WELPP 10-K Annual Report Dec. 31, 2018

WISCONSIN ELECTRIC POWER CO

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10-K 1 a2018we10k.htm WISCONSIN ELECTRIC 2018 FORM10-K Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

(Mark One)



[X]	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2018



[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ________________ to ___________________



Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	IRS Employer 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

Securities registered pursuant to Section 12(b) of the Act :

None

Securities registered pursuant to Section 12(g) of the Act :



Serial Preferred Stock, 3.60% Series, $100 Par Value
Six Per Cent. Preferred Stock, $100 Par Value

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes [ ] No [X]

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes [ ] No [X]

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 every Interactive Data File required to be submitted 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 such files).

Yes [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

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]		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]

As of June 30, 2018 (and currently), all of the common stock of Wisconsin Electric Power Company is held by WEC Energy Group, Inc.



	State the aggregate market value of the voting and non-voting common equity held by non-affiliates of the Registrant.

None.



	Number of shares outstanding of each class of common stock, as of
	January 31, 2019

Common Stock, $10 par value, 33,289,327 shares outstanding

Documents incorporated by reference :

Portions of Wisconsin Electric Power Company's Definitive information statement on Schedule 14C for its Annual Meeting of Shareholders, to be held on April 25, 2019, are incorporated by reference into Part III hereof.

Table of Contents

WISCONSIN ELECTRIC POWER COMPANY

ANNUAL REPORT ON FORM 10-K

For the Year Ended December 31, 2018

TABLE OF CONTENTS



					Page
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION					1
PART I					3
ITEM 1.	BUSINESS				3
	A.	INTRODUCTION			3
	B.	UTILITY SEGMENT			3
	C.	OTHER SEGMENT			12
	D.	REGULATION			12
	E.	ENVIRONMENTAL COMPLIANCE			15
	F.	EMPLOYEES			15
ITEM 1A.	RISK FACTORS				16
ITEM 1B.	UNRESOLVED STAFF COMMENTS				25
ITEM 2.	PROPERTIES				26
ITEM 3.	LEGAL PROCEEDINGS				27
ITEM 4.	MINE SAFETY DISCLOSURES				27
	EXECUTIVE OFFICERS OF THE REGISTRANT				28
PART II					29
ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES				29
ITEM 6.	SELECTED FINANCIAL DATA				29
ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS				30
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK				49
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA				50
	A.	Report of Independent Registered Public Accounting Firm			50
	B.	Consolidated Income Statements			51
	C.	Consolidated Balance Sheets			52
	D.	Consolidated Statements of Cash Flows			53
	E.	Consolidated Statements of Equity			54
	F.	Consolidated Statements of Capitalization			55
	G.	Notes to Consolidated Financial Statements			56
		Note 1	Summary of Significant Accounting Policies	56
		Note 2	Dispositions	64
		Note 3	Related Parties	64
		Note 4	Operating Revenues	66
		Note 5	Regulatory Assets and Liabilities	68
		Note 6	Property, Plant, and Equipment	69
		Note 7	Asset Retirement Obligations	70
		Note 8	Common Equity	70
		Note 9	Preferred Stock	72
		Note 10	Short-Term Debt and Lines of Credit	73
		Note 11	Long-Term Debt and Capital Lease Obligations	73
		Note 12	Income Taxes	76
		Note 13	Fair Value Measurements	79
		Note 14	Derivative Instruments	80
		Note 15	Employee Benefits	80
		Note 16	Investment in American Transmission Company	86
		Note 17	Segment Information	86
		Note 18	Variable Interest Entities	87



2018 Form 10-K	i	Wisconsin Electric Power Company

Table of Contents



		Note 19	Commitments and Contingencies	88
		Note 20	Supplemental Cash Flow Information	92
		Note 21	Regulatory Environment	93
		Note 22	Other Income, Net	94
		Note 23	Quarterly Financial Information (Unaudited)	94
		Note 24	New Accounting Pronouncements	94
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE				97
ITEM 9A.	CONTROLS AND PROCEDURES				97
ITEM 9B.	OTHER INFORMATION				97
PART III					98
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANT				98
ITEM 11.	EXECUTIVE COMPENSATION				98
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS				98
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE				98
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES				99
PART IV					100
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES				100
ITEM 16.	FORM 10-K SUMMARY				103
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS					104
SIGNATURES					105



2018 Form 10-K	ii	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
Integrys		Integrys Holding, Inc.
UMERC		Upper Michigan Energy Resources Corporation
WBS		WEC Business Services LLC
WE		Wisconsin Electric Power Company
We Power		W.E. Power, LLC
WEC Energy Group		WEC Energy Group, Inc.
WG		Wisconsin Gas LLC
Wispark		Wispark LLC
WPS		Wisconsin Public Service Corporation

Federal and State Regulatory Agencies
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
IRS		United States Internal Revenue Service
MDEQ		Michigan Department of Environmental Quality
MPSC		Michigan Public Service Commission
PSCW		Public Service Commission of Wisconsin
SEC		Securities and Exchange Commission
WDNR		Wisconsin Department of Natural Resources

Accounting Terms
AFUDC		Allowance for Funds Used During Construction
ARO		Asset Retirement Obligation
ASC		Accounting Standards Codification
ASU		Accounting Standards Update
CWIP		Construction Work in Progress
FASB		Financial Accounting Standards Board
GAAP		Generally Accepted Accounting Principles
OPEB		Other Postretirement Employee Benefits

Environmental Terms
ACE		Affordable Clean Energy
Act 141		2005 Wisconsin Act 141
CAA		Clean Air Act
CO ₂		Carbon Dioxide
CPP		Clean Power Plan
GHG		Greenhouse Gas
NAAQS		National Ambient Air Quality Standards
NOx		Nitrogen Oxide
SO ₂		Sulfur Dioxide

Measurements
Dth		Dekatherm
MW		Megawatt
MWh		Megawatt-hour



2018 Form 10-K	iii	Wisconsin Electric Power Company

Table of Contents



Other Terms and Abbreviations
AIA		Affiliated Interest Agreement
ARR		Auction Revenue Right
Compensation Committee		Compensation Committee of the Board of Directors of WEC Energy Group, Inc.
D.C. Circuit Court of Appeals		United States Court of Appeals for the District of Columbia Circuit
ERGS		Elm Road Generating Station
ER 1		Elm Road Generating Station Unit 1
ER 2		Elm Road Generating Station Unit 2
Exchange Act		Securities Exchange Act of 1934, as amended
FTR		Financial Transmission Right
GCRM		Gas Cost Recovery Mechanism
LMP		Locational Marginal Price
MCPP		Milwaukee County Power Plant
MISO		Midcontinent Independent System Operator, Inc.
MISO Energy Markets		MISO Energy and Operating Reserves Market
NYMEX		New York Mercantile Exchange
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
Omnibus Stock Incentive Plan		WEC Energy Group 1993 Omnibus Stock Incentive Plan, Amended and Restated Effective as of January 1, 2016
PIPP		Presque Isle Power Plant
Point Beach		Point Beach Nuclear Power Plant
PWGS		Port Washington Generating Station
PWGS 1		Port Washington Generating Station Unit 1
PWGS 2		Port Washington Generating Station Unit 2
ROE		Return on Equity
RTO		Regional Transmission Organization
SSR		System Support Resource
Supreme Court		United States Supreme Court
Tax Legislation		Tax Cuts and Jobs Act of 2017
Tilden		Tilden Mining Company
VAPP		Valley Power Plant



2018 Form 10-K	iv	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 Item 1A. Risk Factors 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/or 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, energy efficiency mandates, and tax laws that affect our ability to use production tax credits and investment tax credits;


•	The remaining uncertainty surrounding the Tax Legislation enacted in December 2017, 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,



2018 Form 10-K	1	Wisconsin Electric Power Company

Table of Contents

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;


•	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 and to comply with state notification laws;


•	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, and related legislation or regulation supporting the use of that technology, that result in competitive disadvantages and create the potential for impairment of existing assets;


•	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.



2018 Form 10-K	2	Wisconsin Electric Power Company

Table of Contents

PART I

ITEM 1. BUSINESS

A. INTRODUCTION

In this report, when we refer to "us," "we," "our," or "ours," we are referring to Wisconsin Electric Power Company. The term "utility" refers to our regulated activities, while the term "non-utility" refers to our activities that are not regulated, as well as the activities of our former subsidiary, Bostco, which was dissolved in October 2018. References to "Notes" are to the Notes to the Consolidated Financial Statements included in this Annual Report on Form 10-K. See Note 2, Dispositions , for more information on the sale of the remaining assets of Bostco and the dissolution of this entity.

We are a subsidiary of WEC Energy Group and were incorporated in the state of Wisconsin in 1896. We maintain our principal executive offices in Milwaukee, Wisconsin and serve customers in Wisconsin and served customers in the Upper Peninsula of Michigan through December 31, 2016. Effective January 1, 2017, we transferred our electric customers (other than Tilden, which is discussed in more detail below) and distribution assets located in the Upper Peninsula of Michigan to UMERC, a stand-alone utility owned by WEC Energy Group. See Note 21, Regulatory Environment, for more information on UMERC.

We conduct our business primarily through our utility reportable segment. Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 16, Investment in American Transmission Company, for more information .

For more information about our utility operations, including financial and geographic information, see Note 17, Segment Information , and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.

Available Information

Our annual and periodic filings with the SEC are available, free of charge, on WEC Energy Group's website, www.wecenergygroup.com, as soon as reasonably practicable after they are filed with or furnished to the SEC. You may also obtain materials we filed with or furnished to the SEC on their website at www.sec.gov .

B. UTILITY SEGMENT

ELECTRIC UTILITY OPERATIONS

We are the largest electric utility in the state of Wisconsin. We generate and distribute electric energy to customers located in southeastern Wisconsin (including the metropolitan Milwaukee area), east central Wisconsin, and northern Wisconsin, and serve an iron ore mine customer, Tilden, in the Upper Peninsula of Michigan.

Through December 31, 2016, we served other electric customers in the Upper Peninsula of Michigan. Effective January 1, 2017, we transferred our electric customers (other than Tilden) and electric distribution assets located in the Upper Peninsula of Michigan to UMERC, a stand-alone utility owned by WEC Energy Group. See Note 3, Related Parties , and Note 21, Regulatory Environment , for more information. UMERC currently meets its market obligations through power purchase agreements with us and WPS. UMERC will begin to generate electricity when its new generation solution in the Upper Peninsula of Michigan begins commercial operation, which is expected to occur during the second quarter of 2019.



2018 Form 10-K	3	Wisconsin Electric Power Company

Table of Contents

Operating Revenues

The following table shows electric utility operating revenues, including steam operations. For information about our operating revenues disaggregated by customer class for the year ended December 31, 2018, see Note 4, Operating Revenues . For more information about our significant accounting policies related to the recognition of revenues, see Note 1(d), Operating Revenues .



	Year Ended December 31
(in millions)	2017		2016
Operating revenues
Residential	$	1,178.4	$	1,243.3
Small commercial and industrial	1,015.9		1,046.1
Large commercial and industrial	657.3		699.3
Other	21.2		21.0
Total retail revenues	2,872.8		3,009.7
Wholesale	118.8		88.7
Resale	238.0		224.4
Steam	23.3		27.2
Other operating revenues *	83.3		90.6
Total operating revenues	$	3,336.2	$	3,440.6


*	Includes SSR revenues, rent income, and ancillary revenues, partially offset by revenues from Tilden that are being deferred until a future rate proceeding. For more information, see the discussion below under the heading "Large Electric Retail Customers."

Electric Sales

Our electric energy deliveries included supply and distribution sales to retail and wholesale customers. In 2018 , retail electric revenues accounted for 90.7% of total electric operating revenues, while wholesale and resale electric revenues accounted for 8.2% of total electric operating revenues. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Utility Segment Contribution to Operating Income for information on MWh sales by customer class.

We are authorized to provide retail electric service in designated territories in the state of Wisconsin, as established by indeterminate permits and boundary agreements with other utilities. Although we no longer provide electric service in certain territories in the state of Michigan, we continue, on an interim basis, to provide service to the Tilden mine located in the Upper Peninsula of Michigan. See the discussion below under the heading "Large Electric Retail Customers."

We buy and sell wholesale electric power by participating in the MISO Energy Markets. The cost of our individual generation offered into the MISO Energy Markets compared to our competitors affects how often our generating units are dispatched and whether we buy or sell power based on our customers' needs. For more information, see D. Regulation.

Steam Sales

We have a steam utility that generates, distributes, and sells steam supplied by VAPP to customers in metropolitan Milwaukee, Wisconsin. Steam is used by customers for processing, space heating, domestic hot water, and humidification. Annual sales of steam fluctuate from year to year based on system growth and variations in weather conditions. In April 2016, we sold the MCPP steam generation and distribution assets, located in Wauwatosa, Wisconsin. MCPP primarily provided steam to the Milwaukee Regional Medical Center hospitals and other campus buildings. See Note 2, Dispositions, for more information .

Electric Sales Forecast

Our service territory experienced growth in weather-normalized retail electric sales in 2018 due to customer growth. We currently forecast retail electric sales volumes, excluding the Tilden iron ore mine located in the Upper Peninsula of Michigan, to grow between 0.5% and 1.0% over the next five years, assuming normal weather. Electric peak demand is expected to grow between flat and 0.5% over the next five years. The Tilden mine will no longer be a retail customer of ours once UMERC's new generation solution in the Upper Peninsula of Michigan begins commercial operation, which is expected to occur in the second quarter of 2019. At that time, Tilden will become a retail customer of UMERC.



2018 Form 10-K	4	Wisconsin Electric Power Company

Table of Contents

Customers



	Year Ended December 31
(in thousands)	2018	2017	2016
Electric customers – end of year
Residential	1,016.3	1,009.1	1,026.0
Small commercial and industrial	115.3	114.5	116.7
Large commercial and industrial	0.6	0.7	0.7
Other	2.6	2.5	2.5
Total electric customers – end of year	1,134.8	1,126.8	1,145.9

Steam customers – end of year	0.4	0.4	0.4

Large Electric Retail Customers

We provide electric utility service to a diversified base of customers in industries such as governmental, municipalities, cooperatives, and marketers, metals and other manufacturing, food products, health services, mining, education, and paper.

In February 2015, Tilden, along with another affiliated iron ore mine located in the Upper Peninsula of Michigan, returned as customers after choosing an alternative electric supplier in September 2013. We entered into a contract with each of the mines to provide full requirements electric service through December 31, 2019. Since 2015, we have been deferring, and expect to continue to defer, the revenues less costs of sales from the mine sales and will apply these amounts for the benefit of Wisconsin retail electric customers in a future rate proceeding, as ordered by the PSCW.

In 2016, one of the iron ore mines closed, and the related contract for full requirements electric service was terminated. In August 2016, WEC Energy Group entered into a new agreement with Tilden under which it will purchase electric power from UMERC for 20 years for the remaining mine, contingent upon UMERC's construction of natural gas-fired generation in the Upper Peninsula of Michigan. Tilden will continue to receive full requirements electric service from us under the existing contract until UMERC's generation solution in the Upper Peninsula of Michigan begins commercial operation, which is expected to occur during the second quarter of 2019. See Note 3, Related Parties , and Note 21, Regulatory Environment , for more information.

Wholesale Customers

We provide wholesale electric service to various customers, including electric cooperatives, municipal joint action agencies, other investor-owned utilities, municipal utilities, and energy marketers. Wholesale sales accounted for 5.2% , 4.6%, and 3.2% of total electric energy sales volumes during 2018 , 2017 , and 2016 , respectively. Wholesale revenues accounted for 3.4%, 3.6%, and 2.6% of total electric operating revenues during 2018 , 2017 , and 2016 , respectively.

Resale

The majority of our sales for resale are sold into an energy market operated by MISO at market rates based on availability of our generation and market demand. Resale sales accounted for 15.3% , 23.5%, and 23.0% of total electric energy sales volumes during 2018 , 2017 , and 2016 , respectively. Resale revenues accounted for 4.8%, 7.1%, and 6.5% of total electric operating revenues during 2018 , 2017 , and 2016 , respectively. Retail fuel costs are reduced by the amount that revenue exceeds the costs of sales derived from these opportunity sales.

Electric Generation and Supply Mix

Our electric supply strategy is to provide our customers with energy from plants using a diverse fuel mix that is expected to maintain a stable, reliable, and affordable supply of electricity. Through our participation in the MISO Energy Markets, we supply a significant amount of electricity to our customers from power plants that we own or lease from We Power. We supplement our internally generated power supply with long-term power purchase agreements, including the Point Beach power purchase agreement discussed under the heading "Power Purchase Commitments," and through spot purchases in the MISO Energy Markets. We also sell excess capacity into the MISO Energy Markets when it is economical, which reduces net fuel costs by offsetting costs of purchased power.



2018 Form 10-K	5	Wisconsin Electric Power Company

Table of Contents

Our rated capacity by fuel type as of December 31, including the units we lease from We Power, is shown below. For more information on our electric generation facilities, see Item 2. Properties.



	Rated Capacity in MW ⁽¹⁾
	2018	2017	2016
Coal	2,489	3,599	3,582
Natural gas:
Combined cycle	1,232	1,182	1,140
Steam turbine ⁽²⁾	269	240	240
Natural gas/oil peaking units ⁽³⁾	989	982	962
Renewables ⁽⁴⁾	145	191	190
Total rated capacity	5,124	6,194	6,114


⁽¹⁾	Rated capacity is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. We are a summer peaking electric utility, and amounts are primarily based on expected capacity ratings for the following summer. The values were established by tests and may change slightly from year to year.


⁽²⁾	The natural gas steam turbine represents the rated capacity associated with VAPP.


⁽³⁾	Certain dual-fueled facilities generally burn oil only if natural gas is not available due to constraints on the natural gas pipeline and/or at the local natural gas distribution company that delivers natural gas to the plants.


⁽⁴⁾	Includes hydroelectric, biomass, and wind generation.

The table below indicates our sources of electric energy supply as a percentage of sales for the three years ended December 31, as well as estimates for 2019 :



	Estimate		Actual
	2019		2018		2017		2016
Company-owned or leased generation units:
Coal *	36.7	%	45.5	%	50.8	%	49.9	%
Natural gas:
Combined cycle	22.2	%	17.7	%	14.7	%	15.9	%
Steam turbine	1.1	%	0.8	%	1.1	%	1.2	%
Natural gas/oil peaking units	0.3	%	0.8	%	0.5	%	0.7	%
Renewables	4.0	%	3.7	%	3.8	%	3.5	%
Total company-owned or leased generation units	64.3	%	68.5	%	70.9	%	71.2	%
Power purchase contracts:
Nuclear	27.8	%	27.1	%	25.2	%	24.6	%
Natural gas	4.4	%	2.3	%	1.8	%	2.4	%
Renewables	1.9	%	1.3	%	1.8	%	1.8	%
Total power purchase contracts	34.1	%	30.7	%	28.8	%	28.8	%
Purchased power from MISO	1.6	%	0.8	%	0.3	%	—	%
Total purchased power	35.7	%	31.5	%	29.1	%	28.8	%
Total electric utility supply	100.0	%	100.0	%	100.0	%	100.0	%


*	Although the generation of PIPP has been included as a source of our electric energy supply for the three years ended December 31, we have only included this generation facility as a source of our estimated 2019 electric energy supply through its expected retirement date on or before May 31, 2019. See Note 6, Property, Plant, and Equipment, for more information .

Reshaping our Generation Fleet

The following discussion summarizes information about our generation facilities, including the planned reshaping of our generation fleet to balance reliability and customer cost with environmental stewardship. 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% and 80% below 2005 levels by 2030 and 2050, respectively.



2018 Form 10-K	6	Wisconsin Electric Power Company

Table of Contents

Coal-Fired Generation

As of December 31, 2018 , our coal-fired generation, including the ERGS units we lease from We Power, consists of three operating plants with a rated capacity of 2,489 MW. For more information about our operating plants, see Item 2. Properties.

We plan to retire approximately 1,500 MW of coal-fired generation by 2020, as a result of WEC Energy Group's generation reshaping plan. As part of this effort during 2018, we retired the Pleasant Prairie power plant, which accounted for approximately 1,190 MW of coal-fired generation. We are required to retire PIPP by May 31, 2019. For more information about the retirement of these plants, see Note 6, Property, Plant, and Equipment .

Natural Gas-Fired Generation

Our natural gas-fired generation, including the PWGS units we lease from We Power, consists of four operating plants, including peaking units, with a rated capacity of 2,300 MW as of December 31, 2018 . For more information about our operating plants, see Item 2. Properties.

Oil-Fired Generation

Our oil-fired generation had a rated capacity of 190 MW as of December 31, 2018 . We also have natural gas-fired peaking units with a rated capacity of 799 MW, which have the ability to burn oil if natural gas is not available due to delivery constraints. For more information about our operating plants, see Item 2. Properties.

Renewable Generation

We meet a portion of our electric generation supply with various renewable energy resources. This helps us maintain compliance with renewable energy legislation in Wisconsin and Michigan. These renewable energy resources also help us maintain diversity in our generation portfolio, which effectively serves as a price hedge against future fuel costs, and will help mitigate the risk of potential unknown costs associated with any future carbon restrictions for electric generators. For more information about our renewable generation, see Item 2. Properties.

I n December 2018, we received approval from the PSCW for the Dedicated Renewable Energy Resource pilot program, a program for customers who wish to access a large-scale renewable project located in Wisconsin that we would operate. The project will contribute toward meeting our peak demand, adding up to 150 MW of renewables to our portfolio.

Solar

I n December 2018, we received approval from the PSCW for the Solar Now pilot program, which is expected to add 35 MW of renewables to our portfolio and will allow commercial and industrial customers to site solar arrays on their property.

Hydroelectric

Our hydroelectric generating system consists of 13 operating plants with a total installed capacity of 91 MW and a rated capacity of 53 MW as of December 31, 2018 . All of our hydroelectric facilities follow FERC guidelines and/or regulations.

Wind

We have four wind sites, consisting of 200 turbines, with an installed capacity of 339 MW and a rated capacity of 46 MW as of December 31, 2018 .

Biomass

We have a biomass-fueled power plant at a Rothschild, Wisconsin paper mill site. Wood waste and wood shavings are used to produce a rated capacity of approximately 46 MW of electric power as well as steam to support the paper mill's operations. Fuel for the power plant is supplied by both the paper mill and through contracts with biomass suppliers. The plant also has the ability to burn natural gas if wood waste and wood shavings are not available.



2018 Form 10-K	7	Wisconsin Electric Power Company

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Generation from Leased We Power Units

As discussed above, we also supply electricity to our customers from power plants that we lease from We Power. These plants include the ERGS units and the PWGS units. Lease payments are billed from We Power to us and then recovered in our rates as authorized by the PSCW, the MPSC, and the FERC. We operate the We Power units and are authorized by the PSCW and state law to fully recover prudently incurred operating and maintenance costs in our Wisconsin electric rates. As the operator of the units, we may request We Power to make capital improvements to, or further investments in, the units. Under the lease terms, these capital improvements or further investments will increase lease payments paid by us and should ultimately be recovered in our rates.

Electric System Reliability

The PSCW requires us to maintain a planning reserve margin above our projected annual peak demand forecast to help ensure reliability of electric service to our customers. These planning reserve requirements are consistent with the MISO calculated planning reserve margin. In 2008, the PSCW established a 14.5% reserve margin requirement for long-term planning (planning years two through ten). For short-term planning (planning year one), the PSCW requires Wisconsin utilities to follow the planning reserve margin established by MISO. MISO has a 17.1% installed capacity reserve margin requirement for the planning year from June 1, 2018 , through May 31, 2019 , and a 16.8% installed capacity reserve margin requirement for the planning year from June 1, 2019 , through May 31, 2020 . MISO's short-term reserve margin requirements experience year-to-year fluctuations, primarily due to changes in the average forced outage rate of generation within the MISO footprint.

Michigan legislation requires all electric providers to demonstrate to the MPSC that they have enough resources to serve the anticipated needs of their customers for a minimum of four consecutive planning years beginning in the upcoming planning year June 1, 2019 , through May 31, 2020 . The MPSC has established future planning reserve margin requirements based on the same study conducted by MISO that determines the short-term reserve margin requirements.

In both of our Wisconsin and Michigan jurisdictions, we had adequate capacity through company-owned generation units, leased generating units, and power purchase contracts to meet the MISO calculated planning reserve margin during the current planning year. We also fully anticipate that we will have adequate capacity to meet the planning reserve margin requirements for the upcoming planning year in both jurisdictions. However, extremely hot weather, unexpected equipment failure, or unavailability across the 15-state MISO footprint could require us to call upon load management procedures. Load management procedures allow for the reduction of energy use through agreements with customers to directly shut off their equipment or through interruptible service, where customers agree to reduce their load in the case of an emergency interruption.

Fuel and Purchased Power Costs

Our retail electric rates in Wisconsin are established by the PSCW and include base amounts for fuel and purchased power costs. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under- or over-collections of actual fuel and purchased power costs that exceed a 2% price variance from the costs included in the rates charged to customers. Prudently incurred fuel and purchased power costs are recovered dollar-for-dollar from our Michigan retail electric customer. For more information about the fuel rules, see D. Regulation.

Our average fuel and purchased power costs per MWh by fuel type were as follows for the years ended December 31:



	2018		2017		2016
Coal	$	22.39	$	22.26	$	22.68
Natural gas combined cycle	22.05		22.85		19.13
Natural gas/oil peaking units	63.29		60.44		46.99
Biomass	97.33		118.76		103.24
Purchased power	45.66		45.50		43.51

We purchase coal under long-term contracts, which helps with price stability. In the past, coal and associated transportation services were exposed to volatility in pricing due to changing domestic and world-wide demand for coal and diesel fuel. To moderate the volatility, we were given PSCW approval for a hedging program, which allows us to hedge up to 75% of our potential risks related to rail transportation fuel surcharge exposure. However, due to decreased volatility over the last few years, we suspended the fuel surcharge hedging program in 2017.



2018 Form 10-K	8	Wisconsin Electric Power Company

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We purchase natural gas for our plants on the spot market from natural gas marketers, utilities, and producers, and we arrange for transportation of the natural gas to our plants. We have firm and interruptible transportation, as well as balancing and storage agreements, intended to support our plants' variable usage. We also have a PSCW-approved program that allows us to hedge up to 75% of our estimated natural gas use for electric generation in order to help manage our natural gas price risk.

Our hedging programs are generally implemented on a 36-month forward-looking basis. The results of these programs are reflected in the average costs of natural gas and purchased power.

Coal Supply

We diversify the coal supply for our electric generating facilities by purchasing coal from several mines in Wyoming, as well as from various other states. For 2019 , approximately 89% of our total projected coal requirements of 6.4 million tons are contracted under fixed-price contracts. See Note 19, Commitments and Contingencies, for more information on amounts of coal purchases and coal deliveries under contract.

The annual tonnage amounts contracted for the next two years are as follows. We have not entered into any coal contracts for years after 2020.



(in thousands)		Annual Tonnage
2019		5,733
2020		1,925

Coal Deliveries

All of our 2019 coal requirements are expected to be shipped by our owned or leased unit trains under existing transportation agreements. The unit trains transport the coal for electric generating facilities from mines in Wyoming, Pennsylvania, and Montana. The coal is transported by train to our rail-served electric-generating facilities and to dock storage in Superior, Wisconsin, until needed by our lake vessel-served facility, PIPP. See Note 6, Property, Plant, and Equipment, for more information about the planned retirement of PIPP. Additional small volume agreements may also be used to supplement the normal coal supply for our facilities.

Midcontinent Independent System Operator Costs

In connection with its status as a FERC approved RTO, MISO developed and operates the MISO Energy Markets, which include its bid-based energy and ancillary services markets. We are a participant in the MISO Energy Markets. For more information on MISO, see D. Regulation.

Power Purchase Commitments

We enter into short and long-term power purchase commitments to meet a portion of our anticipated electric energy supply needs. Our power purchase commitments with unaffiliated parties are 1,279 MW per year for 2019 through 2021 and 1,033 MW per year for 2022 and 2023, which exclude planning capacity purchases. These amounts include 1,033 MW per year related to a long-term power purchase agreement for electricity generated by Point Beach. Due to the actual and planned retirement of generation resources, we have entered into purchase agreements to procure additional planning capacity in order to maintain our compliance with planning reserve requirements as established by the PSCW, MPSC, and MISO.

Other Matters

Seasonality

Our electric utility sales are impacted by seasonal factors and varying weather conditions. We sell more electricity during the summer months because of the residential cooling load. We continue to upgrade our electric distribution system, including substations, transformers, and lines, to meet the demand of our customers. Our generating plants performed as expected during the warmest periods of the summer, and all power purchase commitments under firm contract were received. During this period, we did not require public appeals for conservation, and we did not interrupt or curtail service to non-firm customers who participate in load management programs.



2018 Form 10-K	9	Wisconsin Electric Power Company

Table of Contents

Competition

We face competition from various entities and other forms of energy sources available to customers, including self-generation by large industrial customers and alternative energy sources. We compete with other utilities for sales to municipalities and cooperatives as well as with other utilities and marketers for wholesale electric business.

For more information on competition in our service territories, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Competitive Markets.

Environmental Matters

For information regarding environmental matters, especially as they relate to coal-fired generating facilities, see Note 19, Commitments and Contingencies .

NATURAL GAS UTILITY OPERATIONS

We are authorized to provide retail natural gas distribution service in designated territories in the state of Wisconsin, as established by indeterminate permits and boundary agreements with other utilities. We also transport customer-owned natural gas. We operate in three distinct service areas including west and south of the City of Milwaukee, the Appleton area, and areas within Iron and Vilas Counties, Wisconsin.

We provide natural gas utility service to a diversified base of industrial customers who are largely within our electric service territory. Major industries served include governmental, food and kindred products, education, real estate, and metal manufacturing. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Utility Segment Contribution to Operating Income for information on natural gas sales volumes by customer class.

Operating Revenues

The following table shows natural gas utility operating revenues. For information about our operating revenues disaggregated by customer class for the year ended December 31, 2018, see Note 4, Operating Revenues . For more information about our significant accounting policies related to the recognition of revenues, see Note 1(d), Operating Revenues .



	Year Ended December 31
(in millions)	2017			2016
Operating revenues
Residential	$	249.0		$	238.6
Commercial and industrial	114.3			105.0
Total retail revenues	363.3			343.6
Transport	13.7			13.6
Other operating revenues *	(1.5		)	(5.0		)
Total operating revenues	$	375.5		$	352.2


*	Includes amounts refunded to customers for purchased gas adjustment costs.

Natural Gas Sales Forecast

Our service territory experienced growth in weather-normalized natural gas deliveries (excluding natural gas deliveries for electric generation) in 2018 due to customer growth. We currently forecast retail natural gas delivery volumes to grow at a rate between 0.5% and 1.0% over the next five years, assuming normal weather.



2018 Form 10-K	10	Wisconsin Electric Power Company

Table of Contents

Customers



	Year Ended December 31
(in thousands)	2018	2017	2016
Customers – end of year
Residential	449.4	445.9	442.0
Commercial and industrial	39.9	39.6	39.4
Transport	0.8	0.8	0.7
Total customers	490.1	486.3	482.1

Natural Gas Supply, Pipeline Capacity and Storage

We have been able to meet our contractual obligations with both our suppliers and our customers. For more information on our natural gas utility supply and transportation contracts, see Note 19, Commitments and Contingencies .

Pipeline and Storage Capacity

The interstate pipelines serving Wisconsin originate in major natural gas producing areas of North America: the Oklahoma and Texas basins, western Canada, and the Rocky Mountains. We have contracted for long-term firm capacity from a number of these sources. This strategy reflects management's belief that overall supply security is enhanced by geographic diversification of the supply portfolio.

Due to variations in natural gas usage in Wisconsin, we have also contracted for substantial underground storage capacity, primarily in Michigan. We target storage inventory levels at approximately 40% of forecasted demand for November through March. Diversity of natural gas supply enables us to manage significant changes in demand and to optimize our overall natural gas supply and capacity costs. We generally inject natural gas into storage during the spring and summer months and withdraw it in the winter months.

In June 2017, our parent company completed its acquisition of Bluewater. Bluewater owns natural gas storage facilities in Michigan that provide a portion of the current storage needs for our natural gas utility operations. We have entered into a long-term service agreement to take a portion of the storage from Bluewater. See Note 3, Related Parties, for more information on this transaction.

We hold daily transportation and storage capacity entitlements with interstate pipeline companies as well as other service providers under varied-length long-term contracts.

Pipeline and storage capacity and natural gas supplies under contract can be resold in secondary markets. Peak or near-peak demand generally occurs only a few times each year. The secondary markets facilitate utilization of capacity and supply during times when the contracted capacity and supply are in excess of utility demand. The proceeds from these transactions are passed through to customers, subject to our approved GCRM. For information on our GCRM, see Note 1(d), Operating Revenues .

To ensure a reliable supply of natural gas during peak winter conditions, we have liquefied natural gas and propane facilities located within our distribution system. These facilities are typically utilized during extreme demand conditions to ensure reliable supply to our customers.

Combined with our storage capability, management believes that the volume of natural gas under contract is sufficient to meet our forecasted firm peak-day and seasonal demand. Our forecasted design peak-day throughput is 10.1 million therms for the 2018 through 2019 heating season. Our peak daily send-out during 2018 was 6.8 million therms on January 1, 2018 .

Natural Gas Supply

We have contracts for firm supplies with terms of 3–5 months with suppliers for natural gas acquired in the Chicago, Illinois market hub and in the producing areas discussed above. The pricing of the term contracts is based upon first of the month indices.

We expect to continue to make natural gas purchases in the spot market as price and other circumstances dictate. We have supply relationships with a number of sellers from whom we purchase natural gas in the spot market.



2018 Form 10-K	11	Wisconsin Electric Power Company

Table of Contents

Hedging Natural Gas Supply Prices

We have PSCW approval to hedge up to 60% of planned winter demand and up to 15% of planned summer demand using a mix of NYMEX-based natural gas options and futures contracts. This approval allows us to pass 100% of the hedging costs (premiums, brokerage fees and losses) and proceeds (gains) to customers through our GCRM.

To the extent that opportunities develop and physical supply operating plans are supportive, we also have PSCW approval to utilize NYMEX-based natural gas derivatives to capture favorable forward market price differentials. That approval provides for 100% of the related proceeds to accrue to our GCRM.

Seasonality

Since the majority of our customers use natural gas for heating, customer use is sensitive to weather and is generally higher during the winter months. Accordingly, we are subject to some variations in earnings and working capital throughout the year as a result of changes in weather.

The seasonality of natural gas revenues causes the timing of cash collections to be concentrated from January through June. A portion of our winter natural gas supply needs is typically purchased and stored from April through November. Also, planned capital spending on our natural gas distribution facilities is concentrated in April through November. Because of these timing differences, the cash flow from customers is typically supplemented with temporary increases in short-term borrowings (from external sources) during the late summer and fall. Short-term debt is typically reduced over the January through June period.

Competition

We face varying degrees of competition from other entities and other forms of energy available to consumers. Many large commercial and industrial customers have the ability to switch between natural gas and alternative fuels. Commercial and industrial customers have the opportunity to choose a natural gas supplier other than us. We offer both natural gas transportation service and interruptible natural gas sales to enable customers to better manage their energy costs. Transportation customers purchase natural gas directly from third-party natural gas suppliers and use our distribution systems to transport the natural gas to their facilities. We earn a distribution charge for transporting the natural gas for these customers. As such, the loss of revenue associated with the cost of natural gas that our transportation customers purchase from third-party suppliers has little impact on our net income, as it is offset by an equal reduction to natural gas costs. Customers continue to switch between firm system supply, interruptible system supply, and transportation service each year as the economics and service options change.

C. OTHER SEGMENT

Prior to January 1, 2017, our other segment also included our approximate 23% ownership interest in ATC, a for-profit, transmission-only company regulated by the FERC and certain state regulatory commissions. Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 16, Investment in American Transmission Company, for more information .

D. REGULATION

In addition to the specific regulations noted below, we are also subject to regulations, where applicable, of the EPA, the WDNR, the MDEQ, the Michigan Department of Natural Resources, and the United States Army Corps of Engineers.



2018 Form 10-K	12	Wisconsin Electric Power Company

Table of Contents

Rates

Our rates were regulated by the various commissions shown in the table below during 2018 . These commissions have general supervisory and regulatory powers over public utilities in their respective jurisdictions.



Regulated Rates		Regulatory Commission
Retail electric, natural gas, and steam		PSCW
Retail electric		MPSC *
Wholesale power		FERC


*	Effective January 1, 2017, we transferred all of our electric distribution assets and customers located in the Upper Peninsula of Michigan to UMERC, with the exception of Tilden. See Note 3, Related Parties , and Note 21, Regulatory Environment , for more information.

Embedded within our electric rates is an amount to recover fuel and purchased power costs. The Wisconsin retail fuel rules require us to defer, for subsequent rate recovery or refund, any under-collection or over-collection of fuel and purchased power costs that are outside of our symmetrical fuel cost tolerance, which the PSCW typically sets at plus or minus 2% of our approved fuel and purchased power cost plan. Our deferred fuel and purchased power costs are subject to an excess revenues test. If our ROE in a given year exceeds the ROE authorized by the PSCW, the recovery of under-collected fuel and purchased power costs would be reduced by the amount by which our return exceeds the authorized amount. Prudently incurred fuel and purchased power costs are recovered dollar-for-dollar from our Michigan retail electric customer and our wholesale electric customers.

Our natural gas utility operates under a GCRM as approved by the PSCW. Generally, the GCRM allows for a dollar-for-dollar recovery of prudently incurred natural gas costs.

See Note 1(d), Operating Revenues, for more information on the significant mechanisms we had in place during 2018 that allowed us to recover or refund changes in prudently incurred costs from rate case-approved amounts.

We have been subject to an earnings sharing mechanism since January 2016, and will continue to be subject to it through 2019 . See Note 21, Regulatory Environment , for more information on our earnings sharing mechanism and on how our rates are set. Orders from our respective regulators can be viewed at the following websites:



Regulatory Commission		Website
PSCW		https://psc.wi.gov/
MPSC		http://www.michigan.gov/mpsc/
FERC		http://www.ferc.gov/

The material and information contained on these websites are not intended to be a part of, nor are they incorporated by reference into, this Annual Report on Form 10-K.

The following table compares our utility operating revenues by regulatory jurisdiction for each of the three years ended December 31:



	2018				2017				2016
(in millions)	Amount		Percent		Amount		Percent		Amount		Percent
Electric
Wisconsin	$	2,876.8	89.4	%	$	2,901.2	87.0	%	$	2,973.3	86.4	%
Michigan *	83.8		2.6	%	78.2		2.3	%	154.2		4.5	%
FERC – Wholesale *	258.2		8.0	%	356.8		10.7	%	313.1		9.1	%
Total	3,218.8		100.0	%	3,336.2		100.0	%	3,440.6		100.0	%

Natural Gas – Wisconsin	406.2		100.0	%	375.5		100.0	%	352.2		100.0	%

Total utility operating revenues	$	3,625.0			$	3,711.7			$	3,792.8


*	Effective January 1, 2017, we transferred all of our electric distribution assets and customers located in the Upper Peninsula of Michigan to UMERC, with the exception of Tilden. UMERC currently purchases a portion of its power from us. The revenues received from UMERC are



2018 Form 10-K	13	Wisconsin Electric Power Company

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primarily included in the FERC – Wholesale line above. See Note 3, Related Parties , and Note 21, Regulatory Environment , for additional information on UMERC.

Electric Transmission, Capacity, and Energy Markets

In connection with its status as a FERC approved RTO, MISO operates bid-based energy markets. MISO has been able to assume significant balancing area responsibilities such as frequency control and disturbance control.

In MISO, base transmission costs are currently being paid by load-serving entities located in the service territories of each MISO transmission owner. The FERC has previously confirmed the use of the current transmission cost allocation methodology. Certain additional costs for new transmission projects are allocated throughout the MISO footprint.

As part of MISO, a market-based platform is used for valuing transmission congestion premised upon the LMP system that is used in certain northeastern and mid-Atlantic states. The LMP system includes the ability to hedge transmission congestion costs through ARRs and FTRs. ARRs are allocated to market participants by MISO, and FTRs are purchased through auctions. A new allocation and auction were completed for the period of June 1, 2018 , through May 31, 2019 . The resulting ARR valuation and the secured FTRs are expected to mitigate our transmission congestion risk for that period.

MISO has an annual zonal resource adequacy requirement to ensure there is sufficient generation capacity to serve the MISO market. To meet this requirement, capacity resources can be acquired through MISO's annual capacity auction, bilateral contracts for capacity, or provided from generating or demand response resources. All of our capacity requirements during the planning year from June 1, 2018 , through May 31, 2019 were met.

Other Electric Regulations

We are subject to the Federal Power Act and the corresponding regulations developed by certain federal agencies. The Energy Policy Act amended the Federal Power Act in 2005 to, among other things, make electric utility industry consolidation more feasible, authorize the FERC to review proposed mergers and the acquisition of generation facilities, change the FERC regulatory scheme applicable to qualifying cogeneration facilities, and modify certain other aspects of energy regulations and Federal tax policies applicable to us. Additionally, the Energy Policy Act created an Electric Reliability Organization to be overseen by the FERC, which established mandatory electric reliability standards and has the authority to levy monetary sanctions for failure to comply with these standards.

We are subject to Act 141 in Wisconsin and Public Acts 295 and 342 in Michigan, which contain certain minimum requirements for renewable energy generation.

All of our hydroelectric facilities follow FERC guidelines and/or regulations.

Other Natural Gas Regulations

Almost all of the natural gas we distribute is transported to our distribution systems by interstate pipelines. The pipelines' transportation and storage services are regulated by the FERC under the Natural Gas Act and the Natural Gas Policy Act of 1978. In addition, the Pipeline and Hazardous Materials Safety Administration and the PSCW are responsible for monitoring and enforcing requirements governing our natural gas safety compliance programs for our pipelines under United States Department of Transportation regulations. These regulations include 49 Code of Federal Regulations (CFR) Part 191 (Transportation of Natural and Other Gas by Pipeline; Annual Reports, Incident Reports, and Safety-Related Condition Reports), 49 CFR Part 192 (Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards), and 49 CFR Part 195 (Transportation of Hazardous Liquids by Pipeline).

We are required to provide natural gas service and grant credit (with applicable deposit requirements) to customers within our service territory. We are generally not allowed to discontinue natural gas service during winter moratorium months to residential heating customers who do not pay their bills. Federal and certain state governments have programs that provide for a limited amount of funding for assistance to our low-income customers.



2018 Form 10-K	14	Wisconsin Electric Power Company

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E. ENVIRONMENTAL COMPLIANCE

Our operations are subject to extensive environmental regulation by state and federal environmental agencies governing air and water quality, hazardous and solid waste management, environmental remediation, and management of natural resources. Costs associated with complying with these requirements are significant. Additional future environmental regulations or revisions to existing laws, including for example, additional regulation of GHG emissions, coal combustion products, air emissions, or wastewater discharges, could significantly increase these environmental compliance costs.

Anticipated expenditures for environmental compliance and remediation issues for the next three years are included in the estimated capital expenditures described in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital Requirements. For a discussion of matters related to manufactured gas plant sites and air and water quality, see Note 19, Commitments and Contingencies .

F. EMPLOYEES

As of December 31, 2018 , we had 2,739 employees.

As of December 31, 2018 , we had employees represented under labor agreements with the following bargaining units:



	Number of Employees	Expiration Date of Current Labor Agreement
Local 2150 of International Brotherhood of Electrical Workers	1,611	August 15, 2020
Local 420 of International Union of Operating Engineers	360	September 30, 2021
Local 2006 Unit 1 of United Steel Workers of America	114	October 31, 2021
Local 510 of International Brotherhood of Electrical Workers	75	October 31, 2020
Total	2,160



2018 Form 10-K	15	Wisconsin Electric Power Company

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ITEM 1A. RISK FACTORS

We are subject to a variety of risks, many of which are beyond our control, that may adversely affect our business, financial condition, and results of operations. You should carefully consider the following risk factors, as well as the other information included in this report and other documents filed by us with the SEC from time to time, when making an investment decision.

Risks Related to Legislation and Regulation

Our business is significantly impacted by governmental regulation and oversight.

We are subject to significant state, local, and federal governmental regulation, including regulation by the PSCW, MPSC, and the FERC. These regulations significantly influence our operating environment, may affect our ability to recover costs from utility customers, and cause us to incur substantial compliance and other costs. Changes in regulations, interpretations of regulations, or the imposition of new regulations could also significantly impact us, including requiring us to change our business operations. Many aspects of our operations are regulated and impacted by government regulation, including, but not limited to: the rates we charge our retail electric, natural gas, and steam customers; our authorized rates of return; construction and operation of electric generating facilities and electric and natural gas distribution systems, including the ability to recover such costs; decommissioning generating facilities and the ability to recover the related costs, and continuing to recover the return on the carrying value of these facilities; wholesale power service practices; electric reliability requirements and accounting; participation in the interstate natural gas pipeline capacity market; standards of service; issuance of securities; short-term debt obligations; transactions with affiliates; and billing practices. Failure to comply with any applicable rules or regulations may lead to customer refunds, penalties, and other payments, which could materially and adversely affect our results of operations and financial condition.

The rates we are allowed to charge our customers for retail and wholesale services have the most significant impact on our financial condition, results of operations, and liquidity. Rate regulation provides us an opportunity to recover prudently incurred costs and earn a reasonable rate of return on invested capital. However, our ability to obtain rate adjustments in the future is dependent upon regulatory action, and there is no assurance that our regulators will consider all of our costs to have been prudently incurred. In addition, our rate proceedings may not always result in rates that fully recover our costs or provide for a reasonable ROE. We defer certain costs and revenues as regulatory assets and liabilities for future recovery from or refund to customers, as authorized by our regulators. Future recovery of regulatory assets is not assured and is subject to review and approval by our regulators. If recovery of regulatory assets is not approved or is no longer deemed probable, these costs would be recognized in current period expense and could have a material adverse impact on our results of operations, cash flows, and financial condition.

We believe we have obtained the necessary permits, approvals, authorizations, certificates, and licenses for our existing operations, have complied with all of their associated terms, and that our business is conducted in accordance with applicable laws. These permits, approvals, authorizations, certificates, and licenses may be revoked or modified by the agencies that granted them if facts develop that differ significantly from the facts assumed when they were issued. In addition, discharge permits and other approvals and licenses are often granted for a term that is less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. In addition, existing regulations may be revised or reinterpreted by federal, state, and local agencies, or these agencies may adopt new laws and regulations that apply to us. We cannot predict the impact on our business and operating results of any such actions by these agencies.

If we are unable to recover costs of complying with regulations or other associated costs in customer rates in a timely manner, or if we are unable to obtain, renew, or comply with these governmental permits, approvals, authorizations, certificates, or licenses, our results of operations and financial condition could be materially and adversely affected.

We face significant costs to comply with existing and future environmental laws and regulations.

Our operations are subject to numerous federal and state environmental laws and regulations. These laws and regulations govern, among other things, air emissions (including, but not limited to: CO _2, methane, mercury, SO ₂ , and NOx), water quality, wastewater discharges, and management of hazardous, toxic, and solid wastes and substances. We incur significant costs to comply with these environmental requirements, including costs associated with the installation of pollution control equipment, environmental monitoring, emissions fees, and permits at our facilities. In addition, if we fail to comply with environmental laws and regulations, even if caused by factors beyond our control, that failure may result in the assessment of civil or criminal penalties and fines.



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The EPA adopted and implemented (or is in the process of implementing) regulations governing the emission of NOx, SO ₂ , fine particulate matter, mercury, and other air pollutants under the CAA through the NAAQS, the Mercury and Air Toxics Standards rule, the CPP, the Cross-State Air Pollution Rule, and other air quality regulations. In addition, the EPA finalized regulations under the Clean Water Act that govern cooling water intake structures at our power plants and revised the effluent guidelines for steam electric generating plants. The EPA and the United States Army Corps of Engineers (Army Corps) have also adopted a final rule that would expand traditional federal jurisdiction over navigable waters and related wetlands for permitting and other regulatory matters. However, this rule has been stayed, and the EPA and the Army Corps have proposed revisions to it. We continue to assess the potential cost of complying, and to explore different alternatives in order to comply, with these and other environmental regulations. In addition, as a result of the actions taken by the sitting President and Federal Executive Branch since taking office in January 2017, as well as its announced future plans and other factors, there is uncertainty as to what capital expenditures or additional costs may ultimately be required to comply with existing and future environmental laws and regulations.

Existing environmental laws and regulations may be revised or new laws or regulations may be adopted at the federal or state level that could result in significant additional expenditures for our generation units or distribution systems, including, without limitation, costs to further limit GHG emissions from our operations; operating restrictions on our facilities; and increased compliance costs. In addition, the operation of emission control equipment and compliance with rules regulating our intake and discharge of water could increase our operating costs and reduce the generating capacity of our power plants. Any such regulation may also create substantial additional costs in the form of taxes or emission allowances and could affect the availability and/or cost of fossil fuels.

As a result, certain of our coal-fired electric generating facilities have become uneconomical to maintain and operate, which has resulted in some of these units being retired or converted to an alternative type of fuel. For example, as part of our goal to retire approximately 1,500 MW of coal-fired generation by 2020, we retired the Pleasant Prairie power plant during 2018 and are required to retire PIPP by May 31, 2019. Certain of our remaining coal-fired electric generating facilities may also be retired or converted in the future. If other generation facility owners in the Midwest retire a significant number of older coal-fired generation facilities, a potential reduction in the region's capacity reserve margin below acceptable risk levels may result. This could impair the reliability of the grid in the Midwest, particularly during peak demand periods. A reduction in available future capacity could also adversely affect our ability to serve our customers' needs.

We are also subject to significant liabilities related to the investigation and remediation of environmental impacts at certain of our current and former facilities and at third-party owned sites. We accrue liabilities and defer costs (recorded as regulatory assets) incurred in connection with our former manufactured gas plant sites. These costs include all costs incurred to date that we expect to recover, management's best estimates of future costs for investigation and remediation, related legal expenses, and are net of amounts recovered by or that may be recovered from insurance or other third parties. Due to the potential for the imposition of stricter standards and greater regulation in the future, the possibility that other potentially responsible parties may not be financially able to contribute to cleanup costs, a change in conditions or discovery of additional contamination, our remediation costs could increase, and the timing of our capital and/or operating expenditures in the future may accelerate or could vary from the amounts currently accrued.

In the event we are not able to recover all of our environmental expenditures and related costs from our customers in the future, our results of operations and financial condition could be adversely affected. Further, increased costs recovered through rates could contribute to reduced demand for electricity and natural gas, which could adversely affect our results of operations, cash flows, and financial condition.

Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, has increased generally throughout the United States. In particular, personal injury, property damage, and other claims for damages alleged to have been caused by environmental impacts and alleged exposure to hazardous materials have become more frequent. In addition to claims relating to our current facilities, we may also be subject to potential liability in connection with the environmental condition of facilities that we previously owned and operated, regardless of whether the liabilities arose before, during, or after the time we owned or operated these facilities. If we fail to comply with environmental laws and regulations or cause (or caused) harm to the environment or persons, that failure or harm may result in the assessment of civil penalties and damages against us. The incurrence of a material environmental liability or a material judgment in any action for personal injury or property damage related to environmental matters could have a significant adverse effect on our results of operations and financial condition.



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We may face significant costs to comply with the regulation of greenhouse gas emissions.

Management believes it is reasonably likely that the scientific and political attention to issues concerning the existence and extent of climate change, and the role of human activity in it, will continue, with the potential for further regulation that affects our operations. In 2015, the EPA issued a final rule regulating GHG emissions from existing generating units, referred to as the CPP, 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, be held in abeyance, which remains the case. In August 2018, the EPA issued a proposed replacement rule for the CPP, the ACE rule. The proposed ACE rule would require the EPA to develop emission guidelines for states to use to develop their individual state plans. The state plans would focus on reducing GHG emissions by improving the efficiency of fossil-fueled power plants. In December 2018, the EPA proposed to revise the regulations related to new, modified, and reconstructed fossil-fueled power plants. We are continuing to analyze the GHG emission profile of our electric generation resources and to work with other stakeholders to determine the potential impacts to our operations of the CPP, the proposed ACE rule, and federal GHG regulations in general.

There is no guarantee that we will be allowed to fully recover costs incurred to comply with these and other federal regulations or that cost recovery will not be delayed or otherwise conditioned. GHG regulations that may be adopted in the future, at either the federal or state level, may cause our environmental compliance spending to differ materially from the amounts currently estimated. In December 2016, Michigan enacted Act 342, which retains the 10% renewable energy portfolio requirement through 2018, increases the requirement to 12.5% for years 2019 through 2020, and increases the requirement to 15.0% for 2021. These regulations, as well as changes in the fuel markets and advances in technology, could make additional electric generating units uneconomic to maintain or operate, may impact how we operate our existing fossil-fueled power plants and biomass facility, and could affect unit retirement and replacement decisions in the future. These regulations could also adversely affect our future results of operations, cash flows, and financial condition.

In addition, our natural gas delivery systems may generate fugitive gas as a result of normal operations and as a result of excavation, construction, and repair. Fugitive gas typically vents to the atmosphere and consists primarily of methane. CO ₂ is also a byproduct of natural gas consumption. As a result, future regulation of GHG emissions could increase the price of natural gas, restrict the use of natural gas, and adversely affect our ability to operate our natural gas facilities. A significant increase in the price of natural gas may increase rates for our natural gas customers, which could reduce natural gas demand.

We also continue to monitor efforts by investors and other stakeholders to increase pressure on us and others to take more aggressive action to reduce future GHG emissions in order to limit future global temperature increases to less than two degrees Celsius. These efforts could impact how we operate our electric generating units and natural gas facilities and lead to increased competition and regulation, all of which could have a material adverse effect on our operations and financial condition.

Changes in federal income tax policy may adversely affect our financial condition, results of operations, and cash flows, as well as our credit ratings.

We have invested or will be investing in renewable energy generating facilities, several of which generate production tax credits and investment tax credits that we use to reduce our federal tax obligations. The amount of tax credits we earn depends on the level of electricity generated, the applicable tax credit rate, and the amount of the investment in qualifying property. If our tax credits were disallowed in whole or in part as a results of an IRS audit or changes in tax law, we could owe tax liabilities for previously recognized tax credits that could significantly impact our earnings and cash flows.

In addition, if corporate tax rate or policies are changed with future federal or state legislation, we may be required to take material charges against earnings. For example, the United States federal income tax legislation enacted in December 2017 significantly changed the United States Internal Revenue Code, including taxation of United States corporations, by, among other things, reducing the federal corporate income tax rate, limiting interest deductions, and altering the expensing of capital expenditures. Parts of the Tax Legislation still remain unclear and will require interpretations and implementing regulations by the Treasury Department and the IRS, as well as state income tax authorities, and the Tax Legislation could be subject to potential amendments and technical corrections, any of which could lessen or increase certain adverse impacts of the Tax Legislation. In addition, the regulatory treatment of the impacts of the Tax Legislation will be subject to the discretion of the FERC and state public utility commissions. State



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and local taxing authorities continue to evaluate the impact of federal income tax reform, and any changes on the state or local level could lessen or increase the impacts of the Tax Legislation.

There is still uncertainty as to when or how credit rating agencies, capital markets, the FERC, or state public utility commissions will treat any additional impacts of the Tax Legislation. These impacts could subject us to credit rating downgrades. It is unclear whether additional opportunities may evolve for us to manage the adverse impacts of the Tax Legislation. In addition, certain financial metrics used by credit rating agencies, such as our funds from operations-to-debt percentage, could be negatively impacted by future rulings related to the Tax Legislation.

In addition, the FERC and state public utility commissions continue to engage with us to determine how certain tax savings will be returned to ratepayers. In December 2017, we deferred the estimated tax benefits for return to ratepayers through bill credits or reductions in regulatory assets. We have received written orders from the MPSC and the PSCW addressing the refunding of certain of these tax benefits to ratepayers in Michigan and Wisconsin, respectively. Despite receiving these written orders, the amount of tax benefits we must return to ratepayers could change if state commissions take additional action. Furthermore, if the amounts our regulators order us to return to ratepayers exceeds the actual amount of tax savings realized, or our regulators require the tax savings to be applied in a manner other than we had expected, it could have a material adverse effect on our financial condition, results of operations, and cash flow.

While our analysis and interpretation of the Tax Legislation is ongoing, based on our current evaluation, we do not expect the limitations on interest deductions to materially adversely affect our earnings. Any amendments to the Tax Legislation or interpretations, or implementing regulations by the Treasury Department and/or the IRS contrary to our interpretation of the Tax Legislation could limit our ability to deduct the interest on some of our outstanding debt.

There may be other material adverse effects resulting from the Tax Legislation that we have not yet identified. If we are unable to successfully take actions to manage any adverse impacts of the Tax Legislation, or if additional interpretations, regulations, amendments, or technical corrections exacerbate the adverse impacts of the Tax Legislation, the Tax Legislation could have an adverse effect on our financial condition, results of operations, cash flows, and on the value of investments in our debt securities, and could result in credit rating agencies placing our credit ratings on negative outlook or downgrading our credit ratings.

Failure to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act could have a material effect on our results of operations.

We are subject to reporting, disclosure control, and other obligations under Section 404 of the Sarbanes-Oxley Act (SOX). SOX contains provisions requiring our management to report on the effectiveness of our internal control over financial reporting. We have undertaken, or will undertake, a variety of initiatives to integrate, standardize, centralize, and streamline our operations with technology, including, but not limited to, an enterprise resource planning system and a customer information and billing system. There is a risk that we will not be able to conclude that our internal control over financial reporting is effective because of the discovery of material weaknesses, with either our current controls and processes or with the implementation of new controls and processes around these new technologies. Any failure to maintain effective internal controls could cause investors to lose confidence in the accuracy or completeness of our financial reports, restrict our access to the capital markets, or subject us to investigations by the SEC or other regulatory authorities.

We could be subject to higher costs and penalties as a result of mandatory reliability standards.

We are subject to mandatory reliability and critical infrastructure protection standards established by the North American Electric Reliability Corporation and enforced by the FERC. The critical infrastructure protection standards focus on controlling access to critical physical and cyber security assets. Compliance with the mandatory reliability standards could subject us to higher operating costs. If we were ever found to be in noncompliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties.

Risks Related to the Operation of Our Business

Our operations are subject to risks arising from the reliability of our electric generation, transmission, and distribution facilities, natural gas infrastructure facilities, and other facilities, as well as the reliability of third-party transmission providers.

Our financial performance depends on the successful operation of our electric generation and natural gas and electric distribution facilities. The operation of these facilities involves many risks, including operator error and the breakdown or failure of equipment or



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processes. Potential breakdown or failure may occur due to severe weather; catastrophic events (i.e., fires, earthquakes, explosions, tornadoes, floods, droughts, pandemic health events, etc.); significant changes in water levels in waterways; fuel supply or transportation disruptions; accidents; employee labor disputes; construction delays or cost overruns; shortages of or delays in obtaining equipment, material, and/or labor; performance below expected levels; operating limitations that may be imposed by environmental or other regulatory requirements; terrorist attacks; or cyber security intrusions. Any of these events could lead to substantial financial losses.

Because our electric generation facilities are interconnected with third-party transmission facilities, the operation of our facilities could also be adversely affected by events impacting their systems. Unplanned outages at our power plants may reduce our revenues, cause us to incur significant costs if we are required to operate our higher cost electric generators or purchase replacement power to satisfy our obligations, and could result in additional maintenance expenses.

Insurance, warranties, performance guarantees, or recovery through the regulatory process may not cover any or all of these lost revenues or increased expenses, which could adversely affect our results of operations and cash flows.

Our operations are subject to various conditions that can result in fluctuations in energy sales to customers, including customer growth and general economic conditions in our service areas, varying weather conditions, and energy conservation efforts.

Our results of operations and cash flows are affected by the demand for electricity and natural gas, which can vary greatly based upon:

•

Fluctuations in customer growth and general economic conditions in our service areas. Customer growth and energy use can be negatively impacted by population declines as well as economic factors in our service territories, including workforce reductions, stagnant wage growth, changing levels of support from state and local government for economic development, business closings, and reductions in the level of business investment. We are impacted by economic cycles and the competitiveness of the commercial and industrial customers we serve. Any economic downturn, disruption of financial markets, or reduced incentives by state government for economic development could adversely affect the financial condition of our customers and demand for their products or services. These risks could directly influence the demand for electricity and natural gas as well as the need for additional power generation and generating facilities. We could also be exposed to greater risks of accounts receivable write-offs if customers are unable to pay their bills.

•

Weather conditions . Demand for electricity is greater in the summer and winter months when cooling and heating is necessary. In addition, demand for natural gas peaks in the winter heating season. As a result, our overall results may fluctuate substantially on a seasonal basis. In addition, milder temperatures during the summer cooling season and during the winter heating season may result in lower revenues and net income.

•

Our customers' continued focus on energy conservation and ability to meet their own energy needs . Our customers' use of electricity and natural gas has decreased as a result of continued individual conservation efforts, including the use of more energy efficient technologies. Customers could also voluntarily reduce their consumption of energy in response to decreases in their disposable income and increases in energy prices. Conservation of energy can be influenced by certain federal and state programs that are intended to influence how consumers use energy. For example, several states, including Wisconsin and Michigan, have adopted energy efficiency targets to reduce energy consumption by certain dates.

As part of our planning process, we estimate the impacts of changes in customer growth and general economic conditions, weather, and customer energy conservation efforts, but risks still remain. Any of these matters, as well as any regulatory delay in adjusting rates as a result of reduced sales from effective conservation measures or the adoption of new technologies, could adversely impact our results of operations and financial condition.

We are actively involved with several significant capital projects, which are subject to a number of risks and uncertainties that could adversely affect project costs and completion of construction projects.

Our business requires substantial capital expenditures for investments in, among other things, capital improvements to our electric generating facilities, electric and natural gas distribution infrastructure, and other projects, including projects for environmental compliance. We also expect to invest in renewable energy generating facilities as part of WEC Energy Group's generation reshaping plan.

Achieving the intended benefits of any large construction project is subject to many uncertainties, some of which we will have limited or no control over, that could adversely affect project costs and completion time. These risks include, but are not limited to, the ability to adhere to established budgets and time frames; the availability of labor or materials at estimated costs; the ability of



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contractors to perform under their contracts; strikes; adverse weather conditions; potential legal challenges; changes in applicable laws or regulations; other governmental actions; continued public and policymaker support for such projects; and events in the global economy. In addition, certain of these projects require the approval of our regulators. If construction of commission-approved projects should materially and adversely deviate from the schedules, estimates, and projections on which the approval was based, our regulators may deem the additional capital costs as imprudent and disallow recovery of them through rates, and otherwise available production tax credits and investment tax credits for renewable energy projects could be lost.

To the extent that delays occur, costs become unrecoverable, tax credits are lost, or we (or third parties with whom we partner) otherwise become unable to effectively manage and complete our capital projects, our results of operations, cash flows, and financial condition may be adversely affected.

Advances in technology could make our electric generating facilities less competitive.

Advances in new technologies that produce power or reduce power consumption are ongoing and include renewable energy technologies, customer-oriented generation, energy storage devices, and energy efficiency technologies. We generate power at central station power plants to achieve economies of scale and produce power at a competitive cost. There are distributed generation technologies that produce power, including fuel cells, microturbines, wind turbines, and solar cells, which have become more cost competitive than they were in the past. It is possible that legislation or regulations could be adopted supporting the use of these technologies. There is also a risk that advances in technology will continue to reduce the costs of these alternative methods of producing power to a level that is competitive with that of central station power production. If these technologies become cost competitive and achieve economies of scale, our market share could be eroded, and the value of our generating facilities could be reduced. Advances in technology could also change the channels through which our electric customers purchase or use power, which could reduce our sales and revenues or increase our expenses.

Our operations are subject to risks beyond our control, including but not limited to, cyber security intrusions, terrorist attacks, acts of war, or unauthorized access to personally identifiable information.

We have been subject to attempted cyber attacks from time to time, but these attacks have not had a material impact on our system or business operations. Despite the implementation of security measures, all assets and systems are potentially vulnerable to disability, failures, or unauthorized access due to physical or cyber security intrusions caused by human error, vendor bugs, terrorist attacks, or other malicious acts. These threats against our generation facilities, electric and natural gas distribution infrastructure, our information and technology systems, and network infrastructure, including that of third parties on which we rely, could result in a full or partial disruption of our ability to generate, transmit, purchase, or distribute electricity or natural gas or cause environmental repercussions. If our assets or systems were to fail, be physically damaged, or be breached, and were not recovered in a timely manner, we may be unable to perform critical business functions, and data, including sensitive information, could be compromised.

We operate in an industry that requires the use of sophisticated information technology systems and network infrastructure, which control an interconnected system of generation, distribution, and transmission systems shared with third parties. A successful physical or cyber security intrusion may occur despite our security measures or those that we require our vendors to take, which include compliance with reliability standards and critical infrastructure protection standards. Successful cyber security intrusions, including those targeting the electronic control systems used at our generating facilities and electric and natural gas transmission and distribution systems, could disrupt our operations and result in loss of service to customers. These intrusions may cause unplanned outages at our power plants, which may reduce our revenues or cause us to incur significant costs if we are required to operate our higher cost electric generators or purchase replacement power to satisfy our obligations, and could result in additional maintenance expenses. The risk of such intrusions may also increase our capital and operating costs as a result of having to implement increased security measures for protection of our information technology and infrastructure.

Our continued efforts to integrate, consolidate, and streamline our operations have also resulted in increased reliance on current and recently completed projects for technology systems, including an enterprise resource planning system, a customer information and billing system, automated meter reading systems, and other similar technological tools and initiatives. We implement procedures to protect our systems, but we cannot guarantee that the procedures we have implemented to protect against unauthorized access to secured data and systems are adequate to safeguard against all security breaches. The failure of any of these or other similarly important technologies, or our inability to support, update, expand, and/or integrate these technologies with those of our affiliates could materially and adversely impact our operations, diminish customer confidence and our reputation, materially increase the costs we incur to protect against these risks, and subject us to possible financial liability or increased regulation or litigation.



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Our business requires the collection and retention of personally identifiable information of our customers, shareholders, and employees, who expect that we will adequately protect such information. Security breaches may expose us to a risk of loss or misuse of confidential and proprietary information. A significant theft, loss, or fraudulent use of personally identifiable information may lead to potentially large costs to notify and protect the impacted persons, and/or could cause us to become subject to significant litigation, costs, liability, fines, or penalties, any of which could materially and adversely impact our results of operations as well as our reputation with customers, shareholders, and regulators, among others. In addition, we may be required to incur significant costs associated with governmental actions in response to such intrusions or to strengthen our information and electronic control systems. We may also need to obtain additional insurance coverage related to the threat of such intrusions.

Any operational disruption or environmental repercussions caused by these on-going threats to our assets and technology systems could result in a significant decrease in our revenues or significant reconstruction or remediation costs, which could materially and adversely affect our results of operations, financial condition, and cash flows. The costs of repairing damage to our facilities, operational disruptions, protecting personally identifiable information, and notifying impacted persons, as well as related legal claims, may also not be recoverable in rates, may exceed the insurance limits on our insurance policies, or, in some cases, may not be covered by insurance.

Transporting and distributing natural gas involves numerous risks that may result in accidents and other operating risks and costs.

Inherent in natural gas distribution activities are a variety of hazards and operational risks, such as leaks, accidental explosions, and mechanical problems, which could materially and adversely affect our results of operations, financial condition, and cash flows. In addition, these risks could result in serious injury to employees and non-employees, loss of human life, significant damage to property, environmental pollution, impairment of operations, and substantial losses to us. The location of natural gas pipelines near populated areas, including residential areas, commercial business centers, and industrial sites, could increase the level of damages resulting from these risks. These activities may subject us to litigation and/or administrative proceedings from time to time, which could result in substantial monetary judgments, fines, or penalties against us, or be resolved on unfavorable terms.

We may fail to attract and retain an appropriately qualified workforce.

We operate in an industry that requires many of our employees to possess unique technical skill sets. Events such as an aging workforce without appropriate replacements, the mismatch of skill sets to future needs, or the unavailability of contract resources may lead to operating challenges or increased costs. These operating challenges include lack of resources, loss of knowledge, and a lengthy time period associated with skill development. In addition, current and prospective employees may determine that they do not wish to work for us. Failure to hire and obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be adversely affected.

Failure of our counterparties to meet their obligations, including obligations under power purchase, natural gas supply, and transportation agreements, could have an adverse impact on our results of operations.

We are exposed to the risk that counterparties to various arrangements who owe us money, electricity, natural gas, or other commodities or services will not be able to perform their obligations. Should the counterparties to these arrangements fail to perform, we may be required to replace the underlying commitment at current market prices or we may be unable to meet all of our customers' electric and natural gas requirements unless or until alternative supply arrangements are put in place. In such event, we may incur losses, and our results of operations, financial position, or liquidity could be adversely affected.

We have entered into several power purchase, natural gas supply, and transportation agreements with non-affiliated companies, and continue to look for additional opportunities to enter into these agreements. Revenues are dependent on the continued performance by the counterparties of their obligations under the power purchase, natural gas supply, and transportation agreements. Although we have a comprehensive credit evaluation process and contractual protections, it is possible that one or more counterparties could fail to perform their obligations under these agreements. If this were to occur, we generally would expect that any operating and other costs that were initially allocated to a defaulting customer's power purchase, natural gas supply, or transportation agreement would be reallocated among our retail customers. To the extent these costs are not allowed to be reallocated by our regulators or there is any regulatory delay in adjusting rates, a customer default under these agreements could have a negative impact on our results of operations and cash flows.



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Risks Related to Economic and Market Volatility

Our business is dependent on our ability to successfully access capital markets.

We rely on access to credit and capital markets to support our capital requirements, including expenditures for our utility infrastructure and to comply with future regulatory requirements, to the extent not satisfied by the cash flow generated by our operations. We have historically secured funds from a variety of sources, including the issuance of short-term and long-term debt securities. Successful implementation of our long-term business strategies, including capital investment, is dependent upon our ability to access the capital markets, including the banking and commercial paper markets, on competitive terms and rates. In addition, we rely on a committed bank credit agreement as back-up liquidity, which allows us to access the low cost commercial paper markets.

Our access to the credit and capital markets could be limited, or our cost of capital significantly increased, due to any of the following risks and uncertainties:


•	A rating downgrade;


•	An economic downturn or uncertainty;


•	Prevailing market conditions and rules;


•	Concerns over foreign economic conditions;


•	Changes in tax policy;


•	Changes in investment criteria of institutional investors;


•	War or the threat of war; and


•	The overall health and view of the utility and financial institution industries.

If any of these risks or uncertainties limit our access to the credit and capital markets or significantly increase our cost of capital, it could limit our ability to implement, or increase the costs of implementing, our business plan, which, in turn, could materially and adversely affect our results of operations, cash flows, and financial condition.

A downgrade in our credit ratings could negatively affect our ability to access capital at reasonable costs and/or require the posting of collateral.

There are a number of factors that impact our credit ratings, including, but not limited to, capital structure, regulatory environment, the ability to cover liquidity requirements, and other requirements for capital. We could experience a downgrade in our ratings if the rating agencies determine that the level of business or financial risk of us or the utility industry has deteriorated. Changes in rating methodologies by the rating agencies could also have a negative impact on credit ratings.

Any downgrade by the rating agencies could:


•	Increase borrowing costs under our existing credit facility;


•	Require the payment of higher interest rates in future financings and possibly reduce the pool of creditors;


•	Decrease funding sources by limiting our access to the commercial paper market;


•	Limit the availability of adequate credit support for our operations; and


•	Trigger collateral requirements in various contracts.

See the risk factor titled "Changes in federal income tax policy may adversely affect our financial condition, results of operations, and cash flows, as well as our credit ratings" above for information about how the Tax Legislation could impact our credit ratings.

Fluctuating commodity prices could negatively impact our electric and natural gas utility operations.

Our operating and liquidity requirements are impacted by changes in the forward and current market prices of natural gas, coal, electricity, renewable energy credits, and ancillary services.

We burn natural gas in several of our electric generation plants, and as a supplemental fuel at several coal-fired plants. In many instances the cost of purchased power is tied to the cost of natural gas. The cost of natural gas may increase because of disruptions in the supply of natural gas due to a curtailment in production or distribution, international market conditions, the demand for natural gas, and the availability of shale gas and potential regulations affecting its accessibility.



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For Wisconsin retail electric customers, we bear the risk for the recovery of fuel and purchased power costs within a symmetrical 2% fuel tolerance band compared to the forecast of fuel and purchased power costs established in our rate structure. Prudently incurred fuel and purchased power costs are recovered dollar-for-dollar from our Michigan retail electric customer and our wholesale electric customers. We receive dollar-for-dollar recovery of prudently incurred natural gas costs from our natural gas customers.

Changes in commodity prices could result in:


•	Higher working capital requirements, particularly related to natural gas inventory, accounts receivable, and cash collateral postings;


•	Reduced profitability to the extent that lower revenues, increased bad debt, and interest expense are not recovered through rates;


•	Higher rates charged to our customers, which could impact our competitive position;


•	Reduced demand for energy, which could impact revenues and operating expenses; and


•	Shutting down of generation facilities if the cost of generation exceeds the market price for electricity.

We may not be able to obtain an adequate supply of coal, which could limit our ability to operate our coal-fired facilities.

We own and operate several coal-fired electric generating units. Although we generally carry sufficient coal inventory at our generating facilities to protect against an interruption or decline in supply, there can be no assurance that the inventory levels will be adequate. While we have coal supply and transportation contracts in place, we cannot assure that the counterparties to these agreements will be able to fulfill their obligations to supply coal to us or that we will be able to take delivery of all the coal volume contracted for. If we are unable to obtain our coal requirements under our coal supply and transportation contracts, we may be required to purchase coal at higher prices or we may be forced to reduce generation at our coal-fired units, which could lead to increased fuel costs. The increase in fuel costs could result in either reduced margins on net sales into the MISO Energy Markets, a reduction in the volume of net sales into the MISO Energy Markets, and/or an increase in net power purchases in the MISO Energy Markets. There is no guarantee that we would be able to fully recover any increased costs in rates or that recovery would not otherwise be delayed, either of which could adversely affect our cash flows.

The use of derivative contracts could result in financial losses.

We use derivative instruments such as swaps, options, futures, and forwards to manage commodity price exposure. We could recognize financial losses as a result of volatility in the market value of these contracts or if a counterparty fails to perform. These risks are managed through risk management policies, which might not work as planned and cannot entirely eliminate the risks associated with these activities. In addition, although our hedging programs must be approved by the PSCW, derivative contracts entered into for hedging purposes might not offset the underlying exposure being hedged as expected, resulting in financial losses. In the absence of actively quoted market prices and pricing information from external sources, the value of these financial instruments can involve management's judgment or use of estimates. Changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

Restructuring in the regulated energy industry and competition in the retail and wholesale markets could have a negative impact on our business and revenues.

The regulated energy industry continues to experience significant structural changes. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant adverse financial impact on us.

The FERC continues to support the existing RTOs that affect the structure of the wholesale market within these RTOs. In connection with its status as a FERC approved RTO, MISO implemented bid-based energy markets that are part of the MISO Energy Markets. All market participants, including us, must submit day-ahead and/or real-time bids and offers for energy at locations across the MISO region. MISO then calculates the most efficient solution for all of the bids and offers made into the market that day and establishes an LMP that reflects the market price for energy. We are required to follow MISO's instructions when dispatching generating units to support MISO's responsibility for maintaining the stability of the transmission system. MISO also implemented an ancillary services market for operating reserves that schedules energy and ancillary services at the same time as part of the energy market, allowing for more efficient use of generation assets in the MISO Energy Markets. These market designs continue to have the potential to increase the costs of transmission, the costs associated with inefficient generation dispatching, the costs of participation in the MISO Energy Markets, and the costs associated with estimated payment settlements.



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The FERC rules related to transmission are designed to facilitate competition in the wholesale electricity markets among regulated utilities, non-utility generators, wholesale power marketers, and brokers by providing greater flexibility and more choices to wholesale customers, including initiatives designed to encourage the integration of renewable sources of supply. In addition, along with transactions contemplating physical delivery of energy, financial laws and regulations impact hedging and trading based on futures contracts and derivatives that are traded on various commodities exchanges, as well as over-the-counter. Technology changes in the power and fuel industries also have significant impacts on wholesale transactions and related costs. We currently cannot predict the impact of these and other developments or the effect of changes in levels of wholesale supply and demand, which are driven by factors beyond our control.

We may experience poor investment performance of benefit plan holdings due to changes in assumptions and market conditions.

We have significant obligations related to pension and OPEB plans. If WEC Energy Group is unable to successfully manage our benefit plan assets and medical costs, our cash flows, financial condition, or results of operations could be adversely impacted. Our cost of providing these plans is dependent upon a number of factors, including actual plan experience, changes made to the plans, and assumptions concerning the future. Types of assumptions include earnings on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation, estimated withdrawals by retirees, and our required or voluntary contributions to the plans. Plan assets are subject to market fluctuations and may yield returns that fall below projected return rates. In addition, medical costs for both active and retired employees may increase at a rate that is significantly higher than we currently anticipate. Our funding requirements could be impacted by a decline in the market value of plan assets, changes in interest rates, changes in demographics (including the number of retirements) or changes in life expectancy assumptions.

We may be unable to obtain insurance on acceptable terms or at all, and the insurance coverage we do obtain may not provide protection against all significant losses.

Our ability to obtain insurance, as well as the cost and coverage of such insurance, could be affected by developments affecting our business; international, national, state, or local events; and the financial condition of insurers and our contractors that are required to acquire and maintain insurance for our benefit. Insurance coverage may not continue to be available at all or at rates or terms similar to those presently available to us. In addition, our insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. Any losses for which we are not fully insured or that are not covered by insurance at all could materially adversely affect our results of operations, cash flows, and financial position.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.



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ITEM 2. PROPERTIES

We own our principal properties outright, except that the major portion of our electric utility distribution lines, steam utility distribution mains and natural gas utility distribution mains and services are located, for the most part, on or under streets and highways and on land owned by others and are generally subject to granted easements, consents, or permits. In addition, we lease the ERGS and PWGS generating units from We Power.

Electric Facilities

As of December 31, 2018 , we owned, or leased from We Power, the following generating assets:



Name	Location	Fuel	Number of Generating Units	Rated Capacity In MW ⁽¹⁾
Coal-fired plants
ERGS	Oak Creek, WI	Coal	2	1,057	⁽²⁾
PIPP	Marquette, MI	Coal	5	353	⁽³⁾
OCPP	Oak Creek, WI	Coal	4	1,079
Total coal-fired plants			11	2,489
Natural gas-fired plants
Concord Combustion Turbines	Watertown, WI	Natural Gas/Oil	4	359
Germantown Combustion Turbines	Germantown, WI	Natural Gas/Oil	5	270
Paris Combustion Turbines	Union Grove, WI	Natural Gas/Oil	4	360
PWGS	Port Washington, WI	Natural Gas	2	1,232
VAPP	Milwaukee, WI	Natural Gas	2	269
Total natural gas-fired plants			17	2,490
Renewables
Hydro Plants (13 in number)	WI and MI	Hydro	30	53
Rothschild Biomass Plant	Rothschild, WI	Biomass	1	46
Blue Sky Green Field	Fond du Lac, WI	Wind	88	17
Byron Wind Turbines	Fond du Lac, WI	Wind	2	—
Glacier Hills	Cambria, WI	Wind	90	26
Montfort Wind Energy Center	Montfort, WI	Wind	20	3
Total renewables			231	145
Total system			259	5,124


⁽¹⁾	Values are primarily based on the net dependable capacity ratings for summer 2019 using historical generation. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand.


⁽²⁾	This facility is jointly owned by We Power and two other unaffiliated entities. The capacity indicated for the facility is equal to We Power's portion of total plant capacity based on its 83.34% ownership.


⁽³⁾	We are required to retire the PIPP units during the second quarter of 2019 . See Note 6, Property, Plant, and Equipment, for more information on the plant retirement.

As of December 31, 2018 , we operated approximately 19,800 miles of overhead distribution lines and 25,000 miles of underground distribution cable, as well as 312 electric distribution substations and approximately 290,300 line transformers.

Natural Gas Facilities

As of December 31, 2018 , our natural gas distribution system included approximately 11,400 miles of distribution mains connected at 25 gate stations to the pipeline transmission systems of ANR Pipeline Company, Great Lakes Transmission Company, Guardian Pipeline L.L.C., Natural Gas Pipeline Company of America, and Northern Natural Pipeline Company and approximately 414,000 natural gas lateral services. We have a liquefied natural gas storage plant that converts and stores, in liquefied form, natural gas received during periods of low consumption. The liquefied natural gas storage plant has a send-out capability of 70,000 Dth per day. Our natural gas distribution system consists almost entirely of plastic and coated steel pipe.



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We also own office buildings, natural gas regulating and metering stations, and major service centers, including garage and warehouse facilities, in certain communities we serve. Where distribution lines and services and natural gas distribution mains and services occupy private property, we have in some, but not all instances, obtained consents, permits or easements for these installations from the apparent owners or those in possession of those properties, generally without an examination of ownership records or title.

Steam Facilities

As of December 31, 2018 , the steam system supplied by the VAPP consisted of approximately 40 miles of both high pressure and low pressure steam piping, approximately four miles of walkable tunnels and other pressure regulating equipment.

ITEM 3. LEGAL PROCEEDINGS

The following should be read in conjunction with Note 19, Commitments and Contingencies , and Note 21, Regulatory Environment , in this report for additional information on material legal proceedings and matters related to us.

In addition to those legal proceedings discussed in Note 19, Commitments and Contingencies , Note 21, 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 4. MINE SAFETY DISCLOSURES

Not Applicable.



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EXECUTIVE OFFICERS OF THE REGISTRANT

The names, ages, and positions of our executive officers at December 31, 2018 are listed below along with their business experience during the past five years. All officers are appointed until they resign, die, or are removed pursuant to our Bylaws. There are no family relationships among these officers, nor is there any agreement or understanding between any officer and any other person pursuant to which the officer was selected.

Gale E. Klappa. ⁽¹⁾ Age 68.


•	WEC Energy Group — Chairman of the Board and Chief Executive Officer since October 2017, and from May 2004 to May 2016. Non-Executive Chairman of the Board from May 2016 to October 2017. Director since December 2003. President from April 2003 to August 2013.


•	WE — Chairman of the Board since January 2018, and from May 2004 to May 2016. Chief Executive Officer since January 2018, and from August 2003 to May 2016. Director since January 2018, and from December 2003 to May 2016. President from August 2003 to June 2015.

J. Kevin Fletcher. ⁽²⁾ Age 60.


•	WEC Energy Group — President since October 2018.


•	WE — President from May 2016 to November 2018. Director since June 2015. Executive Vice President - Customer Service and Operations from June 2015 to April 2016. Senior Vice President - Customer Operations from October 2011 to June 2015.

Robert M. Garvin. Age 52.


•	WEC Energy Group — Executive Vice President - External Affairs since June 2015. Senior Vice President - External Affairs from April 2011 to June 2015.


•	WE — Executive Vice President - External Affairs since June 2015. Senior Vice President - External Affairs from April 2011 to June 2015.

William J. Guc. Age 49.


•	WEC Energy Group — Controller since October 2015. Vice President since June 2015.


•	WE — Vice President and Controller since October 2015.


•	Integrys Energy Group — Vice President and Treasurer from December 2010 to June 2015.

Margaret C. Kelsey. Age 54 .


•	WEC Energy Group — Executive Vice President, Corporate Secretary and General Counsel since January 2018. Executive Vice President from September 2017 to January 2018.


•	WE — Executive Vice President, Corporate Secretary and General Counsel since January 2018. Director since January 2018.


•	Modine Manufacturing Company - General Counsel, Corporate Secretary, and Vice President - Legal from April 2008 to August 2017. Vice President - Corporate Communications from April 2014 to August 2017.

Scott J. Lauber. ⁽³⁾ Age 53.


•	WEC Energy Group — Executive Vice President, Chief Financial Officer and Treasurer since October 2018. Executive Vice President and Chief Financial Officer from April 2016 to October 2018. Vice President and Treasurer from February 2013 to March 2016.


•	WE — Executive Vice President, Chief Financial Officer and Treasurer since October 2018. Director since April 2016. Executive Vice President and Chief Financial Officer from April 2016 to October 2018. Vice President and Treasurer from February 2013 to March 2016.

Tom Metcalfe. Age 51.


•	WE — President since November 2018. Director since January 2018. Executive Vice President - Generation from April 2016 to November 2018. Senior Vice President - Power Generation from January 2014 to March 2016.

Certain executive officers also hold officer and/or director positions at our other significant subsidiaries.


⁽¹⁾	Effective February 1, 2019, Mr. Klappa was appointed Executive Chairman of WEC Energy Group. Also, effective February 1, 2019, Mr. Fletcher succeeded Mr. Klappa as Chairman and Chief Executive Officer of WE. Mr Klappa remains a Director of WE.


⁽²⁾	Effective February 1, 2019, Mr. Fletcher was appointed President and Chief Executive Officer and a Director of WEC Energy Group. Also effective February 1, 2019, Mr. Fletcher was appointed Chairman and Chief Executive Officer of WE.


⁽³⁾	Effective February 1, 2019, Mr. Lauber was named Senior Executive Vice President, Chief Financial Officer and Treasurer of WEC Energy Group.



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PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

There is no established public trading market for our common stock, as WEC Energy Group owns all of our outstanding common stock. See Note 8, Common Equity, for more information .

ITEM 6. SELECTED FINANCIAL DATA

WISCONSIN ELECTRIC POWER COMPANY

COMPARATIVE FINANCIAL DATA AND OTHER STATISTICS



As of or for Year Ended December 31
(in millions)	2018		2017 *		2016		2015		2014
Operating revenues	$	3,625.0	$	3,711.7	$	3,792.8	$	3,854.1	$	4,059.4
Net income attributed to common shareholder	358.3		335.6		364.3		375.7		376.7
Total assets	13,538.3		13,121.6		13,371.5		13,139.6		12,597.2
Long-term debt and capital lease obligations (excluding current portion)	5,266.8		5,236.1		5,417.6		5,351.3		4,875.2


*	Reflects the impact of the transfer of our investment in ATC to another subsidiary of WEC Energy Group and the transfer of net assets to UMERC in 2017. See Note 3, Related Parties and Note 16, Investment in American Transmission Company , for more information on these transactions.



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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CORPORATE DEVELOPMENTS

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 17, Segment Information , for more information on our reportable business segments.

Effective January 1, 2017, our customers (other than Tilden) and electric distribution assets located in the Upper Peninsula of Michigan were transferred to UMERC, a new stand-alone utility owned by WEC Energy Group. See Note 3, Related Parties , and Note 21, Regulatory Environment , for more information.

Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 16, Investment in American Transmission Company, for more information . In March 2017, we sold the remaining real estate holdings of Bostco, and, in October 2018, Bostco was dissolved. See Note 2, Dispositions , for more information.

Corporate Strategy

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

Reshaping Our Generation Fleet

WEC Energy Group has developed and is executing a plan to reshape its generation portfolio. This plan will balance reliability and customer cost with environmental stewardship. Taken as a whole, this plan should reduce costs to customers, preserve fuel diversity, and lower carbon emissions. Generation reshaping includes retiring older fossil fuel generation units, building state-of-the-art natural gas generation, and investing in cost-effective zero-carbon generation with a goal of reducing 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 a total of approximately 1,800 MW of coal-fired generation by 2020 across its electric utilities, and add additional natural gas-fired generating units and renewable generation, including utility-scale solar projects. As part of this effort, we retired our 1,190 MW Pleasant Prairie power plant 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 6, Property, Plant, and Equipment , for information related to the Pleasant Prairie power plant retirement and the planned retirement of the 350 MW Presque Isle power plant as part of WEC Energy Group's plan.

In December 2018, we received approval from the PSCW for two renewable energy pilot programs. The Solar Now pilot is expected to add 35 MW of solar to our portfolio, allowing commercial and industrial customers to site solar arrays on their property. The second program, the Dedicated Renewable Energy Resource pilot, would allow large commercial and industrial customers to access renewable resources that we would operate, adding up to 150 MW of renewables to our portfolio, and allowing these larger customers to meet their sustainability and renewable energy goals. As the cost of renewable energy generation installations continues to decline, these pilots have become cost effective opportunities for us and our customers to participate in renewable energy.

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 Midwest for the eighth year in a row.



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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.

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 3, Related Parties , for information on WEC Energy Group's acquisition of Bluewater. See Note 2, Dispositions , for information on the sale of the MCPP steam generation and distribution assets and 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. Our 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.



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RESULTS OF OPERATIONS

Consolidated Earnings

The following table compares our consolidated results:



	Year Ended December 31
(in millions)	2018			2017		2016
Operating revenues	$	3,625.0		$	3,711.7	$	3,792.8
Cost of sales	1,262.1			1,286.4		1,292.1
Other operation and maintenance	1,502.4			1,352.0		1,425.5
Depreciation and amortization	348.1			331.6		325.4
Property and revenue taxes	109.9			109.6		115.6
Operating income	402.5			632.1		634.2
Equity in earnings of transmission affiliate	—			—		55.5
Other income, net	20.2			13.2		4.4
Interest expense	120.1			117.3		117.6
Income before income taxes	302.6			528.0		576.5
Income tax (benefit) expense	(56.9		)	191.2		211.0
Preferred stock dividend requirements	1.2			1.2		1.2
Net income attributed to common shareholder	$	358.3		$	335.6	$	364.3

The table below shows the year-over-year income statement impacts 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 below, the changes related to these items had no impact on net income attributed to common shareholder. See Note 12, Income Taxes , and Note 21, Regulatory Environment , for more information.



(in millions)	2018 Compared with 2017 B (W)			Change Related to Flow Through of Tax Repairs			Change Related to Tax Legislation			Remaining Change B (W)
Operating revenues	$	(86.7	)	$	(88.1	)	$	(25.6	)	$	27.0
Cost of sales	24.3			—			—			24.3
Other operation and maintenance	(150.4		)	(77.8		)	(67.7		)	(4.9		)
Depreciation and amortization	(16.5		)	—			—			(16.5		)
Property and revenue taxes	(0.3		)	—			—			(0.3		)
Operating income	(229.6		)	(165.9		)	(93.3		)	29.6
Other income, net	7.0			—			—			7.0
Interest expense	(2.8		)	—			—			(2.8		)
Income before income taxes	(225.4		)	(165.9		)	(93.3		)	33.8
Income tax (benefit) expense	248.1			165.9			93.3			(11.1		)
Preferred stock dividend requirements	—			—			—			—
Net income attributed to common shareholder	$	22.7		$	—		$	—		$	22.7

See below for additional information on the year-over year changes in our 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 useful basis for evaluating utility operations 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,



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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 years ended December 31, 2018 , 2017 , and 2016 was $402.5 million , $632.1 million , and $634.2 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.

Utility Segment Contribution to Operating Income

Effective January 1, 2017, we transferred our electric customers (other than Tilden) located in the Upper Peninsula of Michigan to UMERC. See Note 3, Related Parties, for more information .



	Year Ended December 31
(in millions)	2018		2017		2016
Electric revenues	$	3,218.8	$	3,336.2	$	3,440.6
Fuel and purchased power	1,010.1		1,064.3		1,091.8
Total electric margins	2,208.7		2,271.9		2,348.8

Natural gas revenues	406.2		375.5		352.2
Cost of natural gas sold	252.0		222.1		200.3
Total natural gas margins	154.2		153.4		151.9

Total electric and natural gas margins	2,362.9		2,425.3		2,500.7

Other operation and maintenance	1,502.4		1,352.0		1,425.5
Depreciation and amortization	348.1		331.6		325.4
Property and revenue taxes	109.9		109.6		115.6
Operating income	$	402.5	$	632.1	$	634.2

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



	Year Ended December 31
(in millions)	2018		2017		2016
Operation and maintenance not included in line items below	$	442.7	$	481.8	$	495.5
We Power ⁽¹⁾	506.9		513.0		513.2
Transmission ⁽²⁾	265.1		251.9		273.8
Transmission expense related to the flow through of tax repairs ⁽³⁾	77.8		—		—
Transmission expense related to Tax Legislation ⁽⁴⁾	67.7		—		—
Regulatory amortizations and other pass through expenses ⁽⁵⁾	98.1		96.7		96.6
Earnings sharing mechanism ⁽⁶⁾	37.2		0.1		21.1
Other	6.9		8.5		25.3
Total other operation and maintenance	$	1,502.4	$	1,352.0	$	1,425.5

⁽¹⁾

Represents costs associated with the We Power generation units, including operating and maintenance costs, as well as the lease payments that are billed from We Power to us and then recovered in our rates. During 2018 , 2017 , and 2016 , $485.3 million , $535.1 million, and $528.4 million, respectively, of both lease and operating and maintenance costs were billed to 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 differences between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During 2018 , 2017 , and 2016 , $286.3 million , $303.8 million, and $335.3 million, respectively, of costs were billed to us by transmission providers.



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⁽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 21, 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 21, 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 21, Regulatory Environment, for more information about our earnings sharing mechanism.

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



	Year Ended December 31
	MWh (in thousands)
Electric Sales Volumes	2018	2017	2016
Customer class
Residential	8,025.1	7,648.5	8,136.6
Small commercial and industrial	8,920.6	8,768.4	9,061.1
Large commercial and industrial	8,457.9	8,340.3	9,217.6
Other	138.7	144.9	143.4
Total retail	25,542.3	24,902.1	26,558.7
Wholesale	1,688.5	1,600.2	1,134.2
Resale	4,931.9	8,144.5	8,282.1
Total sales in MWh	32,162.7	34,646.8	35,975.0



	Year Ended December 31
	Therms (in millions)
Natural Gas Sales Volumes	2018	2017	2016
Customer class
Residential	383.2	344.3	341.7
Commercial and industrial	217.9	193.4	186.3
Total retail	601.1	537.7	528.0
Transport	339.2	314.2	323.8
Total sales in therms	940.3	851.9	851.8



	Year Ended December 31
	Degree Days
Weather *	2018	2017	2016
Heating (6,515 normal)	6,685	5,908	6,068
Cooling (731 normal)	929	772	991


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

2018 Compared with 2017

Electric Utility Margins

Electric utility margins decreased $63.2 million during 2018, compared with 2017. The significant factors impacting the lower electric utility margins were:


•	An $88.1 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 21, Regulatory Environment , for more information.



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•	A $15.9 million decrease in wholesale margins driven by reduced capacity rates due in part to the Tax Legislation.

•

A $13.4 million year-over-year negative impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, our electric utility margins are impacted by under- or over-collections of certain fuel and purchased power costs that are less than a 2% price variance from the costs included in rates, and the remaining variance that exceeds the 2% variance is deferred.


•	A $10.2 million decrease in margins related to savings from the Tax Legislation that we are required to return to customers through bill credits or reductions in other regulatory assets. See Note 12, Income Taxes , and Note 21, Regulatory Environment , for more information.

These decreases in electric utility margins were partially offset by:

•

A $44.6 million increase related to higher retail sales volumes during 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, 2018 was 13.2% colder than 2017. As measured by cooling degree days, 2018 was 20.3% warmer than 2017.

•

A $25.9 million increase related to SSR payments we refunded to MISO in 2017 as directed by a FERC order received in October 2017. The FERC order reduced the costs eligible for reimbursement to us for the operation and maintenance of our PIPP units under an SSR agreement we have with MISO. A portion of these payments was returned to us through the MISO allocation process and reduced transmission expense in 2017 as discussed below.

Natural Gas Utility Margins

Natural gas utility margins increased $0.8 million during 2018, compared with 2017. The most significant factor impacting the higher natural gas utility margins was a $10.6 million increase related to higher sales volumes, primarily driven by colder winter weather, customer growth, and higher use per retail customer due in part to a stronger economy. This increase in natural gas utility margins was partially offset by $9.9 million of savings from the Tax Legislation that we are required to return to customers through bill credits. See Note 12, Income Taxes , and Note 21, Regulatory Environment , for more information.

Operating Income

Operating income at the utility segment decreased $229.6 million during 2018, compared with 2017. This decrease was driven by $167.2 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes) and the $62.4 million net decrease in margins discussed above.

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


•	A $77.8 million increase in transmission expense related to the flow through of tax repairs, as discussed in the other operation and maintenance table above.


•	A $67.7 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.


•	A $37.1 million increase in expense related to our earnings sharing mechanism. See Note 21, Regulatory Environment , for more information.


•	A $16.5 million increase in depreciation and amortization, driven by an increase in capital expenditures as we continue to execute on our capital plan.


•	A $13.2 million increase in transmission expense in 2018, driven by lower expense in 2017 related to a FERC order received in October 2017 to reduce SSR costs related to PIPP. A portion of the payments we initially refunded to MISO were returned to us, as discussed under electric utility margins.



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These increases in operating expenses were partially offset by a $56.4 million decrease in expenses across all of our plants, in part due 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 on or before May 31, 2019. This resulted in lower maintenance and labor costs during 2018. See Note 6, Property, Plant, and Equipment, for more information on the plant retirements.

2017 Compared with 2016

Electric Utility Margins

Electric utility margins decreased $76.9 million during 2017, compared with 2016. The significant factors impacting the lower electric utility margins were:

•

A $74.1 million decrease related to lower sales volumes during 2017, primarily driven by unfavorable weather, lower overall retail use per customer, and the transfer of customers and their related sales to UMERC. Cooler summer and warmer winter weather in 2017, and an additional day of sales during 2016 due to leap year, contributed to the decrease. As measured by cooling degree days, 2017 was 22.1% cooler than 2016. As measured by heating degree days, 2017 was 2.6% warmer than 2016.

•

A $25.9 million decrease related to SSR payments we refunded to MISO as directed by a FERC order received in October 2017. The FERC order reduced the costs eligible for reimbursement to us for the operation and maintenance of our PIPP units under an SSR agreement we have with MISO. A portion of these payments was returned to us through the MISO allocation process and reduced transmission expense as discussed below. See Note 21, Regulatory Environment , for more information.


•	A $3.5 million decrease in steam margins driven by the sale of the MCPP in April 2016. See Note 2, Dispositions, for more information .

These decreases in electric utility margins were partially offset by $36.5 million of lower capacity payments to a counterparty during 2017, related to improved contract terms.

Natural Gas Utility Margins

Natural gas utility margins increased $1.5 million during 2017, compared with 2016. The most significant factor impacting the higher natural gas utility margins was higher retail sales volumes, primarily driven by higher overall retail use per customer and customer growth. The higher retail sales volumes in 2017 were partially offset by an additional day of sales during 2016 due to leap year.

Operating Income

Operating income at the utility segment decreased $2.1 million during 2017, compared with 2016. This decrease was driven by the $75.4 million net decrease in margins discussed above, partially offset by $73.3 million of lower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes).

We experienced lower overall operating expenses related to synergy savings resulting from WEC Energy Group's acquisition of Integrys. The significant factors impacting the decrease in operating expenses during 2017, compared with 2016, which were due in part to synergy savings, were:


•	A $21.9 million decrease in transmission expenses, driven by a FERC order received in October 2017 to reduce SSR costs related to PIPP. A portion of the payments we initially refunded to MISO were returned to us, as discussed under electric utility margins.


•	A $21.0 million decrease in expenses related to our earnings sharing mechanism. See Note 21, Regulatory Environment , for more information.


•	A $19.1 million decrease in electric and natural gas distribution expenses, primarily related to the transfer of electric customers and their related sales to UMERC, lower metering costs, and other cost savings.


•	A $16.8 million decrease in expenses related to charitable projects supporting our customers and the communities within our service territories.



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These decreases in operating expenses were partially offset by a $10.9 million gain recorded in April 2016 related to the sale of the MCPP. See Note 2, Dispositions, for more information .

Equity in Earnings of Transmission Affiliate



	Year Ended December 31
(in millions)	2018		2017		2016
Equity in earnings of transmission affiliate	$	—	$	—	$	55.5

2017 Compared with 2016

At December 31, 2016, we owned approximately 23% of ATC. Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 16, Investment in American Transmission Company, for more information .

Consolidated Other Income, Net



	Year Ended December 31
(in millions)	2018		2017			2016
AFUDC – Equity	$	3.9	$	3.1		$	4.2
Non-service credit (cost) components of net periodic benefit costs	5.7		(6.5		)	(4.7		)
Interest income	2.2		2.3			2.2
Other, net	8.4		14.3			2.7
Other income, net	$	20.2	$	13.2		$	4.4

2018 Compared with 2017

Other income, net increased $7.0 million during 2018 , compared with 2017 , driven by the year-over-year increase in income from the non-service components of our net periodic pension and OPEB costs. See Note 15, Employee Benefits, for more information on our benefit costs.

2017 Compared with 2016

Other income, net increased $8.8 million during 2017 , compared with 2016 . The increase was driven by higher gains on property sales during 2017, compared to 2016, and the expenses we incurred in 2016 related to the disposition of certain non-utility real estate assets. These increases were partially offset by lower AFUDC during 2017 and higher costs from the non-service components of our net periodic pension and OPEB costs.

Consolidated Interest Expense



	Year Ended December 31
(in millions)	2018		2017		2016
Interest expense	$	120.1	$	117.3	$	117.6

Consolidated Income Tax Expense



	Year Ended December 31
	2018		2017		2016
Effective tax rate	(18.8	)%	36.2	%	36.6	%

2018 Compared with 2017

Our effective tax rate was (18.8)% in 2018 compared to 36.2% in 2017. This decrease was primarily due to a 39.9% effective tax rate benefit from the flow through of tax repairs in connection with the Wisconsin rate settlement. Also contributing to the decrease in the effective tax rate was the impact of the Tax Legislation. See Note 12, Income Taxes , and Note 21, Regulatory Environment for more information.



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We expect our 2019 annual effective tax rate to be between (17)% and (16)%, which includes an estimated 38.5% effective tax rate benefit due to the flow through of tax repairs in connection with the Wisconsin rate settlement. Excluding the impact of the tax repairs, the expected 2019 range would be between 21.5% and 22.5%.

2017 Compared with 2016

Our effective tax rate was 36.2% in 2017 compared to 36.6% in 2016. This decrease in our effective tax rate was primarily due to increased renewable energy credits related to wind projects and favorable compensation expense.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

The following table summarizes our cash flows during the years ended December 31:



(in millions)	2018			2017			2016			Change in 2018 Over 2017			Change in 2017 Over 2016
Cash provided by (used in):
Operating activities	$	962.2		$	698.0		$	848.4		$	264.2		$	(150.4	)
Investing activities	(640.4		)	(568.2		)	(436.8		)	(72.2		)	(131.4		)
Financing activities	(313.9		)	(132.9		)	(423.3		)	(181.0		)	290.4

Operating Activities

2018 Compared with 2017

Net cash provided by operating activities increased $264.2 million during 2018 , compared with 2017 , driven by:


•	A $99.2 million increase in cash related to higher overall collections from customers, primarily due to favorable weather during 2018 , compared with 2017 .

•

An $85.0 million increase in cash from lower payments for operating and maintenance expenses. During 2018 , our payments were lower for accounts payable to related parties as well as for plant maintenance and labor costs, due in part to the retirement in 2018 of the Pleasant Prairie power plant and winding down of operations at the PIPP in anticipation of a 2019 retirement. See Note 6, Property, Plant, and Equipment, for more information about the retirement of our plants. In addition, our lease payments to We Power decreased as a result of the Tax legislation, and our payments for transmission costs decreased in 2018.


•	A $54.0 million net increase in cash related to a decrease in cash paid for income taxes during 2018 , compared with 2017 . This increase in cash was primarily the result of the utilization of certain tax benefit carryforwards.


•	A $28.9 million increase in cash due to realized gains from the settlement of our natural gas and petroleum products contracts, combined with lower cash collateral requirements related to open natural gas contracts in 2018, compared with 2017. See Note 14, Derivative Instruments, for more information .

2017 Compared with 2016

Net cash provided by operating activities decreased $150.4 million during 2017 , compared with 2016 , driven by:


•	A $171.9 million net decrease in cash related to $71.7 million of cash paid for income taxes during 2017 , compared with $100.2 million of cash received during 2016 . This decrease in cash was primarily due to the extension of bonus depreciation in December 2015, which resulted in the receipt of an income tax refund during 2016.


•	A $149.8 million decrease in cash related to lower overall collections from customers during 2017 , compared with 2016 . Collections from customers decreased primarily because of unfavorable weather and the loss of sales from the transfer of customers to UMERC in 2017.



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•	Cash distributions provided by ATC of $38.4 million during 2016 . Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 16, Investment in American Transmission Company, for more information .

These decreases in net cash provided by operating activities were partially offset by:


•	A $115.7 million increase in cash from lower payments for transfers of certain benefit-related liabilities to WBS during 2017, compared with 2016.


•	A $56.9 million increase in cash from lower payments for operating and maintenance expenses. During 2017 , our payments related to transmission, electric and natural gas distribution, and charitable projects decreased.


•	A $32.5 million net increase in cash resulting from lower payments for fuel and purchased power due to the transfer of electric customers to UMERC effective January 1, 2017. This increase in cash was partially offset by higher payments for natural gas, primarily due to higher commodity prices. The average per-unit cost of natural gas sold increased 8.9% during 2017 , compared with 2016 .

Investing Activities

2018 Compared with 2017

Net cash used in investing activities increased $72.2 million during 2018 , compared with 2017 , driven by:


•	Net payments of $51.0 million to affiliates during 2018 , related to transfers of an enterprise resource planning system, other software, and equipment. There were no similar transfers in 2017 .


•	A $21.2 million decrease in the proceeds received from the sale of assets during 2018 , compared with 2017 . See Note 2, Dispositions, for more information .


•	A $7.1 million increase in cash paid for capital expenditures during 2018 , compared with 2017 , which is discussed in more detail below.

2017 Compared with 2016

Net cash used in investing activities increased $131.4 million during 2017 , compared with 2016 , driven by:


•	A $126.6 million increase in cash paid for capital expenditures during 2017 , compared with 2016 , which is discussed in more detail below.


•	Cash of $13.1 million received during 2016 related to transfers of certain software to WBS. There were no similar transfers in 2017 .


•	An $8.8 million decrease in the proceeds received from the sale of assets during 2017 , compared with 2016 . See Note 2, Dispositions, for more information .

These increases in net cash used in investing activities were partially offset by $16.1 million of capital contributions paid to ATC during 2016. Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group.

Capital Expenditures

Capital expenditures for the years ended December 31 were as follows:



(in millions)	2018		2017		2016		Change in 2018 Over 2017		Change in 2017 Over 2016
Capital expenditures	$	603.2	$	596.1	$	469.5	$	7.1	$	126.6



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2018 Compared with 2017

The increase in cash paid for capital expenditures during 2018 , compared with 2017 , 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 – Capital Expenditures and Significant Capital Projects below for more information.

2017 Compared with 2016

The increase in cash paid for capital expenditures during 2017, compared with 2016, was driven by upgrades to our electric and natural gas distribution systems, including main replacement projects and an advanced metering infrastructure program, as well as various projects at the OCPP.

Financing Activities

2018 Compared with 2017

Net cash used in financing activities increased $181.0 million during 2018 , compared with 2017 , driven by:


•	A $250.0 million repayment of long-term debt during 2018 .


•	A $127.9 million net decrease in cash due to $76.0 million of net repayments of commercial paper during 2018 , compared with $51.9 million of net borrowings of commercial paper during 2017 .


•	A $70.0 million increase in dividends paid to our parent during 2018 , compared with 2017 .


•	A $47.0 million decrease in equity contributions received from our parent to balance our capital structure in 2018 , compared with 2017 .

These increases in net cash used in financing activities were partially offset by:


•	A $300.0 million increase in cash due to the issuance of long-term debt during 2018 .


•	An $18.5 million repayment to our parent during 2017 related to our former subsidiary's note payable.

2017 Compared with 2016

Net cash used in financing activities decreased $290.4 million during 2017 , compared with 2016 , driven by:


•	A $215.0 million decrease in dividends paid to our parent during 2017 compared with 2016 . During 2016 , we paid special dividends to our parent to balance our capital structure.


•	A $75.0 million equity contribution received from our parent to balance our capital structure in 2017 .


•	A $36.9 million increase in net borrowings of commercial paper during 2017 , compared with 2016 .

These decreases in net cash used for financing activities were partially offset by a $17.4 million increase in repayments to our parent during 2017 related to our former subsidiary's note payable, compared with 2016 .

Significant Financing Activities

For more information on our financing activities, see Note 10, Short-Term Debt and Lines of Credit , and Note 11, Long-Term Debt and Capital Lease Obligations .



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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 arrangements, 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 10, Short-Term Debt and Lines of Credit, for more information on our credit facility.

At December 31, 2018 , we were in compliance with all covenants related to outstanding short-term and long-term debt. We expect to be in compliance with all such debt covenants for the foreseeable future. See Note 11, Long-Term Debt and Capital Lease Obligations, for more information about our long-term debt.

Working Capital

As of December 31, 2018 , our current liabilities exceeded our current assets by $60.6 million . We do not expect this to have any impact on our liquidity since we believe we have an adequate back-up line 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, if necessary.

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 any 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

Contractual Obligations

We have the following contractual obligations and other commercial commitments as of December 31, 2018 :



	Payments Due by Period ⁽¹⁾
(in millions)	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Long-term debt obligations ⁽²⁾	$	5,288.3	$	372.7	$	522.5	$	207.5	$	4,185.6
Capital lease obligations ⁽³⁾	7,564.5		403.9		810.5		783.8		5,566.3
Operating lease obligations ⁽⁴⁾	21.7		2.9		3.5		1.4		13.9
Energy and transportation purchase obligations ⁽⁵⁾	10,160.6		761.9		1,385.2		1,429.0		6,584.5
Purchase orders ⁽⁶⁾	300.4		101.8		134.9		38.9		24.8
Pension and OPEB funding obligations ⁽⁷⁾	11.5		3.9		7.6		—		—
Total contractual obligations	$	23,347.0	$	1,647.1	$	2,864.2	$	2,460.6	$	16,375.1


⁽¹⁾	The amounts included in the table are calculated using current market prices, forward curves, and other estimates.


⁽²⁾	Principal and interest payments on long-term debt (excluding capital lease obligations).


⁽³⁾	Capital lease obligations for power purchase commitments and the leases with We Power.


⁽⁴⁾	Operating lease obligations for land and rail car leases.


⁽⁵⁾	Energy and transportation purchase obligations under various contracts for the procurement of fuel, power, gas supply, and associated transportation related to utility operations.


⁽⁶⁾	Purchase obligations related to normal business operations, information technology, and other services.


⁽⁷⁾	Obligations for pension and OPEB plans cannot reasonably be estimated beyond 2021 .

The table above does not reflect estimated future payments related to the manufactured gas plant remediation liability of $13.2 million at December 31, 2018 , as the amount and timing of payments are uncertain. We expect to incur costs annually to remediate these sites. See Note 19, Commitments and Contingencies, for more information about environmental liabilities.

AROs in the amount of $70.7 million are not included in the above table. Settlement of these liabilities cannot be determined with certainty, but we believe the majority of these liabilities will be settled in more than five years. See Note 7, Asset Retirement Obligations, for more information .

Obligations for utility operations have historically been included as part of the rate-making process and therefore are generally recoverable from customers.

Capital Expenditures and 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, additional changes in tax laws and regulations, acquisition and development opportunities, market volatility, and economic trends. Our estimated capital expenditures for the next three years are as follows:



(in millions)
2019	$	636.7
2020	876.3
2021	979.0
Total	$	2,492.0



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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.

Common Stock Matters

For information related to our common stock matters, see Note 8, Common Equity .

Investments in Outside Trusts

We use outside trusts to fund our pension and certain OPEB obligations. These trusts had investments of approximately $1.2 billion as of December 31, 2018 . These trusts hold investments that are subject to the volatility of the stock market and interest rates. We contributed $6.3 million, $8.3 million, and $8.0 million to our pension and OPEB plans in 2018 , 2017 , and 2016 , respectively. Future contributions to the plans will be dependent upon many factors, including the performance of existing plan assets and long-term discount rates. For additional information, see Note 15, Employee Benefits .

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. See Note 1(o), Guarantees , Note 10, Short-Term Debt and Lines of Credit , and Note 18, Variable Interest Entities , for more information.

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

Market Risks and Other Significant Risks

We are exposed to market and other significant risks as a result of the nature of our businesses and the environments in which those businesses operate. These risks, described in further detail below, include but are not limited to:

Regulatory Recovery

We account for our regulated operations in accordance with accounting guidance under the Regulated Operations Topic of the FASB ASC. Our rates are determined by various regulatory commissions. Our primary regulator is the PSCW. See Note 21, Regulatory Environment , for additional information regarding recent rate proceedings and orders.

Regulated entities are allowed to defer certain costs that would otherwise be charged to expense if the regulated entity believes the recovery of those costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by our regulators. Recovery of the deferred costs in future rates is subject to the review and approval by those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of the deferred costs is not approved by our regulators, the costs would be charged to income in the current period. In general, our regulatory assets are recovered over a period of between one to six years. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities. As of December 31, 2018 , our regulatory assets were $2,902.3 million , and our regulatory liabilities were $2,014.2 million .

Due to the Tax Legislation signed into law in December 2017, we remeasured our deferred taxes and recorded a tax benefit of $1,065 million. We have been returning this tax benefit to ratepayers through bill credits and reductions to other regulatory assets, which we expect to continue. See Note 12, Income Taxes , and Note 21, Regulatory Environment , for more information.



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Commodity Costs

In the normal course of providing energy, we are subject to market fluctuations in the costs of coal, natural gas, purchased power, and fuel oil used in the delivery of coal. We manage our fuel and natural gas supply costs through a portfolio of short and long-term procurement contracts with various suppliers for the purchase of coal, natural gas, and fuel oil. In addition, we manage the risk of price volatility through natural gas and electric hedging programs.

Embedded within our rates are amounts to recover fuel, natural gas, and purchased power costs. We have recovery mechanisms in place that allow us to recover or refund all or a portion of the changes in prudently incurred fuel, natural gas, and purchased power costs from rate case-approved amounts. See Item 1. Business – D. Regulation for more information on these mechanisms.

Higher commodity costs can increase our working capital requirements, result in higher gross receipts taxes, and lead to increased energy efficiency investments by our customers to reduce utility usage and/or fuel substitution. Higher commodity costs combined with slower economic conditions also expose us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills. See Note 1(d), Operating Revenues, for more information on our mechanism that allows for cost recovery or refund of uncollectible expense.

Weather

Our utility rates are based upon estimated normal temperatures. Our electric utility margins are unfavorably sensitive to below normal temperatures during the summer cooling season and, to some extent, to above normal temperatures during the winter heating season. Our natural gas utility margins are unfavorably sensitive to above normal temperatures during the winter heating season. A summary of actual weather information in our service territory during 2018 , 2017 , and 2016 , as measured by degree days, may be found in Results of Operations.

Interest Rates

We are exposed to interest rate risk resulting from our short-term borrowings and projected near-term debt financing needs. We manage exposure to interest rate risk by limiting the amount of our variable rate obligations and continually monitoring the effects of market changes on interest rates. When it is advantageous to do so, we enter into long-term fixed rate debt.

Based on our variable rate debt outstanding at December 31, 2018 , and December 31, 2017 , a hypothetical increase in market interest rates of one percentage point would have increased annual interest expense by $1.4 million and $2.1 million in 2018 and 2017 , respectively. This sensitivity analysis was performed assuming a constant level of variable rate debt during the period and an immediate increase in interest rates, with no other changes for the remainder of the period.

Marketable Securities Return

We use various trusts to fund our pension and OPEB obligations. These trusts invest in debt and equity securities. Changes in the market prices of these assets can affect future pension and OPEB expenses. Additionally, future contributions can also be affected by the investment returns on trust fund assets. We believe that the financial risks associated with investment returns would be partially mitigated through future rate actions by the PSCW.

The fair value of our trust fund assets and expected long-term returns were approximately:



(in millions)	As of December 31, 2018		Expected Return on Assets in 2019
Pension trust funds	$	1,019.8	7.00	%
OPEB trust funds	$	201.5	7.25	%

Fiduciary oversight of the pension and OPEB trust fund investments is the responsibility of an Investment Trust Policy Committee. The Committee works with external actuaries and investment consultants on an ongoing basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target asset allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. The targeted asset allocations are intended to reduce risk, provide long-term financial stability for the plans, and



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maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments. Investment strategies utilize a wide diversification of asset types and qualified external investment managers.

WEC Energy Group consults with its investment advisors on an annual basis to help it forecast expected long-term returns on plan assets by reviewing actual historical returns and calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the funds.

Economic Conditions

Our service territories are primarily within the state of Wisconsin. As such, we are exposed to market risks in the regional Midwest economy. In addition, any economic downturn or disruption of national or international markets could adversely affect the financial condition of our customers and demand for their products, which could affect their demand for our products.

Inflation

We continue to monitor the impact of inflation, especially with respect to the costs of medical plans, fuel, transmission access, construction costs, and regulatory and environmental compliance in order to minimize its effects in future years through pricing strategies, productivity improvements, and cost reductions. We do not believe the impact of general inflation will have a material impact on our future results of operations.

For additional information concerning risk factors, including market risks, see the Cautionary Statement Regarding Forward-Looking Information at the beginning of this report and Item 1A. Risk Factors.

Competitive Markets

Electric Utility Industry

The regulated energy industry continues to experience significant changes. The FERC continues to support large RTOs, which affects the structure of the wholesale market. To this end, MISO implemented the MISO Energy Markets, including the use of LMP to value electric transmission congestion and losses. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant and adverse financial impact on us.

Electric utility revenues in Wisconsin are regulated by the PSCW. The PSCW continues to maintain the position that the question of whether to implement electric retail competition in Wisconsin should ultimately be decided by the Wisconsin legislature. No such legislation has been introduced in Wisconsin to date, and it is uncertain when, if at all, retail choice might be implemented in Wisconsin.

Natural Gas Utility Industry

The PSCW previously instituted generic proceedings to consider how its regulation of natural gas distribution utilities should change to reflect a competitive environment in the natural gas industry. To date, the PSCW has made a policy decision to provide customer classes with competitive markets the option to choose an alternative retail natural gas supplier. The PSCW has also adopted standards for transactions between a utility and its natural gas marketing affiliates. All of our Wisconsin customer classes have competitive market choices and, therefore, can purchase natural gas directly from either an alternative retail natural gas supplier or their local natural gas utility.

We offer natural gas transportation services to our customers that elect to purchase natural gas from an alternative retail natural gas supplier. Since these transportation customers continue to use our distribution systems to transport natural gas to their facilities, we earn distribution revenues from them. As such, there is little impact on our net income from customers purchasing natural gas from an alternative retail natural gas supplier as natural gas costs are passed through to customers in rates on a one-for-one basis. We are currently unable to predict the impact of potential future industry restructuring on our results of operations or financial position.



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Environmental Matters

See Note 19, Commitments and Contingencies , for a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change.

Other Matters

Tax Cuts and Jobs Act of 2017

In December 2017, the Tax Legislation was signed into law. 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 21, Regulatory Environment , for more information.

Bonus Depreciation Provisions

Bonus depreciation is an additional amount of first-year tax deductible depreciation that is awarded above what would normally be available. The bonus depreciation deduction available for public utility property subject to rate-making by a government entity or public utility commission was modified by the Tax Legislation signed into law on December 22, 2017. Based on the provisions of the Tax Legislation, bonus depreciation can no longer be deducted for public utility property acquired and placed in service after December 31, 2017.

Critical Accounting Policies and Estimates

Preparation of financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions. In addition, the financial and operating environment may also have a significant effect, not only on the operation of our business, but on our results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied have not changed.

The following is a list of accounting policies that are most significant to the portrayal of our financial condition and results of operations and that require management's most difficult, subjective or complex judgments:

Long-Lived Assets

In accordance with ASC 360, Property, Plant, and Equipment, we periodically assess the recoverability of certain long-lived assets when events or changes in circumstances indicate that the carrying amount of those long-lived assets may not be recoverable. Examples of events or changes in circumstances include, but are not limited to, a significant decrease in the market price, a significant change in use, adverse legal factors or a change in business climate, operating or cash flow losses, or an expectation that the asset might be sold. These assessments require significant assumptions and judgments by management. The long-lived assets assessed for impairment generally include certain assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future.

We have evaluated future plans for our older and less efficient fossil fuel generating units and have either retired or announced the retirement of certain generating units. In accordance with ASC 980-360, Regulated Operations – Property, Plant, and Equipment, when it becomes probable that a generating unit will be retired before the end of its useful life, we assess whether the generating unit meets the criteria for abandonment accounting. Generating units that are considered probable of abandonment are expected to cease operations in the near term, significantly before the end of their original estimated useful lives. As a result, the remaining net book value of these assets can be significant. If a generating unit meets applicable criteria to be considered probable of abandonment, and the unit has been abandoned, we assess the likelihood of recovery of the remaining carrying value of that generating unit at the end of each reporting period. If it becomes probable that regulators will disallow full recovery as well as a return on the remaining net book value of a generating unit that is either abandoned or probable of being abandoned, an



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impairment loss may be required. An impairment loss would be recorded if the remaining carrying value of the generating unit is greater than the present value of the amount expected to be recovered from ratepayers.

Pleasant Prairie power plant was retired during 2018. PIPP continued to meet the criteria to be considered probable of abandonment as of December 31, 2018 . We plan to ask for full cost recovery of and a full return on the remaining book value of these generating units and have concluded that no impairment was required related to these assets as of December 31, 2018 . See Note 6, Property, Plant, and Equipment, for more information on our generating units, including various approvals we have received from the FERC.

Pension and Other Postretirement Employee Benefits

The costs of providing non-contributory defined pension benefits and OPEB, described in Note 15, Employee Benefits , are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.

Pension and OPEB costs are impacted by actual employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans, and earnings on plan assets. Pension and OPEB costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, mortality and discount rates, and expected health care cost trends. Changes made to the plan provisions may also impact current and future pension and OPEB costs.

Pension and OPEB plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity and fixed income market returns, as well as changes in general interest rates, may result in increased or decreased benefit costs in future periods. We believe that such changes in costs would be recovered or refunded through the ratemaking process.

The following table shows how a given change in certain actuarial assumptions would impact the projected benefit obligation and the reported net periodic pension cost. Each factor below reflects an evaluation of the change based on a change in that assumption only.



Actuarial Assumption (in millions, except percentages)	Percentage-Point Change in Assumption	Impact on Projected Benefit Obligation			Impact on 2018 Pension Cost
Discount rate	(0.5)	$	55.5		$	4.6
Discount rate	0.5	(49.8		)	(3.6		)
Rate of return on plan assets	(0.5)	N/A			5.3
Rate of return on plan assets	0.5	N/A			(5.3		)

The following table shows how a given change in certain actuarial assumptions would impact the accumulated OPEB obligation and the reported net periodic OPEB cost. Each factor below reflects an evaluation of the change based on a change in that assumption only.



Actuarial Assumption (in millions, except percentages)	Percentage-Point Change in Assumption	Impact on Postretirement Benefit Obligation			Impact on 2018 Postretirement Benefit Cost
Discount rate	(0.5)	$	14.6		$	0.7
Discount rate	0.5	(13.1		)	—
Health care cost trend rate	(0.5)	(7.1		)	(1.2		)
Health care cost trend rate	0.5	8.2			1.4
Rate of return on plan assets	(0.5)	N/A			1.1
Rate of return on plan assets	0.5	N/A			(1.1		)

The discount rates are selected based on hypothetical bond portfolios consisting of noncallable (or callable with make-whole provisions), noncollateralized, high-quality corporate bonds across the full maturity spectrum. The bonds are generally rated "Aa" with a minimum amount outstanding of $50.0 million. From the hypothetical bond portfolios, a single rate is determined that equates the market value of the bonds purchased to the discounted value of the plans' expected future benefit payments.

We establish our expected return on asset assumption based on consideration of historical and projected asset class returns, as well as the target allocations of the benefit trust portfolios. The assumed long-term rate of return on pension plan assets was 7.00% in 2018 , 2017 , and 2016 . The actual rate of return on pension plan assets, net of fees, was (2.91)%, 11.48%, and 6.91%, in 2018 , 2017 , and 2016 , respectively.



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In selecting assumed health care cost trend rates, past performance and forecasts of health care costs are considered. For more information on health care cost trend rates and a table showing future payments that we expect to make for our pension and OPEB, see Note 15, Employee Benefits .

Regulatory Accounting

Our utility operations follow the guidance under the Regulated Operations Topic of the FASB ASC. Our financial statements reflect the effects of the ratemaking principles followed by the jurisdictions regulating us. Certain items that would otherwise be immediately recognized as revenues and expenses are deferred as regulatory assets and regulatory liabilities for future recovery or refund to customers, as authorized by our regulators.

Future recovery of regulatory assets is not assured and is generally subject to review by regulators in rate proceedings for matters such as prudence and reasonableness. Once approved, the regulatory assets and liabilities are amortized into earnings over the rate recovery period. If recovery or refund of costs is not approved or is no longer considered probable, these regulatory assets or liabilities are recognized in current period earnings. Management regularly assesses whether these regulatory assets and liabilities are probable of future recovery or refund by considering factors such as changes in the regulatory environment, earnings from our electric and natural gas utility operations, and the status of any pending or potential deregulation legislation.

The application of the Regulated Operations Topic of the FASB ASC would be discontinued if all or a separable portion of our utility operations no longer met the criteria for application. Our regulatory assets and liabilities would be written off to income as an unusual or infrequently occurring item in the period in which discontinuation occurred. As of December 31, 2018 , we had $2,902.3 million in regulatory assets and $2,014.2 million in regulatory liabilities. See Note 5, Regulatory Assets and Liabilities, for more information .

Unbilled Revenues

We record utility operating revenues when energy is delivered to our customers. However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated. This unbilled revenue is estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses, and applicable customer rates. Significant fluctuations in energy demand for the unbilled period or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. Total utility operating revenues during 2018 of approximately $3.6 billion included accrued utility revenues of $215.6 million as of December 31, 2018 .

Income Tax Expense

We are required to estimate income taxes for each of the jurisdictions in which we operate as part of the process of preparing consolidated financial statements. This process involves estimating current income tax liabilities together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for income tax and accounting purposes. These differences result in deferred income tax assets and liabilities, which are included within our balance sheets. We also assess the likelihood that our deferred income tax assets will be recovered through future taxable income. To the extent we believe that realization is not likely, we establish a valuation allowance, which is offset by an adjustment to income tax expense in our income statements.

Uncertainty associated with the application of tax statutes and regulations and the outcomes of tax audits and appeals requires that judgments and estimates be made in the accrual process and in the calculation of effective tax rates. Only income tax benefits that meet the "more likely than not" recognition threshold may be recognized or continue to be recognized. Unrecognized tax benefits are re-evaluated quarterly and changes are recorded based on new information, including the issuance of relevant guidance by the courts or tax authorities and developments occurring in the examinations of our tax returns.

Significant management judgment is required in determining our provision for income taxes, deferred income tax assets and liabilities, the liability for unrecognized tax benefits, and any valuation allowance recorded against deferred income tax assets. The assumptions involved are supported by historical data, reasonable projections, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. Significant changes in these assumptions could have a material impact on our



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financial condition and results of operations. See Note 1(l), Income Taxes , and Note 12, Income Taxes , for a discussion of accounting for income taxes.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks, as well as Note 1(m), Fair Value Measurements ,

Note 1(n), Derivative Instruments , and Note 1(o), Guarantees , for information concerning potential market risks to which we are exposed.



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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

A. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholder and the Board of Directors of Wisconsin Electric Power Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets and statements of capitalization of Wisconsin Electric Power Company and subsidiary (the “Company”) as of December 31, 2018 and 2017, the related consolidated statements of income, equity, and cash flows, for each of the three years in the period ended December 31, 2018, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/DELOITTE & TOUCHE LLP

Milwaukee, Wisconsin

February 26, 2019

We have served as the Company's auditor since 2002.



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B. CONSOLIDATED INCOME STATEMENTS



Year Ended December 31
(in millions)	2018			2017			2016
Operating revenues	$	3,625.0		$	3,711.7		$	3,792.8

Operating expenses
Cost of sales	1,262.1			1,286.4			1,292.1
Other operation and maintenance	1,502.4			1,352.0			1,425.5
Depreciation and amortization	348.1			331.6			325.4
Property and revenue taxes	109.9			109.6			115.6
Total operating expenses	3,222.5			3,079.6			3,158.6

Operating income	402.5			632.1			634.2

Equity in earnings of transmission affiliate	—			—			55.5
Other income, net	20.2			13.2			4.4
Interest expense	120.1			117.3			117.6
Other expense	(99.9		)	(104.1		)	(57.7		)

Income before income taxes	302.6			528.0			576.5
Income tax (benefit) expense	(56.9		)	191.2			211.0
Net income	359.5			336.8			365.5

Preferred stock dividend requirements	1.2			1.2			1.2
Net income attributed to common shareholder	$	358.3		$	335.6		$	364.3

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



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C. CONSOLIDATED BALANCE SHEETS



At December 31
(in millions, except share and per share amounts)	2018		2017
Assets
Current assets
Cash and cash equivalents	$	20.2	$	12.3
Accounts receivable and unbilled revenues, net of reserves of $40.9 and $39.5, respectively	472.3		513.8
Accounts receivable from related parties	112.4		109.1
Materials, supplies, and inventories	241.4		250.7
Prepayments	163.7		144.3
Other	6.3		9.4
Current assets	1,016.3		1,039.6

Long-term assets
Property, plant, and equipment, net of accumulated depreciation of $3,450.1 and $3,741.8, respectively	9,528.9		10,007.7
Regulatory assets	2,902.2		1,984.9
Other	90.9		89.4
Long-term assets	12,522.0		12,082.0
Total assets	$	13,538.3	$	13,121.6

Liabilities and Equity
Current liabilities
Short-term debt	$	134.9	$	210.9
Current portion of long-term debt	250.0		250.0
Current portion of capital lease obligations	49.9		42.5
Accounts payable	248.9		329.3
Accounts payable to related parties	226.0		131.5
Accrued payroll and benefits	50.4		53.4
Other	116.8		170.0
Current liabilities	1,076.9		1,187.6

Long-term liabilities
Long-term debt	2,459.6		2,412.3
Capital lease obligations	2,807.2		2,823.8
Deferred income taxes	1,298.3		1,155.5
Regulatory liabilities	2,002.3		1,708.0
Pension and OPEB obligations	118.5		143.2
Other	284.3		276.9
Long-term liabilities	8,970.2		8,519.7

Commitments and contingencies (Note 19)

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	831.3		802.7
Retained earnings	2,296.6		2,248.3
Common shareholder's equity	3,460.8		3,383.9

Preferred stock	30.4		30.4
Total liabilities and equity	$	13,538.3	$	13,121.6

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



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D. CONSOLIDATED STATEMENTS OF CASH FLOWS



Year Ended December 31
(in millions)	2018			2017			2016
Operating activities
Net income	$	359.5		$	336.8		$	365.5
Reconciliation to cash provided by operating activities
Depreciation and amortization	348.1			331.6			325.4
Deferred income taxes and investment tax credits, net	(0.7		)	109.7			206.2
Contributions and payments related to pension and OPEB plans	(6.3		)	(8.3		)	(8.0		)
Equity income in transmission affiliate, net of distributions	—			—			(17.2		)
Payments for liabilities transferred to affiliates	(10.1		)	(0.3		)	(116.0		)
Change in –
Accounts receivable and unbilled revenues	34.8			(64.9		)	(59.0		)
Materials, supplies, and inventories	9.3			20.3			30.6
Prepaid taxes	(28.3		)	0.5			39.4
Other current assets	13.5			(11.8		)	9.3
Accounts payable	13.2			45.8			31.3
Accrued taxes	(41.1		)	12.8			30.4
Other current liabilities	(5.2		)	12.2			10.7
Other, net	275.5			(86.4		)	(0.2		)
Net cash provided by operating activities	962.2			698.0			848.4

Investing activities
Capital expenditures	(603.2		)	(596.1		)	(469.5		)
Capital contributions to transmission affiliate	—			—			(16.1		)
Proceeds from the sale of assets	1.7			22.9			31.7
Proceeds from assets transferred to affiliates	8.8			—			13.1
Payments for assets transferred from affiliates	(59.8		)	—			—
Other, net	12.1			5.0			4.0
Net cash used in investing activities	(640.4		)	(568.2		)	(436.8		)

Financing activities
Change in short-term debt	(76.0		)	51.9			15.0
Repayment of subsidiary note to parent	—			(18.5		)	(1.1		)
Issuance of long-term debt	300.0			—			—
Retirement of long-term debt	(250.0		)	—			—
Equity contribution from parent	28.0			75.0			—
Payment of dividends to parent	(310.0		)	(240.0		)	(455.0		)
Payment of preferred stock dividends	(1.2		)	(1.2		)	(1.2		)
Other, net	(4.7		)	(0.1		)	19.0
Net cash used in financing activities	(313.9		)	(132.9		)	(423.3		)

Net change in cash and cash equivalents	7.9			(3.1		)	(11.7		)
Cash and cash equivalents at beginning of year	12.3			15.4			27.1
Cash and cash equivalents at end of year	$	20.2		$	12.3		$	15.4

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



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E. CONSOLIDATED STATEMENTS OF EQUITY



	Wisconsin Electric Power Company Common Shareholder's Equity
	Common Stock		Additional Paid-In Capital			Retained Earnings			Total Common Shareholder's Equity			Preferred Stock		Total Equity
(in millions)	Common Stock		Additional Paid-In Capital			Retained Earnings			Total Common Shareholder's Equity			Preferred Stock		Total Equity
Balance at December 31, 2015	$	332.9	$	999.7		$	2,231.4		$	3,564.0		$	30.4	$	3,594.4
Net income	—		—			365.5			365.5			—		365.5
Dividends
Common stock	—		—			(455.0		)	(455.0		)	—		(455.0		)
Preferred stock	—		—			(1.2		)	(1.2		)	—		(1.2		)
Tax benefit of exercised stock options allocated from parent	—		19.3			—			19.3			—		19.3
Stock-based compensation and other	—		1.1			0.1			1.2			—		1.2
Balance at December 31, 2016	$	332.9	$	1,020.1		$	2,140.8		$	3,493.8		$	30.4	$	3,524.2
Net income	—		—			336.8			336.8			—		336.8
Dividends
Common stock	—		—			(240.0		)	(240.0		)	—		(240.0		)
Preferred stock	—		—			(1.2		)	(1.2		)	—		(1.2		)
Cumulative effect adjustment from adoption of ASU 2016-09	—		—			11.9			11.9			—		11.9
Equity contribution from parent	—		75.0			—			75.0			—		75.0
Transfer of net assets to UMERC	—		(61.1		)	—			(61.1		)	—		(61.1		)
Transfer of ATC ownership interest and related taxes	—		(228.6		)	—			(228.6		)	—		(228.6		)
Settlement of a short-term note receivable between Bostco and our parent company	—		(4.8		)	—			(4.8		)	—		(4.8		)
Stock-based compensation and other	—		2.1			—			2.1			—		2.1
Balance at December 31, 2017	$	332.9	$	802.7		$	2,248.3		$	3,383.9		$	30.4	$	3,414.3
Net income	—		—			359.5			359.5			—		359.5
Dividends
Common stock	—		—			(310.0		)	(310.0		)	—		(310.0		)
Preferred stock	—		—			(1.2		)	(1.2		)	—		(1.2		)
Equity contribution from parent	—		28.0			—			28.0			—		28.0
Stock-based compensation and other	—		0.6			—			0.6			—		0.6
Balance at December 31, 2018	$	332.9	$	831.3		$	2,296.6		$	3,460.8		$	30.4	$	3,491.2

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



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F. CONSOLIDATED STATEMENTS OF CAPITALIZATION



At December 31 (in millions)			2018			2017
Common shareholder's equity (see accompanying statement)			3,460.8			3,383.9
Preferred stock (Note 9)			30.4			30.4
Long-term debt	Interest Rate	Year Due
Debentures (unsecured)	1.70%	2018	—			250.0
	4.25%	2019	250.0			250.0
	2.95%	2021	300.0			300.0
	3.10%	2025	250.0			250.0
	6.50%	2028	150.0			150.0
	5.625%	2033	335.0			335.0
	5.70%	2036	300.0			300.0
	3.65%	2042	250.0			250.0
	4.25%	2044	250.0			250.0
	4.30%	2045	250.0			250.0
	4.30%	2048	300.0			—
	6.875%	2095	100.0			100.0
Obligations under capital leases			2,857.1			2,866.3
Total			5,592.1			5,551.3
Unamortized debt issuance costs			(6.0		)	(3.2		)
Unamortized discount, net			(19.4		)	(19.5		)
Total long-term debt and capital lease obligations, including current portion			5,566.7			5,528.6
Current portion of long-term debt and capital lease obligations			(299.9		)	(292.5		)
Total long-term debt and capital lease obligations			5,266.8			5,236.1
Total long-term capitalization			$	8,758.0		$	8,650.4

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



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G. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1— SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) Nature of Operations —We are an electric, natural gas, and steam utility company that serves electric customers in Wisconsin, an iron ore mine owned by Tilden in the Upper Peninsula of Michigan, natural gas customers in Wisconsin, and steam customers in metropolitan Milwaukee, Wisconsin. WEC Energy Group owns all of our outstanding common stock.

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, and UMERC became operational effective January 1, 2017. This utility holds the electric assets previously held by us, and the electric and natural gas distribution assets previously held by WPS, located in the Upper Peninsula of Michigan. The existing contract between Tilden and us will remain in place until a new power generation solution for the region is commercially operational, which is expected to occur during the second quarter of 2019.

As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, balance sheets, statements of cash flows, statements of equity, and statements of capitalization, unless otherwise noted.

Through October 2018, we had one wholly owned subsidiary, Bostco. At December 31, 2016, Bostco had total assets of $24.4 million . In March 2017, we sold substantially all of the remaining assets of Bostco, and, in October 2018, Bostco was dissolved. See Note 2, Dispositions, for more information . The financial statements include our accounts and the accounts of our former wholly owned subsidiary. Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method.

(b) Basis of Presentation —We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates.

(c) Cash and Cash Equivalents —Cash and cash equivalents include marketable debt securities with an original maturity of three months or less.

(d) Operating Revenues —The following discussion includes our significant accounting policies related to operating revenues, including our adoption of ASU 2014-09, Revenues from Contracts with Customers. For additional required disclosures on disaggregation of operating revenues as required by this ASU, see Note 4, 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.



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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.

Revenues from Contracts with Customers

Electric Utility Operating Revenues

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 transaction price of the performance obligations for residential and commercial and industrial customers is valued using the rates, charges, terms, and conditions of service included in our tariffs, which have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month. Our retail electric rates in Wisconsin include base amounts for fuel and purchased power costs, which also impact our revenues. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under- or over-collections of actual fuel and purchased power costs that exceed a 2% price variance from the costs included in the rates charged to customers. We monitor the deferral of under-collected costs to ensure that it does not cause us to earn a greater ROE than authorized by the PSCW. In contrast, the rates of our Michigan retail electric customer include recovery of fuel and purchased power costs on a one-for-one basis. In addition, our Wisconsin residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates.

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. 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.

The transaction price of the performance obligations for wholesale customers is valued using the rates, charges, terms, and conditions of service for sales included in our tariffs, which have been approved by the FERC. These wholesale rates include recovery of fuel and purchased power costs from customers on a one-for-one basis. 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.

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



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hour are recorded as resale revenues on our income statements. 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 .

Natural Gas Utility Operating Revenues

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

The transaction price of the performance obligations for our natural gas customers is valued using rates, charges, terms, and conditions of service included 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.

Our tariffs include various rate mechanisms that allow us to recover or refund changes in prudently incurred costs from rate case-approved amounts. Our rates include one-for-one recovery mechanisms for natural gas commodity costs. We defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year. In addition, our Wisconsin residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates.

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

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.

(e) Materials, Supplies, and Inventories —Our inventory as of December 31 consisted of:



(in millions)	2018		2017
Materials and supplies	$	146.1	$	140.7
Fossil fuel	58.7		74.8
Natural gas in storage	36.6		35.2
Total	$	241.4	$	250.7



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

(f) Regulatory Assets and Liabilities —The economic effects of regulation can result in regulated companies recording costs and revenues that have been or are expected to be allowed in the rate-making process in a period different from the period in which the costs or revenues would be recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent probable future revenues associated with certain costs or liabilities that have been deferred and are expected to be recovered through rates charged to customers. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or amounts that are collected in rates for future costs.

Recovery or refund of regulatory assets and liabilities is based on specific periods determined by the regulators or occurs over the normal operating period of the assets and liabilities to which they relate. If at any reporting date a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery with the reduction charged to expense in the reporting period the determination is made. See Note 5, Regulatory Assets and Liabilities, for more information .

(g) Property, Plant, and Equipment —We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to other operation and maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.

We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the PSCW and MPSC that include estimates for salvage value and removal costs. Depreciation as a percent of average depreciable utility plant was 3.18% , 2.95% , and 3.00% in 2018 , 2017 , and 2016 , respectively.

We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 5 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement.

For assets other than our regulated assets and leased equipment, we accrue depreciation expense at straight-line rates over the estimated useful lives of the assets, or over the non-cancellable lease term for leased equipment.

Third parties reimburse us for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs are recorded as a reduction to property, plant, and equipment.

See Note 6, Property, Plant, and Equipment, for more information .

(h) Allowance for Funds Used During Construction —AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC – Debt) used during plant construction, and a return on shareholders' capital (AFUDC – Equity) used for construction purposes. AFUDC – Debt is recorded as a reduction of interest expense, and AFUDC – Equity is recorded in other income, net.

Approximately 50% of our retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. Our average AFUDC retail rates were 8.45% for 2018 , 2017 , and 2016 . Our average AFUDC wholesale rates were 3.63% , 5.94% , and 2.73% for 2018 , 2017 , and 2016 , respectively.

We recorded the following AFUDC for the years ended December 31:



(in millions)	2018		2017		2016
AFUDC – Debt	$	1.5	$	1.2	$	1.7
AFUDC – Equity	$	3.9	$	3.1	$	4.2

(i) Asset Retirement Obligations —We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. An ARO liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the



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obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The ARO liabilities are accreted each period using the credit-adjusted risk-free interest rates associated with the expected settlement dates of the AROs. These rates are determined when the obligations are incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated capitalized retirement costs. We recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. See Note 7, Asset Retirement Obligations, for more information .

(j) Asset Impairment —We periodically assess the recoverability of certain long-lived assets when factors indicate the carrying value of such assets may be impaired or such assets are planned to be sold. These assessments require significant assumptions and judgments by management. The long-lived assets assessed for impairment generally include certain assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset.

When it becomes probable that a generating unit will be retired before the end of its useful life, we assess whether the generating unit meets the criteria for abandonment accounting. Generating units that are considered probable of abandonment are expected to cease operations in the near term, significantly before the end of their original estimated useful lives. If a generating unit meets the applicable criteria to be considered probable of abandonment, and the unit has been abandoned, we assess the likelihood of recovery of the remaining carrying value of that generating unit at the end of each reporting period. If it becomes probable that regulators will disallow full recovery as well as a return on the remaining net book value of a generating unit that is either abandoned or probable of being abandoned, an impairment loss may be required. An impairment loss would be recorded if the remaining carrying value of the generating unit is greater than the present value of the amount expected to be recovered from ratepayers. See Note 6, Property, Plant, and Equipment, for more information .

(k) Stock-Based Compensation —Our employees participate in the WEC Energy Group stock-based compensation plans. In accordance with the WEC Energy Group shareholder approved Omnibus Stock Incentive Plan, WEC Energy Group provides long-term incentives through its equity interests to its non-employee directors, selected officers, and other key employees. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in WEC Energy Group common stock, cash, or a combination thereof. The number of shares of WEC Energy Group common stock authorized for issuance under the plan is 34.3 million .

Stock-based compensation expense is allocated to us based on the outstanding awards held by our employees and our allocation of labor costs. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period.

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which modified certain aspects of the accounting for stock-based compensation awards. This ASU became effective for us on January 1, 2017. Under the new guidance, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement on a prospective basis. Prior to January 1, 2017, these amounts were recorded in additional paid in capital on the balance sheet, and excess tax benefits could only be recognized to the extent they reduced taxes payable. In the first quarter of 2017, we recorded an $11.9 million cumulative-effect adjustment to increase retained earnings for excess tax benefits that had not been recognized in prior years as they did not reduce taxes payable.

ASU 2016-09 also requires excess tax benefits to be classified as an operating activity on the statement of cash flows. As we elected to apply this provision on a prospective basis, the 2016 excess tax benefits continue to be reflected as a financing activity. As allowed under this ASU, we also elected to account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period.

Stock Options

Our employees are granted WEC Energy Group non-qualified stock options that generally vest on a cliff-basis after a three -year period. The exercise price of a stock option under the plan cannot be less than 100% of the fair market value of WEC Energy Group common stock on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market



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value of WEC Energy Group common stock on the date of the grant. Options may not be exercised within six months of the grant date except in the event of a change in control. Options expire no later than 10 years from the date of grant.

WEC Energy Group stock options are classified as equity awards. The fair value of each stock option was calculated using a binomial option-pricing model. The following table shows the estimated weighted-average fair value per stock option granted to our employees along with the weighted-average assumptions used in the valuation models:



	2018			2017			2016
Stock options granted	81,730			80,770			92,880

Estimated weighted-average fair value per stock option	$	7.26		$	7.12		$	4.92

Assumptions used to value the options:
Risk-free interest rate	1.6% – 2.5%			0.7% – 2.5%			0.5% – 2.2%
Dividend yield	3.5		%	3.5		%	4.0		%
Expected volatility	18.0		%	19.0		%	18.0		%
Expected life (years)	5.1			6.2			5.8

The risk-free interest rate was based on the United States Treasury interest rate with a term consistent with the expected life of the stock options. The dividend yield was based on WEC Energy Group's dividend rate at the time of the grant and historical stock prices. Expected volatility and expected life assumptions were based on WEC Energy Group's historical experience.

Restricted Shares

WEC Energy Group restricted shares granted to our employees have a three -year vesting period with one-third of the award vesting on each anniversary of the grant date. The restricted shares are classified as equity awards.

Performance Units

Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. Under the plan, the ultimate number of units that will be awarded is dependent on WEC Energy Group's total shareholder return (stock price appreciation plus dividends) as compared to the total shareholder return of a peer group of companies over a three -year period, and beginning in 2017, other performance metrics as determined by the Compensation Committee. Participants may earn between 0% and 175% of the base performance unit award, as adjusted pursuant to the terms of the plan. Performance units also accrue forfeitable dividend equivalents in the form of additional performance units.

All grants of performance units are settled in cash and are accounted for as liability awards accordingly. The fair value of the performance units reflects our estimate of the final expected value of the awards, which is based on WEC Energy Group's stock price and performance achievement under the terms of the award. Stock-based compensation costs are recorded over the three -year performance period.

See Note 8, Common Equity , for more information on WEC Energy Group's stock-based compensation plans.

(l) Income Taxes —We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense.

Investment tax credits associated with regulated operations are deferred and amortized over the life of the assets. We are included in WEC Energy Group's consolidated Federal and state income tax returns. In accordance with our tax allocation agreement with WEC Energy Group, we are allocated income tax payments and refunds based upon our separate tax computation. See Note 12, Income Taxes, for more information .



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We recognize interest and penalties accrued related to unrecognized tax benefits in income tax expense in our income statements.

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

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

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

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

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

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

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

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

See Note 13, Fair Value Measurements, for more information .

(n) 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 assets or liabilities 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.

We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows.

Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets. See Note 14, Derivative Instruments, for more information .



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(o) Guarantees —We follow the guidance of the Guarantees Topic of the FASB ASC, which requires, under certain circumstances, that the guarantor recognize a liability for the fair value of the obligation undertaken in issuing the guarantee at its inception. As of December 31, 2018 , we had $26.2 million of standby letters of credit issued by financial institutions for the benefit of third parties that extended credit to us which automatically renew each year unless proper termination notice is given. These amounts are not reflected on our balance sheets.

(p) Employee Benefits —The costs of pension and OPEB plans are expensed over the periods during which employees render service. These costs are distributed among WEC Energy Group's subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for our net periodic benefit cost calculated under GAAP. See Note 15, Employee Benefits, for more information .

(q) Customer Deposits and Credit Balances —When utility customers apply for new service, they may be required to provide a deposit for the service. Customer deposits are recorded within other current liabilities on our balance sheets.

Utility customers can elect to be on a budget plan. Under this type of plan, a monthly installment amount is calculated based on estimated annual usage. During the year, the monthly installment amount is reviewed by comparing it to actual usage. If necessary, an adjustment is made to the monthly amount. Annually, the budget plan is reconciled to actual annual usage. Payments in excess of actual customer usage are recorded within other current liabilities on our balance sheets.

(r) Environmental Remediation Costs —We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including coal combustion product landfill sites and manufactured gas plant sites. See Note 7, Asset Retirement Obligations, for more information regarding coal combustion product landfill sites and Note 19, Commitments and Contingencies , for more information regarding manufactured gas plant sites.

We record environmental remediation liabilities when site assessments indicate remediation is probable and we can reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potentially responsible parties or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation.

We have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the PSCW's approval.

We review our estimated costs of remediation annually for our manufactured gas plant sites and coal combustion product landfill sites. We adjust the liabilities and related regulatory assets, as appropriate, to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year.

(s) Customer Concentrations of Credit Risk —We provide regulated electric, natural gas, and steam service to customers in Wisconsin and to Tilden located in the Upper Peninsula of Michigan. See Note 3, Related Parties , and Note 21, Regulatory Environment , for information regarding the transfer of our customers located in the Upper Peninsula of Michigan to UMERC as of January 1, 2017. The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Our credit risk exposure is mitigated by our recovery mechanism for uncollectible expense discussed in Note 1(d), Operating Revenues . As a result, we did not have any significant concentrations of credit risk at December 31, 2018 . In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2018 .



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NOTE 2— DISPOSITIONS

Utility Segment

Sale of Milwaukee County Power Plant

In April 2016, we sold the MCPP steam generation and distribution assets, located in Wauwatosa, Wisconsin. MCPP primarily provided steam to the Milwaukee Regional Medical Center hospitals and other campus buildings. During the second quarter of 2016, we recorded a pre-tax gain on the sale of $10.9 million ( $6.5 million after tax), which was included in other operation and maintenance 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 of this plant 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.

Other Segment

Sale of Bostco LLC 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, and in October 2018, Bostco was dissolved. 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— RELATED PARTIES

We routinely enter into transactions with related parties, including WEC Energy Group, its other subsidiaries, ATC, and other affiliated entities.

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

Following our parent company's acquisition of Integrys on June 29, 2015, an AIA (Non-WBS AIA) went into effect. The Non-WBS AIA governed the provision and receipt of services by WEC Energy Group's subsidiaries, except that WBS continued to provide services to Integrys and its subsidiaries only under the existing WBS AIAs. WBS provided services to WEC Energy Group and the former Wisconsin Energy Corporation subsidiaries, including us, under interim WBS AIAs. The PSCW and all other relevant state commissions approved the Non-WBS AIA or granted appropriate waivers related to the Non-WBS AIA.

Services under the Non-WBS AIA were subject to various pricing methodologies. All services provided by any regulated subsidiary to another regulated subsidiary were priced at cost. All services provided by any regulated subsidiary to any nonregulated subsidiary were priced at the greater of cost or fair market value. All services provided by any nonregulated subsidiary to any regulated subsidiary were priced at the lesser of cost or fair market value. All services provided by any regulated or nonregulated subsidiary to WBS were priced at cost.

WBS provided several categories of services (including financial, human resource, and administrative services) to us pursuant to the interim WBS AIAs, which were approved, or from which we were granted appropriate waivers, by the appropriate regulators, including the PSCW. As required by FERC regulations for centralized service companies, WBS renders services at cost. The PSCW must be notified prior to making changes to the services offered under and the allocation methods specified in the interim WBS AIAs. Other modifications or amendments to the interim WBS AIAs would require PSCW approval. Recovery of allocated costs is addressed in our rate cases.

A new AIA took effect January 1, 2017. The new agreement replaced the previous agreements. The pricing methodology and services under this new agreement are substantially identical to those under the agreements that were replaced. All of the applicable state commissions approved modifications to the new AIA to incorporate WEC Energy Group's acquisition of Bluewater. See below for more information on the acquisition.



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In connection with the sale of Bostco’s remaining real estate holdings, Wispark, a subsidiary of WEC Energy Group, provided $7.0 million of financing to the buyer and established a corresponding note receivable. Bostco had a $7.0 million related party receivable from Wispark that was paid in April 2017. See Note 2, Dispositions, for more information on the real estate sale.

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

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

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



(in millions)	2018		2017
Accounts receivable
Services provided to ATC	$	2.2	$	0.8
Accounts payable
Services received from ATC	19.4		22.2

The following table shows activity associated with our related party transactions for the years ended December 31:



(in millions)	2018			2017			2016
Lease agreements
Lease payments to We Power ⁽¹⁾	$	373.7		$	420.5		$	412.2
CWIP billed to We Power	39.5			57.3			37.9
Transactions with WBS ⁽²⁾
Billings to WBS	61.5			255.7		⁽³⁾	213.8		⁽³⁾
Billings from WBS ⁽⁴⁾	243.4			215.4			310.6
Transactions with WPS
Natural gas purchases from WPS	1.9			1.6			1.9
Billings to WPS ⁽²⁾	17.8		⁽³⁾	28.2			9.0
Billings from WPS ⁽²⁾	10.9			4.5			4.2
Transactions with WG
Natural gas purchases from WG	5.3			5.3			5.3
Billings to WG ⁽²⁾	59.0		⁽³⁾	64.0			60.6
Billings from WG ⁽²⁾	32.6			23.1			21.5
Transactions with UMERC ⁽⁵⁾
Electric sales to UMERC	29.6			30.8			—
Billings to UMERC ⁽²⁾	15.8		⁽³⁾	125.5			—
Transactions with Bluewater ⁽⁶⁾
Storage service fees	15.0			2.7			—
Transactions with ATC
Charges to ATC for services and construction	13.9			10.9			10.0
Charges from ATC for network transmission services	232.0			241.4			247.8
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 the Tax Legislation.


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


⁽³⁾	Includes $8.8 million for the transfer of certain software assets to affiliates for the year ended December 31, 2018 , and $13.1 million for the transfer of certain software assets to WBS for the year ended December 31, 2016. Also includes $1.2 million for the transfer of certain benefit-related liabilities from WBS for the year ended December 31, 2017 .



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⁽⁴⁾	For the years ended December 31, 2018 , 2017 , and 2016 , includes $10.0 million , $1.5 million , and $116.0 million , respectively, for the transfer of certain benefit-related liabilities to WBS. Also includes $59.8 million for the transfer of certain software assets from WBS for the year ended December 31, 2018 .


⁽⁵⁾	UMERC became operational effective January 1, 2017. See below for more information.


⁽⁶⁾	WEC Energy Group's acquisition of Bluewater was completed on June 30, 2017. See below for more information.

Parent Company's Acquisition of Natural Gas Storage Facilities in Michigan

In June 2017, our parent company completed its 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 entered into a long-term service agreement with a wholly owned subsidiary of Bluewater to take a portion of the storage, which was then approved by the PSCW in November 2017. See Note 21, Regulatory Environment, 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. See Note 21, Regulatory Environment, for more information . We transferred approximately 27,500 retail electric customers and 50 electric distribution-only customers to UMERC, along with approximately 2,500 miles of electric distribution lines. We also transferred related electric distribution substations in the Upper Peninsula of Michigan and all property rights for the distribution assets to UMERC. The book value of net assets, including the related deferred income tax liabilities, transferred to UMERC from us in 2017, was $61.1 million . This transaction was a non-cash equity transfer recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss. UMERC currently meets its market obligations through power purchase agreements with us and WPS.

NOTE 4— OPERATING REVENUES

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 years ended December 31, 2017 and 2016 , due to our adoption of ASU 2014-09, Revenues from Contracts with Customers, under the modified retrospective method. See Note 1(d), Operating Revenues, for more information about our significant accounting policies related to operating revenues.



	Wisconsin Electric Power Company Consolidated
(in millions)	Year ended December 31, 2018
Electric utility	$	3,212.7
Natural gas utility	405.1
Total revenues from contracts with customers	3,617.8
Other operating revenues	7.2
Total operating revenues	$	3,625.0



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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)	Year ended December 31, 2018
Residential	$	1,220.8
Small commercial and industrial	1,020.0
Large commercial and industrial	656.6
Other	20.7
Total retail revenues	2,918.1
Wholesale	108.5
Resale	153.7
Steam	24.1
Other utility revenues	8.3
Total electric utility operating revenues	$	3,212.7

Natural Gas Utility Operating Revenues

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



	Natural Gas Utility Operating Revenues
(in millions)	Year ended December 31, 2018
Residential	$	264.3
Commercial and industrial	126.3
Total retail revenues	390.6
Transport	13.4
Other utility revenues	1.1
Total natural gas utility operating revenues	$	405.1

Other Operating Revenues

Other operating revenues consist primarily of the following:



(in millions)	Year ended December 31, 2018
Late payment charges	$	8.2
Leases	2.9
Alternative revenues *	(3.9		)
Total other operating revenues	$	7.2


*	Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to wholesale true-ups, as discussed in Note 1(d), Operating Revenues .



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NOTE 5— REGULATORY ASSETS AND LIABILITIES

The following regulatory assets were reflected on our balance sheets as of December 31:



(in millions)	2018		2017		See Note
Regulatory assets ^{(1) (2)}
Capital leases	$	869.3	$	801.3	11
Plant retirements	754.1		6.6		6
Pension and OPEB costs ⁽³⁾	490.6		484.4		15
Income tax related items ⁽⁴⁾	317.9		—		12
SSR	316.7		298.9		21
Electric transmission costs	57.8		220.7		21
We Power generation ⁽⁵⁾	43.0		71.3
AROs	28.7		41.4		7
Other, net	24.2		60.3
Total regulatory assets	$	2,902.3	$	1,984.9

Balance Sheet Presentation
Current assets	$	0.1	$	—
Regulatory assets	2,902.2		1,984.9
Total regulatory assets	$	2,902.3	$	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⁾

As of December 31, 2018 , we had $10.9 million of regulatory assets not earning a return, $98.7 million of regulatory assets earning a return based on short-term interest rates, and $316.7 million of regulatory assets earning a return based on long-term interest rates. The regulatory assets not earning a return relate to certain environmental remediation costs, the recovery of which depends on the timing of the actual expenditures. The other regulatory assets in the table either earn a return or the cash has not yet been expended, in which case the regulatory assets are offset by liabilities.


⁽³⁾	Primarily represents the unrecognized future pension and OPEB costs related to our defined benefit pension and OPEB plans. We are authorized recovery of these regulatory assets over the average remaining service life of each plan.


⁽⁴⁾	For information on the flow through of tax repairs and the regulatory treatment of the impacts of the Tax Legislation, see Note 21, Regulatory Environment .


⁽⁵⁾	Represents amounts recoverable from customers related to our costs of the generating units leased from We Power, including subsequent capital additions. See Note 11, Long-Term Debt and Capital Lease Obligations , for information on the Tax Legislation impacts on the lease payments.

The following regulatory liabilities were reflected on our balance sheets as of December 31:



(in millions)	2018		2017		See Note
Regulatory liabilities
Income tax related items ⁽¹⁾	$	1,024.8	$	849.1	12
Removal costs ⁽²⁾	748.1		730.0
Mines deferral ⁽³⁾	120.8		95.1
Pension and OPEB costs ⁽⁴⁾	74.7		10.0		15
Uncollectible expense ⁽⁵⁾	16.4		6.4		1(d)
Energy efficiency programs ⁽⁶⁾	13.5		11.1
Other, net	15.9		19.4
Total regulatory liabilities	$	2,014.2	$	1,721.1

Balance Sheet Presentation
Current liabilities	$	11.9	$	13.1
Regulatory liabilities	2,002.3		1,708.0
Total regulatory liabilities	$	2,014.2	$	1,721.1



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⁽¹⁾	For information on the regulatory treatment of the impacts of the Tax Legislation, see Note 21, Regulatory Environment .


⁽²⁾	Represents amounts collected from customers to cover the future cost of property, plant, and equipment removals that are not legally required. Legal obligations related to the removal of property, plant, and equipment are recorded as AROs.


⁽³⁾	Represents the deferral of revenues less the associated cost of sales related to Tilden, which were not included in the PSCW's 2015 rate order. We intend to request that this deferral be applied for the benefit of Wisconsin retail electric customers in a future rate proceeding.


⁽⁴⁾	Primarily represents the unrecognized future pension and OPEB benefits related to our defined benefit pension and OPEB plans. We will amortize these regulatory liabilities into net periodic benefit cost over the average remaining service life of each plan.


⁽⁵⁾	Represents amounts refundable to customers related to our uncollectible expense tracking mechanism. This mechanism allows us to recover or refund the difference between actual uncollectible write-offs and the amounts recovered in rates.


⁽⁶⁾	Represents amounts refundable to customers related to programs designed to meet energy efficiency standards.

NOTE 6— PROPERTY, PLANT, AND EQUIPMENT

Property, plant, and equipment consisted of the following utility and non-utility and other assets at December 31:



(in millions)	2018		2017
Electric – generation	$	3,560.0	$	3,447.7
Electric – distribution	4,837.9		4,600.2
Natural gas – distribution, storage, and transmission	1,269.6		1,166.8
Property, plant, and equipment to be retired	174.8		872.7
Other	801.8		656.0
Less: Accumulated depreciation	3,239.4		2,970.3
Net	7,404.7		7,773.1
CWIP	124.7		159.5
Net utility property, plant, and equipment	7,529.4		7,932.6

Property under capital leases	3,043.5		3,009.1
Less: Accumulated amortization	1,055.6		945.9
Net leased facilities	1,987.9		2,063.2

Non-utility and other property, plant, and equipment	11.6		11.9

Total property, plant, and equipment	$	9,528.9	$	10,007.7

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 December 2017, a severance liability in the amount of $25.8 million was recorded in other current liabilities related to these plant retirements.



(in millions)
Severance liability at December 31, 2017	$	25.8
Severance payments	(9.9		)
Other	(3.0		)
Total severance liability at December 31, 2018	$	12.9

Pleasant Prairie Power Plant

The Pleasant Prairie power plant was retired effective April 10, 2018. The carrying value of this plant was $645.9 million at December 31, 2018 . This amount included the net book value of $749.5 million , which was classified as a regulatory asset on our balance sheet. In addition, a $103.6 million cost of removal reserve related to the Pleasant Prairie power plant was classified as a regulatory liability at December 31, 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



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the income statement. We have FERC approval to continue to collect the carrying value of the Pleasant Prairie power plant using the approved composite depreciation rates, in addition to a return on the remaining carrying value. However, this approval is subject to refund while the FERC completes its prudency review. We will address the accounting and regulatory treatment related to the retirement of Pleasant Prairie with the PSCW in conjunction with our anticipated 2019 rate case. 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 19, 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. Upon receiving this approval, retirement of the PIPP generating units became probable. Pursuant to MISO's April 2018 approval of the retirement of the plant, the PIPP units are required to be retired on or before May 31, 2019. The carrying value of the PIPP units was $174.8 million at December 31, 2018 . This amount included net book value of $185.4 million , which was classified as plant to be retired within property, plant, and equipment on our balance sheet. In addition, a $10.6 million cost of removal reserve related to the PIPP units was classified as a regulatory liability at December 31, 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. Upon retirement of PIPP, we will file with the FERC for approval to continue to collect the carrying value of the PIPP using the current approved composite depreciation rates, in addition to a return on the remaining carrying value. We will address the accounting and regulatory treatment related to the retirement of the PIPP with the PSCW in conjunction with our anticipated 2019 Wisconsin rate case, and also expect that the retirement will be addressed by the MPSC. See Note 21, Regulatory Environment, for more information .

NOTE 7— ASSET RETIREMENT OBLIGATIONS

We have recorded AROs primarily for asbestos abatement at certain generation and substation facilities, the removal and dismantlement of biomass and hydro generation facilities, and the closure of fly-ash landfills at our generation facilities. We establish regulatory assets and liabilities to record the differences between ongoing expense recognition under the ARO accounting rules and the rate-making practices for retirement costs authorized by the applicable regulators. On our balance sheets, AROs are recorded within other long-term liabilities.

The following table shows changes to our AROs during the years ended December 31:



(in millions)	2018			2017			2016
Balance as of January 1	$	68.3		$	61.5		$	58.7
Accretion	3.3			3.2			3.0
Additions and revisions to estimated cash flows	1.0			5.5			—
Liabilities settled	(1.9		)	(1.9		)	(0.2		)
Balance as of December 31	$	70.7		$	68.3		$	61.5

NOTE 8— COMMON EQUITY

Stock-Based Compensation Plans

The following table summarizes our pre-tax stock-based compensation expense and the related tax benefit recognized in income for the years ended December 31:



(in millions)	2018		2017		2016
Stock options	$	2.0	$	1.3	$	1.8
Restricted stock	3.0		0.8		1.8
Performance units	9.6		9.9		3.9
Stock-based compensation expense	$	14.6	$	12.0	$	7.5
Related tax benefit	$	4.0	$	4.8	$	3.0

Stock-based compensation costs capitalized during 2018 , 2017 , and 2016 were not significant.



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Stock Options

The following is a summary of our employees' WEC Energy Group stock option activity during 2018 :



Stock Options	Number of Options		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Life (in years)	Aggregate Intrinsic Value (in millions)
Outstanding as of January 1, 2018	1,196,147		$	37.29
Granted	81,730		$	66.02
Exercised	(340,563	)	$	29.45
Transferred	(238,500	)	$	39.71
Outstanding as of December 31, 2018	698,814		$	43.64	5.0	$	17.9
Exercisable as of December 31, 2018	538,764		$	39.30	4.1	$	16.1

The aggregate intrinsic value of outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they exercised all of their options on December 31, 2018 . This is calculated as the difference between WEC Energy Group's closing stock price on December 31, 2018 , and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the years ended December 31, 2018 , 2017 , and 2016 was $12.9 million , $11.2 million , and $14.1 million , respectively. Cash received by WEC Energy Group from exercises of its options by our employees was $10.0 million , $7.7 million , and $12.1 million during the years ended December 31, 2018 , 2017 , and 2016 , respectively. The actual tax benefit from option exercises for the same periods was approximately $2.7 million , $4.5 million , and $5.6 million , respectively.

As of December 31, 2018 , we expected to recognize approximately $1.0 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group stock options over the next 1.7 years on a weighted-average basis.

During the first quarter of 2019 , the Compensation Committee awarded 59,404 non-qualified WEC Energy Group stock options with an exercise price of $68.18 and a weighted-average grant date fair value of $8.60 per option to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

Restricted Shares

The following is a summary of our employees' WEC Energy Group restricted stock activity during 2018 :



Restricted Shares	Number of Shares		Weighted-Average Grant Date Fair Value
Outstanding and unvested as of January 1, 2018	15,283		$	54.96
Granted	7,518		$	64.99
Released	(5,380	)	$	54.58
Transferred	(5,823	)	$	57.17
Forfeited	(1,747	)	$	60.50
Outstanding and unvested as of December 31, 2018	9,851		$	60.53

The intrinsic value of WEC Energy Group restricted stock held by our employees that was released was $0.4 million , $0.5 million , and $0.4 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively. The actual tax benefit from released restricted shares for the same years was $0.1 million , $0.2 million , and $0.2 million , respectively.

As of December 31, 2018 , we expected to recognize approximately $1.3 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group restricted stock over the next 1.6 years on a weighted-average basis.

During the first quarter of 2019 , the Compensation Committee awarded 5,181 WEC Energy Group restricted shares to our officers and other key employees under its normal schedule of awarding long-term incentive compensation. The grant date fair value of these awards was $68.18 per share.



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Performance Units

During 2018 , 2017 , and 2016 , the Compensation Committee awarded 32,650 ; 34,765 ; and 35,700 WEC Energy Group performance units, respectively, to our officers and other key employees under the WEC Energy Group Performance Unit Plan.

Performance units with an intrinsic value of $2.0 million , $1.4 million , and $3.4 million were settled during 2018 , 2017 , and 2016 , respectively. The actual tax benefit from the distribution of performance units for the same years was approximately $0.4 million , $0.4 million , and $0.5 million , respectively.

At December 31, 2018 , our employees held 68,583 of outstanding WEC Energy Group performance units, including dividend equivalents. A liability of $4.3 million was recorded on our balance sheet at December 31, 2018 related to these outstanding units. As of December 31, 2018 , we expected to recognize approximately $8.6 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group performance units over the next 1.3 years on a weighted-average basis.

During the first quarter of 2019 , performance units held by our employees with an intrinsic value of $2.2 million were settled. The actual tax benefit from the distribution of these awards was $0.5 million . In January 2019 , the Compensation Committee also awarded 22,452 WEC Energy Group performance units to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

Restrictions

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.

In accordance with our most recent rate order, we may not pay common dividends above the test year forecasted amount reflected in our rate case, if it would cause our average common equity ratio, on a financial basis, to fall below our authorized level of 51% . A return of capital in excess of the test year amount can be paid by us at the end of the year provided that our average common equity ratio does not fall below the authorized level.

We may not pay common dividends to WEC Energy Group under our Restated Articles of Incorporation if any dividends on our outstanding preferred stock have not been paid. In addition, pursuant to the terms of our 3.60% Serial Preferred Stock, our ability to declare common dividends would be limited to 75% or 50% of net income during a twelve month period if our common stock equity to total capitalization, as defined in the preferred stock designation, is less than 25% and 20% , respectively.

See Note 10, Short-Term Debt and Lines of Credit , for discussion of certain financial covenants related to short-term debt obligations.

As of December 31, 2018 , our restricted retained earnings totaled $2.2 billion .

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

NOTE 9— PREFERRED STOCK

The following table shows preferred stock authorized and outstanding at December 31, 2018 and 2017 :



(in millions, except share and per share amounts)	Shares Authorized	Shares Outstanding	Redemption Price Per Share		Total
$100 par value, Six Per Cent. Preferred Stock	45,000	44,498	—		$	4.4
$100 par value, Serial Preferred Stock	2,286,500
3.60% Series		260,000	$	101	26.0
$25 par value, Serial Preferred Stock	5,000,000	—	—		—
Total					$	30.4



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NOTE 10— SHORT-TERM DEBT AND LINES OF CREDIT

The following table shows our short-term borrowings and their corresponding weighted-average interest rates as of December 31:



(in millions, except percentages)	2018			2017
Commercial paper
Amount outstanding at December 31	$	134.9		$	210.9
Average interest rate on amounts outstanding at December 31	2.96		%	1.81		%

Our average amount of commercial paper borrowings based on daily outstanding balances during 2018 was $132.6 million , with a weighted-average interest rate during the period of 2.26% .

We have entered into a bank back-up credit facility to maintain short-term credit liquidity which, among other terms, requires us to maintain, subject to certain exclusions, a total funded debt to capitalization ratio of 65% or less. As of December 31, 2018 , we were in compliance with this ratio.

The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including remaining available capacity under this facility as of December 31 :



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

Less:
Letters of credit issued inside credit facility		$	1.2
Commercial paper outstanding		134.9

Available capacity under existing agreement		$	363.9

This facility has a renewal provision for two one -year extensions, subject to lender approval.

Our bank back-up credit facility contains customary covenants, including certain limitations on our ability to sell assets. The credit facility also contains customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, Employee Retirement Income Security Act of 1974 defaults and change of control.

NOTE 11— LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS

See our statements of capitalization for details on our long-term debt.

Debentures and Notes

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.



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The following table shows the future maturities of our long-term debt outstanding (excluding obligations under capital leases) as of December 31, 2018 :



(in millions)
2019	$	250.0
2020	—
2021	300.0
2022	—
2023	—
Thereafter	2,185.0
Total	$	2,735.0

We amortize debt premiums, discounts, and debt issuance costs over the life of the debt and we include the costs in interest expense.

Obligations Under Capital Leases

We are the obligor under a power purchase contract with an unaffiliated third party and we lease power plants from We Power. Under capital lease accounting, we have recorded the leased plants and corresponding obligations under the capital leases on our balance sheets. We treat these agreements as operating leases for rate-making purposes. We record our minimum lease payments under the power purchase contract as purchased power expense on our income statements. We record the lease payments under our leases with We Power as rent expense in other operation and maintenance in our income statements. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under capital lease accounting as a deferred regulatory asset on our balance sheets. See Note 5, Regulatory Assets and Liabilities, for more information on our plant related capital leases.

Power Purchase Commitment

In 1997, we entered into a 25 -year power purchase contract with an unaffiliated independent power producer. The contract, for 236 MW of firm capacity from a natural gas-fired cogeneration facility, includes zero minimum energy requirements. When the contract expires in 2022 , we may, at our option and with proper notice, renew for another 10 years or purchase the generating facility at fair market value or allow the contract to expire. We account for this contract as a capital lease and recorded the leased facility and corresponding obligation under the capital lease at the estimated fair value of the plant's electric generating facilities. We are amortizing the leased facility on a straight-line basis over the original 25 -year term of the contract.

We treat the long-term power purchase contract as an operating lease for rate-making purposes and we record our minimum lease payments as cost of sales on our income statements. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under capital lease accounting as a deferred regulatory asset on our balance sheets. Due to the timing and the amounts of the minimum lease payments, the regulatory asset increased to approximately

$78.5 million during 2009, at which time the regulatory asset began to be reduced to zero over the remaining life of the contract. The total obligation under the capital lease was $23.3 million as of December 31, 2018 , and will decrease to zero over the remaining life of the contract.

Port Washington Generating Station

We are leasing PWGS 1 and PWGS 2, two 545 MW natural gas-fired generation units which were placed in service in July 2005 and May 2008, respectively, from We Power under PSCW approved leases. The leased units and corresponding obligations for the units have been recorded at the estimated fair value of $736.9 million . We are amortizing the leased units on a straight-line basis over the original 25 -year term of the leases. The lease payments are expected to be recovered through our rates, as supported by the 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $129.2 million in the year 2021 for PWGS 1 and to approximately $125.9 million in the year 2023 for PWGS 2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the capital leases for the units was $634.5 million as of December 31, 2018 , and will decrease to zero over the remaining lives of the contracts.



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When the PWGS 1 and PWGS 2 contracts expire in 2030 and 2033, respectively, we may, at our option and with proper notice, choose to renew one or both contracts for up to three consecutive renewal terms (each renewal term would approximate 80% of the then remaining economic useful life of the respective generation unit), purchase one or both generating facilities at fair market value, or allow the contracts to expire.

Elm Road Generating Station

We are leasing ER 1, ER 2, and the common facilities, which are also utilized by our OC 5 through OC 8, from We Power under PSCW approved leases. We are amortizing the leased units on a straight-line basis over the 30 -year term of the leases. ER 1 and ER 2 were placed in service in February 2010 and January 2011, respectively. The leased units and corresponding capital lease obligations have been recorded at the estimated fair value of $2,166.3 million . The lease payments are expected to be recovered through our rates, as supported by the 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $521.8 million in the year 2028 for ER 1 and to approximately $427.9 million in the year 2029 for ER 2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the capital leases was $2,199.3 million as of December 31, 2018 , and will decrease to zero over the remaining lives of the contracts.

When the ER 1 and ER 2 contracts expire in 2040 and 2041, respectively, we may, at our option and with proper notice, choose to renew one or both contracts for up to three consecutive renewal terms (each renewal term would approximate 80% of the then remaining economic useful life of the respective generation unit), purchase one or both generating facilities at fair market value, or allow the contracts to expire.

We paid the following lease payments during 2018, 2017, and 2016:



(in millions)	2018		2017		2016
Long-term power purchase commitment	$	7.7	$	7.2	$	37.6
PWGS	76.6		85.0		82.4
ERGS	297.1		335.5		329.8
Total	$	381.4	$	427.7	$	449.8

The rates charged to our customers related to the We Power leases have remained level for each of the three years ended December 31, 2018, 2017, and 2016, at $398.6 million . Because this is also the amount that was charged to operating and maintenance expense during these years, the lease payments made to We Power over this three-year period did not match the amounts we recorded as lease expense. As disclosed in the table above, lease payments related to the PWGS and ERGS leases were $373.7 million , $420.5 million , and $412.2 million in 2018, 2017, and 2016, respectively. As a result of the Tax Legislation, the lease payments were recalculated and decreased by approximately $50 million in 2018, resulting in lower lease payments when compared to lease expense recorded in 2018. Partially offsetting the lower lease payments made in 2018, and also the driving factor behind the higher lease payments in 2017 and 2016, compared to lease expense, were capital additions placed in service or that are in process since our last rate case. These capital additions are factored into our bill from We Power, but have not yet been factored into the rates we are collecting from customers. The difference between the payments we have made to We Power and the amounts collected in rates and recorded as lease expense is not expected to impact earnings as we are allowed to record the difference as an increase or reduction to the We Power generation regulatory asset until our next rate case. See Note 5, Regulatory Assets and Liabilities , for more information on the regulatory asset related to the We Power leases, and also Note 12, Income Taxes , and Note 21, Regulatory Environment , for more information on the Tax Legislation and our rates.



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The following table summarizes our capitalized leased facilities as of December 31:



(in millions)	2018			2017
Long-term power purchase commitment
Under capital lease	$	140.3		$	140.3
Accumulated amortization	(120.9		)	(115.2		)
Total long-term power purchase commitment	19.4			25.1

PWGS
Under capital lease	736.9			727.4
Accumulated amortization	(335.9		)	(305.1		)
Total PWGS	401.0			422.3

ERGS
Under capital lease	2,166.3			2,141.4
Accumulated amortization	(598.8		)	(525.6		)
Total ERGS	1,567.5			1,615.8

Total leased facilities	$	1,987.9		$	2,063.2

Future minimum lease payments under our capital leases and the present value of our net minimum lease payments as of December 31, 2018 are as follows:



(in millions)	Power Purchase Commitment			PWGS			ERGS			Total
2019	$	15.5		$	97.6		$	290.8		$	403.9
2020	16.4			97.6			290.8			404.8
2021	17.2			97.6			290.8			405.6
2022	7.6			97.6			290.6			395.8
2023	—			97.6			290.5			388.1
Thereafter	—			773.5			4,792.8			5,566.3
Total minimum lease payments	56.7			1,261.5			6,246.3			7,564.5
Less: Estimated executory costs	(26.1		)	—			—			(26.1		)
Net minimum lease payments	30.6			1,261.5			6,246.3			7,538.4
Less: Interest	(7.3		)	(627.0		)	(4,047.0		)	(4,681.3		)
Present value of minimum lease payments	23.3			634.5			2,199.3			2,857.1
Less: Due currently	(4.9		)	(22.3		)	(22.7		)	(49.9		)
Long-term obligations under capital lease	$	18.4		$	612.2		$	2,176.6		$	2,807.2

NOTE 12— INCOME TAXES

Income Tax Expense

The following table is a summary of income tax expense for each of the years ended December 31:



(in millions)	2018			2017			2016
Current tax (benefit) expense	$	(56.2	)	$	81.5		$	4.8
Deferred income taxes, net	0.1			110.6			207.3
Investment tax credit, net	(0.8		)	(0.9		)	(1.1		)
Total income tax (benefit) expense	$	(56.9	)	$	191.2		$	211.0



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Statutory Rate Reconciliation

The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following:



	2018					2017					2016
(in millions)	Amount			Effective Tax Rate		Amount			Effective Tax Rate		Amount			Effective Tax Rate
Expected tax at statutory federal tax rates	$	63.3		21.0	%	$	184.4		35.0	%	$	201.4		35.0	%
State income taxes net of federal tax benefit	19.6			6.5	%	27.9			5.3	%	31.8			5.5	%
Tax repairs *	(120.7		)	(39.9	)%	—			—	%	—			—	%
Federal excess amortization	(15.5		)	(5.1	)%	—			—	%	—			—	%
Production tax credits	(9.4		)	(3.1	)%	(17.6		)	(3.3	)%	(16.5		)	(2.8	)%
Investment tax credit restored	(0.8		)	(0.3	)%	(0.9		)	(0.2	)%	(1.1		)	(0.2	)%
AFUDC – Equity	(0.8		)	(0.3	)%	(1.1		)	(0.2	)%	(1.5		)	(0.3	)%
Domestic production activities deferral (deduction)	6.1			2.0	%	(7.8		)	(1.5	)%	(7.8		)	(1.4	)%
Other, net	1.3			0.4	%	6.3			1.1	%	4.7			0.8	%
Total income tax (benefit) expense	$	(56.9	)	(18.8	)%	$	191.2		36.2	%	$	211.0		36.6	%

In accordance with a settlement agreement with the PSCW, 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. 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. See Note 21, Regulatory Environment, for more information about the impact of the Tax Legislation and the Wisconsin rate settlement.

Deferred Income Tax Assets and Liabilities

On December 22, 2017, the Tax Legislation was signed into law. For businesses, the Tax Legislation reduced the corporate federal tax rate from a maximum of 35% to a 21% rate effective January 1, 2018. In December 2017, we recorded a tax benefit related to the re-measurement of our deferred taxes in the amount of approximately $1,065 million . Accordingly, this amount was recorded as both an increase to regulatory liabilities as well as a decrease to certain existing regulatory assets as of December 31, 2017.

On December 22, 2017, the SEC staff issued guidance in Staff Accounting Bulletin 118 (SAB 118), Income Tax Accounting Implications of the Tax Cuts and Jobs Act, which provided 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 were considered "provisional" and subject to revision at December 31, 2017, and through 2018, as discussed in SAB 118.

In 2018, we considered all available guidance from industry and income tax authorities related to these tax items, analyzed the impact on Alternative Minimum Tax Credit carryforwards, and revised our estimates for re-measurement of deferred income taxes related to guidance on bonus depreciation. At December 31, 2018, we no longer considered any amounts related to bonus depreciation and future tax benefit utilization "provisional." However, any further amendments or technical corrections to the Tax Legislation could subject these tax items to revision.



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The components of deferred income taxes as of December 31 were as follows:



(in millions)	2018		2017
Deferred tax assets
Tax gross up – regulatory items	$	203.0	$	240.1
Deferred revenues	129.3		128.8
Future tax benefits	15.9		133.1
Employee benefits and compensation	—		50.2
Other	156.6		82.4
Total deferred tax assets	$	504.8	$	634.6

Deferred tax liabilities
Property-related	$	1,365.9	$	1,487.0
Deferred costs – Pleasant Prairie	176.0		—
Deferred costs – SSR	110.7		81.4
Employee benefits and compensation	55.9		117.4
Deferred transmission costs	55.4		60.1
Other	39.2		44.2
Total deferred tax liabilities	1,803.1		1,790.1
Deferred tax liability, net	$	1,298.3	$	1,155.5

Consistent with rate-making treatment, deferred taxes in the table above are offset for temporary differences that have related regulatory assets and liabilities.

At December 31, 2018, we had $11.6 million of tax credit carryforwards resulting in deferred tax assets of $11.6 million . Tax credit carryforwards begin to expire in 2038. We expect to have future taxable income sufficient to utilize these deferred tax assets. At December 31, 2017, we had $4.0 million and $125.6 million of federal charitable contribution and tax credit carryforwards resulting in deferred tax assets of $0.8 million and $125.6 million , respectively. At December 31, 2018, we had $68.7 million of state net operating losses resulting in deferred tax assets of $4.3 million . These state net operating loss carryforwards begin to expire in 2035. We expect to have future taxable income sufficient to utilize these deferred tax assets. At December 31, 2017, we had $74.7 million and $31.9 million of state net operating loss and state charitable contribution carryforwards resulting in deferred tax assets of $4.7 million and $2.0 million , respectively.

Unrecognized Tax Benefits

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:



(in millions)	2018		2017
Balance as of January 1	$	—	$	5.1
Reductions for tax positions of prior years	—		(5.1		)
Balance as of December 31	$	—	$	—

We do not expect any unrecognized tax benefits to affect our effective tax rate in periods after December 31, 2018.

For the years ended December 31, 2018, 2017, and 2016, we recognized no interest, $0.7 million of interest income, and $0.2 million of interest expense, respectively, related to unrecognized tax benefits in our income statements. For the years ended December 31, 2018, 2017, and 2016, we recognized no penalties related to unrecognized tax benefits in our income statements. For the years ended December 31, 2018 and 2017, we had no interest accrued and no penalties accrued related to unrecognized tax benefits on our balance sheets.

We do not anticipate any significant increases in the total amount of unrecognized tax benefits within the next 12 months.

Our primary tax jurisdictions include Federal and the state of Wisconsin. With a few exceptions we are no longer subject to Federal income tax examinations by the IRS for years prior to 2015. As of December 31, 2018, we were subject to examination by the Wisconsin taxing authority for tax years 2014 through 2018.



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NOTE 13— FAIR VALUE MEASUREMENTS

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:



	December 31, 2018
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	0.7	$	—	$	—	$	0.7
FTRs	—		—		4.4		4.4
Total derivative assets	$	0.7	$	—	$	4.4	$	5.1

Derivative liabilities
Natural gas contracts	$	1.2	$	—	$	—	$	1.2
Coal contracts	—		0.1		—		0.1
Total derivative liabilities	$	1.2	$	0.1	$	—	$	1.3



	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:



(in millions)	2018			2017			2016
Balance at the beginning of the period	$	2.4		$	3.1		$	1.6
Purchases	9.4			6.9			8.1
Settlements	(7.4		)	(7.6		)	(6.6		)
Balance at the end of the period	$	4.4		$	2.4		$	3.1

Fair Value of Financial Instruments

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



	December 31, 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	2,709.6		2,881.6		2,662.3		2,976.3

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



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NOTE 14— DERIVATIVE INSTRUMENTS

The following table shows our derivative assets and derivative liabilities, none of which are designated as hedging instruments.



	December 31, 2018				December 31, 2017
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	0.7	$	1.2	$	0.6	$	1.9
Petroleum products contracts	—		—		0.9		—
FTRs	4.4		—		2.4		—
Coal contracts	—		0.1		0.6		0.1
Total other current	$	5.1	$	1.3	$	4.5	$	2.0

Other long-term
Natural gas contracts	$	—	$	—	$	—	$	0.2
Coal contracts	—		—		0.1		0.2
Total other long-term	$	—	$	—	$	0.1	$	0.4
Total	$	5.1	$	1.3	$	4.6	$	2.4

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



	December 31, 2018			December 31, 2017				December 31, 2016
(in millions)	Volume	Gains		Volume	Gains (Losses)			Volume	Gains (Losses)
Natural gas contracts	53.4 Dth	$	9.7	26.9 Dth	$	(1.0	)	35.3 Dth	$	(12.3	)
Petroleum products contracts	4.2 gallons	1.2		16.7 gallons	(1.4		)	10.3 gallons	(2.6		)
FTRs	21.2 MWh	3.4		27.1 MWh	7.6			25.3 MWh	7.3
Total		$	14.3		$	5.2			$	(7.6	)

At December 31, 2018 and 2017 , we had posted cash collateral of $1.1 million and $4.9 million , respectively, in our margin accounts.

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



	December 31, 2018							December 31, 2017
(in millions)	Derivative Assets			Derivative Liabilities				Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	5.1		$	1.3			$	4.6		$	2.4
Gross amount not offset on the balance sheet	(0.6		)	(1.3		)	*	(1.3		)	(2.0		)	*
Net amount	$	4.5		$	—			$	3.3		$	0.4


*	Includes cash collateral posted of $0.7 million at both December 31, 2018 and 2017 .

NOTE 15— EMPLOYEE BENEFITS

Pension and Other Postretirement Employee Benefits

We participate in WEC Energy Group's defined benefit pension plans and OPEB plans that cover substantially all of our employees. We are responsible for our share of the plan assets and obligations. The benefits for a portion of these plans are funded through irrevocable trusts, as allowed for income tax purposes. Our balance sheets reflect only the liabilities associated with our past and current employees and our share of the plan assets and obligations. We also offer medical, dental, and life insurance benefits to active employees and their dependents. We expense the costs of these benefits as incurred.

Generally, employees who started with us after 1995 receive a benefit based on a percentage of their annual salary plus an interest credit, while employees who started before 1996 receive a benefit based upon years of service and final average salary. New



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management employees hired after December 31, 2014, and certain new represented employees hired after May 1, 2017, receive an annual company contribution to their 401(k) savings plan instead of being enrolled in the defined benefit plans.

We use a year-end measurement date to measure the funded status of all of the pension and OPEB plans. Due to the regulated nature of our business, we have concluded that substantially all of the unrecognized costs resulting from the recognition of the funded status of the pension and OPEB plans qualify as a regulatory asset.

The following tables provide a reconciliation of the changes in our share of the plans' benefit obligations and fair value of assets:



	Pension Costs								OPEB Costs
(in millions)	2018				2017				2018				2017
Change in benefit obligation
Obligation at January 1	$	1,193.9			$	1,177.0			$	303.5			$	298.5
Service cost	13.2				12.2				6.9				7.0
Interest cost	42.3				47.0				11.1				12.1
Participant contributions	—				—				7.6				5.7
Plan amendments	—				—				—				(6.8		)
Net transfer to/from affiliates	(4.5		)	⁽¹⁾	(13.4		)	⁽²⁾	—				(3.3		)	⁽²⁾
Actuarial loss (gain)	(62.7		)		53.1				(86.2		)		5.1
Benefit payments	(82.8		)		(82.0		)		(22.8		)		(16.5		)
Federal subsidy on benefits paid	N/A				N/A				0.9				1.7
Transfer	—				—				6.7			⁽³⁾	—
Obligation at December 31	$	1,099.4			$	1,193.9			$	227.7			$	303.5

Change in fair value of plan assets
Fair value at January 1	$	1,134.1			$	1,102.8			$	220.1			$	205.1
Actual return on plan assets	(31.0		)		121.9				(5.7		)		25.9
Employer contributions	4.0				5.1				2.3				3.2
Participant contributions	—				—				7.6				5.7
Net transfer to/from affiliates	(4.5		)	⁽¹⁾	(13.7		)	⁽²⁾	—				(3.3		)	⁽²⁾
Benefit payments	(82.8		)		(82.0		)		(22.8		)		(16.5		)
Fair value at December 31	$	1,019.8			$	1,134.1			$	201.5			$	220.1
Funded status at December 31	$	(79.6	)		$	(59.8	)		$	(26.2	)		$	(83.4	)


⁽¹⁾	Benefit obligations and plan assets were moved along with our employees who were transferred to/from affiliated entities. See Note 3, Related Parties, for more information .


⁽²⁾	Benefit obligations and plan assets were moved along with our employees who were transferred to/from affiliated entities, primarily a result of our customer service employees being transferred to WBS.


⁽³⁾	Represents a premium medical account that was transferred into the OPEB benefit obligation.

The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows:



	Pension Costs						OPEB Costs
(in millions)	2018			2017			2018			2017
Other long-term assets	$	12.7		$	—		$	—		$	—
Pension and OPEB obligations	92.3			59.8			26.2			83.4
Total net liabilities	$	(79.6	)	$	(59.8	)	$	(26.2	)	$	(83.4	)

The accumulated benefit obligation for all defined benefit pension plans was $1,097.9 million and $1,192.4 million as of December 31, 2018 and 2017 , respectively.



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The following table shows information for the pension plans for which we have an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31:



(in millions)	2018		2017
Projected benefit obligation	$	997.0	$	1,193.9
Accumulated benefit obligation	995.5		1,192.4
Fair value of plan assets	904.7		1,134.1

The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31:



	Pension Costs						OPEB Costs
(in millions)	2018			2017			2018			2017
Net regulatory assets (liabilities)
Net actuarial loss (gain)	$	491.0		$	485.4		$	(66.6	)	$	(1.6	)
Prior service credits	(1.8		)	(1.0		)	(6.1		)	(8.4		)
Total	$	489.2		$	484.4		$	(72.7	)	$	(10.0	)

The following table shows the estimated amounts that will be amortized into net periodic benefit cost during 2019 :



(in millions)	Pension Costs		OPEB Costs
Net actuarial loss (gain)	$	28.7	$	(1.6	)
Prior service costs (credits)	0.4		(1.9		)
Total 2019 – estimated amortization	$	29.1	$	(3.5	)

The components of net periodic benefit cost (including amounts capitalized to our balance sheets) for the years ended December 31 were as follows:



	Pension Costs									OPEB Costs
(in millions)	2018			2017			2016			2018			2017			2016
Service cost	$	13.2		$	12.2		$	10.5		$	6.9		$	7.0		$	7.3
Interest cost	42.3			47.0			49.7			11.1			12.1			13.2
Expected return on plan assets	(75.2		)	(76.6		)	(77.7		)	(15.5		)	(14.7		)	(14.0		)
Plan settlement	—			4.1			—			—			—			—
Amortization of prior service cost (credit)	0.8			1.1			1.6			(2.2		)	(1.4		)	(1.1		)
Amortization of net actuarial loss	38.0			35.4			32.4			—			—			1.0
Net periodic benefit cost	$	19.1		$	23.2		$	16.5		$	0.3		$	3.0		$	6.4

Effective January 1, 2018, we adopted ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, which modifies certain aspects of the accounting for employee benefit costs. Under the new guidance, only the service cost component can be included in total operating expenses. The remaining components of net periodic benefit cost are required to be presented in the income statement separately from the service cost component, outside of operating income. As required, this change was applied retrospectively to all prior periods presented. Accordingly, for the years ended December 31, 2018 , 2017 , and 2016 , we have presented the service cost component of our retirement benefit plans in other operation and maintenance on the income statements, while presenting the non-service cost components in other income, net.



2018 Form 10-K	82	Wisconsin Electric Power Company

Table of Contents

As required by ASU 2017-07, our income statements for the years ended December 31, 2017 and 2016, were retroactively restated from what was previously presented in our 2017 Annual Report on Form 10-K. The impacts to our income statements from adoption of this standard are reflected in the table below.



	Year Ended December 31, 2017							Year Ended December 31, 2016
(in millions)	Form 10-K Income Statement		Impact of ASU 2017-07			Income Statement After Adoption		Form 10-K Income Statement		Impact of ASU 2017-07			Income Statement After Adoption
Operating expenses
Other operation and maintenance	$	1,358.5	$	(6.5	)	$	1,352.0	$	1,430.2	$	(4.7	)	$	1,425.5

Other expense
Other income, net	19.7		(6.5		)	13.2		9.1		(4.7		)	4.4

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

The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31:



	Pension		OPEB
	2018	2017	2018	2017
Discount rate	4.30%	3.65%	4.30%	3.65%
Rate of compensation increase	3.40%	3.20%	N/A	N/A
Assumed medical cost trend rate (Pre 65)	N/A	N/A	6.25%	6.50%
Ultimate trend rate (Pre 65)	N/A	N/A	5.00%	5.00%
Year ultimate trend rate is reached (Pre 65)	N/A	N/A	2024	2024
Assumed medical cost trend rate (Post 65)	N/A	N/A	6.12%	6.18%
Ultimate trend rate (Post 65)	N/A	N/A	5.00%	5.00%
Year ultimate trend rate is reached (Post 65)	N/A	N/A	2028	2028

The weighted-average assumptions used to determine the net periodic benefit cost for the plans were as follows for the years ended December 31:



	Pension Costs
	2018	2017	2016
Discount rate	3.65%	4.12%	4.45%
Expected return on plan assets	7.00%	7.00%	7.00%
Rate of compensation increase	3.40%	3.20%	3.50%



	OPEB Costs
	2018	2017	2016
Discount rate	3.65%	4.10%	4.45%
Expected return on plan assets	7.25%	7.25%	7.25%
Assumed medical cost trend rate (Pre 65)	6.50%	7.00%	7.50%
Ultimate trend rate (Pre 65)	5.00%	5.00%	5.00%
Year ultimate trend rate is reached (Pre 65)	2024	2021	2021
Assumed medical cost trend rate (Post 65)	6.18%	7.00%	7.50%
Ultimate trend rate (Post 65)	5.00%	5.00%	5.00%
Year ultimate trend rate is reached (Post 65)	2028	2021	2021



2018 Form 10-K	83	Wisconsin Electric Power Company

Table of Contents

WEC Energy Group consults with its investment advisors on an annual basis to help forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund. For 2019 , the expected return on asset assumption is 7.00% for the pension plan and 7.25% for the OPEB plan.

Assumed health care cost trend rates have a significant effect on the amounts reported by us for the health care plans. For the year ended December 31, 2018 , a one-percentage-point change in assumed health care cost trend rates would have had the following effects:



(in millions)	1% Increase		1% Decrease
Effect on total of service and interest cost components of net periodic postretirement health care benefit cost	$	2.8	$	(2.2	)
Effect on the health care component of the accumulated postretirement benefit obligation	16.8		(14.0		)

Plan Assets

Current pension trust assets and amounts which are expected to be contributed to the trusts in the future are expected to be adequate to meet pension payment obligations to current and future retirees.

The Investment Trust Policy Committee oversees investment matters related to all of our funded benefit plans. The Committee works with external actuaries and investment consultants on an on-going basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. They are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments.

Our pension trust target asset allocation is 35% equity investments, 55% fixed income investments, and 10% private equity and real estate investments. The two OPEB trusts' target asset allocations are 50% equity investments and 50% fixed income investments, and 70% equity investments and 30% fixed income investments, respectively. Equity securities include investments in large-cap, mid-cap, and small-cap companies. Fixed income securities include corporate bonds of companies from diversified industries, mortgage and other asset backed securities, commercial paper, and United States Treasuries.

Pension and OPEB plan investments are recorded at fair value. See Note 1(m), Fair Value Measurements, for more information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used.

The following tables summarize the fair values of our investments by asset class:



	December 31, 2018
	Pension Plan Assets								OPEB Assets
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Asset Class
Equity securities:
Unites States Equity	$	89.0	$	—	$	—	$	89.0	$	24.6	$	—	$	—	$	24.6
International Equity	85.8		—		—		85.8		24.0		—		—		24.0
Fixed income securities: *
United States Bonds	66.2		436.5		—		502.7		24.0		48.2		—		72.2
International Bonds	8.3		31.4		—		39.7		1.6		3.0		—		4.6
	$	249.3	$	467.9	$	—	$	717.2	$	74.2	$	51.2	$	—	$	125.4
Investments measured at net asset value							$	302.6							$	76.1
Total	$	249.3	$	467.9	$	—	$	1,019.8	$	74.2	$	51.2	$	—	$	201.5


*	This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries.



2018 Form 10-K	84	Wisconsin Electric Power Company

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	December 31, 2017
	Pension Plan Assets								OPEB Assets
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Asset Class
Cash and cash equivalents	$	—	$	6.6	$	—	$	6.6	$	2.1	$	0.5	$	—	$	2.6
Equity securities:
United States equity	109.4		0.1		—		109.5		29.0		—		—		29.0
International equity	114.4		—		—		114.4		32.2		—		—		32.2
Fixed income securities: *
United States bonds	75.9		467.8		—		543.7		24.4		46.3		—		70.7
International bonds	9.7		32.8		—		42.5		1.7		2.9		—		4.6
Private Equity and Real Estate	—		20.6		55.3		75.9		—		1.4		3.8		5.2
	$	309.4	$	527.9	$	55.3	$	892.6	$	89.4	$	51.1	$	3.8	$	144.3
Investments measured at net asset value							$	241.5							$	75.8
Total	$	309.4	$	527.9	$	55.3	$	1,134.1	$	89.4	$	51.1	$	3.8	$	220.1


*	This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries.

The following tables set forth a reconciliation of changes in the fair value of pension and OPEB plan assets categorized as Level 3 in the fair value hierarchy:



	Private Equity and Real Estate
(in millions)	Pension			OPEB
Beginning balance at January 1, 2018	$	55.3		$	3.8
Realized and unrealized gains	4.1			0.8
Purchases	9.8			0.7
Liquidations	(1.2		)	(0.1		)
Transfers out of level 3	(68.0		)	(5.2		)
Ending balance at December 31, 2018	$	—		$	—



	Private Equity and Real Estate
(in millions)	Pension		OPEB
Beginning balance at January 1, 2017	$	11.0	$	0.7
Realized and unrealized gains	1.9		0.2
Purchases	22.3		1.5
Transfers into level 3	20.1		1.4
Ending balance at December 31, 2017	$	55.3	$	3.8

Cash Flows

We expect to contribute $3.8 million to the pension plans and $0.1 million to the OPEB plans in 2019 , dependent upon various factors affecting us, including our liquidity position and the effects of the new Tax Legislation.

The following table shows the payments, reflecting expected future service, that we expect to make for pension and OPEB:



(in millions)	Pension Costs		OPEB Costs
2019	$	91.8	$	11.5
2020	91.7		12.7
2021	86.7		13.3
2022	84.5		13.7
2023	81.7		14.0
2024-2028	360.5		70.2



2018 Form 10-K	85	Wisconsin Electric Power Company

Table of Contents

Savings Plans

WEC Energy Group sponsors 401(k) savings plans that allow substantially all of our full-time employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. A percentage of employee contributions are matched by us through a contribution into the employee's savings plan account, up to certain limits. The 401(k) savings plans include an Employee Stock Ownership Plan. Certain employees receive an employer retirement contribution, which amounts are contributed to an employee's savings plan account. Total costs incurred under all of these plans were $11.9 million in 2018 , $11.7 million in 2017 , and $10.4 million in 2016 .

NOTE 16— INVESTMENT IN AMERICAN TRANSMISSION COMPANY

At December 31, 2016, we owned approximately 23% of ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects. Effective January 1, 2017, based upon input we received from the PSCW, we transferred our investment in ATC to another subsidiary of WEC Energy Group. This transaction was a non-cash equity transfer between entities under common control, and therefore, did not result in the recognition of a gain or loss. The following table provides a reconciliation of our investment in ATC during the years ended December 31:



(in millions)	2017		2016
Balance at January 1	$	402.0	$	382.2
Less: Transfer of ownership interest	402.0		—
Add: Earnings from equity method investment	—		55.5
Add: Capital contributions	—		16.1
Less: Distributions	—		51.7		*
Less: Other	—		0.1
Balance at December 31	$	—	$	402.0


*	Of this amount, $13.4 million was recorded as a receivable from ATC at December 31, 2016.

See Note 3, Related Parties, for more information on transactions with ATC.

NOTE 17— SEGMENT INFORMATION

We use operating income to measure segment profitability and to allocate resources to our businesses. At December 31, 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. Effective January 1, 2017, we transferred all of our electric distribution assets and customers located in the Upper Peninsula of Michigan to UMERC, with the exception of Tilden. See Note 3, Related Parties , and Note 21, Regulatory Environment , for additional information. 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, Dispositions, for more information . Prior to January 1, 2017, our other segment also included our approximate 23% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 16, Investment in American Transmission Company, for more information .



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All of our operations and assets are located within the United States. The following tables show summarized financial information related to our reportable segments for the years ended December 31, 2018 , 2017 , and 2016 .



2018 (in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Operating revenues	$	3,625.0	$	—	$	3,625.0
Other operation and maintenance	1,502.4		—		1,502.4
Depreciation and amortization	348.1		—		348.1
Operating income	402.5		—		402.5
Interest expense	120.1		—		120.1
Capital expenditures	603.2		—		603.2
Total assets	13,538.3		—		13,538.3



2017 (in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Operating revenues	$	3,711.7	$	—	$	3,711.7
Other operation and maintenance *	1,352.0		—		1,352.0
Depreciation and amortization	331.6		—		331.6
Operating income *	632.1		—		632.1
Interest expense	117.0		0.3		117.3
Capital expenditures	596.1		—		596.1
Total assets	13,121.6		—		13,121.6


*	Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 15, Employee Benefits, for more information on this new standard.



2016 (in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Operating revenues	$	3,792.8	$	—	$	3,792.8
Other operation and maintenance *	1,425.5		—		1,425.5
Depreciation and amortization	325.4		—		325.4
Operating income *	634.2		—		634.2
Equity in earnings of transmission affiliate	—		55.5		55.5
Interest expense	116.6		1.0		117.6
Capital expenditures	468.9		0.6		469.5
Total assets	12,945.1		426.4		13,371.5


*	Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 15, Employee Benefits, for more information on this new standard.

NOTE 18— 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.



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American Transmission Company LLC

As of December 31, 2016, we owned approximately 23% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. However, effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. ATC was a variable interest entity, but consolidation was not required since we were not ATC's primary beneficiary. We did not have the power to direct the activities that most significantly impacted ATC's economic performance. At December 31, 2016, we accounted for ATC as an equity method investment. See Note 16, Investment in American Transmission Company, for more information .

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 three 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 $56.7 million of required capacity payments over the remaining term of this agreement. We believe that the required capacity payments under this contract will continue to be recoverable in rates, and our maximum exposure to loss is limited to the capacity payments under the contract.

NOTE 19— COMMITMENTS AND CONTINGENCIES

We have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, operating leases, 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.

The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2018 .



				Payments Due By Period
(in millions)	Date Contracts Extend Through	Total Amounts Committed		2019		2020		2021		2022		2023		Later Years
Electric utility:
Nuclear	2033	$	8,764.4	$	445.4	$	475.1	$	501.1	$	531.2	$	563.0	$	6,248.6
Coal supply and transportation	2023	798.4		233.6		165.4		129.6		134.8		135.0		—
Purchased power	2043	101.6		22.7		19.4		12.3		10.4		7.6		29.2
Natural gas utility supply and transportation	2048	496.2		60.2		47.7		34.6		25.9		21.1		306.7
Total		$	10,160.6	$	761.9	$	707.6	$	677.6	$	702.3	$	726.7	$	6,584.5

Operating Leases

We lease property, plant, and equipment under various terms. The operating leases generally require us to pay property taxes, insurance premiums, and maintenance costs associated with the leased property. Many of our leases contain one of the following options upon the end of the lease term: (a) purchase the property at the current fair market value, or (b) exercise a renewal option, as set forth in the lease agreement.

Rental expense attributable to operating leases was $3.0 million , $4.0 million , and $5.0 million in 2018 , 2017 , and 2016 , respectively.



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Future minimum payments under noncancelable operating leases are payable as follows:



Year Ending December 31	Payments (in millions)
2019	$	2.9
2020	2.8
2021	0.7
2022	0.7
2023	0.7
Later years	13.9
Total	$	21.7

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 SO ₂ , NOx, 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.

We have continued to pursue a proactive strategy to manage our environmental compliance obligations, including:


•	the development of additional sources of renewable electric energy supply;


•	the addition of improvements for water quality matters such as treatment technologies to meet regulatory discharge limits and improvements to our cooling water intake systems;


•	the addition of emission control equipment to existing facilities to comply with ambient air quality standards and federal clean air rules;


•	the protection of wetlands and waterways, threatened and endangered species, and cultural resources associated with utility construction projects;


•	the retirement of old coal-fired power plants and conversion to modern, efficient, natural gas generation, super-critical pulverized coal generation, and/or replacement with renewable generation;


•	the beneficial use of ash and other products from coal-fired and biomass generating units; and


•	the remediation of former manufactured gas plant sites.

Air Quality

National Ambient Air Quality Standards

After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, which lowered the limit for ground-level ozone, creating a more stringent standard than the 2008 NAAQS. 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.

Mercury and Air Toxics Standards

In December 2018, the EPA proposed to revise the Supplemental Cost Finding for the mercury and air toxics standards (MATS) rule as well as the CAA required risk and technology review (RTR). The EPA was required by the Supreme Court to review both costs and benefits of complying with the MATS rule. After its review of costs, the EPA determined that it is not appropriate and necessary to regulate hazardous air pollutant emissions from power plants under Section 112 of the CAA. As a result, under the proposed rule, the emission standards and other requirements of the MATS rule first enacted in 2012 would remain in place. The EPA is not proposing to remove coal and oil fired power plants from the list of sources that are regulated under Section 112. The EPA also proposes that no revisions to MATS are warranted based on the results of the RTR. As a result, we do not expect the proposed rule to have a material impact on our financial condition or operations.



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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 ACE rule. The proposed ACE rule would require the EPA to develop emission guidelines for states to use to develop their individual state plans. The state plans would focus on reducing GHG emissions by improving the efficiency of fossil-fueled power plants.

In December 2018, the EPA proposed to revise the New Source Performance Standards for GHG emissions from new, modified, and

reconstructed fossil fueled power plants. The EPA determined that the best system of emission reduction (BSER) for new,

modified, and reconstructed coal units is highly efficient generation that would be equivalent to supercritical steam conditions for

larger units and subcritical steam conditions for smaller units. This proposed BSER would replace the determination from the 2015

rule, which identified BSER as partial carbon capture and storage.

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. We are working with industry members to evaluate potential GHG reduction pathways.

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 approximately 1,500 MW of coal-fired generation by 2020, including PIPP, which we are required to retire by May 31, 2019, and the 2018 retirement of Pleasant Prairie power plant. See Note 6, Property, Plant, and Equipment, for more information .

We are required to report our CO ₂ equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2017 , we reported aggregated CO ₂ equivalent emissions of approximately 23.5 million metric tonnes to the EPA. Based upon our preliminary analysis of the data, we estimate that we will report CO ₂ equivalent emissions of approximately

20.0 million metric tonnes to the EPA for 2018 . The level of CO ₂ and other GHG emissions varies from year to year and is dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO.

We are also required to report CO ₂ equivalent amounts related to the natural gas that our natural gas operations distribute and sell. For 2017 , we reported aggregated CO ₂ equivalent emissions of approximately 3.7 million metric tonnes to the EPA. Based upon our preliminary analysis of the data, we estimate that we will report CO ₂ equivalent emissions of approximately 4.2 million metric tonnes to the EPA for 2018 .

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

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

The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, 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 BTA requirements.



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We have received a BTA determination by the WDNR, with EPA concurrence, for our intake modification at the VAPP. Due to the retirement of the Pleasant Prairie power plant and our plans to retire PIPP, we do not believe that BTA determinations will be necessary for these units. Although we currently believe that existing technologies at PWGS and OC 5 through OC 8 satisfy the BTA requirements, final determinations 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 BTA requirements for these units.

We also have provided information to the WDNR and the MDEQ about planned unit retirements. Following discussions with the MDEQ, in January 2019, we submitted a signed certification stating that PIPP will be retired no later than June 1, 2019. Based on this submittal, the MDEQ has authority to waive any remaining BTA requirements applicable to the PIPP units.

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

Steam Electric Effluent Limitation Guidelines

The EPA's final steam electric effluent limitation guidelines (ELG) rule took effect in January 2016. This rule created new requirements for several types of power plant wastewaters. The two new requirements that affect us relate to discharge limits for bottom ash transport water (BATW) and wet flue gas desulfurization (FGD) wastewater. Various petitions challenging the rule were consolidated and are pending in the United States Court of Appeals for the Fifth Circuit. In April 2017, the EPA issued an administrative stay of certain compliance deadlines while further reviewing the rule. In September 2017, the EPA issued a final rule (Postponement Rule) to postpone the earliest compliance date to November 1, 2020 for the BATW and wet FGD wastewater requirements. The latest ELG rule compliance date remains December 31, 2023 for any new wastewater treatment requirements contained in power plant discharge permits. This rule applies to wastewater discharges from our power plant processes in Wisconsin. Litigation over various aspects of the final ELG rule and the Postponement Rule is pending in several federal courts.

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. Due to completed and pending generating unit retirements, we believe 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. Based on preliminary engineering, the estimated rule compliance cost is approximately $50 million .

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 as of December 31:



(in millions)	2018		2017
Regulatory assets	$	24.2	$	30.4
Reserves for future remediation *	13.2		18.5


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



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Renewables, Efficiency, and Conservation

Wisconsin Legislation

In 2005, Wisconsin enacted Act 141, which established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. We have achieved a renewable energy percentage of 8.27% and met our compliance requirements by constructing various wind parks, a biomass facility, and by also relying on renewable energy purchases. We continue to review our renewable energy portfolio and acquire cost-effective renewables as needed to meet our requirements on an ongoing basis. The PSCW administers the renewable program related to Act 141, and we fund the program, along with other utilities, based on 1.2% of our annual operating revenues.

Michigan Legislation

In 2008, Michigan enacted Act 295, which required 10% of the state's electric energy to come from renewables by 2015 and energy optimization (efficiency) targets up to 1% annually by 2015. In December 2016, Michigan revised this legislation with Act 342, which requires additional renewable energy requirements beyond 2015. The revised legislation retained the 10% renewable energy portfolio requirement through 2018, increased the requirement to 12.5% for years 2019 through 2020, and increased the requirement to 15.0% for 2021. We were in compliance with these requirements as of December 31, 2018 . The revised legislation continues to allow recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective. Upon the commercial operation of the new generating solution in the Upper Peninsula of Michigan and Tilden becoming a customer of UMERC, we will no longer be subject to Michigan's renewable energy requirements. See Note 21, Regulatory Environment, for more information regarding the new natural gas-fired generation.

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.

NOTE 20— SUPPLEMENTAL CASH FLOW INFORMATION



(in millions)	2018			2017			2016
Cash (paid) for interest, net of amount capitalized	$	(115.0	)	$	(115.1	)	$	(116.2	)
Cash (paid) received for income taxes, net	(17.7		)	(71.7		)	100.2
Significant non-cash transactions:
Accounts payable related to construction costs	14.0			13.2			9.1
Transfer of investment in ATC to another subsidiary of WEC Energy Group ^{(1) (2)}	—			415.4			—
Transfer of net assets to UMERC ⁽¹⁾	—			61.1			—
Equity settlement of a short-term note receivable between Bostco and our parent company	—			4.8			—


⁽¹⁾	See Note 3, Related Parties , for more information on these transactions.


⁽²⁾	The amount transferred includes a $13.4 million receivable for distributions approved and recorded in December 2016. See Note 16, Investment in American Transmission Company , for more information on this transaction.



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NOTE 21— 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 addressed all base rate impacts of the Tax Legislation, which are being 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.

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

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

As required in the settlement agreement, we anticipate initiating a rate proceeding with the PSCW by April 1, 2019.

Natural Gas Storage Facilities in Michigan

In January 2017, WEC Energy Group signed an agreement for the acquisition of Bluewater. Bluewater owns natural gas storage facilities in Michigan that provide a portion of the current storage needs for our natural gas utility operations. As a result of this agreement, we, along with WG and WPS, filed a request with the PSCW in February 2017 for a declaratory ruling on various items associated with the storage facilities. In the filing, we requested that the PSCW review and confirm the reasonableness and prudency of our potential long-term storage service agreement and interstate natural gas transportation contracts related to the storage facilities. We, along with WG and WPS, also requested approval to amend WEC Energy Group's AIA to ensure WBS and WEC Energy Group's other subsidiaries could provide services to the storage facilities. During June 2017, the PSCW granted, subject to various conditions, these declarations and approvals, and WEC Energy Group acquired Bluewater on June 30, 2017. In September 2017, we



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entered into the long-term service agreement for the natural gas storage, which was then approved by the PSCW in November 2017. See Note 3, Related Parties, for more information .

Formation of Upper Michigan Energy Resources Corporation

In December 2016, both the MPSC and the PSCW approved the operation of UMERC, a subsidiary of WEC Energy Group, as a stand - alone utility in the Upper Peninsula of Michigan, and UMERC became operational effective January 1, 2017. This utility holds the electric and natural gas distribution assets, previously held by WPS and us, located in the Upper Peninsula of Michigan.

In August 2016, WEC Energy Group entered into an agreement with Tilden, under which Tilden will purchase electric power from UMERC for its iron ore mine for 20 years , contingent upon UMERC's construction of approximately 180 MW of natural gas-fired generation in the Upper Peninsula of Michigan.

In October 2017, the MPSC approved both the agreement with Tilden and UMERC's application for a certificate of necessity to begin construction of the proposed generation. The new units are expected to begin commercial operation during the second quarter of 2019. Upon receiving the MPSC's approval, retirement of our PIPP generating units became probable. Pursuant to MISO's April 2018 approval of the retirement of the plant, the PIPP units are required to be retired on or before May 31, 2019. Tilden will remain our customer until this new generation begins commercial operation.

NOTE 22— OTHER INCOME, NET

Total other income, net was as follows for the years ended December 31 :



(in millions)	2018		2017			2016
AFUDC – Equity	$	3.9	$	3.1		$	4.2
Non-service credit (cost) components of net periodic benefit costs	5.7		(6.5		)	(4.7		)
Interest income	2.2		2.3			2.2
Other, net	8.4		14.3			2.7
Other income, net	$	20.2	$	13.2		$	4.4

NOTE 23— QUARTERLY FINANCIAL INFORMATION (Unaudited)



(in millions)	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2018
Operating revenues	$	941.5	$	856.2	$	924.0	$	903.3	$	3,625.0
Operating income	136.4		104.5		107.8		53.8		402.5
Net income attributed to common shareholder	105.8		92.8		103.2		56.5		358.3

2017
Operating revenues	$	972.0	$	855.4	$	943.8	$	940.5	$	3,711.7
Operating income *	186.3		146.1		164.8		134.9		632.1
Net income attributed to common shareholder	101.8		75.3		89.4		69.1		335.6


*	Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 15, Employee Benefits, for more information on this new standard.

NOTE 24— NEW ACCOUNTING PRONOUNCEMENTS

Leases

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which revised the previous 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 was largely unchanged from previous provisions of GAAP.



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We have finalized our inventory of leases, documented our technical accounting issues, and implemented required changes to internal controls and processes as a result of the new lease guidance. In addition, we continue to finalize the related financial disclosures that will be incorporated into our quarterly report on Form 10-Q for the quarter ended March 31, 2019.

As required, we adopted Topic 842 for interim and annual periods beginning January 1, 2019. We utilized the following practical expedients, which were available under ASU 2016-02, in our adoption of the new lease guidance.


•	We did not reassess whether any expired or existing contracts were leases or contained leases.


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


•	We did not reassess the accounting for initial direct costs for any existing leases.

We did not elect the practical expedient allowing entities to account for the nonlease components in lease contracts as part of the single lease component to which they were related. Instead, in accordance with ASC 842-10-15-31, our policy is to account for each lease component separately from the nonlease components of the contract.

We did not elect the practical expedient to use hindsight in determining the lease term and in assessing impairment of our right-of-use assets. No impairment losses were included in the measurement of our right-of-use assets upon our adoption of Topic 842.

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. We elected this practical expedient upon our adoption of Topic 842, resulting in none of our land easements being treated as leases.

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, if required. We used the optional transition method to apply the new guidance as of January 1, 2019, rather than as of the earliest period presented.

While we are still refining our estimates, we expect that the right of use asset and related lease liability that we will record related to our operating leases will be in the range of $10 million to $20 million . Regarding our capital leases, while the adoption of Topic 842 changed the classification of expense related to these leases on a prospective basis, it had no impact on the total amount of lease expense recorded, and did not impact the capital lease asset and related liability amounts recorded on our balance sheets. Our capital leases relate to power plants leased from We Power and a long-term power purchase commitment with an unaffiliated third party. Prior to January 1, 2019, lease expense related to our We Power leases was recorded as rent expense in other operation and maintenance, while lease expense related to the power purchase commitment was recorded in cost of sales. Subsequent to our adoption of Topic 842, lease expense related to these capital leases is divided between depreciation and amortization and interest expense, as required by the new guidance. We did not require a cumulative-effect adjustment upon adoption of Topic 842, and the new guidance is not expected to have any impact on future net income 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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Cloud Computing

In August 2018, the FASB issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. The standard allows entities who are customers in hosting arrangements that are service contracts to apply the existing internal-use software guidance to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The guidance specifies classification for capitalizing implementation costs and related amortization expense within the financial statements and requires additional disclosures. The guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019. Early adoption is permitted and can be applied either retrospectively or prospectively. We are currently evaluating the transition methods and the impact the adoption of this standard may have on our consolidated financial statements.



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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. 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.

Management's Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2018 .

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

This Annual Report on Form 10-K does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by our independent registered public accounting firm pursuant to rules of the SEC that permit us to provide only management's report in this annual report.

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

ITEM 9B. OTHER INFORMATION

None.



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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANT

The information under "Election of Directors," "Section 16(a) Beneficial Ownership Reporting Compliance," "Corporate Governance – Frequently Asked Questions: What is the process used to identify director nominees and how do I recommend a nominee to WEC Energy Group's Corporate Governance Committee?," "Corporate Governance – Frequently Asked Questions: Are the WEC Energy Group Audit and Oversight and Compensation Committees comprised solely of independent directors?," "Corporate Governance – Frequently Asked Questions: Are all the members of the WEC Energy Group Audit Committee financially literate and does the committee have an 'audit committee financial expert'?," "Corporate Governance – Frequently Asked Questions: Does the Board have a nominating committee?," and "Committees of the WEC Energy Group Board of Directors – Audit and Oversight" in our Definitive Information Statement on Schedule 14C to be filed with the SEC for our Annual Meeting of Shareholders to be held April 25, 2019 (the " 2019 Annual Meeting Information Statement") is incorporated herein by reference. Also see "Executive Officers of the Registrant" in Part I of this report.

WEC Energy Group has adopted a written code of ethics, referred to as its Code of Business Conduct. We are a subsidiary of WEC Energy Group, and as such, all of our directors, executive officers, and employees, including our principal executive officer, principal financial officer and principal accounting officer, have a responsibility to comply with WEC Energy Group's Code of Business Conduct. WEC Energy Group has posted its Code of Business Conduct in the "Governance" section on its website, www.wecenergygroup.com. WEC Energy Group has not provided any waiver to the Code for any director, executive officer, or other employee. Any amendments to, or waivers for directors and executive officers from, the Code of Business Conduct will be disclosed on WEC Energy Group's website or in a current report on Form 8-K.

ITEM 11. EXECUTIVE COMPENSATION

The information under "Compensation Discussion and Analysis," "Executive Compensation," "Director Compensation," "Committees of the WEC Energy Group Board of Directors – Compensation," "Compensation Committee Report," "Pay Ratio Disclosure," "Risk Analysis of Compensation Policies and Practices," and "Certain Relationships and Related Transactions – Compensation Committee Interlocks and Insider Participation" in the 2019 Annual Meeting Information Statement is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

All of our Common Stock is owned by our parent company, WEC Energy Group, 231 West Michigan Street, P.O. Box 1331, Milwaukee, Wisconsin 53201. Our directors and director nominees, who are all executive officers of WE, as well as our other executive officers, do not own any of our voting securities. The information concerning their beneficial ownership in WEC Energy Group common stock set forth under "Stock Ownership of Directors, Nominees and Executive Officers" in the 2019 Annual Meeting Information Statement is incorporated herein by reference.

We do not have any equity compensation plans under which our equity securities may be issued. Our directors, officers and certain employees participate in the compensation plans of WEC Energy Group.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information under "Corporate Governance – Frequently Asked Questions: Who are the independent directors?," "Corporate Governance – Frequently Asked Questions: What are the WEC Energy Group Board's standards of independence?," "Corporate Governance – Frequently Asked Questions: Are the WEC Energy Group Audit and Oversight and Compensation Committees comprised solely of independent directors?," "Corporate Governance – Frequently Asked Questions: Does the Company have policies and procedures in place to review and approve related party transactions?," and "Certain Relationships and Related Transactions" in the 2019 Annual Meeting Information Statement is incorporated herein by reference. A full description of the guidelines the WEC Energy Group Board uses to determine director independence is located in Appendix A of WEC Energy Group's Corporate Governance Guidelines, which can be found on its website, www.wecenergygroup.com.



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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information regarding the fees paid to, and services performed by, our independent auditors and the pre-approval policy of our audit and oversight committee under "Independent Auditors' Fees and Services" in the 2019 Annual Meeting Information Statement is incorporated herein by reference.



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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES



1.	Financial Statements and Report of Independent Registered Public Accounting Firm Included in Part II of This Report

	Description	Page in 10-K

	Report of Independent Registered Public Accounting Firm.	50

	Consolidated Income Statements for the three years ended December 31, 2018, 2017, and 2016.	51

	Consolidated Balance Sheets at December 31, 2018 and 2017.	52

	Consolidated Statements of Cash Flows for the three years ended December 31, 2018, 2017, and 2016.	53

	Consolidated Statements of Equity for the three years ended December 31, 2018, 2017, and 2016.	54

	Consolidated Statements of Capitalization at December 31, 2018 and 2017.	55

	Notes to Consolidated Financial Statements.	56

2.	Financial Statement Schedules Included in Part IV of This Report

	Schedule II, Valuation and Qualifying Accounts, for the three years ended December 31, 2018, 2017, and 2016.	104

	Other schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto.

3.	Exhibits and Exhibit Index

	The following exhibits are filed or furnished with or incorporated by reference in the report with respect to Wisconsin Electric Power Company (File No. 001-01245). An asterisk () indicates incorporation by reference pursuant to Exchange Act Rule 12b-32. Each management contract and compensatory plan or arrangement required to be filed as an exhibit to this report pursuant to Item 15(b) of Form 10-K is identified below by two asterisks (*) following the description of the exhibit.



Number	Exhibit
3	Articles of Incorporation and By-laws

	3.1*	Restated Articles of Incorporation of WE, as amended and restated effective January 10, 1995. (Exhibit (3)-1 to WE's 12/31/94 Form 10-K.)

	3.2*	Bylaws of WE, as amended to May 1, 2000. (Exhibit (3)-2 to WE's 03/31/00 Form 10-Q.)

4	Instruments defining the rights of security holders, including indentures

	4.1*	Reference is made to Article III of the Restated Articles of Incorporation of WE. (See Exhibit 3.1 above.)

	Indentures and Securities Resolutions:

	4.2*	Indenture for Debt Securities of WE (the "WE Indenture"), dated December 1, 1995. (Exhibit (4)-1 to WE's 12/31/95 Form 10-K.)

	4.3*	Securities Resolution No. 1 of WE under the WE Indenture, dated December 5, 1995. (Exhibit (4)-2 to WE's 12/31/95 Form 10-K.)



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Number	Exhibit
	4.4*	Securities Resolution No. 3 of WE under the WE Indenture, dated May 27, 1998. (Exhibit (4)-1 to WE's 06/30/98 Form 10-Q.)

	4.5*	Securities Resolution No. 5 of WE under the WE Indenture, dated as of May 1, 2003. (Exhibit 4.47 filed with Post-Effective Amendment No. 1 to WE's Registration Statement on Form S-3 (File No. 333-101054), filed May 6, 2003.)

	4.6*	Securities Resolution No. 7 of WE under the WE Indenture, dated as of November 2, 2006. (Exhibit 4.1 to WE's 11/02/06 Form 8-K.)

	4.7*	Securities Resolution No. 10 of WE under the WE Indenture, dated as of December 8, 2009. (Exhibit 4.1 to WE's 12/08/09 Form 8-K.)

	4.8*	Securities Resolution No. 11 of WE under the WE Indenture, dated as of September 7, 2011. (Exhibit 4.1 to WE's 09/07/11 Form 8-K.)

	4.9*	Securities Resolution No. 12 of WE under the WE Indenture, dated as of December 5, 2012. (Exhibit 4.1 to WE's 12/05/12 Form 8-K.)

	4.10*	Securities Resolution No. 14 of WE under the WE Indenture, dated as of May 12, 2014. (Exhibit 4.1 to WE's 05/12/14 Form 8-K.)

	4.12*	Securities Resolution No. 15 of WE under the WE Indenture, dated as of May 14, 2015. (Exhibit 4.1 to WE's 05/14/15 Form 8-K.)

	4.12*	Securities Resolution No. 16 of WE under the WE Indenture, dated as of November 13, 2015. (Exhibit 4.1 to WE's 11/13/15 Form 8-K.)

	4.13*	Securities Resolution No. 17 of WE under the WE Indenture, dated as of October 1, 2018. (Exhibit 4.1 to WE's 10/01/18 Form 8-K.)

		Certain agreements and instruments with respect to unregistered long-term debt not exceeding 10 percent of the total assets of the Registrant and its subsidiary on a consolidated basis have been omitted as permitted by related instructions. The Registrant agrees pursuant to Item 601(b)(4) of Regulation S-K to furnish to the Securities and Exchange Commission, upon request, a copy of all such agreements and instruments.

10	Material Contracts

	10.1	WEC Energy Group Supplemental Pension Plan, Amended and Restated Effective as of January 1, 2018.**

	10.2	Legacy Wisconsin Energy Corporation Executive Deferred Compensation Plan, Amended and Restated as of January 1, 2018.**

	10.3	WEC Energy Group Executive Deferred Compensation Plan, Amended and Restated Effective as of January 1, 2018.**

	10.4	WEC Energy Group Non-Qualified Retirement Savings Plan, Amended and Restated Effective as of January 1, 2018.**

	10.5	WEC Energy Group Supplemental Long Term Disability Plan, Amended and Restated Effective as of January 1, 2017.**

	10.6	WEC Energy Group Short-Term Performance Plan, Amended and Restated Effective as of January 1, 2019.**

	10.7*	Wisconsin Energy Corporation 2014 Rabbi Trust Agreement by and between Wisconsin Energy Corporation and The Northern Trust Company dated February 23, 2015, regarding the trust established to provide a source of funds to assist in meeting the liabilities under various nonqualified deferred compensation plans made between Wisconsin Energy Corporation or its subsidiaries and various plan participants. (Exhibit 10.13 to Wisconsin Energy Corporation's 12/31/14 Form 10-K (File No. 001-09057).)**



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Number	Exhibit
	10.8*	Letter Agreement by and between WEC Energy Group, Inc. and Gale E. Klappa, dated as of December 7, 2017. (Exhibit 10.1 to WEC Energy Group's 12/08/17 Form 8-K. (File No. 001-09057).)**

	10.9*	Terms and Conditions Governing Gale Klappa's Restricted Stock Award Under the 1993 Omnibus Stock Incentive Plan. (Exhibit 10.2 to WEC Energy Group's 12/08/17 Form 8-K. (File No. 001-09057).)**

	10.10*	Letter Agreement by and between WEC Energy Group, Inc. and Gale E. Klappa, dated as of January 17, 2019. (Exhibit 10.1 to WEC Energy Group's 01/22/19 Form 8-K. (File No. 001-09057).)**

	10.11*	Letter Agreement by and between Wisconsin Energy Corporation and Robert Garvin, dated January 31, 2011. (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/11 Form 10-Q (File No. 001-09057).)**

	10.12*	Letter Agreement by and between Wisconsin Energy Corporation and Joseph Kevin Fletcher, dated as of August 17, 2011. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/11 Form 10-Q (File No. 001-09057).)**

	10.13*	Letter Agreement by and between WEC Energy Group, Inc. and Margaret C. Kelsey, dated as of July 19, 2017. (Exhibit 10.1 to WEC Energy Group's 09/30/17 Form 10-Q. (File No. 001-09057).)**

	10.14*	1993 Omnibus Stock Incentive Plan, Amended and Restated Effective as of January 1, 2016. (Exhibit 10.19 to WEC Energy Group's 12/31/15 Form 10-K (File No. 001-09057).)**

	10.15*	Terms and Conditions Governing Non-Qualified Stock Option Award under the 1993 Omnibus Stock Incentive Plan. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/07 Form 10-Q (File No. 001-09057).)**

	10.16*	WEC Energy Group Performance Unit Plan, amended and restated effective as of January 1, 2017. (Exhibit 10.1 to WEC Energy Group's 12/01/16 Form 8-K (File No. 001-09057).)**

	10.17*	2016 WEC Energy Group Restricted Stock Award Terms and Conditions governing awards under the 1993 Omnibus Stock Incentive Plan. (Exhibit 10.27 to WEC Energy Group’s 12/31/15 Form 10-K (File No. 001-09057).)**

	10.18*	Wisconsin Energy Corporation Terms and Conditions Governing Non-Qualified Stock Option Award for option awards under the 1993 Omnibus Stock Incentive Plan, approved December 4, 2014. (Exhibit 10.3 to Wisconsin Energy Corporation's 12/04/14 Form 8-K (File No. 001-09057).)**

	10.19*	2016 WEC Energy Group Terms and Conditions Governing Non-Qualified Stock Option Award for option awards under the 1993 Omnibus Stock Incentive Plan. (Exhibit 10.29 to WEC Energy Group’s Form 12/31/15 Form 10-K (File No. 001-09057).)**

	10.20*	Port Washington I Facility Lease Agreement between Port Washington Generating Station LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of May 28, 2003. (Exhibit 10.7 to WE's 06/30/03 Form 10-Q.)

	10.21*	Port Washington II Facility Lease Agreement between Port Washington Generating Station LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of May 28, 2003. (Exhibit 10.8 to WE's 06/30/03 Form 10-Q.)

	10.22*	Elm Road I Facility Lease Agreement between Elm Road Generating Station Supercritical, LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of November 9, 2004. (Exhibit 10.56 to Wisconsin Energy Corporation's 12/31/04 Form 10-K (File No. 001-09057).)

	10.23*	Elm Road II Facility Lease Agreement between Elm Road Generating Station Supercritical, LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of November 9, 2004. (Exhibit 10.57 to Wisconsin Energy Corporation's 12/31/04 Form 10-K (File No. 001-09057).)

	10.24*	Point Beach Nuclear Plant Power Purchase Agreement between FPL Energy Point Beach, LLC and Wisconsin Electric Power Company, dated as of December 19, 2006 (the "PPA"). (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/08 Form 10-Q (File No. 001-09057).)

	10.25*	Letter Agreement between Wisconsin Electric Power Company and FPL Energy Point Beach, LLC, dated October 31, 2007, which amends the PPA. (Exhibit 10.45 to Wisconsin Energy Corporation's 12/31/07 Form 10-K (File No. 001-09057).)



2018 Form 10-K	102	Wisconsin Electric Power Company

Table of Contents



Number	Exhibit

23	Consents of experts and counsel

	23.1	Consent of Independent Registered Public Accounting Firm for WE.

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

ITEM 16. FORM 10-K SUMMARY

None.



2018 Form 10-K	103	Wisconsin Electric Power Company

Table of Contents

SCHEDULE II

WISCONSIN ELECTRIC POWER COMPANY

VALUATION AND QUALIFYING ACCOUNTS



Allowance for Doubtful Accounts (in millions)	Balance at Beginning of Period		Transfer of Net Assets to UMERC ⁽¹⁾			Expense ⁽²⁾		Deferral			Net Write-offs ⁽³⁾			Balance at End of Period
December 31, 2018	$	39.5	$	—		$	32.3	$	(9.1	)	$	(21.8	)	$	40.9
December 31, 2017	40.9		(0.3		)	31.2		(6.4		)	(25.9		)	39.5
December 31, 2016	43.0		—			31.1		(5.7		)	(27.5		)	40.9


⁽¹⁾	See Note 3, Related Parties, for more information .


⁽²⁾	Net of recoveries.


⁽³⁾	Represents amounts written off to the reserve, net of adjustments to regulatory assets.



2018 Form 10-K	104	Wisconsin Electric Power Company

Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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

	By	/s/ J. KEVIN FLETCHER
Date:	February 26, 2019	J. Kevin Fletcher
		Chairman of the Board and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



/s/ J. KEVIN FLETCHER		February 26, 2019
J. Kevin Fletcher, Chairman of the Board and Chief Executive
Officer and Director -- Principal Executive Officer

/s/ SCOTT J. LAUBER		February 26, 2019
Scott J. Lauber, Executive Vice President, Chief Financial
Officer, Treasurer and Director -- Principal Financial Officer

/s/ WILLIAM J. GUC		February 26, 2019
William J. Guc, Vice President and
Controller -- Principal Accounting Officer

/s/ MARGARET C. KELSEY		February 26, 2019
Margaret C. Kelsey, Director

/s/ GALE E. KLAPPA		February 26, 2019
Gale E. Klappa, Director

/s/ TOM METCALFE		February 26, 2019
Tom Metcalfe, Director



2018 Form 10-K	105	Wisconsin Electric Power Company

TABLE OF CONTENTS

Part I Item 1. Business Note 2, Dispositions Note 17, Segment Information Note 3, Related Parties Note 21, Regulatory Environment Note 4, Operating Revenues Note 1(d), Operating Revenues Note 6, Property, Plant, and Equipment Note 19, Commitments and Contingencies Item 1A. Risk Factors Item 1B. Unresolved Staff Comments Item 2. Properties Item 3. Legal Proceedings Item 4. Mine Safety Disclosures Part II Item 5. Market For Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity Securities Item 6. Selected Financial Data Note 16, Investment in American Transmission Company Item 7. Management's Discussion and Analysis Of Financial Condition and Results Of Operations Note 12, Income Taxes Note 10, Short-term Debt and Lines Of Credit Note 11, Long-term Debt and Capital Lease Obligations Note 8, Common Equity Note 15, Employee Benefits Note 1(o), Guarantees Note 18, Variable Interest Entities Note 1(l), Income Taxes Item 7A. Quantitative and Qualitative Disclosures About Market Risk Note 1(m), Fair Value Measurements Note 1(n), Derivative Instruments Item 8. Financial Statements and Supplementary Data Note 1 Summary Of Significant Accounting Policies Note 2 Dispositions Note 3 Related Parties Note 4 Operating Revenues Note 5 Regulatory Assets and Liabilities Note 6 Property, Plant, and Equipment Note 7 Asset Retirement Obligations Note 8 Common Equity Note 9 Preferred Stock Note 10 Short-term Debt and Lines Of Credit Note 11 Long-term Debt and Capital Lease Obligations Note 5, Regulatory Assets and Liabilities Note 12 Income Taxes Note 13 Fair Value Measurements Note 14 Derivative Instruments Note 15 Employee Benefits Note 16 Investment in American Transmission Company Note 17 Segment Information Note 18 Variable Interest Entities Note 19 Commitments and Contingencies Note 20 Supplemental Cash Flow Information Note 21 Regulatory Environment Note 22 Other Income, Net Note 23 Quarterly Financial Information (unaudited)Note 24 New Accounting Pronouncements Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Item 9A. Controls and Procedures Item 9B. Other Information Part III Item 10. Directors, Executive Officers and Corporate Governance Of The Registrant Item 11. Executive Compensation Item 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder Matters Item 13. Certain Relationships and Related Transactions, and Director Independence Item 14. Principal Accounting Fees and Services Part IV Item 15. Exhibits and Financial Statement Schedules Item 16. Form 10-k Summary

Exhibits

23.1 Consent of Independent Registered Public Accounting Firm for WE. 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-K Fiscal year ended Dec. 31, 2018

Exhibits