WISCONSIN ELECTRIC POWER CO - Quarter Report: 2017 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended March 31, 2017



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

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

Yes [X] No [ ]

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

Yes [X] No [ ]

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



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

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

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

Yes [ ] No [X]

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

Common Stock, $10 Par Value,

33,289,327 shares outstanding at

March 31, 2017

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

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WISCONSIN ELECTRIC POWER COMPANY

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended March 31, 2017

TABLE OF CONTENTS



				Page
	CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION			1
PART I.	FINANCIAL INFORMATION			3
ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)			3
	Condensed Consolidated Income Statements			3
	Condensed Consolidated Balance Sheets			4
	Condensed Consolidated Statements of Cash Flows			5
	Notes to Condensed Consolidated Financial Statements			6
			Page
	Note 1	General Information	6
	Note 2	Dispositions	6
	Note 3	Common Equity	7
	Note 4	Short-Term Debt and Lines of Credit	7
	Note 5	Materials, Supplies, and Inventories	8
	Note 6	Fair Value Measurements	8
	Note 7	Derivative Instruments	10
	Note 8	Employee Benefits	11
	Note 9	Investment in American Transmission Company	12
	Note 10	Segment Information	12
	Note 11	Variable Interest Entities	13
	Note 12	Related Parties	13
	Note 13	Commitments and Contingencies	15
	Note 14	Supplemental Cash Flow Information	19
	Note 15	Regulatory Environment	19
	Note 16	New Accounting Pronouncements	20
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			22
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			30
ITEM 4.	CONTROLS AND PROCEDURES			31
PART II.	OTHER INFORMATION			32
ITEM 1.	LEGAL PROCEEDINGS			32
ITEM 1A.	RISK FACTORS			32
ITEM 6.	EXHIBITS			33
SIGNATURE				34



03/31/2017 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
Integrys		Integrys Holding, Inc.
UMERC		Upper Michigan Energy Resources Corporation
WBS		WEC Business Services LLC
We Power		W.E. Power, LLC
WEC Energy Group		WEC Energy Group, Inc.
WG		Wisconsin Gas LLC
WPS		Wisconsin Public Service Corporation

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

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

Environmental Terms
CSAPR		Cross-State Air Pollution Rule
GHG		Greenhouse Gas
NAAQS		National Ambient Air Quality Standards
NOx		Nitrogen Oxide
SO₂		Sulfur Dioxide

Measurements
Dth		Dekatherm
MW		Megawatt
MWh		Megawatt-hour

Other Terms and Abbreviations
D.C. Circuit Court of Appeals		United States Court of Appeals for the District of Columbia Circuit
ERGS		Elm Road Generating Station
Exchange Act		Securities Exchange Act of 1934, as amended
FTRs		Financial Transmission Rights
MCPP		Milwaukee County Power Plant
MISO		Midcontinent Independent System Operator, Inc.
MISO Energy Markets		MISO Energy and Operating Reserves Markets
OCPP		Oak Creek Power Plant
OC 5		Oak Creek Power Plant Unit 5



03/31/2017 Form 10-Q	ii	Wisconsin Electric Power Company

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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
ROE		Return on Equity
Supreme Court		United States Supreme Court
VAPP		Valley Power Plant



03/31/2017 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 rate, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, environmental matters, liquidity and capital resources, and other matters.

Forward-looking statements are subject to a number of risks and uncertainties that could cause our actual results to differ materially from those expressed or implied in the statements. These risks and uncertainties include those described in risk factors as set forth in this report and our Annual Report on Form 10-K for the year ended December 31, 2016, and those identified below:


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


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


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


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


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

•

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


•	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 permit conditions by regulatory agencies, and the recovery of associated remediation and compliance costs;

•

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


•	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;



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•	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 incidents, the threat of terrorist incidents, and cyber security intrusion, including the failure to maintain the security of personally identifiable information, the associated costs to protect our assets and personal information, and the costs to notify affected persons to mitigate their information security concerns;


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


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


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


•	The timing, costs, and anticipated benefits associated with the remaining integration efforts relating to Wisconsin Energy Corporation's acquisition of Integrys;


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


•	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.



03/31/2017 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
	March 31
(in millions)	2017			2016
Operating revenues	$	972.0		$	975.5

Operating expenses
Cost of sales	348.6			336.4
Other operation and maintenance	327.8			348.2
Depreciation and amortization	82.1			80.4
Property and revenue taxes	28.4			29.0
Total operating expenses	786.9			794.0

Operating income	185.1			181.5

Equity in earnings of transmission affiliate	—			14.7
Other income, net	4.4			3.0
Interest expense	29.6			29.1
Other expense	(25.2		)	(11.4		)

Income before income taxes	159.9			170.1
Income tax expense	57.8			62.5
Net income	102.1			107.6

Preferred stock dividend requirements	0.3			0.3
Net income attributed to common shareholder	$	101.8		$	107.3

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



03/31/2017 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)	March 31, 2017		December 31, 2016
Assets
Current assets
Cash and cash equivalents	$	10.9	$	15.4
Accounts receivable and unbilled revenues, net of reserves of $44.2 and $40.9, respectively	448.7		503.2
Accounts receivable from related parties	67.5		58.2
Materials, supplies, and inventories	251.6		271.0
Prepayments	109.4		138.0
Other	4.1		24.6
Current assets	892.2		1,010.4

Long-term assets
Property, plant, and equipment, net of accumulated depreciation of $3,609.3 and $3,619.6 respectively	9,785.3		9,832.3
Regulatory assets	2,060.7		2,036.6
Equity investment in transmission affiliate	—		402.0
Other	87.5		90.2
Long-term assets	11,933.5		12,361.1
Total assets	$	12,825.7	$	13,371.5

Liabilities and Equity
Current liabilities
Short-term debt	$	35.0	$	159.0
Current portion of capital lease obligations	30.1		28.5
Subsidiary note payable to WEC Energy Group	5.7		18.5
Accounts payable	230.2		297.9
Accounts payable to related parties	119.3		112.9
Accrued payroll and benefits	36.6		51.8
Accrued interest	35.2		10.9
Accrued taxes	30.1		46.0
Other	69.7		89.2
Current liabilities	591.9		814.7

Long-term liabilities
Long-term debt	2,660.6		2,661.1
Capital lease obligations	2,813.2		2,756.5
Deferred income taxes	2,124.4		2,333.3
Regulatory liabilities	846.6		853.9
Pension and OPEB obligations	163.6		167.6
Other	261.4		260.2
Long-term liabilities	8,869.8		9,032.6

Commitments and contingencies (Note 13)

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	806.1		1,020.1
Retained earnings	2,194.6		2,140.8
Common shareholder's equity	3,333.6		3,493.8

Preferred stock	30.4		30.4
Total liabilities and equity	$	12,825.7	$	13,371.5

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



03/31/2017 Form 10-Q	4	Wisconsin Electric Power Company

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WISCONSIN ELECTRIC POWER COMPANY



CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Three Months Ended
	March 31
(in millions)	2017			2016
Operating Activities
Net income	$	102.1		$	107.6
Reconciliation to cash provided by operating activities
Depreciation and amortization	82.1			82.4
Deferred income taxes and investment tax credits, net	20.7			65.4
Contributions and payments related to pension and OPEB plans	(3.3		)	(2.9		)
Equity income in transmission affiliate, net of distributions	—			(8.7		)
Proceeds from (payments for) liabilities transferred from (to) WBS	0.9			(107.0		)
Change in –
Accounts receivable and unbilled revenues	42.1			39.1
Materials, supplies, and inventories	19.4			35.3
Prepaid taxes	25.1			25.3
Other current assets	3.2			3.8
Accounts payable	(63.5		)	(67.0		)
Accrued taxes	(15.9		)	(4.7		)
Other current liabilities	(11.0		)	11.0
Other, net	7.9			(8.9		)
Net cash provided by operating activities	209.8			170.7

Investing Activities
Capital expenditures	(105.5		)	(92.3		)
Capital contributions to transmission affiliate	—			(3.5		)
Proceeds from the sale of assets	12.9			—
Proceeds from assets transferred to WBS	—			9.9
Other, net	0.4			(0.3		)
Net cash used in investing activities	(92.2		)	(86.2		)

Financing Activities
Change in short-term debt	(124.0		)	48.0
Repayment of subsidiary note to parent	(12.8		)	(2.6		)
Equity contribution from parent	75.0			—
Payments of dividends to parent	(60.0		)	(160.0		)
Payments of preferred stock dividends	(0.3		)	(0.3		)
Other, net	—			9.9
Net cash used in financing activities	(122.1		)	(105.0		)

Net change in cash and cash equivalents	(4.5		)	(20.5		)
Cash and cash equivalents at beginning of period	15.4			27.1
Cash and cash equivalents at end of period	$	10.9		$	6.6

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



03/31/2017 Form 10-Q	5	Wisconsin Electric Power Company

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WISCONSIN ELECTRIC POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

March 31, 2017

NOTE 1—GENERAL INFORMATION

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

Prior to January 1, 2017, we owned approximately 23% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. Effective January 1, 2017, based upon input we received from the PSCW, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 12, Related Parties, for more information on the transfer.

In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan, and UMERC became operational effective January 1, 2017. That utility holds the electric and natural gas distribution assets, previously held by WPS and us, located in the Upper Peninsula of Michigan. The existing contract between the Tilden Mining Company and us will remain in place until a new power generation solution for the region is commercially operational. See Note 12, Related Parties, and Note 15, Regulatory Environment, for more information on UMERC.

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, 2016. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three months ended March 31, 2017, are not necessarily indicative of expected results for 2017 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.

During the second quarter of 2016, we reorganized our business segments to reflect our new internal organization and management structure. All prior period amounts impacted by this change were reclassified to conform to the new presentation. See Note 10, Segment Information, for more information on our business segments.

NOTE 2—DISPOSITIONS

Utility Segment

Sale of Milwaukee County Power Plant

In April 2016, we sold the MCPP steam generation and distribution assets, located in Wauwatosa, Wisconsin. MCPP primarily provided steam to the Milwaukee Regional Medical Center hospitals and other campus buildings. During the second quarter of 2016, we recorded a pre-tax gain on the sale of $10.9 million ($6.5 million after tax), which was included in other operation and maintenance on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations of this plant remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.

Other Segment

Sale of Bostco Real Estate Holdings

In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space. During the first quarter of 2017, we recorded an insignificant gain on the sale, which was included in other income, net on our income statements. The assets included in the sale were not material and, therefore, were not presented



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as held for sale. The results of operations associated with these assets remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.

NOTE 3—COMMON EQUITY

Stock-Based Compensation

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which modifies certain aspects of the accounting for stock-based compensation awards. This ASU became effective for us on January 1, 2017. Under the new guidance, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement on a prospective basis. Prior to January 1, 2017, these amounts were recorded in additional paid in capital on the balance sheet, and the tax benefits could only be recognized to the extent they reduced taxes payable. In the first quarter of 2017, we recorded an $11.9 million cumulative-effect adjustment to retained earnings for excess tax benefits that had not been recognized in prior years as they did not reduce taxes payable. The following table shows the changes to our retained earnings for the three months ended March 31, 2017:



(in millions)	Retained Earnings
Balance at December 31, 2016	$	2,140.8
Net income	102.1
Common stock dividends	(60.0		)
Preferred stock dividends	(0.3		)
Cumulative effect of adoption of ASU 2016-09	11.9
Other	0.1
Balance at March 31, 2017	$	2,194.6

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

As we did not record any excess tax benefits in 2017, adoption of this ASU had no impact on our financial statements other than the cumulative-effect adjustment discussed above.

Restrictions

Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to WEC Energy Group in the form of cash dividends, loans, or advances. In addition, Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group or its subsidiaries. See Note 9, Common Equity, in our 2016 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 4—SHORT-TERM DEBT AND LINES OF CREDIT

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



(in millions, except percentages)	March 31, 2017			December 31, 2016
Commercial paper
Amount outstanding	$	35.0		$	159.0
Weighted-average interest rate on amounts outstanding	1.05		%	0.87		%

Our average amount of commercial paper borrowings based on daily outstanding balances during the three months ended March 31, 2017, was $46.0 million with a weighted-average interest rate during the period of 0.88%.



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As of March 31, 2017, our subsidiary had a $5.7 million note payable to WEC Energy Group with a weighted-average interest rate of 5.23%.

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



(in millions)	Maturity	March 31, 2017
Revolving credit facility	December 2020	$	500.0

Less:
Letters of credit issued inside credit facility		$	18.0
Commercial paper outstanding		35.0

Available capacity under existing agreement		$	447.0

NOTE 5—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:



(in millions)	March 31, 2017		December 31, 2016
Materials and supplies	$	147.5	$	148.1
Fossil fuel	99.1		91.1
Natural gas in storage	5.0		31.8
Total	$	251.6	$	271.0

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

NOTE 6—FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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



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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 at their value as of the end of the reporting period.

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



	March 31, 2017
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	1.6	$	—	$	—	$	1.6
FTRs	—		—		1.1		1.1
Coal contracts	—		1.0		—		1.0
Total derivative assets	$	1.6	$	1.0	$	1.1	$	3.7

Derivative liabilities
Petroleum products contracts	$	0.3	$	—	$	—	$	0.3
Coal contracts	—		1.7		—		1.7
Total derivative liabilities	$	0.3	$	1.7	$	—	$	2.0



	December 31, 2016
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	6.0	$	0.8	$	—	$	6.8
Petroleum products contracts	0.2		—		—		0.2
FTRs	—		—		3.1		3.1
Coal contracts	—		1.9		—		1.9
Total derivative assets	$	6.2	$	2.7	$	3.1	$	12.0

Derivative liabilities
Natural gas contracts	$	0.1	$	—	$	—	$	0.1
Petroleum products contracts	0.1		—		—		0.1
Coal contracts	—		0.5		—		0.5
Total derivative liabilities	$	0.2	$	0.5	$	—	$	0.7

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

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



	Three Months Ended March 31
(in millions)	2017			2016
Balance at the beginning of the period	$	3.1		$	1.6
Settlements	(2.0		)	(1.0		)
Balance at the end of the period	$	1.1		$	0.6



03/31/2017 Form 10-Q	9	Wisconsin Electric Power Company

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Fair Value of Financial Instruments

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



	March 31, 2017				December 31, 2016
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock	$	30.4	$	28.9	$	30.4	$	28.8
Long-term debt	2,660.6		2,896.5		2,661.1		2,923.4

Due to the short-term nature of cash and cash equivalents, net accounts receivable and unbilled revenues, accounts payable, and short-term borrowings, the carrying amount of each such item approximates fair value. The fair value of our preferred stock is estimated based on the quoted market value for the same issue, or by using a dividend discount model. The fair value of our long-term debt is estimated based on the quoted market prices for the same or similar issues. The fair values of long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.

NOTE 7—DERIVATIVE INSTRUMENTS

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

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

The following table shows our derivative assets and derivative liabilities:



	March 31, 2017				December 31, 2016
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	1.6	$	—	$	6.3	$	0.1
Petroleum products contracts	—		0.3		0.2		0.1
FTRs	1.1		—		3.1		—
Coal contracts	1.0		0.9		1.5		0.5
Total other current *	$	3.7	$	1.2	$	11.1	$	0.7

Other long-term
Natural gas contracts	$	—	$	—	$	0.5	$	—
Coal contracts	—		0.8		0.4		—
Total other long-term *	—		0.8		0.9		—
Total	$	3.7	$	2.0	$	12.0	$	0.7


*	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.



03/31/2017 Form 10-Q	10	Wisconsin Electric Power Company

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



	Three Months Ended March 31, 2017				Three Months Ended March 31, 2016
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	8.2 Dth	$	0.5		10.6 Dth	$	(7.2	)
Petroleum products contracts	4.9 gallons	(0.5		)	1.6 gallons	(0.7		)
FTRs	7.0 MWh	2.5			5.2 MWh	1.8
Total		$	2.5			$	(6.1	)

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 March 31, 2017, we had posted cash collateral of $0.4 million in our margin accounts, and at December 31, 2016, we had received cash collateral of $3.4 million in our margin accounts. On our balance sheets, cash collateral provided to others is reflected in other current assets and cash collateral received is reflected in other current liabilities.

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



	March 31, 2017						December 31, 2016
(in millions)	Derivative Assets			Derivative Liabilities			Derivative Assets				Derivative Liabilities
Gross amount recognized on the balance sheet	$	3.7		$	2.0		$	12.0			$	0.7
Gross amount not offset on the balance sheet	(0.3		)	(0.3		)	(3.6		)	*	(0.2		)
Net amount	$	3.4		$	1.7		$	8.4			$	0.5


*	Includes cash collateral received of $3.4 million.

NOTE 8—EMPLOYEE BENEFITS

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



	Pension Costs
	Three Months Ended March 31
(in millions)	2017			2016
Service cost	$	3.0		$	2.7
Interest cost	11.9			12.6
Expected return on plan assets	(19.2		)	(19.4		)
Amortization of prior service cost	0.3			0.4
Amortization of net actuarial loss	8.8			8.0
Net periodic benefit cost	$	4.8		$	4.3



	OPEB Costs
	Three Months Ended March 31
(in millions)	2017			2016
Service cost	$	1.9		$	0.1
Interest cost	3.1			1.9
Expected return on plan assets	(3.6		)	(1.2		)
Amortization of prior service credit	(0.3		)	(0.3		)
Amortization of net actuarial loss	0.3			0.2
Net periodic benefit cost	$	1.4		$	0.7

During the three months ended March 31, 2017, we made payments of $2.6 million related to our pension plans and $0.7 million to our OPEB plans. We expect to make payments of $2.3 million related to our pension plans and $3.7 million related to our OPEB plans during the remainder of 2017, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.



03/31/2017 Form 10-Q	11	Wisconsin Electric Power Company

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NOTE 9—INVESTMENT IN AMERICAN TRANSMISSION COMPANY

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



	Three Months Ended March 31
(in millions)	2017		2016
Balance at beginning of period	$	402.0	$	382.2
Less: Transfer of ownership interest	402.0		—
Add: Earnings from equity method investment	—		14.7
Add: Capital contributions	—		3.5
Less: Distributions	—		6.0
Less: Other	—		0.1
Balance at end of period	$	—	$	394.3

See Note 12, Related Parties, for more information on transactions with ATC.

NOTE 10—SEGMENT INFORMATION

We use operating income to measure segment profitability and to allocate resources to our businesses. At March 31, 2017, we reported two segments, which are described below.

Our utility segment includes our electric and natural gas utility operations. Our electric utility operations are engaged in the generation, distribution, and sale of electricity in southeastern Wisconsin (including metropolitan Milwaukee), east central Wisconsin, northern Wisconsin, and the Upper Peninsula of Michigan. Effective January 1, 2017, we transferred all of our electric distribution assets and customers located in the Upper Peninsula of Michigan to UMERC, with the exception of the Tilden Mining Company. See Note 12, Related Parties, and Note 15, Regulatory Environment, for additional information. Our electric utility operations also include our steam operations, which produce, distribute, and sell steam to customers in metropolitan Milwaukee, Wisconsin. Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers and the transportation of customer-owned natural gas in our three service areas within southeastern, east central, and northern Wisconsin.

Our other segment includes Bostco, our non-utility subsidiary that developed and invested in real estate. In March 2017, we sold substantially all of the remaining assets of Bostco. See Note 2, Dispositions, for more information. Prior to January 1, 2017, our other segment also included our approximate 23% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 9, Investment in American Transmission Company, for more information.

The following tables show summarized financial information related to our reportable segments for the three months ended March 31, 2017 and 2016:



(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Three Months Ended March 31, 2017
Operating revenues	$	972.0	$	—	$	972.0
Other operation and maintenance	327.8		—		327.8
Depreciation and amortization	82.1		—		82.1
Operating income	185.1		—		185.1
Interest expense	29.3		0.3		29.6



03/31/2017 Form 10-Q	12	Wisconsin Electric Power Company

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(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Three Months Ended March 31, 2016
Operating revenues	$	975.5	$	—	$	975.5
Other operation and maintenance	348.2		—		348.2
Depreciation and amortization	80.4		—		80.4
Operating income	181.5		—		181.5
Equity in earnings of transmission affiliate	—		14.7		14.7
Interest expense	28.9		0.2		29.1

NOTE 11—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.

American Transmission Company

As of December 31, 2016, we owned approximately 23% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. However, effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. ATC is a variable interest entity, but consolidation was not required since we were not ATC's primary beneficiary. We did not have the power to direct the activities that most significantly impacted ATC's economic performance. At December 31, 2016, we accounted for ATC as an equity method investment. See Note 9, Investment in American Transmission Company, for more information.

The significant assets and liabilities related to ATC recorded on our balance sheet at December 31, 2016 included our equity investment and accounts payable. At December 31, 2016, our equity investment was $402.0 million, which approximated our maximum exposure to loss as a result of our involvement with ATC. In addition, we had $20.0 million of accounts payable due to ATC at December 31, 2016 for network transmission services.

Purchased Power Agreement

We have identified a purchased power 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 capital lease. The agreement includes no minimum energy requirements over the remaining term of approximately five years. We have examined the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity, and there is no residual guarantee associated with the purchased power agreement.

We have approximately $81.9 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under this contract for the three months ended March 31, 2017 and 2016 were $4.5 million and $13.5 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

NOTE 12—RELATED PARTIES

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

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



03/31/2017 Form 10-Q	13	Wisconsin Electric Power Company

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A new affiliated interest agreement (AIA) took effect January 1, 2017. The new agreement replaced the previous agreements. The pricing methodology and services under this new agreement are substantially identical to those under the agreements that were replaced. In February 2017, a request was filed with the PSCW for modifications to the new AIA to incorporate WEC Energy Group's pending acquisition of a natural gas storage facility in Michigan, which is discussed below.

Bostco, our consolidated subsidiary, had a note payable to our parent company, WEC Energy Group. At March 31, 2017 and December 31, 2016, the balance of this note payable was $5.7 million and $18.5 million, respectively. The $5.7 million note payable was paid off in April 2017.

In connection with the sale of Bostco’s remaining real estate holdings, Wispark LLC, a subsidiary of WEC Energy Group, provided $7.0 million of financing to the buyer and established a corresponding note receivable. As of March 31, 2017, Bostco had a $7.0 million related party receivable from Wispark LLC related to this transaction. The related party receivable was paid in April 2017. See Note 2, Dispositions, for more information on the real estate sale.

On January 1, 2017, based upon input we received from the PSCW, we transferred our investment in ATC and the related receivable for distributions approved and recorded in December 2016, valued at $415.4 million, to another subsidiary of WEC Energy Group. In addition, we transferred $195.1 million of related deferred income tax liabilities. These transactions were a non-cash equity transfer recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss.

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

Our balance sheets included the following receivables and payables related to ATC:



(in millions)	March 31, 2017		December 31, 2016
Accounts receivable
Services provided to ATC	$	0.6	$	1.1
Accounts payable
Services received from ATC	20.1		20.0

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



	Three Months Ended March 31
(in millions)	2017			2016
Lease agreements
Lease payments to We Power ⁽¹⁾	$	104.4		$	107.4
Construction work in progress billed to We Power	16.3			1.3
Transactions with WBS ⁽²⁾
Billings to WBS ⁽³⁾	56.5			56.7
Billings from WBS ⁽⁴⁾	49.8			163.4
Transactions with WPS ⁽²⁾
Billings to WPS	2.5			1.0
Billings from WPS	1.1			0.4
Transactions with WG
Natural gas purchases from WG	1.3			1.4
Services received from WG	5.5			1.1
Services provided to WG	15.8			1.9
Transactions with UMERC ⁽⁵⁾
Electric sales to UMERC	7.7			—
Transactions with ATC
Charges to ATC for services and construction	2.8			2.1
Charges from ATC for network transmission services	60.3			63.3
Refund from ATC per FERC ROE order	(19.4		)	—



03/31/2017 Form 10-Q	14	Wisconsin Electric Power Company

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⁽¹⁾	We make lease payments to We Power, another subsidiary of WEC Energy Group, for PWGS Units 1 and 2 and ERGS Units 1 and 2.


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


⁽³⁾	Includes $0.9 million, for the transfer of certain benefit-related liabilities from WBS for the three months ended March 31, 2017. Includes $9.9 million, for the transfer of certain software assets to WBS for the three months ended March 31, 2016.


⁽⁴⁾	Includes $107.0 million, for the transfer of certain benefit-related liabilities to WBS for the three months ended March 31, 2016. There were no benefit-related liabilities transferred to WBS for the three months ended March 31, 2017.


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

Upper Michigan Energy Resources Corporation

In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan. UMERC, a subsidiary of WEC Energy Group, became operational effective January 1, 2017, and we transferred customers and property, plant, and equipment as of that date. We transferred approximately 27,500 retail electric customers and 50 electric distribution-only customers to UMERC, along with approximately 2,500 miles of electric distribution lines. We also transferred related electric distribution substations in the Upper Peninsula of Michigan and all property rights for the distribution assets to UMERC. The book value of net assets (including the related deferred income tax liabilities) transferred to UMERC from us as of January 1, 2017, was $68.9 million. This transaction was a non-cash equity transfer recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss. The Tilden Mining Company will remain a customer of ours until UMERC's proposed generation solution for the Upper Peninsula of Michigan begins commercial operation.

UMERC obtains its energy through the MISO Energy Markets and meets its market obligations through power purchase agreements with us and WPS.

Parent Company's Acquisition of a Natural Gas Storage Facility in Michigan

In January 2017, our parent company signed an agreement for the acquisition of a natural gas storage facility in Michigan that would provide for some of our current storage needs for our natural gas utility operations. We plan to enter into a long-term service agreement to take the allocated storage, subject to receipt of certain PSCW declarations and approvals and closing of the acquisition. PSCW declarations and approvals and closing of this transaction are expected to occur by the third quarter of 2017. See Note 15, Regulatory Environment, for more information.

NOTE 13—COMMITMENTS AND CONTINGENCIES

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

Unconditional Purchase Obligations

We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of March 31, 2017, were $10,079.4 million.

Environmental Matters

Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as SO₂, NOx, fine particulates, mercury, and GHGs; water discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.



03/31/2017 Form 10-Q	15	Wisconsin Electric Power Company

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Air Quality

Cross-State Air Pollution Rule

In July 2011, the EPA issued the CSAPR, which replaced a previous rule, the Clean Air Interstate Rule. The purpose of the CSAPR was to limit the interstate transport of NOx and SO₂ that contribute to fine particulate matter and ozone nonattainment in downwind states through a proposed allowance allocation and trading plan. After several lawsuits and related appeals, in October 2014, the D.C. Circuit Court of Appeals issued a decision that allowed the EPA to begin implementing CSAPR on January 1, 2015. The emissions budgets of Phase I of the rule applied in 2015 and 2016, while the Phase II emissions budgets apply to 2017 and beyond.

The EPA published its proposed update to the CSAPR for the 2008 ozone NAAQS in December 2015, and issued the final rule in September 2016. We are well positioned to meet the rule requirements and do not expect to incur significant costs to comply with this rule.

Sulfur Dioxide National Ambient Air Quality Standards

The EPA issued a revised 1-Hour SO₂ NAAQS that became effective in August 2010. The EPA issued a final rule in August 2015 describing the implementation requirements and established a compliance timeline for the revised standard. The final rule affords state agencies some latitude in rule implementation. A nonattainment designation could have negative impacts for a localized geographic area, including additional permitting requirements for new or existing sources in the area.

We believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation.

8-Hour Ozone National Ambient Air Quality Standards

The eastern portion of Kenosha County, along with Sheboygan County, are currently designated as nonattainment with the 2008 ozone standard. In response, Wisconsin has updated the 2008 ozone NAAQS attainment plan for Kenosha County and submitted it to the EPA for approval. The plan concluded that Wisconsin will not need to implement any new regulatory measures or programs. The area is forecasted to meet the standard by the 2018 compliance date due to emission control measures already in place. A final EPA action regarding Wisconsin's attainment plan is expected later in 2017. Wisconsin has not yet provided an attainment plan for Sheboygan County.

After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, which lowered the limit for ground-level ozone, creating a more stringent standard than the 2008 NAAQS. This is expected to cause nonattainment for Wisconsin's Lake Michigan shoreline counties (or partial counties), with potential future impacts for our fossil-fueled power plant fleet. In January 2017, the EPA released preliminary interstate ozone transport modeling for the 2015 ozone NAAQS. The EPA is currently scheduled to finalize designations in October 2017. For nonattainment areas, the state of Wisconsin will have to develop a state implementation plan to bring the areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020. We will not know the potential impacts for complying with the 2015 ozone NAAQS until the designations are final and until the state prepares a draft attainment plan.

Although we are still in the process of reviewing and determining potential impacts resulting from this rule, we believe we are well positioned to meet the ozone standard and do not expect to incur significant costs to comply.

Climate Change

In 2015, the EPA issued a final rule regulating GHG emissions from existing generating units, referred to as the Clean Power Plan (CPP), a proposed federal plan and model trading rules as alternatives or guides to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In October 2015, following publication of the CPP, numerous states (including Wisconsin and Michigan) and other parties, filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but in February 2016, the Supreme Court stayed the effectiveness of the CPP until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that further appellate review is sought, at the Supreme Court. The D.C. Circuit Court of Appeals heard one case in September 2016, and the other case is still pending. On April 28, 2017, pursuant to motions made by the EPA, the D.C. Circuit Court of Appeals ordered the cases to be held in abeyance, with



03/31/2017 Form 10-Q	16	Wisconsin Electric Power Company

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supplemental briefs to be provided by May 15, 2017, addressing whether the cases should be remanded to the EPA rather than held in abeyance.

The CPP seeks to achieve state-specific GHG emission reduction goals by 2030, and would have required states to submit plans by September 2016. The goal of the final rule is to reduce nationwide GHG emissions by 32% from 2005 levels. The rule is seeking GHG emission reductions in Wisconsin and Michigan of 41% and 39%, respectively, below 2012 levels by 2030. Interim goals starting in 2022 would require states to achieve about two-thirds of the 2030 required reduction.

In March 2017, President Trump issued an executive order that, among other things, specifically directs the EPA to review, and if appropriate, initiate proceedings to suspend, revise, or rescind the CPP. The EPA announced that it has initiated this review. As a result of this order and related EPA review, as well as the ongoing legal proceedings, the timelines for the GHG emission reduction goals and all other aspects of the CPP are uncertain. In April 2017, the EPA withdrew the proposed rule for a federal plan and model trading rules that were published in October 2015 for use in developing state plans to implement the CPP or for use in states where a plan is not submitted or approved. In addition, the Governor of Wisconsin issued an executive order in February 2016, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan.

Notwithstanding the uncertain future of the CPP, and given current fuel and technology markets, we continue to evaluate opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute towards long-term GHG reductions. Our plan is to work with our industry partners, environmental groups, and the State of Wisconsin, with a goal of reducing CO₂ emissions by approximately 40% below 2005 levels by 2030. We continue to evaluate numerous options in order to meet our CO₂ reduction goal, such as increased use of existing natural gas combined cycle units, co-firing or switching to natural gas in existing coal-fired units, reduced operation or retirement of existing coal-fired units, addition of new renewable energy resources (wind, solar), and consideration of supply and demand-side energy efficiency and distributed generation.

We are required to report our CO₂ equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2016, we reported aggregated CO₂ equivalent emissions of approximately 23.9 million metric tonnes to the EPA. The level of CO₂ and other GHG emissions vary from year to year and are dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO.

We are also required to report CO₂ equivalent emissions from the natural gas that our natural gas utilities distribute and sell. For 2016, we reported aggregated CO₂ equivalent emissions of approximately 3.7 million metric tonnes to the EPA.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

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

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

BTA determinations must also be made by the WDNR and MDEQ to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. We have received an EM BTA determination by the WDNR, with EPA concurrence, for our intake modification at VAPP. BTA determinations for EM will be made in future permit reissuances for PWGS, Pleasant Prairie Power Plant, PIPP, and OC 5 through OC 8.

During 2017 and 2018, we will continue to complete studies and evaluate options to address the EM BTA requirements at these plants. With the exception of Pleasant Prairie Power Plant (which has existing cooling towers that meet EM BTA requirements), we



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cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at the facilities. Based on discussions with the MDEQ, if we provide information about unit retirements with our next National Pollutant Discharge Elimination System permit application and then submit a signed certification by August 2017 stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2022), then the EM BTA requirements will be waived. Entrainment studies were recently completed at PIPP. See the UMERC discussion in Note 15, Regulatory Environment, regarding the potential retirement of PIPP.

We believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation.

Steam Electric Effluent Guidelines

The EPA's final steam electric effluent guidelines rule took effect in January 2016 and applies to discharges of wastewater from our power plant processes in Wisconsin and Michigan. This rule is being litigated in the United States Court of Appeals for the Fifth Circuit (Fifth Circuit Court of Appeals) and may result in changes to the discharge requirements. In April 2017, the EPA granted a petition filed by the Utility Water Act Group to reconsider and stay the steam effluent guidelines and related compliance deadlines. On April 24, 2017, in response to a motion by the EPA, the Fifth Circuit Court of Appeals ordered a stay of the litigation for 120 days while the rule is being redrafted to address the petition's concerns.

After a final rule is back in effect, the WDNR and MDEQ will modify the state rules as necessary and incorporate the new requirements into our facility permits, which are renewed every five years. We expect the new requirements to be phased in between 2018 and 2023 as our permits are renewed. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, these standards will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use.

The final rule phases in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. New requirements for wet scrubber wastewater treatment will require additional zero liquid discharge or other advanced treatment capital improvements for the Oak Creek and Pleasant Prairie facilities. The rule also requires dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are required by the new rule, and modifications will be required at OC 7, OC 8, and the Pleasant Prairie units. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $55 million to $75 million for these advanced treatment and bottom ash transport systems. A similar system would be required at PIPP if we were not expecting to retire the plant. See the UMERC discussion in Note 15, Regulatory Environment, regarding the potential retirement of PIPP.

Land Quality

Manufactured Gas Plant Remediation

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

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

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



(in millions)	March 31, 2017		December 31, 2016
Regulatory assets	$	29.6	$	29.9
Reserves for future remediation	19.0		19.0



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Enforcement and Litigation Matters

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

NOTE 14—SUPPLEMENTAL CASH FLOW INFORMATION



	Three Months Ended March 31
(in millions)	2017			2016
Cash (paid) for interest, net of amount capitalized	$	(4.8	)	$	(4.4	)
Cash (paid) received for income taxes, net	(52.1		)	7.0
Significant noncash transactions:
Accounts payable related to construction costs	11.0			3.2
Transfer of investment in ATC to another subsidiary of WEC Energy Group ^{(1) (2)}	415.4			—
Transfer of net assets to UMERC ⁽¹⁾	68.9			—
Accounts receivable related to the sale of Bostco real estate holdings ⁽¹⁾	7.0			—


⁽¹⁾	See Note 12, Related Parties, for more information on these transactions.


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

NOTE 15—REGULATORY ENVIRONMENT

2018 and 2019 Rates

During April 2017, we, along with WG and WPS, filed an application with the PSCW for approval of a settlement agreement we made with several of our commercial and industrial customers regarding 2018 and 2019 base rates. In this proposed settlement agreement, we agreed to keep electric and natural gas base rates frozen for our customers through 2019. In addition, we agreed to extend and expand the electric real-time pricing options for large commercial and industrial customers, and we agreed to prevent the continued growth of certain escrowed costs. Deferral of the revenue requirement impacts of any federal corporate tax reform enacted in 2017, or during the rate freeze period, was included in the agreement as well. Pursuant to the settlement agreement, we also agreed to keep our earnings sharing mechanism, which applies only to earnings above our authorized ROE, in place through 2019. We expect the PSCW to issue a final order on the settlement agreement in 2017.

Natural Gas Storage Facility in Michigan

In January 2017, WEC Energy Group signed an agreement for the acquisition of a natural gas storage facility in Michigan that would provide some of our current storage needs. As a result of this agreement, we, along with WG and WPS, filed a request with the PSCW in February 2017 for a declaratory ruling on various items associated with the storage facility. In the filing, we requested that the PSCW review and confirm the reasonableness and prudency of our potential long-term storage service agreements and interstate natural gas transportation contracts related to the storage facility. We also requested approval to amend WEC Energy Group's Affiliated Interest Agreement to ensure WBS and WEC Energy Group's other subsidiaries would be able to provide services to the storage facility. We expect to receive these PSCW declarations and approvals by the third quarter of 2017.

Formation of Upper Michigan Energy Resources Corporation

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

In August 2016, WEC Energy Group entered into an agreement with the Tilden Mining Company (Tilden), under which Tilden will purchase electric power from UMERC for its iron ore mine for 20 years. The agreement also calls for UMERC to construct and operate approximately 180 MWs of natural gas-fired generation located in the Upper Peninsula of Michigan. Subject to regulatory approval of both the agreement with Tilden and the construction of the proposed generation, the new units are expected to begin commercial



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operation in 2019 and should allow for the retirement of PIPP no later than 2020. Tilden will remain our customer until this new generation begins commercial operation.

NOTE 16—NEW ACCOUNTING PRONOUNCEMENTS

Revenue Recognition

In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. Several amendments were issued subsequent to the standard to clarify the guidance. The core principle of the guidance is to recognize revenue in an amount that an entity is entitled to receive in exchange for goods and services. The guidance also requires additional disclosures about the nature, amount, timing, and uncertainty of revenues and the related cash flows arising from contracts with customers.

We intend to adopt this standard for interim and annual periods beginning January 1, 2018, as required, and plan to use the modified retrospective method of adoption. If applicable, this method requires a cumulative-effect adjustment to be recorded on the balance sheet as of the beginning of 2018, as if the standard had always been in effect. If applicable, disclosures in 2018 will include a reconciliation of results under the new revenue guidance compared with what would have been reported in 2018 under the old revenue recognition guidance in order to help facilitate comparability with the prior periods.

We are currently reviewing our contracts with customers and related financial disclosures to evaluate the impact of the amended guidance on our existing revenue recognition policies and procedures. We consider our tariff sales, excluding the revenue component related to alternative revenue programs, to be in the scope of the new standard. We have evaluated the nature of these revenues and do not expect that there will be a significant shift in the timing or pattern of revenue recognition for such sales. However, in our evaluation, we are also monitoring unresolved implementation issues for our industry, including the impacts of the new guidance on our ability to recognize revenue for certain contracts where collectability is uncertain. The final resolution of these issues could impact our current accounting policies and revenue recognition.

Recognition and Measurement of Financial Instruments

In January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. This guidance requires equity investments, including other ownership interests such as partnerships, unincorporated joint ventures, and limited liability companies, to be measured at fair value with changes in fair value recognized in net income. It also simplifies the impairment assessment of equity investments without readily determinable fair values and amends certain disclosure requirements associated with the fair value of financial instruments. This ASU does not apply to investments accounted for under the equity method of accounting. We are currently assessing the effects this guidance may have on our financial statements.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, and will be applied using a modified retrospective approach. The main provision of this ASU is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP. We are currently assessing the effects this guidance may have on our financial statements.

Financial Instruments Credit Losses

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



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Classification of Certain Cash Receipts and Cash Payments

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, and will be applied using a retrospective transition method. There are eight main provisions of this ASU for which current GAAP either is unclear or does not include specific guidance. We are currently assessing the effects this guidance may have on our financial statements.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. Under this ASU, an employer is required to disaggregate the service cost component from the other components of the net benefit cost. The amendments provide explicit guidance on how to present the service cost component and the other components of the net benefit cost in the income statement and allow only the service cost component of the net benefit cost to be eligible for capitalization. The amendments should be applied retrospectively for the presentation of the service cost component and the other components of the net benefit cost in the income statement, and prospectively for the capitalization of the service cost component in assets. We are currently assessing the effects this guidance may have on our financial statements.



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

CORPORATE DEVELOPMENTS

The following discussion should be read in conjunction with the accompanying financial statements and related notes and our Annual Report on Form 10-K for the year ended December 31, 2016.

Introduction

We are a wholly owned subsidiary of WEC Energy Group, and derive revenues primarily from the distribution and sale of electricity and natural gas to retail customers in Wisconsin. We have combined common functions with WG and operate under the trade name of "We Energies." We conduct our business primarily through our utility reportable segment. See Note 10, Segment Information, for more information on our reportable business segments.

Effective January 1, 2017, our customers and electric distribution assets located in the Upper Peninsula of Michigan were transferred to UMERC, a new stand-alone utility subsidiary of WEC Energy Group. See Note 12, Related Parties, for more information.

Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 12, Related Parties, for more information.

Corporate Strategy

Our goal is to continue to create long-term value for our customers and WEC Energy Group's shareholders by focusing on the following:

Reliability

We have made significant reliability related investments in recent years, and plan to continue making significant capital investments to strengthen and modernize the reliability of our generation and distribution networks.

Operating Efficiency

We continually look for ways to optimize the operating efficiency of our company. For example, we received approval from the PSCW to make changes at ERGS to enable the facility to burn coal from the Powder River Basin located in the western United States. The coal plant was originally designed to burn coal mined from the eastern United States. This project is creating flexibility and has enabled the plant to operate at lower costs, placing it in a better position to be called upon in the MISO Energy Markets, resulting in lower fuel costs for our customers.

WEC Energy Group continues to focus on integrating and improving business processes and IT infrastructure across all of its companies. We expect these integration efforts to continue to drive operational efficiency.

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, plant, and equipment, that are no longer performing as intended, or have an unacceptable risk profile. See Note 2, Dispositions, for information on the sale of the MCPP and Bostco's remaining real estate holdings.

Exceptional Customer Care

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



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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 in order 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.

RESULTS OF OPERATIONS

THREE MONTHS ENDED MARCH 31, 2017

Consolidated Earnings

Our consolidated earnings for the three months ended March 31, 2017 were $101.8 million, compared to $107.3 million for the same period in 2016. See below for additional information on the $5.5 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 more meaningful basis for evaluating utility operations than operating revenues since the majority of prudently incurred fuel and purchased power costs, as well as prudently incurred natural gas costs, are passed through to customers in current rates. As a result, management uses electric and natural gas margins internally when assessing the operating performance of our utility segment as these measures exclude the majority of revenue fluctuations caused by changes in these expenses. Similarly, the presentation of electric and natural gas margins herein is intended to provide supplemental information for investors regarding our operating performance.

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of our utility segment operating performance. Our utility segment operating income for the three months ended March 31, 2017 and 2016 was $185.1 million and $181.5 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.



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Utility Segment Contribution to Operating Income

The following table compares our utility segment's contribution to operating income for the first quarter of 2017 with the first quarter of 2016, including favorable or better, "B", and unfavorable or worse, "W", variances. Effective January 1, 2017, we transferred our electric customers located in the Upper Peninsula of Michigan to UMERC. See Note 12, Related Parties, for more information.



	Three Months Ended March 31
(in millions)	2017		2016		B (W)
Electric revenues	$	821.8	$	835.6	$	(13.8	)
Fuel and purchased power	252.7		251.3		(1.4		)
Total electric margins	569.1		584.3		(15.2		)

Natural gas revenues	150.2		139.9		10.3
Cost of natural gas sold	95.9		85.1		(10.8		)
Total natural gas margins	54.3		54.8		(0.5		)

Total electric and natural gas margins	623.4		639.1		(15.7		)

Other operation and maintenance	327.8		348.2		20.4
Depreciation and amortization	82.1		80.4		(1.7		)
Property and revenue taxes	28.4		29.0		0.6
Operating income	$	185.1	$	181.5	$	3.6

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



	Three Months Ended March 31
(in millions)	2017		2016		B (W)
Operation and maintenance not included in line items below	$	108.8	$	126.0	$	17.2
We Power ⁽¹⁾	127.6		128.6		1.0
Transmission ⁽²⁾	67.0		68.8		1.8
Regulatory amortizations and other pass through expenses ⁽³⁾	24.4		24.8		0.4
Total other operation and maintenance	$	327.8	$	348.2	$	20.4

⁽¹⁾

Represents costs associated with the We Power generation units, including operating and maintenance costs incurred, as well as the lease payments that are billed from We Power to us and then recovered in our rates. During the three months ended March 31, 2017 and 2016, $124.7 million and $122.8 million, respectively, of both lease and operating and maintenance costs were billed to or incurred by us, with the difference in costs billed or incurred and expenses incurred recognized, deferred, or deducted from the regulatory asset.

⁽²⁾

The PSCW has approved escrow accounting for our ATC and MISO network transmission expenses. As a result, we defer as a regulatory asset or liability the differences between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the three months ended March 31, 2017 and 2016, $55.0 million and $85.5 million, respectively, of costs were billed to us by transmission providers.


⁽³⁾	Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income.



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



	Three Months Ended March 31
	MWh (in thousands)
Electric Sales Volumes	2017	2016		B (W)
Customer Class
Residential	1,825.0	1,919.8		(94.8	)
Small commercial and industrial	2,197.6	2,229.5	*	(31.9	)
Large commercial and industrial	1,985.6	2,348.0	*	(362.4	)
Other	38.6	39.2		(0.6	)
Total retail	6,046.8	6,536.5	*	(489.7	)
Wholesale	447.1	243.5		203.6
Resale	2,132.4	2,105.1		27.3
Total sales in MWh	8,626.3	8,885.1	*	(258.8	)


*	Includes distribution sales for customers who purchased power from an alternative electric supplier in Michigan. Effective January 1, 2017, these customers and the related sales were transferred to UMERC.



	Three Months Ended March 31
	Therms (in millions)
Natural Gas Sales Volumes	2017	2016	B (W)
Customer Class
Residential	155.6	159.3	(3.7	)
Commercial and industrial	85.8	85.1	0.7
Total retail	241.4	244.4	(3.0	)
Transport	89.0	95.9	(6.9	)
Total sales in therms	330.4	340.3	(9.9	)



	Three Months Ended March 31
	Degree Days
Weather *	2017	2016	B(W)
Heating (3,278 normal)	2,849	3,105	(256	)


*	Normal heating 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 $15.2 million during the first quarter of 2017, compared with the same period in 2016. The significant factors impacting the lower electric utility margins were:


•	A $14.5 million decrease related to lower retail sales volumes during the first quarter of 2017, primarily driven by warmer winter weather, the transfer of customers and their related sales to UMERC, and an additional day of sales during the same period in 2016 due to leap year. As measured by heating degree days, the first quarter of 2017 was 8.2% warmer than the same period in 2016.


•	A $3.9 million decrease in steam margins related to the sale of the MCPP in April 2016. See Note 2, Dispositions, for more information.

These decreases in margins were partially offset by $7.2 million of lower capacity payments to a counterparty in the first quarter of 2017.

Natural Gas Utility Margins

Natural gas utility margins decreased $0.5 million during the first quarter of 2017, compared with the same period in 2016. The most significant factor impacting the lower natural gas utility margins were lower retail sales volumes, primarily driven by warmer winter weather. The lower margins were partially offset by higher overall retail use per customer.



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Operating Income

Operating income at the utility segment increased $3.6 million during the first quarter of 2017, compared with the same period in 2016. This increase was driven by $19.3 million of lower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes), partially offset by the $15.7 million decrease in margins discussed above.

The significant factors impacting the decrease in operating expenses were:


•	A $7.6 million decrease in operation and maintenance expenses at our plants, partially related to the seasonal operation of one of our plants, the timing of planned outages and maintenance, and the sale of the MCPP in April 2016. See Note 2, Dispositions, for more information on the sale of the MCPP.


•	A $5.1 million decrease in electric and natural gas distribution expenses.


•	A $3.2 million decrease in transmission expenses, We Power costs, and regulatory amortizations and other pass-through expenses included in the table above.

Equity in Earnings of Transmission Affiliate



	Three Months Ended March 31
(in millions)	2017		2016		B (W)
Equity in earnings of transmission affiliate	$	—	$	14.7	$	(14.7	)

At December 31, 2016, we owned approximately 23% of ATC. On January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 12, Related Parties, for more information.

Consolidated Other Income, Net



	Three Months Ended March 31
(in millions)	2017		2016		B (W)
AFUDC – Equity	$	0.7	$	1.5	$	(0.8	)
Other	3.7		1.5		2.2
Other income, net	$	4.4	$	3.0	$	1.4

Consolidated Interest Expense



	Three Months Ended March 31
(in millions)	2017		2016		B (W)
Interest expense	$	29.6	$	29.1	$	(0.5	)

Income Tax Expense



	Three Months Ended March 31
	2017		2016		B (W)
Effective tax rate	36.1	%	36.7	%	0.6	%

Our effective tax rate decreased by 0.6% when compared to the first quarter of 2016, primarily due to increased renewable energy credits related to wind. We expect our 2017 annual effective tax rate to be between 36.0% and 37.0%.



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LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

The following summarizes our cash flows during the three months ended March 31:



(in millions)	2017			2016			Change in 2017 Over 2016
Cash provided by (used in):
Operating activities	$	209.8		$	170.7		$	39.1
Investing activities	(92.2		)	(86.2		)	(6.0		)
Financing activities	(122.1		)	(105.0		)	(17.1		)

Operating Activities

Net cash provided by operating activities increased $39.1 million during the first quarter of 2017, compared with the same period in 2016, driven by:


•	A $107.0 million increase in cash related to a cash payment to WBS in the first quarter of 2016 for transfers of certain benefit-related liabilities to WBS.


•	A $35.7 million increase in cash from lower payments for operating and maintenance costs. During the first quarter of 2017, our payments related to transmission and electric generation costs decreased.

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


•	A $59.1 million net decrease in cash related to $52.1 million of cash paid for income taxes during the first quarter of 2017, compared with $7.0 million of cash received during the same period in 2016. This decrease in cash was primarily the result of the extension of bonus depreciation in December 2015, resulting in a refund received during the first quarter of 2016.


•	A $28.1 million decrease in cash resulting from higher payments for natural gas and fuel and purchased power, primarily due to higher commodity prices. The average per-unit cost of natural gas sold increased 14.1% during the first quarter of 2017, compared with the same period in 2016.

Investing Activities

Net cash used in investing activities increased $6.0 million during the first quarter of 2017, compared with the same period in 2016, driven by:


•	A $13.2 million increase in cash paid for capital expenditures during the first quarter of 2017, which is discussed in more detail below.


•	Cash of $9.9 million received during the first quarter of 2016, related to transfers of certain software to WBS.

These increases in net cash used in investing activities were partially offset by proceeds of $12.9 million received from the sale of the remaining real estate holdings of Bostco in March 2017. See Note 2, Dispositions, for more information.

Capital Expenditures

Capital expenditures for the first quarter ended March 31 were as follows:



(in millions)	2017		2016		Change in 2017 Over 2016
Capital expenditures	$	105.5	$	92.3	$	13.2

The increase in cash paid for capital expenditures during the first quarter of 2017 was driven by upgrades of our natural gas and electric distribution systems, including a meter replacement project.



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See Significant Capital Projects below for more information.

Financing Activities

Net cash used in financing activities increased $17.1 million during the first quarter of 2017, compared with the same period in 2016, primarily driven by:


•	A $172.0 million net decrease in cash related to $124.0 million of net repayments of commercial paper in the first quarter of 2017, compared with $48.0 million of net borrowings in the same period of 2016.


•	A $10.2 million increase in net repayments of our subsidiary's note to our parent during the first quarter of 2017.

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


•	A $100.0 million decrease in dividends paid on common stock. We paid a special dividend to our parent to balance our capital structure during the first quarter of 2016.


•	A $75.0 million equity contribution received from our parent during the first quarter of 2017.

For more information on our short-term financing activities, see Note 4, Short-Term Debt and Lines of Credit.

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

As of March 31, 2017, we were the obligor under a series of tax-exempt pollution control refunding bonds with an outstanding principal amount of $80.0 million. In August 2009, we terminated a letter of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. We purchased the bonds at par plus accrued interest to the date of purchase. As of March 31, 2017, the repurchased bonds were still outstanding but are not reported in our long-term debt since they are held by us. Depending on market conditions and other factors, we may change the method used to determine the interest rate on this bond series and have it remarketed to third parties.

Working Capital

Although not the case as of March 31, 2017, our current liabilities sometimes exceed our current assets. If this were to occur, we would not expect this to have any impact on our liquidity since we believe we have adequate back-up lines of credit in place for ongoing operations. We also can access the capital markets to finance our construction programs and to refinance current maturities of long-term debt, if necessary.



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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, 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)
2017	$	656.6
2018	595.3
2019	574.3
Total	$	1,826.2

The majority of spending consists of upgrading our electric and natural gas distribution systems to enhance reliability.

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 4, Short-Term Debt and Lines of Credit, and Note 11, Variable Interest Entities.

Contractual Obligations

For additional information about our commitments, see Contractual Obligations in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Requirements in our 2016 Annual Report on Form 10-K.

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity, and capital resources. The following discussion should be read together with the information in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources in our 2016 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, industry restructuring, environmental matters, critical accounting policies and estimates, and other matters.

Environmental Matters

See Note 13, Commitments and Contingencies, for a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change.



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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 Annual Report on Form 10-K for the year ended December 31, 2016. In addition to the Form 10-K disclosures, see Note 6, Fair Value Measurements, and Note 7, Derivative Instruments, in this report for information concerning our market risk exposures.



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ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

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 first quarter of 2017 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 2016 Annual Report on Form 10-K. See Note 13, Commitments and Contingencies, in this report for more information on material legal proceedings and matters related to us.

In addition to those legal proceedings referenced above, 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 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 Annual Report on Form 10-K for the year ended December 31, 2016. See Item 1A. Risk Factors in Part I of our 2016 Annual Report on Form 10-K for a discussion of certain risk factors applicable to us.



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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 File



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SIGNATURE

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



		WISCONSIN ELECTRIC POWER COMPANY
		(Registrant)

		/s/ WILLIAM J. GUC
Date:	May 5, 2017	William J. Guc
		Vice President and Controller

		(Duly Authorized Officer and Chief Accounting Officer)



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