WISCONSIN ELECTRIC POWER CO - Quarter Report: 2016 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended September 30, 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 website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes [X] No [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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

September 30, 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 September 30, 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	Dispositions	6
	Note 3	Common Equity	6
	Note 4	Short-Term Debt and Lines of Credit	7
	Note 5	Materials, Supplies, and Inventories	7
	Note 6	Fair Value Measurements	7
	Note 7	Derivative Instruments	9
	Note 8	Employee Benefits	11
	Note 9	Investment in American Transmission Company	11
	Note 10	Segment Information	12
	Note 11	Variable Interest Entities	13
	Note 12	Related Parties	14
	Note 13	Commitments and Contingencies	15
	Note 14	Supplemental Cash Flow Information	19
	Note 15	Regulatory Environment	19
	Note 16	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			32
ITEM 4.	CONTROLS AND PROCEDURES			33
PART II.	OTHER INFORMATION			34
ITEM 1.	LEGAL PROCEEDINGS			34
ITEM 1A.	RISK FACTORS			34
ITEM 6.	EXHIBITS			35
SIGNATURE				36



09/30/2016 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.)
UMERC		Upper Michigan Energy Resources Corporation
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
MPSC		Michigan Public Service Commission
PSCW		Public Service Commission of Wisconsin
SEC		United States Securities and Exchange Commission
WDNR		Wisconsin Department of Natural Resources

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

Environmental Terms
CAIR		Clean Air Interstate Rule
CSAPR		Cross-State Air Pollution Rule
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 Btu)
MW		Megawatt (One MW equals one million Watts)
MWh		Megawatt-hour



09/30/2016 Form 10-Q	ii	Wisconsin Electric Power Company

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Other Terms and Abbreviations
ALJ		Administrative Law Judge
D.C. Circuit Court of Appeals		United States Court of Appeals for the District of Columbia Circuit
Exchange Act		Securities Exchange Act of 1934, as amended
FTRs		Financial Transmission Rights
MCPP		Milwaukee County Power Plant
MISO		Midcontinent Independent System Operator, Inc.
MISO Energy Markets		MISO Energy and Operating Reserves Markets
PIPP		Presque Isle Power Plant
ROE		Return on Equity
Supreme Court		United States Supreme Court
VAPP		Valley Power Plant



09/30/2016 Form 10-Q	iii	Wisconsin Electric Power Company

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of capital projects, sales and customer growth, rate actions and related filings with regulatory authorities, environmental and other regulations and associated compliance costs, legal proceedings, effective tax rate, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, 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 adjustments to our and/or ATC's ROE, and other regulatory decisions impacting our regulated operations;


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


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

•

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


•	Federal and state legislative and regulatory changes relating to the environment, including climate change and other environmental regulations impacting generation facilities and renewable energy standards, the enforcement of these laws and regulations, changes in the interpretation of permit conditions by regulatory agencies, and the recovery of associated remediation and compliance costs;

•

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


•	Changes in credit ratings, interest rates, and our ability to access the capital markets, caused by volatility in the global credit markets, our capitalization structure, and market perceptions of the utility industry or us;


•	Costs and effects of litigation, administrative proceedings, investigations, settlements, claims, and inquiries;


•	The risk of financial loss, including increases in bad debt expense, associated with the inability of our customers, counterparties, and affiliates to meet their obligations;



09/30/2016 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 Wisconsin Energy Corporation's acquisition of Integrys that could reduce anticipated benefits and the ability to successfully integrate the operations of the combined company;


•	Potential business strategies to acquire and dispose of assets or businesses, which cannot be assured to be completed timely or within budgets;


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


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


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

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



09/30/2016 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						Nine Months Ended
	September 30						September 30
(in millions)	2016			2015			2016			2015
Operating revenues	$	1,023.8		$	981.1		$	2,876.5		$	2,948.7

Operating expenses
Cost of sales	357.1			350.6			977.8			1,090.1
Other operation and maintenance	359.4			355.3			1,043.8			1,040.9
Depreciation and amortization	81.9			76.2			243.1			226.5
Property and revenue taxes	29.0			29.2			87.0			88.0
Total operating expenses	827.4			811.3			2,351.7			2,445.5

Operating income	196.4			169.8			524.8			503.2

Equity in earnings of transmission affiliate	14.6			15.7			40.7			42.1
Other income, net	0.5			2.2			6.7			8.7
Interest expense	29.5			30.4			88.0			88.6
Other expense	(14.4		)	(12.5		)	(40.6		)	(37.8		)

Income before income taxes	182.0			157.3			484.2			465.4
Income tax expense	66.5			56.9			178.2			168.4
Net income	115.5			100.4			306.0			297.0

Preferred stock dividend requirements	0.3			0.3			0.9			0.9
Net income attributed to common shareholder	$	115.2		$	100.1		$	305.1		$	296.1

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



09/30/2016 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)	September 30, 2016			December 31, 2015
Assets
Property, plant, and equipment
In service	$	11,183.0		$	10,917.1
Accumulated depreciation	(3,580.6		)	(3,461.9		)
	7,602.4			7,455.2
Construction work in progress	98.0			170.6
Leased facilities, net	2,077.9			2,141.7
Net property, plant, and equipment	9,778.3			9,767.5
Investments
Equity investment in transmission affiliate	405.5			382.2
Other	0.3			0.3
Total investments	405.8			382.5
Current assets
Cash and cash equivalents	12.2			27.1
Accounts receivable and unbilled revenues, net of reserves of $43.5 and $43.0, respectively	448.7			461.4
Accounts receivable from related parties	40.6			41.1
Materials, supplies, and inventories	264.1			301.6
Prepayments	244.0			171.8
Other	12.0			19.6
Total current assets	1,021.6			1,022.6
Deferred charges and other assets
Regulatory assets	1,950.5			1,855.9
Other	93.0			111.1
Total deferred charges and other assets	2,043.5			1,967.0
Total assets	$	13,249.2		$	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	1,019.2			999.7
Retained earnings	2,216.6			2,231.4
Preferred stock	30.4			30.4
Long-term debt	2,660.5			2,658.8
Capital lease obligations	2,755.9			2,692.5
Total capitalization	9,015.5			8,945.7
Current liabilities
Current portion of capital lease obligations	34.8			123.6
Short-term debt	104.5			144.0
Subsidiary note payable to WEC Energy Group	17.1			19.6
Accounts payable	254.2			286.4
Accounts payable to related parties	109.2			95.7
Accrued payroll and benefits	45.1			87.5
Accrued interest	35.2			11.7
Other	72.5			104.0
Total current liabilities	672.6			872.5
Deferred credits and other liabilities
Regulatory liabilities	814.6			741.2
Deferred income taxes	2,355.9			2,110.0
Pension and OPEB obligations	155.3			210.9
Other	235.3			259.3
Total deferred credits and other liabilities	3,561.1			3,321.4

Commitments and contingencies (Note 13)

Total capitalization and liabilities	$	13,249.2		$	13,139.6

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



09/30/2016 Form 10-Q	4	Wisconsin Electric Power Company

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WISCONSIN ELECTRIC POWER COMPANY



CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Nine Months Ended
	September 30
(in millions)	2016			2015
Operating Activities
Net income	$	306.0		$	297.0
Reconciliation to cash provided by operating activities
Depreciation and amortization	249.0			239.6
Deferred income taxes and investment tax credits, net	248.6			49.4
Contributions and payments related to pension and OPEB plans	(6.4		)	(105.9		)
Equity income in transmission affiliate, net of distributions	(13.0		)	(11.5		)
Payments for liabilities transferred to WBS	(116.1		)	—
Change in –
Accounts receivable and unbilled revenues	13.1			27.5
Materials, supplies, and inventories	37.5			(1.5		)
Prepaid taxes	(75.2		)	27.9
Other current assets	16.1			10.2
Accounts payable	(12.2		)	(28.1		)
Accrued taxes	0.8			51.3
Other current liabilities	(5.8		)	0.9
Other, net	(27.8		)	(47.9		)
Net cash provided by operating activities	614.6			508.9

Investing Activities
Capital expenditures	(322.5		)	(368.8		)
Capital contributions to transmission affiliate	(10.4		)	(3.5		)
Proceeds from the sale of assets	31.7			—
Proceeds from assets transferred to WBS	13.1			—
Other, net	2.9			1.6
Net cash used in investing activities	(285.2		)	(370.7		)

Financing Activities
Dividends paid on common stock	(320.0		)	(180.0		)
Dividends paid on preferred stock	(0.9		)	(0.9		)
Issuance of long-term debt	—			250.0
Change in short-term debt	(39.5		)	(223.1		)
Repayment of subsidiary note to WEC Energy Group	(2.5		)	(2.7		)
Other, net	18.6			5.2
Net cash used in financing activities	(344.3		)	(151.5		)

Net change in cash and cash equivalents	(14.9		)	(13.3		)
Cash and cash equivalents at beginning of period	27.1			24.0
Cash and cash equivalents at end of period	$	12.2		$	10.7

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



09/30/2016 Form 10-Q	5	Wisconsin Electric Power Company

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WISCONSIN ELECTRIC POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

September 30, 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 and nine months ended September 30, 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

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

NOTE 2—DISPOSITIONS

Utility Segment – Sale of Milwaukee County Power Plant

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

NOTE 3—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.



09/30/2016 Form 10-Q	6	Wisconsin Electric Power Company

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NOTE 4—SHORT-TERM DEBT AND LINES OF CREDIT

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



(in millions, except percentages)	September 30, 2016			December 31, 2015
Commercial paper
Amount outstanding	$	104.5		$	144.0
Weighted-average interest rate on amounts outstanding	0.52		%	0.70		%

Our average amount of commercial paper borrowings based on daily outstanding balances during the nine months ended September 30, 2016, was $117.6 million with a weighted-average interest rate during the period of 0.49%.

As of September 30, 2016, our subsidiary had a $17.1 million note payable to WEC Energy Group with a weighted-average interest rate of 5.14%.

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	September 30, 2016
Revolving credit facility	December 2020	$	500.0

Less:
Letters of credit issued inside credit facility		$	26.0
Commercial paper outstanding		104.5

Available capacity under existing agreement		$	369.5

NOTE 5—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:



(in millions)	September 30, 2016		December 31, 2015
Materials and supplies	$	143.4	$	151.1
Fossil fuel	83.1		110.5
Natural gas in storage	37.6		40.0
Total	$	264.1	$	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 6—FAIR VALUE MEASUREMENTS

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

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

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

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



09/30/2016 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.

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



	September 30, 2016
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	2.1	$	1.0	$	—	$	3.1
Petroleum products contracts	0.3		—		—		0.3
Coal contracts	—		1.8		—		1.8
FTRs	—		—		5.4		5.4
Total derivative assets	$	2.4	$	2.8	$	5.4	$	10.6

Derivative liabilities
Natural gas contracts	$	0.5	$	0.1	$	—	$	0.6
Petroleum products contracts	1.0		—		—		1.0
Coal contracts	—		0.1		—		0.1
Total derivative liabilities	$	1.5	$	0.2	$	—	$	1.7



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



09/30/2016 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 September 30						Nine Months Ended September 30
(in millions)	2016			2015			2016			2015
Balance at the beginning of the period	$	7.5		$	3.6		$	1.6		$	7.0
Purchases	—			—			8.1			3.9
Settlements	(2.1		)	(1.1		)	(4.3		)	(8.4		)
Balance at the end of the period	$	5.4		$	2.5		$	5.4		$	2.5

Fair Value of Financial Instruments

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



	September 30, 2016				December 31, 2015
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock	$	30.4	$	29.9	$	30.4	$	27.3
Long-term debt	2,660.5		3,101.5		2,658.8		2,888.2

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

NOTE 7—DERIVATIVE INSTRUMENTS

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



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The following table shows our derivative assets and derivative liabilities:



	September 30, 2016				December 31, 2015
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	3.1	$	0.6	$	0.5	$	8.1
Petroleum products contracts	0.3		1.0		0.9		3.3
Coal contracts	1.3		—		1.7		3.4
FTRs	5.4		—		1.6		—
Total other current *	10.1		1.6		4.7		14.8

Other long-term
Natural gas contracts	—		—		—		1.3
Petroleum products contracts	—		—		0.3		1.1
Coal contracts	0.5		0.1		0.3		4.2
Total other long-term *	0.5		0.1		0.6		6.6
Total	$	10.6	$	1.7	$	5.3	$	21.4


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

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



	Three Months Ended September 30, 2016				Three Months Ended September 30, 2015
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	6.8 Dth	$	(0.5	)	4.2 Dth	$	(1.0	)
Petroleum products contracts	3.3 gallons	(0.4		)	0.7 gallons	—
FTRs	7.7 MWh	4.5			6.1 MWh	1.5
Total		$	3.6			$	0.5



	Nine Months Ended September 30, 2016				Nine Months Ended September 30, 2015
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	27.0 Dth	$	(12.5	)	16.5 Dth	$	(7.9	)
Petroleum products contracts	7.5 gallons	(1.9		)	2.4 gallons	—
FTRs	18.6 MWh	6.8			18.2 MWh	4.4
Total		$	(7.6	)		$	(3.5	)

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At September 30, 2016, and December 31, 2015, we had posted cash collateral of $1.8 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:



	September 30, 2016						December 31, 2015
(in millions)	Derivative Assets			Derivative Liabilities			Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	10.6		$	1.7		$	5.3		$	21.4
Gross amount not offset on the balance sheet *	(1.5		)	(1.5		)	(0.7		)	(13.5		)
Net amount	$	9.1		$	0.2		$	4.6		$	7.9


*	Includes cash collateral posted of $12.8 million at December 31, 2015. There was no cash collateral included at September 30, 2016.



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NOTE 8—EMPLOYEE BENEFITS

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



	Pension Costs
	Three Months Ended September 30						Nine Months Ended September 30
(in millions)	2016			2015			2016			2015
Service cost	$	2.7		$	3.7		$	7.9		$	11.0
Interest cost	12.4			13.3			37.3			39.7
Expected return on plan assets	(19.5		)	(20.9		)	(58.3		)	(62.7		)
Amortization of prior service cost	0.4			0.5			1.2			1.5
Amortization of net actuarial loss	8.1			8.8			24.3			26.7
Net periodic benefit cost	$	4.1		$	5.4		$	12.4		$	16.2



	OPEB Costs
	Three Months Ended September 30						Nine Months Ended September 30
(in millions)	2016			2015			2016			2015
Service cost	$	1.9		$	2.2		$	5.5		$	6.7
Interest cost	3.3			3.4			9.9			10.1
Expected return on plan assets	(3.5		)	(4.0		)	(10.5		)	(12.0		)
Amortization of prior service credit	(0.3		)	(0.2		)	(0.8		)	(0.8		)
Amortization of net actuarial loss	0.2			0.1			0.7			0.7
Net periodic benefit cost	$	1.6		$	1.5		$	4.8		$	4.7

We did not make any contributions to our qualified pension plans during the first nine months of 2016. During the nine months ended September 30, 2016, we made payments of $4.4 million related to our non-qualified pension plans and $2.0 million to our OPEB plans. We expect to make payments of $0.8 million related to our non-qualified pension plans and $2.8 million related 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 9—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 September 30				Nine Months Ended September 30
(in millions)	2016		2015		2016		2015
Balance at beginning of period	$	394.8	$	382.9	$	382.2	$	372.9
Add: Earnings from equity method investment	14.6		15.7		40.7		42.1
Add: Capital contributions	5.8		1.1		10.4		3.3
Less: Distributions received	9.7		12.0		27.7		30.6
Less: Other	—		—		0.1		—
Balance at end of period	$	405.5	$	387.7	$	405.5	$	387.7

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, for which we are reimbursed 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 September 30				Nine Months Ended September 30
(in millions)	2016		2015		2016		2015
Charges to ATC for services and construction	$	2.1	$	2.6	$	6.6	$	7.6
Charges from ATC for network transmission services	61.7		59.0		188.3		176.1



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



(in millions)	September 30, 2016		December 31, 2015
Accounts receivable
Services provided to ATC	$	0.9	$	0.6
Accounts payable
Services received from ATC	20.9		19.9

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



	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2016		2015		2016		2015
Income statement data
Revenues	$	158.1	$	164.5	$	476.6	$	482.0
Operating expenses	80.2		78.0		241.0		238.3
Other expense	23.5		23.1		71.2		71.7
Net income	$	54.4	$	63.4	$	164.4	$	172.0



(in millions)	September 30, 2016		December 31, 2015
Balance sheet data
Current assets	$	86.3	$	80.5
Noncurrent assets	4,205.7		3,948.3
Total assets	$	4,292.0	$	4,028.8

Current liabilities	$	420.7	$	330.3
Long-term debt	1,791.2		1,790.7
Other noncurrent liabilities	318.7		245.0
Shareholders' equity	1,761.4		1,662.8
Total liabilities and shareholders' equity	$	4,292.0	$	4,028.8

NOTE 10—SEGMENT INFORMATION

We use operating income to measure segment profitability and to allocate resources to our businesses. At September 30, 2016, we reported two segments, which are described below.

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

The other segment includes our approximate 23% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions, and Bostco, our non-utility subsidiary, that develops and invests in real estate.



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The following tables show summarized financial information related to our reportable segments for the three and nine months ended September 30, 2016 and 2015:



(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Three Months Ended September 30, 2016
Operating revenues	$	1,023.8	$	—	$	1,023.8
Other operation and maintenance	359.4		—		359.4
Depreciation and amortization	81.9		—		81.9
Operating income	196.4		—		196.4
Equity in earnings of transmission affiliate	—		14.6		14.6
Interest expense	29.3		0.2		29.5



(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Three Months Ended September 30, 2015
Operating revenues	$	981.1	$	—	$	981.1
Other operation and maintenance	355.3		—		355.3
Depreciation and amortization	76.2		—		76.2
Operating income	169.8		—		169.8
Equity in earnings of transmission affiliate	—		15.7		15.7
Interest expense	30.1		0.3		30.4



(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Nine Months Ended September 30, 2016
Operating revenues	$	2,876.5	$	—	$	2,876.5
Other operation and maintenance	1,043.8		—		1,043.8
Depreciation and amortization	243.1		—		243.1
Operating income	524.8		—		524.8
Equity in earnings of transmission affiliate	—		40.7		40.7
Interest expense	87.3		0.7		88.0



(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Nine Months Ended September 30, 2015
Operating revenues	$	2,948.7	$	—	$	2,948.7
Other operation and maintenance	1,040.9		—		1,040.9
Depreciation and amortization	226.5		—		226.5
Operating income	503.2		—		503.2
Equity in earnings of transmission affiliate	—		42.1		42.1
Interest expense	87.6		1.0		88.6

NOTE 11—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.



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

American Transmission Company

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 account for ATC as an equity method investment. See Note 9, Investment in American Transmission Company, for more information.

The significant assets and liabilities related to ATC recorded on our balance sheets included our equity investment and accounts payable. At September 30, 2016, and December 31, 2015, our equity investment was $405.5 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 $20.9 million and $19.9 million of accounts payable due to ATC at September 30, 2016, and December 31, 2015, respectively, for network transmission services.

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, 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 $96.6 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under this contract for the nine months ended September 30, 2016, and 2015 were $40.5 million and $40.2 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

NOTE 12—RELATED PARTIES

We and our consolidated subsidiary, Bostco, routinely enter into transactions with related parties, including WEC Energy Group, its subsidiaries, ATC, and other 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. On April 1, 2016, we, along with WEC Energy Group, filed a new agreement for approval with the PSCW and all other relevant state commissions that would replace our current affiliated interest agreements. The PSCW approved the new agreement in August 2016. We are awaiting approval in one other state before the new agreement will be implemented.

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.

Bostco has a note payable to our parent company, WEC Energy Group. At September 30, 2016 and December 31, 2015, the balance of this note payable was $17.1 million and $19.6 million, respectively.



09/30/2016 Form 10-Q	14	Wisconsin Electric Power Company

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



	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2016		2015		2016		2015
Lease agreements
Lease payments to W.E. Power, LLC ⁽¹⁾	$	91.4	$	96.9	$	308.8	$	290.1
Construction work in progress billed to W.E. Power, LLC	10.8		10.7		28.5		24.6

Transactions with WBS
Billings to WBS ⁽²⁾	46.2		9.2		156.0		9.2
Billings from WBS ⁽³⁾	40.4		0.3		266.0		0.3

Transactions with WPS
Billings to WPS	4.1		3.4		7.0		3.4
Billings from WPS	1.4		0.1		1.9		0.1

Transactions with WG
Natural gas purchases from WG	1.3		1.2		4.0		3.9
Services received from WG	6.0		6.2		16.5		17.7
Services provided to WG	15.5		19.9		45.4		60.1


⁽¹⁾	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.


⁽²⁾	Included in the amount of billings to WBS, for the nine months ended September 30, 2016, was $13.1 million for the transfer of certain software to WBS. There were no transfers of assets to WBS during the three months ended September 30, 2016.


⁽³⁾	Included in the amount of billings from WBS, for the three and nine months ended September 30, 2016, was $9.1 million and $116.1 million, respectively, for the transfer of certain benefit-related liabilities to WBS.

NOTE 13—COMMITMENTS AND CONTINGENCIES

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

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 September 30, 2016, were $10,236.7 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 that may potentially affect 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

Cross-State Air Pollution Rule

In July 2011, the EPA issued the CSAPR, which replaced a previous rule, the 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.



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However, in December 2011, the CSAPR requirements were stayed by the 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 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 CSAPR on January 1, 2015. Phase I emissions budgets applied in 2015 and also apply in 2016, while the Phase II emissions budgets discussed below will apply to 2017 and beyond.

In December 2015, the EPA published its proposed update to the CSAPR for the 2008 ozone NAAQS and issued the final rule in September 2016. Starting in 2017, this rule requires reductions in the ozone season (May 1 through September 30) NOxemissions from power plants in 23 states in the eastern United States, including Wisconsin. The EPA updated Phase II CSAPR NOxozone season budgets for electric generating units in the affected states. In the final rule, the EPA significantly increased the NOx ozone season budget from the proposed rule for Wisconsin starting in 2017. We are currently evaluating compliance options that include using our banked allowances, purchasing allowances, implementing natural gas co-firing at certain of our coal plants, and other NOx control optimizations.

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 required the EPA to complete attainment designations for certain areas with large sources by no later than July 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. In July 2016, the EPA finalized its recommendation and published a notice in the Federal Register designating Marquette County, Michigan as unclassified/attainment, effective September 2016.

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

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 Supreme Court ruled on a challenge to the MATS rule and remanded the case back to the D.C. Circuit Court of Appeals, ruling that the EPA failed to appropriately consider the cost of the regulation. The MATS rule remains in effect until the D.C. Circuit Court of Appeals takes action on the EPA's April 2016 updated cost evaluation.

We believe that 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 now in compliance with MATS.



09/30/2016 Form 10-Q	16	Wisconsin Electric Power Company

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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-fueled 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 D.C. Circuit Court of Appeals heard the case in September 2016.

The final rule for existing fossil-fueled 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 time lines 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. Interim goals starting in 2022 would require states to achieve about two-thirds of the 2030 required reduction. 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-fueled 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. We are evaluating potential actions to prepare for compliance with the Clean Power Plan based on current information available, including the implementation of co-firing of natural gas in certain of our coal-fired power plants.

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 reconsideration of the EPA's final standards for existing, as well as for new, modified, and reconstructed generating units. A petition for reconsideration of the EPA's final standards for existing generating units 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 carbon dioxideequivalent reduction goal by about 10%. In May 2016, the EPA denied the state of Wisconsin's petition for reconsideration related to new, modified, and reconstructed generating units, except that the EPA deferred the portion related to the treatment of biomass. The EPA has not issued decisions yet regarding the above referenced petitions for reconsideration of the final EPA standards for existing generating units. In December 2015, Michigan state agencies announced modeling results that suggest that the state will be able to meet existing source requirements until 2025, based on planned coal plant retirements, along with a continuation of state renewable standards and current levels of energy efficiency.

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 satisfy the IM BTA requirements. For VAPP Units 1 and 2, projects to install fish protection screens were completed to meet the IM BTA standard.



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BTA determinations must also be made by the WDNR and MDEQ to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. We have received an EM BTA determination by the WDNR, with EPA concurrence, for our intake modification at VAPP. BTA determinations for EM will be made in future permit reissuances for 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. Based on discussions with the MDEQ, if we provide information about unit retirements with our next National Pollutant Discharge Elimination System permit application and then submit a signed certification by August 2017 stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2022), then the EM BTA requirements will be waived. Entrainment studies were recently completed at PIPP. See UMERC discussion in Note 15, Regulatory Environment, regarding the potential retirement of 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 7 and 8, and the Pleasant Prairie units. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $55 million to $75 million for these advanced treatment and bottom ash transport systems. A similar system would be required at PIPP if we were not expecting to retire the plant. See UMERC discussion in Note 15, Regulatory Environment, regarding the potential retirement of PIPP.

Valley Power Plant Wisconsin Pollutant Discharge Elimination System Permit

The WDNR issued a Wisconsin Pollutant Discharge Elimination System (WPDES) 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 VAPP Units 1 and 2 cooling water intake structures have been completed. The VAPP WPDES permit is now in place and process wastewater is now being received by the Milwaukee Metropolitan Sewage District, which addresses phosphorous, mercury, and ammonia-nitrogen 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.



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



(in millions)	September 30, 2016		December 31, 2015
Regulatory assets	$	16.7	$	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. All of the substantive requirements from the Consent Decree have either been completed (projects) or have been transferred to the plant's Title V permits (operational limits), and the Consent Decree was terminated in August 2016.

NOTE 14—SUPPLEMENTAL CASH FLOW INFORMATION



	Nine Months Ended September 30
(in millions)	2016			2015
Cash (paid) for interest, net of amount capitalized	$	(62.9	)	$	(60.6	)
Cash (paid) for income taxes, net	(0.1		)	(58.7		)
Significant noncash transactions:
Accounts payable related to construction costs	5.3			5.0

NOTE 15—REGULATORY ENVIRONMENT

Upper Michigan Energy Resources Corporation

In June 2016, WEC Energy Group filed a proposal with the MPSC and the PSCW for approval to operate UMERC as a stand-alone utility in the Upper Peninsula of Michigan. This utility will include our and WPS's electric and natural gas distribution assets located in the Upper Peninsula. The proposal was filed pursuant to the MPSC's approval of the acquisition of Integrys, whereby WEC Energy Group agreed to form a separate Michigan utility company. In October 2016, we reached a unanimous settlement agreement with all parties in Michigan, including the MPSC staff, the Michigan attorney general, and the Tilden Mining Company (Tilden), relating to WEC Energy Group's application to form UMERC. As part of the settlement agreement, the existing contract between us and Tilden will remain in place until a new power generation solution for the region is commercially operational. If the settlement agreement is approved by the MPSC, we anticipate that the new utility will become operational effective January 1, 2017.

In August 2016, WEC Energy Group entered into an agreement with Tilden under which it will purchase electric power from UMERC for 20 years. The agreement also calls for UMERC to construct and operate approximately 170 MW of natural gas generation located in the Upper Peninsula of Michigan. The estimated cost of this project is $255 million, 50% of which is expected to be recovered from Tilden, with the remaining 50% expected to be recovered from utility customers located in the Upper Peninsula of Michigan. Subject to regulatory approval of both the agreement with Tilden and the construction of the proposed generation, the new units are expected to achieve commercial operation in 2019 and should allow for the retirement of PIPP by late 2019 or 2020.

NOTE 16—NEW ACCOUNTING PRONOUNCEMENTS

Revenue Recognition

In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. Several amendments were issued subsequent to the standard to clarify the guidance. The core principle of the guidance is to recognize revenue in an amount that an entity is entitled to receive in exchange for



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goods and services. The guidance also requires additional disclosures about the nature, amount, timing, and uncertainty of revenues and the related cash flows arising from contracts with customers. 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. This guidance requires equity investments, including other ownership interests such as partnerships, unincorporated joint ventures, and limited liability companies, to be measured at fair value with changes in fair value recognized in net income. It also simplifies the impairment assessment of equity investments without readily determinable fair values and amends certain disclosure requirements associated with the fair value of financial instruments. This ASU does not apply to investments accounted for under the equity method of accounting. We are currently assessing the effects this guidance may have on our financial statements.

Leases

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

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. Under this ASU, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement, the tax effects of exercised or vested awards are treated as discrete items in the reporting period in which they occur, and excess tax benefits are recognized in the current period regardless of whether the benefit reduces taxes payable. On the cash flow statement, excess tax benefits are classified along with other income tax cash flows as an operating activity, and cash paid by an employer when directly withholding shares for tax purposes is classified as a financing activity. We are currently assessing the effects this guidance may have on our financial statements.

Financial Instruments Credit Losses

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

Classification of Certain Cash Receipts and Cash Payments

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



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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 our customers and WEC Energy Group's shareholders by focusing on the following:

Reliability

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

Operating Efficiency

We continually look for ways to optimize the operating efficiency of our company. For example, we received approval from the PSCW to make changes at the Oak Creek Expansion plant to enable the facility to burn coal from the Powder River Basin located in the western United States. The coal plant was originally designed to burn coal mined from the eastern United States. This project is expected to create flexibility and should 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. See Note 2, Dispositions, for information on the sale of the MCPP.

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.

One example of how we obtain feedback from our customers is through our "We Care" calls, where our employees contact customers after a completed service call. Customer satisfaction is a priority, and making "We Care" calls is one of the main methods we use to gauge our performance in order to improve customer satisfaction and minimize customer dissatisfaction.



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RESULTS OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2016

Consolidated Earnings

Our consolidated earnings for the three months ended September 30, 2016 were $115.2 million, compared to $100.1 million for the same period in 2015. See below for additional information on the $15.1 million increase in earnings.

Utility Segment Contribution to Operating Income

The following table compares our utility segment's contribution to operating income for the third quarter of 2016 with the third quarter of 2015, including favorable or better, "B", and unfavorable or worse, "W", variances:



	Three Months Ended September 30
(in millions)	2016		2015		B (W)
Electric revenues	$	980.4	$	935.8	$	44.6
Fuel and purchased power	337.2		329.2		(8.0		)
Total electric margins	643.2		606.6		36.6

Natural gas revenues	43.4		45.3		(1.9		)
Cost of natural gas sold	19.9		21.4		1.5
Total natural gas margins	23.5		23.9		(0.4		)

Other operation and maintenance	359.4		355.3		(4.1		)
Depreciation and amortization	81.9		76.2		(5.7		)
Property and revenue taxes	29.0		29.2		0.2
Operating income	$	196.4	$	169.8	$	26.6

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



	Three Months Ended September 30
	MWh (in thousands)
Electric Sales Volumes	2016	2015	B (W)
Customer Class
Residential	2,446.0	2,268.5	177.5
Small commercial and industrial	2,492.6	2,380.6	112.0
Large commercial and industrial	2,359.4	2,300.2	59.2
Other	30.2	34.2	(4.0	)
Total retail	7,328.2	6,983.5	344.7
Wholesale	289.4	265.6	23.8
Resale	2,434.4	2,113.1	321.3
Total sales in MWh	10,052.0	9,362.2	689.8
Electric Customer Choice*	55.7	66.3	(10.6	)


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



	Three Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2016	2015	B (W)
Customer Class
Residential	17.6	20.4	(2.8	)
Commercial and industrial	12.7	13.8	(1.1	)
Total retail	30.3	34.2	(3.9	)
Transport	68.5	65.7	2.8
Total sales in therms	98.8	99.9	(1.1	)



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	Three Months Ended September 30
	Degree Days
Weather *	2016	2015	B(W)
Heating (123 normal)	27	94	(67	)
Cooling (527 normal)	781	521	260


*	Normal heating and cooling 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.

Electric utility margins increased $36.6 million during the third quarter of 2016, compared with the same period in 2015. The significant factors impacting the higher electric utility margins were:


•	A $21.3 million increase related to higher sales volumes during the third quarter of 2016, primarily driven by warmer weather. As measured by cooling degree days, the third quarter of 2016 was 49.9% warmer than the same period in 2015.


•	A $14.2 million positive impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, 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.

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 30.6% quarter over quarter, which had no impact on margins.

Natural gas utility margins decreased $0.4 million during the third quarter of 2016, compared with the same period in 2015. This decrease was driven by lower retail sales volumes, including the impact of warmer weather. As measured by heating degree days, the third quarter of 2016 was 71.3% warmer than the same period in 2015. The third quarter is generally not a heating period, and therefore, it historically has the lowest natural gas margins of the year.

Operating Income

Operating income at the utility segment increased $26.6 million during the third quarter of 2016, compared with the same period in 2015. This increase was driven by the $36.2 million net increase in margins discussed above, partially offset by $9.6 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes).

The significant factors impacting the increase in operating expenses were:

•

A $13.8 million expense related to our earnings sharing mechanism in place, effective January 1, 2016. Under the earnings sharing mechanism, if we earn above our authorized return, 50% of the first 50 basis points of additional utility earnings will be shared with customers and will be used to reduce our transmission escrow. All utility earnings above the first 50 basis points will be used to reduce the transmission escrow. This amount is subject to change based on fourth quarter results.


•	A $9.0 million increase in expenses at our generation plants.


•	A $5.7 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.



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These increases in operating expenses were partially offset by a $14.4 million decrease in benefit costs, primarily related to stock-based compensation.

Other Segment



	Three Months Ended September 30
(in millions)	2016		2015		B (W)
Equity in earnings of transmission affiliate	$	14.6	$	15.7	$	(1.1	)

As a result of several ALJ recommendations and a recent FERC decision regarding allowed transmission ROE, we recognized lower earnings during the third quarter of 2016 from our investment in ATC as compared to the same period in 2015. See Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints below for more information on these decisions.

Consolidated Other Income, Net



	Three Months Ended September 30
(in millions)	2016			2015		B (W)
AFUDC – Equity	$	0.7		$	1.7	$	(1.0	)
Other	(0.2		)	0.5		(0.7		)
Other income, net	$	0.5		$	2.2	$	(1.7	)

Consolidated Interest Expense



	Three Months Ended September 30
(in millions)	2016		2015		B (W)
Interest expense	$	29.5	$	30.4	$	0.9

Income Tax Expense



	Three Months Ended September 30
	2016		2015		B (W)
Effective tax rate	36.5	%	36.2	%	(0.3	)%

NINE MONTHS ENDED SEPTEMBER 30, 2016

Consolidated Earnings

Our consolidated earnings for the nine months ended September 30, 2016 were $305.1 million, compared to $296.1 million for the same period in 2015. See below for additional information on the $9.0 million increase in earnings.



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Utility Segment Contribution to Operating Income

The following table compares our utility segment's contribution to operating income for the first nine months of 2016 with the first nine months of 2015, including favorable or better, "B", and unfavorable or worse, "W", variances:



	Nine Months Ended September 30
(in millions)	2016		2015		B (W)
Electric revenues	$	2,631.1	$	2,644.2	$	(13.1	)
Fuel and purchased power	841.9		901.0		59.1
Total electric margins	1,789.2		1,743.2		46.0

Natural gas revenues	245.4		304.5		(59.1		)
Cost of natural gas sold	135.9		189.1		53.2
Total natural gas margins	109.5		115.4		(5.9		)

Other operation and maintenance	1,043.8		1,040.9		(2.9		)
Depreciation and amortization	243.1		226.5		(16.6		)
Property and revenue taxes	87.0		88.0		1.0
Operating income	$	524.8	$	503.2	$	21.6

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



	Nine Months Ended September 30
	MWh (in thousands)
Electric Sales Volumes	2016	2015	B (W)
Customer Class
Residential	6,206.7	5,968.7	238.0
Small commercial and industrial	6,882.3	6,738.4	143.9
Large commercial and industrial	7,006.5	6,812.2	194.3
Other	103.9	107.0	(3.1	)
Total retail	20,199.4	19,626.3	573.1
Wholesale	803.0	972.2	(169.2	)
Resale	6,290.6	6,105.6	185.0
Total sales in MWh	27,293.0	26,704.1	588.9
Electric Customer Choice*	182.7	383.0	(200.3	)


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



	Nine Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2016	2015	B (W)
Customer Class
Residential	233.5	253.2	(19.7	)
Commercial and industrial	128.2	142.2	(14.0	)
Total retail	361.7	395.4	(33.7	)
Transport	239.6	230.0	9.6
Total sales in therms	601.3	625.4	(24.1	)



	Nine Months Ended September 30
	Degree Days
Weather *	2016	2015	B(W)
Heating (4,413 normal)	4,058	4,684	(626	)
Cooling (685 normal)	977	620	357


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



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Electric Utility Margins

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.

Electric utility margins increased $46.0 million during the nine months ended September 30, 2016, compared with the same period in 2015. The significant factors impacting the higher electric utility margins were:


•	A $24.3 million increase related to higher sales volumes during 2016, primarily driven by warmer weather. As measured by cooling degree days, the nine months ended September 30, 2016, were 57.6% warmer than the same period in 2015.


•	A $12.6 million positive impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, 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.


•	The expiration of $9.6 million of bill credits refunded to customers in 2015 related to the treasury grant we received in connection with our biomass facility.

Natural Gas Utility Margins

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 25.0% period over period, which had no impact on margins.

Natural gas utility margins decreased $5.9 million during the nine months ended September 30, 2016, compared with the same period in 2015. The most significant factor impacting the lower natural gas utility margins was a decrease in sales volumes during 2016, primarily driven by warmer weather. As measured by heating degree days, the nine months ended September 30, 2016 were 13.4% warmer than the same period in 2015.

Operating Income

Operating income at the utility segment increased $21.6 million during the nine months ended September 30, 2016, compared with the same period in 2015. The increase was driven by the $40.1 million net increase in margins discussed above, partially offset by $18.5 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes).

The significant factors impacting the increase in operating expenses were:


•	A $16.6 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.

•


•	A $9.0 million increase in expenses at our generation plants.

These increases in operating expenses were partially offset by:


•	A $10.9 million gain on the sale of the MCPP, which was sold in April 2016. See Note 2, Dispositions, for more information.


•	An $8.5 million decrease in benefit costs, primarily related to stock-based compensation.



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Other Segment



	Nine Months Ended September 30
(in millions)	2016		2015		B (W)
Equity in earnings of transmission affiliate	$	40.7	$	42.1	$	(1.4	)

As a result of several ALJ recommendations and a recent FERC decision regarding allowed transmission ROE, we recognized lower earnings during the first nine months of 2016 from our investment in ATC as compared to the same period in 2015. See Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints below for more information on these decisions.

Consolidated Other Income, Net



	Nine Months Ended September 30
(in millions)	2016		2015		B (W)
AFUDC – Equity	$	3.6	$	4.3	$	(0.7	)
Other	3.1		4.4		(1.3		)
Other income, net	$	6.7	$	8.7	$	(2.0	)

Consolidated Interest Expense



	Nine Months Ended September 30
(in millions)	2016		2015		B (W)
Interest expense	$	88.0	$	88.6	$	0.6

Income Tax Expense



	Nine Months Ended September 30
	2016		2015		B (W)
Effective tax rate	36.8	%	36.2	%	(0.6	)%

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 nine months ended September 30:



(in millions)	2016			2015			Change in 2016 Over 2015
Cash provided by (used in):
Operating activities	$	614.6		$	508.9		$	105.7
Investing activities	(285.2		)	(370.7		)	85.5
Financing activities	(344.3		)	(151.5		)	(192.8		)

Operating Activities

Net cash provided by operating activities increased $105.7 million during the nine months ended September 30, 2016, driven by:


•	A $159.4 million increase in cash from lower payments for natural gas and fuel and purchased power, due to lower commodity prices and warmer weather during the 2016 heating season.


•	A $99.5 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 nine months ended September 30, 2016, compared with contributions of $100.0 million during the same period in 2015.



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•	A $58.6 million net increase in cash from lower income tax payments made during the nine months ended September 30, 2016, primarily the result of the enactment of bonus depreciation later in 2015.

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


•	A $116.1 million cash payment for transfers of certain benefit-related liabilities to WBS during the nine months ended September 30, 2016.


•	An $86.0 million decrease in cash related to lower overall collections from customers. Collections from customers decreased because of lower commodity prices and warmer weather during the 2016 heating season.

Investing Activities

Net cash used in investing activities decreased $85.5 million during the nine months ended September 30, 2016, driven by:


•	A $46.3 million decrease in capital expenditures during the nine months ended September 30, 2016, which is discussed in more detail below.


•	Proceeds of $31.7 million received from the sale of the MCPP in April 2016. See Note 2, Dispositions, for more information.


•	Cash of $13.1 million received during the nine months ended September 30, 2016, related to transfers of certain software to WBS.

Capital Expenditures

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



(in millions)	2016		2015		Change in 2016 Over 2015
Capital expenditures	$	322.5	$	368.8	$	(46.3	)

The decrease in cash paid for capital expenditures during the nine months ended September 30, 2016, was partially related to the completion of the conversion of the fuel source for VAPP from coal to natural gas in November 2015. Also contributing to the decrease were lower payments during 2016 related to upgrades of our electric distribution systems and certain software.

See Significant Capital Projects below for more information.

Financing Activities

Net cash used in financing activities increased $192.8 million during the nine months ended September 30, 2016, primarily driven by a $140.0 million increase in dividends paid on common stock during 2016. During the nine months ended September 30, 2016, we paid special dividends to our parent to balance our capital structure.

In addition, we issued $250.0 million of long-term debt during the nine months ended September 30, 2015. This issuance was used to repay short-term debt, leading to $183.6 million of higher net repayments of short-term debt during the nine months ended September 30, 2015.

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



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Capital Resources and Requirements

Capital Resources

Liquidity

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

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

We maintain a bank back-up credit facility, which provides liquidity support for our obligations with respect to commercial paper and for general corporate purposes. We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. See Note 4, Short-Term Debt and Lines of Credit, for more information about our credit facility.

As of September 30, 2016, we were the obligor under a series of tax-exempt pollution control refunding bonds with an outstanding principal amount of $80.0 million. In August 2009, we terminated a letter of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. We purchased the bonds at par plus accrued interest to the date of purchase. As of September 30, 2016, the repurchased bonds were still outstanding but were not reported in our long-term debt since they were held by us. Depending on market conditions and other factors, we may change the method used to determine the interest rate on this bond series and have it remarketed to third parties. A related bond series that had an outstanding principal amount of $67.0 million matured on August 1, 2016.

Credit Rating Risk

We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. However, we have certain agreements in the form of commodity contracts and employee benefit plans that could require collateral or a termination payment in the event of a credit rating change to below BBB- at S&P Global Ratings and/or Baa3 at Moody's Investors Service (Moody's). We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.

In addition, access to capital markets at a reasonable cost is determined in large part by credit quality. Any credit ratings downgrade could impact our ability to access capital markets.

In June 2016, Moody's, among other actions, affirmed our ratings (senior unsecured, A1; commercial paper, P-1) and changed our rating outlook from stable to negative. The change in rating outlook was due to the absence of certain automatic recovery mechanisms in Wisconsin. We do not believe this change in rating outlook will have a material impact on our ability to access capital markets.

Subject to other factors affecting the credit markets as a whole, we believe our current ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, these security ratings reflect the views of the rating agency only. An explanation of the significance of these ratings may be obtained from the rating agency. Such ratings are not a recommendation to buy, sell, or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency.



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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	$	493.9
2017	656.6
2018	595.3
Total	$	1,745.8

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 $126 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 that primarily support our commodity contracts. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see Note 4, Short-Term Debt and Lines of Credit, and Note 11, Variable Interest Entities.

Contractual Obligations

For additional information about our commitments, see Contractual Obligations in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Requirements in our 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 in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources of 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, critical accounting policies and estimates, and other matters.

Environmental Matters

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

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 2013. The FERC conducted hearings in August 2015, and the 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



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by the FERC in January 2015 for MISO transmission owners. The incentive adder only applies to revenues collected after January 6, 2015. In September 2016, the FERC issued a final order related to this complaint affirming the ALJ's initial decision. The final order requires ATC to provide refunds, with interest, for the 15-month refund period from November 13, 2013, through February 11, 2015. The refunds ATC must provide to us for transmission costs paid during this period will reduce the regulatory assets we recorded under the PSCW-approved escrow accounting for transmission expense.

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 February 12, 2015. The FERC conducted hearings in February 2016 with respect to this second complaint, and the ALJ issued an initial decision in June 2016. The ALJ's initial decision recommended that ATC and all other MISO transmission owners be authorized to collect a base ROE of 9.7%, as well as the 0.5% incentive adder approved for MISO transmission owners. The ALJ's initial decision is not binding on the FERC and applies to revenues collected from February 12, 2015, through May 11, 2016. A FERC order related to this complaint is expected during the second quarter of 2017.

Regarding several of the FERC orders, the MISO transmission owners filed various appeals with the D.C. Circuit Court of Appeals as well as requests for rehearings.

These changes to ATC's ROE will result in lower equity earnings and distributions from ATC in the future. Based on the FERC's final order and the ALJ's initial decisions, we recognized lower earnings during the first nine months of 2016 from our investment in ATC as compared with the same period in 2015.



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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 6, Fair Value Measurements, and Note 7, Derivative Instruments, in this report for information concerning our market risk exposures.



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ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the third 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 13, Commitments and Contingencies, in this report for more information on material legal proceedings and matters related to us.

In addition to those legal proceedings 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 I 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:	November 4, 2016	William J. Guc
		Vice President and Controller

		(Duly Authorized Officer and Chief Accounting Officer)



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