WISCONSIN ELECTRIC POWER CO - FORM 10-Q

Attached files

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EX-31.1 - WISCONSIN ELECTRIC EXHIBIT 31.1 - WISCONSIN ELECTRIC POWER CO	wepco03312016ex311.htm
EX-32.1 - WISCONSIN ELECTRIC EXHIBIT 32.1 - WISCONSIN ELECTRIC POWER CO	wepco03312016ex321.htm
EX-32.2 - WISCONSIN ELECTRIC EXHIBIT 32.2 - WISCONSIN ELECTRIC POWER CO	wepco03312016ex322.htm
EX-31.2 - WISCONSIN ELECTRIC EXHIBIT 31.2 - WISCONSIN ELECTRIC POWER CO	wepco03312016ex312.htm

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, 2016



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 Web site, 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, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.



	Large accelerated filer [ ]		Accelerated filer [ ]
	Non-accelerated filer [ X ]		Smaller reporting company [ ]

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, 2016

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, 2016

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	Common Equity	6
	Note 3	Short-Term Debt and Lines of Credit	7
	Note 4	Materials, Supplies, and Inventories	7
	Note 5	Fair Value Measurements	7
	Note 6	Derivative Instruments	9
	Note 7	Employee Benefits	11
	Note 8	Investment in American Transmission Company	11
	Note 9	Segment Information	12
	Note 10	Variable Interest Entities	13
	Note 11	Related Parties	14
	Note 12	Commitments and Contingencies	15
	Note 13	Supplemental Cash Flow Information	18
	Note 14	Regulatory Environment	19
	Note 15	New Accounting Pronouncements	19
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			21
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



03/31/2016 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. (previously known as Integrys Energy Group, Inc.)
WBS		WEC Business Services LLC
WEC Energy Group		WEC Energy Group, Inc. (previously known as Wisconsin Energy Corporation)
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
PSCW		Public Service Commission of Wisconsin
SEC		United States Securities and Exchange Commission
WDNR		Wisconsin Department of Natural Resources

Accounting Terms
ASU		Accounting Standards Update
FASB		Financial Accounting Standards Board
GAAP		United States Generally Accepted Accounting Principles
OPEB		Other Postretirement Employee Benefits

Environmental Terms
CO₂		Carbon Dioxide
GHG		Greenhouse Gas
MATS		Mercury and Air Toxics Standards
NAAQS		National Ambient Air Quality Standards
NOx		Nitrogen Oxide
SO₂		Sulfur Dioxide

Measurements
Btu		British Thermal Units
Dth		Dekatherm (One Dth equals one million British Thermal Units)
MW		Megawatt (One MW equals one million Watts)
MWh		Megawatt-hour

Other Terms and Abbreviations
Exchange Act		Securities Exchange Act of 1934, as amended
FTRs		Financial Transmission Rights
MISO		Midcontinent Independent System Operator, Inc.
MISO Energy Markets		MISO Energy and Operating Reserves Markets
PIPP		Presque Isle Power Plant
ROE		Return on Equity
SSR		System Support Resource
Treasury Grant		Section 1603 Renewable Energy Treasury Grant
VAPP		Valley Power Plant



03/31/2016 Form 10-Q	ii	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, 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, 2015, 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 businesses;


•	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;



03/31/2016 Form 10-Q	1	Wisconsin Electric Power Company

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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 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 financial performance of ATC and its corresponding contribution to our earnings, as well as the ability of ATC and Duke-American Transmission Company to obtain the required approvals for their transmission projects;


•	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 terms and conditions of the governmental and regulatory approvals of WEC Energy Group's acquisition of Integrys that could reduce anticipated benefits and the ability to successfully integrate the operations of the combined company;


•	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.



03/31/2016 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)	2016			2015
Operating revenues	$	975.5		$	1,084.6

Operating expenses
Cost of sales	336.4			433.4
Other operation and maintenance	348.2			342.4
Depreciation and amortization	80.4			74.7
Property and revenue taxes	29.0			29.4
Total operating expenses	794.0			879.9

Operating income	181.5			204.7

Equity in earnings of transmission affiliate	14.7			14.2
Other income, net	3.0			2.5
Interest expense	29.1			28.7
Other expense	(11.4		)	(12.0		)

Income before income taxes	170.1			192.7
Income tax expense	62.5			71.0
Net income	107.6			121.7

Preferred stock dividend requirements	0.3			0.3
Net income attributed to common shareholder	$	107.3		$	121.4

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



03/31/2016 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, 2016			December 31, 2015
Assets
Property, plant, and equipment
In service	$	10,984.6		$	10,917.1
Accumulated depreciation	(3,500.8		)	(3,461.9		)
	7,483.8			7,455.2
Construction work in progress	154.5			170.6
Leased facilities, net	2,120.5			2,141.7
Net property, plant, and equipment	9,758.8			9,767.5
Investments
Equity investment in transmission affiliate	394.3			382.2
Other	0.3			0.3
Total investments	394.6			382.5
Current assets
Cash and cash equivalents	6.6			27.1
Accounts receivable and unbilled revenues, net of reserves of $45.4 and $43.0, respectively	443.7			461.4
Accounts receivable from related parties	19.6			41.1
Materials, supplies, and inventories	266.3			301.6
Prepayments	153.5			171.8
Other	14.0			19.6
Total current assets	903.7			1,022.6
Deferred charges and other assets
Regulatory assets	1,892.5			1,855.9
Other	93.0			111.1
Total deferred charges and other assets	1,985.5			1,967.0
Total assets	$	13,042.6		$	13,139.6

Capitalization and liabilities
Capitalization
Common stock – $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding	$	332.9		$	332.9
Additional paid in capital	1,009.7			999.7
Retained earnings	2,178.8			2,231.4
Preferred stock	30.4			30.4
Long-term debt	2,659.4			2,658.8
Capital lease obligations	2,761.7			2,692.5
Total capitalization	8,972.9			8,945.7
Current liabilities
Current portion of capital lease obligations	46.8			123.6
Short-term debt	192.0			144.0
Subsidiary note payable to WEC Energy Group	17.0			19.6
Accounts payable	200.8			286.4
Accounts payable to related parties	105.9			95.7
Accrued payroll and benefits	38.5			87.5
Other	144.4			115.7
Total current liabilities	745.4			872.5
Deferred credits and other liabilities
Regulatory liabilities	758.0			741.2
Deferred income taxes	2,178.5			2,110.0
Pension and OPEB obligations	163.2			210.9
Other	224.6			259.3
Total deferred credits and other liabilities	3,324.3			3,321.4

Commitments and contingencies (Note 12)

Total capitalization and liabilities	$	13,042.6		$	13,139.6

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



03/31/2016 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)	2016			2015
Operating Activities
Net income	$	107.6		$	121.7
Reconciliation to cash provided by operating activities
Depreciation and amortization	82.4			79.1
Deferred income taxes and investment tax credits, net	65.4			13.1
Contributions and payments related to pension and OPEB plans	(2.9		)	(102.9		)
Equity income in transmission affiliate, net of distributions	(8.7		)	(5.0		)
Payments for liabilities transferred to WBS	(107.0		)	—
Change in –
Accounts receivable and unbilled revenues	39.1			(4.7		)
Materials, supplies, and inventories	35.3			44.4
Other current assets	29.1			27.6
Accounts payable	(67.0		)	(48.8		)
Accrued taxes, net	(4.7		)	47.6
Other current liabilities	11.0			6.2
Other, net	(8.9		)	(33.4		)
Net cash provided by operating activities	170.7			144.9

Investing Activities
Capital expenditures	(92.3		)	(102.1		)
Investment in transmission affiliate	(3.5		)	(1.2		)
Proceeds from assets transferred to WBS	9.9			—
Other, net	(0.3		)	(1.1		)
Net cash used in investing activities	(86.2		)	(104.4		)

Financing Activities
Dividends paid on common stock	(160.0		)	(60.0		)
Dividends paid on preferred stock	(0.3		)	(0.3		)
Change in short-term debt	48.0			9.7
Repayment of subsidiary note to WEC Energy Group	(2.6		)	(2.3		)
Other, net	9.9			3.7
Net cash used in financing activities	(105.0		)	(49.2		)

Net change in cash and cash equivalents	(20.5		)	(8.7		)
Cash and cash equivalents at beginning of period	27.1			24.0
Cash and cash equivalents at end of period	$	6.6		$	15.3

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



03/31/2016 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, 2016

NOTE 1—GENERAL INFORMATION

On June 29, 2015, our parent company, Wisconsin Energy Corporation, acquired Integrys and changed its name to WEC Energy Group, Inc.

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

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2015. 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, 2016, are not necessarily indicative of expected results for 2016 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.

Reclassifications

On the income statement for the three months ended March 31, 2015, we reclassified $2.5 million, from treasury grant to depreciation and amortization. This reclassification was made to be consistent with the current year presentation on the income statement.

On the statement of cash flows for the quarter ended March 31, 2015, we reclassified $0.6 million from depreciation and amortization to other operating activities. In addition, we reclassified $2.9 million of non-qualified pension and OPEB contributions from other operating activities to contributions and payments related to pension and OPEB plans on the statement of cash flows for the quarter ended March 31, 2015. We also reclassified $3.2 million from other investing activities to capital expenditures on the statement of cash flows for the quarter ended March 31, 2015. These reclassifications were made to be consistent with the current period presentation on the statement of cash flows.

NOTE 2—COMMON EQUITY

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 2015 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.



03/31/2016 Form 10-Q	6	Wisconsin Electric Power Company

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NOTE 3—SHORT-TERM DEBT AND LINES OF CREDIT

The following table shows our short-term borrowings:



(in millions, except percentages)	March 31, 2016			December 31, 2015
Commercial paper
Amount outstanding	$	192.0		$	144.0
Weighted-average interest rate on amounts outstanding	0.47		%	0.70		%

Our average amount of commercial paper borrowings based on daily outstanding balances during the three months ended March 31, 2016, was $92.1 million with a weighted-average interest rate during the period of 0.52%.

As of March 31, 2016, our subsidiary had a $17.0 million note payable to WEC Energy Group with a weighted-average interest rate of 5.09%%.

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, 2016
Revolving credit facility	December 2020	$	500.0
Total short-term credit capacity		$	500.0

Less:
Letters of credit issued inside credit facility		$	18.0
Commercial paper outstanding		192.0

Available capacity under existing agreement		$	290.0

NOTE 4—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:



(in millions)	March 31, 2016		December 31, 2015
Materials and supplies	$	149.8	$	151.1
Fossil fuel	99.1		110.5
Natural gas in storage	17.4		40.0
Total	$	266.3	$	301.6

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

NOTE 5—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.



03/31/2016 Form 10-Q	7	Wisconsin Electric Power Company

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

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

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

We recognize transfers at their value as of the end of the reporting period.

We conduct a thorough review of fair value hierarchy classifications on a quarterly basis.

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, 2016
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	0.2	$	0.3	$	—	$	0.5
FTRs	—		—		0.6		0.6
Petroleum products contracts	1.1		—		—		1.1
Coal contracts	—		1.6		—		1.6
Total derivative assets	$	1.3	$	1.9	$	0.6	$	3.8

Derivative liabilities
Natural gas contracts	$	6.2	$	0.1	$	—	$	6.3
Petroleum products contracts	3.5		—		—		3.5
Coal contracts	—		9.9		—		9.9
Total derivative liabilities	$	9.7	$	10.0	$	—	$	19.7



	December 31, 2015
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	0.5	$	—	$	—	$	0.5
FTRs	—		—		1.6		1.6
Petroleum products contracts	1.2		—		—		1.2
Coal contracts	—		2.0		—		2.0
Total derivative assets	$	1.7	$	2.0	$	1.6	$	5.3

Derivative liabilities
Natural gas contracts	$	9.2	$	0.2	$	—	$	9.4
Petroleum products contracts	4.4		—		—		4.4
Coal contracts	—		7.6		—		7.6
Total derivative liabilities	$	13.6	$	7.8	$	—	$	21.4

The derivative assets and liabilities listed in the tables above include options, swaps, 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.



03/31/2016 Form 10-Q	8	Wisconsin Electric Power Company

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



	Three Months Ended March 31
(in millions)	2016			2015
Balance at the beginning of the period	$	1.6		$	7.0
Settlements	(1.0		)	(3.7		)
Balance at the end of the period	$	0.6		$	3.3

Unrealized gains and losses on Level 3 derivatives are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have no impact on earnings. Realized gains and losses on these instruments flow through cost of sales on the statements of income.

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, 2016				December 31, 2015
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock	$	30.4	$	28.6	$	30.4	$	27.3
Long-term debt	$	2,659.4	$	2,978.8	$	2,658.8	$	2,888.2

Due to the short-term nature of cash and cash equivalents, net accounts receivable, 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 upon the quoted market value for the same or similar issues. The fair value of our long-term debt is estimated based upon the quoted market value for the same or similar issues or upon the quoted market prices of United States Treasury issues having a similar term to maturity, adjusted for our bond rating and the present value of future cash flows.

NOTE 6—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. 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, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities.



03/31/2016 Form 10-Q	9	Wisconsin Electric Power Company

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The following table shows our derivative assets and derivative liabilities:



	March 31, 2016				December 31, 2015
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	0.5	$	5.6	$	0.5	$	8.1
Petroleum products contracts	0.9		3.0		0.9		3.3
Coal contracts	1.6		6.9		1.7		3.4
FTRs	0.6		—		1.6		—
Total other current *	3.6		15.5		4.7		14.8

Other long-term
Natural gas contracts	—		0.7		—		1.3
Petroleum products contracts	0.2		0.5		0.3		1.1
Coal contracts	—		3.0		0.3		4.2
Total other long-term *	0.2		4.2		0.6		6.6
Total	$	3.8	$	19.7	$	5.3	$	21.4


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

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



	Three Months Ended March 31, 2016				Three Months Ended March 31, 2015
(in millions)	Volume	Gains (Losses)			Volume	Gains (Losses)
Natural gas contracts	10.6 Dth	$	(7.2	)	6.4 Dth	$	(3.8	)
Petroleum products contracts	1.6 gallons	(0.7		)	0.9 gallons	(0.1		)
FTRs	5.2 MWh	1.8			6.2 MWh	2.1
Total		$	(6.1	)		$	(1.8	)

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, 2016, and December 31, 2015, we had posted collateral of $10.2 million and $14.9 million, respectively, in our margin accounts. These amounts are recorded on the balance sheets in other current assets.

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



	March 31, 2016						December 31, 2015
(in millions)	Derivative Assets			Derivative Liabilities			Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	3.8		$	19.7		$	5.3		$	21.4
Gross amount not offset on the balance sheet *	(0.1		)	(9.7		)	(0.7		)	(13.5		)
Net amount	$	3.7		$	10.0		$	4.6		$	7.9


*	Includes cash collateral posted of $9.6 million and $12.8 million as of March 31, 2016, and December 31, 2015, respectively.



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NOTE 7—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)	2016			2015
Service cost	$	2.7		$	3.7
Interest cost	12.6			13.3
Expected return on plan assets	(19.4		)	(21.0		)
Amortization of prior service cost	0.4			0.5
Amortization of net actuarial loss	8.0			9.0
Net periodic benefit cost	$	4.3		$	5.5



	OPEB Costs
	Three Months Ended March 31
(in millions)	2016			2015
Service cost	$	0.1		$	2.4
Interest cost	1.9			3.4
Expected return on plan assets	(1.2		)	(4.0		)
Amortization of prior service credit	(0.3		)	(0.3		)
Amortization of net actuarial loss	0.2			0.3
Net periodic benefit cost	$	0.7		$	1.8

We did not make any contributions to our qualified pension plans during the first three months of 2016. During the three months ended March 31, 2016, we made payments of $2.1 million related to our non-qualified pension plans and $0.8 million to our OPEB plans. We expect to make payments of $2.8 million to our pension plans and $2.4 million to our OPEB plans during the remainder of 2016, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

NOTE 8—INVESTMENT IN AMERICAN TRANSMISSION COMPANY

We own approximately 23% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. The following table shows changes to our investment in ATC:



	Three Months Ended March 31
(in millions)	2016		2015
Balance at beginning of period	$	382.2	$	372.9
Add: Earnings from equity method investment	14.7		14.2
Add: Capital contributions	3.5		1.2
Less: Distributions received	6.0		9.2
Less: Other	0.1		0.1
Balance at end of period	$	394.3	$	379.0

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 to us by ATC. We are required to pay the cost of needed transmission infrastructure upgrades for new generation projects while the projects are under construction. ATC reimburses us for these costs when the new generation is placed in service.

The following table summarizes our significant related party transactions with ATC:



	Three Months Ended March 31
(in millions)	2016		2015
Charges to ATC for services and construction	$	2.1	$	2.5
Charges from ATC for network transmission services	63.3		59.6



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



(in millions)	March 31, 2016		December 31, 2015
Accounts receivable
Services provided to ATC	$	1.2	$	0.6
Accounts payable
Services received from ATC	21.1		19.9

Summarized financial data for ATC is included in the following tables:



	Three Months Ended March 31
(in millions)	2016		2015
Income statement data
Revenues	$	164.2	$	152.4
Operating expenses	79.1		80.0
Other expense	24.0		24.4
Net income	$	61.1	$	48.0



(in millions)	March 31, 2016		December 31, 2015
Balance sheet data
Current assets	$	88.7	$	80.5
Noncurrent assets	4,022.1		3,948.3
Total assets	$	4,110.8	$	4,028.8

Current liabilities	$	337.8	$	330.3
Long-term debt	1,790.9		1,790.7
Other noncurrent liabilities	265.8		245.0
Shareholders' equity	1,716.3		1,662.8
Total liabilities and shareholders' equity	$	4,110.8	$	4,028.8

NOTE 9—SEGMENT INFORMATION

At March 31, 2016, we reported three segments, which are described below. We manage our reportable segments separately due to their different operating and regulatory environments.


•	Our electric utility segment is engaged in the generation, distribution, and sale of electricity in southeastern (including metropolitan Milwaukee), east central, and northern Wisconsin and the Upper Peninsula of Michigan.


•	Our natural gas utility segment is 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 steam utility segment produces, distributes, and sells steam to space heating and processing customers in metropolitan Milwaukee, Wisconsin.

Operating income is used to measure segment profitability and to allocate resources to our utility businesses. All of our operations and assets are located within the United States.



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The following tables show summarized financial information concerning our reportable segments for the three months ended March 31, 2016 and 2015:



(in millions)	Electric Utility		Natural Gas Utility		Steam Utility		Wisconsin Electric Power Company Consolidated
Three Months Ended March 31, 2016
Operating revenues *	$	822.0	$	139.9	$	13.6	$	975.5
Other operation and maintenance	326.3		18.5		3.4		348.2
Depreciation and amortization	71.6		7.6		1.2		80.4
Operating income	148.5		27.7		5.3		181.5
Equity in earnings of transmission affiliate	14.7		—		—		14.7

(in millions)	Electric Utility		Natural Gas Utility		Steam Utility		Wisconsin Electric Power Company Consolidated
Three Months Ended March 31, 2015
Operating revenues *	$	868.9	$	197.9	$	17.8	$	1,084.6
Other operation and maintenance	323.4		15.2		3.8		342.4
Depreciation and amortization	66.6		7.0		1.1		74.7
Operating income	158.8		38.7		7.2		204.7
Equity in earnings of transmission affiliate	14.2		—		—		14.2


*	We account for all intersegment revenues at rates established by the PSCW. Intersegment revenues were not material.

NOTE 10—VARIABLE INTEREST ENTITIES

In February 2015, the FASB issued ASU 2015-02, Amendments to the Consolidation Analysis. This ASU focuses on the consolidation analysis for companies that are required to evaluate whether they should consolidate certain legal entities. It emphasizes the risk of loss when determining a controlling financial interest and amends the guidance for assessing how related party relationships affect the consolidation analysis of variable interest entities. We adopted the standard upon its effective date in the first quarter of 2016, and our adoption resulted in no changes to our disclosures or financial statement presentation.

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 and 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

We own approximately 23% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. We have determined that ATC is a variable interest entity but that consolidation is not required since we are not ATC's primary beneficiary. We do not have the power to direct the activities that most significantly impact ATC's economic performance. We instead account for ATC as an equity method investment. See Note 8, Investment in American Transmission Company, for more information.

The significant assets and liabilities related to ATC recorded on our balance sheets included our equity investment and accounts payable. At March 31, 2016 and December 31, 2015, our equity investment was $394.3 million and $382.2 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC. In addition, we had $21.1 million and $19.9 million of accounts payable due to ATC at March 31, 2016 and December 31, 2015, respectively, for network transmission services.



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Purchased Power Agreement

We have identified a purchased power agreement that represents a variable interest. This agreement is for 236 MW of firm capacity from a natural gas-fired cogeneration facility, and we account for it as a capital lease. The agreement includes no minimum energy requirements over the remaining term of approximately six years. We have examined the risks of the entity, including operations and 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 $119.2 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 each of the three months ended March 31, 2016 and 2015 were $13.5 million. Our maximum exposure to loss is limited to the capacity payments under the contract.

NOTE 11—RELATED PARTIES

We and our subsidiary, Bostco, routinely enter into transactions with related parties, including WEC Energy Group, its subsidiaries, ATC, and other entities in which we have material interests.

We provide and receive services, property, and other items of value to and from our parent, WEC Energy Group, and other subsidiaries of WEC Energy Group. Following the acquisition of Integrys by Wisconsin Energy Corporation on June 29, 2015, an affiliated interest agreement (Non-WBS AIA) went into effect. The Non-WBS AIA governs the provision and receipt of services by WEC Energy Group's subsidiaries, except that WBS will continue to provide services to Integrys and its subsidiaries only under the existing WBS affiliated interest agreements (WBS AIAs). WBS will provide services to WEC Energy Group and the former Wisconsin Energy Corporation subsidiaries, including us, under new interim WBS affiliated interest agreements (interim WBS AIAs). The PSCW and all other relevant state commissions have approved the Non-WBS AIA or granted appropriate waivers related to the Non-WBS AIA.

Services under the Non-WBS AIA are subject to various pricing methodologies. All services provided by any regulated subsidiary to another regulated subsidiary are priced at cost. All services provided by any regulated subsidiary to any nonregulated subsidiary are priced at the greater of cost or fair market value. All services provided by any nonregulated subsidiary to any regulated subsidiary are priced at the lesser of cost or fair market value. All services provided by any regulated or nonregulated subsidiary to WBS are priced at cost. During the three months ended March 31, 2016, billings to WBS were $56.7 million. Included in this amount was $9.9 million received for the transfer of certain software to WBS.

WBS provides 15 categories of services (including financial, human resource, and administrative services) to us pursuant to the interim WBS AIAs, which have been approved, or from which we have been granted appropriate waivers, by the appropriate regulators, including the PSCW. As required by FERC regulations for centralized service companies, WBS renders services at cost. The PSCW must be notified prior to making changes to the services offered under and the allocation methods specified in the interim WBS AIAs. Other modifications or amendments to the interim WBS AIAs would require PSCW approval. Recovery of allocated costs is addressed in our rate cases. During the three months ended March 31, 2016, billings from WBS were $163.4 million. Included in this amount was $107.0 million paid for the transfer of certain benefit-related liabilities to WBS.

The PSCW orders approving the Non-WBS AIA and the interim WBS AIAs include an April 1, 2016 sunset date for WEC Energy Group and the former Wisconsin Energy Corporation subsidiaries, including us. We requested, and the PSCW Staff granted, an extension of the Non-WBS AIA and the interim WBS AIA agreements through September 28, 2016. On April 1, 2016, we, along with WEC Energy Group, filed a new agreement for approval with the PSCW and other state commissions. Upon approval by the PSCW and all other relevant state commissions, the proposed agreement would replace the Non-WBS AIA, the WBS AIAs, and the interim WBS AIAs.

We provide services to and receive services from ATC for its transmission facilities under several agreements approved by the PSCW. Services are billed to ATC under these agreements at our fully allocated cost. See Note 8, Investment in American Transmission Company, for more information.

Bostco, our consolidated subsidiary, has a note payable to our parent company, WEC Energy Group. At March 31, 2016 and December 31, 2015, the balance of this note payable was $17.0 million and $19.6 million, respectively.



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



	Three months ended March 31
(in millions)	2016		2015
Lease agreements
Lease payments to W.E. Power, LLC *	$	107.4	$	100.3
Construction work in progress billed to W.E. Power, LLC	1.3		12.1

Transactions with WG
Natural gas purchases from WG	1.4		1.4
Services received from WG	1.1		1.3
Services provided to WG	1.9		2.8


*	We make lease payments to W.E. Power, LLC, another subsidiary of WEC Energy Group, for Port Washington Generating Station Units 1 and 2 and Oak Creek Expansion Units 1 and 2.

NOTE 12—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.

Energy Related Purchased Power Agreements

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, 2016, were $10,630.9 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.

Air Quality

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.

In March 2015, a federal court entered a consent decree between the EPA and the Sierra Club and others agreeing to specific actions related to implementing the revised standard for areas containing large sources emitting above a certain threshold level of SO₂. The consent decree requires the EPA to complete attainment designations for certain areas with large sources by no later than July 2, 2016. SO₂emissions from PIPP are above the consent decree emission threshold, which means that the Marquette area required action earlier than would otherwise have been required under the revised NAAQS. However, we were able to show through modeling that the area should be designated as attainment. Based upon this modeling, the state of Michigan recommended to the EPA that the Marquette area be designated as attainment, and in February 2016, the EPA issued a draft recommendation to have the Marquette area classified as unclassified/attainment. We expect the EPA recommendation to be finalized in 2016.

We believe our fleet overall is well positioned to meet the new regulation.



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8-Hour Ozone National Ambient Air Quality Standards

The EPA completed its review of the 2008 8-hour ozone standard in November 2014, and announced a proposal to tighten (lower) the NAAQS. In October 2015, the EPA released the final rule, which lowered the limit for ground-level ozone. This is expected to cause nonattainment designations for some counties in Wisconsin with potential future impacts for our fossil-fueled power plant fleet. For nonattainment areas, the state 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 and are in the process of reviewing and determining potential impacts resulting from this rule.

Mercury and Other Hazardous Air Pollutants

In December 2011, the EPA issued the final MATS rule, which imposes stringent limitations on emissions of mercury and other hazardous air pollutants from coal and oil-fired electric generating units beginning in April 2015. In addition, both Wisconsin and Michigan have state mercury rules that require a 90% reduction of mercury; however, these rules are not in effect as long as MATS is in place. In June 2015, the United States Supreme Court (Supreme Court) ruled on a challenge to the MATS rule and remanded the case back to the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court of Appeals), ruling that the EPA failed to appropriately consider the cost of the regulation. The MATS rule has been remanded to the EPA to address the Supreme Court decision, but remains in effect until the D.C. Circuit Court of Appeals takes action on the EPA's April 2016 updated cost evaluation.

Our fleet is well positioned to comply with this regulation. In April 2013, we received a one year MATS compliance extension from the MDEQ for PIPP through April 2016. The addition of a dry sorbent injection system for further control of mercury and acid gases at PIPP was placed into service in March 2016, and PIPP is in compliance with MATS.

Climate Change

In 2015, the EPA issued the Clean Power Plan, a final rule regulating GHG emissions from existing generating units, 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 final rule for existing fossil generating units, numerous states (including Wisconsin and Michigan), trade associations, and private 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 rule until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that review is sought, at the Supreme Court. In addition, in February 2016, the Governor of Wisconsin issued Executive Order 186, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan.

The final rule for existing fossil generating units seeks to achieve state-specific GHG emission reduction goals by 2030, and would have required states to submit plans by September 6, 2016. States submitting initial plans and requesting an extension would have been required to submit final plans by September 2018, either alone or in conjunction with other states. The timelines for the 2022 through 2029 interim goals and the 2030 final goal for states, as well as all other aspects of the rule, may be changed due to the stay and subsequent legal proceedings.

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. The building blocks used by the EPA to determine each state's emission reduction requirements include a combination of improving power plant efficiency, increasing reliance on combined cycle natural gas units, and adding new renewable energy resources. We are in the process of reviewing the final rule for existing fossil generating units to determine the potential impacts to our operations. The rule could result in significant additional compliance costs, including capital expenditures, could impact how we operate our existing fossil-fueled power plants and biomass facility, and could have a material adverse impact on our operating costs.

Draft Federal Plan and Model Trading Rules were also published in October 2015 for use in developing state plans or for use in states where a plan is not submitted or approved. In December 2015, the state of Wisconsin submitted petitions for review to the EPA of the final standards for existing as well as new, modified, and reconstructed generating units. A petition for review was also submitted jointly by the Wisconsin utilities. Among other things, the petitions narrowly ask the EPA to consider revising the state goal for existing units to reflect the 2013 retirement of the Kewaunee Power Station, which could lower the state's CO₂equivalent reduction goal by about 10%. Michigan state agencies announced modeling results that suggest that the state will be able to meet existing



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source requirements until 2025, based on planned coal plant retirements, along with a continuation of state renewable standards and current levels of energy efficiency.

We are required to report our CO₂ equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2015, we reported CO₂ equivalent emissions of 25.3 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 amounts related to the natural gas that our natural gas operations distribute and sell. For 2015, we reported CO₂ equivalent emissions of 3.7 million metric tonnes to the EPA related to our distribution and sale of natural gas.

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 and entrainment. The rule became effective in October 2014, and applies to all of our existing generating facilities with cooling water intake structures, except for the Oak Creek expansion 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, except for VAPP Unit 1, satisfy the IM BTA requirements. For VAPP Unit 2, a project to install fish protection screens to meet the IM BTA standard was completed in October 2015. The same types of screens are scheduled to be installed on VAPP Unit 1 starting in September 2016.

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 proposed intake modification at VAPP. BTA determinations for EM will be made in future permit reissuances for Port Washington Generating Station, Pleasant Prairie Power Plant, PIPP, and Oak Creek Power Plant Units 5 through 8.

During 2016–2018, we will be completing studies and evaluating options to address the EM BTA requirements at our plants. With the exception of Pleasant Prairie Power Plant (which has existing cooling towers that meet EM BTA requirements), and VAPP, we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at our facilities. In addition, the rule allows the EM BTA requirements to be waived in cases of pending facility retirements, which we are currently considering for PIPP. Based on discussions with the MDEQ, if we submit a signed certification with our next National Pollutant Discharge Elimination System permit application 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 are currently underway at PIPP.

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. Unless pending challenges to the final guidelines are successful, the WDNR and MDEQ will modify the state rules 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 Oak Creek Units 5 and 6, the Pleasant



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Prairie units, and the PIPP units. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $70 million to to $95 million for these advanced treatment and bottom ash transport systems.

Valley Power Plant Wisconsin Pollutant Discharge Elimination System Permit

The WDNR issued a Wisconsin Pollutant Discharge Elimination System permit for VAPP that became effective in January 2013. The permit contains several additional requirements including effluent toxicity testing and monitoring for additional parameters (phosphorous, mercury, and ammonia-nitrogen), and a new heat addition limit from the cooling water discharges that all took effect immediately. Other long-term compliance requirements include thermal discharge studies, phosphorous evaluation and feasibility for reduction, mercury minimization planning, and the installation of new cooling water intake fish protection screens. Installation of wedge wire screens for fish protection on the VAPP Unit 2 cooling water intake structure is complete. An identical modification is scheduled to begin for VAPP Unit 1 in the third quarter of 2016. We are also currently working on plans to meet the remaining long-term requirements.

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, 2016		December 31, 2015
Regulatory assets	$	17.0	$	16.9
Reserves for future remediation	5.6		5.6

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.

Consent Decree

In April 2003, we entered into a Consent Decree with the EPA, in which we agreed to significantly reduce air emissions from our coal-fired power plants. Under the terms of the Consent Decree, we could request its termination after December 31, 2015. We made this termination request in March 2016, and the request is currently under review.

NOTE 13—SUPPLEMENTAL CASH FLOW INFORMATION



	Three Months Ended March 31
(in millions)	2016			2015
Cash (paid) for interest, net of amount capitalized	$	(4.4	)	$	(4.7	)
Cash received (paid) for income taxes, net of (payments) refunds	7.0			(6.0		)
Significant noncash transactions:
Accounts payable related to construction costs	3.2			1.5



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NOTE 14—REGULATORY ENVIRONMENT

2015 Wisconsin Rate Order

In May 2014, we applied to the PSCW for a biennial review of costs and rates. In December 2014, the PSCW approved the following rate adjustments, effective January 1, 2015:

•

A net bill increase related to non-fuel costs for our retail electric customers of approximately $2.7 million (0.1%) in 2015. This amount reflects the receipt of SSR payments from MISO that were higher than we anticipated when we filed our rate request in May 2014, as well as an offset of $26.6 million related to a refund of prior fuel costs and the remainder of the proceeds from a Treasury Grant that we received in connection with our biomass facility. The majority of this $26.6 million was returned to customers in the form of bill credits in 2015.


•	A rate increase for our retail electric customers of $26.6 million (0.9%) in 2016, related to the expiration of the bill credits provided to customers in 2015.


•	A rate decrease of $13.9 million (-0.5%) in 2015 related to a forecasted decrease in fuel costs.


•	A rate decrease of $10.7 million (-2.4%) for our natural gas customers in 2015, with no rate adjustment in 2016.


•	A rate increase of approximately $0.5 million (2.0%) for our Downtown Milwaukee (Valley) steam utility customers in 2015, with no rate adjustment in 2016.


•	A rate increase of approximately $1.2 million (7.3%) for our Milwaukee County steam utility customers in 2015, with no rate adjustment in 2016.

Our authorized ROE was set at 10.2%, and our common equity component remained at an average of 51.0%. The PSCW order reaffirmed the deferral of our transmission costs, and it verified that 2015 and 2016 fuel costs should continue to be monitored using a 2% tolerance window. The PSCW approved a change in rate design for us, which included higher fixed charges to better match the related fixed costs of providing service. The PSCW order also authorized escrow accounting for SSR revenues because of the uncertainty of the actual revenues we will receive under the PIPP SSR agreements. Under escrow accounting, we record SSR revenues from MISO of $90.7 million a year. If actual SSR payments from MISO exceed $90.7 million a year, the difference is deferred and returned to customers, with interest, in a future rate case. If actual SSR payments from MISO are less than $90.7 million a year, the difference is deferred and recovered from customers with interest, in a future rate case.

In January 2015, certain parties appealed a portion of the PSCW's final decision adopting our specific rate design changes, including new charges for customer-owned generation within our service territory. The Dane County Circuit Court, in its November 2015 order, ruled that there was not enough evidence provided in our rate case to support a demand charge for customer-owned generation. As a result, this demand charge did not take effect on January 1, 2016. No other rates approved by the PSCW in the rate case were impacted by the Dane County Circuit Court order.

NOTE 15—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. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and can either be applied retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently assessing the effects this guidance may have on our financial statements.

Classification and Measurement of Financial Instruments

In January 2016, the FASB issued ASU 2016-01, Classification 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. We are currently assessing the effects this guidance may have on our financial statements.



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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. We are currently assessing the effects this guidance may have on our financial statements.

Stock-Based Compensation

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. 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, 2015.

Introduction

We are a wholly owned subsidiary of WEC Energy Group, and are primarily engaged in the business of generating and distributing electricity in Wisconsin and the Upper Peninsula of Michigan and distributing natural gas in Wisconsin. We have combined common functions with WG, an affiliated public utility, and operate under the trade name of "We Energies."

Corporate Strategy

Our goal is to continue to create long-term value for WEC Energy Group's stockholders and our customers 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 network.

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 the Oak Creek Expansion plant to enable the facility to burn coal from the Powder River Basin (PRB) in the Western United States. The coal plant was originally designed to burn coal mined from the Eastern United States, but the price of that coal increased relative to the PRB coal. This project is expected to create flexibility and enable 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.

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.

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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RESULTS OF OPERATIONS

Consolidated Earnings

The following table compares our consolidated results for the first quarter of 2016 with the first quarter of 2015, including favorable or better, "B", and unfavorable or worse, "W", variances:



	Three Months Ended March 31
(in millions)	2016		2015		B (W)
Electric utility segment	$	148.5	$	158.8	$	(10.3	)
Natural gas utility segment	27.7		38.7		(11.0		)
Steam utility segment	5.3		7.2		(1.9		)
Total operating income	181.5		204.7		(23.2		)
Equity in earnings of transmission affiliate	14.7		14.2		0.5
Other income, net	3.0		2.5		0.5
Interest expense	29.1		28.7		(0.4		)
Income before income taxes	170.1		192.7		(22.6		)
Income tax expense	62.5		71.0		8.5
Preferred stock dividend requirements	0.3		0.3		—
Net income attributed to common shareholder	$	107.3	$	121.4	$	(14.1	)

Electric Utility Segment Contribution to Operating Income



	Three Months Ended March 31
(in millions)	2016		2015		B (W)
Electric revenues	$	822.0	$	868.9	$	(46.9	)
Fuel and purchased power	247.9		292.5		44.6
Total electric margins	574.1		576.4		(2.3		)

Other operation and maintenance	326.3		323.4		(2.9		)
Depreciation and amortization	71.6		66.6		(5.0		)
Property and revenue taxes	27.7		27.6		(0.1		)
Operating income	$	148.5	$	158.8	$	(10.3	)

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	2016	2015	B (W)
Customer Class
Residential	1,919.8	2,008.3	(88.5	)
Small commercial and industrial	2,219.6	2,225.2	(5.6	)
Large commercial and industrial	2,299.6	2,159.1	140.5
Other	39.2	39.0	0.2
Total retail	6,478.2	6,431.6	46.6
Wholesale	243.5	420.0	(176.5	)
Resale	2,105.1	2,104.7	0.4
Total sales in MWh	8,826.8	8,956.3	(129.5	)
Electric Customer Choice*	58.3	250.0	(191.7	)


*	Represents distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.



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	Three Months Ended March 31
	Degree Days
Weather *	2016	2015	B(W)
Heating (3,339 normal)	3,105	3,656	(551	)


*	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 are defined as electric revenues less fuel and purchased power costs. We believe that electric utility margins provide a more meaningful basis for evaluating electric utility operations than electric revenues since the majority of prudently incurred fuel and purchased power costs are passed through to customers in current rates under enacted fuel rules.

Margins at the electric utility segment decreased $2.3 million in the first quarter of 2016, and was driven by an $11.2 million decrease related to sales volume variances, primarily driven by warmer weather. As measured by heating degree days, the first quarter of 2016 was 15.1% warmer than 2015.

This decrease in electric utility margins related to sales volumes was partially offset by a $6.2 million increase in margins from a positive impact from collections of fuel and purchased power costs as compared with costs approved in rates, as well as lower fly ash removal costs. Under the fuel rule, we defer under or over-collections of certain fuel and purchased power costs that exceed a 2% price variance from the costs included in rates, and the remaining variance impacts margins. Fly ash removal costs are not included in the fuel rule recovery mechanism.

Operating Income

Operating income at the electric utility segment decreased $10.3 million during the first quarter of 2016, driven by $8.0 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes) and the $2.3 million decrease in margins discussed above.

The significant factor impacting the increase in operating expenses in the first quarter of 2016 was a $5.0 million increase in depreciation and amortization, driven by an overall increase in utility plant in service. In November 2015, we completed the conversion of the fuel source for VAPP from coal to natural gas.

Natural Gas Utility Segment Contribution to Operating Income



	Three Months Ended March 31
(in millions)	2016		2015		B (W)
Natural gas revenues	$	139.9	$	197.9	$	(58.0	)
Cost of natural gas sold	85.1		135.5		50.4
Total natural gas margins	54.8		62.4		(7.6		)

Other operation and maintenance	18.5		15.2		(3.3		)
Depreciation and amortization	7.6		7.0		(0.6		)
Property and revenue taxes	1.0		1.5		0.5
Operating income	$	27.7	$	38.7	$	(11.0	)



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



	Three Months Ended March 31
	Therms (in millions)
Natural Gas Sales Volumes	2016	2015	B (W)
Customer Class
Residential	159.3	190.0	(30.7	)
Commercial and industrial	85.1	103.8	(18.7	)
Total retail	244.4	293.8	(49.4	)
Transport	95.9	100.2	(4.3	)
Total sales in therms	340.3	394.0	(53.7	)



	Three Months Ended March 31
	Degree Days
Weather *	2016	2015	B(W)
Heating (3,339 normal)	3,105	3,656	(551	)


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

Natural Gas Utility Margins

Natural gas utility margins are defined as natural gas revenues less the cost of natural gas sold. We believe that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues, since prudently incurred natural gas commodity costs are passed through to our customers in current rates. The average per-unit cost of natural gas sold decreased 23.9% quarter over quarter, which had no impact on margins.

Margins at the natural gas utility segment decreased $7.6 million in the first quarter of 2016. The significant factor impacting the lower natural gas utility margins was a decrease in sales volumes, primarily driven by warmer weather in the first quarter of 2016. As measured by heating degree days, the first quarter of 2016 was 15.1% warmer than 2015.

Operating Income

Operating income at the natural gas utility segment decreased $11.0 million during the first quarter of 2016, driven by the $7.6 million decrease in margins discussed above and $3.4 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes).

Significant factors impacting the $3.4 million increase in operating expenses in the first quarter of 2016 included higher facility charges from WBS as well as higher depreciation and amortization expense.

Steam Utility Segment Contribution to Operating Income



	Three Months Ended March 31
(in millions)	2016		2015		B (W)
Steam revenues	$	13.6	$	17.8	$	(4.2	)
Fuel costs	3.4		5.4		2.0
Total steam margins	10.2		12.4		(2.2		)

Other operation and maintenance	3.4		3.8		0.4
Depreciation and amortization	1.2		1.1		(0.1		)
Property and revenue taxes	0.3		0.3		—
Operating income	$	5.3	$	7.2	$	(1.9	)



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	Three Months Ended March 31
(in millions)	2016	2015	B (W)
Pounds of steam sales	957	1,128	(171	)



	Three Months Ended March 31
	Degree Days
Weather *	2016	2015	B(W)
Heating (3,339 normal)	3,105	3,656	(551	)


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

Steam Margins

Steam utility margins are defined as steam revenues less fuel costs. We believe that steam utility margins provide a more meaningful basis for evaluating steam utility operations than steam revenues, since the majority of prudently incurred fuel costs are passed through to customers in current rates under enacted fuel rules.

Margins at the steam utility segment decreased $2.2 million during the first quarter of 2016. The significant factor impacting the lower steam utility margins was a decrease related to sales volumes, primarily driven by warmer weather in the first quarter of 2016. As measured by heating degree days, the first quarter of 2016 was 15.1% warmer than 2015.

Operating Income

Operating income at the steam utility segment decreased $1.9 million, primarily driven by the $2.2 million of lower margins discussed above.

Equity in Earnings of Transmission Affiliate



	Three Months Ended March 31
(in millions)	2016		2015		B (W)
Equity in earnings of transmission affiliate	$	14.7	$	14.2	$	0.5

There were no significant changes in earnings from our ownership interest in ATC.

Consolidated Other Income, Net



	Three Months Ended March 31
(in millions)	2016		2015		B (W)
Allowance for Funds Used During Construction – Equity	$	1.5	$	1.2	$	0.3
Other	1.5		1.3		0.2
Other income, net	$	3.0	$	2.5	$	0.5

Other income, net increased by $0.5 million when compared to the first quarter of 2015. This increase was not significant.

Consolidated Interest Expense



	Three months ended March 31
(in millions)	2016		2015		B (W)
Interest expense	$	29.1	$	28.7	$	(0.4	)

There were no significant changes in interest expense.



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Income Tax Expense



	Three months ended March 31
	2016		2015		B (W)
Effective tax rate	36.7	%	36.8	%	0.1	%

There were no significant changes in our effective tax rate. We expect our 2016 annual effective tax rate to be between 36.0% and 37.0%.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

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



(in millions)	2016			2015			Change in 2016 Over 2015
Cash provided by (used in):
Operating activities	$	170.7		$	144.9		$	25.8
Investing activities	(86.2		)	(104.4		)	18.2
Financing activities	(105.0		)	(49.2		)	(55.8		)

Operating Activities

Net cash provided by operating activities increased $25.8 million in the first quarter of 2016, driven by:


•	A $100.0 million decrease in contributions and payments related to our pension and OPEB plans. We did not make any contributions to our qualified pension plans during the first quarter of 2016.


•	A $35.3 million net increase in cash related to lower payments for natural gas, fuel, and purchased power, partially offset by a decrease in cash from lower overall collections from customers in the first quarter of 2016. This net increase was primarily due to the impact of lower commodity prices in the first quarter of 2016.

These increases in net cash provided by operating activities were partially offset by a $107.0 million cash payment for transfers of certain benefit-related liabilities to WBS in the first quarter of 2016.

Investing Activities

Net cash used in investing activities decreased $18.2 million in the first quarter of 2016, driven by:


•	A $9.8 million decrease in capital expenditures in the first quarter of 2016, which is discussed in more detail below.


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

Capital Expenditures

Capital expenditures by business segment for three months ended March 31 were as follows:



Reportable Segment (in millions)	2016		2015		Change in 2016 Over 2015
Electric utility	$	79.4	$	88.4	$	(9.0	)
Natural gas utility	12.9		13.7		(0.8		)
Total capital expenditures	$	92.3	$	102.1	$	(9.8	)

The decrease in capital expenditures at the electric utility segment in the first quarter of 2016 related to various projects including the conversion of the fuel source for VAPP from coal to natural gas, which was completed in November 2015. The remaining



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decrease was related to timing of payments for environmental compliance projects and upgrading of our electric distribution systems.

See Significant Capital Projects below for more information.

Financing Activities

Net cash used in financing activities increased $55.8 million in the first quarter of 2016, primarily driven by a $100.0 million increase in dividends paid on common stock. In the first quarter of 2016, we paid a special dividend to our parent to balance our capital structure. This increase in cash used for financing activities was partially offset by a $38.3 million increase in net borrowings of commercial paper in the first quarter of 2016.

For more information on short-term debt, see Note 3, 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 3, Short-Term Debt and Lines of Credit, for more information about our credit facility.

The following table shows our capitalization structure:



(in millions)	March 31, 2016
Common equity	$	3,521.4	38.2	%
Preferred stock	30.4		0.3	%
Long-term debt	2,659.4		28.8	%
Capital lease obligations ⁽¹⁾	2,808.5		30.4	%
Short-term debt ⁽²⁾	209.0		2.3	%
Total	$	9,228.7	100.0	%


⁽¹⁾	Includes current maturities.


⁽²⁾	Includes subsidiary note payable to WEC Energy Group.

We are the obligor under two series of tax-exempt pollution control refunding bonds in an outstanding principal amount of $147.0 million. In August 2009, we terminated letters 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, 2016, the repurchased bonds were still outstanding, but were not reported in our consolidated long-term debt because they are held by us. One of the series of bonds, with $67.0 million aggregate principal amount outstanding, matures on August 1, 2016. Depending on market conditions and other factors, we may change the method used to determine the interest rate on the other series of bonds and have them remarketed to third parties.



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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)
2016	$	512.5
2017	587.2
2018	608.9
Total	$	1,708.6

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

We expect to provide total capital contributions to ATC (not included in the above table) of approximately $121 million from 2016 through 2018.

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 which 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 3, Short-Term Debt and Lines of Credit, and Note 10, 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 2015 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 under Factors Affecting Results, Liquidity, and Capital Resources in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2015 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, and other matters.

Environmental Matters

Cross-State Air Pollution Rule

In July 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR), which replaced a previous rule, the Clean Air Interstate Rule (CAIR). The purpose of the CSAPR was to limit the interstate transport of emissions of NOx and SO₂ that contribute to fine particulate matter and ozone nonattainment in downwind states through a proposed allocation plan and allowance trading scheme. The rule was to become effective in January 2012. However, in December 2011, the CSAPR requirements were stayed by the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court of Appeals) and CAIR was implemented during the stay period. In August 2012, the D.C. Circuit Court of Appeals issued a ruling vacating and remanding CSAPR and simultaneously reinstating CAIR pending the issuance of a replacement rule by the EPA. The case was appealed to the United States Supreme Court (Supreme Court). In April 2014, the Supreme Court issued a decision largely upholding CSAPR and remanded it to the D.C. Circuit Court of Appeals for further proceedings. In October 2014, the D.C. Circuit Court of Appeals issued a decision that allowed the EPA to begin implementing



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CSAPR on January 1, 2015. The compliance deadlines were also changed by three years, so that Phase I emissions budgets apply in 2015 and 2016, and Phase 2 emissions budgets will apply to 2017 and beyond.

In December 2015, the EPA published its proposed update to the CSAPR for the 2008 ozone NAAQS and plans to issue a final rule by August 2016. Starting in 2017, this proposed rule would reduce ozone season (May 1 through September 30) NOxemissions from power plants in 23 states in the eastern United States. In this rule, the EPA is proposing to update Phase II CSAPR NOxozone season budgets for electric generating units in the 23 states. An approximate 60% reduction in NOxemissions is proposed for Wisconsin and an approximate 29% reduction is proposed for Michigan, beginning in May 2017. Additional investments in controls and/or shifts in generation may be required depending upon the final outcome of the rule. We submitted comments to the EPA and met with EPA representatives in Washington, D.C. on the potential impacts of the rule.

See Note 12, Commitments and Contingencies, for a discussion of additional environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change.

Other Matters

American Transmission Company Allowed Return On Equity Complaints

In November 2013, a group of MISO industrial customer organizations filed a complaint with the FERC requesting to reduce the base ROE used by MISO transmission owners, including ATC, to 9.15%. ATC's current authorized ROE is 12.2%. In October 2014, the FERC issued an order to hear the complaint on ROE and set a refund effective date retroactive to November 12, 2013. The FERC conducted hearings in August 2015, and the administrative law judge (ALJ) issued an initial decision in December 2015. The ALJ's initial decision recommended that ATC and all other MISO transmission owners be authorized to collect a base ROE of 10.32%, as well as the 0.5% incentive adder approved by the FERC in January 2015 for MISO transmission owners. The ALJ's recommendation is not binding on the FERC. A FERC order related to this complaint is expected during the fourth quarter of 2016.

In February 2015, a second complaint was filed with the FERC requesting a reduction in the base ROE used by MISO transmission owners, including ATC, to 8.67%, with a refund effective date retroactive to the filing date of the complaint. The FERC conducted hearings in February 2016 with respect to this second complaint, and an initial decision is expected by June 30, 2016.

In October 2014, the FERC issued an order, in regard to a similar complaint, reducing the base ROE for New England transmission owners from their existing rate of 11.14% to 10.57%. In this order, the FERC used a revised method for determining the appropriate ROE for FERC-jurisdictional electric utilities. The FERC expects its new methodology will narrow the "zone" of reasonable returns on equity. The FERC has stated that it expects future decisions on pending complaints related to similar ROE issues to be guided by the New England transmission decision.

Any change to ATC's ROE could result in lower equity earnings and distributions from ATC in the future. We are currently unable to determine how the FERC may rule in these complaints. However, we believe it is probable that refunds will be required upon resolution of these issues. Based on the ALJ's initial decision in December 2015, ATC reduced its earnings in the fourth quarter of 2015, which resulted in us recognizing lower earnings from our investment in ATC.

Wisconsin Power and Light's Riverside Energy Center Facility

In April 2015, Wisconsin Power and Light Company (WP&L) filed a Certificate of Public Convenience and Necessity application with the PSCW for approval to construct an approximate 650 MW natural gas-fired combined-cycle generating unit in Beloit, Wisconsin. Construction proposals received by WP&L indicate that the unit could generate up to 700 MWs. In the third quarter of 2015, we, along with our affiliated utility, WPS, requested and received intervention in this proceeding. As intervenors, we and WPS proposed purchased power agreement alternatives to the new generating unit. In December 2015, we entered into a settlement agreement with WPS and WP&L that was approved by the PSCW. Based on the settlement agreement, the generating unit cannot become commercially operational before June 1, 2020. In addition, WP&L must enter into a purchased power agreement with us for MISO planning years 2017, 2018, and 2019, whereby we will sell and WP&L will purchase capacity and energy at certain agreed upon prices. Other major terms of the settlement include an agreement on ownership of our future natural gas units and negotiation of a renewable generation joint development plan. In March 2016, the PSCW approved the construction of the new natural gas-fired generating unit.



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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, 2015. In addition to the Form 10-K disclosures, see Note 5, Fair Value Measurements, and

Note 6, 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 2016 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 2015 Annual Report on Form 10-K. See Note 12, Commitments and Contingencies, and Note 14, Regulatory Environment, in this report for more information on material legal proceedings and matters related to us.

In addition to those legal proceedings discussed in our reports to the SEC, 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, 2015. See Item 1A. Risk Factors in Part 1 of our 2015 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 6, 2016	William J. Guc
		Vice President and Controller

		(Duly Authorized Officer and Chief Accounting Officer)



03/31/2016 Form 10-Q	34	Wisconsin Electric Power Company

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WISCONSIN ELECTRIC POWER CO Reports

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