WELPP 10-Q Quarterly Report Sept. 30, 2018

WISCONSIN ELECTRIC POWER CO

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10-Q 1 a2018q3we10q.htm WISCONSIN ELECTRIC SEPTEMBER 30, 2018 FORM 10-Q Document

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 September 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

September 30, 2018

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

Table of Contents

WISCONSIN ELECTRIC POWER COMPANY

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended September 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	Regulatory Assets and Liabilities	10
	Note 5	Property, Plant, and Equipment	11
	Note 6	Common Equity	11
	Note 7	Short-Term Debt and Lines of Credit	11
	Note 8	Long-Term Debt	12
	Note 9	Materials, Supplies, and Inventories	12
	Note 10	Income Taxes	12
	Note 11	Fair Value Measurements	13
	Note 12	Derivative Instruments	14
	Note 13	Employee Benefits	16
	Note 14	Segment Information	17
	Note 15	Variable Interest Entities	18
	Note 16	Related Parties	18
	Note 17	Commitments and Contingencies	20
	Note 18	Supplemental Cash Flow Information	23
	Note 19	Regulatory Environment	23
	Note 20	New Accounting Pronouncements	24
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			25
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			40
ITEM 4.	CONTROLS AND PROCEDURES			41
PART II.	OTHER INFORMATION			42
ITEM 1.	LEGAL PROCEEDINGS			42
ITEM 1A.	RISK FACTORS			42
ITEM 6.	EXHIBITS			43
SIGNATURE				44



09/30/2018 Form 10-Q	i	Wisconsin Electric Power Company

Table of Contents

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
CO ₂		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



09/30/2018 Form 10-Q	ii	Wisconsin Electric Power Company

Table of Contents



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



09/30/2018 Form 10-Q	iii	Wisconsin Electric Power Company

Table of Contents

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 rates, 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;



09/30/2018 Form 10-Q	1	Wisconsin Electric Power Company

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•	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 Energy Group, 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.



09/30/2018 Form 10-Q	2	Wisconsin Electric Power Company

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WISCONSIN ELECTRIC POWER COMPANY



CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited)	Three Months Ended						Nine Months Ended
	September 30						September 30
(in millions)	2018			2017			2018			2017
Operating revenues	$	924.0		$	943.8		$	2,721.7		$	2,771.2

Operating expenses
Cost of sales	316.5			336.5			944.4			959.0
Other operation and maintenance	384.7			331.2			1,086.9			982.2
Depreciation and amortization	87.4			83.0			259.6			247.8
Property and revenue taxes	27.6			28.3			82.1			85.0
Total operating expenses	816.2			779.0			2,373.0			2,274.0

Operating income	107.8			164.8			348.7			497.2

Other income, net	5.1			4.1			16.2			8.4
Interest expense	29.9			29.3			88.8			88.0
Other expense	(24.8		)	(25.2		)	(72.6		)	(79.6		)

Income before income taxes	83.0			139.6			276.1			417.6
Income tax (benefit) expense	(20.5		)	49.9			(26.6		)	150.2
Net income	103.5			89.7			302.7			267.4

Preferred stock dividend requirements	0.3			0.3			0.9			0.9
Net income attributed to common shareholder	$	103.2		$	89.4		$	301.8		$	266.5

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



09/30/2018 Form 10-Q	3	Wisconsin Electric Power Company

Table of Contents

WISCONSIN ELECTRIC POWER COMPANY



CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts)	September 30, 2018		December 31, 2017
Assets
Current assets
Cash and cash equivalents	$	4.1	$	12.3
Accounts receivable and unbilled revenues, net of reserves of $41.6 and $39.5, respectively	453.4		513.8
Accounts receivable from related parties	97.8		109.1
Materials, supplies, and inventories	255.8		250.7
Prepayments	93.7		144.3
Other	10.4		9.4
Current assets	915.2		1,039.6

Long-term assets
Property, plant, and equipment, net of accumulated depreciation of $3,424.2 and $3,741.8, respectively	9,450.0		10,007.7
Regulatory assets	2,892.1		1,984.9
Other	97.7		89.4
Long-term assets	12,439.8		12,082.0
Total assets	$	13,355.0	$	13,121.6

Liabilities and Equity
Current liabilities
Short-term debt	$	346.0	$	210.9
Current portion of long-term debt	—		250.0
Current portion of capital lease obligations	48.2		42.5
Accounts payable	225.2		329.3
Accounts payable to related parties	161.4		131.5
Accrued payroll and benefits	42.4		53.4
Accrued taxes	80.4		58.2
Other	112.3		111.8
Current liabilities	1,015.9		1,187.6

Long-term liabilities
Long-term debt	2,413.9		2,412.3
Capital lease obligations	2,819.5		2,823.8
Deferred income taxes	1,216.6		1,155.5
Regulatory liabilities	1,899.1		1,708.0
Pension and OPEB obligations	153.5		143.2
Other	291.8		276.9
Long-term liabilities	8,794.4		8,519.7

Commitments and contingencies (Note 17)

Common shareholder's equity
Common stock – $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding	332.9		332.9
Additional paid in capital	831.2		802.7
Retained earnings	2,350.2		2,248.3
Common shareholder's equity	3,514.3		3,383.9

Preferred stock	30.4		30.4
Total liabilities and equity	$	13,355.0	$	13,121.6

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



09/30/2018 Form 10-Q	4	Wisconsin Electric Power Company

Table of Contents

WISCONSIN ELECTRIC POWER COMPANY



CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Nine Months Ended
	September 30
(in millions)	2018			2017
Operating Activities
Net income	$	302.7		$	267.4
Reconciliation to cash provided by operating activities
Depreciation and amortization	259.6			247.8
Deferred income taxes and investment tax credits, net	(67.3		)	105.2
Contributions and payments related to pension and OPEB plans	(5.3		)	(5.9		)
Change in –
Accounts receivable and unbilled revenues	74.4			49.0
Materials, supplies, and inventories	(5.1		)	(23.6		)
Prepaid taxes	32.3			31.2
Other current assets	22.4			5.3
Accounts payable	(65.0		)	(14.6		)
Accrued taxes	25.7			(15.2		)
Other current liabilities	(6.3		)	(15.6		)
Other, net	198.1			(36.7		)
Net cash provided by operating activities	766.2			594.3

Investing Activities
Capital expenditures	(441.7		)	(405.7		)
Proceeds from the sale of assets	0.7			22.9
Proceeds from assets transferred to affiliates	6.1			—
Payments for assets transferred from affiliates	(59.8		)	—
Short-term notes receivable from related parties, net	—			(3.1		)
Other, net	8.2			3.8
Net cash used in investing activities	(486.5		)	(382.1		)

Financing Activities
Change in short-term debt	135.1			(100.0		)
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	(200.0		)	(180.0		)
Payment of preferred stock dividends	(0.9		)	(0.9		)
Other	(0.1		)	0.1
Net cash used in financing activities	(287.9		)	(224.3		)

Net change in cash and cash equivalents	(8.2		)	(12.1		)
Cash and cash equivalents at beginning of period	12.3			15.4
Cash and cash equivalents at end of period	$	4.1		$	3.3

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



09/30/2018 Form 10-Q	5	Wisconsin Electric Power Company

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WISCONSIN ELECTRIC POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

September 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, which was dissolved in October 2018.

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

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

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.



09/30/2018 Form 10-Q	6	Wisconsin Electric Power Company

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


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


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

Disaggregation of Operating Revenues

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

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



	Wisconsin Electric Power Company Consolidated
(in millions)	Three Months Ended September 30, 2018		Nine Months Ended September 30, 2018
Electric utility	$	877.0	$	2,441.2
Natural gas utility	45.4		274.8
Total revenues from contracts with customers	922.4		2,716.0
Other operating revenues	1.6		5.7
Total operating revenues	$	924.0	$	2,721.7

Revenues from Contracts with Customers

Electric Utility Operating Revenues

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



	Electric Utility Operating Revenues
(in millions)	Three Months Ended September 30, 2018		Nine Months Ended September 30, 2018
Residential	$	352.7	$	929.1
Small commercial and industrial	276.9		775.2
Large commercial and industrial	177.9		499.2
Other	5.2		15.5
Total retail revenues	812.7		2,219.0
Wholesale	28.3		85.7
Resale	31.0		111.8
Steam	2.6		16.9
Other utility revenues	2.4		7.8
Total electric utility operating revenues	$	877.0	$	2,441.2

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



09/30/2018 Form 10-Q	7	Wisconsin Electric Power Company

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monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month.

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

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

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

Natural Gas Utility Operating Revenues

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



	Natural Gas Utility Operating Revenues
(in millions)	Three Months Ended September 30, 2018		Nine Months Ended September 30, 2018
Residential	$	20.8	$	176.2
Commercial and industrial	8.1		81.9
Total retail revenues	28.9		258.1
Transport	2.2		9.7
Other utility revenues *	14.3		7.0
Total natural gas utility operating revenues	$	45.4	$	274.8


*	Includes amounts collected from customers for purchased gas adjustment costs.

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



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territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer.

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

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

Other Operating Revenues

Other operating revenues consist primarily of the following:



(in millions)	Three Months Ended September 30, 2018			Nine Months Ended September 30, 2018
Late payment charges	$	1.6		$	6.5
Leases	0.3			2.5
Alternative revenues *	(0.3		)	(3.3		)
Total other operating revenues	$	1.6		$	5.7


*	Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to wholesale true-ups, as discussed below.

Alternative Revenues

Alternative revenues are created from programs authorized by regulators that allow us to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers.

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



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NOTE 4— REGULATORY ASSETS AND LIABILITIES

The following regulatory assets were reflected on our balance sheets at September 30, 2018 and December 31, 2017 . For more information on our regulatory assets, see Note 5, Regulatory Assets and Liabilities, in our 2017 Annual Report on Form 10-K.



(in millions)	September 30, 2018		December 31, 2017
Regulatory assets ⁽¹⁾
Capital leases	$	853.4	$	801.3
Plant retirements ⁽²⁾	760.9		6.6
Unrecognized pension and OPEB costs	455.3		484.4
System support resource	315.0		298.9
Income tax ⁽³⁾	256.5		—
Electric transmission costs ⁽⁴⁾	123.6		220.7
We Power generation	48.7		71.3
Asset retirement obligations	37.2		41.4
Environmental remediation costs	29.7		30.4
Other, net	11.8		29.9
Total regulatory assets	$	2,892.1	$	1,984.9


⁽¹⁾	Based on prior and current rate treatment, we believe it is probable that we will continue to recover from customers the regulatory assets in this table.


⁽²⁾	For information on the retirement of our older and less efficient fossil fuel generating units, see Note 5, Property, Plant, and Equipment .


⁽³⁾	For information on the flow through of tax repairs and the regulatory treatment of the Tax Legislation, see Note 19, Regulatory Environment .


⁽⁴⁾	In May 2018, the PSCW issued an order requiring us to use a portion of our tax benefits related to the Tax Legislation that was signed into law in December 2017 to reduce our transmission regulatory assets. See Note 19, Regulatory Environment, for more information .

The following regulatory liabilities were reflected on our balance sheets at September 30, 2018 and December 31, 2017 . For more information on our regulatory liabilities, see Note 5, Regulatory Assets and Liabilities, in our 2017 Annual Report on Form 10-K.



(in millions)	September 30, 2018		December 31, 2017
Regulatory liabilities
Income tax *	$	983.7	$	849.1
Removal costs	743.1		730.0
Mines deferral	115.4		95.1
Energy efficiency programs	12.9		11.1
Uncollectible expense	11.7		6.4
Other, net	38.4		29.4
Total regulatory liabilities	$	1,905.2	$	1,721.1

Balance Sheet Presentation
Current liabilities	$	6.1	$	13.1
Regulatory liabilities	1,899.1		1,708.0
Total regulatory liabilities	$	1,905.2	$	1,721.1


*	For information on the regulatory treatment of the Tax Legislation, see Note 19, Regulatory Environment .



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NOTE 5— PROPERTY, PLANT, AND EQUIPMENT

Utility Segment Plant to be Retired

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



(in millions)
Severance liability at December 31, 2017	$	25.8
Severance payments	(9.5		)
Other	(3.0		)
Total severance liability at September 30, 2018	$	13.3

Pleasant Prairie Power Plant

The Pleasant Prairie power plant was retired effective April 10, 2018. The carrying value of this plant was $653.3 million at September 30, 2018 . This amount included the net book value of $755.8 million , which was classified as a regulatory asset on our balance sheet. In addition, a $102.5 million cost of removal reserve related to the Pleasant Prairie power plant was classified as a regulatory liability at September 30, 2018 . We continue to amortize this regulatory asset on a straight-line basis using the composite depreciation rates approved by the PSCW before this plant was retired. Amortization is included in depreciation and amortization in the income statement. The physical dismantlement of the plant will not occur immediately. It may take several years to finalize long-term plans for the site. See Note 17, Commitments and Contingencies, for more information .

Presque Isle Power Plant

In October 2017, the MPSC approved UMERC’s application to construct and operate approximately 180 MW of natural gas-fired generation in the Upper Peninsula of Michigan. The new units are expected to begin commercial operation during the second quarter of 2019. Upon receiving the MPSC's approval, retirement of the PIPP generating units became probable. In connection with MISO's April 2018 approval of the retirement of the plant, the PIPP units will be retired on or before May 31, 2019. The carrying value of the PIPP units was $186.9 million at September 30, 2018 . This amount included the net book value of $197.4 million , which was classified as plant to be retired within property, plant, and equipment on our balance sheet. In addition, a $10.5 million cost of removal reserve related to the PIPP units was classified as a regulatory liability at September 30, 2018 . These units are included in rate base, and we continue to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW. See Note 17, Commitments and Contingencies, for more information .

NOTE 6— 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 7—

SHORT-TERM DEBT AND LINES OF CREDIT

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



(in millions, except percentages)	September 30, 2018			December 31, 2017
Commercial paper
Amount outstanding	$	346.0		$	210.9
Weighted-average interest rate on amounts outstanding	2.30		%	1.81		%



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Our average amount of commercial paper borrowings based on daily outstanding balances during the nine months ended September 30, 2018 , was $162.1 million with a weighted-average interest rate during the period of 2.23% .

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



(in millions)	Maturity	September 30, 2018
Revolving credit facility	October 2022	$	500.0

Less:
Letters of credit issued inside credit facility		$	1.2
Commercial paper outstanding		346.0		*
Available capacity under existing agreement		$	152.8


*	See Note 8, Long-Term Debt, for more information about the use of proceeds from our issuance of long-term debt in October 2018.

NOTE 8— LONG-TERM DEBT

In October 2018, we issued $300.0 million of 4.30% Debentures due October 15, 2048, and used the net proceeds to repay short-term debt and for working capital and other corporate purposes.

In July 2018, we redeemed all $80.0 million of our series of tax-exempt pollution control refunding bonds. From August 2009 until they were called, the bonds were not reported in our long-term debt because they were previously repurchased by us.

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

NOTE 9— MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:



(in millions)	September 30, 2018		December 31, 2017
Materials and supplies	$	142.4	$	140.7
Fossil fuel	70.9		74.8
Natural gas in storage	42.5		35.2
Total	$	255.8	$	250.7

Substantially all materials and supplies, fossil fuel, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting.

NOTE 10— INCOME TAXES

The effective tax rates of (24.7)% and (9.6)% for the three and nine months ended September 30, 2018, respectively, differ from the United States statutory federal income tax rate of 21% , primarily due to the flow through of tax repairs in connection with the Wisconsin rate settlement and the impact of the Tax Legislation, partially offset by state income taxes. The Tax Legislation, signed into law in December 2017, required us to remeasure our deferred income taxes and begin to amortize the resulting excess deferred income taxes beginning in 2018 in accordance with normalization requirements. See Note 19, Regulatory Environment, for more information on the Tax Legislation and the Wisconsin rate settlement.

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



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NOTE 11— FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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

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

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



	September 30, 2018
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	1.9	$	0.1	$	—	$	2.0
FTRs	—		—		6.4		6.4
Coal contracts	—		0.2		—		0.2
Total derivative assets	$	1.9	$	0.3	$	6.4	$	8.6

Derivative liabilities
Natural gas contracts	$	0.1	$	—	$	—	$	0.1



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

Derivative liabilities
Natural gas contracts	$	2.0	$	0.1	$	—	$	2.1
Coal contracts	—		0.3		—		0.3
Total derivative liabilities	$	2.0	$	0.4	$	—	$	2.4

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

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



	Three Months Ended September 30						Nine Months Ended September 30
(in millions)	2018			2017			2018			2017
Balance at the beginning of the period	$	8.7		$	6.0		$	2.4		$	3.1
Purchases	—			—			9.4			6.9
Settlements	(2.3		)	(2.3		)	(5.4		)	(6.3		)
Balance at the end of the period	$	6.4		$	3.7		$	6.4		$	3.7

Fair Value of Financial Instruments

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



	September 30, 2018				December 31, 2017
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock	$	30.4	$	28.3	$	30.4	$	30.5
Long-term debt, including current portion	2,413.9		2,570.5		2,662.3		2,976.3

The fair values of long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.

NOTE 12— 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.



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The following table shows our derivative assets and derivative liabilities:



	September 30, 2018				December 31, 2017
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	2.0	$	—	$	0.6	$	1.9
Petroleum products contracts	—		—		0.9		—
FTRs	6.4		—		2.4		—
Coal contracts	0.2		—		0.6		0.1
Total other current *	$	8.6	$	—	$	4.5	$	2.0

Other long-term
Natural gas contracts	$	—	$	0.1	$	—	$	0.2
Coal contracts	—		—		0.1		0.2
Total other long-term *	—		0.1		0.1		0.4
Total	$	8.6	$	0.1	$	4.6	$	2.4


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

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



	Three Months Ended September 30, 2018			Three Months Ended September 30, 2017
(in millions)	Volumes	Gains		Volumes	Gains (Losses)
Natural gas contracts	12.2 Dth	$	0.3	4.6 Dth	$	(0.5	)
Petroleum products contracts	0.9 gallons	0.3		4.1 gallons	(0.5		)
FTRs	5.4 MWh	1.4		6.9 MWh	2.4
Total		$	2.0		$	1.4



	Nine Months Ended September 30, 2018				Nine Months Ended September 30, 2017
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	35.9 Dth	$	(2.1	)	17.8 Dth	$	0.2
Petroleum products contracts	3.4 gallons	0.9			13.9 gallons	(1.4		)
FTRs	16.0 MWh	3.1			21.2 MWh	6.9
Total		$	1.9			$	5.7

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At September 30, 2018 and December 31, 2017 , we had posted cash collateral of $1.7 million and $4.9 million , respectively, in our margin accounts. These amounts were recorded on our balance sheets in other current assets.

The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets:



	September 30, 2018						December 31, 2017
(in millions)	Derivative Assets			Derivative Liabilities			Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	8.6		$	0.1		$	4.6		$	2.4
Gross amount not offset on the balance sheet	(0.1		)	(0.1		)	(1.3		)	(2.0		)	*
Net amount	$	8.5		$	—		$	3.3		$	0.4


*	Includes cash collateral posted of $0.7 million .



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NOTE 13— EMPLOYEE BENEFITS

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



	Pension Costs
	Three Months Ended September 30						Nine Months Ended September 30
(in millions)	2018			2017			2018			2017
Service cost	$	3.3		$	3.0		$	9.9		$	9.1
Interest cost	10.6			11.8			31.7			35.3
Expected return on plan assets	(18.8		)	(19.2		)	(56.4		)	(57.5		)
Loss on plan settlement	—			0.7			—			3.5
Amortization of prior service cost	0.2			0.3			0.6			0.9
Amortization of net actuarial loss	9.5			8.8			28.5			26.5
Net periodic benefit cost	$	4.8		$	5.4		$	14.3		$	17.8



	OPEB Costs
	Three Months Ended September 30						Nine Months Ended September 30
(in millions)	2018			2017			2018			2017
Service cost	$	1.7		$	1.8		$	5.2		$	5.2
Interest cost	2.8			3.0			8.3			9.2
Expected return on plan assets	(3.8		)	(3.6		)	(11.6		)	(10.8		)
Amortization of prior service credit	(0.6		)	(0.2		)	(1.7		)	(0.8		)
Net periodic benefit cost	$	0.1		$	1.0		$	0.2		$	2.8

During the nine months ended September 30, 2018 , we made contributions and payments of $3.8 million related to our pension plans and $1.5 million related to our OPEB plans. We expect to make contributions and payments of $0.3 million related to our pension plans and $3.0 million related to our OPEB plans during the remainder of 2018 , dependent upon various factors affecting us, including our liquidity position and the effects of the new Tax Legislation.

Effective January 1, 2018, we adopted ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, which modifies certain aspects of the accounting for employee benefit costs. Under the new guidance, only the service cost component can be included in total operating expenses. The remaining components of net periodic benefit cost (credit) are required to be presented in the income statement separately from the service cost component, outside of operating income. As required, this change was applied retrospectively to all prior periods presented. Accordingly, for the three and nine months ended September 30 , 2018 and 2017 , we have presented the service cost component of our retirement benefit plans in other operation and maintenance on the income statements, while presenting the non-service components in other income, net.

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



	Three Months Ended September 30					Nine Months Ended September 30
(in millions)	2018			2017		2018			2017
Non-service (credit) cost components	$	(1.6	)	$	1.4	$	(4.5	)	$	5.9

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

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



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NOTE 14— SEGMENT INFORMATION

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

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

Our other segment included Bostco, our non-utility subsidiary that was originally formed to develop and invest in real estate. In March 2017, we sold substantially all of the remaining assets of Bostco, and, in October 2018, Bostco was dissolved. See Note 2, Disposition, for more information .

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



(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Three Months Ended September 30, 2018
Operating revenues	$	924.0	$	—	$	924.0
Other operation and maintenance	384.7		—		384.7
Depreciation and amortization	87.4		—		87.4
Operating income	107.8		—		107.8
Interest expense	29.9		—		29.9



(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Three Months Ended September 30, 2017
Operating revenues	$	943.8	$	—	$	943.8
Other operation and maintenance *	331.2		—		331.2
Depreciation and amortization	83.0		—		83.0
Operating income *	164.8		—		164.8
Interest expense	29.3		—		29.3


*	Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 13, Employee Benefits, for more information on this new standard.



(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Nine Months Ended September 30, 2018
Operating revenues	$	2,721.7	$	—	$	2,721.7
Other operation and maintenance	1,086.9		—		1,086.9
Depreciation and amortization	259.6		—		259.6
Operating income	348.7		—		348.7
Interest expense	88.8		—		88.8



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(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Nine Months Ended September 30, 2017
Operating revenues	$	2,771.2	$	—	$	2,771.2
Other operation and maintenance *	982.2		—		982.2
Depreciation and amortization	247.8		—		247.8
Operating income *	497.2		—		497.2
Interest expense	87.7		0.3		88.0


*	Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 13, Employee Benefits, for more information on this new standard.

NOTE 15— VARIABLE INTEREST ENTITIES

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

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

Purchased Power Agreement

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

We have approximately $60.4 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under this contract for the nine months ended September 30, 2018 and 2017 were $14.1 million and $13.5 million , respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

NOTE 16— 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.



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



(in millions)	September 30, 2018		December 31, 2017
Accounts receivable
Services provided to ATC	$	2.4	$	0.8
Accounts payable
Services received from ATC	19.3		22.2

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



	Three Months Ended September 30					Nine Months Ended September 30
(in millions)	2018			2017		2018			2017
Lease agreements
Lease payments to We Power ⁽¹⁾	$	92.7		$	104.3	$	280.0		$	315.4
Construction work in progress billed to We Power	4.4			5.9		13.2			31.1
Transactions with WBS ⁽²⁾
Billings to WBS	4.1			60.2		12.8			177.2
Billings from WBS	64.2		⁽³⁾	49.4		240.9		⁽³⁾	152.1
Transactions with WPS
Natural gas purchases from WPS	0.6			0.8		1.6			1.3
Billings to WPS ⁽²⁾	3.9			6.4		11.2			14.1
Billings from WPS ⁽²⁾	1.5			1.4		6.6			3.6
Transactions with WG
Natural gas purchases from WG	1.4			1.4		4.0			4.0
Billings to WG ⁽²⁾	10.5		⁽⁴⁾	16.3		37.6		⁽⁴⁾	48.2
Billings from WG ⁽²⁾	4.8			6.0		14.5			17.3
Transactions with UMERC
Electric sales to UMERC	7.4			9.0		22.4			23.1
Billings to UMERC ⁽²⁾	5.2			18.7		12.3			52.6
Transactions with Bluewater ⁽⁵⁾
Storage service fees	4.5			1.4		10.4			1.4
Transactions with ATC
Charges to ATC for services and construction	3.7			2.9		9.4			8.1
Charges from ATC for network transmission services	57.9			60.4		174.0			181.1
Refund from ATC related to a FERC audit	—			—		15.4			—
Refund from ATC per FERC ROE order	—			—		—			19.4


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


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


⁽³⁾	Includes $2.2 million and $59.8 million for the transfer of certain software assets from WBS during the three and nine months ended September 30, 2018 , respectively. There were no software assets transferred from WBS during 2017.


⁽⁴⁾	Includes $0.1 million and $5.3 million for the transfer of certain software assets to WG during the three and nine months ended September 30, 2018 , respectively. There were no software assets transferred to WG during 2017.


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

Upper Michigan Energy Resources Corporation

In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan. UMERC, a subsidiary of WEC Energy Group, became operational effective January 1, 2017, and we transferred customers and property, plant, and equipment as of that date. We transferred approximately 27,500 retail electric customers and 50 electric distribution-only customers to UMERC, along with approximately 2,500 miles of electric distribution lines. We also transferred related electric distribution substations in the Upper Peninsula of Michigan and all property rights for the distribution



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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.

NOTE 17— COMMITMENTS AND CONTINGENCIES

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

Unconditional Purchase Obligations

We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of September 30, 2018 , were $10,266.8 million .

Environmental Matters

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

Air Quality

8-Hour Ozone National Ambient Air Quality Standards

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

Climate Change

In 2015, the EPA issued a final rule regulating GHG emissions from existing generating units, referred to as the Clean Power Plan, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In February 2016, the Supreme Court stayed the effectiveness of the CPP until disposition of certain litigation in the D.C. Circuit Court of Appeals challenging the rule and, to the extent that further appellate review is sought, at the Supreme Court. In April 2017, pursuant to motions made by the EPA, the D.C. Circuit Court of Appeals ordered the challenges to the CPP, as well as related performance standards for new, reconstructed, and modified fossil-fueled power plants, to be held in abeyance, which remains the case.

In December 2017, the EPA issued an advanced notice of proposed rulemaking to solicit input on whether it is appropriate to replace the CPP. Then, in August 2018, the EPA issued a proposed replacement rule for the CPP, the Affordable Clean Energy (ACE) rule. The



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proposed ACE rule would require the EPA to develop emission guidelines for states to use to develop their individual state plans. The state plans would focus on reducing GHG emissions by improving the efficiency of fossil-fueled power plants. The type of power plants most likely affected by this rule would be coal-fueled electric generating units. The EPA is also considering revisions to new source review (NSR) permitting as part of this rulemaking that could allow certain power plant efficiency improvement projects to be implemented without triggering NSR permitting requirements. We submitted comments on the ACE rule by the October 31, 2018 due date.

We continue to evaluate opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute towards long-term GHG reductions. WEC Energy Group's plan, which includes us, is to work with its industry partners, environmental groups, and the State of Wisconsin, with goals of reducing CO ₂ emissions by approximately 40% and 80% below 2005 levels by 2030 and 2050, respectively. We have implemented and continue to evaluate numerous options in order to meet WEC Energy Group's CO ₂ reduction goals. As a result of WEC Energy Group's generation reshaping plan, we expect to retire 1,547 MW of coal generation by 2020, including PIPP, which we are required to retire by May 31, 2019, and Pleasant Prairie power plant, which was retired in April 2018. See Note 5, Property, Plant, and Equipment, for more information . In addition, we are evaluating our goals, and possible subsequent actions, with respect to national and international efforts to reduce future GHG emissions in order to limit future global temperature increases to less than two degrees Celsius.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

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

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

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

We have also provided information to the WDNR and the MDEQ about planned unit retirements. Based on discussions with the MDEQ, if we submit a signed certification stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2023), the EM BTA requirements will be waived. We expect to submit the letter identifying the last operating date for PIPP to the MDEQ no later than early 2019, ahead of when the agency begins processing our pending application for the National Pollutant Discharge Elimination System permit reissuance.

As a result of past capital investments completed to address 316(b) compliance, we believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation.

Steam Electric Effluent Limitation Guidelines

The EPA's final steam electric effluent limitation guidelines (ELG) rule took effect in January 2016. This rule created new requirements for several types of power plant wastewaters. The two new requirements that affect us relate to discharge limits for bottom ash transport water (BATW) and wet flue gas desulfurization (FGD) wastewater. Various petitions challenging the rule were consolidated



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and are pending in the United States Court of Appeals for the Fifth Circuit. In April 2017, the EPA issued an administrative stay of certain compliance deadlines while further reviewing the rule. In September 2017, the EPA issued a final rule (Postponement Rule) to postpone the earliest compliance date to November 1, 2020 for the BATW and wet FGD wastewater requirements. The latest ELG rule compliance date remains December 31, 2023 for any new wastewater treatment requirements contained in power plant discharge permits. This rule applies to wastewater discharges from our power plant processes in Wisconsin. Litigation over various aspects of the final ELG rule and the Postponement Rule is pending in several Federal Courts.

Due to pending generating unit retirements, the only facilities that will require bottom ash system modifications are Oak Creek Units 7 and 8. One wastewater treatment system modification may be required for the wet FGD discharges from the six units that make up the OCPP and ERGS.

As a result of past capital investments completed to address ELG compliance, we believe our fleet overall is well positioned to meet this new regulation. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, as currently constructed, the ELG rule will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use.

The final rule would phase in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. New requirements for wet scrubber wastewater treatment would require additional zero liquid discharge or other advanced treatment capital improvements for the OCPP and ERGS. The rule also would require dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are required by the new rule, and modifications would be required at OC 7 and OC 8. We are beginning preliminary engineering for compliance with the rule and estimate approximately $50 million would be required to design and install these advanced treatment and bottom ash transport systems. This estimate reflects the retirement of PIPP as a result of WEC Energy Group's generation reshaping plan discussed in Climate Change above.

Land Quality

Manufactured Gas Plant Remediation

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

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

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



(in millions)	September 30, 2018		December 31, 2017
Regulatory assets	$	29.7	$	30.4
Reserves for future remediation *	18.5		18.5


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

Enforcement and Litigation Matters

We are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material effect on our financial condition or results of operations.



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NOTE 18— SUPPLEMENTAL CASH FLOW INFORMATION



	Nine Months Ended September 30
(in millions)	2018			2017
Cash (paid) for interest, net of amount capitalized	$	(64.1	)	$	(62.1	)
Cash (paid) for income taxes, net	(14.7		)	(60.7		)
Significant noncash transactions:
Accounts payable related to construction costs	4.0			8.5
Accounts receivable related to assets transferred to affiliates	2.7			—
Transfer of investment in ATC to another subsidiary of WEC Energy Group ^{(1) (2)}	—			415.4
Transfer of net assets to UMERC ⁽¹⁾	—			60.0


⁽¹⁾	See Note 16, Related Parties, for more information on these transactions.


⁽²⁾	The amount transferred included a $13.4 million receivable for distributions approved and recorded in December 2016.

NOTE 19— REGULATORY ENVIRONMENT

Tax Cuts and Jobs Act of 2017

In December 2017, we deferred for return to ratepayers, through future refunds, bill credits, or reductions in other regulatory assets, the estimated tax benefit of $1,065 million related to the Tax Legislation that was signed into law in December 2017. This tax benefit resulted from the revaluation of deferred taxes. The Tax Legislation also reduced the corporate federal tax rate from a maximum of 35% to a 21% rate, effective January 1, 2018.

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

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

2018 and 2019 Rates

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

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



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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 20— NEW ACCOUNTING PRONOUNCEMENTS

Leases

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which revises current guidance (Topic 840) regarding accounting for leases. Revisions include requiring a lessee to recognize a lease asset and a lease liability on its balance sheet for each lease, including operating leases, with an initial term greater than 12 months. In addition, required quantitative and qualitative disclosures related to lease agreements were expanded. For lessors however, accounting for leases is largely unchanged from previous provisions of GAAP. This guidance will be effective for our financial statements for periods beginning after December 15, 2018, and interim periods within those annual periods. Companies are able to elect several practical expedients to aid in the transition to Topic 842. The following three practical expedients must all be elected together, and we intend to elect these practical expedients to aid in our implementation of Topic 842.


•	An entity need not reassess whether any expired or existing contracts are or contain leases.


•	An entity need not reassess the lease classification for any expired or existing leases (that is, all existing leases that were classified as operating leases in accordance with Topic 840, Leases, will continue to be classified as operating leases, and all existing leases that were classified as capital leases in accordance with Topic 840 will continue to be classified as capital leases).


•	An entity need not reassess initial direct costs for any existing leases.

Other practical expedients that can be elected individually, and that we are still assessing as part of our implementation of Topic 842, are as follows:


•	An entity may use hindsight in determining the lease term and in assessing impairment of the entity’s right-of-use assets.


•	An entity may elect, by class of underlying asset, to account for the nonlease components in a contract as part of the single lease component to which they are related.

In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842, which is an amendment to ASU 2016-02. Land easements (also commonly referred to as rights of way) represent the right to use, access or cross another entity's land for a specified purpose. This new guidance permits an entity to elect a transitional practical expedient, to be applied consistently, to not evaluate under Topic 842 land easements that were already in existence or had expired at the time of the entity's adoption of Topic 842. Once Topic 842 is adopted, an entity is required to apply Topic 842 prospectively to all new (or modified) land easements to determine whether the arrangement should be accounted for as a lease. ASU 2018-01 is effective for fiscal years beginning after December 15, 2018. We intend to elect this practical expedient.

In July 2018, the FASB issued ASU 2018-11, "Leases (Topic 842): Targeted Improvements," which amends ASU 2016-02 and allows entities the option to initially apply Topic 842 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. We are in the process of finalizing our inventory of leases, which includes continuing to monitor activities of the FASB as well as utility industry implementation guidance. We also continue to document technical accounting issues, analyze financial reporting implications and implement required changes to internal controls and processes. We plan to adopt Topic 842 effective January 1, 2019, using the optional transition method to apply the new guidance as of January 1, 2019, rather than as of the earliest period presented. Upon adoption, we do expect an increase in assets and liabilities (which we are still in the process of quantifying), although we do not expect the guidance to have a significant impact on our results of operations or cash flows.

Financial Instruments Credit Losses

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. This ASU introduces a new impairment model known as the current expected credit loss model. The ASU requires a financial asset measured at amortized cost to be presented at the net amount expected to be collected. Previously, recognition of the full amount of credit losses was generally delayed until the loss was probable of occurring. We are currently assessing the effects this guidance may have on our financial statements.



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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 2017 Annual Report on Form 10-K.

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 14, 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. Bostco was dissolved in October 2018.

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 CO ₂ emissions by approximately 40% below 2005 levels by 2030. In addition, WEC Energy Group set a new long-term goal of reducing CO ₂ 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 5, Property, Plant, and Equipment , for information related to the Pleasant Prairie power plant retirement and the planned retirement of Presque Isle Power Plant 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 SEPTEMBER 30, 2018

Consolidated Earnings

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



	Three Months Ended September 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	$	924.0		$	943.8	$	(19.8	)	$	(21.9	)	$	(6.0	)	$	8.1
Cost of sales	316.5			336.5		20.0			—			—			20.0
Other operation and maintenance	384.7			331.2		(53.5		)	(27.4		)	(16.9		)	(9.2		)
Depreciation and amortization	87.4			83.0		(4.4		)	—			—			(4.4		)
Property and revenue taxes	27.6			28.3		0.7			—			—			0.7
Operating income	107.8			164.8		(57.0		)	(49.3		)	(22.9		)	15.2
Other income, net	5.1			4.1		1.0			—			—			1.0
Interest expense	29.9			29.3		(0.6		)	—			—			(0.6		)
Income before income taxes	83.0			139.6		(56.6		)	(49.3		)	(22.9		)	15.6
Income tax (benefit) expense	(20.5		)	49.9		70.4			49.3			22.9			(1.8		)
Preferred stock dividend requirements	0.3			0.3		—			—			—			—
Net income attributed to common shareholder	$	103.2		$	89.4	$	13.8		$	—		$	—		$	13.8



09/30/2018 Form 10-Q	26	Wisconsin Electric Power Company

Table of Contents

Our consolidated earnings for the three months ended September 30, 2018 were $103.2 million , compared to $89.4 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 10, Income Taxes , and Note 19, Regulatory Environment , for more information. See below for additional information on the remaining $13.8 million increase 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 September 30, 2018 and 2017 was $107.8 million and $164.8 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



	Three Months Ended September 30
(in millions)	2018		2017		B (W)
Electric revenues	$	878.4	$	899.3	$	(20.9	)
Fuel and purchased power	292.1		315.5		23.4
Total electric margins	586.3		583.8		2.5

Natural gas revenues	45.6		44.5		1.1
Cost of natural gas sold	24.4		21.0		(3.4		)
Total natural gas margins	21.2		23.5		(2.3		)

Total electric and natural gas margins	607.5		607.3		0.2

Other operation and maintenance	384.7		331.2		(53.5		)
Depreciation and amortization	87.4		83.0		(4.4		)
Property and revenue taxes	27.6		28.3		0.7
Operating income	$	107.8	$	164.8	$	(57.0	)



09/30/2018 Form 10-Q	27	Wisconsin Electric Power Company

Table of Contents

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



	Three Months Ended September 30
(in millions)	2018		2017		B (W)
Operation and maintenance not included in line items below	$	113.6	$	109.8	$	(3.8	)
We Power ⁽¹⁾	127.8		129.6		1.8
Transmission ⁽²⁾	66.3		67.5		1.2
Transmission expense related to the flow through of tax repairs ⁽³⁾	27.4		—		(27.4		)
Transmission expense related to Tax Legislation ⁽⁴⁾	16.9		—		(16.9		)
Regulatory amortizations and other pass through expenses ⁽⁵⁾	24.4		24.3		(0.1		)
Earnings sharing mechanisms ⁽⁶⁾	8.3		—		(8.3		)
Total other operation and maintenance	$	384.7	$	331.2	$	(53.5	)

⁽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 September 30, 2018 and 2017 , $124.8 million and $129.0 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 three months ended September 30, 2018 and 2017 , $85.2 million and $86.8 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 their December 31, 2017 levels. See Note 19, Regulatory Environment, for more information .


⁽⁴⁾	Represents additional transmission expense associated with the May 2018 PSCW order requiring us to use 80% of our current 2018 tax benefit, including the amortization associated with the revaluation of deferred taxes, to reduce our transmission regulatory asset balance. See Note 19, 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.


⁽⁶⁾	See Note 19, Regulatory Environment, for more information about our earnings sharing mechanism.

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



	Three Months Ended September 30
	MWh (in thousands)
Electric Sales Volumes	2018	2017	B (W)
Customer Class
Residential	2,367.9	2,151.9	216.0
Small commercial and industrial	2,449.6	2,308.9	140.7
Large commercial and industrial	2,276.3	2,199.7	76.6
Other	33.3	33.2	0.1
Total retail	7,127.1	6,693.7	433.4
Wholesale	412.3	363.6	48.7
Resale	977.5	2,190.4	(1,212.9	)
Total sales in MWh	8,516.9	9,247.7	(730.8	)



09/30/2018 Form 10-Q	28	Wisconsin Electric Power Company

Table of Contents



	Three Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2018	2017	B (W)
Customer Class
Residential	20.3	19.6	0.7
Commercial and industrial	14.1	13.4	0.7
Total retail	34.4	33.0	1.4
Transport	75.2	67.1	8.1
Total sales in therms	109.6	100.1	9.5



	Three Months Ended September 30
	Degree Days
Weather *	2018	2017	B(W)
Heating (113 normal)	75	72	4.2	%
Cooling (556 normal)	686	542	26.6	%


*	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 $2.5 million during the third quarter of 2018, compared with the same quarter in 2017. The significant factor impacting the higher electric utility margins was a $26.9 million increase related to higher retail sales volumes during the third quarter of 2018, primarily driven by favorable weather and higher overall use per retail customer due in part to a stronger economy. As measured by cooling degree days, the third quarter of 2018 was 26.6% warmer than the same quarter in 2017.

This increase in margins was partially offset by:


•	A $21.9 million decrease in margins 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 assets at their December 31, 2017 levels. See Note 19, Regulatory Environment , for more information.


•	A $3.5 million decrease in margins related to amounts expected to be returned to customers through refunds, bill credits, or reductions in other regulatory assets, driven by the Tax Legislation. See Note 10, Income Taxes , and Note 19, Regulatory Environment , for more information.

Natural Gas Utility Margins

Natural gas utility margins decreased $2.3 million during the third quarter of 2018, compared with the same quarter in 2017, and was driven by the amounts expected to be returned to customers through refunds or bill credits related to the Tax Legislation. See Note 10, Income Taxes , and Note 19, Regulatory Environment , for more information.

Operating Income

Operating income at the utility segment decreased $57.0 million during the third quarter of 2018, compared with the same quarter in 2017. This decrease was driven by $57.2 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes), partially offset by the $0.2 million of higher net margins discussed above.

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


•	A $27.4 million increase in transmission expenses related to the flow through of tax repairs, as discussed in the other operation and maintenance table above.



09/30/2018 Form 10-Q	29	Wisconsin Electric Power Company

Table of Contents


•	A $16.9 million increase in transmission expense associated with the May 2018 order from the PSCW related to our required treatment of the benefits associated with the Tax Legislation, as discussed in the other operation and maintenance table above.


•	An $8.3 million expense recorded in the third quarter of 2018 related to our earnings sharing mechanism. See Note 19, Regulatory Environment, for more information .


•	An $8.3 million increase in benefit costs, which included $5.7 million of expenses related to staff reductions.


•	A $4.4 million increase in depreciation and amortization driven by an increase in capital expenditures as we continue to execute on our capital plan.

These increases in operating expenses were partially offset by a $7.5 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 third quarter of 2018. See Note 5, Property, Plant, and Equipment, for more information on the plant retirements.

Consolidated Other Income, Net



	Three Months Ended September 30
(in millions)	2018		2017			B (W)
AFUDC – Equity	$	0.9	$	0.7		$	0.2
Non-service credit (cost) components of net periodic benefit costs	1.6		(1.4		)	3.0
Other, net	2.6		4.8			(2.2		)
Other income, net	$	5.1	$	4.1		$	1.0

Other income, net increased $1.0 million during the third quarter of 2018 , compared with the same quarter in 2017 . The increase was driven by the quarter-over-quarter increase in income from the non-service components of our net periodic pension and OPEB costs. See Note 13, Employee Benefits, for more information on our benefit costs.

Consolidated Interest Expense



	Three Months Ended September 30
(in millions)	2018		2017		B (W)
Interest expense	$	29.9	$	29.3	$	(0.6	)

Consolidated Income Tax (Benefit) Expense



	Three Months Ended September 30
	2018		2017		B (W)
Effective tax rate	(24.7	)%	35.7	%	60.4	%

Our effective tax rate decreased by 60.4% when compared with the third quarter of 2017, primarily due to a 43.2% 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 10, Income Taxes , and Note 19, Regulatory Environment , for more information.



09/30/2018 Form 10-Q	30	Wisconsin Electric Power Company

Table of Contents

NINE MONTHS ENDED SEPTEMBER 30, 2018

Consolidated Earnings

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



	Nine Months Ended September 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	$	2,721.7		$	2,771.2	$	(49.5	)	$	(63.2	)	$	(19.0	)	$	32.7
Cost of sales	944.4			959.0		14.6			—			—			14.6
Other operation and maintenance	1,086.9			982.2		(104.7		)	(52.1		)	(50.7		)	(1.9		)
Depreciation and amortization	259.6			247.8		(11.8		)	—			—			(11.8		)
Property and revenue taxes	82.1			85.0		2.9			—			—			2.9
Operating income	348.7			497.2		(148.5		)	(115.3		)	(69.7		)	36.5
Other income, net	16.2			8.4		7.8			—			—			7.8
Interest expense	88.8			88.0		(0.8		)	—			—			(0.8		)
Income before income taxes	276.1			417.6		(141.5		)	(115.3		)	(69.7		)	43.5
Income tax (benefit) expense	(26.6		)	150.2		176.8			115.3			69.7			(8.2		)
Preferred stock dividend requirements	0.9			0.9		—			—			—			—
Net income attributed to common shareholder	$	301.8		$	266.5	$	35.3		$	—		$	—		$	35.3

Our consolidated earnings for the nine months ended September 30, 2018 were $301.8 million , compared to $266.5 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 10, Income Taxes , and Note 19, Regulatory Environment , for more information. See below for additional information on the remaining $35.3 million increase in consolidated earnings.

Non-GAAP Financial Measures

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 nine months ended September 30, 2018 and 2017 was $348.7 million and $497.2 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.



09/30/2018 Form 10-Q	31	Wisconsin Electric Power Company

Table of Contents

Utility Segment Contribution to Operating Income



	Nine Months Ended September 30
(in millions)	2018		2017		B (W)
Electric revenues	$	2,446.0	$	2,514.7	$	(68.7	)
Fuel and purchased power	776.7		809.4		32.7
Total electric margins	1,669.3		1,705.3		(36.0		)

Natural gas revenues	275.7		256.5		19.2
Cost of natural gas sold	167.7		149.6		(18.1		)
Total natural gas margins	108.0		106.9		1.1

Total electric and natural gas margins	1,777.3		1,812.2		(34.9		)

Other operation and maintenance	1,086.9		982.2		(104.7		)
Depreciation and amortization	259.6		247.8		(11.8		)
Property and revenue taxes	82.1		85.0		2.9
Operating income	$	348.7	$	497.2	$	(148.5	)

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



	Nine Months Ended September 30
(in millions)	2018		2017		B (W)
Operation and maintenance not included in line items below	$	323.6	$	324.0	$	0.4
We Power ⁽¹⁾	380.9		384.3		3.4
Transmission ⁽²⁾	198.5		202.0		3.5
Transmission expense related to the flow through of tax repairs ⁽³⁾	52.1		—		(52.1		)
Transmission expense related to Tax Legislation ⁽⁴⁾	50.7		—		(50.7		)
Regulatory amortizations and other pass through expenses ⁽⁵⁾	72.8		71.9		(0.9		)
Earnings sharing mechanism ⁽⁶⁾	8.3		—		(8.3		)
Total other operation and maintenance	$	1,086.9	$	982.2	$	(104.7	)

⁽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 nine months ended September 30, 2018 and 2017 , $361.5 million and $394.0 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 nine months ended September 30, 2018 and 2017 , $205.7 million and $221.4 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 their December 31, 2017 levels. See Note 19, Regulatory Environment, for more information .


⁽⁴⁾	Represents additional transmission expense associated with the May 2018 PSCW order requiring us to use 80% of our current 2018 tax benefit, including the amortization associated with the revaluation of deferred taxes, to reduce our transmission regulatory asset balance. See Note 19, 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.


⁽⁶⁾	See Note 19, Regulatory Environment, for more information about our earnings sharing mechanism.



09/30/2018 Form 10-Q	32	Wisconsin Electric Power Company

Table of Contents

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



	Nine Months Ended September 30
	MWh (in thousands)
Electric Sales Volumes	2018	2017	B (W)
Customer Class
Residential	6,134.8	5,774.7	360.1
Small commercial and industrial	6,796.2	6,610.7	185.5
Large commercial and industrial	6,435.8	6,277.4	158.4
Other	102.9	105.4	(2.5	)
Total retail	19,469.7	18,768.2	701.5
Wholesale	1,232.4	1,207.9	24.5
Resale	3,729.2	5,387.4	(1,658.2	)
Total sales in MWh	24,431.3	25,363.5	(932.2	)



	Nine Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2018	2017	B (W)
Customer Class
Residential	256.7	221.9	34.8
Commercial and industrial	145.2	126.9	18.3
Total retail	401.9	348.8	53.1
Transport	248.0	227.6	20.4
Total sales in therms	649.9	576.4	73.5



	Nine Months Ended September 30
	Degree Days
Weather *	2018	2017	B(W)
Heating (4,282 normal)	4,323	3,669	17.8	%
Cooling (722 normal)	903	745	21.2	%


*	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 $36.0 million during the nine months ended September 30, 2018 , compared with the same period in 2017. The significant factors impacting the lower electric utility margins were:


•	A $63.2 million decrease in margins 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 assets at their December 31, 2017 levels. See Note 19, Regulatory Environment , for more information.


•	An $11.3 million decrease in margins related to amounts expected to be returned to customers through refunds, bill credits, or reductions in other regulatory assets, driven by the Tax Legislation. See Note 10, Income Taxes , and Note 19, Regulatory Environment , for more information.


•	A $5.1 million decrease in wholesale margins driven both by lower sales volumes and reduced capacity rates due in part to the Tax Legislation.

These decreases in margins were partially offset by a $45.6 million increase related to higher retail sales volumes during the nine months ended September 30, 2018 , primarily driven by favorable weather and higher overall use per retail customer due in part to a stronger economy. Colder winter weather and a warmer summer in 2018 contributed to the increase. As measured by heating degree days, the nine months ended September 30, 2018 , were 17.8% colder than the same period in 2017. As measured by cooling degree days, the nine months ended September 30, 2018 , were 21.2% warmer than the same period in 2017.



09/30/2018 Form 10-Q	33	Wisconsin Electric Power Company

Table of Contents

Natural Gas Utility Margins

Natural gas utility margins increased $1.1 million during the nine months ended September 30, 2018 , compared with the same period in 2017. The most significant factor impacting the higher natural gas utility margins was a $9.0 million increase related to higher sales volumes, primarily driven by colder winter weather, customer growth, and higher overall use per retail customer due in part to a stronger economy. This increase in margins was partially offset by $7.7 million of amounts expected to be returned to customers through refunds or bill credits, driven by the Tax Legislation. See Note 10, Income Taxes , and Note 19, Regulatory Environment , for more information.

Operating Income

Operating income at the utility segment decreased $148.5 million during the nine months ended September 30, 2018 , compared with the same period in 2017. The decrease was driven by $113.6 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes) and the $34.9 million net decrease in margins discussed above.

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


•	A $52.1 million increase in transmission expense related to the flow through of tax repairs, as discussed in the other operation and maintenance table above.


•	A $50.7 million increase in transmission expense associated with the May 2018 order from the PSCW related to our required treatment of the benefits associated with the Tax Legislation, as discussed in the other operation and maintenance table above.


•	An $11.8 million increase in depreciation and amortization, driven by an increase in capital expenditures as we continue to execute on our capital plan.


•	An $8.3 million expense recorded in the third quarter of 2018 related to our earnings sharing mechanism. See Note 19, Regulatory Environment , for more information.


•	A $7.0 million increase in benefit costs, which included $5.7 million of expenses related to staff reductions.

These increases in operating expenses were partially offset by a $14.3 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 nine months ended September 30, 2018 . See Note 5, Property, Plant, and Equipment, for more information on the plant retirements.

Consolidated Other Income, Net



	Nine Months Ended September 30
(in millions)	2018		2017			B (W)
AFUDC – Equity	$	2.9	$	2.1		$	0.8
Non-service credit (cost) components of net periodic benefit costs	4.5		(5.9		)	10.4
Other	8.8		12.2			(3.4		)
Other income, net	$	16.2	$	8.4		$	7.8

Other income, net increased $7.8 million during the nine months ended September 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 13, Employee Benefits, for more information on our benefit costs.



09/30/2018 Form 10-Q	34	Wisconsin Electric Power Company

Table of Contents

Consolidated Interest Expense



	Nine Months Ended September 30
(in millions)	2018		2017		B (W)
Interest expense	$	88.8	$	88.0	$	(0.8	)

Consolidated Income Tax (Benefit) Expense



	Nine Months Ended September 30
	2018		2017		B (W)
Effective tax rate	(9.6	)%	36.0	%	45.6	%

Our effective tax rate decreased by 45.6% when compared with the nine months ended September 30, 2017 , primarily due to a 30.4% 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 10, Income Taxes , and Note 19, Regulatory Environment , for more information.

We expect our 2018 annual effective tax rate benefit to be between (19)% and (18)%, which includes an estimated 40% 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 nine months ended September 30 :



(in millions)	2018			2017			Change in 2018 Over 2017
Cash provided by (used in):
Operating activities	$	766.2		$	594.3		$	171.9
Investing activities	(486.5		)	(382.1		)	(104.4		)
Financing activities	(287.9		)	(224.3		)	(63.6		)

Operating Activities

Net cash provided by operating activities increased $171.9 million during the nine months ended September 30, 2018 , compared with the same period in 2017 , driven by :


•	A $60.5 million increase in cash related to higher overall collections from customers, primarily due to favorable weather during the nine months ended September 30, 2018 , compared with the same period in 2017 .


•	A $54.3 million increase in cash from lower payments for other operation and maintenance costs. During the nine months ended September 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 $46.0 million increase in cash related to a decrease in cash paid for income taxes during the nine months ended September 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.



09/30/2018 Form 10-Q	35	Wisconsin Electric Power Company

Table of Contents

Investing Activities

Net cash used in investing activities increased $104.4 million during the nine months ended September 30, 2018 , compared with the same period in 2017 , driven by:


•	Net payments of $53.7 million to affiliates during the nine months ended September 30, 2018 , related to transfers of an enterprise resource planning system and other software. There were no similar transfers in 2017 .


•	A $36.0 million increase in cash paid for capital expenditures during the nine months ended September 30, 2018 , compared with the same period in 2017 , which is discussed in more detail below.


•	A $22.2 million decrease in the proceeds received from the sale of assets during the nine months ended September 30, 2018 , compared with the same period in 2017 . See Note 2, Disposition, for more information .

Capital Expenditures

Capital expenditures for the nine months ended September 30 were as follows:



(in millions)	2018		2017		Change in 2018 Over 2017
Capital expenditures	$	441.7	$	405.7	$	36.0

The increase in cash paid for capital expenditures during the nine months ended September 30, 2018 , was driven by upgrades to our natural gas and electric distribution systems, including main replacement projects, an information technology project created to improve our billing, call center, and credit collection functions, and various other software projects.

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

Financing Activities

Net cash used in financing activities increased $63.6 million during the nine months ended September 30, 2018 , compared with the same period in 2017 , primarily driven by:

•

A $250.0 million repayment of long-term debt during the nine months ended September 30, 2018 . A portion of this repayment was financed with a net increase in cash of $235.1 million from commercial paper, which resulted from $135.1 million of net borrowings during the nine months ended September 30, 2018 , compared with $100.0 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 nine months ended September 30, 2018 , compared with the same period in 2017 .


•	A $20.0 million increase in dividends paid to our parent during the nine months ended September 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 nine months ended September 30, 2017 .

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

Note 8, Long-Term Debt .



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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 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 7, Short-Term Debt and Lines of Credit, for more information on our credit facility.

Working Capital

As of September 30, 2018 , our current liabilities exceeded our current assets by $100.7 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.



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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	$	608.6
2019	636.7
2020	876.3
Total	$	2,121.6

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.

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 7, Short-Term Debt and Lines of Credit , and

Note 15, 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 17, 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.



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Other Matters

Tax Cuts and Jobs Act of 2017

In December 2017, the Tax Legislation was signed into law. The PSCW issued a written order in May 2018 regarding how to refund certain 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 19, 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 11, Fair Value Measurements , and

Note 12, 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 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 third quarter of 2018 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.



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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 17, Commitments and Contingencies , and Note 19, 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 17, Commitments and Contingencies ,

Note 19, 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 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 2017 Annual Report on Form 10-K. See Item 1A. Risk Factors in Part I of our Form 10-K for a discussion of certain risk factors applicable to us.



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ITEM 6. EXHIBITS



Number	Exhibit
4	Instruments defining the rights of security holders, including indentures
	4.1	Securities Resolution No. 17 of WE, dated as of October 1, 2018, under the Indenture for Debt Securities, dated as of December 1, 1995, between WE and U.S. Bank National Association (as successor to Firstar Trust Company), as Trustee. (Exhibit 4.1 to WE's Form 8-K filed October 4, 2018.)

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



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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:	November 2, 2018	William J. Guc
		Vice President and Controller

		(Duly Authorized Officer and Chief Accounting Officer)



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Part I. Financial Information Item 1. Financial Statements Note 1 General Information Note 2 Disposition Note 3 Operating Revenues Note 4 Regulatory Assets and Liabilities Note 5, Property, Plant, and Equipment Note 19, Regulatory Environment Note 5 Property, Plant, and Equipment Note 6 Common Equity Note 7 Short-term Debt and Lines Of Credit Note 8 Long-term Debt Note 9 Materials, Supplies, and Inventories Note 10 Income Taxes Note 11 Fair Value Measurements Note 12 Derivative Instruments Note 13 Employee Benefits Note 14 Segment Information Note 15 Variable Interest Entities Note 16 Related Parties Note 17 Commitments and Contingencies Note 18 Supplemental Cash Flow Information Note 19 Regulatory Environment Note 20 New Accounting Pronouncements Item 2. Management's Discussion and Analysis Of Financial Condition and Results Of Operations Note 14, Segment Information Note 2, Disposition Note 10, Income Taxes Note 7, Short-term Debt and Lines Of Credit Note 8, Long-term Debt Note 15, Variable Interest Entities Note 17, Commitments and Contingencies Item 3. Quantitative and Qualitative Disclosures About Market Risk Note 11, Fair Value Measurements Note 12, Derivative Instruments Item 4. Controls and Procedures Part II. Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 6. Exhibits

Exhibits

4.1 Securities Resolution No. 17 of WE, dated as of October 1, 2018, under the Indenture for Debt Securities, dated as of December 1, 1995, between WE and U.S. Bank National Association (as successor to Firstar Trust Company), as Trustee. (Exhibit 4.1 to WE's Form 8-K filed October 4, 2018.) 31.1 Certification Pursuant to Rule13a-14(a) or 15d-14(a), as Adopted Pursuant to Section302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification Pursuant to Rule13a-14(a) or 15d-14(a), as Adopted Pursuant to Section302 of the Sarbanes-Oxley Act of 2002. 32.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section906 of the Sarbanes-Oxley Act of 2002. 32.2 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section906 of the Sarbanes-Oxley Act of 2002.

WELPP 10-Q Quarter ended Sept. 30, 2018

Exhibits