Wisconsin Electric Power Company PFD 3.60% (WELPP) 10-Q 2 Nov 18 2018 Q3 Quarterly report Financial data

DOCUMENT AND ENTITY INFORMATION

DOCUMENT AND ENTITY INFORMATION	9 Months Ended
	Sep. 30, 2018shares
Document Entity Information [Abstract]
Entity registrant name	WISCONSIN ELECTRIC POWER CO
Entity central index key	107,815
Current fiscal year end date	--12-31
Entity filer category	Non-accelerated Filer
Document type	10-Q
Document period end date	Sep. 30, 2018
Document fiscal year focus	2,018
Document fiscal period focus	Q3
Amendment flag	false
Entity common stock, shares outstanding	33,289,327
Emerging growth company	false
Small business	false

CONDENSED CONSOLIDATED INCOME S

CONDENSED CONSOLIDATED INCOME STATEMENTS - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Statement [Abstract]
Operating revenues	$ 924	$ 943.8	$ 2,721.7	$ 2,771.2
Operating expenses
Cost of sales	316.5	336.5	944.4	959
Other operation and maintenance	384.7	331.2	1,086.9	982.2
Depreciation and amortization	87.4	83	259.6	247.8
Property and revenue taxes	27.6	28.3	82.1	85
Total operating expenses	816.2	779	2,373	2,274
Operating income	107.8	164.8	348.7	497.2
Other income, net	5.1	4.1	16.2	8.4
Interest expense	29.9	29.3	88.8	88
Other expense	(24.8)	(25.2)	(72.6)	(79.6)
Income before income taxes	83	139.6	276.1	417.6
Income tax (benefit) expense	(20.5)	49.9	(26.6)	150.2
Net income	103.5	89.7	302.7	267.4
Preferred stock dividend requirements	0.3	0.3	0.9	0.9
Net income attributed to common shareholder	$ 103.2	$ 89.4	$ 301.8	$ 266.5

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 4.1	$ 12.3
Accounts receivable and unbilled revenues, net of reserves of $41.6 and $39.5, respectively	453.4	513.8
Accounts receivable from related parties	97.8	109.1
Materials, supplies, and inventories	255.8	250.7
Prepayments	93.7	144.3
Other	10.4	9.4
Current assets	915.2	1,039.6
Long-term assets
Property, plant, and equipment, net of accumulated depreciation of $3,424.2 and $3,741.8, respectively	9,450	10,007.7
Regulatory assets	2,892.1	1,984.9
Other	97.7	89.4
Long-term assets	12,439.8	12,082
Total assets	13,355	13,121.6
Current liabilities
Short-term debt	346	210.9
Current portion of long-term debt	0	250
Current portion of capital lease obligations	48.2	42.5
Accounts payable	225.2	329.3
Accounts payable to related parties	161.4	131.5
Accrued payroll and benefits	42.4	53.4
Accrued taxes	80.4	58.2
Other	112.3	111.8
Current liabilities	1,015.9	1,187.6
Long-term liabilities
Long-term debt	2,413.9	2,412.3
Capital lease obligations	2,819.5	2,823.8
Deferred income taxes	1,216.6	1,155.5
Regulatory liabilities	1,899.1	1,708
Pension and OPEB obligations	153.5	143.2
Other	291.8	276.9
Long-term liabilities	8,794.4	8,519.7
Commitments and contingencies (Note 17)
Common shareholder's equity
Common stock – $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding	332.9	332.9
Additional paid in capital	831.2	802.7
Retained earnings	2,350.2	2,248.3
Common shareholder's equity	3,514.3	3,383.9
Preferred stock	30.4	30.4
Total liabilities and equity	$ 13,355	$ 13,121.6

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS (PARENTHETICALS) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Accounts receivable and unbilled revenues, reserves	$ 41.6	$ 39.5
Property, plant, and equipment, accumulated depreciation	$ 3,424.2	$ 3,741.8
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 CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Operating Activities
Net income	$ 302.7	$ 267.4
Reconciliation to cash provided by operating activities
Depreciation and amortization	259.6	247.8
Deferred income taxes and investment tax credits, net	(67.3)	105.2
Contributions and payments related to pension and OPEB plans	(5.3)	(5.9)
Change in –
Accounts receivable and unbilled revenues	74.4	49
Materials, supplies, and inventories	(5.1)	(23.6)
Prepaid taxes	32.3	31.2
Other current assets	22.4	5.3
Accounts payable	(65)	(14.6)
Accrued taxes	25.7	(15.2)
Other current liabilities	(6.3)	(15.6)
Other, net	198.1	(36.7)
Net cash provided by operating activities	766.2	594.3
Investing Activities
Capital expenditures	(441.7)	(405.7)
Proceeds from the sale of assets	0.7	22.9
Proceeds from assets transferred to affiliates	6.1	0
Payments for assets transferred from affiliates	(59.8)	0
Short-term notes receivable from related parties, net	0	(3.1)
Other, net	8.2	3.8
Net cash used in investing activities	(486.5)	(382.1)
Financing Activities
Change in short-term debt	135.1	(100)
Repayment of subsidiary note to parent	0	(18.5)
Retirement of long-term debt	(250)	0
Equity contribution from parent	28	75
Payment of dividends to parent	(200)	(180)
Payment of preferred stock dividends	(0.9)	(0.9)
Other	(0.1)	0.1
Net cash used in financing activities	(287.9)	(224.3)
Net change in cash and cash equivalents	(8.2)	(12.1)
Cash and cash equivalents at beginning of period	12.3	15.4
Cash and cash equivalents at end of period	$ 4.1	$ 3.3

GENERAL INFORMATION

GENERAL INFORMATION	9 Months Ended
	Sep. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
GENERAL INFORMATION	GENERAL INFORMATION As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, balance sheets, and statements of cash flows, 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 and its subsidiary, Bostco, which was dissolved in October 2018. 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, 2017 . 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 nine months ended September 30 , 2018 are not necessarily indicative of expected results for 2018 due to seasonal variations and other factors. In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results.

DISPOSITIONS

DISPOSITIONS	9 Months Ended
	Sep. 30, 2018
Discontinued Operations and Disposal Groups [Abstract]
DISPOSITIONS	DISPOSITION Other Segment – Sale of Bostco Real Estate Holdings In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space. During the first quarter of 2017, we recorded an insignificant gain on the sale, which was included in other income, net on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations associated with these assets remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.

OPERATING REVENUES

OPERATING REVENUES	9 Months Ended
	Sep. 30, 2018
Revenue from Contract with Customer [Abstract]
OPERATING REVENUES	OPERATING REVENUES Adoption of ASU 2014-09, Revenues from Contracts with Customers On January 1, 2018, we adopted ASU 2014-09, Revenues from Contracts with Customers, and the related amendments. In accordance with the guidance, we recognize revenues when control of the promised goods or services is transferred to our customers in an amount that reflects the consideration we expect to be entitled to receive in exchange for those goods or services. These revenues include unbilled revenues, which are estimated using the amount of energy delivered to our customers but not billed until after the end of the period. We adopted this standard using the modified retrospective method. Results for reporting periods beginning after January 1, 2018, are presented under the new standard. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Adoption of the standard did not result in an adjustment to our opening retained earnings balance as of January 1, 2018, and we do not expect the adoption of the standard to have a material impact on our net income in future periods. We adopted the following practical expedients and optional exemptions for the implementation of this standard: • We elected to exclude from the transaction price any amounts collected from customers for all sales taxes and other similar taxes. • When applicable, we elected to apply the standard to a portfolio of contracts with similar characteristics, primarily our tariff-based contracts, as we reasonably expect that the effects on the financial statements of applying this guidance to the portfolio would not differ materially from applying this guidance to the individual contracts. • We elected to recognize revenue in the amount we have the right to invoice for performance obligations satisfied over time when the consideration received from a customer corresponds directly with the value provided to the customer during the same period. • We elected to not disclose the remaining performance obligations of a contract that has an original expected duration of one year or less. • We elected to apply this standard only to contracts that are not completed as of the date of initial application. Disaggregation of Operating Revenues The following tables present our operating revenues disaggregated by revenue source. We only have revenues associated with 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 revenue and cash flows are affected by economic factors. For our utility segment, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations have different expectations of service, energy and demand requirements, and are impacted by regulatory activities within their jurisdictions. Comparable amounts have not been presented for the three and nine months ended September 30 , 2017, due to our adoption of this standard under the modified retrospective method. Wisconsin Electric Power Company Consolidated (in millions) Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Electric utility $ 877.0 $ 2,441.2 Natural gas utility 45.4 274.8 Total revenues from contracts with customers 922.4 2,716.0 Other operating revenues 1.6 5.7 Total operating revenues $ 924.0 $ 2,721.7 Revenues from Contracts with Customers Electric Utility Operating Revenues The following table disaggregates electric utility operating revenues into customer class: Electric Utility Operating Revenues (in millions) Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Residential $ 352.7 $ 929.1 Small commercial and industrial 276.9 775.2 Large commercial and industrial 177.9 499.2 Other 5.2 15.5 Total retail revenues 812.7 2,219.0 Wholesale 28.3 85.7 Resale 31.0 111.8 Steam 2.6 16.9 Other utility revenues 2.4 7.8 Total electric utility operating revenues $ 877.0 $ 2,441.2 Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. The rates, charges, terms, and conditions of service for sales to these customers are included in tariffs that have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month. Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have us provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. The rates, charges, terms and conditions of service for sales to wholesale customers are included in tariffs that have been approved by the FERC. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric operations and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis. We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales and net sales in a single hour are recorded as resale revenues. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets. For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days . For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility’s costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual current year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services. Natural Gas Utility Operating Revenues The following table disaggregates natural gas utility operating revenues into customer class: Natural Gas Utility Operating Revenues (in millions) Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Residential $ 20.8 $ 176.2 Commercial and industrial 8.1 81.9 Total retail revenues 28.9 258.1 Transport 2.2 9.7 Other utility revenues * 14.3 7.0 Total natural gas utility operating revenues $ 45.4 $ 274.8 * Includes amounts collected from customers for purchased gas adjustment costs. We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under our tariffs. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In certain of our service territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer. The transaction price of the performance obligations is valued using rates in our tariffs, which have been approved by the PSCW. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month. Consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days . Other Operating Revenues Other operating revenues consist primarily of the following: (in millions) Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Late payment charges $ 1.6 $ 6.5 Leases 0.3 2.5 Alternative revenues * (0.3 ) (3.3 ) Total other operating revenues $ 1.6 $ 5.7 * Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to wholesale true-ups, as discussed below. Alternative Revenues Alternative revenues are created from programs authorized by regulators that allow us to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers. Our only alternative revenue program relates to the wholesale electric service that we provide to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.

REGULATORY ASSETS AND LIABILITI

REGULATORY ASSETS AND LIABILITIES	9 Months Ended
	Sep. 30, 2018
Regulatory Assets and Liabilities Disclosure [Abstract]
REGULATORY ASSETS AND LIABILITIES	REGULATORY ASSETS AND LIABILITIES The following regulatory assets were reflected on our balance sheets at September 30, 2018 and December 31, 2017 . For more information on our regulatory assets, see Note 5, Regulatory Assets and Liabilities, in our 2017 Annual Report on Form 10-K. (in millions) September 30, 2018 December 31, 2017 Regulatory assets (1) Capital leases $ 853.4 $ 801.3 Plant retirements (2) 760.9 6.6 Unrecognized pension and OPEB costs 455.3 484.4 System support resource 315.0 298.9 Income tax (3) 256.5 — Electric transmission costs (4) 123.6 220.7 We Power generation 48.7 71.3 Asset retirement obligations 37.2 41.4 Environmental remediation costs 29.7 30.4 Other, net 11.8 29.9 Total regulatory assets $ 2,892.1 $ 1,984.9 (1) Based on prior and current rate treatment, we believe it is probable that we will continue to recover from customers the regulatory assets in this table. (2) For information on the retirement of our older and less efficient fossil fuel generating units, see Note 5, Property, Plant, and Equipment . (3) For information on the flow through of tax repairs and the regulatory treatment of the Tax Legislation, see Note 19, Regulatory Environment . (4) In May 2018, the PSCW issued an order requiring us to use a portion of our tax benefits related to the Tax Legislation that was signed into law in December 2017 to reduce our transmission regulatory assets. See Note 19, Regulatory Environment, for more information . The following regulatory liabilities were reflected on our balance sheets at September 30, 2018 and December 31, 2017 . For more information on our regulatory liabilities, see Note 5, Regulatory Assets and Liabilities, in our 2017 Annual Report on Form 10-K. (in millions) September 30, 2018 December 31, 2017 Regulatory liabilities Income tax * $ 983.7 $ 849.1 Removal costs 743.1 730.0 Mines deferral 115.4 95.1 Energy efficiency programs 12.9 11.1 Uncollectible expense 11.7 6.4 Other, net 38.4 29.4 Total regulatory liabilities $ 1,905.2 $ 1,721.1 Balance Sheet Presentation Current liabilities $ 6.1 $ 13.1 Regulatory liabilities 1,899.1 1,708.0 Total regulatory liabilities $ 1,905.2 $ 1,721.1 * For information on the regulatory treatment of the Tax Legislation, see Note 19, Regulatory Environment .

PROPERTY, PLANT, AND EQUIPMENT

PROPERTY, PLANT, AND EQUIPMENT	9 Months Ended
	Sep. 30, 2018
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT, AND EQUIPMENT	PROPERTY, PLANT, AND EQUIPMENT Utility Segment Plant to be Retired We have evaluated future plans for our older and less efficient fossil fuel generating units and have either retired or announced the retirement of the plants identified below. In addition, a severance liability was recorded in other current liabilities on our balance sheets related to these plant retirements. (in millions) Severance liability at December 31, 2017 $ 25.8 Severance payments (9.5 ) Other (3.0 ) Total severance liability at September 30, 2018 $ 13.3 Pleasant Prairie Power Plant The Pleasant Prairie power plant was retired effective April 10, 2018. The carrying value of this plant was $653.3 million at September 30, 2018 . This amount included the net book value of $755.8 million , which was classified as a regulatory asset on our balance sheet. In addition, a $102.5 million cost of removal reserve related to the Pleasant Prairie power plant was classified as a regulatory liability at September 30, 2018 . We continue to amortize this regulatory asset on a straight-line basis using the composite depreciation rates approved by the PSCW before this plant was retired. Amortization is included in depreciation and amortization in the income statement. The physical dismantlement of the plant will not occur immediately. It may take several years to finalize long-term plans for the site. See Note 17, Commitments and Contingencies, for more information . Presque Isle Power Plant In October 2017, the MPSC approved UMERC’s application to construct and operate approximately 180 MW of natural gas-fired generation in the Upper Peninsula of Michigan. The new units are expected to begin commercial operation during the second quarter of 2019. Upon receiving the MPSC's approval, retirement of the PIPP generating units became probable. In connection with MISO's April 2018 approval of the retirement of the plant, the PIPP units will be retired on or before May 31, 2019. The carrying value of the PIPP units was $186.9 million at September 30, 2018 . This amount included the net book value of $197.4 million , which was classified as plant to be retired within property, plant, and equipment on our balance sheet. In addition, a $10.5 million cost of removal reserve related to the PIPP units was classified as a regulatory liability at September 30, 2018 . These units are included in rate base, and we continue to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW. See Note 17, Commitments and Contingencies, for more information .

COMMON EQUITY

COMMON EQUITY	9 Months Ended
	Sep. 30, 2018
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 2017 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	9 Months Ended
	Sep. 30, 2018
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) September 30, 2018 December 31, 2017 Commercial paper Amount outstanding $ 346.0 $ 210.9 Weighted-average interest rate on amounts outstanding 2.30 % 1.81 % Our average amount of commercial paper borrowings based on daily outstanding balances during the nine months ended September 30, 2018 , was $162.1 million with a weighted-average interest rate during the period of 2.23% . 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 September 30, 2018 Revolving credit facility October 2022 $ 500.0 Less: Letters of credit issued inside credit facility $ 1.2 Commercial paper outstanding 346.0 * Available capacity under existing agreement $ 152.8 * See Note 8, Long-Term Debt, for more information about the use of proceeds from our issuance of long-term debt in October 2018.

LONG-TERM DEBT

LONG-TERM DEBT	9 Months Ended
	Sep. 30, 2018
Long-term Debt, Unclassified [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT In October 2018, we issued $300.0 million of 4.30% Debentures due October 15, 2048, and used the net proceeds to repay short-term debt and for working capital and other corporate purposes. In July 2018, we redeemed all $80.0 million of our series of tax-exempt pollution control refunding bonds. From August 2009 until they were called, the bonds were not reported in our long-term debt because they were previously repurchased by us. In June 2018, our $250.0 million of 1.70% Debentures matured, and the outstanding principal was paid with proceeds received from issuing commercial paper.

MATERIALS, SUPPLIES, AND INVENT

MATERIALS, SUPPLIES, AND INVENTORIES	9 Months Ended
	Sep. 30, 2018
Inventory Disclosure [Abstract]
MATERIALS, SUPPLIES, AND INVENTORIES	MATERIALS, SUPPLIES, AND INVENTORIES Our inventory consisted of: (in millions) September 30, 2018 December 31, 2017 Materials and supplies $ 142.4 $ 140.7 Fossil fuel 70.9 74.8 Natural gas in storage 42.5 35.2 Total $ 255.8 $ 250.7 Substantially all materials and supplies, fossil fuel, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting.

INCOME TAXES

INCOME TAXES	9 Months Ended
	Sep. 30, 2018
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES The effective tax rates of (24.7)% and (9.6)% for the three and nine months ended September 30, 2018, 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 Wisconsin rate settlement and the impact of the Tax Legislation, partially offset by state income taxes. The Tax Legislation, signed into law in December 2017, required us to remeasure our deferred income taxes and begin to amortize the resulting excess deferred income taxes beginning in 2018 in accordance with normalization requirements. See Note 19, Regulatory Environment, for more information on the Tax Legislation and the Wisconsin rate settlement. On December 22, 2017, the SEC staff issued guidance in Staff Accounting Bulletin 118 (SAB 118), Income Tax Accounting Implications of the Tax Legislation, which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, certain amounts related to bonus depreciation and future tax benefit utilization recorded in the financial statements as a result of the Tax Legislation are to be considered "provisional" as discussed in SAB 118 and subject to revision. We are awaiting additional guidance from industry and income tax authorities in order to finalize our accounting.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	9 Months Ended
	Sep. 30, 2018
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	FAIR VALUE MEASUREMENTS Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. When possible, we base the valuations of our 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. We recognize transfers between levels of the fair value hierarchy at their value as of the end of the reporting period. The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: September 30, 2018 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 1.9 $ 0.1 $ — $ 2.0 FTRs — — 6.4 6.4 Coal contracts — 0.2 — 0.2 Total derivative assets $ 1.9 $ 0.3 $ 6.4 $ 8.6 Derivative liabilities Natural gas contracts $ 0.1 $ — $ — $ 0.1 December 31, 2017 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.5 $ 0.1 $ — $ 0.6 Petroleum products contracts 0.9 — — 0.9 FTRs — — 2.4 2.4 Coal contracts — 0.7 — 0.7 Total derivative assets $ 1.4 $ 0.8 $ 2.4 $ 4.6 Derivative liabilities Natural gas contracts $ 2.0 $ 0.1 $ — $ 2.1 Coal contracts — 0.3 — 0.3 Total derivative liabilities $ 2.0 $ 0.4 $ — $ 2.4 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 Markets. The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2018 2017 2018 2017 Balance at the beginning of the period $ 8.7 $ 6.0 $ 2.4 $ 3.1 Purchases — — 9.4 6.9 Settlements (2.3 ) (2.3 ) (5.4 ) (6.3 ) Balance at the end of the period $ 6.4 $ 3.7 $ 6.4 $ 3.7 Fair Value of Financial Instruments The following table shows the financial instruments included on our balance sheets that are not recorded at fair value: September 30, 2018 December 31, 2017 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 28.3 $ 30.4 $ 30.5 Long-term debt, including current portion 2,413.9 2,570.5 2,662.3 2,976.3 The fair values of long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.

DERIVATIVE INSTRUMENTS

DERIVATIVE INSTRUMENTS	9 Months Ended
	Sep. 30, 2018
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: September 30, 2018 December 31, 2017 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 2.0 $ — $ 0.6 $ 1.9 Petroleum products contracts — — 0.9 — FTRs 6.4 — 2.4 — Coal contracts 0.2 — 0.6 0.1 Total other current * $ 8.6 $ — $ 4.5 $ 2.0 Other long-term Natural gas contracts $ — $ 0.1 $ — $ 0.2 Coal contracts — — 0.1 0.2 Total other long-term * — 0.1 0.1 0.4 Total $ 8.6 $ 0.1 $ 4.6 $ 2.4 * 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 derivative instruments are primarily recorded in cost of sales on the income statements. Our estimated notional sales volumes and realized gains (losses) were as follows: Three Months Ended September 30, 2018 Three Months Ended September 30, 2017 (in millions) Volumes Gains Volumes Gains (Losses) Natural gas contracts 12.2 Dth $ 0.3 4.6 Dth $ (0.5 ) Petroleum products contracts 0.9 gallons 0.3 4.1 gallons (0.5 ) FTRs 5.4 MWh 1.4 6.9 MWh 2.4 Total $ 2.0 $ 1.4 Nine Months Ended September 30, 2018 Nine Months Ended September 30, 2017 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 35.9 Dth $ (2.1 ) 17.8 Dth $ 0.2 Petroleum products contracts 3.4 gallons 0.9 13.9 gallons (1.4 ) FTRs 16.0 MWh 3.1 21.2 MWh 6.9 Total $ 1.9 $ 5.7 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 September 30, 2018 and December 31, 2017 , we had posted cash collateral of $1.7 million and $4.9 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: September 30, 2018 December 31, 2017 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 8.6 $ 0.1 $ 4.6 $ 2.4 Gross amount not offset on the balance sheet (0.1 ) (0.1 ) (1.3 ) (2.0 ) * Net amount $ 8.5 $ — $ 3.3 $ 0.4 * Includes cash collateral posted of $0.7 million .

EMPLOYEE BENEFITS

EMPLOYEE BENEFITS	9 Months Ended
	Sep. 30, 2018
Retirement Benefits [Abstract]
EMPLOYEE BENEFITS	EMPLOYEE BENEFITS The following tables show the components of net periodic pension and OPEB costs for our benefit plans: Pension Costs Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2018 2017 2018 2017 Service cost $ 3.3 $ 3.0 $ 9.9 $ 9.1 Interest cost 10.6 11.8 31.7 35.3 Expected return on plan assets (18.8 ) (19.2 ) (56.4 ) (57.5 ) Loss on plan settlement — 0.7 — 3.5 Amortization of prior service cost 0.2 0.3 0.6 0.9 Amortization of net actuarial loss 9.5 8.8 28.5 26.5 Net periodic benefit cost $ 4.8 $ 5.4 $ 14.3 $ 17.8 OPEB Costs Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2018 2017 2018 2017 Service cost $ 1.7 $ 1.8 $ 5.2 $ 5.2 Interest cost 2.8 3.0 8.3 9.2 Expected return on plan assets (3.8 ) (3.6 ) (11.6 ) (10.8 ) Amortization of prior service credit (0.6 ) (0.2 ) (1.7 ) (0.8 ) Net periodic benefit cost $ 0.1 $ 1.0 $ 0.2 $ 2.8 During the nine months ended September 30, 2018 , we made contributions and payments of $3.8 million related to our pension plans and $1.5 million related to our OPEB plans. We expect to make contributions and payments of $0.3 million related to our pension plans and $3.0 million related to our OPEB plans during the remainder of 2018 , dependent upon various factors affecting us, including our liquidity position and the effects of the new Tax Legislation. Effective January 1, 2018, we adopted ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, which modifies certain aspects of the accounting for employee benefit costs. Under the new guidance, only the service cost component can be included in total operating expenses. The remaining components of net periodic benefit cost (credit) are required to be presented in the income statement separately from the service cost component, outside of operating income. As required, this change was applied retrospectively to all prior periods presented. Accordingly, for the three and nine months ended September 30 , 2018 and 2017 , we have presented the service cost component of our retirement benefit plans in other operation and maintenance on the income statements, while presenting the non-service components in other income, net. The following table shows the non-service (credit) cost components of net benefit costs: Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2018 2017 2018 2017 Non-service (credit) cost components $ (1.6 ) $ 1.4 $ (4.5 ) $ 5.9 For the three and nine months ended September 30 , 2017 , the non-service components of net benefit cost (credit) were reclassified from other operation and maintenance to other income, net, on our income statements. Under ASU 2017-07, only the service cost component of net periodic benefit cost is eligible for capitalization to property, plant, and equipment. In prior periods, a portion of all net benefit cost components was capitalized to property, plant, and equipment. As required, this amendment was applied prospectively, beginning January 1, 2018. As a result of the application of accounting principles for rate regulated entities, the non-service cost (credit) components of the net benefit cost (credit) that are no longer eligible for capitalization under this standard, but are capitalized under the regulatory framework, are presented as regulatory assets or liabilities rather than property, plant, and equipment.

SEGMENT INFORMATION

SEGMENT INFORMATION	9 Months Ended
	Sep. 30, 2018
Segment Reporting [Abstract]
SEGMENT INFORMATION	SEGMENT INFORMATION We use operating income to measure segment profitability and to allocate resources to our businesses. At September 30, 2018 , we reported two segments, which are described below. Our utility segment includes both our electric and 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, and to one customer in the Upper Peninsula of Michigan. Our electric utility operations also include our steam operations, which produce, distribute, and sell steam to customers in metropolitan Milwaukee, Wisconsin. 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 our three service areas within southeastern, east central, and northern Wisconsin. Our other segment included Bostco, our non-utility subsidiary that was originally formed to develop and invest in real estate. In March 2017, we sold substantially all of the remaining assets of Bostco, and, in October 2018, Bostco was dissolved. See Note 2, Disposition, for more information . The following tables show summarized financial information for the three and nine months ended September 30 , 2018 and 2017 , related to our reportable segments: (in millions) Utility Other Wisconsin Electric Power Company Consolidated Three Months Ended September 30, 2018 Operating revenues $ 924.0 $ — $ 924.0 Other operation and maintenance 384.7 — 384.7 Depreciation and amortization 87.4 — 87.4 Operating income 107.8 — 107.8 Interest expense 29.9 — 29.9 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Three Months Ended September 30, 2017 Operating revenues $ 943.8 $ — $ 943.8 Other operation and maintenance * 331.2 — 331.2 Depreciation and amortization 83.0 — 83.0 Operating income * 164.8 — 164.8 Interest expense 29.3 — 29.3 * Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 13, Employee Benefits, for more information on this new standard. (in millions) Utility Other Wisconsin Electric Power Company Consolidated Nine Months Ended September 30, 2018 Operating revenues $ 2,721.7 $ — $ 2,721.7 Other operation and maintenance 1,086.9 — 1,086.9 Depreciation and amortization 259.6 — 259.6 Operating income 348.7 — 348.7 Interest expense 88.8 — 88.8 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Nine Months Ended September 30, 2017 Operating revenues $ 2,771.2 $ — $ 2,771.2 Other operation and maintenance * 982.2 — 982.2 Depreciation and amortization 247.8 — 247.8 Operating income * 497.2 — 497.2 Interest expense 87.7 0.3 88.0 * Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 13, Employee Benefits, for more information on this new standard.

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	9 Months Ended
	Sep. 30, 2018
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Determination Methodology and Factors [Abstract]
VARIABLE INTEREST ENTITIES	VARIABLE INTEREST ENTITIES The primary beneficiary of a variable interest entity must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in variable interest entities. We assess our relationships with potential variable interest entities, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to power purchase agreements, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance. Purchased Power Agreement We have a purchased power agreement that represents a variable interest. This agreement is for 236 MW of firm capacity from a natural gas-fired cogeneration facility, and we account for it as a capital lease. The agreement includes no minimum energy requirements over the remaining term of approximately four 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 purchased power agreement. We have approximately $60.4 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under this contract for the nine months ended September 30, 2018 and 2017 were $14.1 million and $13.5 million , respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

RELATED PARTIES

RELATED PARTIES	9 Months Ended
	Sep. 30, 2018
Related Party Transactions [Abstract]
RELATED PARTIES	RELATED PARTIES We routinely enter into transactions with related parties, including WEC Energy Group, its other subsidiaries, ATC (a for-profit electric transmission company regulated by the FERC and certain state regulatory commissions), and other affiliated entities. We provide and receive services, property, and other items of value to and from our parent, WEC Energy Group, and other subsidiaries of WEC Energy Group. On January 1, 2017, based upon input we received from the PSCW, we transferred our $415.4 million investment in ATC, and the related receivable for distributions approved and recorded in December 2016 to another subsidiary of WEC Energy Group. In addition, during 2017 we transferred $186.8 million of related deferred income tax liabilities. These transactions were non-cash equity transfers recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss. We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed by ATC. Services are billed to and from ATC under agreements approved by the PSCW, at each of our fully allocated costs. Our balance sheets included the following receivables and payables related to transactions entered into with ATC: (in millions) September 30, 2018 December 31, 2017 Accounts receivable Services provided to ATC $ 2.4 $ 0.8 Accounts payable Services received from ATC 19.3 22.2 The following table shows activity associated with our related party transactions: Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2018 2017 2018 2017 Lease agreements Lease payments to We Power (1) $ 92.7 $ 104.3 $ 280.0 $ 315.4 Construction work in progress billed to We Power 4.4 5.9 13.2 31.1 Transactions with WBS (2) Billings to WBS 4.1 60.2 12.8 177.2 Billings from WBS 64.2 (3) 49.4 240.9 (3) 152.1 Transactions with WPS Natural gas purchases from WPS 0.6 0.8 1.6 1.3 Billings to WPS (2) 3.9 6.4 11.2 14.1 Billings from WPS (2) 1.5 1.4 6.6 3.6 Transactions with WG Natural gas purchases from WG 1.4 1.4 4.0 4.0 Billings to WG (2) 10.5 (4) 16.3 37.6 (4) 48.2 Billings from WG (2) 4.8 6.0 14.5 17.3 Transactions with UMERC Electric sales to UMERC 7.4 9.0 22.4 23.1 Billings to UMERC (2) 5.2 18.7 12.3 52.6 Transactions with Bluewater (5) Storage service fees 4.5 1.4 10.4 1.4 Transactions with ATC Charges to ATC for services and construction 3.7 2.9 9.4 8.1 Charges from ATC for network transmission services 57.9 60.4 174.0 181.1 Refund from ATC related to a FERC audit — — 15.4 — Refund from ATC per FERC ROE order — — — 19.4 (1) We make lease payments to We Power, another subsidiary of WEC Energy Group, for PWGS Units 1 and 2 and ERGS Units 1 and 2. Lease payments were reduced in 2018 as a result of tax savings related to Tax Legislation. (2) Includes amounts billed for services, pass through costs, and other items in accordance with approved affiliated interest agreements. (3) Includes $2.2 million and $59.8 million for the transfer of certain software assets from WBS during the three and nine months ended September 30, 2018 , respectively. There were no software assets transferred from WBS during 2017. (4) Includes $0.1 million and $5.3 million for the transfer of certain software assets to WG during the three and nine months ended September 30, 2018 , respectively. There were no software assets transferred to WG during 2017. (5) WEC Energy Group's acquisition of Bluewater was completed June 30, 2017. See below for more information. Upper Michigan Energy Resources Corporation In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan. UMERC, a subsidiary of WEC Energy Group, became operational effective January 1, 2017, and we transferred customers and property, plant, and equipment as of that date. We transferred approximately 27,500 retail electric customers and 50 electric distribution-only customers to UMERC, along with approximately 2,500 miles of electric distribution lines. We also transferred related electric distribution substations in the Upper Peninsula of Michigan and all property rights for the distribution assets to UMERC. The book value of net assets, including the related deferred income tax liabilities, transferred to UMERC from us in 2017 was $61.1 million . This transaction was a non-cash equity transfer recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss. UMERC currently meets its market obligations through power purchase agreements with us and WPS. WEC Energy Group's Acquisition of Natural Gas Storage Facilities in Michigan On June 30, 2017, WEC Energy Group completed the acquisition of Bluewater for $226.0 million . Bluewater owns natural gas storage facilities in Michigan that provide a portion of the current storage needs for our natural gas utility operations. In September 2017, we finalized a long-term service agreement with a wholly owned subsidiary of Bluewater to take the allocated storage, which was then approved by the PSCW in November 2017.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	9 Months Ended
	Sep. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES We 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 September 30, 2018 , were $10,266.8 million . Environmental Matters Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as sulfur dioxide, nitrogen oxide, fine particulates, mercury, and GHGs; water intake and discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites. Air Quality 8-Hour Ozone National Ambient Air Quality Standards After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, which lowered the limit for ground-level ozone, creating a more stringent standard than the 2008 National Ambient Air Quality Standards. The EPA issued final nonattainment area designations on May 1, 2018. The following counties within our service territory were designated as partial nonattainment: Kenosha, Manitowoc, Northern Milwaukee/Ozaukee, and Sheboygan shorelines. The state of Wisconsin will need to develop a state implementation plan to bring these areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020. We believe we are well positioned to meet the requirements associated with the ozone standard and do not expect to incur significant costs to comply. Climate Change In 2015, the EPA issued a final rule regulating GHG emissions from existing generating units, referred to as the Clean Power Plan, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In February 2016, the Supreme Court stayed the effectiveness of the CPP until disposition of certain litigation in the D.C. Circuit Court of Appeals challenging the rule and, to the extent that further appellate review is sought, at the Supreme Court. In April 2017, pursuant to motions made by the EPA, the D.C. Circuit Court of Appeals ordered the challenges to the CPP, as well as related performance standards for new, reconstructed, and modified fossil-fueled power plants, to be held in abeyance, which remains the case. In December 2017, the EPA issued an advanced notice of proposed rulemaking to solicit input on whether it is appropriate to replace the CPP. Then, in August 2018, the EPA issued a proposed replacement rule for the CPP, the Affordable Clean Energy (ACE) rule. The proposed ACE rule would require the EPA to develop emission guidelines for states to use to develop their individual state plans. The state plans would focus on reducing GHG emissions by improving the efficiency of fossil-fueled power plants. The type of power plants most likely affected by this rule would be coal-fueled electric generating units. The EPA is also considering revisions to new source review (NSR) permitting as part of this rulemaking that could allow certain power plant efficiency improvement projects to be implemented without triggering NSR permitting requirements. We submitted comments on the ACE rule by the October 31, 2018 due date. We continue to evaluate opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute towards long-term GHG reductions. WEC Energy Group's plan, which includes us, is to work with its industry partners, environmental groups, and the State of Wisconsin, with goals of reducing CO 2 emissions by approximately 40% and 80% below 2005 levels by 2030 and 2050, respectively. We have implemented and continue to evaluate numerous options in order to meet WEC Energy Group's CO 2 reduction goals. As a result of WEC Energy Group's generation reshaping plan, we expect to retire 1,547 MW of coal generation by 2020, including PIPP, which we are required to retire by May 31, 2019, and Pleasant Prairie power plant, which was retired in April 2018. See Note 5, Property, Plant, and Equipment, for more information . In addition, we are evaluating our goals, and possible subsequent actions, with respect to national and international efforts to reduce future GHG emissions in order to limit future global temperature increases to less than two degrees Celsius. 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, which requires that the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts from both impingement (entrapping organisms on water intake screens) and entrainment (drawing organisms into water intake). 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. Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities satisfy the IM BTA requirements. BTA determinations must also be made by the WDNR and MDEQ to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. We have received an EM BTA determination by the WDNR, with EPA concurrence, for our intake modification at the Valley power plant. Due to the retirement of the Pleasant Prairie power plant and our plans to retire PIPP, we do not believe that BTA determinations for EM will be necessary for these units. Although we currently believe that existing technologies at PWGS and OC 5 through OC 8 satisfy the EM BTA requirements, BTA determinations to address EM reduction requirements will not be made until discharge permits are renewed for these units. Until that time, we cannot determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements for these units. During 2018, we will continue to evaluate options to address the EM BTA requirements for these units. We have also provided information to the WDNR and the MDEQ about planned unit retirements. Based on discussions with the MDEQ, if we submit a signed certification stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2023), the EM BTA requirements will be waived. We expect to submit the letter identifying the last operating date for PIPP to the MDEQ no later than early 2019, ahead of when the agency begins processing our pending application for the National Pollutant Discharge Elimination System permit reissuance. As a result of past capital investments completed to address 316(b) compliance, we believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation. Steam Electric Effluent Limitation Guidelines The EPA's final steam electric effluent limitation guidelines (ELG) rule took effect in January 2016. This rule created new requirements for several types of power plant wastewaters. The two new requirements that affect us relate to discharge limits for bottom ash transport water (BATW) and wet flue gas desulfurization (FGD) wastewater. Various petitions challenging the rule were consolidated and are pending in the United States Court of Appeals for the Fifth Circuit. In April 2017, the EPA issued an administrative stay of certain compliance deadlines while further reviewing the rule. In September 2017, the EPA issued a final rule (Postponement Rule) to postpone the earliest compliance date to November 1, 2020 for the BATW and wet FGD wastewater requirements. The latest ELG rule compliance date remains December 31, 2023 for any new wastewater treatment requirements contained in power plant discharge permits. This rule applies to wastewater discharges from our power plant processes in Wisconsin. Litigation over various aspects of the final ELG rule and the Postponement Rule is pending in several Federal Courts. Due to pending generating unit retirements, the only facilities that will require bottom ash system modifications are Oak Creek Units 7 and 8. One wastewater treatment system modification may be required for the wet FGD discharges from the six units that make up the OCPP and ERGS. As a result of past capital investments completed to address ELG compliance, we believe our fleet overall is well positioned to meet this new regulation. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, as currently constructed, the ELG rule will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use. The final rule would phase in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. New requirements for wet scrubber wastewater treatment would require additional zero liquid discharge or other advanced treatment capital improvements for the OCPP and ERGS. The rule also would require dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are required by the new rule, and modifications would be required at OC 7 and OC 8. We are beginning preliminary engineering for compliance with the rule and estimate approximately $50 million would be required to design and install these advanced treatment and bottom ash transport systems. This estimate reflects the retirement of PIPP as a result of WEC Energy Group's generation reshaping plan discussed in Climate Change above. 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 related to manufactured gas plant sites: (in millions) September 30, 2018 December 31, 2017 Regulatory assets $ 29.7 $ 30.4 Reserves for future remediation * 18.5 18.5 * 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 effect on our financial condition or results of operations.

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	9 Months Ended
	Sep. 30, 2018
Supplemental Cash Flow Information [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	SUPPLEMENTAL CASH FLOW INFORMATION Nine Months Ended September 30 (in millions) 2018 2017 Cash (paid) for interest, net of amount capitalized $ (64.1 ) $ (62.1 ) Cash (paid) for income taxes, net (14.7 ) (60.7 ) Significant noncash transactions: Accounts payable related to construction costs 4.0 8.5 Accounts receivable related to assets transferred to affiliates 2.7 — Transfer of investment in ATC to another subsidiary of WEC Energy Group (1) (2) — 415.4 Transfer of net assets to UMERC (1) — 60.0 (1) See Note 16, Related Parties, for more information on these transactions. (2) The amount transferred included a $13.4 million receivable for distributions approved and recorded in December 2016.

REGULATORY ENVIRONMENT

REGULATORY ENVIRONMENT	9 Months Ended
	Sep. 30, 2018
Regulated Operations [Abstract]
REGULATORY ENVIRONMENT	REGULATORY ENVIRONMENT Tax Cuts and Jobs Act of 2017 In December 2017, we deferred for return to ratepayers, through future refunds, bill credits, or reductions in other regulatory assets, the estimated tax benefit of $1,065 million related to the Tax Legislation that was signed into law in December 2017. This tax benefit resulted from the revaluation of deferred taxes. The Tax Legislation also reduced the corporate federal tax rate from a maximum of 35% to a 21% rate, effective January 1, 2018. In May 2018, the PSCW issued an order regarding the benefits associated with the Tax Legislation. The PSCW order requires our electric utility operations to use 80% of the current 2018 and 2019 tax benefits to reduce our transmission regulatory asset. The remaining 20% is to be returned to electric customers in the form of bill credits. For our natural gas utility operations, the PSCW indicated that 100% of the current 2018 and 2019 tax benefits should be returned to natural gas customers in the form of bill credits. Regarding the net tax benefit associated with the revaluation of deferred taxes, amortization required in accordance with normalization accounting is to be used to reduce our transmission regulatory asset for our electric utility operations and is being deferred for our natural gas utility operations. The timing and method of returning the remaining net tax benefit associated with the revaluation of deferred taxes for our electric and natural gas utility operations was not addressed and will be determined in a future rate proceeding. We currently serve one retail electric customer in Michigan, and have reached a settlement with that customer. That settlement was approved by the MPSC in May 2018 and addresses all base rate impacts of the Tax Legislation, which will be returned to the customer through bill credits. 2018 and 2019 Rates During April 2017, we, along with WG and WPS, 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 freezes base rates through 2019 for our electric, natural gas, and steam customers. Based on the PSCW order, our authorized ROE remains at 10.2% , and our current capital cost structure will remain unchanged through 2019. Various intervenors had filed requests for rehearing, all of which have been denied. In addition to freezing base rates, the settlement agreement extends and expands the electric real-time market pricing program options for large commercial and industrial customers and mitigates the continued growth of certain escrowed costs during the base rate freeze period by accelerating the recognition of certain tax benefits. We will flow 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 offsets 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 earn above our authorized ROE, 50% of the first 50 basis points of additional utility earnings must be shared with customers. All utility earnings above the first 50 basis points must also be shared with customers.

NEW ACCOUNTING PRONOUNCEMENTS

NEW ACCOUNTING PRONOUNCEMENTS	9 Months Ended
	Sep. 30, 2018
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
NEW ACCOUNTING PRONOUNCEMENTS	NEW ACCOUNTING PRONOUNCEMENTS Leases In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which revises current guidance (Topic 840) regarding accounting for leases. Revisions include requiring a lessee to recognize a lease asset and a lease liability on its balance sheet for each lease, including operating leases, with an initial term greater than 12 months. In addition, required quantitative and qualitative disclosures related to lease agreements were expanded. For lessors however, accounting for leases is largely unchanged from previous provisions of GAAP. This guidance will be effective for our financial statements for periods beginning after December 15, 2018, and interim periods within those annual periods. Companies are able to elect several practical expedients to aid in the transition to Topic 842. The following three practical expedients must all be elected together, and we intend to elect these practical expedients to aid in our implementation of Topic 842. • An entity need not reassess whether any expired or existing contracts are or contain leases. • An entity need not reassess the lease classification for any expired or existing leases (that is, all existing leases that were classified as operating leases in accordance with Topic 840, Leases, will continue to be classified as operating leases, and all existing leases that were classified as capital leases in accordance with Topic 840 will continue to be classified as capital leases). • An entity need not reassess initial direct costs for any existing leases. Other practical expedients that can be elected individually, and that we are still assessing as part of our implementation of Topic 842, are as follows: • An entity may use hindsight in determining the lease term and in assessing impairment of the entity’s right-of-use assets. • An entity may elect, by class of underlying asset, to account for the nonlease components in a contract as part of the single lease component to which they are related. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842, which is an amendment to ASU 2016-02. Land easements (also commonly referred to as rights of way) represent the right to use, access or cross another entity's land for a specified purpose. This new guidance permits an entity to elect a transitional practical expedient, to be applied consistently, to not evaluate under Topic 842 land easements that were already in existence or had expired at the time of the entity's adoption of Topic 842. Once Topic 842 is adopted, an entity is required to apply Topic 842 prospectively to all new (or modified) land easements to determine whether the arrangement should be accounted for as a lease. ASU 2018-01 is effective for fiscal years beginning after December 15, 2018. We intend to elect this practical expedient. In July 2018, the FASB issued ASU 2018-11, "Leases (Topic 842): Targeted Improvements," which amends ASU 2016-02 and allows entities the option to initially apply Topic 842 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. We are in the process of finalizing our inventory of leases, which includes continuing to monitor activities of the FASB as well as utility industry implementation guidance. We also continue to document technical accounting issues, analyze financial reporting implications and implement required changes to internal controls and processes. We plan to adopt Topic 842 effective January 1, 2019, using the optional transition method to apply the new guidance as of January 1, 2019, rather than as of the earliest period presented. Upon adoption, we do expect an increase in assets and liabilities (which we are still in the process of quantifying), although we do not expect the guidance to have a significant impact on our results of operations or cash flows. Financial Instruments Credit Losses In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. This ASU introduces a new impairment model known as the current expected credit loss model. The ASU requires a financial asset measured at amortized cost to be presented at the net amount expected to be collected. Previously, recognition of the full amount of credit losses was generally delayed until the loss was probable of occurring. We are currently assessing the effects this guidance may have on our financial statements.

GENERAL INFORMATION (Policies)

GENERAL INFORMATION (Policies)	9 Months Ended
	Sep. 30, 2018
Accounting policies
Consolidation	As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, balance sheets, and statements of cash flows, 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 and its subsidiary, Bostco, which was dissolved in October 2018.
Basis of accounting	We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2017 . 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 nine months ended September 30 , 2018 are not necessarily indicative of expected results for 2018 due to seasonal variations and other factors. In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results.
Fair Value Measurements	Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. When possible, we base the valuations of our 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. We recognize transfers between levels of the fair value hierarchy at their value as of the end of the reporting period.
Derivative Instruments	We use derivatives as part of our risk management program to manage the risks associated with the price volatility of 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	Leases In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which revises current guidance (Topic 840) regarding accounting for leases. Revisions include requiring a lessee to recognize a lease asset and a lease liability on its balance sheet for each lease, including operating leases, with an initial term greater than 12 months. In addition, required quantitative and qualitative disclosures related to lease agreements were expanded. For lessors however, accounting for leases is largely unchanged from previous provisions of GAAP. This guidance will be effective for our financial statements for periods beginning after December 15, 2018, and interim periods within those annual periods. Companies are able to elect several practical expedients to aid in the transition to Topic 842. The following three practical expedients must all be elected together, and we intend to elect these practical expedients to aid in our implementation of Topic 842. • An entity need not reassess whether any expired or existing contracts are or contain leases. • An entity need not reassess the lease classification for any expired or existing leases (that is, all existing leases that were classified as operating leases in accordance with Topic 840, Leases, will continue to be classified as operating leases, and all existing leases that were classified as capital leases in accordance with Topic 840 will continue to be classified as capital leases). • An entity need not reassess initial direct costs for any existing leases. Other practical expedients that can be elected individually, and that we are still assessing as part of our implementation of Topic 842, are as follows: • An entity may use hindsight in determining the lease term and in assessing impairment of the entity’s right-of-use assets. • An entity may elect, by class of underlying asset, to account for the nonlease components in a contract as part of the single lease component to which they are related. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842, which is an amendment to ASU 2016-02. Land easements (also commonly referred to as rights of way) represent the right to use, access or cross another entity's land for a specified purpose. This new guidance permits an entity to elect a transitional practical expedient, to be applied consistently, to not evaluate under Topic 842 land easements that were already in existence or had expired at the time of the entity's adoption of Topic 842. Once Topic 842 is adopted, an entity is required to apply Topic 842 prospectively to all new (or modified) land easements to determine whether the arrangement should be accounted for as a lease. ASU 2018-01 is effective for fiscal years beginning after December 15, 2018. We intend to elect this practical expedient. In July 2018, the FASB issued ASU 2018-11, "Leases (Topic 842): Targeted Improvements," which amends ASU 2016-02 and allows entities the option to initially apply Topic 842 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. We are in the process of finalizing our inventory of leases, which includes continuing to monitor activities of the FASB as well as utility industry implementation guidance. We also continue to document technical accounting issues, analyze financial reporting implications and implement required changes to internal controls and processes. We plan to adopt Topic 842 effective January 1, 2019, using the optional transition method to apply the new guidance as of January 1, 2019, rather than as of the earliest period presented. Upon adoption, we do expect an increase in assets and liabilities (which we are still in the process of quantifying), although we do not expect the guidance to have a significant impact on our results of operations or cash flows. Financial Instruments Credit Losses In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. This ASU introduces a new impairment model known as the current expected credit loss model. The ASU requires a financial asset measured at amortized cost to be presented at the net amount expected to be collected. Previously, recognition of the full amount of credit losses was generally delayed until the loss was probable of occurring. We are currently assessing the effects this guidance may have on our financial statements.
Utility segment
Disaggregation of Operating Revenues
Revenue Recognition	Adoption of ASU 2014-09, Revenues from Contracts with Customers On January 1, 2018, we adopted ASU 2014-09, Revenues from Contracts with Customers, and the related amendments. In accordance with the guidance, we recognize revenues when control of the promised goods or services is transferred to our customers in an amount that reflects the consideration we expect to be entitled to receive in exchange for those goods or services. These revenues include unbilled revenues, which are estimated using the amount of energy delivered to our customers but not billed until after the end of the period. We adopted this standard using the modified retrospective method. Results for reporting periods beginning after January 1, 2018, are presented under the new standard. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Adoption of the standard did not result in an adjustment to our opening retained earnings balance as of January 1, 2018, and we do not expect the adoption of the standard to have a material impact on our net income in future periods. We adopted the following practical expedients and optional exemptions for the implementation of this standard: • We elected to exclude from the transaction price any amounts collected from customers for all sales taxes and other similar taxes. • When applicable, we elected to apply the standard to a portfolio of contracts with similar characteristics, primarily our tariff-based contracts, as we reasonably expect that the effects on the financial statements of applying this guidance to the portfolio would not differ materially from applying this guidance to the individual contracts. • We elected to recognize revenue in the amount we have the right to invoice for performance obligations satisfied over time when the consideration received from a customer corresponds directly with the value provided to the customer during the same period. • We elected to not disclose the remaining performance obligations of a contract that has an original expected duration of one year or less. • We elected to apply this standard only to contracts that are not completed as of the date of initial application.
Revenue Recognition for Alternative Revenue Programs	Alternative Revenues Alternative revenues are created from programs authorized by regulators that allow us to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers. Our only alternative revenue program relates to the wholesale electric service that we provide to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.
Utility segment | Electric
Disaggregation of Operating Revenues
Revenue Recognition	Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. The rates, charges, terms, and conditions of service for sales to these customers are included in tariffs that have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month. Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have us provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. The rates, charges, terms and conditions of service for sales to wholesale customers are included in tariffs that have been approved by the FERC. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric operations and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis. We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales and net sales in a single hour are recorded as resale revenues. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets. For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days . For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility’s costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual current year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services.
Utility segment | Natural gas
Disaggregation of Operating Revenues
Revenue Recognition	We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under our tariffs. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In certain of our service territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer. The transaction price of the performance obligations is valued using rates in our tariffs, which have been approved by the PSCW. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month. Consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days .

OPERATING REVENUES (Tables)

OPERATING REVENUES (Tables) - Utility segment	9 Months Ended
	Sep. 30, 2018
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	The following tables present our operating revenues disaggregated by revenue source. We only have revenues associated with 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 revenue and cash flows are affected by economic factors. For our utility segment, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations have different expectations of service, energy and demand requirements, and are impacted by regulatory activities within their jurisdictions. Comparable amounts have not been presented for the three and nine months ended September 30 , 2017, due to our adoption of this standard under the modified retrospective method. Wisconsin Electric Power Company Consolidated (in millions) Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Electric utility $ 877.0 $ 2,441.2 Natural gas utility 45.4 274.8 Total revenues from contracts with customers 922.4 2,716.0 Other operating revenues 1.6 5.7 Total operating revenues $ 924.0 $ 2,721.7
Revenues from contracts with customers | Electric
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	Electric Utility Operating Revenues The following table disaggregates electric utility operating revenues into customer class: Electric Utility Operating Revenues (in millions) Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Residential $ 352.7 $ 929.1 Small commercial and industrial 276.9 775.2 Large commercial and industrial 177.9 499.2 Other 5.2 15.5 Total retail revenues 812.7 2,219.0 Wholesale 28.3 85.7 Resale 31.0 111.8 Steam 2.6 16.9 Other utility revenues 2.4 7.8 Total electric utility operating revenues $ 877.0 $ 2,441.2
Revenues from contracts with customers | Natural gas
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	Natural Gas Utility Operating Revenues The following table disaggregates natural gas utility operating revenues into customer class: Natural Gas Utility Operating Revenues (in millions) Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Residential $ 20.8 $ 176.2 Commercial and industrial 8.1 81.9 Total retail revenues 28.9 258.1 Transport 2.2 9.7 Other utility revenues * 14.3 7.0 Total natural gas utility operating revenues $ 45.4 $ 274.8 * Includes amounts collected from customers for purchased gas adjustment costs.
Other operating revenues
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	Other Operating Revenues Other operating revenues consist primarily of the following: (in millions) Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Late payment charges $ 1.6 $ 6.5 Leases 0.3 2.5 Alternative revenues * (0.3 ) (3.3 ) Total other operating revenues $ 1.6 $ 5.7 * Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to wholesale true-ups, as discussed below.

REGULATORY ASSETS AND LIABILI_2

REGULATORY ASSETS AND LIABILITIES (Tables)	9 Months Ended
	Sep. 30, 2018
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of regulatory assets	The following regulatory assets were reflected on our balance sheets at September 30, 2018 and December 31, 2017 . For more information on our regulatory assets, see Note 5, Regulatory Assets and Liabilities, in our 2017 Annual Report on Form 10-K. (in millions) September 30, 2018 December 31, 2017 Regulatory assets (1) Capital leases $ 853.4 $ 801.3 Plant retirements (2) 760.9 6.6 Unrecognized pension and OPEB costs 455.3 484.4 System support resource 315.0 298.9 Income tax (3) 256.5 — Electric transmission costs (4) 123.6 220.7 We Power generation 48.7 71.3 Asset retirement obligations 37.2 41.4 Environmental remediation costs 29.7 30.4 Other, net 11.8 29.9 Total regulatory assets $ 2,892.1 $ 1,984.9 (1) Based on prior and current rate treatment, we believe it is probable that we will continue to recover from customers the regulatory assets in this table. (2) For information on the retirement of our older and less efficient fossil fuel generating units, see Note 5, Property, Plant, and Equipment . (3) For information on the flow through of tax repairs and the regulatory treatment of the Tax Legislation, see Note 19, Regulatory Environment . (4) In May 2018, the PSCW issued an order requiring us to use a portion of our tax benefits related to the Tax Legislation that was signed into law in December 2017 to reduce our transmission regulatory assets. See Note 19, Regulatory Environment, for more information .
Schedule of regulatory liabilities	The following regulatory liabilities were reflected on our balance sheets at September 30, 2018 and December 31, 2017 . For more information on our regulatory liabilities, see Note 5, Regulatory Assets and Liabilities, in our 2017 Annual Report on Form 10-K. (in millions) September 30, 2018 December 31, 2017 Regulatory liabilities Income tax * $ 983.7 $ 849.1 Removal costs 743.1 730.0 Mines deferral 115.4 95.1 Energy efficiency programs 12.9 11.1 Uncollectible expense 11.7 6.4 Other, net 38.4 29.4 Total regulatory liabilities $ 1,905.2 $ 1,721.1 Balance Sheet Presentation Current liabilities $ 6.1 $ 13.1 Regulatory liabilities 1,899.1 1,708.0 Total regulatory liabilities $ 1,905.2 $ 1,721.1 * For information on the regulatory treatment of the Tax Legislation, see Note 19, Regulatory Environment .

PROPERTY, PLANT, AND EQUIPMENT

PROPERTY, PLANT, AND EQUIPMENT (Tables)	9 Months Ended
	Sep. 30, 2018
Restructuring cost and reserve
Schedule of changes to our severance liability	In addition, a severance liability was recorded in other current liabilities on our balance sheets related to these plant retirements. (in millions) Severance liability at December 31, 2017 $ 25.8 Severance payments (9.5 ) Other (3.0 ) Total severance liability at September 30, 2018 $ 13.3

SHORT-TERM DEBT AND LINES OF _2

SHORT-TERM DEBT AND LINES OF CREDIT (Tables)	9 Months Ended
	Sep. 30, 2018
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) September 30, 2018 December 31, 2017 Commercial paper Amount outstanding $ 346.0 $ 210.9 Weighted-average interest rate on amounts outstanding 2.30 % 1.81 %
Schedule of revolving credit facilities 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 September 30, 2018 Revolving credit facility October 2022 $ 500.0 Less: Letters of credit issued inside credit facility $ 1.2 Commercial paper outstanding 346.0 * Available capacity under existing agreement $ 152.8 * See Note 8, Long-Term Debt, for more information about the use of proceeds from our issuance of long-term debt in October 2018.

MATERIALS, SUPPLIES, AND INVE_2

MATERIALS, SUPPLIES, AND INVENTORIES (Tables)	9 Months Ended
	Sep. 30, 2018
Inventory Disclosure [Abstract]
Schedule of inventory	Our inventory consisted of: (in millions) September 30, 2018 December 31, 2017 Materials and supplies $ 142.4 $ 140.7 Fossil fuel 70.9 74.8 Natural gas in storage 42.5 35.2 Total $ 255.8 $ 250.7

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	9 Months Ended
	Sep. 30, 2018
Fair Value Disclosures [Abstract]
Fair value of assets and liabilities measured on a recurring basis, categorized by level within the fair value hierarchy	The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: September 30, 2018 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 1.9 $ 0.1 $ — $ 2.0 FTRs — — 6.4 6.4 Coal contracts — 0.2 — 0.2 Total derivative assets $ 1.9 $ 0.3 $ 6.4 $ 8.6 Derivative liabilities Natural gas contracts $ 0.1 $ — $ — $ 0.1 December 31, 2017 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.5 $ 0.1 $ — $ 0.6 Petroleum products contracts 0.9 — — 0.9 FTRs — — 2.4 2.4 Coal contracts — 0.7 — 0.7 Total derivative assets $ 1.4 $ 0.8 $ 2.4 $ 4.6 Derivative liabilities Natural gas contracts $ 2.0 $ 0.1 $ — $ 2.1 Coal contracts — 0.3 — 0.3 Total derivative liabilities $ 2.0 $ 0.4 $ — $ 2.4
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 September 30 Nine Months Ended September 30 (in millions) 2018 2017 2018 2017 Balance at the beginning of the period $ 8.7 $ 6.0 $ 2.4 $ 3.1 Purchases — — 9.4 6.9 Settlements (2.3 ) (2.3 ) (5.4 ) (6.3 ) Balance at the end of the period $ 6.4 $ 3.7 $ 6.4 $ 3.7
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 are not recorded at fair value: September 30, 2018 December 31, 2017 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 28.3 $ 30.4 $ 30.5 Long-term debt, including current portion 2,413.9 2,570.5 2,662.3 2,976.3

DERIVATIVE INSTRUMENTS (Tables)

DERIVATIVE INSTRUMENTS (Tables)	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative assets and derivative liabilities	The following table shows our derivative assets and derivative liabilities: September 30, 2018 December 31, 2017 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 2.0 $ — $ 0.6 $ 1.9 Petroleum products contracts — — 0.9 — FTRs 6.4 — 2.4 — Coal contracts 0.2 — 0.6 0.1 Total other current * $ 8.6 $ — $ 4.5 $ 2.0 Other long-term Natural gas contracts $ — $ 0.1 $ — $ 0.2 Coal contracts — — 0.1 0.2 Total other long-term * — 0.1 0.1 0.4 Total $ 8.6 $ 0.1 $ 4.6 $ 2.4 * On our balance sheets, we classify derivative assets and liabilities as other current or other long-term based on the maturities of the underlying contracts.
Estimated notional volumes and realized gains(losses)	Our estimated notional sales volumes and realized gains (losses) were as follows: Three Months Ended September 30, 2018 Three Months Ended September 30, 2017 (in millions) Volumes Gains Volumes Gains (Losses) Natural gas contracts 12.2 Dth $ 0.3 4.6 Dth $ (0.5 ) Petroleum products contracts 0.9 gallons 0.3 4.1 gallons (0.5 ) FTRs 5.4 MWh 1.4 6.9 MWh 2.4 Total $ 2.0 $ 1.4 Nine Months Ended September 30, 2018 Nine Months Ended September 30, 2017 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 35.9 Dth $ (2.1 ) 17.8 Dth $ 0.2 Petroleum products contracts 3.4 gallons 0.9 13.9 gallons (1.4 ) FTRs 16.0 MWh 3.1 21.2 MWh 6.9 Total $ 1.9 $ 5.7
Offsetting Assets and Liabilities	The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: September 30, 2018 December 31, 2017 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 8.6 $ 0.1 $ 4.6 $ 2.4 Gross amount not offset on the balance sheet (0.1 ) (0.1 ) (1.3 ) (2.0 ) * Net amount $ 8.5 $ — $ 3.3 $ 0.4 * Includes cash collateral posted of $0.7 million .

EMPLOYEE BENEFITS (Tables)

EMPLOYEE BENEFITS (Tables)	9 Months Ended
	Sep. 30, 2018
Retirement Benefits [Abstract]
Schedule of net benefit costs	The following tables show the components of net periodic pension and OPEB costs for our benefit plans: Pension Costs Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2018 2017 2018 2017 Service cost $ 3.3 $ 3.0 $ 9.9 $ 9.1 Interest cost 10.6 11.8 31.7 35.3 Expected return on plan assets (18.8 ) (19.2 ) (56.4 ) (57.5 ) Loss on plan settlement — 0.7 — 3.5 Amortization of prior service cost 0.2 0.3 0.6 0.9 Amortization of net actuarial loss 9.5 8.8 28.5 26.5 Net periodic benefit cost $ 4.8 $ 5.4 $ 14.3 $ 17.8 OPEB Costs Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2018 2017 2018 2017 Service cost $ 1.7 $ 1.8 $ 5.2 $ 5.2 Interest cost 2.8 3.0 8.3 9.2 Expected return on plan assets (3.8 ) (3.6 ) (11.6 ) (10.8 ) Amortization of prior service credit (0.6 ) (0.2 ) (1.7 ) (0.8 ) Net periodic benefit cost $ 0.1 $ 1.0 $ 0.2 $ 2.8
Schedule of non-service components	The following table shows the non-service (credit) cost components of net benefit costs: Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2018 2017 2018 2017 Non-service (credit) cost components $ (1.6 ) $ 1.4 $ (4.5 ) $ 5.9

SEGMENT INFORMATION (Tables)

SEGMENT INFORMATION (Tables)	9 Months Ended
	Sep. 30, 2018
Segment Reporting [Abstract]
Schedule of information related to our reportable segments	The following tables show summarized financial information for the three and nine months ended September 30 , 2018 and 2017 , related to our reportable segments: (in millions) Utility Other Wisconsin Electric Power Company Consolidated Three Months Ended September 30, 2018 Operating revenues $ 924.0 $ — $ 924.0 Other operation and maintenance 384.7 — 384.7 Depreciation and amortization 87.4 — 87.4 Operating income 107.8 — 107.8 Interest expense 29.9 — 29.9 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Three Months Ended September 30, 2017 Operating revenues $ 943.8 $ — $ 943.8 Other operation and maintenance * 331.2 — 331.2 Depreciation and amortization 83.0 — 83.0 Operating income * 164.8 — 164.8 Interest expense 29.3 — 29.3 * Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 13, Employee Benefits, for more information on this new standard. (in millions) Utility Other Wisconsin Electric Power Company Consolidated Nine Months Ended September 30, 2018 Operating revenues $ 2,721.7 $ — $ 2,721.7 Other operation and maintenance 1,086.9 — 1,086.9 Depreciation and amortization 259.6 — 259.6 Operating income 348.7 — 348.7 Interest expense 88.8 — 88.8 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Nine Months Ended September 30, 2017 Operating revenues $ 2,771.2 $ — $ 2,771.2 Other operation and maintenance * 982.2 — 982.2 Depreciation and amortization 247.8 — 247.8 Operating income * 497.2 — 497.2 Interest expense 87.7 0.3 88.0 * Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 13, Employee Benefits, for more information on this new standard.

RELATED PARTIES (Tables)

RELATED PARTIES (Tables)	9 Months Ended
	Sep. 30, 2018
Related Party Transactions [Abstract]
Schedule of related party transactions balance sheet information	Our balance sheets included the following receivables and payables related to transactions entered into with ATC: (in millions) September 30, 2018 December 31, 2017 Accounts receivable Services provided to ATC $ 2.4 $ 0.8 Accounts payable Services received from ATC 19.3 22.2
Schedule of activity associated with related party transactions	The following table shows activity associated with our related party transactions: Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2018 2017 2018 2017 Lease agreements Lease payments to We Power (1) $ 92.7 $ 104.3 $ 280.0 $ 315.4 Construction work in progress billed to We Power 4.4 5.9 13.2 31.1 Transactions with WBS (2) Billings to WBS 4.1 60.2 12.8 177.2 Billings from WBS 64.2 (3) 49.4 240.9 (3) 152.1 Transactions with WPS Natural gas purchases from WPS 0.6 0.8 1.6 1.3 Billings to WPS (2) 3.9 6.4 11.2 14.1 Billings from WPS (2) 1.5 1.4 6.6 3.6 Transactions with WG Natural gas purchases from WG 1.4 1.4 4.0 4.0 Billings to WG (2) 10.5 (4) 16.3 37.6 (4) 48.2 Billings from WG (2) 4.8 6.0 14.5 17.3 Transactions with UMERC Electric sales to UMERC 7.4 9.0 22.4 23.1 Billings to UMERC (2) 5.2 18.7 12.3 52.6 Transactions with Bluewater (5) Storage service fees 4.5 1.4 10.4 1.4 Transactions with ATC Charges to ATC for services and construction 3.7 2.9 9.4 8.1 Charges from ATC for network transmission services 57.9 60.4 174.0 181.1 Refund from ATC related to a FERC audit — — 15.4 — Refund from ATC per FERC ROE order — — — 19.4 (1) We make lease payments to We Power, another subsidiary of WEC Energy Group, for PWGS Units 1 and 2 and ERGS Units 1 and 2. Lease payments were reduced in 2018 as a result of tax savings related to Tax Legislation. (2) Includes amounts billed for services, pass through costs, and other items in accordance with approved affiliated interest agreements. (3) Includes $2.2 million and $59.8 million for the transfer of certain software assets from WBS during the three and nine months ended September 30, 2018 , respectively. There were no software assets transferred from WBS during 2017. (4) Includes $0.1 million and $5.3 million for the transfer of certain software assets to WG during the three and nine months ended September 30, 2018 , respectively. There were no software assets transferred to WG during 2017. (5) WEC Energy Group's acquisition of Bluewater was completed June 30, 2017. See below for more information.

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	9 Months Ended
	Sep. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
Schedule of regulatory assets and reserves related to manufactured gas plant sites	We have established the following regulatory assets and reserves related to manufactured gas plant sites: (in millions) September 30, 2018 December 31, 2017 Regulatory assets $ 29.7 $ 30.4 Reserves for future remediation * 18.5 18.5 * Recorded within other long-term liabilities on our balance sheets.

SUPPLEMENTAL CASH FLOW INFORM_2

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	9 Months Ended
	Sep. 30, 2018
Supplemental Cash Flow Information [Abstract]
Schedule of supplemental cash flow information	Nine Months Ended September 30 (in millions) 2018 2017 Cash (paid) for interest, net of amount capitalized $ (64.1 ) $ (62.1 ) Cash (paid) for income taxes, net (14.7 ) (60.7 ) Significant noncash transactions: Accounts payable related to construction costs 4.0 8.5 Accounts receivable related to assets transferred to affiliates 2.7 — Transfer of investment in ATC to another subsidiary of WEC Energy Group (1) (2) — 415.4 Transfer of net assets to UMERC (1) — 60.0 (1) See Note 16, Related Parties, for more information on these transactions. (2) The amount transferred included a $13.4 million receivable for distributions approved and recorded in December 2016.

OPERATING REVENUES - DISAGGREGA

OPERATING REVENUES - DISAGGREGATION OF OPERATING REVENES (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Disaggregation of Operating Revenues
Operating revenues	$ 924	$ 943.8	$ 2,721.7	$ 2,771.2
Utility segment
Disaggregation of Operating Revenues
Operating revenues	924	$ 943.8	2,721.7	$ 2,771.2
Utility segment | Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	1.6		5.7
Utility segment | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	922.4		2,716
Utility segment | Electric | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	877		2,441.2
Utility segment | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 45.4		$ 274.8

OPERATING REVENUES ELECTRIC UTI

OPERATING REVENUES ELECTRIC UTILITY OPERATING REVENUES (Details) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2018USD ($)	Sep. 30, 2018USD ($)contractperformance_obligations
Electric
Disaggregation of Operating Revenues
Number of performance obligations | performance_obligations		1
Number of contracts | contract		1
Number of days payment is due		30 days
Electric | Wholesale
Disaggregation of Operating Revenues
Number of performance obligations | performance_obligations		2
Revenues from contracts with customers | Utility segment | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 922.4	$ 2,716
Revenues from contracts with customers | Utility segment | Electric | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	877	2,441.2
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	352.7	929.1
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Small commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	276.9	775.2
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Large commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	177.9	499.2
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Other
Disaggregation of Operating Revenues
Revenues from contracts with customers	5.2	15.5
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Total retail
Disaggregation of Operating Revenues
Revenues from contracts with customers	812.7	2,219
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Wholesale
Disaggregation of Operating Revenues
Revenues from contracts with customers	28.3	85.7
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Resale
Disaggregation of Operating Revenues
Revenues from contracts with customers	31	111.8
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Steam
Disaggregation of Operating Revenues
Revenues from contracts with customers	2.6	16.9
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Other utility
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 2.4	$ 7.8

OPERATING REVENUES NATURAL GAS

OPERATING REVENUES NATURAL GAS UTILITY OPERATING REVENUES (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2018
Natural gas
Disaggregation of Operating Revenues
Number of days payment is due		30 days
Revenues from contracts with customers | Utility segment | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 922.4	$ 2,716
Revenues from contracts with customers | Utility segment | Natural gas | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	45.4	274.8
Revenues from contracts with customers | Utility segment | Natural gas | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	20.8	176.2
Revenues from contracts with customers | Utility segment | Natural gas | Transferred over time | Commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	8.1	81.9
Revenues from contracts with customers | Utility segment | Natural gas | Transferred over time | Total retail
Disaggregation of Operating Revenues
Revenues from contracts with customers	28.9	258.1
Revenues from contracts with customers | Utility segment | Natural gas | Transferred over time | Transport
Disaggregation of Operating Revenues
Revenues from contracts with customers	2.2	9.7
Revenues from contracts with customers | Utility segment | Natural gas | Transferred over time | Other utility
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 14.3	$ 7

OPERATING REVENUES - OTHER OPER

OPERATING REVENUES - OTHER OPERATING REVENUES (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Disaggregation of Operating Revenues
Operating revenues	$ 924	$ 943.8	$ 2,721.7	$ 2,771.2
Utility segment
Disaggregation of Operating Revenues
Operating revenues	924	$ 943.8	2,721.7	$ 2,771.2
Utility segment | Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	1.6		5.7
Utility segment | Other operating revenues | Late payment charges
Disaggregation of Operating Revenues
Operating revenues	1.6		6.5
Utility segment | Other operating revenues | Leases
Disaggregation of Operating Revenues
Operating revenues	0.3		2.5
Utility segment | Other operating revenues | Alternative revenues
Disaggregation of Operating Revenues
Operating revenues	$ (0.3)		$ (3.3)

REGULATORY ASSETS AND LIABILI_3

REGULATORY ASSETS AND LIABILITIES - REGULATORY ASSETS (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Regulatory assets
Total regulatory assets	$ 2,892.1	$ 1,984.9
Capital leases
Regulatory assets
Total regulatory assets	853.4	801.3
Plant retirements
Regulatory assets
Total regulatory assets	760.9	6.6
Unrecognized pension and OPEB costs
Regulatory assets
Total regulatory assets	455.3	484.4
System support resource
Regulatory assets
Total regulatory assets	315	298.9
Income tax
Regulatory assets
Total regulatory assets	256.5	0
Electric transmission costs
Regulatory assets
Total regulatory assets	123.6	220.7
We Power generation
Regulatory assets
Total regulatory assets	48.7	71.3
Asset retirement obligations
Regulatory assets
Total regulatory assets	37.2	41.4
Environmental remediation costs
Regulatory assets
Total regulatory assets	29.7	30.4
Other, net
Regulatory assets
Total regulatory assets	$ 11.8	$ 29.9

REGULATORY ASSETS AND LIABILI_4

REGULATORY ASSETS AND LIABILITIES - REGULATORY LIABILITIES (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Regulatory liabilities
Current liabilities	$ 6.1	$ 13.1
Regulatory liabilities	1,899.1	1,708
Total regulatory liabilities	1,905.2	1,721.1
Income tax
Regulatory liabilities
Total regulatory liabilities	983.7	849.1
Removal costs
Regulatory liabilities
Total regulatory liabilities	743.1	730
Mines deferral
Regulatory liabilities
Total regulatory liabilities	115.4	95.1
Energy efficiency programs
Regulatory liabilities
Total regulatory liabilities	12.9	11.1
Uncollectible expense
Regulatory liabilities
Total regulatory liabilities	11.7	6.4
Other, net
Regulatory liabilities
Total regulatory liabilities	$ 38.4	$ 29.4

PROPERTY, PLANT, AND EQUIPMEN_2

PROPERTY, PLANT, AND EQUIPMENT (Details) $ in Millions	1 Months Ended	9 Months Ended
	Oct. 31, 2017MW	Sep. 30, 2018USD ($)	Dec. 31, 2017USD ($)
Property, plant, and equipment
Cost of removal reserve classified as a regulatory liability		$ 1,905.2	$ 1,721.1
Net book value of plant classified as a regulatory asset		2,892.1	$ 1,984.9
UMERC
Property, plant, and equipment
Capacity of natural gas-fired generation facility (in megawatts) | MW	180
Pleasant Prairie power plant
Property, plant, and equipment
Plant to be retired, at carrying value		653.3
Cost of removal reserve classified as a regulatory liability		102.5
Net book value of plant classified as a regulatory asset		755.8
Presque Isle power plant
Property, plant, and equipment
Plant to be retired, at carrying value		186.9
Cost of removal reserve classified as a regulatory liability		10.5
Plant to be retired, Net		197.4
Utility segment
Changes to severance liability
Severance liability, balance at beginning of period		25.8
Severance payments		(9.5)
Other		(3)
Severance liability, balance at end of the period		$ 13.3

SHORT-TERM DEBT AND LINES OF _3

SHORT-TERM DEBT AND LINES OF CREDIT - SHORT-TERM BORROWINGS (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Short-term borrowings
Commercial paper outstanding	$ 346	$ 210.9
Commercial paper
Short-term borrowings
Commercial paper outstanding	$ 346	$ 210.9
Weighted-average interest rate on amounts outstanding	2.30%	1.81%
Average amount outstanding during the period	$ 162.1
Weighted-average interest rate during the period	2.23%

SHORT-TERM DEBT AND LINES OF _4

SHORT-TERM DEBT AND LINES OF CREDIT - REVOLVING CREDIT FACILITIES (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Revolving credit facility
Letters of credit issued inside credit facility	$ 1.2
Commercial paper outstanding	346	$ 210.9
Available capacity under existing agreement	152.8
Credit facility maturing during October 2022
Revolving credit facility
Revolving credit facility	500
Commercial paper
Revolving credit facility
Commercial paper outstanding	$ 346	$ 210.9

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details) - USD ($) $ in Millions	Oct. 15, 2018	Sep. 30, 2018
Debt Instrument [Line Items]
Long-term Pollution Control Bond		$ 80
WE Debentures due 2018
Debt Instrument [Line Items]
Retirement of long-term debt		$ 250
Interest rate on long-term debt		1.70%
Subsequent event | WE 4.30% Debentures due 2048
Debt Instrument [Line Items]
Proceeds from Issuance of Debt	$ 300
Interest rate on long-term debt	4.30%

MATERIALS, SUPPLIES, AND INVE_3

MATERIALS, SUPPLIES, AND INVENTORIES (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Inventory Disclosure [Abstract]
Materials and supplies	$ 142.4	$ 140.7
Fossil fuel	70.9	74.8
Natural gas in storage	42.5	35.2
Total	$ 255.8	$ 250.7

INCOME TAXES (Details)

INCOME TAXES (Details)	1 Months Ended	3 Months Ended	9 Months Ended
	Dec. 31, 2017	Sep. 30, 2018	Sep. 30, 2018	Sep. 30, 2017
Effective Income Tax Rate Reconciliation, Percent
Total income tax benefit, percentage		(24.70%)	(9.60%)
Statutory federal income tax, percentage			21.00%	35.00%
Measurement period to complete accounting related to Tax Cuts and Jobs Act	1 year

FAIR VALUE MEASUREMENTS - ASSET

FAIR VALUE MEASUREMENTS - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Assets
Derivative asset	$ 8.6	$ 4.6
Liabilities
Derivative liability	0.1	2.4
Fair value measurements on a recurring basis
Assets
Derivative asset	8.6	4.6
Liabilities
Derivative liability		2.4
Fair value measurements on a recurring basis | Level 1
Assets
Derivative asset	1.9	1.4
Liabilities
Derivative liability		2
Fair value measurements on a recurring basis | Level 2
Assets
Derivative asset	0.3	0.8
Liabilities
Derivative liability		0.4
Fair value measurements on a recurring basis | Level 3
Assets
Derivative asset	6.4	2.4
Liabilities
Derivative liability		0
Fair value measurements on a recurring basis | Natural gas contracts
Assets
Derivative asset	2	0.6
Liabilities
Derivative liability	0.1	2.1
Fair value measurements on a recurring basis | Natural gas contracts | Level 1
Assets
Derivative asset	1.9	0.5
Liabilities
Derivative liability	0.1	2
Fair value measurements on a recurring basis | Natural gas contracts | Level 2
Assets
Derivative asset	0.1	0.1
Liabilities
Derivative liability	0	0.1
Fair value measurements on a recurring basis | Natural gas contracts | Level 3
Assets
Derivative asset	0	0
Liabilities
Derivative liability	0	0
Fair value measurements on a recurring basis | Petroleum products contracts
Assets
Derivative asset		0.9
Fair value measurements on a recurring basis | Petroleum products contracts | Level 1
Assets
Derivative asset		0.9
Fair value measurements on a recurring basis | Petroleum products contracts | Level 2
Assets
Derivative asset		0
Fair value measurements on a recurring basis | Petroleum products contracts | Level 3
Assets
Derivative asset		0
Fair value measurements on a recurring basis | FTRs
Assets
Derivative asset	6.4	2.4
Fair value measurements on a recurring basis | FTRs | Level 1
Assets
Derivative asset	0	0
Fair value measurements on a recurring basis | FTRs | Level 2
Assets
Derivative asset	0	0
Fair value measurements on a recurring basis | FTRs | Level 3
Assets
Derivative asset	6.4	2.4
Fair value measurements on a recurring basis | Coal contracts
Assets
Derivative asset	0.2	0.7
Liabilities
Derivative liability		0.3
Fair value measurements on a recurring basis | Coal contracts | Level 1
Assets
Derivative asset	0	0
Liabilities
Derivative liability		0
Fair value measurements on a recurring basis | Coal contracts | Level 2
Assets
Derivative asset	0.2	0.7
Liabilities
Derivative liability		0.3
Fair value measurements on a recurring basis | Coal contracts | Level 3
Assets
Derivative asset	$ 0	0
Liabilities
Derivative liability		$ 0

FAIR VALUE MEASUREMENTS - LEVEL

FAIR VALUE MEASUREMENTS - LEVEL 3 RECONCILIATION (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Level 3 rollforward
Balance at the beginning of the period	$ 8.7	$ 6	$ 2.4	$ 3.1
Purchases	0	0	9.4	6.9
Settlements	(2.3)	(2.3)	(5.4)	(6.3)
Balance at the end of the period	$ 6.4	$ 3.7	$ 6.4	$ 3.7

FAIR VALUE MEASUREMENTS - FINAN

FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Carrying value and estimated fair value of financial instruments
Preferred stock	$ 30.4	$ 30.4
Carrying Amount
Carrying value and estimated fair value of financial instruments
Preferred stock	30.4	30.4
Long-term debt, including current portion	2,413.9	2,662.3
Fair Value
Carrying value and estimated fair value of financial instruments
Preferred stock	28.3	30.5
Long-term debt, including current portion	$ 2,570.5	$ 2,976.3

DERIVATIVE INSTRUMENTS - DERIVA

DERIVATIVE INSTRUMENTS - DERIVATIVE ASSETS AND DERIVATIVE LIABILITIES (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Derivative Asset
Other current derivative assets	$ 8.6	$ 4.5
Other long-term derivative assets	0	0.1
Derivative asset	8.6	4.6
Derivative Liability
Other current derivative liabilities	0	2
Other long-term derivative liabilities	0.1	0.4
Derivative liability	0.1	2.4
Natural gas contracts
Derivative Asset
Other current derivative assets	2	0.6
Other long-term derivative assets	0	0
Derivative Liability
Other current derivative liabilities	0	1.9
Other long-term derivative liabilities	0.1	0.2
Petroleum products contracts
Derivative Asset
Other current derivative assets	0	0.9
Derivative Liability
Other current derivative liabilities	0	0
FTRs
Derivative Asset
Other current derivative assets	6.4	2.4
Derivative Liability
Other current derivative liabilities	0	0
Coal contracts
Derivative Asset
Other current derivative assets	0.2	0.6
Other long-term derivative assets	0	0.1
Derivative Liability
Other current derivative liabilities	0	0.1
Other long-term derivative liabilities	$ 0	$ 0.2

DERIVATIVE INSTRUMENTS - GAINS

DERIVATIVE INSTRUMENTS - GAINS (LOSSES) AND NOTIONAL VOLUMES (Details) gal in Millions, MWh in Millions, MMBTU in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018USD ($)MWhMMBTUgal	Sep. 30, 2017USD ($)MWhMMBTUgal	Sep. 30, 2018USD ($)MWhMMBTUgal	Sep. 30, 2017USD ($)MWhMMBTUgal
Realized Gain (Loss) on Derivatives
Gains (Losses)	$ 2	$ 1.4	$ 1.9	$ 5.7
Natural gas contracts
Realized Gain (Loss) on Derivatives
Gains (Losses)	$ 0.3	$ (0.5)	$ (2.1)	$ 0.2
Notional Sales Volumes
Notional sales volumes | MMBTU	12.2	4.6	35.9	17.8
Petroleum products contracts
Realized Gain (Loss) on Derivatives
Gains (Losses)	$ 0.3	$ (0.5)	$ 0.9	$ (1.4)
Notional Sales Volumes
Notional sales volumes (gallons) | gal	0.9	4.1	3.4	13.9
FTRs
Realized Gain (Loss) on Derivatives
Gains (Losses)	$ 1.4	$ 2.4	$ 3.1	$ 6.9
Notional Sales Volumes
Notional sales volumes | MWh	5.4	6.9	16	21.2

DERIVATIVE INSTRUMENTS - OFFSET

DERIVATIVE INSTRUMENTS - OFFSETTING TABLE (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Cash collateral
Collateral in margin account	$ 1.7	$ 4.9
Offsetting Derivative Assets
Gross amount recognized on the balance sheet	8.6	4.6
Gross amount not offset on the balance sheet	(0.1)	(1.3)
Net amount	8.5	3.3
Offsetting Derivative Liabilities
Gross amount recognized on the balance sheet	0.1	2.4
Gross amount not offset on the balance sheet	(0.1)	(2)
Net amount	$ 0	0.4
Collateral posted		$ 0.7

EMPLOYEE BENEFITS-COSTS AND CON

EMPLOYEE BENEFITS-COSTS AND CONTRIBUTIONS (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Components of net periodic benefit costs
Contributions and payments related to pension and OPEB plans			$ 5.3	$ 5.9
Pension Costs
Components of net periodic benefit costs
Service cost	$ 3.3	$ 3	9.9	9.1
Interest cost	10.6	11.8	31.7	35.3
Expected return on plan assets	(18.8)	(19.2)	(56.4)	(57.5)
Loss on plan settlement	0	0.7	0	3.5
Amortization of prior service (credit) cost	0.2	0.3	0.6	0.9
Amortization of net actuarial loss	9.5	8.8	28.5	26.5
Net periodic benefit cost	4.8	5.4	14.3	17.8
Contributions and payments related to pension and OPEB plans			3.8
Estimated future employer contributions for the remainder of the year	0.3		0.3
Other Postretirement Benefit Costs
Components of net periodic benefit costs
Service cost	1.7	1.8	5.2	5.2
Interest cost	2.8	3	8.3	9.2
Expected return on plan assets	(3.8)	(3.6)	(11.6)	(10.8)
Amortization of prior service (credit) cost	(0.6)	(0.2)	(1.7)	(0.8)
Net periodic benefit cost	0.1	$ 1	0.2	$ 2.8
Contributions and payments related to pension and OPEB plans			1.5
Estimated future employer contributions for the remainder of the year	$ 3		$ 3

EMPLOYEE BENEFITS-IMPACT OF ADO

EMPLOYEE BENEFITS-IMPACT OF ADOPTION OF ASU 2017-07 (Details) - Accounting Standards Update 2017-07 - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Non-service (credit) cost components of net benefit cost	$ (1.6)		$ (4.5)
Impact of ASU 2017-07
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Non-service (credit) cost components of net benefit cost		$ 1.4		$ 5.9

SEGMENT INFORMATION (Details)

SEGMENT INFORMATION (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018USD ($)customer	Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)areasegmentcustomer	Sep. 30, 2017USD ($)
Segment information
Number of reportable segments | segment			2
Operating revenues	$ 924	$ 943.8	$ 2,721.7	$ 2,771.2
Other operation and maintenance	384.7	331.2	1,086.9	982.2
Depreciation and amortization	87.4	83	259.6	247.8
Operating income	107.8	164.8	348.7	497.2
Interest expense	$ 29.9	29.3	$ 88.8	88
Michigan
Segment information
Number of customers | customer	1		1
Utility segment
Segment information
Number of service areas | area			3
Operating revenues	$ 924	943.8	$ 2,721.7	2,771.2
Other operation and maintenance	384.7	331.2	1,086.9	982.2
Depreciation and amortization	87.4	83	259.6	247.8
Operating income	107.8	164.8	348.7	497.2
Interest expense	29.9	29.3	88.8	87.7
Other segments
Segment information
Operating revenues	0	0	0	0
Other operation and maintenance	0	0	0	0
Depreciation and amortization	0	0	0	0
Operating income	0	0	0	0
Interest expense	$ 0	$ 0	$ 0	$ 0.3

VARIABLE INTEREST ENTITIES (Det

VARIABLE INTEREST ENTITIES (Details) - Purchased power agreement $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)MW	Sep. 30, 2017USD ($)
Variable interest entities
Firm capacity from purchased power agreement (in megawatts) | MW	236
Minimum energy requirements over remaining term of purchased power agreement (in megawatts) | MW	0
Remaining term of purchased power agreement (in years)	4 years
Residual guarantee associated with purchased power agreement	$ 0
Required payments over remaining term of purchased power agreement	60.4
Total capacity and lease payments	$ 14.1	$ 13.5

RELATED PARTIES (Details)

RELATED PARTIES (Details) - ATC - USD ($) $ in Millions	Jan. 01, 2017	Dec. 31, 2017	Sep. 30, 2018
Related parties
Transfer equity method investment and related receivable for distributions transfer to affiliated company	$ 415.4
Transfer of deferred income tax related to ATC to affiliated company		$ 186.8
Accounts receivable, related parties, current		0.8	$ 2.4
Accounts payable, related parties, current		$ 22.2	$ 19.3

RELATED PARTIES - OTHER TRANSAC

RELATED PARTIES - OTHER TRANSACTIONS (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Jun. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Related parties
Payments for transfer of assets from related parties				$ 59.8	$ 0
Proceeds from assets transferred to affiliates				6.1	0
We Power LLC
Related parties
Lease payments to W.E. Power, LLC		$ 92.7	$ 104.3	280	315.4
Construction work In progress billed to related party		4.4	5.9	13.2	31.1
WBS
Related parties
Charges to related party for services and billings		4.1	60.2	12.8	177.2
Charges from related party for services and billings		64.2	49.4	240.9	152.1
Payments for transfer of assets from related parties		2.2		59.8	0
WPS
Related parties
Charges to related party for services and billings		3.9	6.4	11.2	14.1
Charges from related party for services and billings		1.5	1.4	6.6	3.6
Natural gas purchases		0.6	0.8	1.6	1.3
WG
Related parties
Charges to related party for services and billings		10.5	16.3	37.6	48.2
Charges from related party for services and billings		4.8	6	14.5	17.3
Natural gas purchases		1.4	1.4	4	4
Proceeds from assets transferred to affiliates		0.1		5.3	0
UMERC
Related parties
Charges to related party for services and billings		5.2	18.7	12.3	52.6
Electric sales to UMERC		7.4	9	22.4	23.1
Bluewater
Related parties
Charges from related party for services and billings		4.5	1.4	10.4	1.4
Purchase price	$ 226
ATC
Related parties
Charges to related party for services and billings		3.7	2.9	9.4	8.1
Charges from related party for services and billings		57.9	60.4	174	181.1
Refund from ATC related to a FERC audit		0	0	15.4	0
Refund from ATC per FERC ROE order		$ 0	$ 0	$ 0	$ 19.4

RELATED PARTIES - UMERC (Detail

RELATED PARTIES - UMERC (Details) - UMERC transfer $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)	Jan. 01, 2017milecustomer
Related parties
Miles of electric distribution lines | mile		2,500
Book value of net assets transferred (including the related deferred income tax liabilities) | $	$ 61.1
Utility segment
Related parties
Number of customers		27,500
Electric distribution
Related parties
Number of customers		50

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Millions	Sep. 30, 2018USD ($)
Minimum future commitments for purchase obligations
Purchase obligations	$ 10,266.8

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) $ in Millions	1 Months Ended	9 Months Ended
	Oct. 31, 2014compliance_option	Sep. 30, 2018USD ($)degreecelsiusgenerating_unitsMW	Dec. 31, 2017USD ($)
Climate Change | Electric
Air quality
Company goal for percentage of carbon dioxide emissions reduction by 2030		40.00%
Long-term company goal for percentage of carbon dioxide emissions reduction by 2050		80.00%
Coal generation capacity expected to be retired by 2020 | MW		1,547
Climate Change | Electric | Maximum
Air quality
Global temperature increases limit | degreecelsius		2
Clean Water Act Cooling Water Intake Structure Rule | Electric
Water quality
Number of compliance options available to meet standard | compliance_option	7
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
Regulatory assets recorded for remediation of manufactured gas plant sites		29.7	$ 30.4
Reserves recorded for remediation of manufactured gas plant sites		$ 18.5	$ 18.5

SUPPLEMENTAL CASH FLOW INFORM_3

SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2016
Supplemental Cash Flow Information [Abstract]
Cash (paid) for interest, net of amount capitalized	$ (64.1)	$ (62.1)
Cash (paid) for income taxes, net	(14.7)	(60.7)
Significant noncash transactions
Accounts payable related to construction costs	4	8.5
Assets transferred between affiliates
Significant noncash transactions
Accounts receivable related to assets transferred to affiliates	2.7	0
ATC
Significant noncash transactions
Transfer of investment in ATC to another subsidiary of WEC Energy Group	0	415.4
Distributions receivable from ATC			$ 13.4
UMERC
Significant noncash transactions
Transfer of net assets to UMERC	$ 0	$ 60

REGULATORY ENVIRONMENT (Details

REGULATORY ENVIRONMENT (Details) $ in Millions	1 Months Ended			9 Months Ended
	May 31, 2018	Dec. 31, 2017USD ($)	Sep. 30, 2017	Sep. 30, 2018changecustomer	Sep. 30, 2017
Regulatory environment
Corporate federal tax rate (as a percent)				21.00%	35.00%
Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates
Regulatory environment
Approved return on equity (as a percent)			10.20%
Income Statement impact of flow through of repair related deferred tax liabilities | change				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%
Michigan Public Service Commission (MPSC)
Regulatory environment
Number of retail electric customers served in Michigan | customer				1
Tax Cuts And Jobs Act Of 2017
Regulatory environment
Change in deferred taxes from tax legislation | $		$ 1,065
Electric rates | Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates
Regulatory environment
Percentage of current tax benefit from Tax Cuts and Jobs Act of 2017 to be used to reduce certain regulatory assets	80.00%
Percent of current tax benefit from Tax Cuts and Jobs Act of 2017 to be returned to customers via bill credits	20.00%
Natural gas rates | Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates
Regulatory environment
Percent of current tax benefit from Tax Cuts and Jobs Act of 2017 to be returned to customers via bill credits	100.00%