WISCONSIN ELECTRIC POWER CO - Quarter Report: 2019 June (Form 10-Q)

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)



☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2019



☐	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

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 ☒ 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 ☒ No ☐

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

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 ☒

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



	Common Stock, $10 Par Value,
	33,289,327	shares outstanding at
	June 30, 2019

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

Table of Contents

WISCONSIN ELECTRIC POWER COMPANY

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended June 30, 2019

TABLE OF CONTENTS



				Page
	CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION			1
PART I.	FINANCIAL INFORMATION			3
ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)			3
	Condensed Consolidated Income Statements			3
	Condensed Consolidated Balance Sheets			4
	Condensed Consolidated Statements of Cash Flows			5
	Condensed Consolidated Statements of Equity			6
	Notes to Condensed Consolidated Financial Statements			7
			Page
	Note 1	General Information	7
	Note 2	Operating Revenues	7
	Note 3	Regulatory Assets and Liabilities	9
	Note 4	Property, Plant, and Equipment	9
	Note 5	Common Equity	10
	Note 6	Short-Term Debt and Lines of Credit	10
	Note 7	Leases	10
	Note 8	Materials, Supplies, and Inventories	15
	Note 9	Income Taxes	15
	Note 10	Fair Value Measurements	16
	Note 11	Derivative Instruments	17
	Note 12	Guarantees	19
	Note 13	Employee Benefits	19
	Note 14	Segment Information	19
	Note 15	Variable Interest Entities	20
	Note 16	Commitments and Contingencies	20
	Note 17	Supplemental Cash Flow Information	23
	Note 18	Regulatory Environment	23
	Note 19	New Accounting Pronouncements	24
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			25
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			41
ITEM 4.	CONTROLS AND PROCEDURES			41
PART II.	OTHER INFORMATION			42
ITEM 1.	LEGAL PROCEEDINGS			42
ITEM 1A.	RISK FACTORS			42
ITEM 6.	EXHIBITS			42
SIGNATURE				43



06/30/2019 Form 10-Q	i	Wisconsin Electric Power Company

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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
Bostco		Bostco LLC
UMERC		Upper Michigan Energy Resources Corporation
We Power		W.E. Power, LLC
WEC Energy Group		WEC Energy Group, Inc.
WG		Wisconsin Gas LLC

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
PSCW		Public Service Commission of Wisconsin
SEC		United States Securities and Exchange Commission

Accounting Terms
AFUDC		Allowance for Funds Used During Construction
ASU		Accounting Standards Update
FASB		Financial Accounting Standards Board
GAAP		United States Generally Accepted Accounting Principles
OPEB		Other Postretirement Employee Benefits

Environmental Terms
ACE		Affordable Clean Energy
BATW		Bottom Ash Transport Water
BSER		Best System of Emission Reduction
BTA		Best Technology Available
CAA		Clean Air Act
CO₂		Carbon Dioxide
ELG		Steam Electric Effluent Limitation Guidelines
FGD		Flue Gas Desulfurization
GHG		Greenhouse Gas
MATS		Mercury and Air Toxics Standards
RTR		Risk and Technology Review

Measurements
Dth		Dekatherm
MW		Megawatt
MWh		Megawatt-hour

Other Terms and Abbreviations
AMI		Advanced Metering Infrastructure
Badger Hollow II		Badger Hollow Solar Farm II
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



06/30/2019 Form 10-Q	ii	Wisconsin Electric Power Company

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MISO		Midcontinent Independent System Operator, Inc.
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
PIPP		Presque Isle 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
SSR		System Support Resource
Tax Legislation		Tax Cuts and Jobs Act of 2017
Tilden		Tilden Mining Company



06/30/2019 Form 10-Q	iii	Wisconsin Electric Power Company

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

Forward-looking statements are subject to a number of risks and uncertainties that could cause our actual results to differ materially from those expressed or implied in the statements. These risks and uncertainties include those described in risk factors as set forth in this report and our 2018 Annual Report on Form 10-K, and those identified below:


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


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


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


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


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

•

The impact of federal, state, and local legislative and/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 WEC Energy Group and 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,



06/30/2019 Form 10-Q	1	Wisconsin Electric Power Company

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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, if at all, or within budgets;


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


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


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


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

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



06/30/2019 Form 10-Q	2	Wisconsin Electric Power Company

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WISCONSIN ELECTRIC POWER COMPANY



CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited)	Three Months Ended						Six Months Ended
CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited)	June 30						June 30
(in millions)	2019			2018			2019			2018
Operating revenues	$	791.7		$	856.2		$	1,752.5		$	1,797.7

Operating expenses
Cost of sales	253.5			270.9			610.7			627.9
Other operation and maintenance	234.3			366.6			493.2			702.2
Depreciation and amortization	95.2			86.9			191.2			172.2
Property and revenue taxes	26.1			27.3			51.9			54.5
Total operating expenses	609.1			751.7			1,347.0			1,556.8

Operating income	182.6			104.5			405.5			240.9

Other income, net	5.9			15.3			11.4			11.1
Interest expense	119.6			29.2			239.5			58.9
Other expense	(113.7		)	(13.9		)	(228.1		)	(47.8		)

Income before income taxes	68.9			90.6			177.4			193.1
Income tax benefit	(16.3		)	(2.5		)	(22.8		)	(6.1		)
Net income	85.2			93.1			200.2			199.2

Preferred stock dividend requirements	0.3			0.3			0.6			0.6
Net income attributed to common shareholder	$	84.9		$	92.8		$	199.6		$	198.6

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



06/30/2019 Form 10-Q	3	Wisconsin Electric Power Company

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WISCONSIN ELECTRIC POWER COMPANY



CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts)	June 30, 2019		December 31, 2018
Assets
Current assets
Cash and cash equivalents	$	4.6	$	20.2
Accounts receivable and unbilled revenues, net of reserves of $37.6 and $40.9, respectively	403.5		472.3
Accounts receivable from related parties	65.0		112.4
Materials, supplies, and inventories	228.0		241.4
Prepayments	138.6		163.7
Other	16.6		6.3
Current assets	856.3		1,016.3

Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $4,447.2 and $4,505.5, respectively	9,383.5		9,528.9
Regulatory assets	3,126.9		2,902.2
Other	112.6		90.9
Long-term assets	12,623.0		12,522.0
Total assets	$	13,479.3	$	13,538.3

Liabilities and Equity
Current liabilities
Short-term debt	$	39.5	$	134.9
Current portion of long-term debt	250.0		250.0
Current portion of finance and capital lease obligations	53.8		49.9
Accounts payable	207.4		248.9
Accounts payable to related parties	161.5		226.0
Accrued payroll and benefits	44.8		50.4
Other	112.9		116.8
Current liabilities	869.9		1,076.9

Long-term liabilities
Long-term debt	2,460.4		2,459.6
Finance and capital lease obligations	2,804.6		2,807.2
Deferred income taxes	1,345.6		1,298.3
Regulatory liabilities	2,026.2		2,002.3
Pension and OPEB obligations	106.9		118.5
Other	287.0		284.3
Long-term liabilities	9,030.7		8,970.2

Commitments and contingencies (Note 16)

Common shareholder's equity
Common stock – $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding	332.9		332.9
Additional paid in capital	929.2		831.3
Retained earnings	2,286.2		2,296.6
Common shareholder's equity	3,548.3		3,460.8

Preferred stock	30.4		30.4
Total liabilities and equity	$	13,479.3	$	13,538.3

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



06/30/2019 Form 10-Q	4	Wisconsin Electric Power Company

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WISCONSIN ELECTRIC POWER COMPANY



CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Six Months Ended
	June 30
(in millions)	2019			2018
Operating Activities
Net income	$	200.2		$	199.2
Reconciliation to cash provided by operating activities
Depreciation and amortization	191.2			172.2
Deferred income taxes and investment tax credits, net	(42.6		)	(39.5		)
Contributions and payments related to pension and OPEB plans	(3.2		)	(3.8		)
Change in –
Accounts receivable and unbilled revenues	112.9			57.9
Materials, supplies, and inventories	13.4			14.0
Prepayments	25.1			23.5
Other current assets	(9.2		)	4.9
Accounts payable	(98.5		)	(36.2		)
Accrued taxes	(0.3		)	19.0
Other current liabilities	(16.8		)	(18.1		)
Other, net	63.2			138.5
Net cash provided by operating activities	435.4			531.6

Investing Activities
Capital expenditures	(230.4		)	(287.0		)
Payments for assets transferred from affiliates	—			(50.1		)
Other, net	5.1			6.0
Net cash used in investing activities	(225.3		)	(331.1		)

Financing Activities
Change in short-term debt	(95.4		)	130.9
Retirement of long-term debt	—			(250.0		)
Payments for finance lease obligations	(24.4		)	—
Equity contribution from parent	105.0			28.0
Payment of dividends to parent	(210.0		)	(120.0		)
Other, net	(0.9		)	(0.6		)
Net cash used in financing activities	(225.7		)	(211.7		)

Net change in cash and cash equivalents	(15.6		)	(11.2		)
Cash and cash equivalents at beginning of period	20.2			12.3
Cash and cash equivalents at end of period	$	4.6		$	1.1

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



06/30/2019 Form 10-Q	5	Wisconsin Electric Power Company

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WISCONSIN ELECTRIC POWER COMPANY



CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited)

	Wisconsin Electric Power Company Common Shareholder's Equity
(in millions)	Common Stock		Additional Paid In Capital			Retained Earnings			Total Common Shareholder's Equity			Preferred Stock		Total Equity
Balance at December 31, 2018	$	332.9	$	831.3		$	2,296.6		$	3,460.8		$	30.4	$	3,491.2
Net income	—		—			115.0			115.0			—		115.0
Dividends
Common stock	—		—			(150.0		)	(150.0		)	—		(150.0		)
Preferred stock	—		—			(0.3		)	(0.3		)	—		(0.3		)
Stock-based compensation and other	—		0.2			—			0.2			—		0.2
Balance at March 31, 2019	$	332.9	$	831.5		$	2,261.3		$	3,425.7		$	30.4	$	3,456.1
Net income	—		—			85.2			85.2			—		85.2
Dividends
Common stock	—		—			(60.0		)	(60.0		)	—		(60.0		)
Preferred stock	—		—			(0.3		)	(0.3		)	—		(0.3		)
Equity contribution from parent	—		105.0			—			105.0			—		105.0
Transfer of net assets to UMERC	—		(7.3		)	—			(7.3		)	—		(7.3		)
Balance at June 30, 2019	$	332.9	$	929.2		$	2,286.2		$	3,548.3		$	30.4	$	3,578.7



	Wisconsin Electric Power Company Common Shareholder's Equity
(in millions)	Common Stock		Additional Paid In Capital		Retained Earnings			Total Common Shareholder's Equity			Preferred Stock		Total Equity
Balance at December 31, 2017	$	332.9	$	802.7	$	2,248.3		$	3,383.9		$	30.4	$	3,414.3
Net income	—		—		106.1			106.1			—		106.1
Dividends
Common stock	—		—		(60.0		)	(60.0		)	—		(60.0		)
Preferred stock	—		—		(0.3		)	(0.3		)	—		(0.3		)
Equity contribution from parent	—		28.0		—			28.0			—		28.0
Stock-based compensation and other	—		0.2		—			0.2			—		0.2
Balance at March 31, 2018	$	332.9	$	830.9	$	2,294.1		$	3,457.9		$	30.4	$	3,488.3
Net income	—		—		93.1			93.1			—		93.1
Dividends
Common stock	—		—		(60.0		)	(60.0		)	—		(60.0		)
Preferred stock	—		—		(0.3		)	(0.3		)	—		(0.3		)
Stock-based compensation and other	—		0.3		—			0.3			—		0.3
Balance at June 30, 2018	$	332.9	$	831.2	$	2,326.9		$	3,491.0		$	30.4	$	3,521.4

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



06/30/2019 Form 10-Q	6	Wisconsin Electric Power Company

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WISCONSIN ELECTRIC POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

June 30, 2019

NOTE 1—GENERAL INFORMATION

Wisconsin Electric Power Company serves approximately 1.1 million electric customers and 0.5 million natural gas customers.

As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. In this report, when we refer to "the Company," "us," "we," "our," or "ours," we are referring to Wisconsin Electric Power Company and its former subsidiary, Bostco, which was dissolved in October 2018.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2018. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and six months ended June 30, 2019 are not necessarily indicative of expected results for 2019 due to seasonal variations and other factors.

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

NOTE 2—OPERATING REVENUES

For more information about our significant accounting policies related to operating revenues, see Note 1(d), Operating Revenues, in our 2018 Annual Report on Form 10-K.

Disaggregation of Operating Revenues

The following tables present our operating revenues disaggregated by revenue source for 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 revenues 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.



	Wisconsin Electric Power Company Consolidated
	Three Months Ended June 30				Six Months Ended June 30
(in millions)	2019		2018		2019		2018
Electric utility	$	723.7	$	784.6	$	1,502.5	$	1,564.2
Natural gas utility	64.7		68.6		242.6		229.4
Total revenues from contracts with customers	788.4		853.2		1,745.1		1,793.6
Other operating revenues	3.3		3.0		7.4		4.1
Total operating revenues	$	791.7	$	856.2	$	1,752.5	$	1,797.7



06/30/2019 Form 10-Q	7	Wisconsin Electric Power Company

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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
	Three Months Ended June 30				Six Months Ended June 30
(in millions)	2019		2018		2019		2018
Residential	$	266.5	$	295.0	$	569.1	$	576.4
Small commercial and industrial	241.9		260.6		487.0		498.3
Large commercial and industrial	139.4		172.4		295.4		321.3
Other	4.9		4.9		10.5		10.3
Total retail revenues	652.7		732.9		1,362.0		1,406.3
Wholesale	20.1		28.9		49.0		57.4
Resale	41.8		17.1		73.1		80.8
Steam	4.3		4.6		14.4		14.3
Other utility revenues	4.8		1.1		4.0		5.4
Total electric utility operating revenues	$	723.7	$	784.6	$	1,502.5	$	1,564.2

Natural Gas Utility Operating Revenues

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



	Natural Gas Utility Operating Revenues
	Three Months Ended June 30				Six Months Ended June 30
(in millions)	2019		2018		2019			2018
Residential	$	35.4	$	40.7	$	161.0		$	155.4
Commercial and industrial	14.1		18.2		75.0			73.8
Total retail revenues	49.5		58.9		236.0			229.2
Transport	2.9		3.1		7.2			7.5
Other utility revenues *	12.3		6.6		(0.6		)	(7.3		)
Total natural gas utility operating revenues	$	64.7	$	68.6	$	242.6		$	229.4


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

Other Operating Revenues

Other operating revenues consist primarily of the following:



	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2019			2018			2019		2018
Late payment charges	$	2.0		$	2.1		$	4.7	$	4.9
Rental revenues	1.5			1.4			2.2		2.2
Alternative revenues *	(0.2		)	(0.5		)	0.5		(3.0		)
Total other operating revenues	$	3.3		$	3.0		$	7.4	$	4.1


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



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NOTE 3—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets and liabilities were reflected on our balance sheets at June 30, 2019 and December 31, 2018. For more information on our regulatory assets and liabilities, see Note 5, Regulatory Assets and Liabilities, in our 2018 Annual Report on Form 10-K.



(in millions)	June 30, 2019		December 31, 2018
Regulatory assets
Plant retirements *	$	954.5	$	754.1
Finance and capital leases	900.6		869.3
Pension and OPEB costs	475.6		490.6
Income tax related items	372.6		317.9
SSR	319.0		316.7
We Power generation	38.6		43.0
Electric transmission costs	25.2		57.8
Environmental remediation costs	23.6		24.2
Other, net	17.2		28.7
Total regulatory assets	$	3,126.9	$	2,902.3

Balance sheet presentation
Other current assets	$	—	$	0.1
Regulatory assets	3,126.9		2,902.2
Total regulatory assets	$	3,126.9	$	2,902.3


*	On March 31, 2019, we retired the PIPP generating units. See Note 4, Property, Plant, and Equipment, for more information on the retirement of the PIPP units.



(in millions)	June 30, 2019		December 31, 2018
Regulatory liabilities
Income tax related items	$	1,012.9	$	1,024.8
Removal costs	765.3		748.1
Mines deferral	130.5		120.8
Pension and OPEB costs	73.7		74.7
Uncollectible expense	20.9		16.4
Energy efficiency programs	14.7		13.5
Other, net	23.2		15.9
Total regulatory liabilities	$	2,041.2	$	2,014.2

Balance sheet presentation
Other current liabilities	$	15.0	$	11.9
Regulatory liabilities	2,026.2		2,002.3
Total regulatory liabilities	$	2,041.2	$	2,014.2

NOTE 4—PROPERTY, PLANT, AND EQUIPMENT

Presque Isle Power Plant

Pursuant to MISO's April 2018 approval of the retirement of the PIPP, these units were retired on March 31, 2019. As a result of the retirement of the plant, the net book value was reclassified as a regulatory asset on our balance sheet. In the second quarter of 2019, $12.5 million of the regulatory asset, along with the related deferred taxes and a portion of the cost of removal reserve, was transferred to UMERC for recovery from their retail customers. At June 30, 2019, the remaining carrying value of the PIPP units on our balance sheet was $155.5 million. This amount included the net book value of $166.1 million, which was classified as a regulatory asset. In addition, a $10.6 million cost of removal reserve related to the PIPP units remained classified as a regulatory liability at June 30, 2019. We have FERC approval to continue to collect the carrying value of the PIPP units using the approved composite depreciation rates, in addition to a return on the remaining carrying value. However, this approval is subject to refund pending the outcome of settlement procedures. We will amortize this regulatory asset on a straight-line basis using the composite depreciation rates approved by the PSCW before the units were retired.



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Severance Liability for Plant Retirements

We have evaluated future plans for our older and less efficient fossil fuel generating units and have retired the PIPP and the Pleasant Prairie power plant. In addition, a severance liability was recorded in other current liabilities on our balance sheets within the utility segment related to these plant retirements.



(in millions)
Severance liability at December 31, 2018	$	12.9
Severance payments	(5.3		)
Other	(1.8		)
Total severance liability at June 30, 2019	$	5.8

NOTE 5—COMMON EQUITY

Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to WEC Energy Group in the form of cash dividends, loans, or advances. In addition, Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group or its subsidiaries. See Note 8, Common Equity, in our 2018 Annual Report on Form 10-K for additional information on these and other restrictions.

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

NOTE 6—SHORT-TERM DEBT AND LINES OF CREDIT

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



(in millions, except percentages)	June 30, 2019			December 31, 2018
Commercial paper
Amount outstanding	$	39.5		$	134.9
Weighted-average interest rate on amounts outstanding	2.50		%	2.96		%

Our average amount of commercial paper borrowings based on daily outstanding balances during the six months ended June 30, 2019 was $62.2 million with a weighted-average interest rate during the period of 2.68%.

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



(in millions)	Maturity	June 30, 2019
Revolving credit facility	October 2022	$	500.0

Less:
Letters of credit issued inside credit facility		$	1.2
Commercial paper outstanding		39.5
Available capacity under existing agreement		$	459.3

NOTE 7—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.

As required, we adopted Topic 842 effective 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.



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•	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 are classified as finance 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 Accounting Standards Codification 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, resulting in none of our land easements being treated as leases upon our adoption of Topic 842.

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. We did not require a cumulative-effect adjustment upon adoption of Topic 842.

Both the right of use assets and related lease liabilities related to our operating leases that were recorded upon adoption of Topic 842 were $13.0 million. Regarding our finance 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 finance lease assets and related liability amounts recorded on our balance sheets.

Obligations Under Operating Leases

We have recorded right of use assets and lease liabilities associated with the following operating leases.


•	Land we are leasing related to our Rothschild biomass plant through June 2051.


•	Rail cars we are leasing to transport coal to various generating facilities through February 2021.


•	Various office space leases.

The operating leases generally require us to pay property taxes, insurance premiums, and operating and maintenance costs associated with the leased property. Many of our leases contain options to renew past the initial term, as set forth in the lease agreement.

Obligations Under Finance Leases

We are the obligor under a power purchase contract with an unaffiliated third party and we lease power plants from We Power. Under finance lease accounting, we have recorded the leased plants and corresponding obligations as right of use assets and lease liabilities on our balance sheets. We treat these agreements as operating leases for rate-making purposes.

Prior to our adoption of Topic 842 on January 1, 2019, we accounted for these finance leases under Topic 980-840, Regulated Operations – Leases, as follows:


•	We recorded our minimum lease payments under the power purchase contract as purchased power expense on our income statement.


•	We recorded our minimum lease payments under our leases with We Power as rent expense in other operation and maintenance in our income statements.



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•	We recorded the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under finance lease accounting rules as a deferred regulatory asset on our balance sheets.

In conjunction with our adoption of Topic 842, while the timing of expense recognition related to our finance leases did not change, the classification of the lease expense changed as follows:


•	Effective January 1, 2019, the minimum lease payments under the power purchase contract were no longer classified within purchased power expense, but were instead recorded as a component of depreciation and amortization and interest expense in accordance with Topic 980-842, Regulated Operations – Leases.


•	Similarly, the lease payments related to our leases with We Power were no longer classified as rent expense within other operation and maintenance in our income statements, but were also divided between amortization expense and interest expense in accordance with Topic 980-842.


•	In order to ensure the timing of lease expense did not change for these finance leases upon adoption of Topic 842, and still resembled the expense recognition pattern of an operating lease, in accordance with Topic 980-842 the amortization of the right of use assets was modified from what would typically be recorded for a finance lease under Topic 842.


•	We continue to record the difference between the minimum lease payments and the sum of imputed interest and unadjusted amortization costs calculated under the finance lease accounting rules as a deferred regulatory asset on our balance sheets.

Power Purchase Commitment

In 1997, we entered into a 25-year power purchase contract with an unaffiliated independent power producer. The contract, for 236 MWs 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 ten years, purchase the generating facility at fair market value, or allow the contract to expire. We originally recorded this leased facility and corresponding obligation on our balance sheets at the estimated fair value of the plant's electric generating facilities.

As previously discussed, we treat the long-term power purchase contract as an operating lease for rate-making purposes. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under finance lease accounting rules as a deferred regulatory asset on our balance sheets. Minimum lease payments are a function of the 236 MWs of firm capacity we receive from the plant and the fixed monthly capacity rate published in the lease. Due to the timing and the amounts of the minimum lease payments, the regulatory asset increased to $78.5 million in 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 finance lease was $21.0 million at June 30, 2019, 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. 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 Wisconsin's 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 $129.4 million in the year 2021 for PWGS 1 and to approximately $126.0 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 finance leases for the units was $626.7 million as of June 30, 2019, and will decrease to zero over the remaining lives of the contracts.

The only variability associated with the PWGS lease payments relates to the potential for future changes in We Power's tax or interest rates, as the positive or negative impact of these changes are generally passed along to us, and subsequently to our customers. Because variability in the lease payments is dependent upon a rate (interest rate or tax rate), the lease payments are considered unavoidable under Topic 842, and are included in the measurement of the right of use asset and lease liability, consistent with how they were treated under Topic 840.

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.



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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 generating units, 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 lease payments are expected to be recovered through our rates, as supported by Wisconsin's 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 $524.7 million in the year 2028 for ER 1 and to approximately $431.1 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 finance leases was $2,210.7 million as of June 30, 2019, and will decrease to zero over the remaining lives of the contracts.

The only variability associated with the ER lease payments relates to the potential for future changes in We Power's tax or interest rates, as the positive or negative impact of these changes are generally passed along to us, and subsequently to our customers. Because variability in the lease payments is dependent upon a rate (interest rate or tax rate), the lease payments are considered unavoidable under Topic 842, and are included in the measurement of the right of use asset and lease liability, consistent with how they were treated under Topic 840.

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.

Amounts Recognized in the Financial Statements

The components of lease expense and supplemental cash flow information related to our leases for the three and six months ended June 30 are as follows:



	Three Months Ended June 30				Six Months Ended June 30
(in millions)	2019		2018		2019			2018
Long-term power purchase commitment	$	2.1	$	1.9	$	4.1		$	3.8
We Power leases	90.6		91.8		182.4			183.6
Total finance/capital lease expense ⁽¹⁾	$	92.7	$	93.7	$	186.5		$	187.4

Operating lease expense ⁽²⁾	0.6		0.7		1.3			1.4
Total lease expense	$	93.3	$	94.4	$	187.8		$	188.8

Other information

Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows for finance/capital leases ⁽³⁾					$	176.0		$	191.1
Operating cash flows for operating leases					$	1.3		$	1.4
Financing cash flows for finance leases ⁽³⁾					$	24.4		$	—

Non-cash activity – right of use assets obtained in exchange for operating lease liabilities					$	13.0

Weighted-average remaining lease term – finance leases					19.1 years
Weighted-average remaining lease term – operating leases					23.0 years

Weighted-average discount rate – finance leases ⁽⁴⁾					13.9		%
Weighted average discount rate – operating leases ⁽⁴⁾					4.4		%

⁽¹⁾

For the three and six months ended June 30, 2019, total finance lease expense included amortization of right of use assets in the amount of $4.8 million and $10.5 million (included in depreciation and amortization expense), respectively, and interest on lease liabilities of $87.9 million and $176.0 million (included in interest expense), respectively. For each of the three and six months ended June 30, 2018, total capital lease cost



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related to the long-term power purchase agreement was included in cost of sales and total capital lease cost related to the PWGS and ERGS units was included in other operation and maintenance.


⁽²⁾	Operating lease expense was included as a component of operation and maintenance for the three and six months ended June 30, 2019 and 2018.


⁽³⁾	Prior to our adoption of Topic 842 on January 1, 2019, all cash flows related to capital leases were recorded as a component of operating cash flows.


⁽⁴⁾	Because our operating leases do not provide an implicit rate of return, we used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments for our operating leases. For our financing leases, the rate implicit in each lease was readily determinable.

The following table summarizes our finance lease right of use assets, which were included in property, plant and equipment on our balance sheets:



(in millions)	June 30, 2019			December 31, 2018
Long-term power purchase commitment
Under finance/capital lease	$	140.3		$	140.3
Accumulated amortization	(123.7		)	(120.9		)
Total long-term power purchase commitment	$	16.6		$	19.4

PWGS
Under finance/capital lease	$	740.0		$	736.9
Accumulated amortization	(351.7		)	(335.9		)
Total PWGS	$	388.3		$	401.0

ERGS
Under finance/capital lease	$	2,188.8		$	2,166.3
Accumulated amortization	(635.8		)	(598.8		)
Total ERGS	$	1,553.0		$	1,567.5

Total finance lease right of use assets/capital lease assets	$	1,957.9		$	1,987.9

Right of use assets related to operating leases were $12.0 million at June 30, 2019, and were included in other long-term assets on our balance sheets.

Future minimum lease payments under our finance and operating leases and the present value of our net minimum lease payments as of June 30, 2019 were as follows:



(in millions)	Total Operating Leases			Power Purchase Commitment			PWGS			ERGS			Total Finance Leases
Six months ending December 31, 2019	$	1.3		$	4.1		$	49.0		$	146.8		$	199.9
2020	2.7			8.8			98.1			293.6			400.5
2021	0.7			9.4			98.1			293.6			401.1
2022	0.6			4.2			98.1			293.5			395.8
2023	0.5			—			98.1			293.3			391.4
2024	0.5			—			98.0			293.3			391.3
Thereafter	13.5			—			678.7			4,547.0			5,225.7
Total minimum lease payments	19.8			26.5			1,218.1			6,161.1			7,405.7
Less: Interest	(7.8		)	(5.5		)	(591.4		)	(3,950.4		)	(4,547.3		)
Present value of minimum lease payments	12.0			21.0			626.7			2,210.7			2,858.4
Less: Short-term lease liabilities	(2.3		)	(5.6		)	(23.8		)	(24.4		)	(53.8		)
Long-term lease liabilities	$	9.7		$	15.4		$	602.9		$	2,186.3		$	2,804.6

Short-term and long-term lease liabilities related to operating leases were included in other current liabilities and other long-term liabilities on the balance sheets, respectively.



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Significant Judgments and Other Information

We are currently party to several easement agreements that allow us access to land we do not own for the purpose of constructing and maintaining certain electric power and natural gas equipment. The majority of payments we make related to easements relate to our wind farms. We have not classified our easements as leases because we view the entire parcel of land specified in our easement agreements to be the identified asset, not just that portion of the parcel that contains our easement. As such, we have concluded that we do not control the use of an identified asset related to our easement agreements, nor do we obtain substantially all of the economic benefits associated with these shared-use assets.

As of August 6, 2019, we have not entered into any material operating leases that have not yet commenced.

NOTE 8—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:



(in millions)	June 30, 2019		December 31, 2018
Materials and supplies	$	147.2	$	146.1
Fossil fuel	59.2		58.7
Natural gas in storage	21.6		36.6
Total	$	228.0	$	241.4

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

NOTE 9—INCOME TAXES

The provision for income taxes 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:



	Three Months Ended June 30, 2019					Three Months Ended June 30, 2018
(in millions)	Amount			Effective Tax Rate		Amount			Effective Tax Rate
Statutory federal income tax	$	14.4		21.0	%	$	18.9		21.0	%
State income taxes net of federal tax benefit	4.5			6.6	%	5.8			6.4	%
Tax repairs	(30.5		)	(44.3	)%	(22.5		)	(24.7	)%
Federal excess deferred tax amortization	(3.8		)	(5.6	)%	(4.4		)	(4.8	)%
Wind production tax credits	(2.2		)	(3.2	)%	(2.3		)	(2.6	)%
Other	1.3			1.8	%	2.0			1.9	%
Total income tax benefit	$	(16.3	)	(23.7	)%	$	(2.5	)	(2.8	)%



	Six Months Ended June 30, 2019					Six Months Ended June 30, 2018
(in millions)	Amount			Effective Tax Rate		Amount			Effective Tax Rate
Statutory federal income tax	$	37.1		21.0	%	$	40.4		21.0	%
State income taxes net of federal tax benefit	11.6			6.6	%	12.5			6.5	%
Tax repairs	(60.1		)	(33.9	)%	(48.0		)	(24.9	)%
Federal excess deferred tax amortization	(10.0		)	(5.7	)%	(9.8		)	(5.1	)%
Wind production tax credits	(5.0		)	(2.8	)%	(5.5		)	(2.9	)%
Other	3.6			1.9	%	4.3			2.2	%
Total income tax benefit	$	(22.8	)	(12.9	)%	$	(6.1	)	(3.2	)%

The effective tax rates of (23.7)% and (12.9)% for the three and six months ended June 30, 2019, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to the flow through of tax repairs in connection with the Wisconsin rate settlement, the impact of the Tax Legislation, and wind production tax credits, partially offset by state income taxes.

The effective tax rates of (2.8)% and (3.2)% for the three and six months ended June 30, 2018, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to the flow through of tax repairs in connection with the Wisconsin rate settlement, the impact of the Tax Legislation, and wind production tax credits, partially offset by state income taxes.



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The Tax Legislation, signed into law in December 2017, required our regulated utilities to remeasure their deferred income taxes and we began to amortize the resulting excess deferred income taxes beginning in 2018 in accordance with normalization requirements (see federal excess deferred tax amortization line above). See Note 18, Regulatory Environment, for more information about the Wisconsin rate settlement.

NOTE 10—FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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

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

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



	June 30, 2019
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	0.3	$	—	$	—	$	0.3
FTRs	—		—		5.8		5.8
Coal contracts	—		0.1		—		0.1
Total derivative assets	$	0.3	$	0.1	$	5.8	$	6.2

Derivative liabilities
Natural gas contracts	$	7.9	$	—	$	—	$	7.9
Coal contracts	—		0.1		—		0.1
Total derivative liabilities	$	7.9	$	0.1	$	—	$	8.0



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	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

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 and Operating Reserves Markets.

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



	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2019			2018			2019			2018
Balance at the beginning of the period	$	2.0		$	0.8		$	4.4		$	2.4
Purchases	6.8			9.4			6.8			9.4
Settlements	(3.0		)	(1.5		)	(5.4		)	(3.1		)
Balance at the end of the period	$	5.8		$	8.7		$	5.8		$	8.7

Fair Value of Financial Instruments

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



	June 30, 2019				December 31, 2018
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock	$	30.4	$	28.2	$	30.4	$	28.3
Long-term debt, including current portion	2,710.4		3,068.9		2,709.6		2,881.6

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

NOTE 11—DERIVATIVE INSTRUMENTS

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

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



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



	June 30, 2019				December 31, 2018
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	0.3	$	7.5	$	0.7	$	1.2
FTRs	5.8		—		4.4		—
Coal contracts	0.1		0.1		—		0.1
Total other current *	$	6.2	$	7.6	$	5.1	$	1.3

Other long-term *
Natural gas contracts	$	—	$	0.4	$	—	$	—
Total	$	6.2	$	8.0	$	5.1	$	1.3


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

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



	Three Months Ended June 30, 2019				Three Months Ended June 30, 2018
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	13.6 Dth	$	(1.1	)	12.0 Dth	$	(0.6	)
Petroleum products contracts	— gallons	—			1.1 gallons	0.2
FTRs	5.6 MWh	0.5			4.8 MWh	0.9
Total		$	(0.6	)		$	0.5



	Six Months Ended June 30, 2019				Six Months Ended June 30, 2018
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	31.7 Dth	$	(2.5	)	23.7 Dth	$	(2.4	)
Petroleum products contracts	— gallons	—			2.5 gallons	0.6
FTRs	11.1 MWh	2.1			10.6 MWh	1.7
Total		$	(0.4	)		$	(0.1	)

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At June 30, 2019 and December 31, 2018, we had posted cash collateral of $10.3 million and $1.1 million, respectively, in our margin accounts. These amounts were recorded on our balance sheets in other current assets.

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



	June 30, 2019							December 31, 2018
(in millions)	Derivative Assets			Derivative Liabilities				Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	6.2		$	8.0			$	5.1		$	1.3
Gross amount not offset on the balance sheet	(0.3		)	(7.9		)	⁽¹⁾	(0.6		)	(1.3		)	⁽²⁾
Net amount	$	5.9		$	0.1			$	4.5		$	—


⁽¹⁾	Includes cash collateral posted of $7.6 million.


⁽²⁾	Includes cash collateral posted of $0.7 million.



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NOTE 12—GUARANTEES

As of June 30, 2019, 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.

NOTE 13—EMPLOYEE BENEFITS

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



	Pension Costs
	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2019			2018			2019			2018
Service cost	$	2.5		$	3.3		$	6.3		$	6.6
Interest cost	11.1			10.5			22.6			21.1
Expected return on plan assets	(18.0		)	(18.6		)	(36.2		)	(37.6		)
Amortization of prior service cost	0.1			0.2			0.2			0.4
Amortization of net actuarial loss	6.8			9.6			14.0			19.0
Net periodic benefit cost	$	2.5		$	5.0		$	6.9		$	9.5



	OPEB Costs
	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2019			2018			2019			2018
Service cost	$	1.0		$	1.7		$	2.2		$	3.5
Interest cost	2.4			2.7			4.8			5.5
Expected return on plan assets	(3.6		)	(3.9		)	(7.1		)	(7.8		)
Amortization of prior service credit	(0.5		)	(0.5		)	(1.0		)	(1.1		)
Amortization of net actuarial gain	(0.7		)	—			(1.1		)	—
Net periodic benefit (credit) cost	$	(1.4	)	$	—		$	(2.2	)	$	0.1

During the six months ended June 30, 2019, we made contributions and payments of $2.5 million related to our pension plans and $0.7 million related to our OPEB plans. We expect to make contributions and payments of $1.3 million related to our pension plans and $2.9 million related to our OPEB plans during the remainder of 2019, dependent upon various factors affecting us, including our liquidity position and the effects of the Tax Legislation.

NOTE 14—SEGMENT INFORMATION

We use operating income to measure segment profitability and to allocate resources to our businesses. At June 30, 2019, 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. Prior to April 1, 2019, we also provided electric service to Tilden, who owns an iron ore mine in the Upper Peninsula of Michigan. This customer was transferred to UMERC on April 1, 2019 as UMERC's new generation in the Upper Peninsula of Michigan is now operational. In addition, our electric utility operations include our steam operations, which produce, distribute, and sell steam to customers in metropolitan Milwaukee. 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.

Prior to October 2018, 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. No significant items were reported in the other segment during the six months ended June 30, 2019 and 2018.



06/30/2019 Form 10-Q	19	Wisconsin Electric Power Company

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NOTE 15—VARIABLE INTEREST ENTITIES

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

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

Power Purchase Agreement

We have a power purchase agreement that represents a variable interest. This agreement is for 236 MWs of firm capacity from a natural gas-fired cogeneration facility, and we account for it as a finance 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 power purchase agreement.

We have $26.5 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 these capacity payments.

NOTE 16—COMMITMENTS AND CONTINGENCIES

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

Unconditional Purchase Obligations

We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of June 30, 2019, were approximately $9.9 billion.

Environmental Matters

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

Air Quality

National Ambient Air Quality Standards

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



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Mercury and Air Toxics Standards

In December 2018, the EPA proposed to revise the Supplemental Cost Finding for the MATS rule as well as the CAA required RTR. The EPA was required by the United States 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.

Climate Change

In July 2019, the EPA published the ACE rule, which provides existing coal-fired generating units with standards for achieving GHG emission reductions. The rule was finalized in conjunction with two other separate and distinct rulemakings, (1) the repeal of the Clean Power Plan, and (2) revised implementing regulations for ACE, ongoing emissions guidelines, and all future emission guidelines for existing sources issued under CAA section 111(d). Every state's plan to implement ACE would need to focus on reducing GHG emissions by improving the efficiency of fossil-fueled power plants. The rule is being litigated.

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

In April 2019, WEC Energy Group issued a climate report, which analyzes its GHG reduction goals with respect to international efforts to limit future global temperature increases to less than two degrees Celsius. WEC Energy Group will continue to update this analysis as climate-change policies and relevant technologies evolve over time with a focus on preserving fuel diversity, lowering costs for customers, and reducing long-term GHG emissions.

WEC Energy Group's plan, which includes us, is to work with its industry peers, environmental groups, public policy makers, and customers, with goals of reducing CO₂ emissions by approximately 40% and 80% below 2005 levels by 2030 and 2050, respectively. As a result of WEC Energy Group's generation reshaping plan, we retired approximately 1,500 MW of coal generation since the beginning of 2018. This plan consisted of the March 31, 2019 retirement of the PIPP as well as the 2018 retirement of the Pleasant Prairie power plant. See Note 4, Property, Plant, and Equipment, for more information on the retirement of the PIPP.

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 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.

We have received BTA determinations for Valley power plant. 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 provided information to the Wisconsin Department of Natural Resources and the MDEQ about generating unit retirements. Following discussions with the MDEQ, in January 2019, we submitted a signed certification stating that the PIPP would be retired no later than June 1, 2019. The PIPP was retired on March 31, 2019.

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



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Steam Electric Effluent Limitation Guidelines

The EPA's final 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 BATW and wet FGD wastewater.

This rule is being litigated, and various petitions challenging it were consolidated 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.

As a result of past capital investments completed to address ELG compliance, we believe our fleet overall is well positioned to meet the regulations. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, in its current form, the ELG rule would require additional wastewater treatment retrofits and the installation of other equipment to minimize process water use. Due to completed generating unit retirements, we believe the only facilities that would require bottom ash system modifications are OC 7 and OC 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:



(in millions)	June 30, 2019		December 31, 2018
Regulatory assets	$	23.6	$	24.2
Reserves for future remediation *	13.2		13.2


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

Enforcement and Litigation Matters

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



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NOTE 17—SUPPLEMENTAL CASH FLOW INFORMATION



	Six Months Ended June 30
(in millions)	2019			2018
Cash (paid) for interest, net of amount capitalized *	$	(239.1	)	$	(57.8	)
Cash (paid) for income taxes, net	(10.6		)	(8.2		)
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs	6.6			4.5
Accounts payable related to the transfer of certain software assets from affiliates	—			7.5
Accounts receivable related to the transfer of certain software assets to affiliates	—			5.4

On January 1, 2019, we adopted ASU 2016-02, Leases (Topic 842). This ASU required us to prospectively change the classification of our finance lease payments on the income statement. As a result, during the six months ended June 30, 2019, we classified the interest component of our finance lease payments as cash paid for interest since it was included in interest expense on the income statement. However, prior to our adoption of Topic 842, the interest component was not considered cash paid for interest since it was not included in interest expense on the income statement. See Note 7, Leases, for more information on Topic 842 and our finance leases.

NOTE 18—REGULATORY ENVIRONMENT

2020 and 2021 Rates

In March 2019, we filed an application with the PSCW to increase our retail electric, natural gas, and steam rates, effective January 1, 2020. Our proposal is targeting an effective electric rate increase of approximately $83 million (2.9%) in 2020 and an additional increase of $83 million (2.9%) in 2021. For our natural gas and steam customers, our proposal is targeting effective rate increases of approximately $15 million (3.9%) and $1 million (4.5%), respectively, in 2020, with no additional increases in 2021. Our proposal reflects a ROE of 10.35% and a common equity component average of 52.0% on a financial basis. We also proposed to continue having an earnings sharing mechanism through 2021.

Our proposed increase in electric rates was driven by higher transmission charges, recovery of SSR revenues that were assumed in our 2015 rate order but were not received, and an increase in costs associated with a purchased power agreement previously approved by the PSCW. Our proposed electric rates reflect our request to partially offset these increases with approximately $111 million of previously deferred tax benefits from the Tax Legislation. Our proposal also includes our request for approval to continue collecting the carrying value of the Pleasant Prairie power plant and the PIPP using the current approved composite depreciation rates, in addition to a return on the remaining carrying value of the plants.

The proposed increase at our natural gas utility was driven by continued investment in our natural gas distribution system.

A final order is expected from the PSCW by the end of 2019, with rates effective January 1, 2020.

2018 and 2019 Rates

During April 2017, we, along with WG and Wisconsin Public Service Corporation, 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.



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

Solar Generation Project

On August 1, 2019, we, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire an ownership interest in Badger Hollow II, a solar project that will be located in Iowa County, Wisconsin. Subject to receipt of the PSCW's approval, we will own 100 MW of the output of this project. Our share of the cost of this project is estimated to be $130 million. Commercial operation for Badger Hollow II is targeted for the end of 2021.

NOTE 19—NEW ACCOUNTING PRONOUNCEMENTS

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.

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 financial statements.

Disclosure Requirements for Defined Benefit Plans

In August 2018, the FASB issued ASU 2018-14, Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans. The pronouncement modifies the disclosure requirements for defined benefit pension and other postretirement benefit plans. The guidance removes disclosures that are no longer considered cost beneficial, clarifies the specific requirements of disclosures and adds disclosure requirements identified as relevant. The modifications affect annual period disclosures and must be applied on a retrospective basis to all periods presented. The guidance will be effective for annual reporting periods ending after December 15, 2020, with early adoption permitted. We are currently evaluating the effects of this pronouncement on our Notes to Consolidated Financial Statements.



06/30/2019 Form 10-Q	24	Wisconsin Electric Power Company

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

CORPORATE DEVELOPMENTS

The following discussion should be read in conjunction with the accompanying financial statements and related notes and our 2018 Annual Report on Form 10-K.

Introduction

We are a wholly owned subsidiary of WEC Energy Group, and derive revenues primarily from the distribution and sale of electricity and natural gas to retail customers in Wisconsin. We conduct our business primarily through our utility reportable segment. See Note 14, Segment Information, for more information on our reportable business segments.

Corporate Strategy

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

Reshaping Our Generation Fleet

WEC Energy Group has developed and is executing a plan to reshape its generation portfolio. This plan will balance reliability and customer cost with environmental stewardship. Taken as a whole, this plan should reduce costs to customers, preserve fuel diversity, and lower carbon emissions. Generation reshaping includes retiring older fossil fuel generation units, building state-of-the-art natural gas generation, and investing in cost-effective zero-carbon generation with a goal of reducing CO₂ emissions by approximately 40% below 2005 levels by 2030 and by approximately 80% below 2005 levels by 2050. WEC Energy Group has retired approximately 1,800 MW of coal generation since the beginning of 2018 across its electric utilities, and expects to add additional natural gas-fired generating units and renewable generation, including utility-scale solar projects. 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 as it may take several years to finalize long-term plans for the site. We retired the Presque Isle power plant (PIPP) in March 2019. See Note 4, Property, Plant, and Equipment, for information related to the PIPP retirement.

As part of its commitment to invest in zero-carbon generation, WEC Energy Group plans to invest in utility scale solar of up to 350 MW within its Wisconsin segment, which includes us. We have partnered with an unaffiliated utility to acquire an ownership interest in Badger Hollow Solar Farm II, a solar project that will be located in Iowa County, Wisconsin. Subject to PSCW approval, we will own 100 MW of the output of the project. Commercial operation is targeted for the end of 2021. 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 utility owned 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 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 in 2018 by PA Consulting Group, an independent consulting firm, as the most reliable utility in the Midwest for the eighth year in a row. We Energies is the trade name under which we and WG, another wholly owned subsidiary of WEC Energy Group, operate.

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



06/30/2019 Form 10-Q	25	Wisconsin Electric Power Company

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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.

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

THREE MONTHS ENDED JUNE 30, 2019

Consolidated Earnings

The following table compares our consolidated results for the second quarter of 2019 with the second quarter of 2018, including favorable or better, "B", and unfavorable or worse, "W", variances:



	Three Months Ended June 30
(in millions)	2019			2018			B (W)			Change Related to Flow Through of Tax Repairs			Change Related to Adoption of New Lease Guidance (Topic 842)			Remaining Change B (W)
Operating revenues	$	791.7		$	856.2		$	(64.5	)	$	(4.6	)	$	—		$	(59.9	)
Cost of sales	253.5			270.9			17.4			—			2.1			15.3
Other operation and maintenance	234.3			366.6			132.3			(6.5		)	90.6			48.2
Depreciation and amortization	95.2			86.9			(8.3		)	—			(4.8		)	(3.5		)
Property and revenue taxes	26.1			27.3			1.2			—			—			1.2
Operating income	182.6			104.5			78.1			(11.1		)	87.9			1.3
Other income, net	5.9			15.3			(9.4		)	—			—			(9.4		)
Interest expense	119.6			29.2			(90.4		)	—			(87.9		)	(2.5		)
Income before income taxes	68.9			90.6			(21.7		)	(11.1		)	—			(10.6		)
Income tax benefit	(16.3		)	(2.5		)	13.8			11.1			—			2.7
Preferred stock dividend requirements	0.3			0.3			—			—			—			—
Net income attributed to common shareholder	$	84.9		$	92.8		$	(7.9	)	$	—		$	—		$	(7.9	)

Our consolidated earnings decreased $7.9 million during the second quarter of 2019, compared with the same quarter in 2018. The table above shows the income statement impacts associated with the flow through of tax repairs beginning January 1, 2018 and the adoption of ASU 2016-02, Leases (Topic 842), effective January 1, 2019. As shown in the table above, the changes related to these items had no impact on net income attributed to common shareholder, but did significantly impact our operating income. See Note 18, Regulatory Environment, for more information on the flow through of tax repairs and Note 7, Leases, for more information on the adoption of Topic 842. See below for additional information on the $7.9 million decrease in consolidated earnings.

Non-GAAP Financial Measures

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

We believe that electric and natural gas margins provide a 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, the presentation of electric and natural gas margins herein is intended to provide supplemental information for investors regarding our operating performance.

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of our utility segment operating performance. Our utility segment operating income for the three months ended June 30, 2019 and 2018 was $182.6 million and $104.5 million, respectively. The operating income discussion below includes a table that provides the calculation of electric margins and natural gas margins, along with a reconciliation to utility segment operating income.



06/30/2019 Form 10-Q	27	Wisconsin Electric Power Company

Table of Contents

Utility Segment Contribution to Operating Income



	Three Months Ended June 30
(in millions)	2019		2018		B (W)
Electric revenues	$	726.6	$	787.3	$	(60.7	)
Fuel and purchased power	218.1		232.5		14.4
Total electric margins	508.5		554.8		(46.3		)

Natural gas revenues	65.1		68.9		(3.8		)
Cost of natural gas sold	35.4		38.4		3.0
Total natural gas margins	29.7		30.5		(0.8		)

Total electric and natural gas margins	538.2		585.3		(47.1		)

Other operation and maintenance	234.3		366.6		132.3
Depreciation and amortization	95.2		86.9		(8.3		)
Property and revenue taxes	26.1		27.3		1.2
Operating income	$	182.6	$	104.5	$	78.1

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



	Three Months Ended June 30
(in millions)	2019		2018		B (W)
Operation and maintenance not included in line items below	$	79.8	$	108.0	$	28.2
We Power ⁽¹⁾	34.2		125.9		91.7
Transmission ⁽²⁾	62.6		66.1		3.5
Transmission expense related to the flow through of tax repairs ⁽³⁾	16.5		10.0		(6.5		)
Transmission expense related to Tax Legislation ⁽⁴⁾	17.5		33.8		16.3
Regulatory amortizations and other pass through expenses ⁽⁵⁾	23.7		22.8		(0.9		)
Total other operation and maintenance	$	234.3	$	366.6	$	132.3

⁽¹⁾

Represents costs associated with the We Power generation units, including operating and maintenance costs we recognized. For the three months ended June 30, 2018, the amount also included the lease payments that were billed from We Power to us and then recovered in our rates. We adopted ASU 2016-02, Leases (Topic 842) effective January 1, 2019, which revised the previous guidance regarding the accounting for leases. As a result of this adoption, for the three months ended June 30, 2019, the $90.6 million of lease expense related to the We Power leases was no longer classified within other operation and maintenance, but was instead recorded as $3.6 million and $87.0 million of depreciation and amortization and interest expense, respectively, in accordance with Topic 842.

During the three months ended June 30, 2019, $45.6 million of operating and maintenance costs were billed to or incurred by us related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset. During the three months ended June 30, 2018, $126.1 million of both lease and operating and maintenance costs were billed to or incurred by us related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

⁽²⁾

Represents transmission expense that we are authorized to collect in rates, in accordance with the PSCW's approval of escrow accounting for our ATC and MISO network transmission expenses. As a result, we defer as a regulatory asset or liability, the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the three months ended June 30, 2019 and 2018, $80.5 million and $64.2 million, respectively, of costs were billed to us by transmission providers.


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


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



06/30/2019 Form 10-Q	28	Wisconsin Electric Power Company

Table of Contents

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



	Three Months Ended June 30
	MWh (in thousands)
Electric Sales Volumes	2019	2018	B (W)
Customer Class
Residential	1,682.0	1,855.0	(173.0	)
Small commercial and industrial	2,048.4	2,165.0	(116.6	)
Large commercial and industrial	1,693.2	2,133.7	(440.5	)
Other	33.1	32.0	1.1
Total retail	5,456.7	6,185.7	(729.0	)
Wholesale	296.6	394.2	(97.6	)
Resale	1,604.5	560.3	1,044.2
Total sales in MWh	7,357.8	7,140.2	217.6



	Three Months Ended June 30
	Therms (in millions)
Natural Gas Sales Volumes	2019	2018	B (W)
Customer Class
Residential	55.9	59.0	(3.1	)
Commercial and industrial	31.3	35.0	(3.7	)
Total retail	87.2	94.0	(6.8	)
Transport	79.3	77.7	1.6
Total sales in therms	166.5	171.7	(5.2	)



	Three Months Ended June 30
	Degree Days
Weather *	2019	2018	B (W)
Heating (921 normal)	973	1,023	(4.9	)%
Cooling (166 normal)	76	217	(65.0	)%


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

Electric Utility Margins

Electric utility margins decreased $46.3 million during the second quarter of 2019, compared with the same quarter in 2018. The significant factors impacting the lower electric utility margins were:


•	A $27.0 million decrease related to lower retail sales volumes during the second quarter of 2019, primarily driven by unfavorable weather. As measured by cooling degree days, the second quarter of 2019 was 65.0% cooler than the same quarter in 2018. As measured by heating degree days, the second quarter of 2019 was 4.9% warmer than the same quarter in 2018.

•

A $16.3 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. This decrease in margins was offset by a corresponding decrease in transmission expense. We received the PSCW order in May 2018, which required us to use 80% of the current 2018 and 2019 tax benefits to reduce certain regulatory assets. Prior to receiving the order, we recorded all of the expected benefits related to the Tax Legislation as if they would be returned to customers through bill credits, which resulted in a decrease in revenues in the first quarter of 2018. After receiving the order during the second quarter of 2018, we reversed a portion of this decrease in revenues we had assumed would be returned to customers as bill credits and instead applied the tax savings by reducing the regulatory assets.


•	A $4.6 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 18, Regulatory Environment, for more information.



06/30/2019 Form 10-Q	29	Wisconsin Electric Power Company

Table of Contents


•	A $4.6 million decrease in wholesale margins driven by lower sales volumes to UMERC. UMERC's new natural gas-fired generation in the Upper Peninsula of Michigan began commercial operation on March 31, 2019, at which time we ceased providing wholesale services to UMERC.


•	A $4.0 million decrease in margins related to Tilden, who owns an iron ore mine in the Upper Peninsula of Michigan. Tilden, who was our customer, became a customer of UMERC once the new generation solution began commercial operation on March 31, 2019.

These decreases in margins were partially offset by a $10.3 million quarter-over-quarter positive impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, our margins are impacted by under- or over-collections of certain fuel and purchased power costs that are less than a 2% price variance from the costs included in rates, and the remaining variance that exceeds the 2% variance is deferred.

Natural Gas Utility Margins

Natural gas utility margins decreased $0.8 million during the second quarter of 2019, compared with the same quarter in 2018. The most significant factor impacting the decrease in natural gas utility margins was lower sales volumes, primarily driven by unfavorable weather during the second quarter of 2019, compared with the same quarter in 2018.

Operating Income

Operating income at the utility segment increased $78.1 million during the second quarter of 2019, compared with the same quarter in 2018. This increase was driven by $125.2 million of lower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes), partially offset by the $47.1 million decrease in margins discussed above.

The significant factors impacting the decrease in operating expenses during the second quarter of 2019, compared with the same quarter in 2018, were:

•

A $90.6 million decrease in other operation and maintenance resulting from the adoption of the new lease guidance. As discussed in the other operation and maintenance table above, the adoption of Topic 842, effective January 1, 2019, required us to change the income statement classification of our lease payments related to the We Power leases. For the second quarter of 2019, the lease expense related to the We Power leases was no longer classified within other operation and maintenance, but was instead recorded as a component of depreciation and amortization and interest expense in accordance with Topic 842.


•	An $11.5 million decrease in operation and maintenance expenses across all of our plants, in part due to the retirements of the Pleasant Prairie power plant in April 2018 and the PIPP in March 2019. This resulted in lower maintenance and labor costs during the second quarter of 2019. See Note 4, Property, Plant, and Equipment, for more information on the retirement of the PIPP.


•	A $9.9 million decrease in operation and maintenance expense due to a 2018 item that was offset in other income, net and had no impact on net income for the quarter.

•

A $9.8 million net decrease in transmission expense. This was primarily driven by a $16.3 million decrease related to the May 2018 order from the PSCW related to our required treatment of the benefits associated with the Tax Legislation, which was offset by a corresponding decrease in margins, as previously discussed. Partially offsetting this decrease to transmission expense was a $6.5 million increase related to the flow through of tax repairs. Both changes in transmission expense are discussed in the other operation and maintenance table above.

These decreases in operating expenses were partially offset by an $8.3 million increase in depreciation and amortization, driven by capital expenditures as we continue to execute on our capital plan and additional expense recognized related to the adoption of Topic 842, as discussed in the other operation and maintenance table above.



06/30/2019 Form 10-Q	30	Wisconsin Electric Power Company

Table of Contents

Consolidated Other Income, Net



	Three Months Ended June 30
(in millions)	2019		2018		B (W)
AFUDC – Equity	$	0.8	$	1.0	$	(0.2	)
Non-service components of net periodic benefit costs	2.6		1.2		1.4
Other, net	2.5		13.1		(10.6		)
Other income, net	$	5.9	$	15.3	$	(9.4	)

Other income, net decreased $9.4 million during the second quarter of 2019, compared with the same quarter in 2018. The decrease was primarily driven by a 2018 item that was offset in other operation and maintenance expense and had no impact on net income for the quarter.

Consolidated Interest Expense



	Three Months Ended June 30
(in millions)	2019		2018		B (W)
Interest expense	$	119.6	$	29.2	$	(90.4	)

Interest expense increased $90.4 million during the second quarter of 2019, compared with the same quarter in 2018, primarily due to the adoption of ASU 2016-02, Leases (Topic 842). Effective January 1, 2019, minimum lease payments billed from We Power to us were no longer classified within operation and maintenance, but were instead recorded as a component of depreciation and amortization and interest expense in accordance with Topic 842. As a result of the adoption, for the three months ended June 30, 2019, $87.9 million of minimum lease payments were recorded as interest expense on finance lease liabilities. See Note 7, Leases, for more information.

Consolidated Income Tax Benefit



	Three Months Ended June 30
	2019		2018		B (W)
Effective tax rate	(23.7	)%	(2.8	)%	20.9	%

Our effective tax rate decreased by 20.9% when compared with the second quarter of 2018, primarily due to an increase in the benefit from the flow through of tax repairs in connection with the Wisconsin rate settlement. See Note 9, Income Taxes and Note 18, Regulatory Environment, for more information.



06/30/2019 Form 10-Q	31	Wisconsin Electric Power Company

Table of Contents

SIX MONTHS ENDED JUNE 30, 2019

Consolidated Earnings

The following table compares our consolidated results for the six months ended June 30, 2019 with the six months ended June 30, 2018, including favorable or better, "B", and unfavorable or worse, "W", variances:



	Six Months Ended June 30
(in millions)	2019			2018			B (W)			Change Related to Flow Through of Tax Repairs			Change Related to Adoption of New Lease Guidance (Topic 842)			Remaining Change B (W)
Operating revenues	$	1,752.5		$	1,797.7		$	(45.2	)	$	(9.6	)	$	—		$	(35.6	)
Cost of sales	610.7			627.9			17.2			—			4.1			13.1
Other operation and maintenance	493.2			702.2			209.0			(7.1		)	182.4			33.7
Depreciation and amortization	191.2			172.2			(19.0		)	—			(10.5		)	(8.5		)
Property and revenue taxes	51.9			54.5			2.6			—			—			2.6
Operating income	405.5			240.9			164.6			(16.7		)	176.0			5.3
Other income, net	11.4			11.1			0.3			—			—			0.3
Interest expense	239.5			58.9			(180.6		)	—			(176.0		)	(4.6		)
Income before income taxes	177.4			193.1			(15.7		)	(16.7		)	—			1.0
Income tax benefit	(22.8		)	(6.1		)	16.7			16.7			—			—
Preferred stock dividend requirements	0.6			0.6			—			—			—			—
Net income attributed to common shareholder	$	199.6		$	198.6		$	1.0		$	—		$	—		$	1.0

Our consolidated earnings increased $1.0 million during the six months ended June 30, 2019, compared with the same period in 2018. The table above shows the income statement impacts associated with the flow through of tax repairs beginning January 1, 2018 and the adoption of ASU 2016-02, Leases (Topic 842), effective January 1, 2019. As shown in the table above, the changes related to these items had no impact on net income attributed to common shareholder, but did significantly impact our operating income. See Note 18, Regulatory Environment, for more information on the flow through of tax repairs and Note 7, Leases, for more information on the adoption of Topic 842. See below for additional information on the $1.0 million increase in consolidated earnings.

Non-GAAP Financial Measures

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of our utility segment operating performance. Our utility segment operating income for the six months ended June 30, 2019 and 2018 was $405.5 million and $240.9 million, respectively. The operating income discussion below includes a table that provides the calculation of electric margins and natural gas margins, along with a reconciliation to utility segment operating income.



06/30/2019 Form 10-Q	32	Wisconsin Electric Power Company

Table of Contents

Utility Segment Contribution to Operating Income



	Six Months Ended June 30
(in millions)	2019		2018		B (W)
Electric revenues	$	1,509.1	$	1,567.6	$	(58.5	)
Fuel and purchased power	457.4		484.6		27.2
Total electric margins	1,051.7		1,083.0		(31.3		)

Natural gas revenues	243.4		230.1		13.3
Cost of natural gas sold	153.3		143.3		(10.0		)
Total natural gas margins	90.1		86.8		3.3

Total electric and natural gas margins	1,141.8		1,169.8		(28.0		)

Other operation and maintenance	493.2		702.2		209.0
Depreciation and amortization	191.2		172.2		(19.0		)
Property and revenue taxes	51.9		54.5		2.6
Operating income	$	405.5	$	240.9	$	164.6

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



	Six Months Ended June 30
(in millions)	2019		2018		B (W)
Operation and maintenance not included in line items below	$	180.8	$	210.0	$	29.2
We Power ⁽¹⁾	70.1		253.1		183.0
Transmission ⁽²⁾	129.3		132.2		2.9
Transmission expense related to the flow through of tax repairs ⁽³⁾	31.8		24.7		(7.1		)
Transmission expense related to Tax Legislation ⁽⁴⁾	32.7		33.8		1.1
Regulatory amortizations and other pass through expenses ⁽⁵⁾	48.5		48.4		(0.1		)
Total other operation and maintenance	$	493.2	$	702.2	$	209.0

⁽¹⁾

Represents costs associated with the We Power generation units, including operating and maintenance costs we recognized. For the six months ended June 30, 2018, the amount also included the lease payments that were billed from We Power to us and then recovered in our rates. We adopted ASU 2016-02, Leases (Topic 842) effective January 1, 2019, which revised the previous guidance regarding the accounting for leases. As a result of this adoption, for the six months ended June 30, 2019, the $182.4 million of lease expense related to the We Power leases was no longer classified within other operation and maintenance, but was instead recorded as $8.2 million and $174.2 million of depreciation and amortization and interest expense, respectively, in accordance with Topic 842.

During the six months ended June 30, 2019, $76.4 million of operating and maintenance costs were billed to or incurred by us related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset. During the six months ended June 30, 2018, $236.7 million of both lease and operating and maintenance costs were billed to or incurred by us related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

⁽²⁾

Represents transmission expense that we are authorized to collect in rates, in accordance with the PSCW's approval of escrow accounting for our ATC and MISO network transmission expenses. As a result, we defer as a regulatory asset or liability the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the six months ended June 30, 2019 and 2018, $161.3 million and $120.5 million, respectively, of costs were billed to us by transmission providers.


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


⁽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 18, Regulatory Environment, for more information.


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



06/30/2019 Form 10-Q	33	Wisconsin Electric Power Company

Table of Contents

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



	Six Months Ended June 30
	MWh (in thousands)
Electric Sales Volumes	2019	2018	B (W)
Customer Class
Residential	3,671.5	3,766.9	(95.4	)
Small commercial and industrial	4,211.7	4,346.6	(134.9	)
Large commercial and industrial	3,713.0	4,159.5	(446.5	)
Other	69.5	69.6	(0.1	)
Total retail	11,665.7	12,342.6	(676.9	)
Wholesale	743.2	820.1	(76.9	)
Resale	2,698.8	2,751.7	(52.9	)
Total sales in MWh	15,107.7	15,914.4	(806.7	)



	Six Months Ended June 30
	Therms (in millions)
Natural Gas Sales Volumes	2019	2018	B (W)
Customer Class
Residential	252.6	236.4	16.2
Commercial and industrial	135.9	131.1	4.8
Total retail	388.5	367.5	21.0
Transport	181.0	172.8	8.2
Total sales in therms	569.5	540.3	29.2



	Six Months Ended June 30
	Degree Days
Weather *	2019	2018	B (W)
Heating (4,192 normal)	4,456	4,248	4.9	%
Cooling (166 normal)	76	217	(65.0	)%


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

Electric Utility Margins

Electric utility margins decreased $31.3 million during the six months ended June 30, 2019, compared with the same period in 2018. The significant factors impacting the lower electric utility margins were:


•	A $19.6 million decrease related to lower retail sales volumes during the six months ended June 30, 2019, primarily driven by unfavorable weather during the second quarter of 2019. As measured by cooling degree days, the six months ended June 30, 2019, were 65.0% cooler than the same period in 2018.


•	A $9.6 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 18, Regulatory Environment, for more information.

Natural Gas Utility Margins

Natural gas utility margins increased $3.3 million during the six months ended June 30, 2019, compared with the same period in 2018. The most significant factor impacting the higher natural gas utility margins was higher sales volumes, primarily driven by colder winter weather, customer growth, and higher use per retail customer during the six months ended June 30, 2019, compared with the same period in 2018.



06/30/2019 Form 10-Q	34	Wisconsin Electric Power Company

Table of Contents

Operating Income

Operating income at the utility segment increased $164.6 million during the six months ended June 30, 2019, compared with the same period in 2018. The increase was driven by $192.6 million of lower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes), partially offset by the $28.0 million net decrease in margins discussed above.

The significant factors impacting the decrease in operating expenses during the six months ended June 30, 2019, compared with the same period in 2018, were:

•

A $182.4 million decrease in other operation and maintenance resulting from the adoption of the new lease guidance. As discussed in the other operation and maintenance table above, the adoption of Topic 842, effective January 1, 2019, required us to change the income statement classification of our lease payments related to the We Power leases. For the six months ended June 30, 2019, the lease expense related to the We Power leases was no longer classified within other operation and maintenance, but was instead recorded as a component of depreciation and amortization and interest expense in accordance with Topic 842.


•	A $23.1 million decrease in operation and maintenance expenses across all of our plants, in part due to the retirements of the Pleasant Prairie power plant in April 2018 and the PIPP in March 2019. This resulted in lower maintenance and labor costs during the six months ended June 30, 2019. See Note 4, Property, Plant, and Equipment, for more information on the retirement of the PIPP.


•	A $9.9 million decrease in operation and maintenance expense due to a 2018 item that was offset in other income, net and had no impact on net income for six months ended June 30, 2019.

These decreases in operating expenses were partially offset by:


•	A $19.0 million increase in depreciation and amortization, driven by capital expenditures as we continue to execute on our capital plan and additional expense recognized related to the adoption of Topic 842, as discussed in the other operation and maintenance table above.


•	A $14.8 million increase in benefit costs, primarily related to deferred compensation.


•	A $7.1 million increase in transmission expense related to the flow through of tax repairs, as discussed in the other operation and maintenance table above.

Consolidated Other Income, Net



	Six Months Ended June 30
(in millions)	2019		2018		B (W)
AFUDC – Equity	$	1.4	$	2.0	$	(0.6	)
Non-service components of net periodic benefit costs	4.3		2.9		1.4
Other	5.7		6.2		(0.5		)
Other income, net	$	11.4	$	11.1	$	0.3

Consolidated Interest Expense



	Six Months Ended June 30
(in millions)	2019		2018		B (W)
Interest expense	$	239.5	$	58.9	$	(180.6	)

Interest expense increased $180.6 million during the six months ended June 30, 2019, compared with the same period in 2018, primarily due to the adoption of ASU 2016-02, Leases (Topic 842). Effective January 1, 2019, minimum lease payments billed from We Power to us were no longer classified within operation and maintenance, but were instead recorded as a component of depreciation and amortization and interest expense in accordance with Topic 842. As a result of the adoption, for the six months ended June 30, 2019, $176.0 million of minimum lease payments were recorded as interest expense on finance lease liabilities. See Note 7, Leases, for more information.



06/30/2019 Form 10-Q	35	Wisconsin Electric Power Company

Table of Contents

Consolidated Income Tax Benefit



	Six Months Ended June 30
	2019		2018		B (W)
Effective tax rate	(12.9	)%	(3.2	)%	9.7	%

Our effective tax rate decreased by 9.7% when compared with the six months ended June 30, 2018, primarily due to an increase in the benefit from the flow through of tax repairs in connection with the Wisconsin rate settlement. See Note 9, Income Taxes, and Note 18, Regulatory Environment, for more information.

We expect our 2019 annual effective tax rate to be between (18.0)% and (17.0)%, which includes an estimated 39.5% 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 effective tax rate would be between 21.5% and 22.5%.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

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



(in millions)	2019			2018			Change in 2019 Over 2018
Cash provided by (used in):
Operating activities	$	435.4		$	531.6		$	(96.2	)
Investing activities	(225.3		)	(331.1		)	105.8
Financing activities	(225.7		)	(211.7		)	(14.0		)

Operating Activities

Net cash provided by operating activities decreased $96.2 million during the six months ended June 30, 2019, compared with the same period in 2018. Our adoption of ASU 2016-02, Leases (Topic 842), on January 1, 2019 did not have a significant impact on our cash flows from operating activities as the $181.3 million increase in cash paid for interest was primarily offset by a corresponding decrease in cash paid for other operation and maintenance. As a result, this classification change is not reflected in our discussion below. See Note 7, Leases, for more information. The $96.2 million decrease in net cash provided by operating activities was driven by:


•	A $45.1 million decrease in cash from higher payments for other operation and maintenance expenses. During the six months ended June 30, 2019, our payments were higher for accounts payable, transmission, and benefits, compared with the same period in 2018.


•	A $36.2 million decrease in cash primarily related to the impact of the Tax Legislation, which resulted in lower overall collections from customers during the six months ended June 30, 2019, compared with the same period in 2018.


•	A $17.9 million decrease in cash due to higher collateral requirements during the six months ended June 30, 2019, compared with the same period in 2018, driven by an increase in our derivative liabilities.

These decreases in net cash provided by operating activities were partially offset by a $16.6 million increase in cash primarily related to lower payments for fuel and purchased power during the six months ended June 30, 2019, compared with the same period in 2018, due to the retirements of the Pleasant Prairie power plant in April 2018 and the PIPP in March 2019.



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Investing Activities

Net cash used in investing activities decreased $105.8 million during the six months ended June 30, 2019, compared with the same period in 2018, driven by:


•	A $56.6 million decrease in cash paid for capital expenditures during the six months ended June 30, 2019, compared with the same period in 2018, which is discussed in more detail below.


•	A payment of $50.1 million to WEC Business Services LLC during the six months ended June 30, 2018 for the transfer of an enterprise resource planning system and other software to us.

Capital Expenditures

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



(in millions)	2019		2018		Change in 2019 Over 2018
Capital expenditures	$	230.4	$	287.0	$	(56.6	)

The decrease in cash paid for capital expenditures during the six months ended June 30, 2019, compared with the same period in 2018, was primarily driven by upgrades to our electric distribution system, projects at the OCPP, and the implementation of an enterprise resource planning system during the six months ended June 30, 2018. These decreases in cash paid for capital expenditures were partially offset by increased capital expenditures for an information technology project created to improve our billing, call center, and credit collection functions during the six months ended June 30, 2019.

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

Financing Activities

Net cash used in financing activities increased $14.0 million during the six months ended June 30, 2019, compared with the same period in 2018, driven by:


•	A $226.3 million net decrease in cash due to $95.4 million of net repayments of commercial paper during the six months ended June 30, 2019, compared with $130.9 million of net borrowings of commercial paper during the same period in 2018.


•	A $90.0 million decrease in cash due to higher dividends paid to our parent during the six months ended June 30, 2019, compared with the same period in 2018, to balance our capital structure.

•

A $24.4 million decrease in cash related to a change in the cash flow classification of our principal payments for finance lease obligations due to our adoption of Topic 842. Under Topic 842, our principal payments for finance lease obligations were no longer classified as cash flows from operating activities during the six months ended June 30, 2019 but were instead classified as cash flows from financing activities. See Note 7, Leases, for more information on Topic 842 and our finance lease obligations.

These decreases in cash were partially offset by:


•	A $250.0 million increase in cash related to a repayment of long-term debt during the six months ended June 30, 2018.


•	A $77.0 million increase in cash related to higher equity contributions received from our parent during the six months ended June 30, 2019, compared with the same period in 2018, to balance our capital structure.

Significant Financing Activities

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



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Capital Resources and Requirements

Capital Resources

Liquidity

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

We currently have access to the capital markets and have been able to generate funds internally and externally to meet our capital requirements. Our ability to attract the necessary financial capital at reasonable terms is critical to our overall strategic plan. We currently believe that we have adequate capacity to fund our operations for the foreseeable future through our existing borrowing arrangement, access to capital markets, and internally generated cash.

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

Working Capital

As of June 30, 2019, our current liabilities exceeded our current assets by $13.6 million. We do not expect this to have any impact on our liquidity since we believe we have adequate back-up lines of credit in place for our ongoing operations. We also believe that we can access the capital markets to finance our construction programs and to refinance current maturities of long-term debt, 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

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

The majority of spending consists of upgrading our electric and natural gas distribution systems to enhance reliability. These upgrades include the 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. We have partnered with an unaffiliated utility to acquire an ownership interest in Badger Hollow II, a solar project that will be located in Iowa County, Wisconsin. We will own 100 MW of the output of the project. Our share of the cost of this project is estimated to be $130 million. Commercial operation is targeted for the end of 2021. Solar generation technology has greatly improved, has become more cost-effective, and it complements our summer demand curve.

Off-Balance Sheet Arrangements

We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including letters of credit that primarily support our commodity contracts. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see Note 6, Short-Term Debt and Lines of Credit, Note 12, Guarantees, and Note 15, Variable Interest Entities.

Contractual Obligations

For information about our commitments, see Contractual Obligations in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Requirements in our 2018 Annual Report on Form 10-K. There were no material changes to our commitments outside the ordinary course of business during the six months ended June 30, 2019.

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity, and capital resources. The following discussion should be read together with the information in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources in our 2018 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, competitive markets, environmental matters, critical accounting policies and estimates, and other matters.

Market Risks and Other Significant Risks

We are exposed to market and other significant risks as a result of the nature of our business and the environment in which we operate. These risks include, but are not limited to, the regulatory recovery risk described below. 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 in our 2018 Annual Report on Form 10-K for a discussion of other significant risks applicable to us.



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Regulatory Recovery

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 the PSCW. Recovery of the deferred costs in future rates is subject to the review and approval by the PSCW. 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 the PSCW, the costs would be charged to income in the current period. The PSCW 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.

Due to the Tax Legislation signed into law in December 2017, we remeasured our deferred taxes and recorded a tax benefit of $1,102 million. We have been returning the amortization of this tax benefit to ratepayers through bill credits and reductions to other regulatory assets, which we expect to continue.

See Note 18, Regulatory Environment, for more information regarding our pending rate proceeding and previously issued rate order.

Environmental Matters

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

Other Matters

Tax Cuts and Jobs Act of 2017

In December 2017, the Tax Legislation was signed into law. In May 2018, the PSCW issued a written order regarding how to refund certain tax savings from the Tax Legislation to our ratepayers in Wisconsin. In addition, the Michigan Public Service Commission approved a settlement with Tilden, who owns the iron ore mine located in the Upper Peninsula of Michigan we provided retail electric service to prior to April 1, 2019, that addressed all base rate impacts of the Tax Legislation. We expect that the various remaining impacts of the Tax Legislation on our Wisconsin operations will be addressed in our pending rate case we filed with the PSCW in March 2019. See Note 18, Regulatory Environment, for more information on our pending rate case. 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.



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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes related to market risk from the disclosures presented in our 2018 Annual Report on Form 10-K. In addition to the Form 10-K disclosures, see 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 in Item 2 of Part I of this report, as well as Note 10, Fair Value Measurements, Note 11, Derivative Instruments, and Note 12, Guarantees, in this report for information concerning our market risk exposures.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the second quarter of 2019 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.



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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The following should be read in conjunction with Item 3. Legal Proceedings in Part I of our 2018 Annual Report on Form 10-K. See Note 16, Commitments and Contingencies, and Note 18, Regulatory Environment, in this report for more information on material legal proceedings and matters related to us.

In addition to those legal proceedings discussed in Note 16, Commitments and Contingencies, and Note 18, Regulatory Environment, 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.

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors presented in our 2018 Annual Report on Form 10-K. See Item 1A. Risk Factors in Part I of our Form 10-K for a discussion of certain risk factors applicable to us.

ITEM 6. EXHIBITS



Number	Exhibit
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 Files

	101.INS	Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document

	101.SCH	Inline XBRL Taxonomy Extension Schema

	101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase

	101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase

	101.LAB	Inline XBRL Taxonomy Extension Label Linkbase

	101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase

104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)



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SIGNATURE

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



		WISCONSIN ELECTRIC POWER COMPANY
		(Registrant)

		/s/ WILLIAM J. GUC
Date:	August 6, 2019	William J. Guc
		Vice President and Controller

		(Duly Authorized Officer and Chief Accounting Officer)



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