Wisconsin Electric Power Company PFD 3.60% (WELPP) 10-Q 4 May 18 2018 Q1 Quarterly report Financial data

DOCUMENT AND ENTITY INFORMATION

DOCUMENT AND ENTITY INFORMATION	3 Months Ended
	Mar. 31, 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	Mar. 31, 2018
Document fiscal year focus	2,018
Document fiscal period focus	Q1
Amendment flag	false
Entity common stock, shares outstanding	33,289,327

CONDENSED CONSOLIDATED INCOME S

CONDENSED CONSOLIDATED INCOME STATEMENTS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Income Statement [Abstract]
Operating revenues	$ 941.5	$ 972
Cost of sales	357	348.6
Other operation and maintenance	335.6	326.6
Depreciation and amortization	85.3	82.1
Property and revenue taxes	27.2	28.4
Total operating expenses	805.1	785.7
Operating income	136.4	186.3
Other (expense) income, net	(4.2)	3.2
Interest expense	29.7	29.6
Other expense	(33.9)	(26.4)
Income before income taxes	102.5	159.9
Income tax (benefit) expense	(3.6)	57.8
Net income	106.1	102.1
Preferred stock dividend requirements	0.3	0.3
Net income attributed to common shareholder	$ 105.8	$ 101.8

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 10.4	$ 12.3
Accounts receivable and unbilled revenues, net of reserves of $43.5 and $39.5, respectively	489.1	513.8
Accounts receivable from related parties	146.3	109.1
Materials, supplies, and inventories	214.7	250.7
Prepayments	114.3	144.3
Other	7.1	9.4
Current assets	981.9	1,039.6
Long-term assets
Property, plant, and equipment, net of accumulated depreciation of $3,798.9 and $3,741.8, respectively	10,086.2	10,007.7
Regulatory assets	2,122.4	1,984.9
Other	104.9	89.4
Long-term assets	12,313.5	12,082
Total assets	13,295.4	13,121.6
Current liabilities
Short-term debt	60	210.9
Current portion of long-term debt	250	250
Current portion of capital lease obligations	44.6	42.5
Accounts payable	217.6	329.3
Accounts payable to related parties	249.5	131.5
Accrued payroll and benefits	37.5	53.4
Accrued taxes	65.7	58.2
Other	142.1	111.8
Current liabilities	1,067	1,187.6
Long-term liabilities
Long-term debt	2,412.8	2,412.3
Capital lease obligations	2,811.5	2,823.8
Deferred income taxes	1,179.7	1,155.5
Regulatory liabilities	1,891.1	1,708
Pension and OPEB obligations	156.9	143.2
Other	288.1	276.9
Long-term liabilities	8,740.1	8,519.7
Commitments and contingencies (Note 15)
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	830.9	802.7
Retained earnings	2,294.1	2,248.3
Common shareholder's equity	3,457.9	3,383.9
Preferred stock	30.4	30.4
Total liabilities and equity	$ 13,295.4	$ 13,121.6

CONDENSED CONSOLIDATED BALANCE4

CONDENSED CONSOLIDATED BALANCE SHEETS (PARENTHETICALS) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Accounts receivable and unbilled revenues, reserves	$ 43.5	$ 39.5
Property, plant, and equipment, accumulated depreciation	$ 3,798.9	$ 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	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Operating Activities
Net income	$ 106.1	$ 102.1
Reconciliation to cash provided by operating activities
Depreciation and amortization	85.3	82.1
Deferred income taxes and investment tax credits, net	(15.4)	20.7
Contributions and payments related to pension and OPEB plans	(2.1)	(3.3)
(Payments for) proceeds from liabilities transferred (to) from WBS	(1.4)	0.9
Change in –
Accounts receivable and unbilled revenues	(12.5)	42.1
Materials, supplies, and inventories	36	19.4
Prepaid taxes	24.2	25.1
Other current assets	6	3.2
Accounts payable	12.3	(63.5)
Accrued taxes	10.9	(15.9)
Amounts refundable to customers	15.7	10
Other current liabilities	(1.8)	(21)
Other, net	106.6	7.9
Net cash provided by operating activities	369.9	209.8
Investing Activities
Capital expenditures	(141.9)	(105.5)
Proceeds from the sale of assets	0.5	12.9
Payment for assets received from WBS	(48.9)	0
Other, net	1.7	0.4
Net cash used in investing activities	(188.6)	(92.2)
Financing Activities
Change in short-term debt	(150.9)	(124)
Repayment of subsidiary note to parent	0	(12.8)
Equity contribution from parent	28	75
Payments of dividends to parent	(60)	(60)
Payments of preferred stock dividends	(0.3)	(0.3)
Net cash used in financing activities	(183.2)	(122.1)
Net change in cash and cash equivalents	(1.9)	(4.5)
Cash and cash equivalents at beginning of period	12.3	15.4
Cash and cash equivalents at end of period	$ 10.4	$ 10.9

GENERAL INFORMATION

GENERAL INFORMATION	3 Months Ended
	Mar. 31, 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. 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 months ended March 31 , 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	3 Months Ended
	Mar. 31, 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	3 Months Ended
	Mar. 31, 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, revenues are recognized 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. 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. There are no revenues associated with our other segment. Comparable amounts have not been presented for the three months ended March 31, 2017, due to our adoption of this standard under the modified retrospective method. (in millions) Wisconsin Electric Power Company Consolidated Three Months Ended March 31, 2018 Electric utility $ 779.6 Natural gas utility 160.8 Total revenues from contracts with customers 940.4 Other operating revenues 1.1 Total operating revenues $ 941.5 Revenues from Contracts with Customers Electric Utility Operating Revenues The following table disaggregates electric utility operating revenues into customer class for the current period: (in millions) Electric Utility Operating Revenues Three Months Ended March 31, 2018 Residential $ 281.4 Small commercial and industrial 237.7 Large commercial and industrial 148.9 Other 5.4 Total retail revenues 673.4 Wholesale 28.5 Resale 63.7 Steam 9.7 Other utility revenues 4.3 Total electric utility operating revenues $ 779.6 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 and consists 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. 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 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 utilities 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 for the current period: (in millions) Natural Gas Utility Operations Three Months Ended March 31, 2018 Residential $ 114.7 Commercial and industrial 55.6 Total retail revenues 170.3 Transport 4.4 Other utility revenues * (13.9 ) Total natural gas utility operating revenues $ 160.8 * Includes amounts (refunded to) 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. Certain of our 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. 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 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 March 31, 2018 Late payment charges $ 2.8 Leases 0.8 Alternative revenues * (2.5 ) Total other operating revenues $ 1.1 * 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 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 or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.

PROPERTY, PLANT, AND EQUIPMENT

PROPERTY, PLANT, AND EQUIPMENT	3 Months Ended
	Mar. 31, 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 announced the retirement of the plants identified below. The net book value of these plants was classified as plant to be retired within property, plant, and equipment on our balance sheet at March 31, 2018 . In addition, severance expense in the amount of $25.8 million was recorded within the utility segment in 2017 related to these announced plant retirements. Pleasant Prairie Power Plant As a result of a MISO ruling in December 2017, the Pleasant Prairie power plant was retired effective April 10, 2018. Retirement of the Pleasant Prairie power plant was considered probable at March 31, 2018 . The net book value of this generating unit was $674.1 million at March 31, 2018 , and was classified as plant to be retired within property, plant, and equipment on our balance sheet. This unit is included in rate base, and we continue to depreciate it on a straight-line basis using the composite depreciation rates approved by the PSCW. 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 15, Commitments and Contingencies, for more information regarding the new natural gas-fired generation. 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. These new units are expected to begin commercial operation by mid-2019. Upon receiving the MPSC's approval, retirement of the PIPP generating units became probable. As a result of a MISO ruling received in April 2018, the PIPP units must be retired no later than May 31, 2019. The net book value of these units was $188.7 million at March 31, 2018 , and was classified as plant to be retired within property, plant, and equipment on our balance sheet. 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 15, Commitments and Contingencies, for more information .

COMMON EQUITY

COMMON EQUITY	3 Months Ended
	Mar. 31, 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	3 Months Ended
	Mar. 31, 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) March 31, 2018 December 31, 2017 Commercial paper Amount outstanding $ 60.0 $ 210.9 Weighted-average interest rate on amounts outstanding 2.05 % 1.81 % Our average amount of commercial paper borrowings based on daily outstanding balances during the three months ended March 31, 2018 , was $96.2 million with a weighted-average interest rate during the period of 1.86% . 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 March 31, 2018 Revolving credit facility October 2022 $ 500.0 Less: Letters of credit issued inside credit facility $ 1.2 Commercial paper outstanding 60.0 Available capacity under existing agreement $ 438.8

MATERIALS, SUPPLIES, AND INVENT

MATERIALS, SUPPLIES, AND INVENTORIES	3 Months Ended
	Mar. 31, 2018
Inventory Disclosure [Abstract]
MATERIALS, SUPPLIES, AND INVENTORIES	MATERIALS, SUPPLIES, AND INVENTORIES Our inventory consisted of: (in millions) March 31, 2018 December 31, 2017 Materials and supplies $ 136.2 $ 140.7 Fossil fuel 73.9 74.8 Natural gas in storage 4.6 35.2 Total $ 214.7 $ 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	3 Months Ended
	Mar. 31, 2018
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES The provision for income taxes for the quarter ended March 31, 2018, differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following: Amount Effective Tax Rate Statutory federal income tax $ 21.5 21.0 % State income taxes net of federal tax benefit 6.7 6.5 % Federal tax reform (5.4 ) (5.2 )% Tax repairs (25.5 ) (24.9 )% Other (0.9 ) (0.9 )% Total income tax benefit $ (3.6 ) (3.5 )% The effective tax rate of (3.5)% for the first quarter of 2018 differs from the United States statutory federal income tax rate of 21% primarily due to the flow through of tax repairs in connection with the Wisconsin rate settlement and the impact of the Tax Legislation, partially offset by state income taxes. The Tax Legislation, signed into law in December 2017, required 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 Federal tax reform line above). See Note 17, 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 Cuts and Jobs Act, 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	3 Months Ended
	Mar. 31, 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: March 31, 2018 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.4 $ — $ — $ 0.4 Petroleum products contracts 0.5 — — 0.5 FTRs — — 0.8 0.8 Coal contracts — 0.7 — 0.7 Total derivative assets $ 0.9 $ 0.7 $ 0.8 $ 2.4 Derivative liabilities Natural gas contracts $ 0.5 $ 0.1 $ — $ 0.6 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 March 31 (in millions) 2018 2017 Balance at the beginning of the period $ 2.4 $ 3.1 Settlements (1.6 ) (2.0 ) Balance at the end of the period $ 0.8 $ 1.1 Fair Value of Financial Instruments The following table shows the financial instruments included on our balance sheets that are not recorded at fair value: March 31, 2018 December 31, 2017 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 29.1 $ 30.4 $ 30.5 Long-term debt, including current portion 2,662.8 2,903.7 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	3 Months Ended
	Mar. 31, 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: March 31, 2018 December 31, 2017 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 0.4 $ 0.3 $ 0.6 $ 1.9 Petroleum products contracts 0.5 — 0.9 — FTRs 0.8 — 2.4 — Coal contracts 0.7 — 0.6 0.1 Total other current * $ 2.4 $ 0.3 $ 4.5 $ 2.0 Other long-term Natural gas contracts $ — $ 0.3 $ — $ 0.2 Coal contracts — — 0.1 0.2 Total other long-term * — 0.3 0.1 0.4 Total $ 2.4 $ 0.6 $ 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 March 31, 2018 Three Months Ended March 31, 2017 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 11.7 Dth $ (1.8 ) 8.2 Dth $ 0.5 Petroleum products contracts 1.4 gallons 0.4 4.9 gallons (0.5 ) FTRs 5.8 MWh 0.8 7.0 MWh 2.5 Total $ (0.6 ) $ 2.5 On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At March 31, 2018 and December 31, 2017 , we had posted cash collateral of $3.8 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: March 31, 2018 December 31, 2017 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 2.4 $ 0.6 $ 4.6 $ 2.4 Gross amount not offset on the balance sheet (0.4 ) (0.5 ) (1 ) (1.3 ) (2.0 ) (2 ) Net amount $ 2.0 $ 0.1 $ 3.3 $ 0.4 (1) Includes cash collateral posted of $0.1 million . (2) Includes cash collateral posted of $0.7 million .

EMPLOYEE BENEFITS

EMPLOYEE BENEFITS	3 Months Ended
	Mar. 31, 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 March 31 (in millions) 2018 2017 Service cost $ 3.3 $ 3.0 Interest cost 10.6 11.9 Expected return on plan assets (19.0 ) (19.2 ) Amortization of prior service cost 0.2 0.3 Amortization of net actuarial loss 9.4 8.8 Net periodic benefit cost $ 4.5 $ 4.8 OPEB Costs Three Months Ended March 31 (in millions) 2018 2017 Service cost $ 1.8 $ 1.9 Interest cost 2.8 3.1 Expected return on plan assets (3.9 ) (3.6 ) Amortization of prior service credit (0.6 ) (0.3 ) Amortization of net actuarial loss — 0.3 Net periodic benefit cost $ 0.1 $ 1.4 During the three months ended March 31, 2018 , we made contributions and payments of $1.5 million related to our pension plans and $0.6 million related to our OPEB plans. We expect to make contributions and payments of $2.4 million related to our pension plans and $4.3 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 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 quarters ended March 31, 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 cost components in other income, net. For the quarter ended March 31, 2018, the non-service cost components of net benefit cost were in a net credit position, in the amount of $(1.7) million . For the quarter ended March 31, 2017, the non-service cost components of net benefit cost were in a net debit position, in the amount of $1.2 million , and were reclassified from other operation and maintenance to other income, net, on our income statements. As required by ASU 2017-07, our income statements for the years ended December 31, 2017, 2016, and 2015 were retroactively restated from what was previously presented in our 2017 Annual Report on Form 10-K. The impacts to our income statements from adoption of this standard are reflected in the table below. Year Ended December 31, 2017 Year Ended December 31, 2016 Year Ended December 31, 2015 (in millions) Form 10-K Income Statement Impact of ASU 2017-07 Income Statement After Adoption Form 10-K Income Statement Impact of ASU 2017-07 Income Statement After Adoption Form 10-K Income Statement Impact of ASU 2017-07 Income Statement After Adoption Operating expenses Other operation and maintenance $ 1,358.5 $ (6.5 ) $ 1,352.0 $ 1,430.2 $ (4.7 ) $ 1,425.5 $ 1,384.9 $ (4.3 ) $ 1,380.6 Other expense Other income, net 19.7 (6.5 ) 13.2 9.1 (4.7 ) 4.4 11.2 (4.3 ) 6.9 In addition, 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 components of the net benefit cost that are no longer eligible for capitalization under this standard, but are capitalized under the regulatory framework, will be presented as regulatory assets or liabilities rather than property, plant, and equipment.

SEGMENT INFORMATION

SEGMENT INFORMATION	3 Months Ended
	Mar. 31, 2018
Segment Reporting [Abstract]
SEGMENT INFORMATION	SEGMENT INFORMATION We use operating income to measure segment profitability and to allocate resources to our businesses. At March 31, 2018 , we reported two segments, which are described below. Our utility segment includes 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 includes 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. See Note 2, Disposition, for more information . The following tables show summarized financial information for the three months ended March 31 , 2018 and 2017 , related to our reportable segments: (in millions) Utility Other Wisconsin Electric Power Company Consolidated Three Months Ended March 31, 2018 Operating revenues $ 941.5 $ — $ 941.5 Other operation and maintenance 335.6 — 335.6 Depreciation and amortization 85.3 — 85.3 Operating income 136.4 — 136.4 Interest expense 29.7 — 29.7 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Three Months Ended March 31, 2017 Operating revenues $ 972.0 $ — $ 972.0 Other operation and maintenance * 326.6 — 326.6 Depreciation and amortization 82.1 — 82.1 Operating income * 186.3 — 186.3 Interest expense 29.3 0.3 29.6 * Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 11, Employee Benefits, for more information on this new standard.

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	3 Months Ended
	Mar. 31, 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 $67.7 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 three months ended March 31, 2018 and 2017 were $4.7 million and $4.5 million , respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

RELATED PARTIES

RELATED PARTIES	3 Months Ended
	Mar. 31, 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, 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, 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) March 31, 2018 December 31, 2017 Accounts receivable Services provided to ATC $ 1.3 $ 0.8 Accounts payable Services received from ATC 16.4 22.2 The following table shows activity associated with our related party transactions: Three Months Ended March 31 (in millions) 2018 2017 Lease agreements Lease payments to We Power (1) $ 92.2 $ 104.4 Construction work in progress billed to We Power 3.8 16.3 Transactions with WBS (2) Billings to WBS (3) 5.9 56.5 Billings from WBS (4) 108.1 49.8 Transactions with WPS (2) Billings to WPS 3.0 2.5 Billings from WPS 3.2 1.1 Transactions with WG Natural gas purchases from WG 1.3 1.3 Billings to WG 13.9 15.8 Billings from WG 4.7 5.5 Transactions with UMERC Electric sales to UMERC 8.1 7.7 Billings to UMERC (2) 4.2 4.7 Transactions with Bluewater (5) Storage service fees 1.3 — Transactions with ATC Charges to ATC for services and construction 3.0 2.8 Charges from ATC for network transmission services 58.0 60.3 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. (2) Includes amounts billed for services, pass through costs, and other items in accordance with approved AIAs. (3) Includes $0.9 million for the transfer of certain benefit-related liabilities from WBS for the three months ended March 31, 2017 . There were no benefit-related liabilities transferred from WBS for the three months ended March 31, 2018 . (4) Includes $1.4 million for the transfer of certain benefit-related liabilities to WBS for the three months ended March 31, 2018 . Also includes $48.9 million for the transfer of certain software assets from WBS for the three months ended March 31, 2018 . There were no benefit-related liabilities transferred to WBS or assets transferred from WBS for the three months ended March 31, 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 will 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. See Note 17, Regulatory Environment, for more information .

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	3 Months Ended
	Mar. 31, 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 March 31, 2018 , were $9,890.7 million . Environmental Matters Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as sulfur dioxide, nitrogen oxide, fine particulates, mercury, and GHGs; water intake and discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites. Air Quality 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 NAAQS. In December 2017, the EPA informed Wisconsin of its intended area designations of all the counties along Wisconsin's Lake Michigan shoreline, except Brown, Kewaunee, Marinette, and Oconto Counties, as either partial or full nonattainment. Waukesha and Washington counties were also included due to the counties being in the Milwaukee combined statistical area. The EPA issued final nonattainment area designations on May 1, 2018. The final designations differ significantly from the intended nonattainment areas EPA proposed late in December 2017. The following counties were designated as partial nonattainment: Manitowoc, Sheboygan, Northern Milwaukee/Ozaukee shoreline, and Kenosha. Racine, Waukesha, and Washington counties will be designated attainment/unclassifiable. For nonattainment areas, the state of Wisconsin will have to develop a state implementation plan to bring the 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, a proposed federal plan and model trading rules as alternatives or guides to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In October 2015, following publication of the CPP, numerous states (including Wisconsin and Michigan) and other parties, filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but in February 2016, the Supreme Court stayed the effectiveness of the CPP until disposition of the litigation in the D.C. Circuit Court of Appeals and, to the extent that further appellate review is sought, at the Supreme Court. The D.C. Circuit Court of Appeals heard one case in September 2016, and the other case is still pending. In April 2017, pursuant to motions made by the EPA, the D.C. Circuit Court of Appeals ordered the cases to be held in abeyance. Supplemental briefs were provided addressing whether the cases should be remanded to the EPA rather than held in abeyance. The EPA argued that the cases should continue to be held in abeyance pending the conclusion of the EPA's review of the CPP and any resulting rulemaking. The CPP seeks to achieve state-specific GHG emission reduction goals by 2030, and would have required states to submit plans by September 2016. The goal of the final rule is to reduce nationwide GHG emissions by 32% from 2005 levels. The rule is seeking GHG emission reductions in Wisconsin and Michigan of 41% and 39% , respectively, below 2012 levels by 2030. Interim goals starting in 2022 would require states to achieve about two-thirds of the 2030 required reduction. In March 2017, President Trump issued an executive order that, among other things, specifically directs the EPA to review, and if appropriate, initiate proceedings to suspend, revise, or rescind the CPP and related GHG regulations for new, reconstructed, or modified fossil-fueled power plants. As a result of this order and related EPA review, as well as the ongoing legal proceedings, the timelines for the GHG emission reduction goals and all other aspects of the CPP are uncertain. In April 2017, the EPA withdrew the proposed rule for a federal plan and model trading rules that were published in October 2015 for use in developing state plans to implement the CPP or for use in states where a plan is not submitted or approved. In October 2017, the EPA issued a proposed rulemaking to repeal the CPP. In December 2017, the EPA issued an advanced notice of proposed rulemaking to solicit input on whether it is appropriate to replace the CPP. In addition, the Governor of Wisconsin issued an executive order in February 2016, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan to implement the CPP. Notwithstanding the uncertain future of the CPP, and given current fuel and technology markets, 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 a goal of reducing CO 2 emissions by approximately 40% below 2005 levels by 2030. We have implemented and continue to evaluate numerous options in order to meet WEC Energy Group's CO 2 reduction goal, such as increased use of existing natural gas combined cycle units, co-firing or switching to natural gas in existing coal-fired units, reduced operation or retirement of existing coal-fired units, addition of new renewable energy resources (wind, solar), and consideration of supply and demand-side energy efficiency and distributed generation. As a result of WEC Energy Group's generation reshaping plan, we expect to retire 1,547 MW of coal generation by 2020, including Pleasant Prairie power plant (now retired) and PIPP. See Note 4, Property, Plant, and Equipment, for more information . In addition, we are evaluating our goal, 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. We are required to report our CO 2 equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2017, we reported aggregated CO 2 equivalent emissions of 23.5 million metric tonnes to the EPA. The level of CO 2 and other GHG emissions varies from year to year and is dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO. We are also required to report CO 2 equivalent amounts related to the natural gas that our natural gas operations distribute and sell. For 2017, we reported aggregated CO 2 equivalent emissions of 3.7 million metric tonnes to the EPA. Water Quality Clean Water Act Cooling Water Intake Structure Rule In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act, 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 Valley Power Plant. Due to our plans to retire PIPP and Pleasant Prairie power plant (now retired), 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 yet 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 during 2018, ahead of when the agency begins processing our pending application for the National Pollutant Discharge Elimination System permit reissuance. 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. Various petitions challenging the rule were consolidated and are pending in the United States Fifth Circuit Court of Appeals. 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 dates for the bottom ash transport water and wet flue gas desulfurization wastewater requirements . This rule applies to wastewater discharges from our power plant processes in Wisconsin and Michigan. While the ELG compliance deadlines are postponed, the WDNR and the MDEQ have indicated that they will refrain from incorporating certain new requirements into any reissued discharge permits between 2018 and 2023. After a final rule is back in effect, the WDNR and MDEQ have indicated that they will modify the state rules as necessary and incorporate the new requirements into our facility permits, which are renewed every five years . 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 planned retirements of certain of our generation plants 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) March 31, 2018 December 31, 2017 Regulatory assets $ 30.1 $ 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	3 Months Ended
	Mar. 31, 2018
Supplemental Cash Flow Information [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	SUPPLEMENTAL CASH FLOW INFORMATION Three Months Ended March 31 (in millions) 2018 2017 Cash (paid) for interest, net of amount capitalized $ (4.7 ) $ (4.8 ) Cash (paid) for income taxes, net — (52.1 ) Significant noncash transactions: Accounts payable related to construction costs 7.3 11.0 Transfer of investment in ATC to another subsidiary of WEC Energy Group (1) (2) — 415.4 Transfer of net assets to UMERC (1) — 68.9 Accounts receivable related to the sale of Bostco real estate holdings (3) — 7.0 (1) See Note 14, 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. (3) See Note 2, Disposition, for more information on this transaction.

REGULATORY ENVIRONMENT

REGULATORY ENVIRONMENT	3 Months Ended
	Mar. 31, 2018
Regulated Operations [Abstract]
REGULATORY ENVIRONMENT	REGULATORY ENVIRONMENT Tax Cuts and Jobs Act of 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 in December 2017. The current 2018 tax benefit related to the Tax Legislation, which reduced the corporate federal tax rate from a maximum of 35% to a 21% rate, effective January 1, 2018, is also being deferred for return to ratepayers. In April 2018, the PSCW issued a preliminary determination regarding the benefits associated with the Tax Legislation. For our electric utility operations, the PSCW indicated that 80% of the current 2018 and 2019 tax benefits should be used to reduce our transmission regulatory asset, with the remaining 20% returned to our electric customers in the form of bill credits. For our natural gas utility operations, the PSCW indicated that 100% of current 2018 and 2019 tax benefits should be returned to our 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 for our electric operations should be used to reduce our transmission regulatory asset, while the timing and method of returning the remaining net tax benefit associated with the revaluation of deferred taxes was not addressed and will be determined in a future rate proceeding. Until we receive the final written order, the specific terms are subject to change. We currently serve one retail electric customer in Michigan, and have reached a settlement with that customer. That settlement was filed with the MPSC in March 2018 and addresses all base rate impacts of the Tax Legislation. 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 will freeze base rates through 2019 for electric and natural gas 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 our 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. Natural Gas Storage Facilities in Michigan In January 2017, WEC Energy Group signed an agreement for the acquisition of Bluewater. Bluewater owns natural gas storage facilities in Michigan that are providing a portion of the current storage needs for our natural gas operations. As a result of this agreement, we, along with WG and WPS, filed a request with the PSCW in February 2017 for a declaratory ruling on various items associated with the storage facilities. In the filing, we requested that the PSCW review and confirm the reasonableness and prudency of our potential long-term storage service agreement and interstate natural gas transportation contracts related to the storage facilities. We also requested approval to amend WEC Energy Group's AIA to ensure WBS and WEC Energy Group's other subsidiaries could provide services to the storage facilities. The PSCW granted, subject to various conditions, these declarations and approvals, and WEC Energy Group acquired Bluewater on June 30, 2017. In September 2017, we finalized the long-term service agreement for the natural gas storage, which was approved by the PSCW in November 2017. See Note 14, Related Parties, for more information .

NEW ACCOUNTING PRONOUNCEMENTS

NEW ACCOUNTING PRONOUNCEMENTS	3 Months Ended
	Mar. 31, 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. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, and will be applied using a modified retrospective approach. The main provision of this ASU is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP. We are currently assessing the effects this guidance may have on our financial statements. 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)	3 Months Ended
	Mar. 31, 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.
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 months ended March 31 , 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. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, and will be applied using a modified retrospective approach. The main provision of this ASU is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP. We are currently assessing the effects this guidance may have on our financial statements. 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 | Electric
Accounting policies
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 and consists 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. 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 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 utilities 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
Accounting policies
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. Certain of our 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. 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 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 .
Utility segment | Alternative revenues
Accounting policies
Revenue Recognition	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 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 or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.

OPERATING REVENUES (Tables)

OPERATING REVENUES (Tables)	3 Months Ended
	Mar. 31, 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. There are no revenues associated with our other segment. Comparable amounts have not been presented for the three months ended March 31, 2017, due to our adoption of this standard under the modified retrospective method. (in millions) Wisconsin Electric Power Company Consolidated Three Months Ended March 31, 2018 Electric utility $ 779.6 Natural gas utility 160.8 Total revenues from contracts with customers 940.4 Other operating revenues 1.1 Total operating revenues $ 941.5
Revenues from contracts with customers | Utility segment | 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 for the current period: (in millions) Electric Utility Operating Revenues Three Months Ended March 31, 2018 Residential $ 281.4 Small commercial and industrial 237.7 Large commercial and industrial 148.9 Other 5.4 Total retail revenues 673.4 Wholesale 28.5 Resale 63.7 Steam 9.7 Other utility revenues 4.3 Total electric utility operating revenues $ 779.6
Revenues from contracts with customers | Utility segment | 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 for the current period: (in millions) Natural Gas Utility Operations Three Months Ended March 31, 2018 Residential $ 114.7 Commercial and industrial 55.6 Total retail revenues 170.3 Transport 4.4 Other utility revenues * (13.9 ) Total natural gas utility operating revenues $ 160.8 * Includes amounts (refunded to) collected from customers for purchased gas adjustment costs.
Other operating revenues | Utility segment
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 March 31, 2018 Late payment charges $ 2.8 Leases 0.8 Alternative revenues * (2.5 ) Total other operating revenues $ 1.1 * 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.

SHORT-TERM DEBT AND LINES OF 26

SHORT-TERM DEBT AND LINES OF CREDIT (Tables)	3 Months Ended
	Mar. 31, 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) March 31, 2018 December 31, 2017 Commercial paper Amount outstanding $ 60.0 $ 210.9 Weighted-average interest rate on amounts outstanding 2.05 % 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 March 31, 2018 Revolving credit facility October 2022 $ 500.0 Less: Letters of credit issued inside credit facility $ 1.2 Commercial paper outstanding 60.0 Available capacity under existing agreement $ 438.8

MATERIALS, SUPPLIES, AND INVE27

MATERIALS, SUPPLIES, AND INVENTORIES (Tables)	3 Months Ended
	Mar. 31, 2018
Inventory Disclosure [Abstract]
Schedule of inventory	Our inventory consisted of: (in millions) March 31, 2018 December 31, 2017 Materials and supplies $ 136.2 $ 140.7 Fossil fuel 73.9 74.8 Natural gas in storage 4.6 35.2 Total $ 214.7 $ 250.7

INCOME TAXES (Tables)

INCOME TAXES (Tables)	3 Months Ended
	Mar. 31, 2018
Income Tax Disclosure [Abstract]
Schedule of Effective Income Tax Rate Reconciliation	The provision for income taxes for the quarter ended March 31, 2018, differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following: Amount Effective Tax Rate Statutory federal income tax $ 21.5 21.0 % State income taxes net of federal tax benefit 6.7 6.5 % Federal tax reform (5.4 ) (5.2 )% Tax repairs (25.5 ) (24.9 )% Other (0.9 ) (0.9 )% Total income tax benefit $ (3.6 ) (3.5 )%

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	3 Months Ended
	Mar. 31, 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: March 31, 2018 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.4 $ — $ — $ 0.4 Petroleum products contracts 0.5 — — 0.5 FTRs — — 0.8 0.8 Coal contracts — 0.7 — 0.7 Total derivative assets $ 0.9 $ 0.7 $ 0.8 $ 2.4 Derivative liabilities Natural gas contracts $ 0.5 $ 0.1 $ — $ 0.6 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 March 31 (in millions) 2018 2017 Balance at the beginning of the period $ 2.4 $ 3.1 Settlements (1.6 ) (2.0 ) Balance at the end of the period $ 0.8 $ 1.1
Schedule of carrying value and estimated fair value of financial instruments not recorded at fair value	The following table shows the financial instruments included on our balance sheets that are not recorded at fair value: March 31, 2018 December 31, 2017 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 29.1 $ 30.4 $ 30.5 Long-term debt, including current portion 2,662.8 2,903.7 2,662.3 2,976.3

DERIVATIVE INSTRUMENTS (Tables)

DERIVATIVE INSTRUMENTS (Tables)	3 Months Ended
	Mar. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative assets and derivative liabilities	The following table shows our derivative assets and derivative liabilities: March 31, 2018 December 31, 2017 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 0.4 $ 0.3 $ 0.6 $ 1.9 Petroleum products contracts 0.5 — 0.9 — FTRs 0.8 — 2.4 — Coal contracts 0.7 — 0.6 0.1 Total other current * $ 2.4 $ 0.3 $ 4.5 $ 2.0 Other long-term Natural gas contracts $ — $ 0.3 $ — $ 0.2 Coal contracts — — 0.1 0.2 Total other long-term * — 0.3 0.1 0.4 Total $ 2.4 $ 0.6 $ 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 March 31, 2018 Three Months Ended March 31, 2017 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 11.7 Dth $ (1.8 ) 8.2 Dth $ 0.5 Petroleum products contracts 1.4 gallons 0.4 4.9 gallons (0.5 ) FTRs 5.8 MWh 0.8 7.0 MWh 2.5 Total $ (0.6 ) $ 2.5
Offsetting Assets and Liabilities	The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: March 31, 2018 December 31, 2017 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 2.4 $ 0.6 $ 4.6 $ 2.4 Gross amount not offset on the balance sheet (0.4 ) (0.5 ) (1 ) (1.3 ) (2.0 ) (2 ) Net amount $ 2.0 $ 0.1 $ 3.3 $ 0.4 (1) Includes cash collateral posted of $0.1 million . (2) Includes cash collateral posted of $0.7 million .

EMPLOYEE BENEFITS (Tables)

EMPLOYEE BENEFITS (Tables)	3 Months Ended
	Mar. 31, 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 March 31 (in millions) 2018 2017 Service cost $ 3.3 $ 3.0 Interest cost 10.6 11.9 Expected return on plan assets (19.0 ) (19.2 ) Amortization of prior service cost 0.2 0.3 Amortization of net actuarial loss 9.4 8.8 Net periodic benefit cost $ 4.5 $ 4.8 OPEB Costs Three Months Ended March 31 (in millions) 2018 2017 Service cost $ 1.8 $ 1.9 Interest cost 2.8 3.1 Expected return on plan assets (3.9 ) (3.6 ) Amortization of prior service credit (0.6 ) (0.3 ) Amortization of net actuarial loss — 0.3 Net periodic benefit cost $ 0.1 $ 1.4
Schedule of retroactively restated Income Statement	The impacts to our income statements from adoption of this standard are reflected in the table below. Year Ended December 31, 2017 Year Ended December 31, 2016 Year Ended December 31, 2015 (in millions) Form 10-K Income Statement Impact of ASU 2017-07 Income Statement After Adoption Form 10-K Income Statement Impact of ASU 2017-07 Income Statement After Adoption Form 10-K Income Statement Impact of ASU 2017-07 Income Statement After Adoption Operating expenses Other operation and maintenance $ 1,358.5 $ (6.5 ) $ 1,352.0 $ 1,430.2 $ (4.7 ) $ 1,425.5 $ 1,384.9 $ (4.3 ) $ 1,380.6 Other expense Other income, net 19.7 (6.5 ) 13.2 9.1 (4.7 ) 4.4 11.2 (4.3 ) 6.9

SEGMENT INFORMATION (Tables)

SEGMENT INFORMATION (Tables)	3 Months Ended
	Mar. 31, 2018
Segment Reporting [Abstract]
Schedule of information related to our reportable segments	The following tables show summarized financial information for the three months ended March 31 , 2018 and 2017 , related to our reportable segments: (in millions) Utility Other Wisconsin Electric Power Company Consolidated Three Months Ended March 31, 2018 Operating revenues $ 941.5 $ — $ 941.5 Other operation and maintenance 335.6 — 335.6 Depreciation and amortization 85.3 — 85.3 Operating income 136.4 — 136.4 Interest expense 29.7 — 29.7 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Three Months Ended March 31, 2017 Operating revenues $ 972.0 $ — $ 972.0 Other operation and maintenance * 326.6 — 326.6 Depreciation and amortization 82.1 — 82.1 Operating income * 186.3 — 186.3 Interest expense 29.3 0.3 29.6 * Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 11, Employee Benefits, for more information on this new standard.

RELATED PARTIES (Tables)

RELATED PARTIES (Tables)	3 Months Ended
	Mar. 31, 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) March 31, 2018 December 31, 2017 Accounts receivable Services provided to ATC $ 1.3 $ 0.8 Accounts payable Services received from ATC 16.4 22.2
Schedule of activity associated with related party transactions	The following table shows activity associated with our related party transactions: Three Months Ended March 31 (in millions) 2018 2017 Lease agreements Lease payments to We Power (1) $ 92.2 $ 104.4 Construction work in progress billed to We Power 3.8 16.3 Transactions with WBS (2) Billings to WBS (3) 5.9 56.5 Billings from WBS (4) 108.1 49.8 Transactions with WPS (2) Billings to WPS 3.0 2.5 Billings from WPS 3.2 1.1 Transactions with WG Natural gas purchases from WG 1.3 1.3 Billings to WG 13.9 15.8 Billings from WG 4.7 5.5 Transactions with UMERC Electric sales to UMERC 8.1 7.7 Billings to UMERC (2) 4.2 4.7 Transactions with Bluewater (5) Storage service fees 1.3 — Transactions with ATC Charges to ATC for services and construction 3.0 2.8 Charges from ATC for network transmission services 58.0 60.3 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. (2) Includes amounts billed for services, pass through costs, and other items in accordance with approved AIAs. (3) Includes $0.9 million for the transfer of certain benefit-related liabilities from WBS for the three months ended March 31, 2017 . There were no benefit-related liabilities transferred from WBS for the three months ended March 31, 2018 . (4) Includes $1.4 million for the transfer of certain benefit-related liabilities to WBS for the three months ended March 31, 2018 . Also includes $48.9 million for the transfer of certain software assets from WBS for the three months ended March 31, 2018 . There were no benefit-related liabilities transferred to WBS or assets transferred from WBS for the three months ended March 31, 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)	3 Months Ended
	Mar. 31, 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) March 31, 2018 December 31, 2017 Regulatory assets $ 30.1 $ 30.4 Reserves for future remediation * 18.5 18.5 * Recorded within other long-term liabilities on our balance sheets.

SUPPLEMENTAL CASH FLOW INFORM35

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	3 Months Ended
	Mar. 31, 2018
Supplemental Cash Flow Information [Abstract]
Schedule of supplemental cash flow information	Three Months Ended March 31 (in millions) 2018 2017 Cash (paid) for interest, net of amount capitalized $ (4.7 ) $ (4.8 ) Cash (paid) for income taxes, net — (52.1 ) Significant noncash transactions: Accounts payable related to construction costs 7.3 11.0 Transfer of investment in ATC to another subsidiary of WEC Energy Group (1) (2) — 415.4 Transfer of net assets to UMERC (1) — 68.9 Accounts receivable related to the sale of Bostco real estate holdings (3) — 7.0 (1) See Note 14, 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. (3) See Note 2, Disposition, for more information on this transaction.

OPERATING REVENUES - DISAGGREGA

OPERATING REVENUES - DISAGGREGATION OF OPERATING REVENES (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)contractperformance_obligations	Mar. 31, 2017USD ($)
Disaggregation of Operating Revenues
Operating revenues	$ 941.5	$ 972
Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	$ 1.1
Electric
Disaggregation of Operating Revenues
Number of contracts | contract	1
Number of performance obligations | performance_obligations	2
Number of days payment is due	30 days
Natural gas
Disaggregation of Operating Revenues
Number of days payment is due	30 days
Utility segment
Disaggregation of Operating Revenues
Operating revenues	$ 941.5	$ 972
Utility segment | Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	1.1
Utility segment | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Operating revenues	940.4
Utility segment | Electric | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Operating revenues	779.6
Utility segment | Electric | Transferred over time | Revenues from contracts with customers | Residential
Disaggregation of Operating Revenues
Operating revenues	281.4
Utility segment | Electric | Transferred over time | Revenues from contracts with customers | Small commercial and industrial
Disaggregation of Operating Revenues
Operating revenues	237.7
Utility segment | Electric | Transferred over time | Revenues from contracts with customers | Large commercial and industrial
Disaggregation of Operating Revenues
Operating revenues	148.9
Utility segment | Electric | Transferred over time | Revenues from contracts with customers | Other
Disaggregation of Operating Revenues
Operating revenues	5.4
Utility segment | Electric | Transferred over time | Revenues from contracts with customers | Total retail
Disaggregation of Operating Revenues
Operating revenues	673.4
Utility segment | Electric | Transferred over time | Revenues from contracts with customers | Wholesale
Disaggregation of Operating Revenues
Operating revenues	28.5
Utility segment | Electric | Transferred over time | Revenues from contracts with customers | Resale
Disaggregation of Operating Revenues
Operating revenues	63.7
Utility segment | Electric | Transferred over time | Revenues from contracts with customers | Steam
Disaggregation of Operating Revenues
Operating revenues	9.7
Utility segment | Electric | Transferred over time | Revenues from contracts with customers | Other utility
Disaggregation of Operating Revenues
Operating revenues	4.3
Utility segment | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Operating revenues	160.8
Utility segment | Natural gas | Transferred over time | Revenues from contracts with customers | Residential
Disaggregation of Operating Revenues
Operating revenues	114.7
Utility segment | Natural gas | Transferred over time | Revenues from contracts with customers | Total retail
Disaggregation of Operating Revenues
Operating revenues	170.3
Utility segment | Natural gas | Transferred over time | Revenues from contracts with customers | Commercial and industrial
Disaggregation of Operating Revenues
Operating revenues	55.6
Utility segment | Natural gas | Transferred over time | Revenues from contracts with customers | Transport
Disaggregation of Operating Revenues
Operating revenues	4.4
Utility segment | Natural gas | Transferred over time | Revenues from contracts with customers | Other utility
Disaggregation of Operating Revenues
Operating revenues	$ (13.9)

OPERATING REVENUES - OTHER OPER

OPERATING REVENUES - OTHER OPERATING REVENUES (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Disaggregation of Operating Revenues
Operating revenues	$ 941.5	$ 972
Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	1.1
Other operating revenues | Late payment charges
Disaggregation of Operating Revenues
Operating revenues	2.8
Other operating revenues | Leases
Disaggregation of Operating Revenues
Operating revenues	0.8
Other operating revenues | Alternative revenues
Disaggregation of Operating Revenues
Operating revenues	$ (2.5)

PROPERTY, PLANT, AND EQUIPMENT

PROPERTY, PLANT, AND EQUIPMENT (Details) $ in Millions	1 Months Ended	12 Months Ended
	Oct. 31, 2017MW	Dec. 31, 2017USD ($)	Mar. 31, 2018USD ($)
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, Net			$ 674.1
Presque Isle power plant
Property, plant, and equipment
Plant to be retired, Net			$ 188.7
Utility segment
Property, plant, and equipment
Severance expense		$ 25.8

SHORT-TERM DEBT AND LINES OF 39

SHORT-TERM DEBT AND LINES OF CREDIT - SHORT-TERM BORROWINGS (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Short-term borrowings
Commercial paper outstanding	$ 60	$ 210.9
Commercial paper
Short-term borrowings
Weighted-average interest rate on amounts outstanding	2.05%	1.81%
Average amount outstanding during the period	$ 96.2
Weighted-average interest rate during the period	1.86%

SHORT-TERM DEBT AND LINES OF 40

SHORT-TERM DEBT AND LINES OF CREDIT - REVOLVING CREDIT FACILITIES (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Revolving credit facility
Letters of credit issued inside credit facility	$ 1.2
Commercial paper outstanding	60	$ 210.9
Available capacity under existing agreement	438.8
Credit facility maturing during October 2022
Revolving credit facility
Revolving credit facility	$ 500

MATERIALS, SUPPLIES, AND INVE41

MATERIALS, SUPPLIES, AND INVENTORIES (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Inventory Disclosure [Abstract]
Materials and supplies	$ 136.2	$ 140.7
Fossil fuel	73.9	74.8
Natural gas in storage	4.6	35.2
Total	$ 214.7	$ 250.7

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended
	Dec. 31, 2017	Mar. 31, 2018	Mar. 31, 2017
Effective Income Tax Rate Reconciliation, Amount
Statutory federal income tax, amount		$ 21.5
State income taxes net of federal tax benefit, amount		6.7
Federal tax reform, amount		(5.4)
Tax repairs, amount		(25.5)
Other, amount		(0.9)
Total income tax benefit, amount		$ (3.6)	$ 57.8
Effective Income Tax Rate Reconciliation, Percent
Statutory federal income tax, percentage		21.00%	35.00%
State income taxes net of federal tax benefit, percentage		6.50%
Federal tax reform, percentage		(5.20%)
Tax repairs, percentage		(24.90%)
Other, percentage		(0.90%)
Total income tax benefit, percentage		(3.50%)
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	Mar. 31, 2018	Dec. 31, 2017
Assets
Derivative asset	$ 2.4	$ 4.6
Liabilities
Derivative liability	0.6	2.4
Fair value measurements on a recurring basis
Assets
Derivative asset	2.4	4.6
Liabilities
Derivative liability		2.4
Fair value measurements on a recurring basis | Level 1
Assets
Derivative asset	0.9	1.4
Liabilities
Derivative liability		2
Fair value measurements on a recurring basis | Level 2
Assets
Derivative asset	0.7	0.8
Liabilities
Derivative liability		0.4
Fair value measurements on a recurring basis | Level 3
Assets
Derivative asset	0.8	2.4
Liabilities
Derivative liability		0
Fair value measurements on a recurring basis | Natural gas contracts
Assets
Derivative asset	0.4	0.6
Liabilities
Derivative liability	0.6	2.1
Fair value measurements on a recurring basis | Natural gas contracts | Level 1
Assets
Derivative asset	0.4	0.5
Liabilities
Derivative liability	0.5	2
Fair value measurements on a recurring basis | Natural gas contracts | Level 2
Assets
Derivative asset	0	0.1
Liabilities
Derivative liability	0.1	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	0.5	0.9
Fair value measurements on a recurring basis | Petroleum products contracts | Level 1
Assets
Derivative asset	0.5	0.9
Fair value measurements on a recurring basis | Petroleum products contracts | Level 2
Assets
Derivative asset	0	0
Fair value measurements on a recurring basis | Petroleum products contracts | Level 3
Assets
Derivative asset	0	0
Fair value measurements on a recurring basis | FTRs
Assets
Derivative asset	0.8	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	0.8	2.4
Fair value measurements on a recurring basis | Coal contracts
Assets
Derivative asset	0.7	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	0.7	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
	Mar. 31, 2018	Mar. 31, 2017
Level 3 rollforward
Balance at the beginning of the period	$ 2.4	$ 3.1
Settlements	(1.6)	(2)
Balance at the end of the period	$ 0.8	$ 1.1

FAIR VALUE MEASUREMENTS - FINAN

FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Millions	Mar. 31, 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	2,662.8	2,662.3
Fair Value
Carrying value and estimated fair value of financial instruments
Preferred stock	29.1	30.5
Long-term debt, including current portion	$ 2,903.7	$ 2,976.3

DERIVATIVE INSTRUMENTS - DERIVA

DERIVATIVE INSTRUMENTS - DERIVATIVE ASSETS AND DERIVATIVE LIABILITIES (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Derivative Asset
Other current derivative assets	$ 2.4	$ 4.5
Other long-term derivative assets	0	0.1
Derivative asset	2.4	4.6
Derivative Liability
Other current derivative liabilities	0.3	2
Other long-term derivative liabilities	0.3	0.4
Derivative liability	0.6	2.4
Natural gas contracts
Derivative Asset
Other current derivative assets	0.4	0.6
Other long-term derivative assets	0	0
Derivative Liability
Other current derivative liabilities	0.3	1.9
Other long-term derivative liabilities	0.3	0.2
Petroleum products contracts
Derivative Asset
Other current derivative assets	0.5	0.9
Derivative Liability
Other current derivative liabilities	0	0
FTRs
Derivative Asset
Other current derivative assets	0.8	2.4
Derivative Liability
Other current derivative liabilities	0	0
Coal contracts
Derivative Asset
Other current derivative assets	0.7	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
	Mar. 31, 2018USD ($)MWhMMBTUgal	Mar. 31, 2017USD ($)MWhMMBTUgal
Realized Gain (Loss) on Derivatives
Gains (Losses)	$ (0.6)	$ 2.5
Natural gas contracts
Realized Gain (Loss) on Derivatives
Gains (Losses)	$ (1.8)	$ 0.5
Notional Sales Volumes
Notional sales volumes | MMBTU	11.7	8.2
Petroleum products contracts
Realized Gain (Loss) on Derivatives
Gains (Losses)	$ 0.4	$ (0.5)
Notional Sales Volumes
Notional sales volumes (gallons) | gal	1.4	4.9
FTRs
Realized Gain (Loss) on Derivatives
Gains (Losses)	$ 0.8	$ 2.5
Notional Sales Volumes
Notional sales volumes | MWh	5.8	7

DERIVATIVE INSTRUMENTS - OFFSET

DERIVATIVE INSTRUMENTS - OFFSETTING TABLE (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Cash collateral
Collateral in margin account	$ 3.8	$ 4.9
Offsetting Derivative Assets
Gross amount recognized on the balance sheet	2.4	4.6
Gross amount not offset on the balance sheet	(0.4)	(1.3)
Net amount	2	3.3
Offsetting Derivative Liabilities
Gross amount recognized on the balance sheet	0.6	2.4
Gross amount not offset on the balance sheet	(0.5)	(2)
Net amount	0.1	0.4
Collateral posted	$ 0.1	$ 0.7

EMPLOYEE BENEFITS-COSTS AND CON

EMPLOYEE BENEFITS-COSTS AND CONTRIBUTIONS (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Components of net periodic benefit costs
Contributions and payments related to pension and OPEB plans	$ 2.1	$ 3.3
Pension Costs
Components of net periodic benefit costs
Service cost	3.3	3
Interest cost	10.6	11.9
Expected return on plan assets	(19)	(19.2)
Amortization of prior service cost (credit)	0.2	0.3
Amortization of net actuarial loss	9.4	8.8
Net periodic benefit cost	4.5	4.8
Contributions and payments related to pension and OPEB plans	1.5
Estimated future employer contributions for the remainder of the year	2.4
Other Postretirement Benefit Costs
Components of net periodic benefit costs
Service cost	1.8	1.9
Interest cost	2.8	3.1
Expected return on plan assets	(3.9)	(3.6)
Amortization of prior service cost (credit)	(0.6)	(0.3)
Amortization of net actuarial loss	0	0.3
Net periodic benefit cost	0.1	$ 1.4
Contributions and payments related to pension and OPEB plans	0.6
Estimated future employer contributions for the remainder of the year	$ 4.3

EMPLOYEE BENEFITS-IMPACT OF ADO

EMPLOYEE BENEFITS-IMPACT OF ADOPTION OF ASU 2017-07 (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other operation and maintenance			$ 1,352	$ 1,425.5	$ 1,380.6
Other income, net	$ (4.2)	$ 3.2	13.2	4.4	6.9
2017 Form 10-K Income Statement
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other operation and maintenance			1,358.5	1,430.2	1,384.9
Other income, net			19.7	9.1	11.2
Accounting Standards Update 2017-07
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Non-service cost components of net benefit cost	$ (1.7)
Accounting Standards Update 2017-07 | Impact of ASU 2017-07
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Non-service cost components of net benefit cost		$ 1.2
Other operation and maintenance			(6.5)	(4.7)	(4.3)
Other income, net			$ (6.5)	$ (4.7)	$ (4.3)

SEGMENT INFORMATION (Details)

SEGMENT INFORMATION (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)areasegmentcustomer	Mar. 31, 2017USD ($)
Segment information
Number of reportable segments | segment	2
Operating revenues	$ 941.5	$ 972
Other operation and maintenance	335.6	326.6
Depreciation and amortization	85.3	82.1
Operating income	136.4	186.3
Interest expense	$ 29.7	29.6
Michigan
Segment information
Number of customers | customer	1
Utility segment
Segment information
Number of service areas | area	3
Operating revenues	$ 941.5	972
Other operation and maintenance	335.6	326.6
Depreciation and amortization	85.3	82.1
Operating income	136.4	186.3
Interest expense	29.7	29.3
Other
Segment information
Operating revenues	0	0
Other operation and maintenance	0	0
Depreciation and amortization	0	0
Operating income	0	0
Interest expense	$ 0	$ 0.3

VARIABLE INTEREST ENTITIES (Det

VARIABLE INTEREST ENTITIES (Details) - Purchased power agreement $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)MW	Mar. 31, 2017USD ($)
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	67.7
Total capacity and lease payments	$ 4.7	$ 4.5

RELATED PARTIES (Details)

RELATED PARTIES (Details) - ATC - USD ($) $ in Millions	Jan. 01, 2017	Mar. 31, 2018	Dec. 31, 2017
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		$ 1.3	$ 0.8
Accounts payable, related parties, current		$ 16.4	$ 22.2

RELATED PARTIES - OTHER TRANSAC

RELATED PARTIES - OTHER TRANSACTIONS (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended
	Jun. 30, 2017	Mar. 31, 2018	Mar. 31, 2017
Related parties
(Payments for) proceeds from liabilities transferred (to) from WBS		$ (1.4)	$ 0.9
We Power LLC
Related parties
Lease payments to W.E. Power, LLC		92.2	104.4
Construction work In progress billed to related party		3.8	16.3
WBS
Related parties
Charges to related party for services and billings		5.9	56.5
Charges from related party for services and billings		108.1	49.8
(Payments for) proceeds from liabilities transferred (to) from WBS		0	0.9
Payments for transfer of liabilities to related parties		1.4	0
Payments for transfer of assets from related parties		48.9	0
WPS
Related parties
Charges to related party for services and billings		3	2.5
Charges from related party for services and billings		3.2	1.1
WG
Related parties
Charges to related party for services and billings		13.9	15.8
Charges from related party for services and billings		4.7	5.5
Natural gas purchases		1.3	1.3
UMERC
Related parties
Charges to related party for services and billings		4.2	4.7
Electric sales to UMERC		8.1	7.7
Bluewater
Related parties
Charges from related party for services and billings		1.3	0
Purchase price	$ 226
ATC
Related parties
Charges to related party for services and billings		3	2.8
Charges from related party for services and billings		58	60.3
Refund from ATC per FERC ROE order		$ 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	Mar. 31, 2018USD ($)
Minimum future commitments for purchase obligations
Purchase obligations	$ 9,890.7

COMMITMENTS AND CONTINGENCIES57

COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) T in Millions, $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Oct. 31, 2014compliance_option	Mar. 31, 2018USD ($)degreecelsiusMW	Dec. 31, 2017USD ($)T	Dec. 31, 2015	Sep. 30, 2016Case
Climate Change | Electric
Air quality
Number of legal cases heard by a court | Case					1
Percentage of nationwide greenhouse gas emissions reduction				32.00%
Interim Requirement Greenhouse Gas Emissions Reductions				0.667
Company goal for percentage of carbon dioxide emissions reduction		40.00%
Coal Generation Capacity Expected To Be Retired By 2020 | MW		1,547
Carbon Dioxide Emissions | T			23.5
Climate Change | Electric | Maximum
Air quality
Global temperature increases limit | degreecelsius		2
Climate Change | Electric | Wisconsin
Air quality
Percentage of greenhouse gas emissions reduction by state				41.00%
Climate Change | Electric | Michigan
Air quality
Percentage of greenhouse gas emissions reduction by state				39.00%
Climate Change | Natural gas
Air quality
Carbon Dioxide Emissions | T			3.7
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
Renewal period for facility permits		5 years
Steam Electric Effluent Limitation Guidelines | Electric | Minimum
Water quality
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		30.1	$ 30.4
Reserves recorded for remediation of manufactured gas plant sites		$ 18.5	$ 18.5

SUPPLEMENTAL CASH FLOW INFORM58

SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2016
Supplemental Cash Flow Information [Abstract]
Cash (paid) for interest, net of amount capitalized	$ (4.7)	$ (4.8)
Cash (paid) for income taxes, net	0	(52.1)
Significant noncash transactions
Accounts payable related to construction costs	7.3	11
ATC
Significant noncash transactions
Transfer of investment in ATC to another subsidiary of WEC Energy Group	0	415.4
Distributions receivable transferred to affiliate			$ 13.4
UMERC
Significant noncash transactions
Transfer of net assets to UMERC	0	68.9
Bostco
Significant noncash transactions
Accounts receivable related to the sale of Bostco real estate holdings	$ 0	$ 7

REGULATORY ENVIRONMENT (Details

REGULATORY ENVIRONMENT (Details) $ in Millions	1 Months Ended			3 Months Ended
	Apr. 30, 2018	Dec. 31, 2017USD ($)	Sep. 30, 2017	Mar. 31, 2018customer	Mar. 31, 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%
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 | Subsequent event
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 | Subsequent event
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%