	0
Fair value measurements on a recurring basis | Natural gas contracts
Assets
Derivative assets	4.6	3.4
Liabilities
Derivative liabilities	22.7	22.7
Fair value measurements on a recurring basis | Natural gas contracts | Level 1
Assets
Derivative assets	3.9	1.4
Liabilities
Derivative liabilities	22.7	21.4
Fair value measurements on a recurring basis | Natural gas contracts | Level 2
Assets
Derivative assets	0.7	2
Liabilities
Derivative liabilities	0	1.3
Fair value measurements on a recurring basis | Natural gas contracts | Level 3
Assets
Derivative assets	0	0
Liabilities
Derivative liabilities	0	0
Fair value measurements on a recurring basis | FTRs
Assets
Derivative assets	0.9	3.1
Fair value measurements on a recurring basis | FTRs | Level 1
Assets
Derivative assets	0	0
Fair value measurements on a recurring basis | FTRs | Level 2
Assets
Derivative assets	0	0
Fair value measurements on a recurring basis | FTRs | Level 3
Assets
Derivative assets	0.9	3.1
Fair value measurements on a recurring basis | Coal contracts
Assets
Derivative assets	0.3	0.4
Liabilities
Derivative liabilities	0.1	0.2
Fair value measurements on a recurring basis | Coal contracts | Level 1
Assets
Derivative assets	0	0
Liabilities
Derivative liabilities	0	0
Fair value measurements on a recurring basis | Coal contracts | Level 2
Assets
Derivative assets	0.3	0.4
Liabilities
Derivative liabilities	0.1	0.2
Fair value measurements on a recurring basis | Coal contracts | Level 3
Assets
Derivative assets	0	0
Liabilities
Derivative liabilities	0	0
Fair value measurements on a recurring basis | Interest rate swaps
Liabilities
Derivative liabilities	10	6
Fair value measurements on a recurring basis | Interest rate swaps | Level 1
Liabilities
Derivative liabilities	0	0
Fair value measurements on a recurring basis | Interest rate swaps | Level 2
Liabilities
Derivative liabilities	10	6
Fair value measurements on a recurring basis | Interest rate swaps | Level 3
Liabilities
Derivative liabilities	$ 0	$ 0

FAIR VALUE MEASUREMENTS - UNREA

FAIR VALUE MEASUREMENTS - UNREALIZED GAIN (LOSS) ON INVESTMENTS (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Fair Value Disclosures [Abstract]
Net unrealized losses included in earnings related to investments held at end of period	$ 14.2
Net unrealized gains included in earnings related to investments held at end of period		$ 8.6

FAIR VALUE MEASUREMENTS - LEVEL

FAIR VALUE MEASUREMENTS - LEVEL 3 RECONCILIATION (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Level 3 rollforward
Balance at the beginning of the period	$ 3.1	$ 7.4
Settlements	(2.2)	(4.3)
Balance at the end of the period	$ 0.9	$ 3.1

FAIR VALUE MEASUREMENTS - FINAN

FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Financial instruments
Preferred stock of subsidiary	$ 30.4	$ 30.4
Carrying amount
Financial instruments
Preferred stock of subsidiary	30.4	30.4
Long-term debt, including current portion	11,844.8	11,858.3
Finance lease obligations	44.2	45.9
Fair value
Financial instruments
Preferred stock of subsidiary	28.3	29.5
Long-term debt, including current portion	$ 12,920.8	$ 13,035.9

DERIVATIVE INSTRUMENTS - DERIVA

DERIVATIVE INSTRUMENTS - DERIVATIVE ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Derivative assets
Other current derivative assets	$ 4.1	$ 6.7
Other long-term derivative assets	1.7	0.2
Total derivative assets	5.8	6.9
Derivative liabilities
Other current derivative liabilities	27.9	24.8
Other long-term derivative liabilities	4.9	4.1
Total derivative liabilities	32.8	28.9
Natural gas contracts
Derivative assets
Other current derivative assets	3	3.4
Other long-term derivative assets	1.6	0
Derivative liabilities
Other current derivative liabilities	22.7	21.8
Other long-term derivative liabilities	0	0.9
FTRs
Derivative assets
Other current derivative assets	0.9	3.1
Derivative liabilities
Other current derivative liabilities	0	0
Coal contracts
Derivative assets
Other current derivative assets	0.2	0.2
Other long-term derivative assets	0.1	0.2
Derivative liabilities
Other current derivative liabilities	0.1	0.2
Other long-term derivative liabilities	0	0
Interest rate swaps
Derivative assets
Other current derivative assets	0	0
Other long-term derivative assets	0	0
Derivative liabilities
Other current derivative liabilities	5.1	2.8
Other long-term derivative liabilities	$ 4.9	$ 3.2

DERIVATIVE INSTRUMENTS - GAINS

DERIVATIVE INSTRUMENTS - GAINS (LOSSES) AND NOTIONAL VOLUMES (Details) MWh in Millions, MMBTU in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2020USD ($)MMBTUMWh	Mar. 31, 2019USD ($)MMBTUMWh
Realized gains (losses)
Gains (losses)	$ (23.3)	$ 1.8
Natural gas contracts
Realized gains (losses)
Gains (losses)	$ (24.7)	$ (0.5)
Notional sales volumes
Notional sales volumes | MMBTU	58.4	56.1
FTRs
Realized gains (losses)
Gains (losses)	$ 1.4	$ 2.3
Notional sales volumes
Notional sales volumes | MWh	7.2	8.1

DERIVATIVE INSTRUMENTS - BALANC

DERIVATIVE INSTRUMENTS - BALANCE SHEET OFFSETTING (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Cash collateral
Cash collateral posted in margin accounts	$ 28.8	$ 34.4
Offsetting derivative assets
Gross amount recognized on the balance sheet	5.8	6.9
Gross amount not offset on the balance sheet	(3.9)	(1.4)
Net amount	1.9	5.5
Offsetting derivative liabilities
Gross amount recognized on the balance sheet	32.8	28.9
Gross amount not offset on the balance sheet	(22.7)	(21.4)
Net amount	10.1	7.5
Collateral posted	$ 18.8	$ 20

DERIVATIVE INSTRUMENTS - CASH F

DERIVATIVE INSTRUMENTS - CASH FLOW HEDGES (Details) $ in Millions	3 Months Ended
	Mar. 31, 2020USD ($)number_of_interest_rate_swaps	Mar. 31, 2019USD ($)
Derivative instruments
Interest expense	$ 129.4	$ 124.4
WEC Energy Group | WEC Energy Group's Junior Subordinated Notes due in 2067
Derivative instruments
Long-term debt outstanding	$ 500
WEC Energy Group | Interest rate swaps
Derivative instruments
Number of interest rate swaps | number_of_interest_rate_swaps	2
Interest rate swap notional value	$ 250
Interest rate swap fixed interest rate	4.9765%
Derivative losses recognized in other comprehensive loss	$ (4.7)	(1.6)
Net derivative gains (losses) reclassified from accumulated other comprehensive loss to interest expense	(0.1)	$ 0.4
Amount to be reclassified from accumulated other comprehensive loss to interest expense	$ 3.5

GUARANTEES (Details)

GUARANTEES (Details) $ in Millions	Mar. 31, 2020USD ($)
Guarantees
Total guarantees	$ 149.1
Guarantees expiring in less than 1 year	21.2
Guarantees expiring within 1 to 3 years	0.4
Guarantees with expiration over 3 years	127.5
Guarantees supporting commodity transactions of subsidiaries
Guarantees
Total guarantees	31.6
Guarantees expiring in less than 1 year	9.2
Guarantees expiring within 1 to 3 years	0.2
Guarantees with expiration over 3 years	22.2
Standby letters of credit
Guarantees
Total guarantees	95.5
Guarantees expiring in less than 1 year	1.2
Guarantees expiring within 1 to 3 years	0.2
Guarantees with expiration over 3 years	94.1
Surety bonds
Guarantees
Total guarantees	9.9
Guarantees expiring in less than 1 year	9.9
Guarantees expiring within 1 to 3 years	0
Guarantees with expiration over 3 years	0
Other guarantees
Guarantees
Total guarantees	12.1
Guarantees expiring in less than 1 year	0.9
Guarantees expiring within 1 to 3 years	0
Guarantees with expiration over 3 years	11.2
Other indemnifications
Guarantees
Total guarantees	12.1
Liability related to workers compensation coverage	11.2
UMERC | Guarantees supporting commodity transactions of subsidiaries
Guarantees
Total guarantees	4.2
Bluewater | Guarantees supporting commodity transactions of subsidiaries
Guarantees
Total guarantees	6.2
WECI | Guarantees supporting commodity transactions of subsidiaries
Guarantees
Total guarantees	$ 21.2

EMPLOYEE BENEFITS-COSTS AND CON

EMPLOYEE BENEFITS-COSTS AND CONTRIBUTIONS (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Components of net periodic benefit cost
Contributions and payments related to pension and OPEB plans	$ 3.7	$ 4.2
Pension Benefits
Components of net periodic benefit cost
Service cost	13.1	11.3
Interest cost	26.1	30.6
Expected return on plan assets	(47.9)	(48.7)
Loss on plan settlement	0.3	0.8
Amortization of prior service (credit) cost	0.4	0.6
Amortization of net actuarial (gain) loss	24.2	19
Net periodic benefit (credit) cost	16.2	13.6
Contributions and payments related to pension and OPEB plans	3.5
Estimated future employer contributions for the remainder of the year	8
Other Postretirement Benefits
Components of net periodic benefit cost
Service cost	4.1	4.4
Interest cost	4.7	6.5
Expected return on plan assets	(15.1)	(13.7)
Amortization of prior service (credit) cost	(3.7)	(3.9)
Amortization of net actuarial (gain) loss	(5.4)	(0.7)
Net periodic benefit (credit) cost	(15.4)	$ (7.4)
Contributions and payments related to pension and OPEB plans	0.2
Estimated future employer contributions for the remainder of the year	$ 0.8

GOODWILL (Details)

GOODWILL (Details) $ in Millions	3 Months Ended
	Mar. 31, 2020USD ($)
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, 2020	Mar. 31, 2019
Changes to investments in transmission affiliates
Investment in transmission affiliates, balance at beginning of period	$ 1,720.8	$ 1,665.3
Add: Earnings (loss) from equity method investment	39.8	36.1
Add: Capital contributions	3	3.4
Less: Distributions	40.6	34.2
Less: Return of capital	5.3
Investment in transmission affiliates, balance at end of period	$ 1,717.7	1,670.6
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	$ 1,684.7	1,625.3
Add: Earnings (loss) from equity method investment	39.6	36.5
Add: Capital contributions	3	3
Less: Distributions	40.6	34.2
Less: Return of capital	0
Investment in transmission affiliates, balance at end of period	$ 1,686.7	1,630.6
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	$ 36.1	40
Add: Earnings (loss) from equity method investment	0.2	(0.4)
Add: Capital contributions	0	0.4
Less: Distributions	0	0
Less: Return of capital	5.3
Investment in transmission affiliates, balance at end of period	$ 31	$ 40

INVESTMENT IN TRANSMISSION AF_4

INVESTMENT IN TRANSMISSION AFFILIATES - RELATED PARTY TRANSACTIONS (Details) - ATC - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Investment in transmission affiliates
Charges to ATC for services and construction	$ 6	$ 4
Charges from ATC for network transmission services	$ 86.9	$ 87.1

INVESTMENT IN TRANSMISSION AF_5

INVESTMENT IN TRANSMISSION AFFILIATES - RELATED PARTY TRANSACTIONS BALANCE SHEET INFORMATION (Details) $ in Millions	Mar. 31, 2020USD ($)solar_projects	Dec. 31, 2019USD ($)
WPS
Investment in transmission affiliates
Number of new solar projects | solar_projects	2
ATC
Investment in transmission affiliates
Accounts receivable for services provided to ATC	$ 2.6	$ 3.5
Accounts payable for services received from ATC	29.3	29
Amounts due from ATC for transmission infrastructure upgrades	$ 2.3	$ 2.8

INVESTMENT IN TRANSMISSION AF_6

INVESTMENT IN TRANSMISSION AFFILIATES - SUMMARIZED FINANCIAL DATA (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2019
Income statement data
Operating revenues	$ 2,108.6	$ 2,377.4
Operating expenses	1,482	1,834.6
Other expense, net	84	57.4
Balance sheet data
Current assets	1,845.3		$ 2,093.6
Noncurrent assets	32,986.9		32,858.2
Total assets	34,832.2		34,951.8
Current liabilities	2,847.7		3,182.7
Other noncurrent liabilities	1,106		1,128.9
Total liabilities and shareholders' equity	34,832.2		34,951.8
ATC
Income statement data
Operating revenues	186.8	177.7
Operating expenses	95.2	90.4
Other expense, net	28.5	28.8
Net income	63.1	$ 58.5
Balance sheet data
Current assets	82.4		84.7
Noncurrent assets	5,283.2		5,244.2
Total assets	5,365.6		5,328.9
Current liabilities	526.3		502.6
Long-term debt	2,313		2,312.8
Other noncurrent liabilities	307.9		298.9
Shareholders' equity	2,218.4		2,214.6
Total liabilities and shareholders' equity	$ 5,365.6		$ 5,328.9

SEGMENT INFORMATION (Details)

SEGMENT INFORMATION (Details) $ in Millions	3 Months Ended
	Mar. 31, 2020USD ($)segment	Mar. 31, 2019USD ($)
Segment information
Number of reportable segments | segment	6
Operating revenues	$ 2,108.6	$ 2,377.4
Other operation and maintenance	455.7	550.6
Depreciation and amortization	239.1	226.4
Operating income (loss)	626.6	542.8
Equity in earnings of transmission affiliates	39.8	36.1
Interest expense	129.4	124.4
Wisconsin
Segment information
Operating revenues	1,498.9	1,633.4
Illinois
Segment information
Operating revenues	447.6	536.5
Other States
Segment information
Operating revenues	146.4	185.2
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	39.8	36.1
Interest expense	$ 4.8	2.6
Non-Utility Energy Infrastructure
Segment information
Natural gas storage needs provided to Wisconsin utilities	33.00%
Operating revenues	$ 129.6	127.8
Other operation and maintenance	5.2	3.8
Depreciation and amortization	24.5	22.6
Operating income (loss)	91.5	92.7
Equity in earnings of transmission affiliates	0	0
Interest expense	15.3	15.7
Corporate and Other
Segment information
Operating revenues	0.5	1.7
Other operation and maintenance	(1.6)	(1)
Depreciation and amortization	6.1	6.4
Operating income (loss)	(4.2)	(3.9)
Equity in earnings of transmission affiliates	0	0
Interest expense	35.1	35.1
Reconciling Eliminations
Segment information
Other operation and maintenance	(4.5)	(0.7)
Depreciation and amortization	(12.2)	(4.6)
Operating income (loss)	(86.5)	(87.2)
Equity in earnings of transmission affiliates	0	0
Interest expense	$ (87.1)	(89.5)
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	$ 0.2	(0.4)
ATC Holdco | Electric Transmission
Segment information
Equity method investment, ownership interest (as a percent)	75.00%
Bishop Hill III | Non-Utility Energy Infrastructure
Segment information
WEC's ownership interest in Bishop Hill III Wind Energy Center	90.00%
Coyote Ridge | Non-Utility Energy Infrastructure
Segment information
WEC's ownership interest in Coyote Ridge Wind, LLC	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	$ 456.6	548.5
Depreciation and amortization	220.7	202
Operating income (loss)	625.8	541.2
Equity in earnings of transmission affiliates	0	0
Interest expense	161.3	160.5
Total utility revenues | Wisconsin
Segment information
Other operation and maintenance	330.8	392.7
Depreciation and amortization	165.4	151
Operating income (loss)	426.8	361.8
Equity in earnings of transmission affiliates	0	0
Interest expense	143.1	143.4
Total utility revenues | Illinois
Segment information
Other operation and maintenance	104.1	128.2
Depreciation and amortization	47.5	44.5
Operating income (loss)	161.6	137.9
Equity in earnings of transmission affiliates	0	0
Interest expense	16	14.8
Total utility revenues | Other States
Segment information
Other operation and maintenance	21.7	27.6
Depreciation and amortization	7.8	6.5
Operating income (loss)	37.4	41.5
Equity in earnings of transmission affiliates	0	0
Interest expense	2.2	2.3
External Revenues
Segment information
Operating revenues	2,108.6	2,377.4
External Revenues | Electric Transmission
Segment information
Operating revenues	0	0
External Revenues | Non-Utility Energy Infrastructure
Segment information
Operating revenues	15.2	20.6
External Revenues | Corporate and Other
Segment information
Operating revenues	0.5	1.7
External Revenues | Reconciling Eliminations
Segment information
Operating revenues	0	0
External Revenues | Total utility revenues
Segment information
Operating revenues	2,092.9	2,355.1
External Revenues | Total utility revenues | Wisconsin
Segment information
Operating revenues	1,498.9	1,633.4
External Revenues | Total utility revenues | Illinois
Segment information
Operating revenues	447.6	536.5
External Revenues | Total utility revenues | Other States
Segment information
Operating revenues	146.4	185.2
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	114.4	107.2
Intersegment Transactions [Member] | Corporate and Other
Segment information
Operating revenues	0	0
Intersegment Transactions [Member] | Reconciling Eliminations
Segment information
Operating revenues	(114.4)	(107.2)
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, 2020USD ($)MW	Dec. 31, 2019USD ($)	Mar. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Variable interest entities
Equity investment	$ 1,717.7	$ 1,720.8	$ 1,670.6	$ 1,665.3
ATC
Variable interest entities
Ownership interest (as a percent)	60.00%
Equity investment	$ 1,686.7	1,684.7
ATC Holdco
Variable interest entities
Ownership interest (as a percent)	75.00%
Equity investment	$ 31	$ 36.1
Power purchase agreement
Variable interest entities
Firm capacity from power purchase agreement (in megawatts) | MW	236
Minimum energy requirements over remaining term of power purchase agreement (in megawatts) | MW	0
Remaining term of power purchase agreement (in years)	2 years
Residual guarantee associated with power purchase agreement	$ 0
Required payments over remaining term of power purchase agreement	$ 20.2

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Billions	Mar. 31, 2020USD ($)
Minimum future commitments for purchase obligations
Purchase obligations	$ 11.2

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) $ in Millions	1 Months Ended		3 Months Ended	15 Months Ended
	Apr. 30, 2019degreecelsius	Dec. 31, 2018change	Mar. 31, 2020USD ($)generating_unitsStates	Mar. 31, 2019MW	Dec. 31, 2019USD ($)
Manufactured gas plant remediation
Regulatory assets			$ 3,578.8		$ 3,527.6
Environmental remediation costs
Manufactured gas plant remediation
Regulatory assets			$ 686.4		685.5
Mercury and Air Toxics Standards | Electric
Air quality
Revisions to Mercury and Air Toxics Standards | change		0
Climate Change | Electric
Air quality
Number of states challenging the ACE rule | States			22
Company goal for percentage of carbon dioxide emissions reduction by 2030				40.00%
Capacity of coal generation retired, in megawatts | MW				1,800
Per mile rate of methane emission reduction			30.00%
Climate Change | Electric | Maximum
Air quality
Global temperature increases limit | degreecelsius	2
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			$ 60
Manufactured Gas Plant Remediation | Natural gas
Manufactured gas plant remediation
Reserves for future environmental remediation			589.4		589.2
Manufactured Gas Plant Remediation | Natural gas | Environmental remediation costs
Manufactured gas plant remediation
Regulatory assets			$ 686.4		$ 685.5

SUPPLEMENTAL CASH FLOW INFORM_3

SUPPLEMENTAL CASH FLOW INFORMATION - SUPPLEMENTAL INFORMATION (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Supplemental cash flow information
Cash paid for interest, net of amount capitalized	$ 85.8	$ 66.3
Cash paid (received) for income taxes, net	(11.2)	0.2
Significant non-cash investing and financing transactions
Accounts payable related to construction costs	$ 102.5	$ 74.7

SUPPLEMENTAL CASH FLOW INFORM_4

SUPPLEMENTAL CASH FLOW INFORMATION - RECONCILIATION OF CASH AND CASH EQUIVALENTS AND RESTRICTED CASH (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019	Mar. 31, 2019	Dec. 31, 2018
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
Cash and cash equivalents	$ 15.4	$ 37.5
Restricted cash included in other long term assets	50.3	44.8
Cash, cash equivalents, and restricted cash	$ 65.7	$ 82.3	$ 89.1	$ 146.1

REGULATORY ENVIRONMENT - COVID-

REGULATORY ENVIRONMENT - COVID-19 (Details)	1 Months Ended
	Mar. 31, 2020order
Public Service Commission of Wisconsin (PSCW)
Public Utilities, General Disclosures [Line Items]
Number of orders issued in response to COVID-19	2
Illinois Commerce Commission (ICC)
Public Utilities, General Disclosures [Line Items]
Minimum period of time required for flexible credit and collection procedures	6 months

REGULATORY ENVIRONMENT - WI 202

REGULATORY ENVIRONMENT - WI 2020 AND 2021 RATES (Details) - Public Service Commission of Wisconsin (PSCW) $ in Millions	1 Months Ended
	Dec. 31, 2019USD ($)utility	Sep. 30, 2017USD ($)
2020 and 2021 rates
Public Utilities, General Disclosures [Line Items]
Number of utilities with earnings sharing mechanism | utility	3
Percentage of first 25 basis points of additional earnings retained by the utility	100.00%
Return on equity in excess of authorized amount (as a percent)	0.25%
Percentage of additional earnings between 25 and 75 basis points refunded to customers	50.00%
Return on equity in excess of first 25 basis points above authorized amount (as a percent)	0.50%
Percentage of earnings in excess of 75 basis points refunded to customers	100.00%
Electric rates | 2020 and 2021 rates | Tax Cuts and Jobs Act of 2017
Public Utilities, General Disclosures [Line Items]
Amortization period	2 years
Natural gas rates | 2020 and 2021 rates | Tax Cuts and Jobs Act of 2017
Public Utilities, General Disclosures [Line Items]
Amortization period	4 years
Number of gas utilities amortizing unprotected deferred tax expense over 4 years | utility	3
WE | 2020 and 2021 rates
Public Utilities, General Disclosures [Line Items]
Approved return on equity (as a percent)	10.00%
Approved common equity component average (as a percent)	52.50%
WE | Electric rates | 2020 rates
Public Utilities, General Disclosures [Line Items]
Approved rate increase	$ 15.3
Approved rate increase (as a percent)	0.50%
WE | Electric rates | 2020 rates | Tax Cuts and Jobs Act of 2017
Public Utilities, General Disclosures [Line Items]
Amortization of regulatory liabilities	$ 65
WE | Electric rates | 2021 rates | Tax Cuts and Jobs Act of 2017
Public Utilities, General Disclosures [Line Items]
Amortization of regulatory liabilities	65
WE | Electric rates | 2020 and 2021 rates
Public Utilities, General Disclosures [Line Items]
Pleasant Prairie power plant's book value to be securitized	100
WE | Natural gas rates | 2020 rates
Public Utilities, General Disclosures [Line Items]
Approved rate increase	$ 10.4
Approved rate increase (as a percent)	2.80%
WE | Natural gas rates | 2020 rates | Tax Cuts and Jobs Act of 2017
Public Utilities, General Disclosures [Line Items]
Amortization of regulatory liabilities	$ (5)
WE | Natural gas rates | 2021 rates | Tax Cuts and Jobs Act of 2017
Public Utilities, General Disclosures [Line Items]
Amortization of regulatory liabilities	(5)
WE | Steam rates | 2020 rates
Public Utilities, General Disclosures [Line Items]
Approved rate increase	$ 1.9
Approved rate increase (as a percent)	8.60%
WPS | 2020 and 2021 rates
Public Utilities, General Disclosures [Line Items]
Approved return on equity (as a percent)	10.00%
Approved common equity component average (as a percent)	52.50%
WPS | Electric rates | 2020 rates
Public Utilities, General Disclosures [Line Items]
Approved rate increase	$ 15.8
Approved rate increase (as a percent)	1.60%
WPS | Electric rates | 2020 rates | Tax Cuts and Jobs Act of 2017
Public Utilities, General Disclosures [Line Items]
Amortization of regulatory liabilities	$ 11
WPS | Electric rates | 2021 rates | Tax Cuts and Jobs Act of 2017
Public Utilities, General Disclosures [Line Items]
Amortization of regulatory liabilities	39
WPS | Electric rates | 2020 and 2021 rates
Public Utilities, General Disclosures [Line Items]
Authorized Revenue Requirement For ReACT		$ 275
Cost of the ReACT project	$ 342
WPS | Electric rates | 2020 and 2021 rates | ReACT
Public Utilities, General Disclosures [Line Items]
Collection of ReACT Regulatory Asset in Years	8 years
WPS | Electric rates | 2020 and 2021 rates | Earnings sharing mechanisms
Public Utilities, General Disclosures [Line Items]
Amortization period	2 years
Amortization of regulatory liabilities	$ 21
WPS | Natural gas rates | 2020 rates
Public Utilities, General Disclosures [Line Items]
Approved rate increase	$ 4.3
Approved rate increase (as a percent)	1.40%
WPS | Natural gas rates | 2020 rates | Tax Cuts and Jobs Act of 2017
Public Utilities, General Disclosures [Line Items]
Amortization of regulatory liabilities	$ 5
WPS | Natural gas rates | 2021 rates | Tax Cuts and Jobs Act of 2017
Public Utilities, General Disclosures [Line Items]
Amortization of regulatory liabilities	$ 5
WG | 2020 and 2021 rates
Public Utilities, General Disclosures [Line Items]
Approved return on equity (as a percent)	10.20%
Approved common equity component average (as a percent)	52.50%
WG | Natural gas rates | 2020 rates
Public Utilities, General Disclosures [Line Items]
Approved rate increase	$ (1.5)
Approved rate increase (as a percent)	(0.20%)
WG | Natural gas rates | 2020 rates | Tax Cuts and Jobs Act of 2017
Public Utilities, General Disclosures [Line Items]
Amortization of regulatory liabilities	$ 3
WG | Natural gas rates | 2021 rates | Tax Cuts and Jobs Act of 2017
Public Utilities, General Disclosures [Line Items]
Amortization of regulatory liabilities	$ 3

REGULATORY ENVIRONMENT - WI 201

REGULATORY ENVIRONMENT - WI 2018 AND 2019 RATES (Details) - Public Service Commission of Wisconsin (PSCW) - 2018 and 2019 rates $ in Millions	1 Months Ended	24 Months Ended
	Sep. 30, 2017USD ($)utility	Dec. 31, 2019USD ($)
Public Utilities, General Disclosures [Line Items]
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%
WE
Public Utilities, General Disclosures [Line Items]
Approved return on equity (as a percent)	10.20%
Income statement impact of flow through of repair-related deferred tax liabilities		$ 0
WPS
Public Utilities, General Disclosures [Line Items]
Approved return on equity (as a percent)	10.00%
Authorized Revenue Requirement For ReACT	$ 275
WG
Public Utilities, General Disclosures [Line Items]
Approved return on equity (as a percent)	10.30%

REGULATORY ENVIRONMENT - WI LIQ

REGULATORY ENVIRONMENT - WI LIQUEFIED NATURAL GAS FACILITIES (Details) - Public Service Commission of Wisconsin (PSCW) - Liquefied Natural Gas Facilities $ in Millions	Nov. 01, 2019USD ($)Bcf
Public Utilities, General Disclosures [Line Items]
Estimated project costs | $	$ 370
WE
Public Utilities, General Disclosures [Line Items]
Natural gas supply	1
WG
Public Utilities, General Disclosures [Line Items]
Natural gas supply	1

REGULATORY ENVIRONMENT - WI SOL

REGULATORY ENVIRONMENT - WI SOLAR GENERATION PROJECTS (Details) - Public Service Commission of Wisconsin (PSCW) - WE - Badger Hollow Solar Farm II $ in Millions	Mar. 01, 2020USD ($)MW
Public Utilities, General Disclosures [Line Items]
Solar project output that approval was requested for from the PSCW (in megawatts) | MW	100
Estimated project costs | $	$ 130

REGULATORY ENVIRONMENT - PGL (D

REGULATORY ENVIRONMENT - PGL (Details)	Mar. 31, 2020Assurance
Illinois Commerce Commission (ICC) | PGL
Public Utilities, General Disclosures [Line Items]
Amount of assurance that PGL's QIP rider costs will be recoverable	0