10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended June 30, 2018

Commission	Registrant; State of Incorporation;	IRS Employer
File Number	Address; and Telephone Number	Identification No.
001-01245	WISCONSIN ELECTRIC POWER COMPANY	39-0476280
	(A Wisconsin Corporation)
	231 West Michigan Street
	P.O. Box 2046
	Milwaukee, WI 53201
	(414) 221-2345

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes [X]    No [ ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes [X]     No [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer [  ]	Accelerated filer [  ]
Non-accelerated filer [X] (Do not check if a smaller reporting company)	Smaller reporting company [  ]
	Emerging growth company [  ]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes [ ]    No [X]

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:

Common Stock, $10 Par Value,

33,289,327 shares outstanding at

June 30, 2018

All of the common stock of Wisconsin Electric Power Company is owned by WEC Energy Group, Inc.

WISCONSIN ELECTRIC POWER COMPANY

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended June 30, 2018

TABLE OF CONTENTS

				Page
	CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION			1
PART I.	FINANCIAL INFORMATION			3
ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)			3
	Condensed Consolidated Income Statements			3
	Condensed Consolidated Balance Sheets			4
	Condensed Consolidated Statements of Cash Flows			5
	Notes to Condensed Consolidated Financial Statements			6
			Page
	Note 1	General Information	6
	Note 2	Disposition	6
	Note 3	Operating Revenues	6
	Note 4	Property, Plant, and Equipment	9
	Note 5	Common Equity	10
	Note 6	Short-Term Debt and Lines of Credit	10
	Note 7	Long-Term Debt	10
	Note 8	Materials, Supplies, and Inventories	11
	Note 9	Income Taxes	11
	Note 10	Fair Value Measurements	11
	Note 11	Derivative Instruments	13
	Note 12	Employee Benefits	14
	Note 13	Segment Information	15
	Note 14	Variable Interest Entities	16
	Note 15	Related Parties	17
	Note 16	Commitments and Contingencies	19
	Note 17	Supplemental Cash Flow Information	22
	Note 18	Regulatory Environment	22
	Note 19	New Accounting Pronouncements	23
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			24
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			38
ITEM 4.	CONTROLS AND PROCEDURES			39
PART II.	OTHER INFORMATION			40
ITEM 1.	LEGAL PROCEEDINGS			40
ITEM 1A.	RISK FACTORS			40
ITEM 6.	EXHIBITS			41
SIGNATURE				42

06/30/2018 Form 10-Q i Wisconsin Electric Power Company

GLOSSARY OF TERMS AND ABBREVIATIONS

The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:

Subsidiaries and Affiliates
ATC	American Transmission Company LLC
Bluewater	Bluewater Natural Gas Holding, LLC
Bostco	Bostco LLC
UMERC	Upper Michigan Energy Resources Corporation
WBS	WEC Business Services LLC
We Power	W.E. Power, LLC
WEC Energy Group	WEC Energy Group, Inc.
WG	Wisconsin Gas LLC
WPS	Wisconsin Public Service Corporation
Federal and State Regulatory Agencies
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
MDEQ	Michigan Department of Environmental Quality
MPSC	Michigan Public Service Commission
PSCW	Public Service Commission of Wisconsin
SEC	United States Securities and Exchange Commission
WDNR	Wisconsin Department of Natural Resources
Accounting Terms
AFUDC	Allowance for Funds Used During Construction
ASU	Accounting Standards Update
FASB	Financial Accounting Standards Board
GAAP	United States Generally Accepted Accounting Principles
OPEB	Other Postretirement Employee Benefits
Environmental Terms
CO2	Carbon Dioxide
CPP	Clean Power Plan
GHG	Greenhouse Gas
Measurements
Dth	Dekatherm
MW	Megawatt
MWh	Megawatt-hour
Other Terms and Abbreviations
D.C. Circuit Court of Appeals	United States Court of Appeals for the District of Columbia Circuit
ERGS	Elm Road Generating Station
Exchange Act	Securities Exchange Act of 1934, as amended
FTRs	Financial Transmission Rights
MISO	Midcontinent Independent System Operator, Inc.
MISO Energy Markets	MISO Energy and Operating Reserves Markets
OCPP	Oak Creek Power Plant
OC 5	Oak Creek Power Plant Unit 5
OC 6	Oak Creek Power Plant Unit 6
OC 7	Oak Creek Power Plant Unit 7
OC 8	Oak Creek Power Plant Unit 8

06/30/2018 Form 10-Q ii Wisconsin Electric Power Company

PIPP	Presque Isle Power Plant
PWGS	Port Washington Generating Station
ROE	Return on Equity
Supreme Court	United States Supreme Court
Tax Legislation	Tax Cuts and Jobs Act of 2017

06/30/2018 Form 10-Q iii Wisconsin Electric Power Company

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

In this report, we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act. Readers are cautioned not to place undue reliance on these forward-looking statements. Forward-looking statements may be identified by reference to a future period or periods or by the use of terms such as "anticipates," "believes," "could," "estimates," "expects," "forecasts," "goals," "guidance," "intends," "may," "objectives," "plans," "possible," "potential," "projects," "seeks," "should," "targets," "will," or variations of these terms.

Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of capital projects, sales and customer growth, rate actions and related filings with regulatory authorities, environmental and other regulations and associated compliance costs, legal proceedings, effective tax rate, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, environmental matters, liquidity and capital resources, and other matters.

Forward-looking statements are subject to a number of risks and uncertainties that could cause our actual results to differ materially from those expressed or implied in the statements. These risks and uncertainties include those described in risk factors as set forth in this report and our 2017 Annual Report on Form 10-K, and those identified below:

• Factors affecting utility operations such as catastrophic weather-related damage, environmental incidents, unplanned facility outages and repairs and maintenance, and electric transmission or natural gas pipeline system constraints;

• Factors affecting the demand for electricity and natural gas, including political developments, unusual weather, changes in economic conditions, customer growth and declines, commodity prices, energy conservation efforts, and continued adoption of distributed generation by customers;

• The timing, resolution, and impact of rate cases and negotiations, including recovery of deferred and current costs and the ability to earn a reasonable return on investment, and other regulatory decisions impacting our regulated operations;

• The ability to obtain and retain customers, including wholesale customers, due to increased competition in our electric and natural gas markets from retail choice and alternative electric suppliers, and continued industry consolidation;

• The timely completion of capital projects within budgets, as well as the recovery of the related costs through rates;

• The impact of federal, state, and local legislative and regulatory changes, including changes in rate-setting policies or procedures, deregulation and restructuring of the electric and/or natural gas utility industries, transmission or distribution system operation, the approval process for new construction, reliability standards, pipeline integrity and safety standards, allocation of energy assistance, and energy efficiency mandates;

• The uncertainty surrounding the recently enacted Tax Legislation, including implementing regulations and IRS interpretations, the amount to be returned to our ratepayers, and its impact, if any, on our credit ratings;

• Federal and state legislative and regulatory changes relating to the environment, including climate change and other environmental regulations impacting generation facilities and renewable energy standards, the enforcement of these laws and regulations, changes in the interpretation of regulations or permit conditions by regulatory agencies, and the recovery of associated remediation and compliance costs;

• Factors affecting the implementation of WEC Energy Group's generation reshaping plan, including related regulatory decisions, the cost of materials, supplies, and labor, and the feasibility of competing projects;

• Increased pressure on us by investors and other stakeholder groups to take more aggressive action to reduce future GHG emissions in order to limit future global temperature increases;

• The risks associated with changing commodity prices, particularly natural gas and electricity, and the availability of sources of fossil fuel, natural gas, purchased power, materials needed to operate environmental controls at our electric generating facilities, or water supply due to high demand, shortages, transportation problems, nonperformance by electric energy or natural gas suppliers under existing power purchase or natural gas supply contracts, or other developments;

06/30/2018 Form 10-Q 1 Wisconsin Electric Power Company

• Changes in credit ratings, interest rates, and our ability to access the capital markets, caused by volatility in the global credit markets, our capitalization structure, and market perceptions of the utility industry or us;

• Costs and effects of litigation, administrative proceedings, investigations, settlements, claims, and inquiries;

• The risk of financial loss, including increases in bad debt expense, associated with the inability of our customers, counterparties, and affiliates to meet their obligations;

• Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading markets and fuel suppliers and transporters;

• The direct or indirect effect on our business resulting from terrorist attacks and cyber security intrusions, as well as the threat of such incidents, including the failure to maintain the security of personally identifiable information, the associated costs to protect our utility assets, technology systems, and personal information, and the costs to notify affected persons to mitigate their information security concerns;

• The investment performance of our employee benefit plan assets, as well as unanticipated changes in related actuarial assumptions, which could impact future funding requirements;

• Factors affecting the employee workforce, including loss of key personnel, internal restructuring, work stoppages, and collective bargaining agreements and negotiations with union employees;

• Advances in technology that result in competitive disadvantages and create the potential for impairment of existing assets;

• The timing, costs, and anticipated benefits associated with the remaining integration efforts relating to WEC Energy Group's acquisition of Integrys Holding, Inc.;

• Potential business strategies to acquire and dispose of assets or businesses, which cannot be assured to be completed timely or within budgets;

• The timing and outcome of any audits, disputes, and other proceedings related to taxes;

• The ability to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act, while both integrating and continuing to consolidate WEC Energy Group's enterprise systems with those of its other utilities;

• The effect of accounting pronouncements issued periodically by standard-setting bodies; and

• Other considerations disclosed elsewhere herein and in other reports we file with the SEC or in other publicly disseminated written documents.

We expressly disclaim any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

06/30/2018 Form 10-Q 2 Wisconsin Electric Power Company

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WISCONSIN ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited)	Three Months Ended						Six Months Ended
	June 30						June 30
(in millions)	2018			2017			2018			2017
Operating revenues	$	856.2		$	855.4		$	1,797.7		$	1,827.4
Operating expenses
Cost of sales	270.9			273.9			627.9			622.5
Other operation and maintenance	366.6			324.4			702.2			651.0
Depreciation and amortization	86.9			82.7			172.2			164.8
Property and revenue taxes	27.3			28.3			54.5			56.7
Total operating expenses	751.7			709.3			1,556.8			1,495.0
Operating income	104.5			146.1			240.9			332.4
Other income, net	15.3			1.1			11.1			4.3
Interest expense	29.2			29.1			58.9			58.7
Other expense	(13.9		)	(28.0		)	(47.8		)	(54.4		)
Income before income taxes	90.6			118.1			193.1			278.0
Income tax (benefit) expense	(2.5		)	42.5			(6.1		)	100.3
Net income	93.1			75.6			199.2			177.7
Preferred stock dividend requirements	0.3			0.3			0.6			0.6
Net income attributed to common shareholder	$	92.8		$	75.3		$	198.6		$	177.1

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.

06/30/2018 Form 10-Q 3 Wisconsin Electric Power Company

WISCONSIN ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts)	June 30, 2018		December 31, 2017
Assets
Current assets
Cash and cash equivalents	$	1.1	$	12.3
Accounts receivable and unbilled revenues, net of reserves of $39.6 and $39.5, respectively	456.0		513.8
Accounts receivable from related parties	114.6		109.1
Materials, supplies, and inventories	236.7		250.7
Prepayments	120.8		144.3
Other	12.1		9.4
Current assets	941.3		1,039.6
Long-term assets
Property, plant, and equipment, net of accumulated depreciation of $3,377.9 and $3,741.8, respectively	9,378.7		10,007.7
Regulatory assets	2,879.4		1,984.9
Other	111.1		89.4
Long-term assets	12,369.2		12,082.0
Total assets	$	13,310.5	$	13,121.6
Liabilities and Equity
Current liabilities
Short-term debt	$	341.8	$	210.9
Current portion of long-term debt	—		250.0
Current portion of capital lease obligations	46.4		42.5
Accounts payable	237.1		329.3
Accounts payable to related parties	186.4		131.5
Accrued payroll and benefits	44.9		53.4
Accrued taxes	73.8		58.2
Other	98.0		111.8
Current liabilities	1,028.4		1,187.6
Long-term liabilities
Long-term debt	2,413.4		2,412.3
Capital lease obligations	2,819.3		2,823.8
Deferred income taxes	1,190.4		1,155.5
Regulatory liabilities	1,893.6		1,708.0
Pension and OPEB obligations	157.7		143.2
Other	286.3		276.9
Long-term liabilities	8,760.7		8,519.7
Commitments and contingencies (Note 16)
Common shareholder's equity
Common stock – $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding	332.9		332.9
Additional paid in capital	831.2		802.7
Retained earnings	2,326.9		2,248.3
Common shareholder's equity	3,491.0		3,383.9
Preferred stock	30.4		30.4
Total liabilities and equity	$	13,310.5	$	13,121.6

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.

06/30/2018 Form 10-Q 4 Wisconsin Electric Power Company

WISCONSIN ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Six Months Ended
	June 30
(in millions)	2018			2017
Operating Activities
Net income	$	199.2		$	177.7
Reconciliation to cash provided by operating activities
Depreciation and amortization	172.2			164.8
Deferred income taxes and investment tax credits, net	(39.5		)	64.1
Contributions and payments related to pension and OPEB plans	(3.8		)	(5.6		)
Change in –
Accounts receivable and unbilled revenues	57.9			26.7
Materials, supplies, and inventories	14.0			(7.2		)
Other current assets	28.4			10.1
Accounts payable	(36.2		)	(8.1		)
Accrued taxes	19.0			(24.4		)
Other current liabilities	(18.1		)	(24.2		)
Other, net	138.5			(14.0		)
Net cash provided by operating activities	531.6			359.9
Investing Activities
Capital expenditures	(287.0		)	(246.9		)
Proceeds from the sale of assets	0.6			22.0
Payments for assets transferred from affiliates	(50.1		)	—
Short-term notes receivable from related parties, net	—			(3.1		)
Other, net	5.4			2.3
Net cash used in investing activities	(331.1		)	(225.7		)
Financing Activities
Change in short-term debt	130.9			(84.0		)
Repayment of subsidiary note to parent	—			(18.5		)
Retirement of long-term debt	(250.0		)	—
Equity contribution from parent	28.0			75.0
Payment of dividends to parent	(120.0		)	(120.0		)
Payment of preferred stock dividends	(0.6		)	(0.6		)
Other	—			0.1
Net cash used in financing activities	(211.7		)	(148.0		)
Net change in cash and cash equivalents	(11.2		)	(13.8		)
Cash and cash equivalents at beginning of period	12.3			15.4
Cash and cash equivalents at end of period	$	1.1		$	1.6

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.

06/30/2018 Form 10-Q 5 Wisconsin Electric Power Company

WISCONSIN ELECTRIC POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

June 30, 2018

NOTE 1—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 and six months ended June 30, 2018, are not necessarily indicative of expected results for 2018 due to seasonal variations and other factors.

In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results.

NOTE 2—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.

NOTE 3—OPERATING REVENUES

Adoption of ASU 2014-09, Revenues from Contracts with Customers

On January 1, 2018, we adopted ASU 2014-09, Revenues from Contracts with Customers, and the related amendments. In accordance with the guidance, we recognize revenues when control of the promised goods or services is transferred to our customers in an amount that reflects the consideration we expect to be entitled to receive in exchange for those goods or services. These revenues include unbilled revenues, which are estimated using the amount of energy delivered to our customers but not billed until after the end of the period.

We adopted this standard using the modified retrospective method. Results for reporting periods beginning after January 1, 2018, are presented under the new standard. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Adoption of the standard did not result in an adjustment to our opening retained earnings balance as of January 1, 2018, and we do not expect the adoption of the standard to have a material impact on our net income in future periods.

We adopted the following practical expedients and optional exemptions for the implementation of this standard:

• We elected to exclude from the transaction price any amounts collected from customers for all sales taxes and other similar taxes.

• When applicable, we elected to apply the standard to a portfolio of contracts with similar characteristics, primarily our tariff-based contracts, as we reasonably expect that the effects on the financial statements of applying this guidance to the portfolio would not differ materially from applying this guidance to the individual contracts.

• We elected to recognize revenue in the amount we have the right to invoice for performance obligations satisfied over time when the consideration received from a customer corresponds directly with the value provided to the customer during the same period.

06/30/2018 Form 10-Q 6 Wisconsin Electric Power Company

• We elected to not disclose the remaining performance obligations of a contract that has an original expected duration of one year or less.

• We elected to apply this standard only to contracts that are not completed as of the date of initial application.

Disaggregation of Operating Revenues

The following tables present our operating revenues disaggregated by revenue source. We only have revenues associated with our utility segment. We do not have any revenues associated with our other segment. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For our utility segment, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations have different expectations of service, energy and demand requirements, and are impacted by regulatory activities within their jurisdictions.

Comparable amounts have not been presented for the three and six months ended June 30, 2017, due to our adoption of this standard under the modified retrospective method.

	Wisconsin Electric Power Company Consolidated
(in millions)	Three Months Ended June 30, 2018		Six Months Ended June 30, 2018
Electric utility	$	784.6	$	1,564.2
Natural gas utility	68.6		229.4
Total revenues from contracts with customers	853.2		1,793.6
Other operating revenues	3.0		4.1
Total operating revenues	$	856.2	$	1,797.7

Revenues from Contracts with Customers

Electric Utility Operating Revenues

The following table disaggregates electric utility operating revenues into customer class:

	Electric Utility Operating Revenues
(in millions)	Three Months Ended June 30, 2018		Six Months Ended June 30, 2018
Residential	$	295.0	$	576.4
Small commercial and industrial	260.6		498.3
Large commercial and industrial	172.4		321.3
Other	4.9		10.3
Total retail revenues	732.9		1,406.3
Wholesale	28.9		57.4
Resale	17.1		80.8
Steam	4.6		14.3
Other utility revenues	1.1		5.4
Total electric utility operating revenues	$	784.6	$	1,564.2

Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. The rates, charges, terms, and conditions of service for sales to these customers are included in tariffs that have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month.

06/30/2018 Form 10-Q 7 Wisconsin Electric Power Company

Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have us provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. The rates, charges, terms and conditions of service for sales to wholesale customers are included in tariffs that have been approved by the FERC. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric operations and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis.

We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales and net sales in a single hour are recorded as resale revenues. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets.

For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days. For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility’s costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual current year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services.

Natural Gas Utility Operating Revenues

The following table disaggregates natural gas utility operating revenues into customer class:

	Natural Gas Utility Operations
(in millions)	Three Months Ended June 30, 2018		Six Months Ended June 30, 2018
Residential	$	40.7	$	155.4
Commercial and industrial	18.2		73.8
Total retail revenues	58.9		229.2
Transport	3.1		7.5
Other utility revenues *	6.6		(7.3		)
Total natural gas utility operating revenues	$	68.6	$	229.4

* Includes amounts collected from (refunded to) customers for purchased gas adjustment costs.

We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under our tariffs. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In certain of our service territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer.

06/30/2018 Form 10-Q 8 Wisconsin Electric Power Company

The transaction price of the performance obligations is valued using rates in our tariffs, which have been approved by the PSCW. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month.

Consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days.

Other Operating Revenues

Other operating revenues consist primarily of the following:

(in millions)	Three Months Ended June 30, 2018			Six Months Ended June 30, 2018
Late payment charges	$	2.1		$	4.9
Leases	1.4			2.2
Alternative revenues *	(0.5		)	(3.0		)
Total other operating revenues	$	3.0		$	4.1

* 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 record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers.

Our only alternative revenue program relates to the wholesale electric service that we provide to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.

NOTE 4—PROPERTY, PLANT, AND EQUIPMENT

Utility Segment Plant to be Retired

We have evaluated future plans for our older and less efficient fossil fuel generating units and have either retired or announced the retirement of the plants identified below. In addition, a severance liability was recorded in other current liabilities on our balance sheets related to these plant retirements.

(in millions)
Severance liability at December 31, 2017	$	25.8
Severance payments	(8.7		)
Other	(3.0		)
Total severance liability at June 30, 2018	$	14.1

Pleasant Prairie Power Plant

The Pleasant Prairie power plant was retired effective April 10, 2018. The carrying value of this plant was $667.7 million at June 30, 2018. This amount included the net book value of $774.2 million, which was reclassified as a regulatory asset on our balance sheet in the second quarter as a result of the retirement of the plant. In addition, a $106.5 million cost of removal reserve related to the Pleasant Prairie power plant was recorded as a regulatory liability at June 30, 2018. We continue to amortize this regulatory asset on

06/30/2018 Form 10-Q 9 Wisconsin Electric Power Company

a straight-line basis using the composite depreciation rates approved by the PSCW before this plant was retired. Amortization is included in depreciation and amortization in the income statement. The physical dismantlement of the plant will not occur immediately. It may take several years to finalize long-term plans for the site. See Note 16, Commitments and Contingencies, for more information.

Presque Isle Power Plant

In October 2017, the MPSC approved UMERC’s application to construct and operate approximately 180 MW of natural gas-fired generation in the Upper Peninsula of Michigan. The new units are expected to begin commercial operation during the second quarter of 2019. Upon receiving the MPSC's approval, retirement of the PIPP generating units became probable. In connection with MISO's April 2018 approval of the retirement of the plant, the PIPP units will be retired on or before May 31, 2019. The carrying value of the PIPP units was $189.7 million at June 30, 2018. This amount included the net book value of $199.8 million, which was classified as plant to be retired within property, plant, and equipment on our balance sheet. In addition, a $10.1 million cost of removal reserve related to the PIPP units was recorded as a regulatory liability at June 30, 2018. These units are included in rate base, and we continue to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW. See Note 16, Commitments and Contingencies, for more information.

NOTE 5—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.

NOTE 6—SHORT-TERM DEBT AND LINES OF CREDIT

The following table shows our short-term borrowings and their corresponding weighted-average interest rates:

(in millions, except percentages)	June 30, 2018			December 31, 2017
Commercial paper
Amount outstanding	$	341.8		$	210.9
Weighted-average interest rate on amounts outstanding	2.35		%	1.81		%

Our average amount of commercial paper borrowings based on daily outstanding balances during the six months ended June 30, 2018, was $79.2 million with a weighted-average interest rate during the period of 2.06%.

The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including available capacity under this facility:

(in millions)	Maturity	June 30, 2018
Revolving credit facility	October 2022	$	500.0
Less:
Letters of credit issued inside credit facility		$	1.2
Commercial paper outstanding		341.8
Available capacity under existing agreement		$	157.0

NOTE 7—LONG-TERM DEBT

In July 2018, we redeemed all $80.0 million outstanding of our series of tax-exempt pollution control refunding bonds. Since August 2009, the bonds were outstanding, but were not reported in our long-term debt because they were held by us.

06/30/2018 Form 10-Q 10 Wisconsin Electric Power Company

In June 2018, our $250.0 million of 1.70% Debentures matured, and the outstanding principal was paid with proceeds received from issuing commercial paper.

NOTE 8—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:

(in millions)	June 30, 2018		December 31, 2017
Materials and supplies	$	137.2	$	140.7
Fossil fuel	75.9		74.8
Natural gas in storage	23.6		35.2
Total	$	236.7	$	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.

NOTE 9—INCOME TAXES

The effective tax rates of (2.8)% and (3.2)% for the three and six months ended June 30, 2018, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to the flow through of tax repairs in connection with the Wisconsin rate settlement and the impact of the Tax Legislation, partially offset by state income taxes. The Tax Legislation, signed into law in December 2017, required us to remeasure our deferred income taxes and begin to amortize the resulting excess deferred income taxes beginning in 2018 in accordance with normalization requirements. See Note 18, Regulatory Environment, for more information on the Tax Legislation and the Wisconsin rate settlement.

On December 22, 2017, the SEC staff issued guidance in Staff Accounting Bulletin 118 (SAB 118), Income Tax Accounting Implications of the Tax Legislation, which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, certain amounts related to bonus depreciation and future tax benefit utilization recorded in the financial statements as a result of the Tax Legislation are to be considered "provisional" as discussed in SAB 118 and subject to revision. We are awaiting additional guidance from industry and income tax authorities in order to finalize our accounting.

NOTE 10—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.

06/30/2018 Form 10-Q 11 Wisconsin Electric Power Company

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:

	June 30, 2018
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	1.5	$	—	$	—	$	1.5
Petroleum products contracts	0.3		—		—		0.3
FTRs	—		—		8.7		8.7
Coal contracts	—		0.5		—		0.5
Total derivative assets	$	1.8	$	0.5	$	8.7	$	11.0
Derivative liabilities
Natural gas contracts	$	0.1	$	—	$	—	$	0.1

	December 31, 2017
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	0.5	$	0.1	$	—	$	0.6
Petroleum products contracts	0.9		—		—		0.9
FTRs	—		—		2.4		2.4
Coal contracts	—		0.7		—		0.7
Total derivative assets	$	1.4	$	0.8	$	2.4	$	4.6
Derivative liabilities
Natural gas contracts	$	2.0	$	0.1	$	—	$	2.1
Coal contracts	—		0.3		—		0.3
Total derivative liabilities	$	2.0	$	0.4	$	—	$	2.4

The derivative assets and liabilities listed in the tables above include options, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy Markets.

The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy:

	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2018			2017			2018			2017
Balance at the beginning of the period	$	0.8		$	1.1		$	2.4		$	3.1
Purchases	9.4			6.9			9.4			6.9
Settlements	(1.5		)	(2.0		)	(3.1		)	(4.0		)
Balance at the end of the period	$	8.7		$	6.0		$	8.7		$	6.0

06/30/2018 Form 10-Q 12 Wisconsin Electric Power Company

Fair Value of Financial Instruments

The following table shows the financial instruments included on our balance sheets that are not recorded at fair value:

	June 30, 2018				December 31, 2017
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock	$	30.4	$	28.7	$	30.4	$	30.5
Long-term debt, including current portion	2,413.4		2,603.4		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.

NOTE 11—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:

	June 30, 2018				December 31, 2017
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	1.5	$	—	$	0.6	$	1.9
Petroleum products contracts	0.3		—		0.9		—
FTRs	8.7		—		2.4		—
Coal contracts	0.5		—		0.6		0.1
Total other current *	$	11.0	$	—	$	4.5	$	2.0
Other long-term
Natural gas contracts	$	—	$	0.1	$	—	$	0.2
Coal contracts	—		—		0.1		0.2
Total other long-term *	—		0.1		0.1		0.4
Total	$	11.0	$	0.1	$	4.6	$	2.4

* On our balance sheets, we classify derivative assets and liabilities as other current or other long-term based on the maturities of the underlying contracts.

06/30/2018 Form 10-Q 13 Wisconsin Electric Power Company

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 June 30, 2018				Three Months Ended June 30, 2017
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	12.0 Dth	$	(0.6	)	5.0 Dth	$	0.2
Petroleum products contracts	1.1 gallons	0.2			4.9 gallons	(0.4		)
FTRs	4.8 MWh	0.9			7.3 MWh	2.0
Total		$	0.5			$	1.8

	Six Months Ended June 30, 2018				Six Months Ended June 30, 2017
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	23.7 Dth	$	(2.4	)	13.2 Dth	$	0.7
Petroleum products contracts	2.5 gallons	0.6			9.8 gallons	(0.9		)
FTRs	10.6 MWh	1.7			14.3 MWh	4.5
Total		$	(0.1	)		$	4.3

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At June 30, 2018 and December 31, 2017, we had posted cash collateral of $1.0 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:

	June 30, 2018						December 31, 2017
(in millions)	Derivative Assets			Derivative Liabilities			Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	11.0		$	0.1		$	4.6		$	2.4
Gross amount not offset on the balance sheet	(0.1		)	(0.1		)	(1.3		)	(2.0		)	*
Net amount	$	10.9		$	—		$	3.3		$	0.4

* Includes cash collateral posted of $0.7 million.

NOTE 12—EMPLOYEE BENEFITS

The following tables show the components of net periodic pension and OPEB costs for our benefit plans:

	Pension Costs
	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2018			2017			2018			2017
Service cost	$	3.3		$	3.1		$	6.6		$	6.1
Interest cost	10.5			11.6			21.1			23.5
Expected return on plan assets	(18.6		)	(19.1		)	(37.6		)	(38.3		)
Loss on plan settlement	—			2.8			—			2.8
Amortization of prior service cost	0.2			0.3			0.4			0.6
Amortization of net actuarial loss	9.6			8.9			19.0			17.7
Net periodic benefit cost	$	5.0		$	7.6		$	9.5		$	12.4

06/30/2018 Form 10-Q 14 Wisconsin Electric Power Company

	OPEB Costs
	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2018			2017			2018			2017
Service cost	$	1.7		$	1.5		$	3.5		$	3.4
Interest cost	2.7			3.1			5.5			6.2
Expected return on plan assets	(3.9		)	(3.6		)	(7.8		)	(7.2		)
Amortization of prior service credit	(0.5		)	(0.3		)	(1.1		)	(0.6		)
Amortization of net actuarial gain	—			(0.3		)	—			—
Net periodic benefit cost	$	—		$	0.4		$	0.1		$	1.8

During the six months ended June 30, 2018, we made contributions and payments of $2.9 million related to our pension plans and $0.9 million related to our OPEB plans. We expect to make contributions and payments of $1.2 million related to our pension plans and $3.5 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 thethree and six months ended June 30,2018and2017, we have presented the service cost component of our retirement benefit plans in other operation and maintenance on the income statements, while presenting the non-service components in other income, net.

The following table shows the non-service (credit) cost components of net benefit costs:

	Three Months Ended June 30					Six Months Ended June 30
(in millions)	2018			2017		2018			2017
Non-service (credit) cost components	$	(1.2	)	$	3.3	$	(2.9	)	$	4.5

For the three and six months ended June 30, 2017, the non-service components of net benefit cost were reclassified from other operation and maintenance to other income, net, on our income statements.

Under ASU 2017-07, only the service cost component of net periodic benefit cost is eligible for capitalization to property, plant, and equipment. In prior periods, a portion of all net benefit cost components was capitalized to property, plant, and equipment. As required, this amendment was applied prospectively, beginning January 1, 2018. As a result of the application of accounting principles for rate regulated entities, the non-service cost components of the net benefit cost that are no longer eligible for capitalization under this standard, but are capitalized under the regulatory framework, are presented as regulatory assets or liabilities rather than property, plant, and equipment.

NOTE 13—SEGMENT INFORMATION

We use operating income to measure segment profitability and to allocate resources to our businesses. At June 30, 2018, we reported two segments, which are described below.

Our utility segment includes both our electric and natural gas utility operations. Our electric utility operations are engaged in the generation, distribution, and sale of electricity to customers in southeastern Wisconsin (including metropolitan Milwaukee), east central Wisconsin, and northern Wisconsin, and to one customer in the Upper Peninsula of Michigan. Our electric utility operations also include our steam operations, which produce, distribute, and sell steam to customers in metropolitan Milwaukee, Wisconsin. Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers and the transportation of customer-owned natural gas in our three service areas within southeastern, east central, and northern Wisconsin.

Our other segment 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.

06/30/2018 Form 10-Q 15 Wisconsin Electric Power Company

The following tables show summarized financial information for the three and six months ended June 30, 2018 and 2017, related to our reportable segments:

(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Three Months Ended June 30, 2018
Operating revenues	$	856.2	$	—	$	856.2
Other operation and maintenance	366.6		—		366.6
Depreciation and amortization	86.9		—		86.9
Operating income	104.5		—		104.5
Interest expense	29.2		—		29.2

(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Three Months Ended June 30, 2017
Operating revenues	$	855.4	$	—	$	855.4
Other operation and maintenance *	324.4		—		324.4
Depreciation and amortization	82.7		—		82.7
Operating income *	146.1		—		146.1
Interest expense	29.1		—		29.1

* Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 12, Employee Benefits, for more information on this new standard.

(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Six Months Ended June 30, 2018
Operating revenues	$	1,797.7	$	—	$	1,797.7
Other operation and maintenance	702.2		—		702.2
Depreciation and amortization	172.2		—		172.2
Operating income	240.9		—		240.9
Interest expense	58.9		—		58.9

(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Six Months Ended June 30, 2017
Operating revenues	$	1,827.4	$	—	$	1,827.4
Other operation and maintenance *	651.0		—		651.0
Depreciation and amortization	164.8		—		164.8
Operating income *	332.4		—		332.4
Interest expense	58.4		0.3		58.7

* Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 12, Employee Benefits, for more information on this new standard.

NOTE 14—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.

06/30/2018 Form 10-Q 16 Wisconsin Electric Power Company

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 $64.1 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 six months ended June 30, 2018 and 2017 were $9.4 million and $9.0 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

NOTE 15—RELATED PARTIES

We routinely enter into transactions with related parties, including WEC Energy Group, its other subsidiaries, ATC (a for-profit electric transmission company regulated by the FERC and certain state regulatory commissions), and other affiliated entities.

We provide and receive services, property, and other items of value to and from our parent, WEC Energy Group, and other subsidiaries of WEC Energy Group.

On January 1, 2017, based upon input we received from the PSCW, we transferred our $415.4 million investment in ATC, and the related receivable for distributions approved and recorded in December 2016 to another subsidiary of WEC Energy Group. In addition, during 2017 we transferred $186.8 million of related deferred income tax liabilities. These transactions were non-cash equity transfers recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss.

We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed by ATC. Services are billed to and from ATC under agreements approved by the PSCW, at each of our fully allocated costs.

Our balance sheets included the following receivables and payables related to transactions entered into with ATC:

(in millions)	June 30, 2018		December 31, 2017
Accounts receivable
Services provided to ATC	$	1.3	$	0.8
Accounts payable
Services received from ATC	19.3		22.2

06/30/2018 Form 10-Q 17 Wisconsin Electric Power Company

The following table shows activity associated with our related party transactions:

	Three Months Ended June 30				Six Months Ended June 30
(in millions)	2018		2017		2018		2017
Lease agreements
Lease payments to We Power (1)	$	95.1	$	106.7	$	187.3	$	211.1
Construction work in progress billed to We Power	5.0		8.9		8.8		25.2
Transactions with WBS (2)
Billings to WBS	2.8		60.5		8.7		117.0
Billings from WBS (3)	68.6		52.9		176.7		102.7
Transactions with WPS (2)
Billings to WPS	4.3		5.2		7.3		7.7
Billings from WPS	1.9		1.1		5.1		2.2
Transactions with WG
Natural gas purchases from WG	1.3		1.3		2.6		2.6
Billings to WG (2) (4)	13.2		16.1		27.1		31.9
Billings from WG (2)	5.0		5.8		9.7		11.3
Transactions with UMERC
Electric sales to UMERC	6.9		6.4		15.0		14.1
Billings to UMERC (2)	2.9		29.3		7.1		33.9
Transactions with Bluewater (5)
Storage service fees	4.6		—		5.9		—
Transactions with ATC
Charges to ATC for services and construction	2.7		2.4		5.7		5.2
Charges from ATC for network transmission services	58.1		60.4		116.1		120.7
Refund from ATC related to a FERC audit	15.4		—		15.4		—
Refund from ATC per FERC ROE order	—		—		—		19.4

⁽¹⁾  We make lease payments to We Power, another subsidiary of WEC Energy Group, for PWGS Units 1 and 2 and ERGS Units 1 and 2. Lease payments were reduced in 2018 as a result of tax savings related to Tax Legislation.

⁽²⁾  Includes amounts billed for services, pass through costs, and other items in accordance with approved affiliated interest agreements.

⁽³⁾  Includes $8.7 million and $57.6 million for the transfer of certain software assets from WBS during the three and six months ended June 30, 2018, respectively. There were no software assets transferred from WBS during 2017.

⁽⁴⁾  Includes $5.2 million for the transfer of certain software assets to WG during the three and six months ended June 30, 2018. There were no software assets transferred to WG during 2017.

⁽⁵⁾  WEC Energy Group's acquisition of Bluewater was completed June 30, 2017. See below for more information.

Upper Michigan Energy Resources Corporation

In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan. UMERC, a subsidiary of WEC Energy Group, became operational effective January 1, 2017, and we transferred customers and property, plant, and equipment as of that date. We transferred approximately 27,500 retail electric customers and 50 electric distribution-only customers to UMERC, along with approximately 2,500 miles of electric distribution lines. We also transferred related electric distribution substations in the Upper Peninsula of Michigan and all property rights for the distribution assets to UMERC. The book value of net assets, including the related deferred income tax liabilities, transferred to UMERC from us in 2017 was $61.1 million. This transaction was a non-cash equity transfer recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss. UMERC currently meets its market obligations through power purchase agreements with us and WPS.

06/30/2018 Form 10-Q 18 Wisconsin Electric Power Company

WEC Energy Group's Acquisition of Natural Gas Storage Facilities in Michigan

On June 30, 2017, WEC Energy Group completed the acquisition of Bluewater for $226.0 million. Bluewater owns natural gas storage facilities in Michigan that provide a portion of the current storage needs for our natural gas utility operations. In September 2017, we finalized a long-term service agreement with a wholly owned subsidiary of Bluewater to take the allocated storage, which was then approved by the PSCW in November 2017.

NOTE 16—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 June 30, 2018, were $9,760.2 million.

Environmental Matters

Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as sulfur dioxide, nitrogen oxide, fine particulates, mercury, and GHGs; water intake and discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.

Air Quality

8-Hour Ozone National Ambient Air Quality Standards

After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, which lowered the limit for ground-level ozone, creating a more stringent standard than the 2008 National Ambient Air Quality Standards. The EPA issued final nonattainment area designations on May 1, 2018. The following counties within our service territory were designated as partial nonattainment: Kenosha, Manitowoc, Northern Milwaukee/Ozaukee, and Sheboygan shorelines. The state of Wisconsin will need to develop a state implementation plan to bring these areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020. We believe we are well positioned to meet the requirements associated with the ozone standard and do not expect to incur significant costs to comply.

Climate Change

In 2015, the EPA issued a final rule regulating GHG emissions from existing generating units, referred to as the Clean Power Plan, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In 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. 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. In April 2017, pursuant to motions made by the EPA, the D.C. Circuit Court of Appeals ordered the challenges to the CPP, as well as related performance standards for new, reconstructed, and modified fossil-fueled power plants, to be held in abeyance, which remains the case.

In March 2017, President Trump issued an executive order that, among other things, specifically directed the EPA to review the CPP and related GHG regulations for new, reconstructed, or modified fossil-fueled power plants. 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. The EPA is expected to issue a proposed CPP replacement rule, or decide to rescind the CPP without replacing it, during the third quarter of 2018.

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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 CO₂ emissions by approximately 40% below 2005 levels by 2030. In addition, WEC Energy Group's new long-term goal is to reduce CO₂ emissions by approximately 80% below 2005 levels by 2050. We have implemented and continue to evaluate numerous options in order to meet WEC Energy Group's CO₂ reduction goals. Options considered include 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 (retired in April 2018) and PIPP. See Note 4, Property, Plant, and Equipment, for more information. In addition, we are evaluating our goals, and possible subsequent actions, with respect to national and international efforts to reduce future GHG emissions in order to limit future global temperature increases to less than two degrees Celsius.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act, which requires that the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts from both impingement (entrapping organisms on water intake screens) and entrainment (drawing organisms into water intake). The rule became effective in October 2014 and applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted under the rules governing new facilities.

Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities satisfy the IM BTA requirements. 

BTA determinations must also be made by the WDNR and MDEQ to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. We have received an EM BTA determination by the WDNR, with EPA concurrence, for our intake modification at Valley power plant. Due to the retirement of the Pleasant Prairie Power Plant and our plans to retire PIPP, we do not believe that BTA determinations for EM will be necessary for these units. Although we currently believe that existing technologies at PWGS and OC 5 through OC 8 satisfy the EM BTA requirements, BTA determinations to address EM reduction requirements will not be made until discharge permits are renewed for these units. Until that time, we cannot determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements for these units. During 2018, we will continue to evaluate options to address the EM BTA requirements for these units.

We have also provided information to the WDNR and the MDEQ about planned unit retirements. Based on discussions with the MDEQ, if we submit a signed certification stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2023), the EM BTA requirements will be waived. We expect to submit the letter identifying the last operating date for PIPP to the MDEQ 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 desulfurizationwastewater requirements. This rule applies to wastewater discharges from our power plant processes in Wisconsin and Michigan. In February 2018, the Center for Biological Diversity (CBD) filed suit in the U.S. District Court of Arizona challenging the Postponement

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Rule. In April 2018, the Utility Water Act Group filed a motion to dismiss the CBD suit for lack of subject matter jurisdiction. 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 retirement of PIPP as a result of WEC Energy Group's generation reshaping plan discussed in Climate Change above.

Land Quality

Manufactured Gas Plant Remediation

We have identified sites at which we or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. We are responsible for the environmental remediation of these sites. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure.

The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites.

We have established the following regulatory assets and reserves related to manufactured gas plant sites:

(in millions)	June 30, 2018		December 31, 2017
Regulatory assets	$	29.9	$	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.

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NOTE 17—SUPPLEMENTAL CASH FLOW INFORMATION

	Six Months Ended June 30
(in millions)	2018			2017
Cash (paid) for interest, net of amount capitalized	$	(57.8	)	$	(57.6	)
Cash (paid) for income taxes, net	(8.2		)	(63.4		)
Significant noncash transactions:
Accounts payable related to construction costs	4.5			13.0
Accounts payable related to assets transferred from affiliates	7.5			—
Accounts receivable related to assets transferred to affiliates	5.4			—
Transfer of investment in ATC to another subsidiary of WEC Energy Group (1) (2)	—			415.4
Transfer of net assets to UMERC (1)	—			60.0

⁽¹⁾ See Note 15, 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.

NOTE 18—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 May 2018, the PSCW issued an order regarding the benefits associated with the Tax Legislation. The PSCW order requires our electric utility operations to use 80% of the current 2018 and 2019 tax benefits to reduce our transmission regulatory asset. The remaining 20% is to be returned to electric customers in the form of bill credits. For our natural gas utility operations, the PSCW indicated that 100% of current 2018 and 2019 tax benefits should be returned to natural gas customers in the form of bill credits. Regarding the net tax benefit associated with the revaluation of deferred taxes, amortization required in accordance with normalization accounting is to be used to reduce our transmission regulatory asset for our electric utility operations and is being deferred for our natural gas utility operations. The timing and method of returning the remaining net tax benefit associated with the revaluation of deferred taxes for our electric and natural gas utility operations was not addressed and will be determined in a future rate proceeding. During the six months ended June 30, 2018, we reduced our transmission regulatory asset by $33.8 million as a result of the PSCW order.

We currently serve one retail electric customer in Michigan, and have reached a settlement with that customer. That settlement was approved by the MPSC in May 2018 and addresses all base rate impacts of the Tax Legislation, which will be returned to the customer through bill credits.

2018 and 2019 Rates

During April 2017, we, along with WG and WPS, filed an application with the PSCW for approval of a settlement agreement we made with several of our commercial and industrial customers regarding 2018 and 2019 base rates. In September 2017, the PSCW issued an order that approved the settlement agreement, which will freeze base rates through 2019 for our electric, natural gas, and steam customers. Based on the PSCW order, our authorized ROE remains at 10.2%, and our current capital cost structure will remain unchanged through 2019. Various intervenors had filed requests for rehearing, all of which have been denied.

In addition to freezing base rates, the settlement agreement extends and expands the electric real-time market pricing program options for large commercial and industrial customers and mitigates the continued growth of certain escrowed costs during the base rate freeze period by accelerating the recognition of certain tax benefits. We will flow through the tax benefit of our repair-related deferred tax liabilities in 2018 and 2019, to maintain certain regulatory asset balances at their December 31, 2017 levels. While we would typically follow the normalization accounting method and utilize the tax benefits of the deferred tax liabilities in rate making as an offset to rate base, benefiting customers over time, the federal tax code does allow for passing these tax repair-related benefits

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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.

NOTE 19—NEW ACCOUNTING PRONOUNCEMENTS

Leases

In February 2016, the FASB issued ASU 2016-02, Leases. This ASU was subsequently amended by ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842, ASU 2018-10, Codification Improvements to Topic 842, Leases, and ASU 2018-11, Targeted Improvements. The main provision of ASU 2016-02 is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP. In addition, this ASU expands the required quantitative and qualitative disclosures related to lease agreements. This guidance is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. This guidance must be adopted using a modified retrospective approach and provides for a number of optional transition practical expedients. We expect to apply the package of practical expedients allowed by this ASU which, among other things, allows the carryforward of prior conclusions related to lease identification and classification. We have not yet determined whether we will elect any other practical expedients upon transition. 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.

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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CORPORATE DEVELOPMENTS

The following discussion should be read in conjunction with the accompanying financial statements and related notes and our Annual Report on Form 10-K for the year ended December 31, 2017.

Introduction

We are a wholly owned subsidiary of WEC Energy Group, and derive revenues primarily from the distribution and sale of electricity and natural gas to retail customers in Wisconsin. We have combined common functions with WG and operate under the trade name of "We Energies." We conduct our business primarily through our utility reportable segment. See Note 13, Segment Information, for more information on our reportable business segments.

In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space. See Note 2, Disposition, for more information.

Corporate Strategy

Our goal is to continue to build and sustain long-term value for customers and shareholders by focusing on the fundamentals of our business: reliability; operating efficiency; financial discipline; customer care; and safety.

Reshaping Our Generation Fleet

WEC Energy Group has developed and is executing a plan to reshape its generation portfolio. This plan will balance reliability and customer cost with environmental stewardship. Taken as a whole, this plan should reduce costs to customers, preserve fuel diversity, and lower carbon emissions. Generation reshaping includes retiring older fossil fuel generation units, building state-of-the-art natural gas generation, and investing in cost-effective zero-carbon generation with a goal of reducing CO₂ emissions by approximately 40% below 2005 levels by 2030. In addition, WEC Energy Group set a new long-term goal of reducing CO₂ emissions by approximately 80% below 2005 levels by 2050. WEC Energy Group expects to retire approximately 1,800 MW of coal generation by 2020 across its electric utilities, and add additional natural gas-fired generating units and renewable generation, including utility-scale solar projects. Our 1,190 MW Pleasant Prairie power plant was retired in April 2018. The physical dismantlement of the Pleasant Prairie power plant will not occur immediately. It may take several years to finalize long-term plans for the site. See Note 4, Property, Plant, and Equipment, for information related to the Pleasant Prairie power plant retirement and the planned retirement of PIPP as part of WEC Energy Group's plan.

Reliability

We have made significant reliability-related investments in recent years, and plan to continue strengthening and modernizing our generation fleet and distribution networks to further improve reliability. Our investments, coupled with our commitment to operating efficiency and customer care, resulted in We Energies being recognized by PA Consulting Group, an independent consulting firm, as the most reliable utility in the United States in 2017 and, for the seventh year in a row, as the most reliable utility in the Midwest.

Operating Efficiency

We continually look for ways to optimize the operating efficiency of our company. For example, we are making progress on our Advanced Metering Infrastructure program, replacing aging meter-reading equipment on both our network and customer property. An integrated system of smart meters, communication networks, and data management programs enables two-way communication between us and our customers. This program reduces the manual effort for disconnects and reconnects and enhances outage management capabilities.

WEC Energy Group continues to focus on integrating and improving business processes and consolidating its IT infrastructure across all of its companies. We expect these efforts to continue to drive operational efficiency and to put us in position to effectively support plans for future growth.

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Financial Discipline

A strong adherence to financial discipline is essential to earning our authorized ROE and maintaining a strong balance sheet, stable cash flows, and quality credit ratings.

We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plants, and equipment, that are no longer performing as intended, or have an unacceptable risk profile. See Note 2, Disposition, for information on the sale of Bostco's remaining real estate holdings.

Exceptional Customer Care

Our approach is driven by an intense focus on delivering exceptional customer care every day. We strive to provide the best value for our customers by embracing constructive change, demonstrating personal responsibility for results, leveraging our capabilities and expertise, and using creative solutions to meet or exceed our customers’ expectations.

One example of how we obtain feedback from our customers is through our "We Care" calls, where our employees contact customers after a completed service call. Customer satisfaction is a priority, and making "We Care" calls is one of the main methods we use to gauge our performance to improve customer satisfaction.

Safety

We have a long-standing commitment to both workplace and public safety, and under our "Target Zero" mission, we have an ultimate goal of zero incidents, accidents, and injuries. We also set goals around injury-prevention activities that raise awareness and facilitate conversations about employee safety. WEC Energy Group's corporate safety program provides a forum for addressing employee concerns, training employees and contractors on current safety standards, and recognizing those who demonstrate a safety focus.

RESULTS OF OPERATIONS

THREE MONTHS ENDED JUNE 30, 2018

Consolidated Earnings

The following table compares our consolidated results for the second quarter of 2018 with the second quarter of 2017, including favorable or better, "B", and unfavorable or worse, "W", variances:

	Three Months Ended June 30
(in millions)	2018			2017		B (W)			Change Related to Flow Through of Tax Repairs			Change Related to Tax Legislation			Remaining Change B (W)
Operating revenues	$	856.2		$	855.4	$	0.8		$	(20.9	)	$	15.4		$	6.3
Cost of sales	270.9			273.9		3.0			—			—			3.0
Other operation and maintenance	366.6			324.4		(42.2		)	(10.0		)	(33.8		)	1.6
Depreciation and amortization	86.9			82.7		(4.2		)	—			—			(4.2		)
Property and revenue taxes	27.3			28.3		1.0			—			—			1.0
Operating income	104.5			146.1		(41.6		)	(30.9		)	(18.4		)	7.7
Other income, net	15.3			1.1		14.2			—			—			14.2
Interest expense	29.2			29.1		(0.1		)	—			—			(0.1		)
Income before income taxes	90.6			118.1		(27.5		)	(30.9		)	(18.4		)	21.8
Income tax (benefit) expense	(2.5		)	42.5		45.0			30.9			18.4			(4.3		)
Preferred stock dividend requirements	0.3			0.3		—			—			—			—
Net income attributed to common shareholder	$	92.8		$	75.3	$	17.5		$	—		$	—		$	17.5

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Our consolidated earnings for the three months ended June 30, 2018 were $92.8 million, compared to $75.3 million for the same quarter in 2017. The table above shows the income statement impact associated with the flow through of tax repairs beginning January 1, 2018 and the Tax Legislation signed into law in December 2017. As shown in the table above, the changes related to these items had no impact on net income attributed to common shareholder. See Note 9, Income Taxes, and Note 18, Regulatory Environment, for more information. See below for additional information on the $17.5 millionincrease in consolidated earnings.

Non-GAAP Financial Measures

The discussion below addresses the operating income contribution of our utility segment and includes financial information prepared in accordance with GAAP, as well as electric margins and natural gas margins, which are not measures of financial performance under GAAP. Electric margin (electric revenues less fuel and purchased power costs) and natural gas margin (natural gas revenues less cost of natural gas sold) are non-GAAP financial measures because they exclude other operation and maintenance expense, depreciation and amortization, and property and revenue taxes.

We believe that electric and natural gas margins provide a more meaningful basis for evaluating utility operations than operating revenues since the majority of prudently incurred fuel and purchased power costs, as well as prudently incurred natural gas costs, are passed through to customers in current rates. As a result, management uses electric and natural gas margins internally when assessing the operating performance of our utility segment as these measures exclude the majority of revenue fluctuations caused by changes in these expenses. Similarly, the presentation of electric and natural gas margins herein is intended to provide supplemental information for investors regarding our operating performance.

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of our utility segment operating performance. Our utility segment operating income for the three months ended June 30, 2018 and 2017 was $104.5 million and $146.1 million, respectively. The operating income discussion below includes a table that provides the calculation of electric margins and natural gas margins, along with a reconciliation to utility segment operating income.

Utility Segment Contribution to Operating Income

The following table compares our utility segment's contribution to operating income for the second quarter of 2018 with the same quarter of 2017, including favorable or better, "B", and unfavorable or worse, "W", variances.

	Three Months Ended June 30
(in millions)	2018		2017		B (W)
Electric revenues	$	787.3	$	793.6	$	(6.3	)
Fuel and purchased power	232.5		241.2		8.7
Total electric margins	554.8		552.4		2.4
Natural gas revenues	68.9		61.8		7.1
Cost of natural gas sold	38.4		32.7		(5.7		)
Total natural gas margins	30.5		29.1		1.4
Total electric and natural gas margins	585.3		581.5		3.8
Other operation and maintenance	366.6		324.4		(42.2		)
Depreciation and amortization	86.9		82.7		(4.2		)
Property and revenue taxes	27.3		28.3		1.0
Operating income	$	104.5	$	146.1	$	(41.6	)

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The following table shows a breakdown of other operation and maintenance:

	Three Months Ended June 30
(in millions)	2018		2017		B (W)
Operation and maintenance not included in line items below	$	108.0	$	106.6	$	(1.4	)
We Power (1)	125.9		127.1		1.2
Transmission (2)	66.1		67.5		1.4
Transmission expense related to the flow through of tax repairs (3)	10.0		—		(10.0		)
Transmission expense related to Tax Legislation (4)	33.8		—		(33.8		)
Regulatory amortizations and other pass through expenses (5)	22.8		23.2		0.4
Total other operation and maintenance	$	366.6	$	324.4	$	(42.2	)

⁽¹⁾  Represents costs associated with the We Power generation units, including operating and maintenance costs incurred, as well as the lease payments that are billed from We Power to us and then recovered in our rates. During the three months ended June 30, 2018 and 2017, $126.1 million and $139.2 million, respectively, of both lease and operating and maintenance costs were billed to or incurred by us, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

⁽²⁾  The PSCW has approved escrow accounting for our ATC and MISO network transmission expenses. As a result, we defer as a regulatory asset or liability the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the three months ended June 30, 2018 and 2017, $64.2 million and $79.6 million, respectively, of costs were billed to us by transmission providers.

⁽³⁾  Represents additional transmission expense associated with the flow through of tax benefits of our repair-related deferred tax liabilities starting in 2018, in accordance with a settlement agreement with the PSCW, to maintain certain regulatory asset balances at our December 31, 2017 levels. See Note 18, Regulatory Environment, for more information.

⁽⁴⁾  As a result of the May 2018 PSCW order requiring us to use 80% of our current 2018 tax benefit to reduce our transmission regulatory asset balance, our transmission expense increased during the second quarter of 2018 with a corresponding offset in income taxes. See Note 18, Regulatory Environment, for more information.

⁽⁵⁾  Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income.

The following tables provide information on delivered sales volumes by customer class and weather statistics:

	Three Months Ended June 30
	MWh (in thousands)
Electric Sales Volumes	2018	2017	B (W)
Customer Class
Residential	1,855.0	1,797.8	57.2
Small commercial and industrial	2,165.0	2,104.2	60.8
Large commercial and industrial	2,133.7	2,092.1	41.6
Other	32.0	33.6	(1.6	)
Total retail	6,185.7	6,027.7	158.0
Wholesale	394.2	397.2	(3.0	)
Resale	560.3	1,064.6	(504.3	)
Total sales in MWh	7,140.2	7,489.5	(349.3	)

	Three Months Ended June 30
	Therms (in millions)
Natural Gas Sales Volumes	2018	2017	B (W)
Customer Class
Residential	59.0	46.7	12.3
Commercial and industrial	35.0	27.8	7.2
Total retail	94.0	74.5	19.5
Transport	77.7	71.4	6.3
Total sales in therms	171.7	145.9	25.8

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	Three Months Ended June 30
	Degree Days
Weather *	2018	2017	B(W)
Heating (914 normal)	1,023	748	36.8	%
Cooling (166 normal)	217	203	6.9	%

* Normal degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin.

Electric Utility Margins

Electric utility margins increased $2.4 million during the second quarter of 2018, compared with the same quarter in 2017. The significant factors impacting the higher electric utility margins were:

• A $17.5 million increase in margins related to an increase in revenues, with a corresponding increase in transmission expense, as a result of the PSCW's order in May 2018 associated with the Tax Legislation. The PSCW order required us to apply 80% of our current 2018 tax benefit against our transmission regulatory asset balance. Prior to receiving the order, we recorded all of the expected benefits related to the Tax Legislation as if they would be returned to customers through refunds or bill credits, which resulted in a decrease in revenue in the first quarter of 2018. In the second quarter of 2018, we reversed a portion of this decrease as a result of the order. See Note 9, Income Taxes, and Note 18, Regulatory Environment, for more information.

• A $9.1 million increase related to higher retail sales volumes during the second quarter of 2018, primarily driven by favorable weather and higher overall use per retail customer. A colder than normal April and a warmer start to summer in 2018 contributed to the increase. As measured by heating degree days, the second quarter of 2018 was 36.8% colder than the same quarter in 2017. As measured by cooling degree days, the second quarter of 2018 was 6.9% warmer than the same quarter in 2017.

These increases in margins were partially offset by:

• A $20.9 million decrease in margins related to a settlement agreement with the PSCW to flow through the tax benefit of our repair-related deferred tax liabilities through reductions in certain regulatory assets, which are amortized to revenues, as discussed in Note 18, Regulatory Environment.

• A $2.8 million quarter-over-quarter negative impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, our electric margins are impacted by under or over-collections of certain fuel and purchased power costs that are less than a 2% price variance from the costs included in rates, and the remaining variance that exceeds the 2% variance is deferred.

Natural Gas Utility Margins

Natural gas utility margins increased $1.4 million during the second quarter of 2018, compared with the same quarter in 2017. The most significant factor impacting the higher natural gas utility margins was a $3.3 million increase related to higher sales volumes, primarily driven by a colder than normal April in 2018, higher use per commercial and industrial customer, and customer growth. This increase in margins was partially offset by $2.1 million of amounts expected to be returned to customers through refunds or bill credits, driven by the Tax Legislation. See Note 9, Income Taxes, and Note 18, Regulatory Environment, for more information.

Operating Income

Operating income at the utility segment decreased $41.6 million during the second quarter of 2018, compared with the same quarter in 2017. This decrease was driven by $45.4 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes), partially offset by the $3.8 million of higher margins discussed above.

06/30/2018 Form 10-Q 28 Wisconsin Electric Power Company

The significant factors impacting the increase in operating expenses during the second quarter of 2018, compared with the same quarter in 2017, were:

• A $33.8 million increase in transmission expense, with a corresponding offset in income taxes, associated with the May 2018 order from the PSCW related to the benefits associated with the Tax Legislation, as discussed in the table above.

• A $10.0 million increase in transmission expenses related to the flow through of tax repairs, as discussed in the table above.

• A $4.2 million increase in depreciation and amortization driven by an overall increase in utility plant in service and the implementation of an enterprise resource planning system in January 2018.

• A $3.4 million increase in benefit costs.

These increases in operating expenses were partially offset by a $2.9 million decrease in expenses at our plants, primarily related to the retirement of the Pleasant Prairie power plant in April 2018 and the winding down of operations in anticipation of the retirement of the PIPP. This resulted in lower maintenance and labor costs during the second quarter of 2018. See Note 4, Property, Plant, and Equipment, for more information on the plant retirements.

Consolidated Other Income, Net

	Three Months Ended June 30
(in millions)	2018		2017		B (W)
AFUDC – Equity	$	1.0	$	0.7	$	0.3
Other, net	14.3		0.4		13.9
Other income, net	$	15.3	$	1.1	$	14.2

Other income, net increased $14.2 million during the second quarter of 2018, compared with the same quarter in 2017. The increase was driven by the timing of the recognition of returns related to certain regulatory assets and the quarter-over-quarter increase in income from the non-service components of our net periodic pension and OPEB costs. See Note 12, Employee Benefits, for more information on our benefit costs.

Consolidated Interest Expense

	Three Months Ended June 30
(in millions)	2018		2017		B (W)
Interest expense	$	29.2	$	29.1	$	(0.1	)

Consolidated Income Tax (Benefit) Expense

	Three Months Ended June 30
	2018		2017		B (W)
Effective tax rate	(2.8	)%	36.0	%	38.8	%

Our effective tax rate decreased by 38.8% when compared with the second quarter of 2017, primarily due to a 24.8% effective tax rate benefit from the flow through of tax repairs in connection with the Wisconsin rate settlement. Also contributing to the decrease in the effective tax rate was the impact of the Tax Legislation. See Note 9, Income Taxes, and Note 18, Regulatory Environment, for more information.

06/30/2018 Form 10-Q 29 Wisconsin Electric Power Company

SIX MONTHS ENDED JUNE 30, 2018

Consolidated Earnings

The following table compares our consolidated results for the six months ended June 30, 2018 with the six months ended June 30, 2017, including favorable or better, "B", and unfavorable or worse, "W", variances:

	Six Months Ended June 30
(in millions)	2018			2017		B (W)			Change Related to Flow Through of Tax Repairs			Change Related to Tax Legislation			Remaining Change B (W)
Operating revenues	$	1,797.7		$	1,827.4	$	(29.7	)	$	(41.3	)	$	(13.0	)	$	24.6
Cost of sales	627.9			622.5		(5.4		)	—			—			(5.4		)
Other operation and maintenance	702.2			651.0		(51.2		)	(24.7		)	(33.8		)	7.3
Depreciation and amortization	172.2			164.8		(7.4		)	—			—			(7.4		)
Property and revenue taxes	54.5			56.7		2.2			—			—			2.2
Operating income	240.9			332.4		(91.5		)	(66.0		)	(46.8		)	21.3
Other income, net	11.1			4.3		6.8			—			—			6.8
Interest expense	58.9			58.7		(0.2		)	—			—			(0.2		)
Income before income taxes	193.1			278.0		(84.9		)	(66.0		)	(46.8		)	27.9
Income tax (benefit) expense	(6.1		)	100.3		106.4			66.0			46.8			(6.4		)
Preferred stock dividend requirements	0.6			0.6		—			—			—			—
Net income attributed to common shareholder	$	198.6		$	177.1	$	21.5		$	—		$	—		$	21.5

Our consolidated earnings for the six months ended June 30, 2018 were $198.6 million, compared to $177.1 million for the same period in 2017. The table above shows the income statement impact associated with the flow through of tax repairs beginning January 1, 2018 and the Tax Legislation signed into law in December 2017. As shown in the table above, the changes related to these items had no impact on net income attributed to common shareholder. See Note 9, Income Taxes, and Note 18, Regulatory Environment, for more information. See below for additional information on the $21.5 millionincrease in consolidated earnings.

Non-GAAP Financial Measures

The discussion below addresses the operating income contribution of our utility segment and includes financial information prepared in accordance with GAAP, as well as electric margins and natural gas margins, which are not measures of financial performance under GAAP. Electric margin (electric revenues less fuel and purchased power costs) and natural gas margin (natural gas revenues less cost of natural gas sold) are non-GAAP financial measures because they exclude other operation and maintenance expense, depreciation and amortization, and property and revenue taxes.

We believe that electric and natural gas margins provide a more meaningful basis for evaluating utility operations than operating revenues since the majority of prudently incurred fuel and purchased power costs, as well as prudently incurred natural gas costs, are passed through to customers in current rates. As a result, management uses electric and natural gas margins internally when assessing the operating performance of our utility segment as these measures exclude the majority of revenue fluctuations caused by changes in these expenses. Similarly, the presentation of electric and natural gas margins herein is intended to provide supplemental information for investors regarding our operating performance.

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of our utility segment operating performance. Our utility segment operating income for the six months ended June 30, 2018 and 2017, was $240.9 million and $332.4 million, respectively. The operating income discussion below includes a table that provides the calculation of electric margins and natural gas margins, along with a reconciliation to utility segment operating income.

06/30/2018 Form 10-Q 30 Wisconsin Electric Power Company

Utility Segment Contribution to Operating Income

The following table compares our utility segment's contribution to operating income for the six months ended June 30, 2018, with the same period in 2017, including favorable or better, "B", and unfavorable or worse, "W", variances.

	Six Months Ended June 30
(in millions)	2018		2017		B (W)
Electric revenues	$	1,567.6	$	1,615.4	$	(47.8	)
Fuel and purchased power	484.6		493.9		9.3
Total electric margins	1,083.0		1,121.5		(38.5		)
Natural gas revenues	230.1		212.0		18.1
Cost of natural gas sold	143.3		128.6		(14.7		)
Total natural gas margins	86.8		83.4		3.4
Total electric and natural gas margins	1,169.8		1,204.9		(35.1		)
Other operation and maintenance	702.2		651.0		(51.2		)
Depreciation and amortization	172.2		164.8		(7.4		)
Property and revenue taxes	54.5		56.7		2.2
Operating income	$	240.9	$	332.4	$	(91.5	)

The following table shows a breakdown of other operation and maintenance:

	Six Months Ended June 30
(in millions)	2018		2017		B (W)
Operation and maintenance not included in line items below	$	210.0	$	214.2	$	4.2
We Power (1)	253.1		254.7		1.6
Transmission (2)	132.2		134.5		2.3
Transmission expense related to the flow through of tax repairs (3)	24.7		—		(24.7		)
Transmission expense related to Tax Legislation (4)	33.8		—		(33.8		)
Regulatory amortizations and other pass through expenses (5)	48.4		47.6		(0.8		)
Total other operation and maintenance	$	702.2	$	651.0	$	(51.2	)

⁽¹⁾  Represents costs associated with the We Power generation units, including operating and maintenance costs incurred, as well as the lease payments that are billed from We Power to us and then recovered in our rates. During the six months ended June 30, 2018 and 2017, $236.7 million and $265.0 million, respectively, of both lease and operating and maintenance costs were billed to or incurred by us, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

⁽²⁾  The PSCW has approved escrow accounting for our ATC and MISO network transmission expenses. As a result, we defer as a regulatory asset or liability the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the six months ended June 30, 2018 and 2017, $120.5 million and $134.7 million, respectively, of costs were billed to us by transmission providers.

⁽³⁾  Represents additional transmission expense associated with the flow through of tax benefits of our repair-related deferred tax liabilities starting in 2018, in accordance with a settlement agreement with the PSCW, to maintain certain regulatory asset balances at our December 31, 2017 levels. See Note 18, Regulatory Environment, for more information.

⁽⁴⁾  As a result of the May 2018 PSCW order requiring us to use 80% of our current 2018 tax benefit to reduce our transmission regulatory asset balance, our transmission expense increased during the six months ended June 30, 2018, with a corresponding offset in income taxes. See Note 18, Regulatory Environment, for more information.

⁽⁵⁾  Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income.

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The following tables provide information on sales volumes by customer class and weather statistics:

	Six Months Ended June 30
	MWh (in thousands)
Electric Sales Volumes	2018	2017	B (W)
Customer Class
Residential	3,766.9	3,622.8	144.1
Small commercial and industrial	4,346.6	4,301.8	44.8
Large commercial and industrial	4,159.5	4,077.7	81.8
Other	69.6	72.2	(2.6	)
Total retail	12,342.6	12,074.5	268.1
Wholesale	820.1	844.3	(24.2	)
Resale	2,751.7	3,197.0	(445.3	)
Total sales in MWh	15,914.4	16,115.8	(201.4	)

	Six Months Ended June 30
	Therms (in millions)
Natural Gas Sales Volumes	2018	2017	B (W)
Customer Class
Residential	236.4	202.3	34.1
Commercial and industrial	131.1	113.5	17.6
Total retail	367.5	315.8	51.7
Transport	172.8	160.5	12.3
Total sales in therms	540.3	476.3	64.0

	Six Months Ended June 30
	Degree Days
Weather *	2018	2017	B(W)
Heating (4,169 normal)	4,248	3,597	18.1	%
Cooling (166 normal)	217	203	6.9	%

* Normal degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin.

Electric Utility Margins

Electric utility margins decreased $38.5 million during the six months ended June 30, 2018, compared with the same period in 2017. The significant factors impacting the lower electric utility margins were:

• A $41.3 million decrease in margins related to a settlement agreement with the PSCW to flow through the tax benefit of our repair-related deferred tax liabilities through reductions in certain regulatory assets, which are amortized to revenues, as discussed in Note 18, Regulatory Environment.

• A $7.8 million decrease in margins related to amounts expected to be refunded to customers through refunds, bill credits, or reductions in other regulatory assets, driven by the Tax Legislation. See Note 9, Income Taxes, and Note 18, Regulatory Environment, for more information.

• A $3.1 million decrease in wholesale margins driven by reduced capacity rates reflecting the Tax Legislation.

• A $2.5 million period-over-period negative impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, our electric margins are impacted by under or over-collections of certain fuel and purchased power costs that are less than a 2% price variance from the costs included in rates, and the remaining variance that exceeds the 2% variance is deferred.

06/30/2018 Form 10-Q 32 Wisconsin Electric Power Company

These decreases in margins were partially offset by an $18.7 million increase related to higher retail sales volumes during the six months ended June 30, 2018, primarily driven by favorable weather and higher overall use per retail customer. Cooler winter weather and a warmer start to summer in 2018 contributed to the increase. As measured by heating degree days, the six months ended June 30, 2018, were 18.1% colder than the same period in 2017. As measured by cooling degree days, the six months ended June 30, 2018, were 6.9% warmer than the same period in 2017.

Natural Gas Utility Margins

Natural gas utility margins increased $3.4 million during the six months ended June 30, 2018, compared with the same period in 2017. The most significant factor impacting the higher natural gas utility margins was an $8.5 million increase related to higher sales volumes, primarily driven by colder winter weather, higher use per commercial and industrial customer, and customer growth. This increase in margins was partially offset by $5.2 million of amounts expected to be returned to customers through refunds or bill credits, driven by the Tax Legislation. See Note 9, Income Taxes, and Note 18, Regulatory Environment, for more information.

Operating Income

Operating income at the utility segment decreased $91.5 million during the six months ended June 30, 2018, compared with the same period in 2017. The decrease was driven by $56.4 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes) and the $35.1 million net decrease in margins discussed above.

The significant factors impacting the increase in operating expenses during the six months ended June 30, 2018, compared with the same period in 2017, were:

• A $33.8 million increase in transmission expense, with a corresponding offset in income taxes, associated with the May 2018 order from the PSCW related to the benefits associated with the Tax Legislation, as discussed in the table above.

• A $24.7 million increase in transmission expense related to the flow through of tax repairs, as discussed in the table above.

• A $7.4 million increase in depreciation and amortization driven by an overall increase in utility plant in service and the implementation of an enterprise resource planning system in January 2018.

These increases in operating expenses were partially offset by:

• A $6.9 million decrease in expenses at our plants, primarily related to the retirement of the Pleasant Prairie power plant in April 2018 and the winding down of operations in anticipation of the retirement of the PIPP. This resulted in lower maintenance and labor costs during the six months ended June 30, 2018. See Note 4, Property, Plant, and Equipment, for more information on the plant retirements.

• A $3.1 million net decrease in transmission expenses, lease costs from We Power, and regulatory amortizations and other pass-through expenses included in the table above. The lower transmission expenses and We Power lease costs were driven by the Tax Legislation.

Consolidated Other Income, Net

	Six Months Ended June 30
(in millions)	2018		2017		B (W)
AFUDC – Equity	$	2.0	$	1.4	$	0.6
Other	9.1		2.9		6.2
Other income, net	$	11.1	$	4.3	$	6.8

Other income, net increased $6.8 million during the six months ended June 30, 2018, compared with the same period in 2017, driven by the period-over-period increase in income from the non-service components of our net periodic pension and OPEB costs. See Note 12, Employee Benefits, for more information on our benefit costs.

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Consolidated Interest Expense

	Six Months Ended June 30
(in millions)	2018		2017		B (W)
Interest expense	$	58.9	$	58.7	$	(0.2	)

Consolidated Income Tax (Benefit) Expense

	Six Months Ended June 30
	2018		2017		B (W)
Effective tax rate	(3.2	)%	36.1	%	39.3	%

Our effective tax rate decreased by 39.3% when compared with the six months ended June 30, 2017, primarily due to a 24.9% effective tax rate benefit from the flow through of tax repairs in connection with the Wisconsin rate settlement. Also contributing to the decrease in the effective tax rate was the impact of the Tax Legislation. See Note 9, Income Taxes, and Note 18, Regulatory Environment, for more information.

We expect our 2018 annual effective tax rate to be between (5)% and (4)%, which includes an estimated 27% effective tax rate benefit from the flow through of tax repairs.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

The following table summarizes our cash flows during the six months ended June 30:

(in millions)	2018			2017			Change in 2018 Over 2017
Cash provided by (used in):
Operating activities	$	531.6		$	359.9		$	171.7
Investing activities	(331.1		)	(225.7		)	(105.4		)
Financing activities	(211.7		)	(148.0		)	(63.7		)

Operating Activities

Net cash provided by operating activities increased $171.7 million during the six months ended June 30, 2018, compared with the same period in 2017, driven by:

• A $94.3 million increase in cash from lower payments for other operation and maintenance costs. During the six months ended June 30, 2018, our payments were lower for accounts payable to related parties as well as for plant maintenance and labor costs. In addition, our payments related to transmission and our lease payments to We Power decreased as a result of the Tax Legislation.

• A $55.2 million increase in cash related to a decrease in cash paid for income taxes during the six months ended June 30, 2018, compared with the same period in 2017. This increase in cash was primarily the result of the utilization of certain tax benefit carryforwards.

• A $33.1 million increase in cash related to higher overall collections from customers, primarily due to favorable weather during the six months endedJune 30, 2018, compared with the same period in 2017.

These increases in net cash provided by operating activities were partially offset by a $21.9 million decrease in cash resulting from higher payments during the six months ended June 30, 2018, compared with the same period in 2017, for natural gas we purchased at the end of 2017 and during the six months ended June 30, 2018, to meet the requirements of our customers during the colder winter weather. The average per-unit cost of natural gas increased 28.4% during the six months ended June 30, 2018, compared with the same period in 2017.

06/30/2018 Form 10-Q 34 Wisconsin Electric Power Company

Investing Activities

Net cash used in investing activities increased $105.4 million during the six months ended June 30, 2018, compared with the same period in 2017, driven by:

• A payment of $50.1 million to affiliates during the six months ended June 30, 2018, related to transfers of an enterprise resource planning system and other software. There were no similar transfers in 2017.

• A $40.1 million increase in cash paid for capital expenditures during the six months ended June 30, 2018, compared with the same period in 2017, which is discussed in more detail below.

• A $21.4 million decrease in the proceeds received from the sale of assets during the six months ended June 30, 2018, compared with the same period in 2017. See Note 2, Disposition, for more information.

Capital Expenditures

Capital expenditures for the six months ended June 30 were as follows:

(in millions)	2018		2017		Change in 2018 Over 2017
Capital expenditures	$	287.0	$	246.9	$	40.1

The increase in cash paid for capital expenditures during the six months ended June 30, 2018 was driven by upgrades of our natural gas and electric distribution systems, including main replacement projects, and various software projects.

See Capital Resources and Requirements – Capital Requirements – Significant Capital Projects for more information.

Financing Activities

Net cash used in financing activities increased $63.7 million during the six months ended June 30, 2018, compared with the same period in 2017, primarily driven by:

• A $250.0 million repayment of long-term debt during the six months ended June 30, 2018. A portion of this repayment was financed with a net increase in cash of $214.9 million from commercial paper, which resulted from $130.9 million of net borrowings during the six months ended June 30, 2018, compared with $84.0 million of net repayments during the same period in 2017. We did not repay any long-term debt during the same period in 2017.

• A $47.0 million decrease in equity contributions received from our parent during the six months ended June 30, 2018, compared with the same period in 2017.

These increases in net cash used in financing activities were partially offset by an $18.5 million repayment of our subsidiary's note to our parent during the six months ended June 30, 2017.

For more information on our financing activities, see Note 6, Short-Term Debt and Lines of Credit, and Note 7, Long-Term Debt.

Capital Resources and Requirements

Capital Resources

Liquidity

We anticipate meeting our capital requirements for our existing operations through internally generated funds and short-term borrowings, supplemented by the issuance of intermediate or long-term debt securities, depending on market conditions and other factors, and equity contributions from our parent.

We currently have access to the capital markets and have been able to generate funds internally and externally to meet our capital requirements. Our ability to attract the necessary financial capital at reasonable terms is critical to our overall strategic plan. We

06/30/2018 Form 10-Q 35 Wisconsin Electric Power Company

currently believe that we have adequate capacity to fund our operations for the foreseeable future through our existing borrowing arrangement, access to capital markets, and internally generated cash.

We maintain a bank back-up credit facility, which provides liquidity support for our obligations with respect to commercial paper and for general corporate purposes. We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. See Note 6, Short-Term Debt and Lines of Credit, for more information on our credit facility.

Working Capital

As of June 30, 2018, our current liabilities exceeded our current assets by $87.1 million. We do not expect this to have any impact on our liquidity since we believe we have adequate back-up lines of credit in place for our ongoing operations. We also believe that we can access the capital markets to finance our construction programs and to refinance current maturities of long-term debt.

Credit Rating Risk

We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. However, we have certain agreements in the form of commodity contracts and employee benefit plans that could require collateral or a termination payment in the event of a credit rating change to below BBB- at S&P Global Ratings and/or Baa3 at Moody's Investors Service. We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.

In addition, access to capital markets at a reasonable cost is determined in large part by credit quality. Any credit ratings downgrade could impact our ability to access capital markets.

Subject to other factors affecting the credit markets as a whole, we believe our current ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, these security ratings reflect the views of the rating agency only. An explanation of the significance of these ratings may be obtained from the rating agency. Such ratings are not a recommendation to buy, sell, or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency.

If we are unable to successfully take actions to manage the adverse impacts of the Tax Legislation, or if additional interpretations, regulations, amendments or technical corrections exacerbate the adverse impacts of the Tax Legislation, the legislation could result in credit rating agencies placing our credit ratings on negative outlook or downgrading our credit ratings. Any such actions by credit rating agencies may make it more difficult and costly for us to issue future debt securities and certain other types of financing and could increase borrowing costs under our credit facility.

Capital Requirements

Significant Capital Projects

We have several capital projects that will require significant capital expenditures over the next three years and beyond. All projected capital requirements are subject to periodic review and may vary significantly from estimates, depending on a number of factors. These factors include environmental requirements, regulatory restraints and requirements, impacts from the Tax Legislation, acquisition and development opportunities, market volatility, and economic trends. Our estimated capital expenditures for the next three years are as follows:

(in millions)
2018	$	598.5
2019	552.5
2020	807.5
Total	$	1,958.5

The majority of spending consists of upgrading our electric and natural gas distribution systems to enhance reliability. These upgrades include the advanced metering infrastructure (AMI) program. AMI is an integrated system of smart meters, communication networks and data management systems that enable two-way communication between utilities and customers.

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Additionally, as part of our commitment to invest in zero-carbon generation, we plan to invest in utility scale solar. Solar generation technology has greatly improved, has become more cost-effective, and it complements our summer demand curve.

Off-Balance Sheet Arrangements

We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including letters of credit that primarily support our commodity contracts. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see Note 6, Short-Term Debt and Lines of Credit, and Note 14, Variable Interest Entities.

Contractual Obligations

For additional information about our commitments, see Contractual Obligations in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Requirements in our 2017 Annual Report on Form 10-K.

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity, and capital resources. The following discussion should be read together with the information in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources in our 2017 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, industry restructuring, environmental matters, critical accounting policies and estimates, and other matters.

Environmental Matters

See Note 16, Commitments and Contingencies, for a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change.

Other Matters

Tax Cuts and Jobs Act of 2017

In December 2017, the Tax Legislation was signed into law. As a result, the PSCW issued a written order in May 2018 regarding how we should refund the tax savings from the Tax Legislation to our ratepayers in Wisconsin. In addition, in May 2018, the MPSC approved a settlement with our one retail electric customer in Michigan that addresses all base rate impacts of the Tax Legislation. We are also working with the FERC to modify our formula rate tariffs for the impacts of the Tax Legislation, and we expect to receive FERC approval for the modified tariffs in 2019. See Note 18, Regulatory Environment, for more information.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes related to market risk from the disclosures presented in our 2017 Annual Report on Form 10-K. In addition to the Form 10-K disclosures, see Note 10, Fair Value Measurements, and Note 11, Derivative Instruments, in this report for information concerning our market risk exposures.

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ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based upon such evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of such period, our disclosure controls and procedures are effective: (i) in recording, processing, summarizing, and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act; and (ii) to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the first quarter of 2018, WEC Energy Group completed an enterprise resource planning (ERP) system integration project to bring all of its subsidiaries, including us, onto a consolidated ERP system. Accordingly, we are modifying the design and documentation of certain internal control processes and procedures related to the integrated ERP system. We do not believe that the implementation of the ERP system will have an adverse effect on our internal control over financial reporting.

With the exception of the ERP system implementation described above, there were no changes in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the second quarter of 2018 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

06/30/2018 Form 10-Q 39 Wisconsin Electric Power Company

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The following should be read in conjunction with Item 3. Legal Proceedings in Part I of our 2017 Annual Report on Form 10-K. See Note 16, Commitments and Contingencies, and Note 18, Regulatory Environment, in this report for more information on material legal proceedings and matters related to us.

In addition to those legal proceedings discussed in Note 16, Commitments and Contingencies, Note 18, Regulatory Environment, and below, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these additional legal proceedings cannot be predicted with certainty, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material effect on our financial statements.

Presque Isle Power Plant Matter

In March 2018, the EPA issued a Finding of Violation to us regarding alleged violations of mercury emission limits for PIPP Units 5, 6, 8, and 9, as well as failure to conduct mercury tests on our low emitting electric utility generating units once every 12 months. We are cooperating with the EPA, and we do not expect this matter to have a material impact on our financial statements.

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors presented in our Annual Report on Form 10-K for the year ended December 31, 2017. See Item 1A. Risk Factors in Part I of our 2017 Annual Report on Form 10-K for a discussion of certain risk factors applicable to us.

06/30/2018 Form 10-Q 40 Wisconsin Electric Power Company

ITEM 6. EXHIBITS

Number	Exhibit
12	Statements re Computation of Ratios
	12.1	Ratio of Earnings to Fixed Charges
31	Rule 13a-14(a) / 15d-14(a) Certifications
	31.1	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Section 1350 Certifications
	32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101	Interactive Data File

06/30/2018 Form 10-Q 41 Wisconsin Electric Power Company

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		WISCONSIN ELECTRIC POWER COMPANY
		(Registrant)
		/s/ WILLIAM J. GUC
Date:	August 3, 2018	William J. Guc
		Vice President and Controller
		(Duly Authorized Officer and Chief Accounting Officer)

06/30/2018 Form 10-Q 42 Wisconsin Electric Power Company

EX-12.1

Exhibit 12.1

WISCONSIN ELECTRIC POWER COMPANY

STATEMENT OF COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES (Unaudited)	Six Months Ended June 30, 2018		Twelve Months Ended December 31
(in millions, except ratios)			2017		2016		2015		2014		2013
EARNINGS
Pre-tax income *	$	193.1	$	528.0	$	572.7	$	584.0	$	593.1	$	549.6
FIXED CHARGES
Interest expense	58.9		117.3		117.6		119.0		116.5		121.4
Capitalized interest	0.8		1.2		1.7		2.2		1.8		7.4
Estimated interest component of rentals	66.8		149.1		154.1		149.8		141.6		140.4
Total fixed charges as defined	126.5		267.6		273.4		271.0		259.9		269.2
Total earnings as defined	$	319.6	$	795.6	$	846.1	$	855.0	$	853.0	$	818.8
RATIO OF EARNINGS TO FIXED CHARGES	2.5x		3.0x		3.1x		3.2x		3.3x		3.0x

* Pre-tax income consists of income before income taxes less undistributed earnings of equity investees.

EX-31.1

Exhibit 31.1

Certification Pursuant to

Rule 13a-14(a) or 15d-14(a),

as Adopted Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002

I, Gale E. Klappa, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Wisconsin Electric Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an Annual Report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	August 3, 2018
	/s/ GALE E. KLAPPA
	Gale E. Klappa
	Chairman of the Board and Chief Executive Officer
	(Principal Executive Officer)

EX-31.2

Exhibit 31.2

Certification Pursuant to

Rule 13a-14(a) or 15d-14(a),

as Adopted Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002

I, Scott J. Lauber, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Wisconsin Electric Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an Annual Report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	August 3, 2018
	/s/ SCOTT J. LAUBER
	Scott J. Lauber
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)

EX-32.1

Exhibit 32.1

Certification Pursuant to

18 U.S.C. Section 1350,

As Adopted Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Wisconsin Electric Power Company (the "Company") on Form 10-Q for the quarter ended June 30, 2018, as filed with the Securities and Exchange Commission on August 3, 2018 (the "Report"), I, Gale E. Klappa, Chairman of the Board and Chief Executive Officer of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ GALE E. KLAPPA

Gale E. Klappa

Chairman of the Board and Chief Executive Officer

August 3, 2018

EX-32.2

Exhibit 32.2

Certification Pursuant to

18 U.S.C. Section 1350,

As Adopted Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Wisconsin Electric Power Company (the "Company") on Form 10-Q for the quarter ended June 30, 2018, as filed with the Securities and Exchange Commission on August 3, 2018 (the "Report"), I, Scott J. Lauber, Executive Vice President and Chief Financial Officer of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ SCOTT J. LAUBER

Scott J. Lauber

Executive Vice President and Chief Financial Officer

August 3, 2018

XML

DOCUMENT AND ENTITY INFORMATION	6 Months Ended
	Jun. 30, 2018 shares
Document Entity Information [Abstract]
Entity registrant name	WISCONSIN ELECTRIC POWER CO
Entity central index key	0000107815
Current fiscal year end date	--12-31
Entity filer category	Non-accelerated Filer
Document type	10-Q
Document period end date	Jun. 30, 2018
Document fiscal year focus	2018
Document fiscal period focus	Q2
Amendment flag	false
Entity common stock, shares outstanding	33,289,327

XML

CONDENSED CONSOLIDATED INCOME STATEMENTS - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Income Statement [Abstract]
Operating revenues	$ 856.2	$ 855.4	$ 1,797.7	$ 1,827.4
Operating expenses
Cost of sales	270.9	273.9	627.9	622.5
Other operation and maintenance	366.6	324.4	702.2	651.0
Depreciation and amortization	86.9	82.7	172.2	164.8
Property and revenue taxes	27.3	28.3	54.5	56.7
Total operating expenses	751.7	709.3	1,556.8	1,495.0
Operating income	104.5	146.1	240.9	332.4
Other income, net	15.3	1.1	11.1	4.3
Interest expense	29.2	29.1	58.9	58.7
Other expense	(13.9)	(28.0)	(47.8)	(54.4)
Income before income taxes	90.6	118.1	193.1	278.0
Income tax (benefit) expense	(2.5)	42.5	(6.1)	100.3
Net income	93.1	75.6	199.2	177.7
Preferred stock dividend requirements	0.3	0.3	0.6	0.6
Net income attributed to common shareholder	$ 92.8	$ 75.3	$ 198.6	$ 177.1

XML

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 1.1	$ 12.3
Accounts receivable and unbilled revenues, net of reserves of $39.6 and $39.5, respectively	456.0	513.8
Accounts receivable from related parties	114.6	109.1
Materials, supplies, and inventories	236.7	250.7
Prepayments	120.8	144.3
Other	12.1	9.4
Current assets	941.3	1,039.6
Long-term assets
Property, plant, and equipment, net of accumulated depreciation of $3,377.9 and $3,741.8, respectively	9,378.7	10,007.7
Regulatory assets	2,879.4	1,984.9
Other	111.1	89.4
Long-term assets	12,369.2	12,082.0
Total assets	13,310.5	13,121.6
Current liabilities
Short-term debt	341.8	210.9
Current portion of long-term debt	0.0	250.0
Current portion of capital lease obligations	46.4	42.5
Accounts payable	237.1	329.3
Accounts payable to related parties	186.4	131.5
Accrued payroll and benefits	44.9	53.4
Accrued taxes	73.8	58.2
Other	98.0	111.8
Current liabilities	1,028.4	1,187.6
Long-term liabilities
Long-term debt	2,413.4	2,412.3
Capital lease obligations	2,819.3	2,823.8
Deferred income taxes	1,190.4	1,155.5
Regulatory liabilities	1,893.6	1,708.0
Pension and OPEB obligations	157.7	143.2
Other	286.3	276.9
Long-term liabilities	8,760.7	8,519.7
Commitments and contingencies (Note 16)
Common shareholder's equity
Common stock – $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding	332.9	332.9
Additional paid in capital	831.2	802.7
Retained earnings	2,326.9	2,248.3
Common shareholder's equity	3,491.0	3,383.9
Preferred stock	30.4	30.4
Total liabilities and equity	$ 13,310.5	$ 13,121.6

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (PARENTHETICALS) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Accounts receivable and unbilled revenues, reserves	$ 39.6	$ 39.5
Property, plant, and equipment, accumulated depreciation	$ 3,377.9	$ 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

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Operating Activities
Net income	$ 199.2	$ 177.7
Reconciliation to cash provided by operating activities
Depreciation and amortization	172.2	164.8
Deferred income taxes and investment tax credits, net	(39.5)	64.1
Contributions and payments related to pension and OPEB plans	(3.8)	(5.6)
Change in –
Accounts receivable and unbilled revenues	57.9	26.7
Materials, supplies, and inventories	14.0	(7.2)
Other current assets	28.4	10.1
Accounts payable	(36.2)	(8.1)
Accrued taxes	19.0	(24.4)
Other current liabilities	(18.1)	(24.2)
Other, net	138.5	(14.0)
Net cash provided by operating activities	531.6	359.9
Investing Activities
Capital expenditures	(287.0)	(246.9)
Proceeds from the sale of assets	0.6	22.0
Payments for assets transferred from affiliates	(50.1)	0.0
Short-term notes receivable from related parties, net	0.0	(3.1)
Other, net	5.4	2.3
Net cash used in investing activities	(331.1)	(225.7)
Financing Activities
Change in short-term debt	130.9	(84.0)
Repayment of subsidiary note to parent	0.0	(18.5)
Retirement of long-term debt	(250.0)	0.0
Equity contribution from parent	28.0	75.0
Payment of dividends to parent	(120.0)	(120.0)
Payment of preferred stock dividends	(0.6)	(0.6)
Other	0.0	0.1
Net cash used in financing activities	(211.7)	(148.0)
Net change in cash and cash equivalents	(11.2)	(13.8)
Cash and cash equivalents at beginning of period	12.3	15.4
Cash and cash equivalents at end of period	$ 1.1	$ 1.6

XML

GENERAL INFORMATION

6 Months Ended

Jun. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

GENERAL INFORMATION

GENERAL INFORMATION

As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, balance sheets, and statements of cash flows, unless otherwise noted. In this report, when we refer to "the Company," "us," "we," "our," or "ours," we are referring to Wisconsin Electric Power Company and its subsidiary, Bostco.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2017. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and six months ended June 30, 2018, are not necessarily indicative of expected results for 2018 due to seasonal variations and other factors.

In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results.

XML

DISPOSITIONS

6 Months Ended

Jun. 30, 2018

Discontinued Operations and Disposal Groups [Abstract]

DISPOSITIONS

DISPOSITION

Other Segment–Sale of Bostco Real Estate Holdings

In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space. During the first quarter of 2017, we recorded an insignificant gain on the sale, which was included in other income, net on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations associated with these assets remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.

XML

OPERATING REVENUES

6 Months Ended

Jun. 30, 2018

Revenue from Contract with Customer [Abstract]

OPERATING REVENUES

OPERATING REVENUES

Adoption of ASU 2014-09, Revenues from Contracts with Customers

On January 1, 2018, we adopted ASU 2014-09, Revenues from Contracts with Customers, and the related amendments. In accordance with the guidance, we recognize revenues when control of the promised goods or services is transferred to our customers in an amount that reflects the consideration we expect to be entitled to receive in exchange for those goods or services. These revenues include unbilled revenues, which are estimated using the amount of energy delivered to our customers but not billed until after the end of the period.

We adopted this standard using the modified retrospective method. Results for reporting periods beginning after January 1, 2018, are presented under the new standard. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Adoption of the standard did not result in an adjustment to our opening retained earnings balance as of January 1, 2018, and we do not expect the adoption of the standard to have a material impact on our net income in future periods.

We adopted the following practical expedients and optional exemptions for the implementation of this standard:

• We elected to exclude from the transaction price any amounts collected from customers for all sales taxes and other similar taxes.

• When applicable, we elected to apply the standard to a portfolio of contracts with similar characteristics, primarily our tariff-based contracts, as we reasonably expect that the effects on the financial statements of applying this guidance to the portfolio would not differ materially from applying this guidance to the individual contracts.

• We elected to recognize revenue in the amount we have the right to invoice for performance obligations satisfied over time when the consideration received from a customer corresponds directly with the value provided to the customer during the same period.

• We elected to not disclose the remaining performance obligations of a contract that has an original expected duration of one year or less.

• We elected to apply this standard only to contracts that are not completed as of the date of initial application.

Disaggregation of Operating Revenues

The following tables present our operating revenues disaggregated by revenue source. We only have revenues associated with our utility segment. We do not have any revenues associated with our other segment. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For our utility segment, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations have different expectations of service, energy and demand requirements, and are impacted by regulatory activities within their jurisdictions.

Comparable amounts have not been presented for the three and six months ended June 30, 2017, due to our adoption of this standard under the modified retrospective method.

	Wisconsin Electric Power Company Consolidated
(in millions)	Three Months Ended June 30, 2018		Six Months Ended June 30, 2018
Electric utility	$	784.6	$	1,564.2
Natural gas utility	68.6		229.4
Total revenues from contracts with customers	853.2		1,793.6
Other operating revenues	3.0		4.1
Total operating revenues	$	856.2	$	1,797.7

Revenues from Contracts with Customers

Electric Utility Operating Revenues

The following table disaggregates electric utility operating revenues into customer class:

	Electric Utility Operating Revenues
(in millions)	Three Months Ended June 30, 2018		Six Months Ended June 30, 2018
Residential	$	295.0	$	576.4
Small commercial and industrial	260.6		498.3
Large commercial and industrial	172.4		321.3
Other	4.9		10.3
Total retail revenues	732.9		1,406.3
Wholesale	28.9		57.4
Resale	17.1		80.8
Steam	4.6		14.3
Other utility revenues	1.1		5.4
Total electric utility operating revenues	$	784.6	$	1,564.2

Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. The rates, charges, terms, and conditions of service for sales to these customers are included in tariffs that have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month.

Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have us provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. The rates, charges, terms and conditions of service for sales to wholesale customers are included in tariffs that have been approved by the FERC. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric operations and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis.

We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales and net sales in a single hour are recorded as resale revenues. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets.

For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days. For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility’s costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual current year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services.

Natural Gas Utility Operating Revenues

The following table disaggregates natural gas utility operating revenues into customer class:

	Natural Gas Utility Operations
(in millions)	Three Months Ended June 30, 2018		Six Months Ended June 30, 2018
Residential	$	40.7	$	155.4
Commercial and industrial	18.2		73.8
Total retail revenues	58.9		229.2
Transport	3.1		7.5
Other utility revenues *	6.6		(7.3		)
Total natural gas utility operating revenues	$	68.6	$	229.4

* Includes amounts collected from (refunded to) customers for purchased gas adjustment costs.

We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under our tariffs. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In certain of our service territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer.

The transaction price of the performance obligations is valued using rates in our tariffs, which have been approved by the PSCW. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month.

Consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days.

Other Operating Revenues

Other operating revenues consist primarily of the following:

(in millions)	Three Months Ended June 30, 2018			Six Months Ended June 30, 2018
Late payment charges	$	2.1		$	4.9
Leases	1.4			2.2
Alternative revenues *	(0.5		)	(3.0		)
Total other operating revenues	$	3.0		$	4.1

* 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 record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers.

Our only alternative revenue program relates to the wholesale electric service that we provide to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.

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PROPERTY, PLANT, AND EQUIPMENT

6 Months Ended

Jun. 30, 2018

Property, Plant and Equipment [Abstract]

PROPERTY, PLANT, AND EQUIPMENT

PROPERTY, PLANT, AND EQUIPMENT

Utility Segment Plant to be Retired

We have evaluated future plans for our older and less efficient fossil fuel generating units and have either retired or announced the retirement of the plants identified below. In addition, a severance liability was recorded in other current liabilities on our balance sheets related to these plant retirements.

(in millions)
Severance liability at December 31, 2017	$	25.8
Severance payments	(8.7		)
Other	(3.0		)
Total severance liability at June 30, 2018	$	14.1

Pleasant Prairie Power Plant

The Pleasant Prairie power plant was retired effective April 10, 2018. The carrying value of this plant was $667.7 million at June 30, 2018. This amount included the net book value of $774.2 million, which was reclassified as a regulatory asset on our balance sheet in the second quarter as a result of the retirement of the plant. In addition, a $106.5 million cost of removal reserve related to the Pleasant Prairie power plant was recorded as a regulatory liability at June 30, 2018. We continue to amortize this regulatory asset on a straight-line basis using the composite depreciation rates approved by the PSCW before this plant was retired. Amortization is included in depreciation and amortization in the income statement. The physical dismantlement of the plant will not occur immediately. It may take several years to finalize long-term plans for the site. See Note 16, Commitments and Contingencies, for more information.

Presque Isle Power Plant

In October 2017, the MPSC approved UMERC’s application to construct and operate approximately 180 MW of natural gas-fired generation in the Upper Peninsula of Michigan. The new units are expected to begin commercial operation during the second quarter of 2019. Upon receiving the MPSC's approval, retirement of the PIPP generating units became probable. In connection with MISO's April 2018 approval of the retirement of the plant, the PIPP units will be retired on or before May 31, 2019. The carrying value of the PIPP units was $189.7 million at June 30, 2018. This amount included the net book value of $199.8 million, which was classified as plant to be retired within property, plant, and equipment on our balance sheet. In addition, a $10.1 million cost of removal reserve related to the PIPP units was recorded as a regulatory liability at June 30, 2018. These units are included in rate base, and we continue to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW. See Note 16, Commitments and Contingencies, for more information.

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COMMON EQUITY

6 Months Ended

Jun. 30, 2018

Equity [Abstract]

COMMON EQUITY

COMMON EQUITY

Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to WEC Energy Group in the form of cash dividends, loans, or advances. In addition, Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group or its subsidiaries. See Note 8, Common Equity, in our 2017 Annual Report on Form 10-K for additional information on these and other restrictions.

We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.

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SHORT-TERM DEBT AND LINES OF CREDIT

6 Months Ended

Jun. 30, 2018

Short-term Debt [Abstract]

SHORT-TERM DEBT AND LINES OF CREDIT

SHORT-TERM DEBT AND LINES OF CREDIT

The following table shows our short-term borrowings and their corresponding weighted-average interest rates:

(in millions, except percentages)	June 30, 2018			December 31, 2017
Commercial paper
Amount outstanding	$	341.8		$	210.9
Weighted-average interest rate on amounts outstanding	2.35		%	1.81		%

Our average amount of commercial paper borrowings based on daily outstanding balances during the six months ended June 30, 2018, was $79.2 million with a weighted-average interest rate during the period of 2.06%.

The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including available capacity under this facility:

(in millions)	Maturity	June 30, 2018
Revolving credit facility	October 2022	$	500.0
Less:
Letters of credit issued inside credit facility		$	1.2
Commercial paper outstanding		341.8
Available capacity under existing agreement		$	157.0

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LONG-TERM DEBT

6 Months Ended

Jun. 30, 2018

Long-term Debt, Unclassified [Abstract]

LONG-TERM DEBT

LONG-TERM DEBT

In July 2018, we redeemed all $80.0 million outstanding of our series of tax-exempt pollution control refunding bonds. Since August 2009, the bonds were outstanding, but were not reported in our long-term debt because they were held by us.

In June 2018, our $250.0 million of 1.70% Debentures matured, and the outstanding principal was paid with proceeds received from issuing commercial paper.

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MATERIALS, SUPPLIES, AND INVENTORIES

6 Months Ended

Jun. 30, 2018

Inventory Disclosure [Abstract]

MATERIALS, SUPPLIES, AND INVENTORIES

MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:

(in millions)	June 30, 2018		December 31, 2017
Materials and supplies	$	137.2	$	140.7
Fossil fuel	75.9		74.8
Natural gas in storage	23.6		35.2
Total	$	236.7	$	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.

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INCOME TAXES

6 Months Ended

Jun. 30, 2018

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

The effective tax rates of (2.8)% and (3.2)% for the three and six months ended June 30, 2018, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to the flow through of tax repairs in connection with the Wisconsin rate settlement and the impact of the Tax Legislation, partially offset by state income taxes. The Tax Legislation, signed into law in December 2017, required us to remeasure our deferred income taxes and begin to amortize the resulting excess deferred income taxes beginning in 2018 in accordance with normalization requirements. See Note 18, Regulatory Environment, for more information on the Tax Legislation and the Wisconsin rate settlement.

On December 22, 2017, the SEC staff issued guidance in Staff Accounting Bulletin 118 (SAB 118), Income Tax Accounting Implications of the Tax Legislation, which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, certain amounts related to bonus depreciation and future tax benefit utilization recorded in the financial statements as a result of the Tax Legislation are to be considered "provisional" as discussed in SAB 118 and subject to revision. We are awaiting additional guidance from industry and income tax authorities in order to finalize our accounting.

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FAIR VALUE MEASUREMENTS

6 Months Ended

Jun. 30, 2018

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).

Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally developed inputs.

We recognize transfers between levels of the fair value hierarchy at their value as of the end of the reporting period.

The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:

	June 30, 2018
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	1.5	$	—	$	—	$	1.5
Petroleum products contracts	0.3		—		—		0.3
FTRs	—		—		8.7		8.7
Coal contracts	—		0.5		—		0.5
Total derivative assets	$	1.8	$	0.5	$	8.7	$	11.0
Derivative liabilities
Natural gas contracts	$	0.1	$	—	$	—	$	0.1

	December 31, 2017
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	0.5	$	0.1	$	—	$	0.6
Petroleum products contracts	0.9		—		—		0.9
FTRs	—		—		2.4		2.4
Coal contracts	—		0.7		—		0.7
Total derivative assets	$	1.4	$	0.8	$	2.4	$	4.6
Derivative liabilities
Natural gas contracts	$	2.0	$	0.1	$	—	$	2.1
Coal contracts	—		0.3		—		0.3
Total derivative liabilities	$	2.0	$	0.4	$	—	$	2.4

The derivative assets and liabilities listed in the tables above include options, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy Markets.

The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy:

	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2018			2017			2018			2017
Balance at the beginning of the period	$	0.8		$	1.1		$	2.4		$	3.1
Purchases	9.4			6.9			9.4			6.9
Settlements	(1.5		)	(2.0		)	(3.1		)	(4.0		)
Balance at the end of the period	$	8.7		$	6.0		$	8.7		$	6.0

Fair Value of Financial Instruments

The following table shows the financial instruments included on our balance sheets that are not recorded at fair value:

	June 30, 2018				December 31, 2017
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock	$	30.4	$	28.7	$	30.4	$	30.5
Long-term debt, including current portion	2,413.4		2,603.4		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.

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DERIVATIVE INSTRUMENTS

6 Months Ended

Jun. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS

DERIVATIVE INSTRUMENTS

We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Our regulated hedging programs are approved by the PSCW.

We record derivative instruments on our balance sheets as an asset or liability measured at fair value unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of fair value accounting to be offset to regulatory assets and liabilities.

The following table shows our derivative assets and derivative liabilities:

	June 30, 2018				December 31, 2017
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	1.5	$	—	$	0.6	$	1.9
Petroleum products contracts	0.3		—		0.9		—
FTRs	8.7		—		2.4		—
Coal contracts	0.5		—		0.6		0.1
Total other current *	$	11.0	$	—	$	4.5	$	2.0
Other long-term
Natural gas contracts	$	—	$	0.1	$	—	$	0.2
Coal contracts	—		—		0.1		0.2
Total other long-term *	—		0.1		0.1		0.4
Total	$	11.0	$	0.1	$	4.6	$	2.4

* On our balance sheets, we classify derivative assets and liabilities as other current or other long-term based on the maturities of the underlying contracts.

Realized gains (losses) on derivative instruments are primarily recorded in cost of sales on the income statements. Our estimated notional sales volumes and realized gains (losses) were as follows:

	Three Months Ended June 30, 2018				Three Months Ended June 30, 2017
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	12.0 Dth	$	(0.6	)	5.0 Dth	$	0.2
Petroleum products contracts	1.1 gallons	0.2			4.9 gallons	(0.4		)
FTRs	4.8 MWh	0.9			7.3 MWh	2.0
Total		$	0.5			$	1.8

	Six Months Ended June 30, 2018				Six Months Ended June 30, 2017
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	23.7 Dth	$	(2.4	)	13.2 Dth	$	0.7
Petroleum products contracts	2.5 gallons	0.6			9.8 gallons	(0.9		)
FTRs	10.6 MWh	1.7			14.3 MWh	4.5
Total		$	(0.1	)		$	4.3

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At June 30, 2018 and December 31, 2017, we had posted cash collateral of $1.0 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:

	June 30, 2018						December 31, 2017
(in millions)	Derivative Assets			Derivative Liabilities			Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	11.0		$	0.1		$	4.6		$	2.4
Gross amount not offset on the balance sheet	(0.1		)	(0.1		)	(1.3		)	(2.0		)	*
Net amount	$	10.9		$	—		$	3.3		$	0.4

* Includes cash collateral posted of $0.7 million.

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EMPLOYEE BENEFITS

6 Months Ended

Jun. 30, 2018

Retirement Benefits [Abstract]

EMPLOYEE BENEFITS

EMPLOYEE BENEFITS

The following tables show the components of net periodic pension and OPEB costs for our benefit plans:

	Pension Costs
	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2018			2017			2018			2017
Service cost	$	3.3		$	3.1		$	6.6		$	6.1
Interest cost	10.5			11.6			21.1			23.5
Expected return on plan assets	(18.6		)	(19.1		)	(37.6		)	(38.3		)
Loss on plan settlement	—			2.8			—			2.8
Amortization of prior service cost	0.2			0.3			0.4			0.6
Amortization of net actuarial loss	9.6			8.9			19.0			17.7
Net periodic benefit cost	$	5.0		$	7.6		$	9.5		$	12.4

	OPEB Costs
	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2018			2017			2018			2017
Service cost	$	1.7		$	1.5		$	3.5		$	3.4
Interest cost	2.7			3.1			5.5			6.2
Expected return on plan assets	(3.9		)	(3.6		)	(7.8		)	(7.2		)
Amortization of prior service credit	(0.5		)	(0.3		)	(1.1		)	(0.6		)
Amortization of net actuarial gain	—			(0.3		)	—			—
Net periodic benefit cost	$	—		$	0.4		$	0.1		$	1.8

During the six months ended June 30, 2018, we made contributions and payments of $2.9 million related to our pension plans and $0.9 million related to our OPEB plans. We expect to make contributions and payments of $1.2 million related to our pension plans and $3.5 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 thethree and six months ended June 30,2018and2017, we have presented the service cost component of our retirement benefit plans in other operation and maintenance on the income statements, while presenting the non-service components in other income, net.

The following table shows the non-service (credit) cost components of net benefit costs:

	Three Months Ended June 30					Six Months Ended June 30
(in millions)	2018			2017		2018			2017
Non-service (credit) cost components	$	(1.2	)	$	3.3	$	(2.9	)	$	4.5

For the three and six months ended June 30, 2017, the non-service components of net benefit cost were reclassified from other operation and maintenance to other income, net, on our income statements.

Under ASU 2017-07, only the service cost component of net periodic benefit cost is eligible for capitalization to property, plant, and equipment. In prior periods, a portion of all net benefit cost components was capitalized to property, plant, and equipment. As required, this amendment was applied prospectively, beginning January 1, 2018. As a result of the application of accounting principles for rate regulated entities, the non-service cost components of the net benefit cost that are no longer eligible for capitalization under this standard, but are capitalized under the regulatory framework, are presented as regulatory assets or liabilities rather than property, plant, and equipment.

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SEGMENT INFORMATION

6 Months Ended

Jun. 30, 2018

Segment Reporting [Abstract]

SEGMENT INFORMATION

SEGMENT INFORMATION

We use operating income to measure segment profitability and to allocate resources to our businesses. At June 30, 2018, we reported two segments, which are described below.

Our utility segment includes both our electric and natural gas utility operations. Our electric utility operations are engaged in the generation, distribution, and sale of electricity to customers in southeastern Wisconsin (including metropolitan Milwaukee), east central Wisconsin, and northern Wisconsin, and to one customer in the Upper Peninsula of Michigan. Our electric utility operations also include our steam operations, which produce, distribute, and sell steam to customers in metropolitan Milwaukee, Wisconsin. Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers and the transportation of customer-owned natural gas in our three service areas within southeastern, east central, and northern Wisconsin.

Our other segment 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 and six months ended June 30, 2018 and 2017, related to our reportable segments:

(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Three Months Ended June 30, 2018
Operating revenues	$	856.2	$	—	$	856.2
Other operation and maintenance	366.6		—		366.6
Depreciation and amortization	86.9		—		86.9
Operating income	104.5		—		104.5
Interest expense	29.2		—		29.2

(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Three Months Ended June 30, 2017
Operating revenues	$	855.4	$	—	$	855.4
Other operation and maintenance *	324.4		—		324.4
Depreciation and amortization	82.7		—		82.7
Operating income *	146.1		—		146.1
Interest expense	29.1		—		29.1

* Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 12, Employee Benefits, for more information on this new standard.

(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Six Months Ended June 30, 2018
Operating revenues	$	1,797.7	$	—	$	1,797.7
Other operation and maintenance	702.2		—		702.2
Depreciation and amortization	172.2		—		172.2
Operating income	240.9		—		240.9
Interest expense	58.9		—		58.9

(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Six Months Ended June 30, 2017
Operating revenues	$	1,827.4	$	—	$	1,827.4
Other operation and maintenance *	651.0		—		651.0
Depreciation and amortization	164.8		—		164.8
Operating income *	332.4		—		332.4
Interest expense	58.4		0.3		58.7

* Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 12, Employee Benefits, for more information on this new standard.

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VARIABLE INTEREST ENTITIES

6 Months Ended

Jun. 30, 2018

Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Determination Methodology and Factors [Abstract]

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES

The primary beneficiary of a variable interest entity must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in variable interest entities.

We assess our relationships with potential variable interest entities, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to power purchase agreements, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance.

Purchased Power Agreement

We have a purchased power agreement that represents a variable interest. This agreement is for 236 MW of firm capacity from a natural gas-fired cogeneration facility, and we account for it as a capital lease. The agreement includes no minimum energy requirements over the remaining term of approximately four years. We have examined the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity, and there is no residual guarantee associated with the purchased power agreement.

We have approximately $64.1 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 six months ended June 30, 2018 and 2017 were $9.4 million and $9.0 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

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RELATED PARTIES

6 Months Ended

Jun. 30, 2018

Related Party Transactions [Abstract]

RELATED PARTIES

RELATED PARTIES

We routinely enter into transactions with related parties, including WEC Energy Group, its other subsidiaries, ATC (a for-profit electric transmission company regulated by the FERC and certain state regulatory commissions), and other affiliated entities.

We provide and receive services, property, and other items of value to and from our parent, WEC Energy Group, and other subsidiaries of WEC Energy Group.

On January 1, 2017, based upon input we received from the PSCW, we transferred our $415.4 million investment in ATC, and the related receivable for distributions approved and recorded in December 2016 to another subsidiary of WEC Energy Group. In addition, during 2017 we transferred $186.8 million of related deferred income tax liabilities. These transactions were non-cash equity transfers recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss.

We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed by ATC. Services are billed to and from ATC under agreements approved by the PSCW, at each of our fully allocated costs.

Our balance sheets included the following receivables and payables related to transactions entered into with ATC:

(in millions)	June 30, 2018		December 31, 2017
Accounts receivable
Services provided to ATC	$	1.3	$	0.8
Accounts payable
Services received from ATC	19.3		22.2

The following table shows activity associated with our related party transactions:

	Three Months Ended June 30				Six Months Ended June 30
(in millions)	2018		2017		2018		2017
Lease agreements
Lease payments to We Power (1)	$	95.1	$	106.7	$	187.3	$	211.1
Construction work in progress billed to We Power	5.0		8.9		8.8		25.2
Transactions with WBS (2)
Billings to WBS	2.8		60.5		8.7		117.0
Billings from WBS (3)	68.6		52.9		176.7		102.7
Transactions with WPS (2)
Billings to WPS	4.3		5.2		7.3		7.7
Billings from WPS	1.9		1.1		5.1		2.2
Transactions with WG
Natural gas purchases from WG	1.3		1.3		2.6		2.6
Billings to WG (2) (4)	13.2		16.1		27.1		31.9
Billings from WG (2)	5.0		5.8		9.7		11.3
Transactions with UMERC
Electric sales to UMERC	6.9		6.4		15.0		14.1
Billings to UMERC (2)	2.9		29.3		7.1		33.9
Transactions with Bluewater (5)
Storage service fees	4.6		—		5.9		—
Transactions with ATC
Charges to ATC for services and construction	2.7		2.4		5.7		5.2
Charges from ATC for network transmission services	58.1		60.4		116.1		120.7
Refund from ATC related to a FERC audit	15.4		—		15.4		—
Refund from ATC per FERC ROE order	—		—		—		19.4

⁽¹⁾  We make lease payments to We Power, another subsidiary of WEC Energy Group, for PWGS Units 1 and 2 and ERGS Units 1 and 2. Lease payments were reduced in 2018 as a result of tax savings related to Tax Legislation.

⁽²⁾  Includes amounts billed for services, pass through costs, and other items in accordance with approved affiliated interest agreements.

⁽³⁾  Includes $8.7 million and $57.6 million for the transfer of certain software assets from WBS during the three and six months ended June 30, 2018, respectively. There were no software assets transferred from WBS during 2017.

⁽⁴⁾  Includes $5.2 million for the transfer of certain software assets to WG during the three and six months ended June 30, 2018. There were no software assets transferred to WG during 2017.

⁽⁵⁾  WEC Energy Group's acquisition of Bluewater was completed June 30, 2017. See below for more information.

Upper Michigan Energy Resources Corporation

In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan. UMERC, a subsidiary of WEC Energy Group, became operational effective January 1, 2017, and we transferred customers and property, plant, and equipment as of that date. We transferred approximately 27,500 retail electric customers and 50 electric distribution-only customers to UMERC, along with approximately 2,500 miles of electric distribution lines. We also transferred related electric distribution substations in the Upper Peninsula of Michigan and all property rights for the distribution assets to UMERC. The book value of net assets, including the related deferred income tax liabilities, transferred to UMERC from us in 2017 was $61.1 million. This transaction was a non-cash equity transfer recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss. UMERC currently meets its market obligations through power purchase agreements with us and WPS.

WEC Energy Group's Acquisition of Natural Gas Storage Facilities in Michigan

On June 30, 2017, WEC Energy Group completed the acquisition of Bluewater for $226.0 million. Bluewater owns natural gas storage facilities in Michigan that provide a portion of the current storage needs for our natural gas utility operations. In September 2017, we finalized a long-term service agreement with a wholly owned subsidiary of Bluewater to take the allocated storage, which was then approved by the PSCW in November 2017.

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COMMITMENTS AND CONTINGENCIES

6 Months Ended

Jun. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

We have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, environmental matters, and enforcement and litigation matters.

Unconditional Purchase Obligations

We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of June 30, 2018, were $9,760.2 million.

Environmental Matters

Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as sulfur dioxide, nitrogen oxide, fine particulates, mercury, and GHGs; water intake and discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.

Air Quality

8-Hour Ozone National Ambient Air Quality Standards

After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, which lowered the limit for ground-level ozone, creating a more stringent standard than the 2008 National Ambient Air Quality Standards. The EPA issued final nonattainment area designations on May 1, 2018. The following counties within our service territory were designated as partial nonattainment: Kenosha, Manitowoc, Northern Milwaukee/Ozaukee, and Sheboygan shorelines. The state of Wisconsin will need to develop a state implementation plan to bring these areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020. We believe we are well positioned to meet the requirements associated with the ozone standard and do not expect to incur significant costs to comply.

Climate Change

In 2015, the EPA issued a final rule regulating GHG emissions from existing generating units, referred to as the Clean Power Plan, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In 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. 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. In April 2017, pursuant to motions made by the EPA, the D.C. Circuit Court of Appeals ordered the challenges to the CPP, as well as related performance standards for new, reconstructed, and modified fossil-fueled power plants, to be held in abeyance, which remains the case.

In March 2017, President Trump issued an executive order that, among other things, specifically directed the EPA to review the CPP and related GHG regulations for new, reconstructed, or modified fossil-fueled power plants. 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. The EPA is expected to issue a proposed CPP replacement rule, or decide to rescind the CPP without replacing it, during the third quarter of 2018.

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 CO₂ emissions by approximately 40% below 2005 levels by 2030. In addition, WEC Energy Group's new long-term goal is to reduce CO₂ emissions by approximately 80% below 2005 levels by 2050. We have implemented and continue to evaluate numerous options in order to meet WEC Energy Group's CO₂ reduction goals. Options considered include 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 (retired in April 2018) and PIPP. See Note 4, Property, Plant, and Equipment, for more information. In addition, we are evaluating our goals, and possible subsequent actions, with respect to national and international efforts to reduce future GHG emissions in order to limit future global temperature increases to less than two degrees Celsius.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act, which requires that the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts from both impingement (entrapping organisms on water intake screens) and entrainment (drawing organisms into water intake). The rule became effective in October 2014 and applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted under the rules governing new facilities.

Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities satisfy the IM BTA requirements. 

BTA determinations must also be made by the WDNR and MDEQ to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. We have received an EM BTA determination by the WDNR, with EPA concurrence, for our intake modification at Valley power plant. Due to the retirement of the Pleasant Prairie Power Plant and our plans to retire PIPP, we do not believe that BTA determinations for EM will be necessary for these units. Although we currently believe that existing technologies at PWGS and OC 5 through OC 8 satisfy the EM BTA requirements, BTA determinations to address EM reduction requirements will not be made until discharge permits are renewed for these units. Until that time, we cannot determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements for these units. During 2018, we will continue to evaluate options to address the EM BTA requirements for these units.

We have also provided information to the WDNR and the MDEQ about planned unit retirements. Based on discussions with the MDEQ, if we submit a signed certification stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2023), the EM BTA requirements will be waived. We expect to submit the letter identifying the last operating date for PIPP to the MDEQ 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 desulfurizationwastewater requirements. This rule applies to wastewater discharges from our power plant processes in Wisconsin and Michigan. In February 2018, the Center for Biological Diversity (CBD) filed suit in the U.S. District Court of Arizona challenging the Postponement Rule. In April 2018, the Utility Water Act Group filed a motion to dismiss the CBD suit for lack of subject matter jurisdiction. 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 retirement of PIPP as a result of WEC Energy Group's generation reshaping plan discussed in Climate Change above.

Land Quality

Manufactured Gas Plant Remediation

We have identified sites at which we or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. We are responsible for the environmental remediation of these sites. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure.

The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites.

We have established the following regulatory assets and reserves related to manufactured gas plant sites:

(in millions)	June 30, 2018		December 31, 2017
Regulatory assets	$	29.9	$	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.

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SUPPLEMENTAL CASH FLOW INFORMATION

6 Months Ended

Jun. 30, 2018

Supplemental Cash Flow Information [Abstract]

SUPPLEMENTAL CASH FLOW INFORMATION

SUPPLEMENTAL CASH FLOW INFORMATION

	Six Months Ended June 30
(in millions)	2018			2017
Cash (paid) for interest, net of amount capitalized	$	(57.8	)	$	(57.6	)
Cash (paid) for income taxes, net	(8.2		)	(63.4		)
Significant noncash transactions:
Accounts payable related to construction costs	4.5			13.0
Accounts payable related to assets transferred from affiliates	7.5			—
Accounts receivable related to assets transferred to affiliates	5.4			—
Transfer of investment in ATC to another subsidiary of WEC Energy Group (1) (2)	—			415.4
Transfer of net assets to UMERC (1)	—			60.0

⁽¹⁾ See Note 15, 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.

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REGULATORY ENVIRONMENT

6 Months Ended

Jun. 30, 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 May 2018, the PSCW issued an order regarding the benefits associated with the Tax Legislation. The PSCW order requires our electric utility operations to use 80% of the current 2018 and 2019 tax benefits to reduce our transmission regulatory asset. The remaining 20% is to be returned to electric customers in the form of bill credits. For our natural gas utility operations, the PSCW indicated that 100% of current 2018 and 2019 tax benefits should be returned to natural gas customers in the form of bill credits. Regarding the net tax benefit associated with the revaluation of deferred taxes, amortization required in accordance with normalization accounting is to be used to reduce our transmission regulatory asset for our electric utility operations and is being deferred for our natural gas utility operations. The timing and method of returning the remaining net tax benefit associated with the revaluation of deferred taxes for our electric and natural gas utility operations was not addressed and will be determined in a future rate proceeding. During the six months ended June 30, 2018, we reduced our transmission regulatory asset by $33.8 million as a result of the PSCW order.

We currently serve one retail electric customer in Michigan, and have reached a settlement with that customer. That settlement was approved by the MPSC in May 2018 and addresses all base rate impacts of the Tax Legislation, which will be returned to the customer through bill credits.

2018 and 2019 Rates

During April 2017, we, along with WG and WPS, filed an application with the PSCW for approval of a settlement agreement we made with several of our commercial and industrial customers regarding 2018 and 2019 base rates. In September 2017, the PSCW issued an order that approved the settlement agreement, which will freeze base rates through 2019 for our electric, natural gas, and steam customers. Based on the PSCW order, our authorized ROE remains at 10.2%, and our current capital cost structure will remain unchanged through 2019. Various intervenors had filed requests for rehearing, all of which have been denied.

In addition to freezing base rates, the settlement agreement extends and expands the electric real-time market pricing program options for large commercial and industrial customers and mitigates the continued growth of certain escrowed costs during the base rate freeze period by accelerating the recognition of certain tax benefits. We will flow through the tax benefit of our repair-related deferred tax liabilities in 2018 and 2019, to maintain certain regulatory asset balances at their December 31, 2017 levels. While we would typically follow the normalization accounting method and utilize the tax benefits of the deferred tax liabilities in rate making as an offset to rate base, benefiting customers over time, the federal tax code does allow for passing these tax repair-related benefits to ratepayers much sooner using the flow through accounting method. The flow through treatment of the repair-related deferred tax liabilities offsets the negative income statement impact of holding the regulatory assets level, resulting in no change to net income.

Pursuant to the settlement agreement, we also agreed to keep our earnings sharing mechanism in place through 2019. Under this earnings sharing mechanism, if we earn above our authorized ROE, 50% of the first 50 basis points of additional utility earnings must be shared with customers. All utility earnings above the first 50 basis points must also be shared with customers.

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NEW ACCOUNTING PRONOUNCEMENTS

6 Months Ended

Jun. 30, 2018

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

NEW ACCOUNTING PRONOUNCEMENTS

NEW ACCOUNTING PRONOUNCEMENTS

Leases

In February 2016, the FASB issued ASU 2016-02, Leases. This ASU was subsequently amended by ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842, ASU 2018-10, Codification Improvements to Topic 842, Leases, and ASU 2018-11, Targeted Improvements. The main provision of ASU 2016-02 is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP. In addition, this ASU expands the required quantitative and qualitative disclosures related to lease agreements. This guidance is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. This guidance must be adopted using a modified retrospective approach and provides for a number of optional transition practical expedients. We expect to apply the package of practical expedients allowed by this ASU which, among other things, allows the carryforward of prior conclusions related to lease identification and classification. We have not yet determined whether we will elect any other practical expedients upon transition. 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.

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GENERAL INFORMATION (Policies)

6 Months Ended

Jun. 30, 2018

Accounting policies

Consolidation

As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, balance sheets, and statements of cash flows, unless otherwise noted. In this report, when we refer to "the Company," "us," "we," "our," or "ours," we are referring to Wisconsin Electric Power Company and its subsidiary, Bostco.

Basis of accounting

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2017. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and six months ended June 30, 2018, are not necessarily indicative of expected results for 2018 due to seasonal variations and other factors.

In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results.

Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).

Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally developed inputs.

We recognize transfers between levels of the fair value hierarchy at their value as of the end of the reporting period.

Derivative Instruments

We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Our regulated hedging programs are approved by the PSCW.

We record derivative instruments on our balance sheets as an asset or liability measured at fair value unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of fair value accounting to be offset to regulatory assets and liabilities.

New Accounting Pronouncements

Leases

In February 2016, the FASB issued ASU 2016-02, Leases. This ASU was subsequently amended by ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842, ASU 2018-10, Codification Improvements to Topic 842, Leases, and ASU 2018-11, Targeted Improvements. The main provision of ASU 2016-02 is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP. In addition, this ASU expands the required quantitative and qualitative disclosures related to lease agreements. This guidance is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. This guidance must be adopted using a modified retrospective approach and provides for a number of optional transition practical expedients. We expect to apply the package of practical expedients allowed by this ASU which, among other things, allows the carryforward of prior conclusions related to lease identification and classification. We have not yet determined whether we will elect any other practical expedients upon transition. 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

Disaggregation of Operating Revenues

Revenue Recognition

Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. The rates, charges, terms, and conditions of service for sales to these customers are included in tariffs that have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month.

Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have us provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. The rates, charges, terms and conditions of service for sales to wholesale customers are included in tariffs that have been approved by the FERC. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric operations and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis.

We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales and net sales in a single hour are recorded as resale revenues. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets.

For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days. For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility’s costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual current year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services.

Utility segment | Natural gas

Disaggregation of Operating Revenues

Revenue Recognition

We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under our tariffs. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In certain of our service territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer.

The transaction price of the performance obligations is valued using rates in our tariffs, which have been approved by the PSCW. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month.

Consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days.

Utility segment | Alternative revenues

Disaggregation of Operating Revenues

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 record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers.

Our only alternative revenue program relates to the wholesale electric service that we provide to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.

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OPERATING REVENUES (Tables) - Utility segment

6 Months Ended

Jun. 30, 2018

Disaggregation of Operating Revenues

Operating revenues disaggregated by revenue source

The following tables present our operating revenues disaggregated by revenue source. We only have revenues associated with our utility segment. We do not have any revenues associated with our other segment. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For our utility segment, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations have different expectations of service, energy and demand requirements, and are impacted by regulatory activities within their jurisdictions.

Comparable amounts have not been presented for the three and six months ended June 30, 2017, due to our adoption of this standard under the modified retrospective method.

	Wisconsin Electric Power Company Consolidated
(in millions)	Three Months Ended June 30, 2018		Six Months Ended June 30, 2018
Electric utility	$	784.6	$	1,564.2
Natural gas utility	68.6		229.4
Total revenues from contracts with customers	853.2		1,793.6
Other operating revenues	3.0		4.1
Total operating revenues	$	856.2	$	1,797.7

Revenues from contracts with customers | Electric

Disaggregation of Operating Revenues

Operating revenues disaggregated by revenue source

Electric Utility Operating Revenues

The following table disaggregates electric utility operating revenues into customer class:

	Electric Utility Operating Revenues
(in millions)	Three Months Ended June 30, 2018		Six Months Ended June 30, 2018
Residential	$	295.0	$	576.4
Small commercial and industrial	260.6		498.3
Large commercial and industrial	172.4		321.3
Other	4.9		10.3
Total retail revenues	732.9		1,406.3
Wholesale	28.9		57.4
Resale	17.1		80.8
Steam	4.6		14.3
Other utility revenues	1.1		5.4
Total electric utility operating revenues	$	784.6	$	1,564.2

Revenues from contracts with customers | Natural gas

Disaggregation of Operating Revenues

Operating revenues disaggregated by revenue source

Natural Gas Utility Operating Revenues

The following table disaggregates natural gas utility operating revenues into customer class:

	Natural Gas Utility Operations
(in millions)	Three Months Ended June 30, 2018		Six Months Ended June 30, 2018
Residential	$	40.7	$	155.4
Commercial and industrial	18.2		73.8
Total retail revenues	58.9		229.2
Transport	3.1		7.5
Other utility revenues *	6.6		(7.3		)
Total natural gas utility operating revenues	$	68.6	$	229.4

* Includes amounts collected from (refunded to) customers for purchased gas adjustment costs.

Other operating revenues

Disaggregation of Operating Revenues

Operating revenues disaggregated by revenue source

Other Operating Revenues

Other operating revenues consist primarily of the following:

(in millions)	Three Months Ended June 30, 2018			Six Months Ended June 30, 2018
Late payment charges	$	2.1		$	4.9
Leases	1.4			2.2
Alternative revenues *	(0.5		)	(3.0		)
Total other operating revenues	$	3.0		$	4.1

* 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.

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PROPERTY, PLANT, AND EQUIPMENT (Tables)

6 Months Ended

Jun. 30, 2018

Restructuring cost and reserve

Schedule of changes to our severance liability

(in millions)
Severance liability at December 31, 2017	$	25.8
Severance payments	(8.7		)
Other	(3.0		)
Total severance liability at June 30, 2018	$	14.1

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SHORT-TERM DEBT AND LINES OF CREDIT (Tables)

6 Months Ended

Jun. 30, 2018

Short-term Debt [Abstract]

Schedule of short-term borrowings and weighted-average interest rates

The following table shows our short-term borrowings and their corresponding weighted-average interest rates:

(in millions, except percentages)	June 30, 2018			December 31, 2017
Commercial paper
Amount outstanding	$	341.8		$	210.9
Weighted-average interest rate on amounts outstanding	2.35		%	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	June 30, 2018
Revolving credit facility	October 2022	$	500.0
Less:
Letters of credit issued inside credit facility		$	1.2
Commercial paper outstanding		341.8
Available capacity under existing agreement		$	157.0

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MATERIALS, SUPPLIES, AND INVENTORIES (Tables)

6 Months Ended

Jun. 30, 2018

Inventory Disclosure [Abstract]

Schedule of inventory

Our inventory consisted of:

(in millions)	June 30, 2018		December 31, 2017
Materials and supplies	$	137.2	$	140.7
Fossil fuel	75.9		74.8
Natural gas in storage	23.6		35.2
Total	$	236.7	$	250.7

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FAIR VALUE MEASUREMENTS (Tables)

6 Months Ended

Jun. 30, 2018

Fair Value Disclosures [Abstract]

Fair value of assets and liabilities measured on a recurring basis, categorized by level within the fair value hierarchy

The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:

	June 30, 2018
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	1.5	$	—	$	—	$	1.5
Petroleum products contracts	0.3		—		—		0.3
FTRs	—		—		8.7		8.7
Coal contracts	—		0.5		—		0.5
Total derivative assets	$	1.8	$	0.5	$	8.7	$	11.0
Derivative liabilities
Natural gas contracts	$	0.1	$	—	$	—	$	0.1

	December 31, 2017
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	0.5	$	0.1	$	—	$	0.6
Petroleum products contracts	0.9		—		—		0.9
FTRs	—		—		2.4		2.4
Coal contracts	—		0.7		—		0.7
Total derivative assets	$	1.4	$	0.8	$	2.4	$	4.6
Derivative liabilities
Natural gas contracts	$	2.0	$	0.1	$	—	$	2.1
Coal contracts	—		0.3		—		0.3
Total derivative liabilities	$	2.0	$	0.4	$	—	$	2.4

Reconciliation of changes in fair value of items categorized as level 3 measurements

The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy:

	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2018			2017			2018			2017
Balance at the beginning of the period	$	0.8		$	1.1		$	2.4		$	3.1
Purchases	9.4			6.9			9.4			6.9
Settlements	(1.5		)	(2.0		)	(3.1		)	(4.0		)
Balance at the end of the period	$	8.7		$	6.0		$	8.7		$	6.0

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:

	June 30, 2018				December 31, 2017
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock	$	30.4	$	28.7	$	30.4	$	30.5
Long-term debt, including current portion	2,413.4		2,603.4		2,662.3		2,976.3

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DERIVATIVE INSTRUMENTS (Tables)

6 Months Ended

Jun. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative assets and derivative liabilities

The following table shows our derivative assets and derivative liabilities:

	June 30, 2018				December 31, 2017
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	1.5	$	—	$	0.6	$	1.9
Petroleum products contracts	0.3		—		0.9		—
FTRs	8.7		—		2.4		—
Coal contracts	0.5		—		0.6		0.1
Total other current *	$	11.0	$	—	$	4.5	$	2.0
Other long-term
Natural gas contracts	$	—	$	0.1	$	—	$	0.2
Coal contracts	—		—		0.1		0.2
Total other long-term *	—		0.1		0.1		0.4
Total	$	11.0	$	0.1	$	4.6	$	2.4

* On our balance sheets, we classify derivative assets and liabilities as other current or other long-term based on the maturities of the underlying contracts.

Estimated notional volumes and realized gains(losses)

Our estimated notional sales volumes and realized gains (losses) were as follows:

	Three Months Ended June 30, 2018				Three Months Ended June 30, 2017
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	12.0 Dth	$	(0.6	)	5.0 Dth	$	0.2
Petroleum products contracts	1.1 gallons	0.2			4.9 gallons	(0.4		)
FTRs	4.8 MWh	0.9			7.3 MWh	2.0
Total		$	0.5			$	1.8

	Six Months Ended June 30, 2018				Six Months Ended June 30, 2017
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	23.7 Dth	$	(2.4	)	13.2 Dth	$	0.7
Petroleum products contracts	2.5 gallons	0.6			9.8 gallons	(0.9		)
FTRs	10.6 MWh	1.7			14.3 MWh	4.5
Total		$	(0.1	)		$	4.3

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:

	June 30, 2018						December 31, 2017
(in millions)	Derivative Assets			Derivative Liabilities			Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	11.0		$	0.1		$	4.6		$	2.4
Gross amount not offset on the balance sheet	(0.1		)	(0.1		)	(1.3		)	(2.0		)	*
Net amount	$	10.9		$	—		$	3.3		$	0.4

* Includes cash collateral posted of $0.7 million.

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EMPLOYEE BENEFITS (Tables)

6 Months Ended

Jun. 30, 2018

Retirement Benefits [Abstract]

Schedule of net benefit costs

The following tables show the components of net periodic pension and OPEB costs for our benefit plans:

	Pension Costs
	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2018			2017			2018			2017
Service cost	$	3.3		$	3.1		$	6.6		$	6.1
Interest cost	10.5			11.6			21.1			23.5
Expected return on plan assets	(18.6		)	(19.1		)	(37.6		)	(38.3		)
Loss on plan settlement	—			2.8			—			2.8
Amortization of prior service cost	0.2			0.3			0.4			0.6
Amortization of net actuarial loss	9.6			8.9			19.0			17.7
Net periodic benefit cost	$	5.0		$	7.6		$	9.5		$	12.4

	OPEB Costs
	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2018			2017			2018			2017
Service cost	$	1.7		$	1.5		$	3.5		$	3.4
Interest cost	2.7			3.1			5.5			6.2
Expected return on plan assets	(3.9		)	(3.6		)	(7.8		)	(7.2		)
Amortization of prior service credit	(0.5		)	(0.3		)	(1.1		)	(0.6		)
Amortization of net actuarial gain	—			(0.3		)	—			—
Net periodic benefit cost	$	—		$	0.4		$	0.1		$	1.8

Schedule of non-service components

The following table shows the non-service (credit) cost components of net benefit costs:

	Three Months Ended June 30					Six Months Ended June 30
(in millions)	2018			2017		2018			2017
Non-service (credit) cost components	$	(1.2	)	$	3.3	$	(2.9	)	$	4.5

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SEGMENT INFORMATION (Tables)

6 Months Ended

Jun. 30, 2018

Segment Reporting [Abstract]

Schedule of information related to our reportable segments

The following tables show summarized financial information for the three and six months ended June 30, 2018 and 2017, related to our reportable segments:

(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Three Months Ended June 30, 2018
Operating revenues	$	856.2	$	—	$	856.2
Other operation and maintenance	366.6		—		366.6
Depreciation and amortization	86.9		—		86.9
Operating income	104.5		—		104.5
Interest expense	29.2		—		29.2

(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Three Months Ended June 30, 2017
Operating revenues	$	855.4	$	—	$	855.4
Other operation and maintenance *	324.4		—		324.4
Depreciation and amortization	82.7		—		82.7
Operating income *	146.1		—		146.1
Interest expense	29.1		—		29.1

* Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 12, Employee Benefits, for more information on this new standard.

(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Six Months Ended June 30, 2018
Operating revenues	$	1,797.7	$	—	$	1,797.7
Other operation and maintenance	702.2		—		702.2
Depreciation and amortization	172.2		—		172.2
Operating income	240.9		—		240.9
Interest expense	58.9		—		58.9

(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Six Months Ended June 30, 2017
Operating revenues	$	1,827.4	$	—	$	1,827.4
Other operation and maintenance *	651.0		—		651.0
Depreciation and amortization	164.8		—		164.8
Operating income *	332.4		—		332.4
Interest expense	58.4		0.3		58.7

* Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 12, Employee Benefits, for more information on this new standard.

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RELATED PARTIES (Tables)

6 Months Ended

Jun. 30, 2018

Related Party Transactions [Abstract]

Schedule of related party transactions balance sheet information

Our balance sheets included the following receivables and payables related to transactions entered into with ATC:

(in millions)	June 30, 2018		December 31, 2017
Accounts receivable
Services provided to ATC	$	1.3	$	0.8
Accounts payable
Services received from ATC	19.3		22.2

Schedule of activity associated with related party transactions

The following table shows activity associated with our related party transactions:

	Three Months Ended June 30				Six Months Ended June 30
(in millions)	2018		2017		2018		2017
Lease agreements
Lease payments to We Power (1)	$	95.1	$	106.7	$	187.3	$	211.1
Construction work in progress billed to We Power	5.0		8.9		8.8		25.2
Transactions with WBS (2)
Billings to WBS	2.8		60.5		8.7		117.0
Billings from WBS (3)	68.6		52.9		176.7		102.7
Transactions with WPS (2)
Billings to WPS	4.3		5.2		7.3		7.7
Billings from WPS	1.9		1.1		5.1		2.2
Transactions with WG
Natural gas purchases from WG	1.3		1.3		2.6		2.6
Billings to WG (2) (4)	13.2		16.1		27.1		31.9
Billings from WG (2)	5.0		5.8		9.7		11.3
Transactions with UMERC
Electric sales to UMERC	6.9		6.4		15.0		14.1
Billings to UMERC (2)	2.9		29.3		7.1		33.9
Transactions with Bluewater (5)
Storage service fees	4.6		—		5.9		—
Transactions with ATC
Charges to ATC for services and construction	2.7		2.4		5.7		5.2
Charges from ATC for network transmission services	58.1		60.4		116.1		120.7
Refund from ATC related to a FERC audit	15.4		—		15.4		—
Refund from ATC per FERC ROE order	—		—		—		19.4

⁽¹⁾  We make lease payments to We Power, another subsidiary of WEC Energy Group, for PWGS Units 1 and 2 and ERGS Units 1 and 2. Lease payments were reduced in 2018 as a result of tax savings related to Tax Legislation.

⁽²⁾  Includes amounts billed for services, pass through costs, and other items in accordance with approved affiliated interest agreements.

⁽³⁾  Includes $8.7 million and $57.6 million for the transfer of certain software assets from WBS during the three and six months ended June 30, 2018, respectively. There were no software assets transferred from WBS during 2017.

⁽⁴⁾  Includes $5.2 million for the transfer of certain software assets to WG during the three and six months ended June 30, 2018. There were no software assets transferred to WG during 2017.

⁽⁵⁾  WEC Energy Group's acquisition of Bluewater was completed June 30, 2017. See below for more information.

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COMMITMENTS AND CONTINGENCIES (Tables)

6 Months Ended

Jun. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Schedule of regulatory assets and reserves related to manufactured gas plant sites

We have established the following regulatory assets and reserves related to manufactured gas plant sites:

(in millions)	June 30, 2018		December 31, 2017
Regulatory assets	$	29.9	$	30.4
Reserves for future remediation *	18.5		18.5

* Recorded within other long-term liabilities on our balance sheets.

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SUPPLEMENTAL CASH FLOW INFORMATION (Tables)

6 Months Ended

Jun. 30, 2018

Supplemental Cash Flow Information [Abstract]

Schedule of supplemental cash flow information

	Six Months Ended June 30
(in millions)	2018			2017
Cash (paid) for interest, net of amount capitalized	$	(57.8	)	$	(57.6	)
Cash (paid) for income taxes, net	(8.2		)	(63.4		)
Significant noncash transactions:
Accounts payable related to construction costs	4.5			13.0
Accounts payable related to assets transferred from affiliates	7.5			—
Accounts receivable related to assets transferred to affiliates	5.4			—
Transfer of investment in ATC to another subsidiary of WEC Energy Group (1) (2)	—			415.4
Transfer of net assets to UMERC (1)	—			60.0

⁽¹⁾ See Note 15, 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.

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OPERATING REVENUES - DISAGGREGATION OF OPERATING REVENES (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Disaggregation of Operating Revenues
Operating revenues	$ 856.2	$ 855.4	$ 1,797.7	$ 1,827.4
Utility segment
Disaggregation of Operating Revenues
Operating revenues	856.2	$ 855.4	1,797.7	$ 1,827.4
Utility segment | Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	3.0		4.1
Utility segment | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Operating revenues	853.2		1,793.6
Utility segment | Electric | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Operating revenues	784.6		1,564.2
Utility segment | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Operating revenues	$ 68.6		$ 229.4

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OPERATING REVENUES ELECTRIC UTILITY OPERATING REVENUES (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)	Jun. 30, 2018 USD ($) contract performance_obligations	Jun. 30, 2017 USD ($)
Disaggregation of Operating Revenues
Operating revenues	$ 856.2	$ 855.4	$ 1,797.7	$ 1,827.4
Electric
Disaggregation of Operating Revenues
Number of performance obligations | performance_obligations			1
Number of contracts | contract			1
Number of days payment is due			30 days
Electric | Wholesale
Disaggregation of Operating Revenues
Number of performance obligations | performance_obligations			2
Utility segment
Disaggregation of Operating Revenues
Operating revenues	856.2	$ 855.4	$ 1,797.7	$ 1,827.4
Revenues from contracts with customers | Utility segment | Transferred over time
Disaggregation of Operating Revenues
Operating revenues	853.2		1,793.6
Revenues from contracts with customers | Utility segment | Electric | Transferred over time
Disaggregation of Operating Revenues
Operating revenues	784.6		1,564.2
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Residential
Disaggregation of Operating Revenues
Operating revenues	295.0		576.4
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Small commercial and industrial
Disaggregation of Operating Revenues
Operating revenues	260.6		498.3
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Large commercial and industrial
Disaggregation of Operating Revenues
Operating revenues	172.4		321.3
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Other
Disaggregation of Operating Revenues
Operating revenues	4.9		10.3
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Total retail
Disaggregation of Operating Revenues
Operating revenues	732.9		1,406.3
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Wholesale
Disaggregation of Operating Revenues
Operating revenues	28.9		57.4
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Resale
Disaggregation of Operating Revenues
Operating revenues	17.1		80.8
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Steam
Disaggregation of Operating Revenues
Operating revenues	4.6		14.3
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Other utility
Disaggregation of Operating Revenues
Operating revenues	$ 1.1		$ 5.4

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OPERATING REVENUES NATURAL GAS UTILITY OPERATING REVENUES (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Disaggregation of Operating Revenues
Operating revenues	$ 856.2	$ 855.4	$ 1,797.7	$ 1,827.4
Natural gas
Disaggregation of Operating Revenues
Number of days payment is due			30 days
Utility segment
Disaggregation of Operating Revenues
Operating revenues	856.2	$ 855.4	$ 1,797.7	$ 1,827.4
Revenues from contracts with customers | Utility segment | Transferred over time
Disaggregation of Operating Revenues
Operating revenues	853.2		1,793.6
Revenues from contracts with customers | Utility segment | Natural gas | Transferred over time
Disaggregation of Operating Revenues
Operating revenues	68.6		229.4
Revenues from contracts with customers | Utility segment | Natural gas | Transferred over time | Residential
Disaggregation of Operating Revenues
Operating revenues	40.7		155.4
Revenues from contracts with customers | Utility segment | Natural gas | Transferred over time | Commercial and industrial
Disaggregation of Operating Revenues
Operating revenues	18.2		73.8
Revenues from contracts with customers | Utility segment | Natural gas | Transferred over time | Total retail
Disaggregation of Operating Revenues
Operating revenues	58.9		229.2
Revenues from contracts with customers | Utility segment | Natural gas | Transferred over time | Transport
Disaggregation of Operating Revenues
Operating revenues	3.1		7.5
Revenues from contracts with customers | Utility segment | Natural gas | Transferred over time | Other utility
Disaggregation of Operating Revenues
Operating revenues	$ 6.6		$ (7.3)

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OPERATING REVENUES - OTHER OPERATING REVENUES (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Disaggregation of Operating Revenues
Operating revenues	$ 856.2	$ 855.4	$ 1,797.7	$ 1,827.4
Utility segment
Disaggregation of Operating Revenues
Operating revenues	856.2	$ 855.4	1,797.7	$ 1,827.4
Utility segment | Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	3.0		4.1
Utility segment | Other operating revenues | Late payment charges
Disaggregation of Operating Revenues
Operating revenues	2.1		4.9
Utility segment | Other operating revenues | Leases
Disaggregation of Operating Revenues
Operating revenues	1.4		2.2
Utility segment | Other operating revenues | Alternative revenues
Disaggregation of Operating Revenues
Operating revenues	$ (0.5)		$ (3.0)

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PROPERTY, PLANT, AND EQUIPMENT (Details) $ in Millions	1 Months Ended	6 Months Ended
	Oct. 31, 2017 MW	Jun. 30, 2018 USD ($)
UMERC
Property, plant, and equipment
Capacity of natural gas-fired generation facility (in megawatts) | MW	180
Pleasant Prairie power plant
Property, plant, and equipment
Plant to be retired, at carrying value		$ 667.7
Plant to be retired, Net		774.2
Cost of removal reserve		106.5
Presque Isle power plant
Property, plant, and equipment
Plant to be retired, at carrying value		189.7
Plant to be retired, Net		199.8
Cost of removal reserve		10.1
Utility segment
Changes to severance liability
Severance liability, balance at beginning of period		25.8
Severance payments		(8.7)
Other		(3.0)
Severance liability, balance at end of the period		$ 14.1

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SHORT-TERM DEBT AND LINES OF CREDIT - SHORT-TERM BORROWINGS (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Short-term borrowings
Commercial paper outstanding	$ 341.8	$ 210.9
Commercial paper
Short-term borrowings
Weighted-average interest rate on amounts outstanding	2.35%	1.81%
Average amount outstanding during the period	$ 79.2
Weighted-average interest rate during the period	2.06%

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SHORT-TERM DEBT AND LINES OF CREDIT - REVOLVING CREDIT FACILITIES (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Revolving credit facility
Letters of credit issued inside credit facility	$ 1.2
Commercial paper outstanding	341.8	$ 210.9
Available capacity under existing agreement	157.0
Credit facility maturing during October 2022
Revolving credit facility
Revolving credit facility	$ 500.0

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LONG-TERM DEBT (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Jul. 31, 2018
WE Debentures due 2018
Debt Instrument [Line Items]
Retirement of long-term debt	$ 250.0
Interest rate on long-term debt	1.70%
Subsequent event
Debt Instrument [Line Items]
Long-term Pollution Control Bond		$ 80.0

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MATERIALS, SUPPLIES, AND INVENTORIES (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Inventory Disclosure [Abstract]
Materials and supplies	$ 137.2	$ 140.7
Fossil fuel	75.9	74.8
Natural gas in storage	23.6	35.2
Total	$ 236.7	$ 250.7

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INCOME TAXES (Details)	1 Months Ended	3 Months Ended	6 Months Ended
	Dec. 31, 2017	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2017
Effective Income Tax Rate Reconciliation, Percent
Total income tax benefit, percentage		(2.80%)	(3.20%)
Statutory federal income tax, percentage			21.00%	35.00%
Measurement period to complete accounting related to Tax Cuts and Jobs Act	1 year

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FAIR VALUE MEASUREMENTS - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Assets
Derivative asset	$ 11.0	$ 4.6
Liabilities
Derivative liability	0.1	2.4
Fair value measurements on a recurring basis
Assets
Derivative asset	11.0	4.6
Liabilities
Derivative liability		2.4
Fair value measurements on a recurring basis | Level 1
Assets
Derivative asset	1.8	1.4
Liabilities
Derivative liability		2.0
Fair value measurements on a recurring basis | Level 2
Assets
Derivative asset	0.5	0.8
Liabilities
Derivative liability		0.4
Fair value measurements on a recurring basis | Level 3
Assets
Derivative asset	8.7	2.4
Liabilities
Derivative liability		0.0
Fair value measurements on a recurring basis | Natural gas contracts
Assets
Derivative asset	1.5	0.6
Liabilities
Derivative liability	0.1	2.1
Fair value measurements on a recurring basis | Natural gas contracts | Level 1
Assets
Derivative asset	1.5	0.5
Liabilities
Derivative liability	0.1	2.0
Fair value measurements on a recurring basis | Natural gas contracts | Level 2
Assets
Derivative asset	0.0	0.1
Liabilities
Derivative liability	0.0	0.1
Fair value measurements on a recurring basis | Natural gas contracts | Level 3
Assets
Derivative asset	0.0	0.0
Liabilities
Derivative liability	0.0	0.0
Fair value measurements on a recurring basis | Petroleum products contracts
Assets
Derivative asset	0.3	0.9
Fair value measurements on a recurring basis | Petroleum products contracts | Level 1
Assets
Derivative asset	0.3	0.9
Fair value measurements on a recurring basis | Petroleum products contracts | Level 2
Assets
Derivative asset	0.0	0.0
Fair value measurements on a recurring basis | Petroleum products contracts | Level 3
Assets
Derivative asset	0.0	0.0
Fair value measurements on a recurring basis | FTRs
Assets
Derivative asset	8.7	2.4
Fair value measurements on a recurring basis | FTRs | Level 1
Assets
Derivative asset	0.0	0.0
Fair value measurements on a recurring basis | FTRs | Level 2
Assets
Derivative asset	0.0	0.0
Fair value measurements on a recurring basis | FTRs | Level 3
Assets
Derivative asset	8.7	2.4
Fair value measurements on a recurring basis | Coal contracts
Assets
Derivative asset	0.5	0.7
Liabilities
Derivative liability		0.3
Fair value measurements on a recurring basis | Coal contracts | Level 1
Assets
Derivative asset	0.0	0.0
Liabilities
Derivative liability		0.0
Fair value measurements on a recurring basis | Coal contracts | Level 2
Assets
Derivative asset	0.5	0.7
Liabilities
Derivative liability		0.3
Fair value measurements on a recurring basis | Coal contracts | Level 3
Assets
Derivative asset	$ 0.0	0.0
Liabilities
Derivative liability		$ 0.0

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FAIR VALUE MEASUREMENTS - LEVEL 3 RECONCILIATION (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Level 3 rollforward
Balance at the beginning of the period	$ 0.8	$ 1.1	$ 2.4	$ 3.1
Purchases	9.4	6.9	9.4	6.9
Settlements	(1.5)	(2.0)	(3.1)	(4.0)
Balance at the end of the period	$ 8.7	$ 6.0	$ 8.7	$ 6.0

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FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Carrying value and estimated fair value of financial instruments
Preferred stock	$ 30.4	$ 30.4
Carrying Amount
Carrying value and estimated fair value of financial instruments
Preferred stock	30.4	30.4
Long-term debt, including current portion	2,413.4	2,662.3
Fair Value
Carrying value and estimated fair value of financial instruments
Preferred stock	28.7	30.5
Long-term debt, including current portion	$ 2,603.4	$ 2,976.3

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DERIVATIVE INSTRUMENTS - DERIVATIVE ASSETS AND DERIVATIVE LIABILITIES (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Derivative Asset
Other current derivative assets	$ 11.0	$ 4.5
Other long-term derivative assets	0.0	0.1
Derivative asset	11.0	4.6
Derivative Liability
Other current derivative liabilities	0.0	2.0
Other long-term derivative liabilities	0.1	0.4
Derivative liability	0.1	2.4
Natural gas contracts
Derivative Asset
Other current derivative assets	1.5	0.6
Other long-term derivative assets	0.0	0.0
Derivative Liability
Other current derivative liabilities	0.0	1.9
Other long-term derivative liabilities	0.1	0.2
Petroleum products contracts
Derivative Asset
Other current derivative assets	0.3	0.9
Derivative Liability
Other current derivative liabilities	0.0	0.0
FTRs
Derivative Asset
Other current derivative assets	8.7	2.4
Derivative Liability
Other current derivative liabilities	0.0	0.0
Coal contracts
Derivative Asset
Other current derivative assets	0.5	0.6
Other long-term derivative assets	0.0	0.1
Derivative Liability
Other current derivative liabilities	0.0	0.1
Other long-term derivative liabilities	$ 0.0	$ 0.2

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DERIVATIVE INSTRUMENTS - GAINS (LOSSES) AND NOTIONAL VOLUMES (Details) gal in Millions, MWh in Millions, MMBTU in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018 USD ($) MWh MMBTU gal	Jun. 30, 2017 USD ($) MWh MMBTU gal	Jun. 30, 2018 USD ($) MWh MMBTU gal	Jun. 30, 2017 USD ($) MWh MMBTU gal
Realized Gain (Loss) on Derivatives
Gains (Losses)	$ 0.5	$ 1.8	$ (0.1)	$ 4.3
Natural gas contracts
Realized Gain (Loss) on Derivatives
Gains (Losses)	$ (0.6)	$ 0.2	$ (2.4)	$ 0.7
Notional Sales Volumes
Notional sales volumes | MMBTU	12.0	5.0	23.7	13.2
Petroleum products contracts
Realized Gain (Loss) on Derivatives
Gains (Losses)	$ 0.2	$ (0.4)	$ 0.6	$ (0.9)
Notional Sales Volumes
Notional sales volumes (gallons) | gal	1.1	4.9	2.5	9.8
FTRs
Realized Gain (Loss) on Derivatives
Gains (Losses)	$ 0.9	$ 2.0	$ 1.7	$ 4.5
Notional Sales Volumes
Notional sales volumes | MWh	4.8	7.3	10.6	14.3

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DERIVATIVE INSTRUMENTS - OFFSETTING TABLE (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Cash collateral
Collateral in margin account	$ 1.0	$ 4.9
Offsetting Derivative Assets
Gross amount recognized on the balance sheet	11.0	4.6
Gross amount not offset on the balance sheet	(0.1)	(1.3)
Net amount	10.9	3.3
Offsetting Derivative Liabilities
Gross amount recognized on the balance sheet	0.1	2.4
Gross amount not offset on the balance sheet	(0.1)	(2.0)
Net amount	$ 0.0	0.4
Collateral posted		$ 0.7

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EMPLOYEE BENEFITS-COSTS AND CONTRIBUTIONS (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Components of net periodic benefit costs
Contributions and payments related to pension and OPEB plans			$ 3.8	$ 5.6
Pension Costs
Components of net periodic benefit costs
Service cost	$ 3.3	$ 3.1	6.6	6.1
Interest cost	10.5	11.6	21.1	23.5
Expected return on plan assets	(18.6)	(19.1)	(37.6)	(38.3)
Loss on plan settlement	0.0	2.8	0.0	2.8
Amortization of prior service cost	0.2	0.3	0.4	0.6
Amortization of net actuarial loss	9.6	8.9	19.0	17.7
Net periodic benefit cost	5.0	7.6	9.5	12.4
Contributions and payments related to pension and OPEB plans			2.9
Estimated future employer contributions for the remainder of the year	1.2		1.2
Other Postretirement Benefit Costs
Components of net periodic benefit costs
Service cost	1.7	1.5	3.5	3.4
Interest cost	2.7	3.1	5.5	6.2
Expected return on plan assets	(3.9)	(3.6)	(7.8)	(7.2)
Amortization of prior service cost	(0.5)	(0.3)	(1.1)	(0.6)
Amortization of net actuarial loss	0.0	(0.3)	0.0	0.0
Net periodic benefit cost	0.0	$ 0.4	0.1	$ 1.8
Contributions and payments related to pension and OPEB plans			0.9
Estimated future employer contributions for the remainder of the year	$ 3.5		$ 3.5

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EMPLOYEE BENEFITS-IMPACT OF ADOPTION OF ASU 2017-07 (Details) - Accounting Standards Update 2017-07 - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Non-service (credit)cost components of net benefit cost	$ (1.2)		$ (2.9)
Impact of ASU 2017-07
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Non-service (credit)cost components of net benefit cost		$ 3.3		$ 4.5

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SEGMENT INFORMATION (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018 USD ($) customer	Jun. 30, 2017 USD ($)	Jun. 30, 2018 USD ($) area segment customer	Jun. 30, 2017 USD ($)
Segment information
Number of reportable segments | segment			2
Operating revenues	$ 856.2	$ 855.4	$ 1,797.7	$ 1,827.4
Other operation and maintenance	366.6	324.4	702.2	651.0
Depreciation and amortization	86.9	82.7	172.2	164.8
Operating income	104.5	146.1	240.9	332.4
Interest expense	$ 29.2	29.1	$ 58.9	58.7
Michigan
Segment information
Number of customers | customer	1		1
Utility segment
Segment information
Number of service areas | area			3
Operating revenues	$ 856.2	855.4	$ 1,797.7	1,827.4
Other operation and maintenance	366.6	324.4	702.2	651.0
Depreciation and amortization	86.9	82.7	172.2	164.8
Operating income	104.5	146.1	240.9	332.4
Interest expense	29.2	29.1	58.9	58.4
Other segments
Segment information
Operating revenues	0.0	0.0	0.0	0.0
Other operation and maintenance	0.0	0.0	0.0	0.0
Depreciation and amortization	0.0	0.0	0.0	0.0
Operating income	0.0	0.0	0.0	0.0
Interest expense	$ 0.0	$ 0.0	$ 0.0	$ 0.3

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VARIABLE INTEREST ENTITIES (Details) - Purchased power agreement $ in Millions	6 Months Ended
	Jun. 30, 2018 USD ($) MW	Jun. 30, 2017 USD ($)
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	$ 0.0
Required payments over remaining term of purchased power agreement	64.1
Total capacity and lease payments	$ 9.4	$ 9.0

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RELATED PARTIES (Details) - ATC - USD ($) $ in Millions		12 Months Ended
	Jan. 01, 2017	Dec. 31, 2017	Jun. 30, 2018
Related parties
Transfer equity method investment and related receivable for distributions transfer to affiliated company	$ 415.4
Transfer of deferred income tax related to ATC to affiliated company		$ 186.8
Accounts receivable, related parties, current		0.8	$ 1.3
Accounts payable, related parties, current		$ 22.2	$ 19.3

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RELATED PARTIES - OTHER TRANSACTIONS (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Related parties
Proceeds from transfer of assets to related party				$ (50.1)	$ 0.0
We Power LLC
Related parties
Lease payments to W.E. Power, LLC		$ 95.1	$ 106.7	187.3	211.1
Construction work In progress billed to related party		5.0	8.9	8.8	25.2
WBS
Related parties
Charges to related party for services and billings		2.8	60.5	8.7	117.0
Charges from related party for services and billings		68.6	52.9	176.7	102.7
Payments for transfer of assets from related parties		8.7		57.6	0.0
WPS
Related parties
Charges to related party for services and billings		4.3	5.2	7.3	7.7
Charges from related party for services and billings		1.9	1.1	5.1	2.2
WG
Related parties
Charges to related party for services and billings		13.2	16.1	27.1	31.9
Charges from related party for services and billings		5.0	5.8	9.7	11.3
Natural gas purchases		1.3	1.3	2.6	2.6
Proceeds from transfer of assets to related party		5.2		5.2	0.0
UMERC
Related parties
Charges to related party for services and billings		2.9	29.3	7.1	33.9
Electric sales to UMERC		6.9	6.4	15.0	14.1
Bluewater
Related parties
Charges from related party for services and billings		4.6	0.0	5.9	0.0
Purchase price	$ 226.0
ATC
Related parties
Charges to related party for services and billings		2.7	2.4	5.7	5.2
Charges from related party for services and billings		58.1	60.4	116.1	120.7
Refund from ATC related to a FERC audit		15.4	0.0	15.4	0.0
Refund from ATC per FERC ROE order		$ 0.0	$ 0.0	$ 0.0	$ 19.4

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RELATED PARTIES - UMERC (Details) - UMERC transfer $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)	Jan. 01, 2017 mile customer
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

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COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Millions	Jun. 30, 2018 USD ($)
Minimum future commitments for purchase obligations
Purchase obligations	$ 9,760.2

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COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) $ in Millions	1 Months Ended	6 Months Ended
	Oct. 31, 2014 compliance_option	Jun. 30, 2018 USD ($) degreecelsius MW	Dec. 31, 2017 USD ($)
Climate Change | Electric
Air quality
Company goal for percentage of carbon dioxide emissions reduction by 2030		40.00%
Long-term company goal for percentage of carbon dioxide emissions reduction by 2050		80.00%
Coal generation capacity expected to be retired by 2020 | MW		1,547
Climate Change | Electric | Maximum
Air quality
Global temperature increases limit | degreecelsius		2
Clean Water Act Cooling Water Intake Structure Rule | Electric
Water quality
Number of compliance options available to meet standard | compliance_option	7
Steam Electric Effluent Limitation Guidelines | Electric
Water quality
Renewal period for facility permits		5 years
Expected costs to achieve required emissions reduction		$ 50.0
Manufactured Gas Plant Remediation | Natural gas
Manufactured gas plant remediation
Regulatory assets recorded for remediation of manufactured gas plant sites		29.9	$ 30.4
Reserves recorded for remediation of manufactured gas plant sites		$ 18.5	$ 18.5

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SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2016
Supplemental Cash Flow Information [Abstract]
Cash (paid) for interest, net of amount capitalized	$ (57.8)	$ (57.6)
Cash (paid) for income taxes, net	(8.2)	(63.4)
Significant noncash transactions
Accounts payable related to construction costs	4.5	13.0
Assets transferred between affiliates
Significant noncash transactions
Accounts payable related to assets transferred from affiliates	7.5	0.0
Accounts receivable related to assets transferred to affiliates	5.4	0.0
ATC
Significant noncash transactions
Transfer of investment in ATC to another subsidiary of WEC Energy Group	0.0	415.4
Distributions receivable from ATC			$ 13.4
UMERC
Significant noncash transactions
Transfer of net assets to UMERC	$ 0.0	$ 60.0

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REGULATORY ENVIRONMENT (Details) $ in Millions	1 Months Ended			6 Months Ended
	May 31, 2018	Dec. 31, 2017 USD ($)	Sep. 30, 2017	Jun. 30, 2018 USD ($) customer	Jun. 30, 2017
Regulatory environment
Corporate federal tax rate (as a percent)				21.00%	35.00%
Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates
Regulatory environment
Approved return on equity (as a percent)			10.20%
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		$ 1,065.0
Electric rates | Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates
Regulatory environment
Percentage of current tax benefit from Tax Cuts and Jobs Act of 2017 to be used to reduce certain regulatory assets	80.00%
Percent of current tax benefit from Tax Cuts and Jobs Act of 2017 to be returned to customers via bill credits	20.00%
Decrease in Regulatory Assets Related to PSCW Tax Legislation Ruling				$ 33.8
Natural gas rates | Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates
Regulatory environment
Percent of current tax benefit from Tax Cuts and Jobs Act of 2017 to be returned to customers via bill credits	100.00%