Wisconsin Electric Power Company PFD 3.60% (WELPP) 10-Q 6 Aug 20 2020 Q2 Quarterly report Financial data

COVER PAGE

COVER PAGE	6 Months Ended
	Jun. 30, 2020shares
Cover [Abstract]
Document type	10-Q
Document Quarterly Report	true
Document period end date	Jun. 30, 2020
Document Transition Report	false
Entity File Number	001-01245
Entity registrant name	WISCONSIN ELECTRIC POWER COMPANY
Entity Tax Identification Number	39-0476280
Entity Incorporation, State or Country Code	WI
Entity Address, Address Line One	231 West Michigan Street
Entity Address, Address Line Two	P.O. Box 2046
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
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity filer category	Non-accelerated Filer
Small business	false
Emerging growth company	false
Entity Shell Company	false
Entity common stock, shares outstanding	33,289,327
Entity central index key	0000107815
Current fiscal year end date	--12-31
Document fiscal year focus	2020
Document fiscal period focus	Q2
Amendment flag	false

CONDENSED INCOME STATEMENTS

CONDENSED INCOME STATEMENTS - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Income Statement [Abstract]
Operating revenues	$ 769.5	$ 791.7	$ 1,640.5	$ 1,752.5
Operating expenses
Cost of sales	235.6	253.5	524.8	610.7
Other operation and maintenance	214.3	234.3	418.9	493.2
Depreciation and amortization	106.2	95.2	210.7	191.2
Property and revenue taxes	24.8	26.1	50.5	51.9
Total operating expenses	580.9	609.1	1,204.9	1,347
Operating income	188.6	182.6	435.6	405.5
Other income, net	4.9	5.9	10.2	11.4
Interest expense	116.6	119.6	235.2	239.5
Other expense	(111.7)	(113.7)	(225)	(228.1)
Income before income taxes	76.9	68.9	210.6	177.4
Income tax expense (benefit)	6	(16.3)	20.7	(22.8)
Net income	70.9	85.2	189.9	200.2
Preferred stock dividend requirements	0.3	0.3	0.6	0.6
Net income attributed to common shareholder	$ 70.6	$ 84.9	$ 189.3	$ 199.6

CONDENSED BALANCE SHEETS

CONDENSED BALANCE SHEETS - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Current assets
Cash and cash equivalents	$ 2	$ 19.1
Accounts receivable and unbilled revenues, net of reserves of $45.7 and $38.1, respectively	427.1	434.6
Accounts receivable from related parties	45.2	86.5
Materials, supplies, and inventories	220	229.8
Prepaid taxes	93.4	104.4
Other	18.6	33.6
Current assets	806.3	908
Assets, Noncurrent [Abstract]
Property, plant, and equipment, net of accumulated depreciation and amortization of $4,725.3 and $4,564.0, respectively	9,680.5	9,586.7
Regulatory assets	2,767.8	2,755.2
Other	100.6	110.9
Long-term assets	12,548.9	12,452.8
Total assets	13,355.2	13,360.8
Current liabilities
Short-term debt	27	115.5
Current portion of finance lease obligations	62.2	57.8
Accounts payable	231	267.6
Accounts payable to related parties	145.6	184.5
Accrued payroll and benefits	45.2	51.3
Accrued taxes	58.3	12.3
Other	99	105.6
Current liabilities	668.3	794.6
Liabilities, Noncurrent [Abstract]
Long-term debt	2,760	2,759.2
Finance lease obligations	2,796.9	2,783.1
Deferred income taxes	1,355.5	1,347.4
Regulatory liabilities	1,726.9	1,744.2
Pension and OPEB obligations	49.8	59.8
Other	271.5	281
Long-term liabilities	8,960.6	8,974.7
Commitments and contingencies (Note 16)
Equity [Abstract]
Common stock – $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding	332.9	332.9
Additional paid in capital	995	929.5
Retained earnings	2,368	2,298.7
Common shareholder's equity	3,695.9	3,561.1
Preferred stock	30.4	30.4
Total liabilities and equity	$ 13,355.2	$ 13,360.8

CONDENSED BALANCE SHEETS (PAREN

CONDENSED BALANCE SHEETS (PARENTHETICALS) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Statement of Financial Position [Abstract]
Accounts receivable and unbilled revenues, reserves	$ 45.7	$ 38.1
Property, plant, and equipment, accumulated depreciation	$ 4,725.3	$ 4,564
Common stock, par value (in dollars per share)	$ 10	$ 10
Common stock, shares authorized	65,000,000	65,000,000
Common stock, shares outstanding	33,289,327	33,289,327

CONDENSED STATEMENTS OF CASH FL

CONDENSED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019
Operating activities
Net income	$ 189.9	$ 200.2
Reconciliation to cash provided by operating activities
Depreciation and amortization	210.7	191.2
Deferred income taxes and investment tax credits, net	(26.5)	(42.6)
Change in –
Accounts receivable and unbilled revenues	49.2	112.9
Materials, supplies, and inventories	9.8	13.4
Prepaid taxes	11	25.1
Other current assets	16.4	(9.2)
Accounts payable	(67.2)	(98.5)
Accrued taxes	46	(0.3)
Other current liabilities	(8.6)	(16.8)
Other, net	30.4	60
Net cash provided by operating activities	461.1	435.4
Investing activities
Capital expenditures	(311.1)	(230.4)
Other, net	5.4	5.1
Net cash used in investing activities	(305.7)	(225.3)
Financing activities
Change in short-term debt	(88.5)	(95.4)
Payments for finance lease obligations	(28.2)	(24.4)
Equity contribution from parent	65	105
Payment of dividends to parent	(120)	(210)
Other, net	(0.8)	(0.9)
Net cash used in financing activities	(172.5)	(225.7)
Net change in cash and cash equivalents	(17.1)	(15.6)
Cash and cash equivalents at beginning of period	19.1	20.2
Cash and cash equivalents at end of period	$ 2	$ 4.6

CONDENSED STATEMENTS OF EQUITY

CONDENSED STATEMENTS OF EQUITY - USD ($) $ in Millions	Total	Total common shareholder's equity	Common stock	Additional paid in capital	Retained earnings	Preferred stock
Balance at Dec. 31, 2018	$ 3,491.2	$ 3,460.8	$ 332.9	$ 831.3	$ 2,296.6	$ 30.4
Statements of equity
Net income attributed to common shareholder	114.7	114.7	0	0	114.7	0
Payment of dividends to parent	(150)	(150)	0	0	(150)	0
Stock-based compensation and other	0.2	0.2	0	0.2	0	0
Balance at Mar. 31, 2019	3,456.1	3,425.7	332.9	831.5	2,261.3	30.4
Balance at Dec. 31, 2018	3,491.2	3,460.8	332.9	831.3	2,296.6	30.4
Statements of equity
Net income attributed to common shareholder	199.6
Equity contribution from parent	105
Balance at Jun. 30, 2019	3,578.7	3,548.3	332.9	929.2	2,286.2	30.4
Balance at Mar. 31, 2019	3,456.1	3,425.7	332.9	831.5	2,261.3	30.4
Statements of equity
Net income attributed to common shareholder	84.9	84.9	0	0	84.9	0
Payment of dividends to parent	(60)	(60)	0	0	(60)	0
Equity contribution from parent	105	105	0	105	0	0
Transfer of net assets to UMERC	(7.3)	(7.3)	0	(7.3)	0	0
Balance at Jun. 30, 2019	3,578.7	3,548.3	332.9	929.2	2,286.2	30.4
Balance at Dec. 31, 2019	3,591.5	3,561.1	332.9	929.5	2,298.7	30.4
Statements of equity
Net income attributed to common shareholder	118.7	118.7	0	0	118.7	0
Payment of dividends to parent	(60)	(60)	0	0	(60)	0
Stock-based compensation and other	0.5	0.5	0	0.5	0	0
Balance at Mar. 31, 2020	3,650.7	3,620.3	332.9	930	2,357.4	30.4
Balance at Dec. 31, 2019	3,591.5	3,561.1	332.9	929.5	2,298.7	30.4
Statements of equity
Net income attributed to common shareholder	189.3
Equity contribution from parent	65
Balance at Jun. 30, 2020	3,726.3	3,695.9	332.9	995	2,368	30.4
Balance at Mar. 31, 2020	3,650.7	3,620.3	332.9	930	2,357.4	30.4
Statements of equity
Net income attributed to common shareholder	70.6	70.6	0	0	70.6	0
Payment of dividends to parent	(60)	(60)	0	0	(60)	0
Equity contribution from parent	65	65	0	65	0	0
Balance at Jun. 30, 2020	$ 3,726.3	$ 3,695.9	$ 332.9	$ 995	$ 2,368	$ 30.4

GENERAL INFORMATION

GENERAL INFORMATION	6 Months Ended
	Jun. 30, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
GENERAL INFORMATION	GENERAL INFORMATION Wisconsin Electric Power Company serves approximately 1.1 million electric customers and 0.5 million natural gas customers. As used in these notes, the term "financial statements" refers to the condensed financial statements. This includes the income statements, 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 Wisconsin Electric Power Company. 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 and six months ended June 30, 2020 are not necessarily indicative of expected results for 2020 due to seasonal variations and other factors, including any continuing financial impacts 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.

OPERATING REVENUES

OPERATING REVENUES	6 Months Ended
	Jun. 30, 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 for our utility segment. We do not have any revenues associated with our other segment. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors. 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. Wisconsin Electric Power Company Three Months Ended June 30 Six Months Ended June 30 (in millions) 2020 2019 2020 2019 Electric utility $ 707.3 $ 723.7 $ 1,436.3 $ 1,502.5 Natural gas utility 61.9 64.7 200.9 242.6 Total revenues from contracts with customers 769.2 788.4 1,637.2 1,745.1 Other operating revenues 0.3 3.3 3.3 7.4 Total operating revenues $ 769.5 $ 791.7 $ 1,640.5 $ 1,752.5 Revenues from Contracts with Customers Electric Utility Operating Revenues The following table disaggregates electric utility operating revenues into customer class: Electric Utility Operating Revenues Three Months Ended June 30 Six Months Ended June 30 (in millions) 2020 2019 2020 2019 Residential $ 312.4 $ 266.5 $ 607.4 $ 569.1 Small commercial and industrial 222.5 241.9 458.5 487.0 Large commercial and industrial 122.8 139.4 245.7 295.4 Other 4.6 4.9 9.7 10.5 Total retail revenues 662.3 652.7 1,321.3 1,362.0 Wholesale 18.0 20.1 37.7 49.0 Resale 22.0 41.8 61.2 73.1 Steam 4.1 4.3 12.5 14.4 Other utility revenues 0.9 4.8 3.6 4.0 Total electric utility operating revenues $ 707.3 $ 723.7 $ 1,436.3 $ 1,502.5 Natural Gas Utility Operating Revenues The following table disaggregates natural gas utility operating revenues into customer class: Natural Gas Utility Operating Revenues Three Months Ended June 30 Six Months Ended June 30 (in millions) 2020 2019 2020 2019 Residential $ 39.2 $ 35.4 $ 138.7 $ 161.0 Commercial and industrial 13.0 14.1 57.3 75.0 Total retail revenues 52.2 49.5 196.0 236.0 Transport 3.5 2.9 8.5 7.2 Other utility revenues (1) 6.2 12.3 (3.6) (0.6) Total natural gas utility operating revenues $ 61.9 $ 64.7 $ 200.9 $ 242.6 (1) Includes amounts collected from (refunded to) customers for purchased gas adjustment costs. Other Operating Revenues Other operating revenues consist primarily of the following: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2020 2019 2020 2019 Rental revenues $ 1.6 $ 1.5 $ 2.3 $ 2.2 Late payment charges (1) — 2.0 2.7 4.7 Alternative revenues (2) (1.3) (0.2) (1.7) 0.5 Total other operating revenues $ 0.3 $ 3.3 $ 3.3 $ 7.4 (1) The reduction in late payment charges is a result of a regulatory order from the PSCW in response to the COVID-19 pandemic, which includes the suspension of late payment charges during a designated time period. See Note 18, Regulatory Environment, for more information. (2) 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 wholesale customers subject to true-up, as discussed in Note 1(d), Operating Revenues, in our 2019 Annual Report on Form 10-K.

CREDIT LOSSES

CREDIT LOSSES	6 Months Ended
	Jun. 30, 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 generated from the sale of electricity and natural gas by our regulated utility operations. Our regulated utility operations are included in our utility segment. No accounts receivable and unbilled revenue balances were reported in the other segment at June 30, 2020. 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. The increase recorded to our allowance for credit losses at June 30, 2020, specific to the economic risks associated with the COVID-19 pandemic not already reflected in our calculated reserve, was not significant. We will continue to monitor the economic impacts of COVID-19 and the resulting effects 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 18, Regulatory Environment, for information on certain regulatory actions that were and/or 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 related allowance for credit losses. (in millions) June 30, 2020 Accounts receivable and unbilled revenues $ 472.8 Allowance for credit losses 45.7 Accounts receivable and unbilled revenues, net (1) $ 427.1 Total accounts receivable, net – past due greater than 90 days (1) $ 41.3 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 95.8 % (1) Our exposure to credit losses for certain regulated utility customers is mitigated by a regulatory mechanism we have in place. Specifically, our residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. As a result, at June 30, 2020, $204.4 million, or 47.9%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. In addition, in its March 24, 2020 order, the PSCW authorized the deferral of credit losses for our 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 related actions we have been required to take to ensure essential utility services are available to customers during this public health emergency. As a result, our exposure to credit losses related to certain commercial and industrial accounts receivable and unbilled revenue balances were also mitigated by regulatory protections at June 30, 2020, but are not included in the percentages in the above table or this note as we continue to assess the impacts of the order. See Note 18, Regulatory Environment, for more information. A rollforward of the allowance for credit losses is included below: (in millions) Six Months Ended June 30, 2020 Balance at December 31, 2019 $ 38.1 Provision for credit losses 13.7 Provision for credit losses deferred for future recovery or refund 3.5 Write-offs charged against the allowance (21.6) Recoveries of amounts previously written off 12.0 Balance at June 30, 2020 $ 45.7 The increase in the allowance for credit losses was driven by an increase in past due accounts receivable balances from December 31, 2019 to June 30, 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. However, as a result of the COVID-19 pandemic, we are still unable to disconnect any of our customers. See Note 18, Regulatory Environment, for more information.

REGULATORY ASSETS AND LIABILITI

REGULATORY ASSETS AND LIABILITIES	6 Months Ended
	Jun. 30, 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 June 30, 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) June 30, 2020 December 31, 2019 Regulatory assets Finance leases $ 958.7 $ 930.5 Plant retirements 776.6 788.8 Pension and OPEB costs 440.8 459.4 Income tax related items 398.6 403.2 SSR 138.8 151.5 Other, net 54.3 21.8 Total regulatory assets $ 2,767.8 $ 2,755.2 (in millions) June 30, 2020 December 31, 2019 Regulatory liabilities Income tax related items $ 847.3 $ 888.1 Removal costs 666.3 654.7 Pension and OPEB benefits 116.6 120.4 Electric transmission costs 54.6 38.6 Uncollectible expense 25.3 28.8 Energy costs refundable through rate adjustments 22.3 12.3 Other, net 9.2 13.3 Total regulatory liabilities $ 1,741.6 $ 1,756.2 Balance sheet presentation Other current liabilities $ 14.7 $ 12.0 Regulatory liabilities 1,726.9 1,744.2 Total regulatory liabilities $ 1,741.6 $ 1,756.2

COMMON EQUITY

COMMON EQUITY	6 Months Ended
	Jun. 30, 2020
Equity [Abstract]
COMMON EQUITY	COMMON EQUITY Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to WEC Energy Group in the form of cash dividends, loans, or advances. In addition, Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group or its subsidiaries. See Note 8, 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.

SHORT-TERM DEBT AND LINES OF CR

SHORT-TERM DEBT AND LINES OF CREDIT	6 Months Ended
	Jun. 30, 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) June 30, 2020 December 31, 2019 Commercial paper Amount outstanding $ 27.0 $ 115.5 Weighted-average interest rate on amounts outstanding 0.16 % 2.03 % Our average amount of commercial paper borrowings based on daily outstanding balances during the six months ended June 30, 2020 was $82.8 million with a weighted-average interest rate during the period of 1.71%. The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including available capacity under this facility: (in millions) Maturity June 30, 2020 Revolving credit facility October 2022 $ 500.0 Less: Letters of credit issued inside credit facility $ 1.0 Commercial paper outstanding 27.0 Available capacity under existing credit facility $ 472.0

LEASES

LEASES	6 Months Ended
	Jun. 30, 2020
Leases [Abstract]
Leases	LEASES See Note 12, Leases, in our 2019 Annual Report on Form 10-K for information related to the power plants we lease from We Power. As new capital projects are completed at these plants, our lease payments to We Power increase. In addition to increases in our lease payments to We Power, we also entered into lease agreements associated with our investment in Badger Hollow II in the second quarter of 2020, as discussed below. We have partnered with an unaffiliated utility to construct the Badger Hollow II wind generation facility in Iowa County, Wisconsin. Once constructed, we will own 100 MW of the output of this facility. The PSCW approved the acquisition of Badger Hollow II in March 2020 and commercial operation is targeted for December 2022. Related to our investment in Badger Hollow II, we, along with an unaffiliated utility partner, entered into several land leases in Iowa County, Wisconsin that commenced in the second quarter of 2020. The leases are for a total of approximately 1,500 acres of land. Each lease has an initial construction term that ends upon achieving commercial operation, then automatically extends for 25 years with an option for an additional 25-year extension. We expect the optional extension to be exercised, and, as a result, the land leases are being amortized over the extended term of the leases. The lease payments will be recovered through rates. Our total obligation under the land related finance leases for Badger Hollow II was $22.8 million at June 30, 2020, and will decrease to zero over the remaining lives of the leases. Long-term lease liabilities related to our finance leases for Badger Hollow II were included in finance lease obligations on the balance sheets. Our finance lease right of use asset related to Badger Hollow II was $22.8 million as of June 30, 2020, and was included in property, plant, and equipment on our balance sheets. In accordance with Accounting Standard Codification Subtopic 980-842, Regulated Operations – Leases (Subtopic 980-842), the expense recognition pattern associated with the Badger Hollow II leases resembles that of an operating lease, as amortization of the right of use assets has been modified from what would typically be recorded for a finance lease under Topic 842. The difference between the minimum lease payments and the sum of imputed interest and unadjusted amortization costs calculated under Topic 842 is deferred as a regulatory asset in accordance with Subtopic 980-842 on our balance sheet. At June 30, 2020, our weighted-average discount rate for the Badger Hollow II finance leases was 3.44%. We used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments. Future minimum lease payments and the corresponding present value of our net minimum lease payments under the finance leases for Badger Hollow II as of June 30, 2020, were as follows: (in millions) Six months ended December 31, 2020 $ 0.2 2021 0.3 2022 0.3 2023 0.7 2024 0.7 2025 0.7 Thereafter 55.0 Total minimum lease payments 57.9 Less:Interest (35.1) Present value of minimum lease payments 22.8 Less: Short-term lease liabilities — Long-term lease liabilities $ 22.8

MATERIALS, SUPPLIES, AND INVENT

MATERIALS, SUPPLIES, AND INVENTORIES	6 Months Ended
	Jun. 30, 2020
Inventory Disclosure [Abstract]
MATERIALS, SUPPLIES, AND INVENTORIES	MATERIALS, SUPPLIES, AND INVENTORIES Our inventory consisted of: (in millions) June 30, 2020 December 31, 2019 Materials and supplies $ 152.3 $ 148.3 Fossil fuel 49.6 51.1 Natural gas in storage 18.1 30.4 Total $ 220.0 $ 229.8 Substantially all 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	6 Months Ended
	Jun. 30, 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 June 30, 2020 Three Months Ended June 30, 2019 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 16.1 21.0 % $ 14.4 21.0 % State income taxes net of federal tax benefit 4.9 6.4 % 4.5 6.6 % Tax repairs — — % (30.5) (44.3) % Federal excess deferred tax amortization – Wisconsin unprotected (9.4) (12.2) % — — % Federal excess deferred tax amortization (5.1) (6.7) % (3.8) (5.6) % Wind production tax credits (2.4) (3.1) % (2.2) (3.2) % Other 1.9 2.4 % 1.3 1.8 % Total income tax expense (benefit) $ 6.0 7.8 % $ (16.3) (23.7) % Six Months Ended June 30, 2020 Six Months Ended June 30, 2019 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 44.1 21.0 % $ 37.1 21.0 % State income taxes net of federal tax benefit 13.5 6.4 % 11.6 6.6 % Tax repairs 1.3 0.6 % (60.1) (33.9) % Federal excess deferred tax amortization – Wisconsin unprotected (22.9) (10.9) % — — % Federal excess deferred tax amortization (12.4) (5.9) % (10.0) (5.7) % Wind production tax credits (5.7) (2.7) % (5.0) (2.8) % Other 2.8 1.3 % 3.6 1.9 % Total income tax expense (benefit) $ 20.7 9.8 % $ (22.8) (12.9) % The effective tax rates of 7.8% and 9.8% for the three and six months ended June 30, 2020, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to the recognition of certain unprotected deferred tax benefits created as a result of the Tax Legislation. In accordance with the rate order received from the PSCW in December 2019, we are amortizing the unprotected deferred tax benefits over periods ranging from two years to four years, to reduce near-term rate impacts to our customers. In addition, the impact of the protected benefits associated with the Tax Legislation, as discussed in more detail below, and wind production tax credits drove a decrease in the effective tax rate, which was partially offset by state income taxes. The effective tax rates of (23.7)% and (12.9)% for the three and six months ended June 30, 2019, respectively, differ 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, the impact of the protected benefits associated with the Tax Legislation, as discussed in more detail below, and wind production tax credits, partially offset by state income taxes. The Tax Legislation, signed into law in December 2017, required us to remeasure the deferred income taxes at our utility segment and we began to amortize the resulting excess protected deferred income taxes beginning in 2018 in accordance with normalization requirements (see federal excess deferred tax amortization line above). See Note 18, Regulatory Environment, for more information.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	6 Months Ended
	Jun. 30, 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: June 30, 2020 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 1.1 $ — $ — $ 1.1 FTRs — — 2.8 2.8 Total derivative assets $ 1.1 $ — $ 2.8 $ 3.9 Derivative liabilities Natural gas contracts $ 2.8 $ — $ — $ 2.8 Coal contracts — 0.1 — 0.1 Total derivative liabilities $ 2.8 $ 0.1 $ — $ 2.9 December 31, 2019 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.4 $ — $ — $ 0.4 FTRs — — 1.5 1.5 Coal contracts — 0.1 — 0.1 Total derivative assets $ 0.4 $ 0.1 $ 1.5 $ 2.0 Derivative liabilities Natural gas contracts $ 5.2 $ — $ — $ 5.2 Coal contracts — 0.2 — 0.2 Total derivative liabilities $ 5.2 $ 0.2 $ — $ 5.4 The derivative assets and liabilities listed in the tables above include options, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy and Operating Reserves Markets. The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2020 2019 2020 2019 Balance at the beginning of the period $ 0.4 $ 2.0 $ 1.5 $ 4.4 Purchases 3.1 6.8 3.1 6.8 Settlements (0.7) (3.0) (1.8) (5.4) Balance at the end of the period $ 2.8 $ 5.8 $ 2.8 $ 5.8 Fair Value of Financial Instruments The following table shows the financial instruments included on our balance sheets that were not recorded at fair value: June 30, 2020 December 31, 2019 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 29.1 $ 30.4 $ 29.5 Long-term debt 2,760.0 3,382.2 2,759.2 3,209.5 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	6 Months Ended
	Jun. 30, 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 purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Our regulated hedging programs are approved by the PSCW. 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, the PSCW allows the effects of fair value accounting to be offset to regulatory assets and liabilities. The following table shows our derivative assets and derivative liabilities, along with their classification on our balance sheets. None of our derivatives are designated as hedging instruments. June 30, 2020 December 31, 2019 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 0.7 $ 2.8 $ 0.4 $ 5.1 FTRs 2.8 — 1.5 — Coal contracts — 0.1 — 0.2 Total other current (1) 3.5 2.9 1.9 5.3 Other long-term Natural gas contracts 0.4 — — 0.1 Coal contracts — — 0.1 — Total other long-term (1) 0.4 — 0.1 0.1 Total $ 3.9 $ 2.9 $ 2.0 $ 5.4 (1) 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 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 June 30, 2020 Three Months Ended June 30, 2019 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 14.0 Dth $ (4.4) 13.6 Dth $ (1.1) FTRs 5.1 MWh 0.5 5.6 MWh 0.5 Total $ (3.9) $ (0.6) Six Months Ended June 30, 2020 Six Months Ended June 30, 2019 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 33.1 Dth $ (11.3) 31.7 Dth $ (2.5) FTRs 10.2 MWh 1.3 11.1 MWh 2.1 Total $ (10.0) $ (0.4) 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 June 30, 2020 and December 31, 2019, we had posted cash collateral of $5.9 million and $8.5 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: June 30, 2020 December 31, 2019 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 3.9 $ 2.9 $ 2.0 $ 5.4 Gross amount not offset on the balance sheet (0.8) (2.8) (1) (0.4) (5.2) (2) Net amount $ 3.1 $ 0.1 $ 1.6 $ 0.2 (1) Includes cash collateral posted of $2.0 million. (2) Includes cash collateral posted of $4.8 million.

GUARANTEES

GUARANTEES	6 Months Ended
	Jun. 30, 2020
Guarantees [Abstract]
GUARANTEES	GUARANTEESAs of June 30, 2020, we had $26.0 million of standby letters of credit issued by financial institutions for the benefit of third parties that extended credit to us which automatically renew each year unless proper termination notice is given. These amounts are not reflected on our balance sheets.

EMPLOYEE BENEFITS

EMPLOYEE BENEFITS	6 Months Ended
	Jun. 30, 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 June 30 Six Months Ended June 30 (in millions) 2020 2019 2020 2019 Service cost $ 2.9 $ 2.5 $ 6.2 $ 6.3 Interest cost 9.4 11.1 18.9 22.6 Expected return on plan assets (17.3) (18.0) (34.7) (36.2) Amortization of prior service cost — 0.1 — 0.2 Amortization of net actuarial loss 9.8 6.8 18.9 14.0 Net periodic benefit cost $ 4.8 $ 2.5 $ 9.3 $ 6.9 OPEB Benefits Three Months Ended June 30 Six Months Ended June 30 (in millions) 2020 2019 2020 2019 Service cost $ 1.0 $ 1.0 $ 2.1 $ 2.2 Interest cost 1.7 2.4 3.4 4.8 Expected return on plan assets (3.9) (3.6) (7.8) (7.1) Amortization of prior service credit (0.2) (0.5) (0.3) (1.0) Amortization of net actuarial gain (2.9) (0.7) (5.3) (1.1) Net periodic benefit credit $ (4.3) $ (1.4) $ (7.9) $ (2.2)

SEGMENT INFORMATION

SEGMENT INFORMATION	6 Months Ended
	Jun. 30, 2020
Segment Reporting [Abstract]
SEGMENT INFORMATION	SEGMENT INFORMATION We use operating income to measure segment profitability and to allocate resources to our businesses. At June 30, 2020, we reported two segments, which are described below. Our utility segment includes our electric utility operations, including steam operations, and our natural gas utility operations. • Our electric utility operations are engaged in the generation, distribution, and sale of electricity to customers in southeastern Wisconsin (including metropolitan Milwaukee), east central Wisconsin, and northern Wisconsin. In addition, our steam operations produce, distribute, and sell steam to customers in metropolitan Milwaukee. Prior to April 1, 2019, we also provided electric service to Tilden, who owns an iron ore mine in the Upper Peninsula of Michigan. This customer was transferred to UMERC on April 1, 2019. • Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers and the transportation of customer-owned natural gas in southeastern, east central, and northern Wisconsin. No significant items were reported in the other segment during the three and six months ended June 30 2020 and 2019.

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	6 Months Ended
	Jun. 30, 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 and investments. 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. 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 $18.0 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	6 Months Ended
	Jun. 30, 2020
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIESWe 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 We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of June 30, 2020, were approximately $9.3 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 territory were designated as partial nonattainment with the 2015 standard: Kenosha and Northern Milwaukee/Ozaukee. 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 was issued in July 2020 remanding the rule to the EPA for further evaluation. 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 2015 rule. Mercury and Air Toxics Standards In May 2020, the EPA finalized revisions to 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 final rule, the emission standards and other requirements of the MATS rule first enacted in 2012 remain in place. The EPA did not remove coal- and oil-fired power plants from the list of sources that are regulated under Section 112. The EPA also determined that no revisions to MATS are warranted based on the results of the RTR. As a result, we do not expect the rule to have a material impact on our financial condition or results of 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 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. WEC Energy Group continues to evaluate opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute toward long-term GHG emissions reductions. In 2019, WEC Energy Group met and exceeded its 2030 goal of reducing CO 2 emissions by 40% below 2005 levels. WEC Energy Group has re-evaluated its carbon reduction goals for its electric generation in light of this progress. As strategies to reduce GHG emissions continue to evolve, WEC Energy Group's updated plan, which includes us, is to work with elected officials, regulatory agencies, customers, environmental groups, and other stakeholders to reduce CO 2 emissions from electricity generation by 70% below 2005 levels by 2030. WEC Energy Group's long-term goal calls for its electric generation fleet to be net carbon neutral by 2050. As a result of WEC Energy Group's generation reshaping plan, we retired approximately 1,500 MW of coal generation since the beginning of 2018, including the 2018 retirement of the Pleasant Prairie power plant as well as the March 2019 retirement of the PIPP. WEC Energy Group also has a goal to decrease the rate of methane emissions from the natural gas distribution lines in its network by 30% per mile by the year 2030 from a 2011 baseline. WEC Energy Group was over half way toward meeting that goal at the end of 2019. Stationary Combustion Turbine Standards (Combustion Turbine Rule) Effective in March 2020, the EPA issued a final regulation for National Air Standards for Hazardous Air Pollutants for Stationary Combustion Turbines. The Combustion Turbine Rule was issued to complete the RTR required by the CAA every five years, and applies only to combustion turbines constructed or reconstructed after January 14, 2003. The Combustion Turbine Rule clarifies certain performance testing, semi-annual and excess emission reporting requirements, implements electronic reporting requirements, and changes certain requirements applicable during startup, shutdown, and malfunction. We have evaluated the rule and do not expect the rule will have a material impact on our financial condition or results of operations. 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 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. We anticipate that the permit renewal will include a final BTA determination to address all of the Section 316(b) rule requirements. As a result of past capital investments completed to address Section 316(b) compliance, we believe our fleet overall is well positioned to meet the regulation and do not expect to incur significant additional 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 us relate to discharge limits for BATW and wet FGD wastewater. As a result of past capital investments, 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 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 $50 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 for generating units that are 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 we 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. We are responsible for the environmental remediation of these sites. 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. 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) June 30, 2020 December 31, 2019 Regulatory assets $ 21.2 $ 22.1 Reserves for future environmental remediation (1) 12.1 12.1 (1) Recorded within other long-term liabilities on our balance sheets. Enforcement and Litigation Matters We 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 impact on our financial condition or results of operations.

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	6 Months Ended
	Jun. 30, 2020
Supplemental Cash Flow Information [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	SUPPLEMENTAL CASH FLOW INFORMATION Six Months Ended June 30 (in millions) 2020 2019 Cash paid for interest, net of amount capitalized $ 233.8 $ 239.1 Cash paid for income taxes, net — 10.6 Significant non-cash investing and financing transactions: Accounts payable related to construction costs 27.8 6.6

REGULATORY ENVIRONMENT

REGULATORY ENVIRONMENT	6 Months Ended
	Jun. 30, 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 territory. In response to the COVID-19 pandemic, Wisconsin declared a public health emergency and issued a shelter-in-place order, which has since been lifted. On March 24, 2020, the PSCW issued two orders regarding certain actions to be taken for purposes of ensuring that essential utility services were, and continue to be, available to our customers. The first order required all public utilities in the state of Wisconsin, including us, to temporarily suspend disconnections, the assessment of late fees, and deposit requirements for all customer classes. In addition, it required 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. In the second order issued on March 24, 2020, 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 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 our commercial and industrial customers. The PSCW will review the recoverability and examine the prudency of any deferred amounts in future rate proceedings. As of June 30, 2020, our deferrals related to the COVID-19 pandemic were not significant. On June 26, 2020, the PSCW issued a written order providing a timeline for the lifting of the temporary provisions required in the initial March 24, 2020 order. Utilities were allowed to disconnect commercial and industrial customers and require deposits for new service as of July 25, 2020 and July 31, 2020, respectively. Additionally, utilities were authorized to reinstate late fees except for the period between the first order and this supplemental order. Utilities can elect to continue to waive all late fees until the end of 2020 or until they are able to implement the changes necessary to prevent late fees from being assessed on past due balances resulting from services provided during the declared health emergency. We are still currently waiving late fees. Utilities will also not be required to offer deferred payment arrangements to all customers after August 15, 2020. On July 24, 2020, the PSCW extended the moratorium on disconnections of residential customers until September 1, 2020. 2020 and 2021 Rates In March 2019, we filed an application with the PSCW to increase our retail electric, natural gas, and steam rates, effective January 1, 2020. In August 2019, we filed an application with the PSCW for approval of a settlement agreement entered into with certain intervenors to resolve several outstanding issues in our rate case. In December 2019, the PSCW issued a written order that approved the settlement agreement without material modification and addressed the remaining outstanding issues that were not included in the settlement agreement. The new rates became effective January 1, 2020. The final order reflects the following: 2020 Effective rate increase Electric (1) $ 15.3 million / 0.5% Gas (2) $ 10.4 million / 2.8% Steam $ 1.9 million / 8.6% ROE 10.0% Common equity component average on a financial basis 52.5% (1) Amount is net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impacts to our customers. The rate order reflects the majority of the unprotected deferred tax benefits from the Tax Legislation being amortized evenly over two years, which results in approximately $65 million of tax benefits being amortized in each of 2020 and 2021. The unprotected deferred tax benefits related to the unrecovered balances of our recently retired plants and our SSR regulatory asset were 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 the PSCW. (2) Amount includes certain deferred tax expense from the Tax Legislation. The rate order reflects all of the unprotected deferred tax expense from the Tax Legislation being amortized evenly over four years, which results in approximately $5 million of previously deferred tax expense being amortized each year. Unprotected deferred tax expense by its nature is eligible to be recovered from customers in a manner and timeline determined to be appropriate by the PSCW. In accordance with our rate order, we filed an application with the PSCW on July 20, 2020 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. We 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 we earn above our authorized ROE: (i) we retain 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 order also requires us to maintain residential and small commercial electric and natural gas customer fixed charges at previously authorized rates and to maintain the status quo for our electric market-based rate programs for large industrial customers through 2021. 2018 and 2019 Rates During April 2017, we, along with Wisconsin Public Service Corporation and WG, filed an application with the PSCW for approval of a settlement agreement we made with several of our 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 our electric, natural gas, and steam customers. Based on the PSCW order, our authorized ROE remained at 10.2% and our capital cost structure 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 during the base rate freeze period by accelerating the recognition of certain tax benefits. We were flowing through the tax benefit of our 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. Pursuant to the settlement agreement, we also agreed to keep our earnings sharing mechanism in place through 2019. Under this earnings sharing mechanism, if we earned above our 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 Facility In November 2019, we filed an application with the PSCW requesting approval to construct a LNG facility. If approved, the facility would provide us with approximately one billion cubic feet of natural gas supply to meet anticipated peak demand without requiring the construction of additional interstate pipeline capacity. This facility is expected to reduce the likelihood of constraints on our natural gas system during the highest demand days of winter. The project is estimated to cost approximately $185 million. Commercial operation for the LNG facility is targeted for the end of 2023. Solar Generation Project

NEW ACCOUNTING PRONOUNCEMENTS

NEW ACCOUNTING PRONOUNCEMENTS	6 Months Ended
	Jun. 30, 2020
Accounting Standards Update and Change in Accounting Principle [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 plan to 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)	6 Months Ended
	Jun. 30, 2020
Accounting policies
Basis of accounting	As used in these notes, the term "financial statements" refers to the condensed financial statements. This includes the income statements, 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 Wisconsin Electric Power Company. 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 and six months ended June 30, 2020 are not necessarily indicative of expected results for 2020 due to seasonal variations and other factors, including any continuing financial impacts 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 generated from the sale of electricity and natural gas by our regulated utility operations. Our regulated utility operations are included in our utility segment. No accounts receivable and unbilled revenue balances were reported in the other segment at June 30, 2020. 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. The increase recorded to our allowance for credit losses at June 30, 2020, specific to the economic risks associated with the COVID-19 pandemic not already reflected in our calculated reserve, was not significant. We will continue to monitor the economic impacts of COVID-19 and the resulting effects that these impacts may have on the ability of our customers to pay their energy bills.
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.
Derivative instruments	We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Our regulated hedging programs are approved by the PSCW. 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, the PSCW allows 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 plan to 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.

OPERATING REVENUES (Tables)

OPERATING REVENUES (Tables) - Utility segment	6 Months Ended
	Jun. 30, 2020
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	The following tables present our operating revenues disaggregated by revenue source for our utility segment. We do not have any revenues associated with our other segment. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors. 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. Wisconsin Electric Power Company Three Months Ended June 30 Six Months Ended June 30 (in millions) 2020 2019 2020 2019 Electric utility $ 707.3 $ 723.7 $ 1,436.3 $ 1,502.5 Natural gas utility 61.9 64.7 200.9 242.6 Total revenues from contracts with customers 769.2 788.4 1,637.2 1,745.1 Other operating revenues 0.3 3.3 3.3 7.4 Total operating revenues $ 769.5 $ 791.7 $ 1,640.5 $ 1,752.5
Revenues from contracts with customers | Electric
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	The following table disaggregates electric utility operating revenues into customer class: Electric Utility Operating Revenues Three Months Ended June 30 Six Months Ended June 30 (in millions) 2020 2019 2020 2019 Residential $ 312.4 $ 266.5 $ 607.4 $ 569.1 Small commercial and industrial 222.5 241.9 458.5 487.0 Large commercial and industrial 122.8 139.4 245.7 295.4 Other 4.6 4.9 9.7 10.5 Total retail revenues 662.3 652.7 1,321.3 1,362.0 Wholesale 18.0 20.1 37.7 49.0 Resale 22.0 41.8 61.2 73.1 Steam 4.1 4.3 12.5 14.4 Other utility revenues 0.9 4.8 3.6 4.0 Total electric utility operating revenues $ 707.3 $ 723.7 $ 1,436.3 $ 1,502.5
Revenues from contracts with customers | Natural gas
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	The following table disaggregates natural gas utility operating revenues into customer class: Natural Gas Utility Operating Revenues Three Months Ended June 30 Six Months Ended June 30 (in millions) 2020 2019 2020 2019 Residential $ 39.2 $ 35.4 $ 138.7 $ 161.0 Commercial and industrial 13.0 14.1 57.3 75.0 Total retail revenues 52.2 49.5 196.0 236.0 Transport 3.5 2.9 8.5 7.2 Other utility revenues (1) 6.2 12.3 (3.6) (0.6) Total natural gas utility operating revenues $ 61.9 $ 64.7 $ 200.9 $ 242.6 (1) Includes amounts collected from (refunded to) customers for purchased gas adjustment costs.
Other operating revenues
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	Other operating revenues consist primarily of the following: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2020 2019 2020 2019 Rental revenues $ 1.6 $ 1.5 $ 2.3 $ 2.2 Late payment charges (1) — 2.0 2.7 4.7 Alternative revenues (2) (1.3) (0.2) (1.7) 0.5 Total other operating revenues $ 0.3 $ 3.3 $ 3.3 $ 7.4 (1) The reduction in late payment charges is a result of a regulatory order from the PSCW in response to the COVID-19 pandemic, which includes the suspension of late payment charges during a designated time period. See Note 18, Regulatory Environment, for more information. (2) 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 wholesale customers subject to true-up, as discussed in Note 1(d), Operating Revenues, in our 2019 Annual Report on Form 10-K.

CREDIT LOSSES (Tables)

CREDIT LOSSES (Tables)	6 Months Ended
	Jun. 30, 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 related allowance for credit losses. (in millions) June 30, 2020 Accounts receivable and unbilled revenues $ 472.8 Allowance for credit losses 45.7 Accounts receivable and unbilled revenues, net (1) $ 427.1 Total accounts receivable, net – past due greater than 90 days (1) $ 41.3 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 95.8 % (1) Our exposure to credit losses for certain regulated utility customers is mitigated by a regulatory mechanism we have in place. Specifically, our residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. As a result, at June 30, 2020, $204.4 million, or 47.9%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. In addition, in its March 24, 2020 order, the PSCW authorized the deferral of credit losses for our 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 related actions we have been required to take to ensure essential utility services are available to customers during this public health emergency. As a result, our exposure to credit losses related to certain commercial and industrial accounts receivable and unbilled revenue balances were also mitigated by regulatory protections at June 30, 2020, but are not included in the percentages in the above table or this note as we continue to assess the impacts of the order. See Note 18, Regulatory Environment, for more information.
Rollforward of the allowances for credit losses	A rollforward of the allowance for credit losses is included below: (in millions) Six Months Ended June 30, 2020 Balance at December 31, 2019 $ 38.1 Provision for credit losses 13.7 Provision for credit losses deferred for future recovery or refund 3.5 Write-offs charged against the allowance (21.6) Recoveries of amounts previously written off 12.0 Balance at June 30, 2020 $ 45.7

REGULATORY ASSETS AND LIABILI_2

REGULATORY ASSETS AND LIABILITIES (Tables)	6 Months Ended
	Jun. 30, 2020
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of regulatory assets	(in millions) June 30, 2020 December 31, 2019 Regulatory assets Finance leases $ 958.7 $ 930.5 Plant retirements 776.6 788.8 Pension and OPEB costs 440.8 459.4 Income tax related items 398.6 403.2 SSR 138.8 151.5 Other, net 54.3 21.8 Total regulatory assets $ 2,767.8 $ 2,755.2
Schedule of regulatory liabilities	(in millions) June 30, 2020 December 31, 2019 Regulatory liabilities Income tax related items $ 847.3 $ 888.1 Removal costs 666.3 654.7 Pension and OPEB benefits 116.6 120.4 Electric transmission costs 54.6 38.6 Uncollectible expense 25.3 28.8 Energy costs refundable through rate adjustments 22.3 12.3 Other, net 9.2 13.3 Total regulatory liabilities $ 1,741.6 $ 1,756.2 Balance sheet presentation Other current liabilities $ 14.7 $ 12.0 Regulatory liabilities 1,726.9 1,744.2 Total regulatory liabilities $ 1,741.6 $ 1,756.2

SHORT-TERM DEBT AND LINES OF _2

SHORT-TERM DEBT AND LINES OF CREDIT (Tables)	6 Months Ended
	Jun. 30, 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) June 30, 2020 December 31, 2019 Commercial paper Amount outstanding $ 27.0 $ 115.5 Weighted-average interest rate on amounts outstanding 0.16 % 2.03 %
Schedule of revolving credit facility and remaining available capacity	The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including available capacity under this facility: (in millions) Maturity June 30, 2020 Revolving credit facility October 2022 $ 500.0 Less: Letters of credit issued inside credit facility $ 1.0 Commercial paper outstanding 27.0 Available capacity under existing credit facility $ 472.0

LEASES (Tables)

LEASES (Tables)	6 Months Ended
	Jun. 30, 2020
Leases [Abstract]
Schedule of minimum lease payments	Future minimum lease payments and the corresponding present value of our net minimum lease payments under the finance leases for Badger Hollow II as of June 30, 2020, were as follows: (in millions) Six months ended December 31, 2020 $ 0.2 2021 0.3 2022 0.3 2023 0.7 2024 0.7 2025 0.7 Thereafter 55.0 Total minimum lease payments 57.9 Less:Interest (35.1) Present value of minimum lease payments 22.8 Less: Short-term lease liabilities — Long-term lease liabilities $ 22.8

MATERIALS, SUPPLIES, AND INVE_2

MATERIALS, SUPPLIES, AND INVENTORIES (Tables)	6 Months Ended
	Jun. 30, 2020
Inventory Disclosure [Abstract]
Schedule of inventory	Our inventory consisted of: (in millions) June 30, 2020 December 31, 2019 Materials and supplies $ 152.3 $ 148.3 Fossil fuel 49.6 51.1 Natural gas in storage 18.1 30.4 Total $ 220.0 $ 229.8

INCOME TAXES (Tables)

INCOME TAXES (Tables)	6 Months Ended
	Jun. 30, 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 June 30, 2020 Three Months Ended June 30, 2019 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 16.1 21.0 % $ 14.4 21.0 % State income taxes net of federal tax benefit 4.9 6.4 % 4.5 6.6 % Tax repairs — — % (30.5) (44.3) % Federal excess deferred tax amortization – Wisconsin unprotected (9.4) (12.2) % — — % Federal excess deferred tax amortization (5.1) (6.7) % (3.8) (5.6) % Wind production tax credits (2.4) (3.1) % (2.2) (3.2) % Other 1.9 2.4 % 1.3 1.8 % Total income tax expense (benefit) $ 6.0 7.8 % $ (16.3) (23.7) % Six Months Ended June 30, 2020 Six Months Ended June 30, 2019 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 44.1 21.0 % $ 37.1 21.0 % State income taxes net of federal tax benefit 13.5 6.4 % 11.6 6.6 % Tax repairs 1.3 0.6 % (60.1) (33.9) % Federal excess deferred tax amortization – Wisconsin unprotected (22.9) (10.9) % — — % Federal excess deferred tax amortization (12.4) (5.9) % (10.0) (5.7) % Wind production tax credits (5.7) (2.7) % (5.0) (2.8) % Other 2.8 1.3 % 3.6 1.9 % Total income tax expense (benefit) $ 20.7 9.8 % $ (22.8) (12.9) %

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	6 Months Ended
	Jun. 30, 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: June 30, 2020 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 1.1 $ — $ — $ 1.1 FTRs — — 2.8 2.8 Total derivative assets $ 1.1 $ — $ 2.8 $ 3.9 Derivative liabilities Natural gas contracts $ 2.8 $ — $ — $ 2.8 Coal contracts — 0.1 — 0.1 Total derivative liabilities $ 2.8 $ 0.1 $ — $ 2.9 December 31, 2019 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.4 $ — $ — $ 0.4 FTRs — — 1.5 1.5 Coal contracts — 0.1 — 0.1 Total derivative assets $ 0.4 $ 0.1 $ 1.5 $ 2.0 Derivative liabilities Natural gas contracts $ 5.2 $ — $ — $ 5.2 Coal contracts — 0.2 — 0.2 Total derivative liabilities $ 5.2 $ 0.2 $ — $ 5.4
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 June 30 Six Months Ended June 30 (in millions) 2020 2019 2020 2019 Balance at the beginning of the period $ 0.4 $ 2.0 $ 1.5 $ 4.4 Purchases 3.1 6.8 3.1 6.8 Settlements (0.7) (3.0) (1.8) (5.4) Balance at the end of the period $ 2.8 $ 5.8 $ 2.8 $ 5.8
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: June 30, 2020 December 31, 2019 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 29.1 $ 30.4 $ 29.5 Long-term debt 2,760.0 3,382.2 2,759.2 3,209.5

DERIVATIVE INSTRUMENTS (Tables)

DERIVATIVE INSTRUMENTS (Tables)	6 Months Ended
	Jun. 30, 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. None of our derivatives are designated as hedging instruments. June 30, 2020 December 31, 2019 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 0.7 $ 2.8 $ 0.4 $ 5.1 FTRs 2.8 — 1.5 — Coal contracts — 0.1 — 0.2 Total other current (1) 3.5 2.9 1.9 5.3 Other long-term Natural gas contracts 0.4 — — 0.1 Coal contracts — — 0.1 — Total other long-term (1) 0.4 — 0.1 0.1 Total $ 3.9 $ 2.9 $ 2.0 $ 5.4 (1) 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 volumes and realized gains (losses)	Our estimated notional sales volumes and realized gains (losses) were as follows: Three Months Ended June 30, 2020 Three Months Ended June 30, 2019 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 14.0 Dth $ (4.4) 13.6 Dth $ (1.1) FTRs 5.1 MWh 0.5 5.6 MWh 0.5 Total $ (3.9) $ (0.6) Six Months Ended June 30, 2020 Six Months Ended June 30, 2019 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 33.1 Dth $ (11.3) 31.7 Dth $ (2.5) FTRs 10.2 MWh 1.3 11.1 MWh 2.1 Total $ (10.0) $ (0.4)
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: June 30, 2020 December 31, 2019 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 3.9 $ 2.9 $ 2.0 $ 5.4 Gross amount not offset on the balance sheet (0.8) (2.8) (1) (0.4) (5.2) (2) Net amount $ 3.1 $ 0.1 $ 1.6 $ 0.2 (1) Includes cash collateral posted of $2.0 million. (2) Includes cash collateral posted of $4.8 million.

EMPLOYEE BENEFITS (Tables)

EMPLOYEE BENEFITS (Tables)	6 Months Ended
	Jun. 30, 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 June 30 Six Months Ended June 30 (in millions) 2020 2019 2020 2019 Service cost $ 2.9 $ 2.5 $ 6.2 $ 6.3 Interest cost 9.4 11.1 18.9 22.6 Expected return on plan assets (17.3) (18.0) (34.7) (36.2) Amortization of prior service cost — 0.1 — 0.2 Amortization of net actuarial loss 9.8 6.8 18.9 14.0 Net periodic benefit cost $ 4.8 $ 2.5 $ 9.3 $ 6.9 OPEB Benefits Three Months Ended June 30 Six Months Ended June 30 (in millions) 2020 2019 2020 2019 Service cost $ 1.0 $ 1.0 $ 2.1 $ 2.2 Interest cost 1.7 2.4 3.4 4.8 Expected return on plan assets (3.9) (3.6) (7.8) (7.1) Amortization of prior service credit (0.2) (0.5) (0.3) (1.0) Amortization of net actuarial gain (2.9) (0.7) (5.3) (1.1) Net periodic benefit credit $ (4.3) $ (1.4) $ (7.9) $ (2.2)

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	6 Months Ended
	Jun. 30, 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) June 30, 2020 December 31, 2019 Regulatory assets $ 21.2 $ 22.1 Reserves for future environmental remediation (1) 12.1 12.1 (1) Recorded within other long-term liabilities on our balance sheets.

SUPPLEMENTAL CASH FLOW INFORM_2

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	6 Months Ended
	Jun. 30, 2020
Supplemental Cash Flow Information [Abstract]
Schedule of supplemental cash flow information	Six Months Ended June 30 (in millions) 2020 2019 Cash paid for interest, net of amount capitalized $ 233.8 $ 239.1 Cash paid for income taxes, net — 10.6 Significant non-cash investing and financing transactions: Accounts payable related to construction costs 27.8 6.6

REGULATORY ENVIRONMENT (Tables)

REGULATORY ENVIRONMENT (Tables)	6 Months Ended
	Jun. 30, 2020
Regulated Operations [Abstract]
Schedule of decisions in regulatory order	The final order reflects the following: 2020 Effective rate increase Electric (1) $ 15.3 million / 0.5% Gas (2) $ 10.4 million / 2.8% Steam $ 1.9 million / 8.6% ROE 10.0% Common equity component average on a financial basis 52.5% (1) Amount is net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impacts to our customers. The rate order reflects the majority of the unprotected deferred tax benefits from the Tax Legislation being amortized evenly over two years, which results in approximately $65 million of tax benefits being amortized in each of 2020 and 2021. The unprotected deferred tax benefits related to the unrecovered balances of our recently retired plants and our SSR regulatory asset were 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 the PSCW. (2) Amount includes certain deferred tax expense from the Tax Legislation. The rate order reflects all of the unprotected deferred tax expense from the Tax Legislation being amortized evenly over four years, which results in approximately $5 million of previously deferred tax expense being amortized each year. Unprotected deferred tax expense by its nature is eligible to be recovered from customers in a manner and timeline determined to be appropriate by the PSCW.

GENERAL INFORMATION - GENERAL (

GENERAL INFORMATION - GENERAL (Details) customer in Millions	Jun. 30, 2020customer
Electric
Product Information [Line Items]
Number Of Customers	1.1
Natural gas
Product Information [Line Items]
Number Of Customers	0.5

OPERATING REVENUES - DISAGGREGA

OPERATING REVENUES - DISAGGREGATION OF OPERATING REVENES (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Disaggregation of Operating Revenues
Operating revenues	$ 769.5	$ 791.7	$ 1,640.5	$ 1,752.5
Utility segment
Disaggregation of Operating Revenues
Operating revenues	769.5	791.7	1,640.5	1,752.5
Utility segment | Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	0.3	3.3	3.3	7.4
Utility segment | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	769.2	788.4	1,637.2	1,745.1
Utility segment | Electric | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	707.3	723.7	1,436.3	1,502.5
Utility segment | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 61.9	$ 64.7	$ 200.9	$ 242.6

OPERATING REVENUES ELECTRIC UTI

OPERATING REVENUES ELECTRIC UTILITY OPERATING REVENUES (Details) - Revenues from contracts with customers - Utility segment - Transferred over time - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 769.2	$ 788.4	$ 1,637.2	$ 1,745.1
Electric
Disaggregation of Operating Revenues
Revenues from contracts with customers	707.3	723.7	1,436.3	1,502.5
Electric | Total retail
Disaggregation of Operating Revenues
Revenues from contracts with customers	662.3	652.7	1,321.3	1,362
Electric | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	312.4	266.5	607.4	569.1
Electric | Small commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	222.5	241.9	458.5	487
Electric | Large commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	122.8	139.4	245.7	295.4
Electric | Other
Disaggregation of Operating Revenues
Revenues from contracts with customers	4.6	4.9	9.7	10.5
Electric | Wholesale
Disaggregation of Operating Revenues
Revenues from contracts with customers	18	20.1	37.7	49
Electric | Resale
Disaggregation of Operating Revenues
Revenues from contracts with customers	22	41.8	61.2	73.1
Electric | Steam
Disaggregation of Operating Revenues
Revenues from contracts with customers	4.1	4.3	12.5	14.4
Electric | Other utility
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 0.9	$ 4.8	$ 3.6	$ 4

OPERATING REVENUES NATURAL GAS

OPERATING REVENUES NATURAL GAS UTILITY OPERATING REVENUES (Details) - Revenues from contracts with customers - Utility segment - Transferred over time - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 769.2	$ 788.4	$ 1,637.2	$ 1,745.1
Natural gas
Disaggregation of Operating Revenues
Revenues from contracts with customers	61.9	64.7	200.9	242.6
Natural gas | Total retail
Disaggregation of Operating Revenues
Revenues from contracts with customers	52.2	49.5	196	236
Natural gas | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	39.2	35.4	138.7	161
Natural gas | Commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	13	14.1	57.3	75
Natural gas | Transport
Disaggregation of Operating Revenues
Revenues from contracts with customers	3.5	2.9	8.5	7.2
Natural gas | Other utility
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 6.2	$ 12.3	$ (3.6)	$ (0.6)

OPERATING REVENUES - OTHER OPER

OPERATING REVENUES - OTHER OPERATING REVENUES (Details) - Utility segment - Other operating revenues - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Disaggregation of Operating Revenues
Other operating revenues	$ 0.3	$ 3.3	$ 3.3	$ 7.4
Rental revenues
Disaggregation of Operating Revenues
Other operating revenues	1.6	1.5	2.3	2.2
Late payment charges
Disaggregation of Operating Revenues
Other operating revenues	0	2	2.7	4.7
Alternative revenues
Disaggregation of Operating Revenues
Other operating revenues	$ (1.3)	$ (0.2)	$ (1.7)	$ 0.5

CREDIT LOSSES - GROSS RECEIVABL

CREDIT LOSSES - GROSS RECEIVABLES AND RELATED ALLOWANCES (Details) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Utility segment
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable and unbilled revenues	$ 472.8
Allowance for credit losses	45.7	$ 38.1
Accounts receivable and unbilled revenues, net	427.1
Total accounts receivable, net - past due greater than 90 days	$ 41.3
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms	95.80%
Amount of net accounts receivable with regulatory protections	$ 204.4
Percent of net accounts receivable with regulatory protections	47.90%
Other Segment
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable and unbilled revenues	$ 0

CREDIT LOSSES - ROLLFORWARD OF

CREDIT LOSSES - ROLLFORWARD OF ALLOWANCES (Details) - Utility segment $ in Millions	6 Months Ended
	Jun. 30, 2020USD ($)
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at December 31, 2019	$ 38.1
Provision for credit losses	13.7
Provision for credit losses deferred for future recovery or refund	3.5
Write-offs charged against the allowance	(21.6)
Recovery of amounts previously written off	12
Balance at June 30, 2020	$ 45.7

REGULATORY ASSETS AND LIABILI_3

REGULATORY ASSETS AND LIABILITIES - REGULATORY ASSETS (Details) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Regulatory assets
Regulatory assets	$ 2,767.8	$ 2,755.2
Finance leases
Regulatory assets
Regulatory assets	958.7	930.5
Plant retirements
Regulatory assets
Regulatory assets	776.6	788.8
Pension and OPEB costs
Regulatory assets
Regulatory assets	440.8	459.4
Income tax related items
Regulatory assets
Regulatory assets	398.6	403.2
SSR
Regulatory assets
Regulatory assets	138.8	151.5
Other, net
Regulatory assets
Regulatory assets	$ 54.3	$ 21.8

REGULATORY ASSETS AND LIABILI_4

REGULATORY ASSETS AND LIABILITIES - REGULATORY LIABILITIES (Details) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Regulatory liabilities
Other current liabilities	$ 14.7	$ 12
Regulatory liabilities	1,726.9	1,744.2
Total regulatory liabilities	1,741.6	1,756.2
Income tax related items
Regulatory liabilities
Total regulatory liabilities	847.3	888.1
Removal costs
Regulatory liabilities
Total regulatory liabilities	666.3	654.7
Pension and OPEB benefits
Regulatory liabilities
Total regulatory liabilities	116.6	120.4
Electric transmission costs
Regulatory liabilities
Total regulatory liabilities	54.6	38.6
Uncollectible expense
Regulatory liabilities
Total regulatory liabilities	25.3	28.8
Energy costs refundable through rate adjustments
Regulatory liabilities
Total regulatory liabilities	22.3	12.3
Other, net
Regulatory liabilities
Total regulatory liabilities	$ 9.2	$ 13.3

SHORT-TERM DEBT AND LINES OF _3

SHORT-TERM DEBT AND LINES OF CREDIT - SHORT-TERM BORROWINGS (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2020	Dec. 31, 2019
Short-term borrowings
Commercial paper outstanding	$ 27	$ 115.5
Commercial paper
Short-term borrowings
Commercial paper outstanding	$ 27	$ 115.5
Weighted-average interest rate on amounts outstanding	0.16%	2.03%
Average amount outstanding during the period	$ 82.8
Weighted-average interest rate during the period	1.71%

SHORT-TERM DEBT AND LINES OF _4

SHORT-TERM DEBT AND LINES OF CREDIT - REVOLVING CREDIT FACILITIES (Details) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Revolving credit facility
Letters of credit issued inside credit facility	$ 1
Commercial paper outstanding	27	$ 115.5
Available capacity under existing credit facility	472
Credit facility maturing October 2022
Revolving credit facility
Revolving credit facility	500
Commercial paper
Revolving credit facility
Commercial paper outstanding	$ 27	$ 115.5

LEASES - BADGER HOLLOW II (Deta

LEASES - BADGER HOLLOW II (Details) - Badger Hollow II Solar Farm $ in Millions	Jun. 30, 2020USD ($)aMW
Leases
Capacity of solar project owned by entity (in megawatts) | MW	100
Solar land lease acreage | a	1,500
Lease initial term	25 years
Lease renewal term	25 years
Finance lease obligations	$ 22.8
Finance lease obligation at the end of the life of solar land contract	0
Right of use asset under finance lease	$ 22.8
Weighted average discount rate for finance lease	3.44%

LEASES - FUTURE MINIMUM LEASE P

LEASES - FUTURE MINIMUM LEASE PAYMENTS (Details) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Finance leases
Less: short-term lease liabilities	$ 62.2	$ 57.8
Long-term lease liabilities	2,796.9	$ 2,783.1
Badger Hollow II Solar Farm
Finance leases
Six months ended December 31, 2020	0.2
2021	0.3
2022	0.3
2023	0.7
2024	0.7
2025	0.7
Thereafter	55
Total minimum lease payments	57.9
Less: interest	(35.1)
Present value of minimum lease payments	22.8
Less: short-term lease liabilities	0
Long-term lease liabilities	$ 22.8

MATERIALS, SUPPLIES, AND INVE_3

MATERIALS, SUPPLIES, AND INVENTORIES (Details) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Inventory Disclosure [Abstract]
Materials and supplies	$ 152.3	$ 148.3
Fossil fuel	49.6	51.1
Natural gas in storage	18.1	30.4
Total	$ 220	$ 229.8

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Effective Income Tax Rate Reconciliation, Amount
Statutory federal income tax, amount	$ 16.1	$ 14.4	$ 44.1	$ 37.1
State income taxes net of federal tax benefit, amount	4.9	4.5	13.5	11.6
Tax repairs, amount	0	(30.5)	1.3	(60.1)
Federal excess deferred tax amortization - Wisconsin unprotected, amount	(9.4)	0	(22.9)	0
Federal excess deferred tax amortization, amount	(5.1)	(3.8)	(12.4)	(10)
Wind production tax credits, amount	(2.4)	(2.2)	(5.7)	(5)
Other, amount	1.9	1.3	2.8	3.6
Total income tax expense (benefit), amount	$ 6	$ (16.3)	$ 20.7	$ (22.8)
Effective Income Tax Rate Reconciliation, Percent
Statutory federal income tax, percent	21.00%	21.00%	21.00%	21.00%
State income taxes net of federal tax benefit, percent	6.40%	6.60%	6.40%	6.60%
Tax repairs, percent	0.00%	(44.30%)	0.60%	(33.90%)
Federal excess deferred tax amortization - WI Unprotected, percent	(12.20%)	0.00%	(10.90%)	0.00%
Federal excess deferred tax amortization, percent	(6.70%)	(5.60%)	(5.90%)	(5.70%)
Wind production tax credits, percent	(3.10%)	(3.20%)	(2.70%)	(2.80%)
Other, percent	2.40%	1.80%	1.30%	1.90%
Total income tax expense (benefit), percent	7.80%	(23.70%)	9.80%	(12.90%)

INCOME TAXES - WI 2020-2021 RAT

INCOME TAXES - WI 2020-2021 RATES (Details) - Public Service Commission of Wisconsin (PSCW) - Tax Cuts and Jobs Act of 2017 - 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	Jun. 30, 2020	Dec. 31, 2019
Assets
Derivative assets	$ 3.9	$ 2
Liabilities
Derivative liabilities	2.9	5.4
Fair value measurements on a recurring basis
Assets
Derivative assets	3.9	2
Liabilities
Derivative liabilities	2.9	5.4
Fair value measurements on a recurring basis | Level 1
Assets
Derivative assets	1.1	0.4
Liabilities
Derivative liabilities	2.8	5.2
Fair value measurements on a recurring basis | Level 2
Assets
Derivative assets	0	0.1
Liabilities
Derivative liabilities	0.1	0.2
Fair value measurements on a recurring basis | Level 3
Assets
Derivative assets	2.8	1.5
Liabilities
Derivative liabilities	0	0
Fair value measurements on a recurring basis | Natural gas contracts
Assets
Derivative assets	1.1	0.4
Liabilities
Derivative liabilities	2.8	5.2
Fair value measurements on a recurring basis | Natural gas contracts | Level 1
Assets
Derivative assets	1.1	0.4
Liabilities
Derivative liabilities	2.8	5.2
Fair value measurements on a recurring basis | Natural gas contracts | Level 2
Assets
Derivative assets	0	0
Liabilities
Derivative liabilities	0	0
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	2.8	1.5
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	2.8	1.5
Fair value measurements on a recurring basis | Coal contracts
Assets
Derivative assets		0.1
Liabilities
Derivative liabilities	0.1	0.2
Fair value measurements on a recurring basis | Coal contracts | Level 1
Assets
Derivative assets		0
Liabilities
Derivative liabilities	0	0
Fair value measurements on a recurring basis | Coal contracts | Level 2
Assets
Derivative assets		0.1
Liabilities
Derivative liabilities	0.1	0.2
Fair value measurements on a recurring basis | Coal contracts | Level 3
Assets
Derivative assets		0
Liabilities
Derivative liabilities	$ 0	$ 0

FAIR VALUE MEASUREMENTS - LEVEL

FAIR VALUE MEASUREMENTS - LEVEL 3 RECONCILIATION (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Level 3 rollforward
Balance at the beginning of the period	$ 0.4	$ 2	$ 1.5	$ 4.4
Purchases	3.1	6.8	3.1	6.8
Settlements	(0.7)	(3)	(1.8)	(5.4)
Balance at the end of the period	$ 2.8	$ 5.8	$ 2.8	$ 5.8

FAIR VALUE MEASUREMENTS - FINAN

FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Financial instruments
Preferred stock	$ 30.4	$ 30.4
Carrying amount
Financial instruments
Preferred stock	30.4	30.4
Long-term debt	2,760	2,759.2
Fair value
Financial instruments
Preferred stock	29.1	29.5
Long-term debt	$ 3,382.2	$ 3,209.5

DERIVATIVE INSTRUMENTS - DERIVA

DERIVATIVE INSTRUMENTS - DERIVATIVE ASSETS AND LIABILITIES (Details) $ in Millions	Jun. 30, 2020USD ($)Instruments	Dec. 31, 2019USD ($)
Derivative assets
Other current derivative assets	$ 3.5	$ 1.9
Other long-term derivative assets	0.4	0.1
Total derivative assets	3.9	2
Derivative liabilities
Other current derivative liabilities	2.9	5.3
Other long-term derivative liabilities	0	0.1
Total derivative liabilities	2.9	5.4
Natural gas contracts
Derivative assets
Other current derivative assets	0.7	0.4
Other long-term derivative assets	0.4	0
Derivative liabilities
Other current derivative liabilities	2.8	5.1
Other long-term derivative liabilities	0	0.1
FTRs
Derivative assets
Other current derivative assets	2.8	1.5
Derivative liabilities
Other current derivative liabilities	0	0
Coal contracts
Derivative assets
Other current derivative assets	0	0
Other long-term derivative assets	0	0.1
Derivative liabilities
Other current derivative liabilities	0.1	0.2
Other long-term derivative liabilities	$ 0	$ 0
Derivatives designated as hedging instruments
Derivative instruments
Number of derivative instruments | Instruments	0

DERIVATIVE INSTRUMENTS - GAINS

DERIVATIVE INSTRUMENTS - GAINS (LOSSES) AND NOTIONAL VOLUMES (Details) MWh in Millions, MMBTU in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020USD ($)MWhMMBTU	Jun. 30, 2019USD ($)MMBTUMWh	Jun. 30, 2020USD ($)MWhMMBTU	Jun. 30, 2019USD ($)MWhMMBTU
Realized gains (losses)
Gains (losses)	$ (3.9)	$ (0.6)	$ (10)	$ (0.4)
Natural gas contracts
Realized gains (losses)
Gains (losses)	$ (4.4)	$ (1.1)	$ (11.3)	$ (2.5)
Notional sales volumes
Notional sales volumes | MMBTU	14	13.6	33.1	31.7
FTRs
Realized gains (losses)
Gains (losses)	$ 0.5	$ 0.5	$ 1.3	$ 2.1
Notional sales volumes
Notional sales volumes | MWh	5.1	5.6	10.2	11.1

DERIVATIVE INSTRUMENTS - BALANC

DERIVATIVE INSTRUMENTS - BALANCE SHEET OFFSETTING (Details) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Cash collateral
Cash collateral posted in margin accounts	$ 5.9	$ 8.5
Offsetting derivative assets
Gross amount recognized on the balance sheet	3.9	2
Gross amount not offset on the balance sheet	(0.8)	(0.4)
Net amount	3.1	1.6
Offsetting derivative liabilities
Gross amount recognized on the balance sheet	2.9	5.4
Gross amount not offset on the balance sheet	(2.8)	(5.2)
Net amount	0.1	0.2
Cash collateral posted	$ 2	$ 4.8

GUARANTEES (Details)

GUARANTEES (Details) $ in Millions	Jun. 30, 2020USD ($)
Standby letters of credit
Guarantees
Guarantees with expiration over 3 years	$ 26

EMPLOYEE BENEFITS-COSTS AND CON

EMPLOYEE BENEFITS-COSTS AND CONTRIBUTIONS (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Pension Benefits
Components of net periodic benefit costs
Service cost	$ 2.9	$ 2.5	$ 6.2	$ 6.3
Interest cost	9.4	11.1	18.9	22.6
Expected return on plan assets	(17.3)	(18)	(34.7)	(36.2)
Amortization of prior service (credit) cost	0	0.1	0	0.2
Amortization of net actuarial (gain) loss	9.8	6.8	18.9	14
Net periodic benefit (credit) cost	4.8	2.5	9.3	6.9
Contributions and payments related to pension and OPEB plans			2.3
Estimated future employer contributions for the remainder of the year	1.4		1.4
Other Postretirement Benefits
Components of net periodic benefit costs
Service cost	1	1	2.1	2.2
Interest cost	1.7	2.4	3.4	4.8
Expected return on plan assets	(3.9)	(3.6)	(7.8)	(7.1)
Amortization of prior service (credit) cost	(0.2)	(0.5)	(0.3)	(1)
Amortization of net actuarial (gain) loss	(2.9)	(0.7)	(5.3)	(1.1)
Net periodic benefit (credit) cost	(4.3)	$ (1.4)	(7.9)	$ (2.2)
Estimated future employer contributions for the remainder of the year	$ 0.1		$ 0.1

SEGMENT INFORMATION (Details)

SEGMENT INFORMATION (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020USD ($)	Jun. 30, 2019USD ($)	Jun. 30, 2020USD ($)segment	Jun. 30, 2019USD ($)
Segment Reporting [Abstract]
Number of reportable segments | segment			2
Significant items reported in the other segment | $	$ 0	$ 0	$ 0	$ 0

VARIABLE INTEREST ENTITIES (Det

VARIABLE INTEREST ENTITIES (Details) - Power purchase agreement $ in Millions	6 Months Ended
	Jun. 30, 2020USD ($)MW
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 | $	$ 18

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Billions	Jun. 30, 2020USD ($)
Minimum future commitments for purchase obligations
Purchase obligations	$ 9.3

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) $ in Millions	1 Months Ended	6 Months Ended	12 Months Ended	15 Months Ended
	May 31, 2020numberOfRevisions	Jun. 30, 2020USD ($)generating_unitsStates	Dec. 31, 2019USD ($)	Mar. 31, 2019MW
Manufactured gas plant remediation
Regulatory assets		$ 2,767.8	$ 2,755.2
Mercury and Air Toxics Standards | Electric
Air quality
Revisions to mercury and air toxics standards | numberOfRevisions	0
Climate Change | Electric
Air quality
Number of states challenging the ACE rule | States		22
Company goal percentage met in 2019 for carbon dioxide emissions reduction below 2005 levels			40.00%
Company goal for percentage of carbon dioxide emission reduction below 2005 levels by 2030		70.00%
Capacity of coal generation retired, in megawatts | MW				1,500
Climate Change | Natural gas
Air quality
Percentage of per mile methane emission reduction by 2030 from a 2011 baseline		30.00%
Steam Electric Effluent Limitation Guidelines | Electric
Water quality
Total units of OCPP and ERGS | generating_units		6
Expected costs to achieve required emissions reduction		$ 50
Manufactured Gas Plant Remediation | Natural gas
Manufactured gas plant remediation
Reserves for future environmental remediation		12.1	$ 12.1
Manufactured Gas Plant Remediation | Natural gas | Environmental remediation costs
Manufactured gas plant remediation
Regulatory assets		$ 21.2	$ 22.1

SUPPLEMENTAL CASH FLOW INFORM_3

SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019
Supplemental Cash Flow Information [Abstract]
Cash paid for interest, net of amount capitalized	$ 233.8	$ 239.1
Cash paid for income taxes, net	0	10.6
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs	$ 27.8	$ 6.6

REGULATORY ENVIRONMENT - COVID-

REGULATORY ENVIRONMENT - COVID-19 (Details)	Mar. 24, 2020order
Public Service Commission of Wisconsin (PSCW)
Public Utilities, General Disclosures [Line Items]
Number of orders issued in response to COVID-19	2

REGULATORY ENVIRONMENT - 2020 A

REGULATORY ENVIRONMENT - 2020 AND 2021 RATES (Details) - Public Service Commission of Wisconsin (PSCW) $ in Millions	1 Months Ended
	Dec. 31, 2019USD ($)
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%
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 rates
Public Utilities, General Disclosures [Line Items]
Approved rate increase	$ 15.3
Approved rate increase (as a percent)	0.50%
Electric rates | 2020 rates | Tax Cuts and Jobs Act of 2017
Public Utilities, General Disclosures [Line Items]
Amortization of regulatory liabilities	$ 65
Electric rates | 2021 rates | Tax Cuts and Jobs Act of 2017
Public Utilities, General Disclosures [Line Items]
Amortization of regulatory liabilities	65
Electric rates | 2020 and 2021 rates
Public Utilities, General Disclosures [Line Items]
Pleasant Prairie power plant's book value to be securitized	$ 100
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 rates
Public Utilities, General Disclosures [Line Items]
Approved rate increase	$ 10.4
Approved rate increase (as a percent)	2.80%
Natural gas rates | 2020 rates | Tax Cuts and Jobs Act of 2017
Public Utilities, General Disclosures [Line Items]
Amortization of regulatory liabilities	$ (5)
Natural gas rates | 2021 rates | Tax Cuts and Jobs Act of 2017
Public Utilities, General Disclosures [Line Items]
Amortization of regulatory liabilities	$ (5)
Natural gas rates | 2020 and 2021 rates | Tax Cuts and Jobs Act of 2017
Public Utilities, General Disclosures [Line Items]
Amortization period	4 years
Steam rates | 2020 rates
Public Utilities, General Disclosures [Line Items]
Approved rate increase	$ 1.9
Approved rate increase (as a percent)	8.60%

REGULATORY ENVIRONMENT - 2018 A

REGULATORY ENVIRONMENT - 2018 AND 2019 RATES (Details) - Public Service Commission of Wisconsin (PSCW) - 2018 and 2019 rates - USD ($) $ in Millions	1 Months Ended	24 Months Ended
	Sep. 30, 2017	Dec. 31, 2019
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
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%

REGULATORY ENVIRONMENT - LIQUEF

REGULATORY ENVIRONMENT - 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]
Natural gas supply | Bcf	1
Estimated project costs | $	$ 185

REGULATORY ENVIRONMENT - SOLAR

REGULATORY ENVIRONMENT - SOLAR GENERATION PROJECTS (Details) - Public Service Commission of Wisconsin (PSCW) - Badger Hollow II Solar Farm $ in Millions	Mar. 01, 2020USD ($)MW
Public Utilities, General Disclosures [Line Items]
Capacity of solar project approved | MW	100
Estimated share of cost for solar project | $	$ 130