WISCONSIN ELECTRIC POWER CO - Quarter Report: 2015 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, 2015



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

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

Yes [X] No [ ]

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

Yes [X] No [ ]

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



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

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

Yes [ ] No [X]

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

Common Stock, $10 Par Value,

33,289,327 shares outstanding at

September 30, 2015

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, 2015

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	Acquisition	6
	Note 3	Common Equity	7
	Note 4	Short-Term Debt and Lines of Credit	9
	Note 5	Long-Term Debt	9
	Note 6	Fair Value Measurements	9
	Note 7	Derivative Instruments	11
	Note 8	Employee Benefits	12
	Note 9	Investment in ATC	13
	Note 10	Segment Information	14
	Note 11	Variable Interest Entities	14
	Note 12	Commitments and Contingencies	15
	Note 13	Supplemental Cash Flow Information	16
	Note 14	Related Party Transactions	16
	Note 15	Michigan Settlement	17
	Note 16	New Accounting Pronouncements	17
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			19
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			33
ITEM 4.	CONTROLS AND PROCEDURES			34
PART II.	OTHER INFORMATION			35
ITEM 1.	LEGAL PROCEEDINGS			35
ITEM 1A.	RISK FACTORS			35
ITEM 6.	EXHIBITS			36
SIGNATURE				37

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GLOSSARY OF TERMS AND ABBREVIATIONS

The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:



Subsidiaries and Affiliates
ATC		American Transmission Company LLC
Bostco		Bostco LLC
Integrys		Integrys Holding, Inc. (previously known as Integrys Energy Group, Inc.)
WBS		WEC Business Services, LLC
WEC Energy Group		WEC Energy Group, Inc.
Wisconsin Energy		Wisconsin Energy Corporation

Federal and State Regulatory Agencies
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
ICC		Illinois Commerce Commission
MDEQ		Michigan Department of Environmental Quality
MPSC		Michigan Public Service Commission
MPUC		Minnesota Public Utilities 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
BTA		Best Technology Available
EM		Entrainment Mortality
GHG		Greenhouse Gas
IM		Impingement Mortality
MATS		Mercury and Air Toxics Standards
NAAQS		National Ambient Air Quality Standards
SO₂		Sulfur Dioxide
WPDES		Wisconsin Pollutant Discharge Elimination System

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

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Other Terms and Abbreviations
Amended Agreement		Amended and Restated Settlement Agreement with the Attorney General of the State of Michigan, the Staff of the MPSC, and Tilden Mining Company and Empire Iron Mining Partnership
Compensation Committee		Compensation Committee of the Board of Directors of WEC Energy Group
Exchange Act		Securities Exchange Act of 1934, as amended
FTRs		Financial Transmission Rights
MISO		Midcontinent Independent System Operator, Inc.
MISO Energy Markets		MISO Energy and Operating Reserves Markets
PIPP		Presque Isle Power Plant
ROE		Return on Equity
SSR		System Support Resource
Treasury Grant		Section 1603 Renewable Energy Treasury Grant
VAPP		Valley Power Plant

iii

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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 Securities Exchange Act of 1934, as amended (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, dividend payout ratios, effective tax rate, projections related to the pension and other postretirement benefit 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 Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2014, and the following:


•	Factors affecting utility operations such as catastrophic weather-related damage, environmental incidents, unplanned facility outages and repairs and maintenance, changes in the cost or availability of materials needed to operate environmental controls at our electric generating facilities, and electric transmission or natural gas pipeline system constraints;


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


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


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


•	The timely completion of capital projects within budgets, as well as the recovery of those 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, including the extension of bonus depreciation, 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, 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;

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


•	Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading markets and fuel suppliers and transporters;


•	The direct or indirect effect on our business resulting from terrorist 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 American Transmission Company LLC (ATC) and its corresponding contribution to our earnings, as well as the ability of ATC and the Duke-American Transmission Company to obtain the required approvals for their transmission projects;


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


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


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


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


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


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


•	Other considerations disclosed elsewhere herein and in other reports we file with the United States Securities and Exchange Commission (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.

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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)	2015			2014			2015			2014
Operating revenues	$	981.1		$	937.8		$	2,948.7		$	3,070.2

Operating expenses
Fuel and purchased power	329.2			338.2			901.0			951.8
Cost of natural gas sold	21.4			27.7			189.1			327.8
Other operation and maintenance	355.3			315.8			1,040.9			972.2
Depreciation and amortization	76.2			71.4			226.5			210.8
Property and revenue taxes	29.2			28.5			88.0			85.4
Total operating expenses	811.3			781.6			2,445.5			2,548.0

Operating income	169.8			156.2			503.2			522.2

Equity in earnings of transmission affiliate	15.7			15.9			42.1			46.4
Other income, net	2.2			1.4			8.7			8.0
Interest expense	30.4			29.0			88.6			87.6
Other expense	(12.5		)	(11.7		)	(37.8		)	(33.2		)

Income before income taxes	157.3			144.5			465.4			489.0
Income tax expense	56.9			54.4			168.4			181.3
Net income	100.4			90.1			297.0			307.7

Preferred stock dividend requirement	0.3			0.3			0.9			0.9
Earnings available for common stockholder	$	100.1		$	89.8		$	296.1		$	306.8

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

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WISCONSIN ELECTRIC POWER COMPANY



CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts)	September 30, 2015			December 31, 2014
Assets
Property, plant and equipment
In service	$	10,801.1		$	10,544.4
Accumulated depreciation	(3,531.6		)	(3,406.1		)
	7,269.5			7,138.3
Construction work in progress	169.2			140.9
Leased facilities, net	2,151.7			2,215.0
Net property, plant and equipment	9,590.4			9,494.2
Investments
Equity investment in transmission affiliate	387.7			372.9
Other	0.3			0.2
Total investments	388.0			373.1
Current assets
Cash and cash equivalents	10.7			24.0
Accounts receivable and unbilled revenues, net of reserves of $47.0 and $46.8, respectively	434.5			488.4
Accounts receivable from related parties	37.5			8.1
Materials, supplies and inventories	321.9			320.5
Prepayments	98.9			139.5
Deferred income taxes	61.0			46.7
Other	15.4			19.0
Total current assets	979.9			1,046.2
Deferred charges and other assets
Regulatory assets	1,711.2			1,626.9
Other	160.7			106.3
Total deferred charges and other assets	1,871.9			1,733.2
Total assets	$	12,830.2		$	12,646.7
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	997.1			984.4
Retained earnings	2,211.8			2,095.5
Preferred stock	30.4			30.4
Long-term debt	2,415.1			2,165.5
Capital lease obligations	2,689.8			2,712.5
Total capitalization	8,677.1			8,321.2
Current liabilities
Current portion of long-term debt and capital lease obligations	369.1			355.6
Short-term debt	81.0			306.8
Subsidiary note payable to WEC Energy Group	19.7			22.4
Accounts payable	257.6			287.2
Accounts payable to related parties	95.6			87.8
Accrued payroll and benefits	77.5			87.1
Accrued income tax, net	55.8			6.0
Other	122.7			107.7
Total current liabilities	1,079.0			1,260.6
Deferred credits and other liabilities
Regulatory liabilities	616.6			615.9
Deferred income taxes	2,022.7			1,963.9
Pension and other postretirement benefit obligations	195.0			254.5
Other	239.8			230.6
Total deferred credits and other liabilities	3,074.1			3,064.9

Commitments and contingencies (Note 12)

Total capitalization and liabilities	$	12,830.2		$	12,646.7

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

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WISCONSIN ELECTRIC POWER COMPANY



CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Nine Months Ended
	September 30
(in millions)	2015			2014
Operating Activities
Net income	$	297.0		$	307.7
Reconciliation to cash provided by operating activities
Depreciation and amortization	239.6			226.2
Deferred income taxes and investment tax credits, net	49.4			125.6
Contributions to pension and other postretirement plans	(105.9		)	(9.4		)
Change in –
Accounts receivable and unbilled revenues	27.5			136.0
Other current assets	36.6			36.0
Accounts payable	(28.1		)	(7.4		)
Accrued taxes, net	51.3			28.8
Other current liabilities	0.9			(24.1		)
Other, net	(59.4		)	(51.4		)
Net cash provided by operating activities	508.9			768.0

Investing Activities
Capital expenditures	(350.2		)	(377.7		)
Cost of removal, net of salvage	(18.6		)	(15.6		)
Investment in transmission affiliate	(3.5		)	(9.2		)
Other, net	1.6			3.1
Net cash used in investing activities	(370.7		)	(399.4		)

Financing Activities
Dividends paid on common stock	(180.0		)	(330.0		)
Dividends paid on preferred stock	(0.9		)	(0.9		)
Issuance of long-term debt	250.0			250.0
Retirement of long-term debt	—			(300.0		)
Change in total short-term debt	(225.8		)	(3.9		)
Other, net	5.2			6.5
Net cash used in financing activities	(151.5		)	(378.3		)

Net change in cash and cash equivalents	(13.3		)	(9.7		)
Cash and cash equivalents at beginning of period	24.0			25.1
Cash and cash equivalents at end of period	$	10.7		$	15.4

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

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WISCONSIN ELECTRIC POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

September 30, 2015

NOTE 1—GENERAL INFORMATION

On June 29, 2015, our parent company, Wisconsin Energy Corporation (Wisconsin Energy), acquired Integrys, and the combined company was renamed WEC Energy Group, Inc. See Note 2, Acquisition, for more information on this acquisition.

As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the condensed consolidated income statements, condensed consolidated balance sheets, and condensed consolidated 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 LLC (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 United States Generally Accepted Accounting Principles (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, 2014. 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, 2015, are not necessarily indicative of expected results for 2015 due to seasonal variations and other factors.

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

NOTE 2—ACQUISITION

On June 29, 2015, our parent company, Wisconsin Energy, acquired 100% of the outstanding common shares of Integrys, a provider of regulated natural gas and electricity, as well as nonregulated renewable energy and compressed natural gas products and services. The combined company was renamed WEC Energy Group, Inc. Our parent company now owns approximately 60% of ATC, a for-profit transmission company regulated by the Federal Energy Regulatory Commission (FERC). Our ownership interest in ATC did not change as a result of the acquisition.

The acquisition was subject to the approvals of various government agencies, including the Public Service Commission of Wisconsin (PSCW). Approvals were obtained from all agencies subject to several conditions. The PSCW order includes the following conditions:

•

We will be subject to an earnings sharing mechanism for three years beginning January 1, 2016. Under the earnings sharing mechanism, if we earn over our authorized rate of return, 50% of the first 50 basis points of additional utility earnings will be shared with customers and will reduce our transmission escrow. All utility earnings above the first 50 basis points will be solely used to reduce the transmission escrow.

•

Any future electric generation projects affecting Wisconsin ratepayers submitted by WEC Energy Group or its subsidiaries will first consider the extent to which existing intercompany resources can meet energy and capacity needs. In September 2015, we and Wisconsin Public Service Corporation filed a joint integrated resource plan with the PSCW for our combined loads, which indicated that no new generation is currently needed.

We do not believe that the conditions set forth in the various regulatory orders approving the acquisition will have a material impact on our operations or financial results.

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NOTE 3—COMMON EQUITY

Stock Option Activity

The following table identifies non-qualified stock options granted by the Compensation Committee of the Board of Directors of WEC Energy Group (Compensation Committee) to our employees:



	2015			2014
Non-qualified stock options granted year to date	495,550			864,860

Estimated fair value per non-qualified stock option	$	5.29		$	4.18

Assumptions used to value the options using a binomial option pricing model:
Risk-free interest rate	0.1% – 2.1%			0.1% – 3.0%
Dividend yield	3.7		%	3.8		%
Expected volatility	18.0		%	18.0		%
Expected forfeiture rate	2.0		%	2.0		%
Expected life (years)	5.8			5.8

The risk-free interest rate is based on the U.S. Treasury interest rate with a term consistent with the expected life of the stock options. Dividend yield, expected volatility, expected forfeiture rate, and expected life assumptions are based on WEC Energy Group's historical experience.

The following is a summary of our employees' WEC Energy Group stock option activity during the three and nine months ended September 30, 2015:



					Weighted-Average
					Remaining	Aggregate
	Number of		Weighted-Average		Contractual Life	Intrinsic Value
Stock Options	Options		Exercise Price		(in years)	(in millions)
Outstanding as of July 1, 2015	6,433,313		$	32.41
Granted	—		$	—
Exercised	(593,230	)	$	23.77
Outstanding as of September 30, 2015	5,840,083		$	33.28

Outstanding as of January 1, 2015	6,450,277		$	30.07
Granted	495,550		$	52.90
Exercised	(1,105,744	)	$	23.33
Outstanding as of September 30, 2015	5,840,083		$	33.28	5.8	$	110.6

Exercisable as of September 30, 2015	3,212,468		$	26.56	4.1	$	82.4

The intrinsic value of WEC Energy Group options exercised by our employees was $15.6 million and $30.2 million for the three and nine months ended September 30, 2015, and $12.7 million and $28.6 million for the same periods in 2014, respectively. Cash received by WEC Energy Group from exercises of its options by our employees was $25.8 million and $30.4 million for the nine months ended September 30, 2015 and 2014, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was $12.1 million and $11.5 million, respectively.

As of September 30, 2015, total compensation cost related to non-vested WEC Energy Group stock options held by our employees and not yet recognized was approximately $2.3 million, which is expected to be recognized over the next 17 months on a weighted-average basis.

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Restricted Shares

The following activity related to restricted stock held by our employees occurred during the three and nine months ended September 30, 2015:



			Weighted-Average
Restricted Shares	Number of Shares		Grant Date Fair Value
Outstanding as of July 1, 2015	93,639		$	46.30
Granted	82,943		$	49.17
Released	—		$	—
Forfeited	(181	)	$	46.16
Outstanding as of September 30, 2015	176,401		$	47.65

Outstanding as of January 1, 2015	100,657		$	38.81
Granted	126,155		$	50.75
Released	(50,230	)	$	37.73
Forfeited	(181	)	$	46.16
Outstanding as of September 30, 2015	176,401		$	47.65

On July 31, 2015, the Compensation Committee awarded certain of our officers and other employees an aggregate of 82,943 shares of restricted stock for the key role each played in WEC Energy Group's acquisition of Integrys. The restricted stock vests in three equal installments on January 29, 2016, January 31, 2017, and July 31, 2018.

WEC Energy Group recognizes the grant date fair value of restricted stock awards in expense over the vesting period of the awards. The intrinsic value of WEC Energy Group restricted stock held by our employees that vested was zero and $2.7 million for the three and nine months ended September 30, 2015, and zero and $2.3 million for the same periods in 2014, respectively. The actual tax benefit realized for the tax deductions from released restricted shares was zero and $1.1 million for the three and nine months ended September 30, 2015, and zero and $0.9 million for the same periods in 2014, respectively.

As of September 30, 2015, total compensation cost related to our share of WEC Energy Group restricted stock not yet recognized was approximately $2.8 million, which is expected to be recognized over the next 22 months on a weighted-average basis.

Performance Units

In January 2015 and 2014, the Compensation Committee awarded 187,450 and 224,735 WEC Energy Group performance units, respectively, to our officers and other key employees under the WEC Energy Group Performance Unit Plan. Performance units earned as of December 31, 2014 and 2013 vested and were settled during the first quarter of 2015 and 2014, and had a total intrinsic value of $11.6 million and $13.1 million, respectively. The actual tax benefit realized for the tax deductions from the settlement of performance units was approximately $4.2 million and $4.7 million, respectively. As of September 30, 2015, total compensation cost related to our share of WEC Energy Group performance units not yet recognized was approximately $11.9 million, which is expected to be recognized over the next 21 months on a weighted-average basis.

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, under Wisconsin law, we are prohibited from loaning funds, either directly or indirectly, to WEC Energy Group. See Note H—Common Equity in our 2014 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.

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NOTE 4—SHORT-TERM DEBT AND LINES OF CREDIT

Our outstanding short-term borrowings were as follows:



(in millions, except percentages)	September 30, 2015			December 31, 2014
Commercial paper	$	81.0		$	306.8
Weighted-average interest rate on commercial paper outstanding	0.21		%	0.25		%

Our average amount of commercial paper borrowings based on daily outstanding balances during the nine months ended September 30, 2015, was $187.6 million with a weighted-average interest rate during the period of 0.23%.

We manage our liquidity by maintaining what we believe to be adequate external financing commitments. 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, 2015
Revolving credit facility	December 2019	$	500.0
Less:
Letters of credit issued inside credit facility		$	18.0
Commercial paper outstanding		81.0
Available capacity under existing agreements		$	401.0

NOTE 5—LONG-TERM DEBT

In May 2015, we issued $250.0 million of 3.10% Debentures due June 1, 2025. The net proceeds were used to repay short-term debt and for general corporate purposes.

In May 2014, we issued $250.0 million of 4.25% Debentures due June 1, 2044. The net proceeds were used to repay short-term debt and for general corporate purposes.

On April 1, 2014, we used short-term borrowings to retire $300.0 million of long-term debt that matured.

NOTE 6—FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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When possible, we base the valuations of our risk management 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.

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:



	As of September 30, 2015
(in millions)	Level 1		Level 2		Level 3		Total
Derivative Assets
Natural gas contracts	$	0.7	$	—	$	—	$	0.7
Financial transmission rights (FTRs)	—		—		2.5		2.5
Petroleum products contracts	0.4		—		—		0.4
Coal contracts	—		0.8		—		0.8
Total Derivative Assets	$	1.1	$	0.8	$	2.5	$	4.4

Derivative Liabilities
Natural gas contracts	$	7.6	$	0.2	$	—	$	7.8
Petroleum products contracts	1.4		—		—		1.4
Coal contracts	—		2.1		—		2.1
Total Derivative Liabilities	$	9.0	$	2.3	$	—	$	11.3



	As of December 31, 2014
(in millions)	Level 1		Level 2		Level 3		Total
Derivative Assets
Natural gas contracts	$	0.4	$	1.9	$	—	$	2.3
FTRs	—		—		7.0		7.0
Coal contracts	—		3.3		—		3.3
Total Derivative Assets	$	0.4	$	5.2	$	7.0	$	12.6

Derivative Liabilities
Natural gas contracts	$	6.8	$	0.3	$	—	$	7.1
Coal contracts	—		0.2		—		0.2
Total Derivative Liabilities	$	6.8	$	0.5	$	—	$	7.3

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 Midcontinent Independent System Operator, Inc. (MISO) market.

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)	2015			2014			2015			2014
Balance at the beginning of the period	$	3.6		$	14.1		$	7.0		$	3.5
Purchases	—			—			3.9			15.6
Settlements	(1.1		)	(4.0		)	(8.4		)	(9.0		)
Balance at the end of the period	$	2.5		$	10.1		$	2.5		$	10.1

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

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Fair Value of Financial Instruments

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



	September 30, 2015				December 31, 2014
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock, no redemption required	$	30.4	$	27.1	$	30.4	$	27.1
Long-term debt, including current portion	$	2,687.0	$	2,626.8	$	2,437.0	$	2,759.6

Due to the short-term nature of cash and cash equivalents, net accounts receivable, accounts payable, and short-term borrowings, the carrying amount of each such item approximates fair value. The fair value of our preferred stock is estimated based upon the quoted market value for the same or similar issues. The fair value of our long-term debt, including the current portion of long-term debt, but excluding capitalized leases and unamortized discount on debt, is estimated based upon the quoted market value for the same or similar issues or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows.

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 the balance sheet as an asset or liability measured at its fair value. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of fair value accounting to be offset to regulatory assets and liabilities.

The following table shows our derivative assets and derivative liabilities:



		September 30, 2015				December 31, 2014
(in millions)	Balance Sheet Presentation	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Natural gas	Other current	$	0.7	$	6.8	$	2.3	$	6.4
Natural gas	Other long-term	—		1.0		—		0.7
Petroleum products	Other current	0.2		1.0		—		—
Petroleum products	Other long-term	0.2		0.4		—		—
FTRs	Other current	2.5		—		7.0		—
Coal	Other current	0.8		1.8		2.7		0.2
Coal	Other long-term	—		0.3		0.6		—
	Other current	4.2		9.6		12.0		6.6
	Other long-term	0.2		1.7		0.6		0.7
Total		$	4.4	$	11.3	$	12.6	$	7.3

Our condensed consolidated income statements include gains (losses) on derivative instruments in fuel and purchased power for those commodities supporting our electric operations and in cost of natural gas sold for the natural gas sold to our customers. Our estimated notional volumes and gains (losses) were as follows:



	Three Months Ended September 30, 2015				Three Months Ended September 30, 2014
(in millions)	Volume	Gains (Losses)			Volume	Gains (Losses)
Natural gas	4.2 Dth	$	(1.0	)	4.1 Dth	$	(0.5	)
Petroleum products	0.7 gallons	—			2.6 gallons	—
FTRs	6.1 MWh	1.5			6.6 MWh	2.0
Total		$	0.5			$	1.5

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	Nine Months Ended September 30, 2015				Nine Months Ended September 30, 2014
(in millions)	Volume	Gains (Losses)			Volume	Gains
Natural gas	16.5 Dth	$	(7.9	)	16.7 Dth	$	4.9
Petroleum products	2.4 gallons	—			7.0 gallons	0.6
FTRs	18.2 MWh	4.4			19.7 MWh	11.6
Total		$	(3.5	)		$	17.1

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, 2015, and December 31, 2014, we had posted collateral of $11.0 million and $6.9 million, respectively, in our margin accounts. These amounts are recorded on the condensed consolidated 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, 2015						December 31, 2014
	Derivative			Derivative			Derivative			Derivative
(in millions)	Assets			Liabilities			Assets			Liabilities
Gross amount recognized on the balance sheet	$	4.4		$	11.3		$	12.6		$	7.3
Gross amount not offset on balance sheet *	(0.9		)	(8.9		)	(0.4		)	(6.8		)
Net Amount	$	3.5		$	2.4		$	12.2		$	0.5


*	Includes cash collateral posted of $8.0 million and $6.4 million as of September 30, 2015, and December 31, 2014, respectively.

NOTE 8—EMPLOYEE BENEFITS

The following table shows the components of net periodic pension and other postretirement employee benefits (OPEB) costs for our benefit plans:



	Pension Costs
	Three Months Ended September 30						Nine Months Ended September 30
(in millions)	2015			2014			2015			2014
Service cost	$	3.7		$	2.3		$	11.0		$	7.0
Interest cost	13.3			14.8			39.7			44.5
Expected return on plan assets	(20.9		)	(19.7		)	(62.7		)	(59.3		)
Amortization of:
Prior service cost	0.5			0.5			1.5			1.5
Actuarial loss	8.8			6.7			26.7			20.2
Net Periodic Benefit Cost	$	5.4		$	4.6		$	16.2		$	13.9



	OPEB Costs
	Three Months Ended September 30						Nine Months Ended September 30
(in millions)	2015			2014			2015			2014
Service cost	$	2.2		$	2.0		$	6.7		$	6.0
Interest cost	3.4			3.6			10.1			10.8
Expected return on plan assets	(4.0		)	(4.0		)	(12.0		)	(12.1		)
Amortization of:
Prior service credit	(0.2		)	(0.4		)	(0.8		)	(1.2		)
Actuarial loss	0.1			—			0.7			0.1
Net Periodic Benefit Cost	$	1.5		$	1.2		$	4.7		$	3.6

We contributed $100.0 million to our qualified pension plan during the first nine months of 2015. No such contribution was made during the first nine months of 2014.

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NOTE 9—INVESTMENT IN ATC

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



	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2015		2014		2015		2014
Balance at beginning of period	$	382.9	$	366.5	$	372.9	$	354.1
Add: Earnings from equity method investment	15.7		15.9		42.1		46.4
Add: Capital contributions	1.1		2.2		3.3		9.1
Less: Distributions received	12.0		12.5		30.6		37.5
Balance at end of period	$	387.7	$	372.1	$	387.7	$	372.1

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



	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2015		2014		2015		2014
Income statement data
Revenues	$	164.5	$	163.7	$	482.0	$	487.0
Operating expenses	78.0		76.6		238.3		229.6
Other expense	23.1		21.6		71.7		65.1
Net income	$	63.4	$	65.5	$	172.0	$	192.3



(in millions)	September 30, 2015		December 31, 2014
Balance sheet data
Current assets	$	80.8	$	66.4
Noncurrent assets	3,900.9		3,728.7
Total assets	$	3,981.7	$	3,795.1

Current liabilities	$	294.8	$	313.1
Long-term debt	1,800.0		1,701.0
Other noncurrent liabilities	207.1		163.8
Shareholders' equity	1,679.8		1,617.2
Total liabilities and shareholders' equity	$	3,981.7	$	3,795.1

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NOTE 10—SEGMENT INFORMATION

Summarized financial information concerning our reportable segments for the three and nine months ended September 30, 2015 and 2014, is shown in the following table:



	Reportable Segments
(in millions)	Electric		Natural Gas			Steam			Total
Three Months Ended September 30, 2015
Operating revenues *	$	929.7	$	45.3		$	6.1		$	981.1
Depreciation and amortization	$	67.7	$	7.4		$	1.1		$	76.2
Operating income (loss)	$	171.2	$	—		$	(1.4	)	$	169.8

Three Months Ended September 30, 2014
Operating revenues *	$	880.1	$	51.9		$	5.8		$	937.8
Depreciation and amortization	$	62.7	$	7.7		$	1.0		$	71.4
Operating income (loss)	$	158.5	$	(0.3	)	$	(2.0	)	$	156.2

Nine Months Ended September 30, 2015
Operating revenues *	$	2,612.1	$	304.5		$	32.1		$	2,948.7
Depreciation and amortization	$	201.5	$	21.6		$	3.4		$	226.5
Operating income	$	452.4	$	45.1		$	5.7		$	503.2

Nine Months Ended September 30, 2014
Operating revenues *	$	2,579.6	$	458.2		$	32.4		$	3,070.2
Depreciation and amortization	$	185.2	$	22.8		$	2.8		$	210.8
Operating income	$	462.7	$	53.6		$	5.9		$	522.2


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

NOTE 11—VARIABLE INTEREST ENTITIES

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

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

ATC

We own approximately 23.0% of ATC, a for-profit, transmission-only company regulated by the FERC. We have determined that ATC is a variable interest entity but that consolidation is not required since we are not ATC's primary beneficiary. We do not have the power to direct the activities that most significantly impact ATC's economic performance. We instead account for ATC as an equity method investment. See Note 9, Investment in ATC, for more information on ATC.

The significant assets and liabilities related to ATC recorded on our balance sheet at September 30, 2015, included our equity investment in this affiliate and accounts payable. At September 30, 2015, our equity investment was $387.7 million, which approximates our maximum exposure to loss as a result of our involvement with ATC. In addition, we had $19.7 million of accounts payable due to ATC for network transmission services at September 30, 2015.

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Purchased Power Agreement

We have identified a purchased power agreement that represents a variable interest. This agreement is for 236 MW of firm capacity from a natural gas-fired cogeneration facility, and we account for it as a capital lease. The agreement includes no minimum energy requirements over the remaining term of approximately 7 years. We have examined the risks of the entity, including operations and maintenance, dispatch, financing, fuel costs and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity, and there is no residual guarantee associated with the purchased power agreement.

We have approximately $141.3 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, 2015 and 2014, were $40.2 million and $39.8 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

NOTE 12—COMMITMENTS AND CONTINGENCIES

Unconditional Purchase Obligations

We routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. 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. Our minimum future commitments related to these purchase obligations as of September 30, 2015, was $10,632.8 million.

Environmental Matters

We periodically review our exposure for environmental remediation costs as evidence becomes available indicating that our liability has changed. Given current information, including the following, we believe that future costs in excess of the amounts accrued and/or disclosed on all presently known and quantifiable environmental contingencies will not be material to our financial position or results of operations.

We have a program of comprehensive environmental remediation planning for former manufactured gas plant sites and coal combustion product disposal/landfill sites. We perform ongoing assessments of these sites.

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 working with the Wisconsin Department of Natural Resources (WDNR) in our investigation and remediation planning. All sites are at various stages of investigation, monitoring, remediation, and closure. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.

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, the PSCW has 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 over five years. Accordingly, we have established regulatory assets for costs associated with these sites.

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



(in millions)	September 30, 2015		December 31, 2014
Regulatory assets	$	18.3	$	18.7
Reserves for future remediation	6.5		6.5

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NOTE 13—SUPPLEMENTAL CASH FLOW INFORMATION



	Nine Months Ended September 30
(in millions)	2015		2014
Cash paid for interest, net of amount capitalized	$	60.6	$	65.6
Cash paid for income taxes, net of refunds	58.7		15.7
Significant noncash transactions:
Accounts payable related to construction costs	5.0		4.8

NOTE 14—RELATED PARTY TRANSACTIONS

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

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

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

WBS provides 15 categories of services (including financial, human resource, and administrative services) to us pursuant to the interim WBS AIAs, which have been approved, or from which we have been granted appropriate waivers, by the appropriate regulators, including the PSCW. As required by FERC regulations for centralized service companies, WBS renders services at cost. The PSCW must be notified prior to making changes to the services offered under and the allocation methods specified in the interim WBS AIAs. Other modifications or amendments to the interim WBS AIAs would require PSCW approval. Recovery of allocated costs is addressed in our rate cases.

The PSCW orders approving the Non-WBS AIA and the interim WBS AIAs include an April 1, 2016, sunset date for WEC Energy Group and the former Wisconsin Energy subsidiaries, including us. We may request one extension of the sunset date. Prior to the sunset date, WEC Energy Group will need to file new or modified Non-WBS and WBS AIAs for approval with the PSCW and other state commissions.

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.

The table below includes information summarizing other transactions entered into with related parties:



(in millions)	September 30, 2015		December 31, 2014
Notes payable *
WEC Energy Group	$	19.7	$	22.4
Accounts payable
Network transmission services from ATC	19.7		18.1


*	Bostco, our consolidated subsidiary, has a note payable to our parent company, WEC Energy Group.

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The following table shows activity associated with related party transactions:



	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2015		2014		2015		2014
Lease agreements
Lease payments to W.E. Power, LLC ⁽¹⁾	$	96.9	$	90.9	$	290.1	$	274.0
Natural gas transactions
Purchases from Wisconsin Public Service Corporation	0.3		—		0.3		—
Interest expense ⁽²⁾
WEC Energy Group	0.3		0.4		1.0		1.1
Transactions with equity method investees
Charges from ATC for network transmission services	59.0		54.2		176.1		162.1
Charges to ATC for services and construction	2.6		1.9		7.6		5.5


⁽¹⁾	We make lease payments to W.E. Power, LLC, a subsidiary of WEC Energy Group, for Port Washington Generating Station Units 1 and 2 and Oak Creek expansion Units 1 and 2.


⁽²⁾	Bostco, our consolidated subsidiary, has a note payable to our parent company, WEC Energy Group.

NOTE 15—MICHIGAN SETTLEMENT

In March 2015, we, along with Wisconsin Energy, entered into an Amended and Restated Settlement Agreement with the Attorney General of the State of Michigan, the Staff of the Michigan Public Service Commission (MPSC), and Tilden Mining Company and Empire Iron Mining Partnership (Amended Agreement) to resolve all objections to Wisconsin Energy's acquisition of Integrys these parties raised at the MPSC. The agreement includes the following provisions:


•	The parties to the Amended Agreement agree that the acquisition satisfies the applicable requirements under Michigan law and should be approved by the MPSC.

•

We will not enter into a System Support Resource (SSR) agreement for the operation of Presque Isle Power Plant (PIPP) so long as both mines, if operational, remain full requirements customers of ours until the earlier of (i) the date a new, clean generation plant located in the Upper Peninsula of Michigan commences commercial operation or (ii) December 31, 2019. The prior SSR agreement was terminated effective February 1, 2015 with the return of the mines as full requirements customers.


•	Wisconsin Energy commits to invest either through an ownership interest or a purchased power agreement, or to have, if formed, a future Michigan jurisdictional utility invest, in this plant subject to the issuance of a Certificate of Necessity from the MPSC. The costs of this plant would be recovered from Michigan customers.

In addition, in March 2015, we entered into a special contract with each of the mines to provide full requirements electric service through December 31, 2019.

In April 2015, the MPSC approved the acquisition of Integrys, the Amended Agreement and the special contracts with the two mines.

NOTE 16—NEW ACCOUNTING PRONOUNCEMENTS

Revenue Recognition

In May 2014, the Financial Accounting Standards Board (FASB) and the International Accounting Standards Board issued their joint revenue recognition standard, Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers. The guidance is based on the principle that revenue is recognized when promised goods or services are transferred to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, with early adoption for fiscal years and interim periods beginning after December 15, 2016, permitted. The standard 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 consolidated financial statements.

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Debt Issuance Costs

In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. The guidance requires debt issuance costs to be presented on the balance sheet as a reduction to the carrying value of the corresponding debt, rather than as an asset as it is currently presented. This guidance is effective for fiscal years and interim periods beginning after December 15, 2015. The standard requires retrospective application by restating each prior period presented in the financial statements. We are currently assessing the effects this guidance may have on our consolidated financial statements.

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

Corporate Developments

Acquisition

On June 29, 2015, our parent company, Wisconsin Energy, completed its acquisition of Integrys and the combined company was renamed WEC Energy Group, Inc. The acquisition was subject to several conditions, including, among others, approval of the shareholders of both Wisconsin Energy and Integrys, the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, and the receipt of approvals from various government agencies, including the FERC, Federal Communications Commission, PSCW, Illinois Commerce Commission (ICC), MPSC, and MPUC.

On July 24, 2015, the Citizens Utility Board, the City of Chicago, and the Illinois State Attorney General's office asked the ICC to rehear the order approving the acquisition. The parties sought additional conditions previously requested during the approval process. The ICC denied this request.

See Note 2, Acquisition, for more information regarding the acquisition.

RESULTS OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2015

Earnings Summary

The following table compares our consolidated results for the third quarter of 2015 with the third quarter of 2014, including favorable or better, "B", and unfavorable or worse, "W", variances:



	Three Months Ended September 30
(in millions)	2015			B (W)			2014
Electric operations	$	171.2		$	12.7		$	158.5
Gas operations	—			0.3			(0.3		)
Steam operations	(1.4		)	0.6			(2.0		)
Total operating income	169.8			13.6			156.2
Equity in earnings of transmission affiliate	15.7			(0.2		)	15.9
Other income, net	2.2			0.8			1.4
Interest expense	30.4			(1.4		)	29.0
Income before income taxes	157.3			12.8			144.5
Income tax expense	56.9			(2.5		)	54.4
Net income	$	100.4		$	10.3		$	90.1

Preferred stock dividend requirement	$	0.3		$	—		$	0.3
Earnings available for common stockholder	$	100.1		$	10.3		$	89.8

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Electric Utility Revenues and Sales



	Three Months Ended September 30
	Electric Revenues (in millions)							MWh (in thousands)
Electric Utility Operations	2015		B (W)			2014		2015	B (W)		2014
Customer Class
Residential	$	345.7	$	37.5		$	308.2	2,268.5	234.7		2,033.8
Small Commercial/Industrial	281.5		(0.3		)	281.8		2,380.6	36.7		2,343.9
Large Commercial/Industrial	187.8		16.4			171.4		2,300.2	319.2		1,981.0
Other – Retail	5.2		(0.1		)	5.3		34.2	0.8		33.4
Total Retail	820.2		53.5			766.7		6,983.5	591.4		6,392.1
Wholesale – Other	24.3		(4.3		)	28.6		265.6	(88.3	)	353.9
Resale – Utilities	58.2		(4.5		)	62.7		2,113.1	149.4		1,963.7
Other Operating Revenues	26.4		5.5			20.9		—	—		—
Total	929.1		50.2			$	878.9	9,362.2	652.5		8,709.7
Electric Customer Choice ⁽¹⁾	0.6		(0.6		)	1.2		66.4	(529	)	595.4
Total, including electric customer choice	$	929.7	$	49.6		$	880.1

Weather – Degree Days ⁽²⁾
Heating (126 Normal)								94	(81	)	175
Cooling (536 Normal)								521	169		352


⁽¹⁾	Represents distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.


⁽²⁾	As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.

Our electric utility operating revenues increased by $49.6 million when compared to the third quarter of 2014. The most significant factors affecting revenues were:


•	Weather – We estimate that our retail revenues for the third quarter of 2015 increased by approximately $39.4 million due to weather. As measured by cooling degree days, the third quarter of 2015 was 48.0% warmer than the same period of 2014.

•

Return of the two iron ore mines – On February 1, 2015, the two iron ore mines returned as retail customers. During 2014, these customers were served by an alternative electric supplier pursuant to the electric customer choice program in Michigan. The return of the mines increased retail revenues by approximately $18.4 million. These revenues will not significantly impact earnings because, under an agreement with the PSCW, we are deferring the net revenues (revenues less fuel and transmission costs) from the mines for the benefit of our Wisconsin retail electric customers.


•	Wholesale Revenues – A $4.3 million decrease in wholesale revenues, primarily due to volume and pricing decreases.


•	Resale Utilities – These sales are also known as opportunity sales. The net margin (revenues less fuel costs) on these sales flow to the benefit of our retail electric customers. Revenues decreased in the third quarter of 2015 by $4.5 million compared to the third quarter of 2014 due to lower prices for electricity in the MISO Energy and Operating Reserves Markets (MISO Energy Markets).

Fuel and Purchased Power

Our fuel and purchased power costs decreased by $9.0 million, or 2.7%, when compared to the third quarter of 2014. This decrease was primarily caused by a reduction in our average cost of fuel and purchased power because of lower natural gas prices as compared to the third quarter of 2014, partially offset by an increase in total MWh sales.

Natural Gas Utility Revenues, Gross Margin and Therm Deliveries

A comparison follows of natural gas utility operating revenues, gross margin and natural gas deliveries during the third quarter of 2015 with the third quarter of 2014. We believe gross margin is a better performance indicator than revenues because changes in the cost of natural gas sold flow through to revenue under natural gas cost recovery mechanisms.

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	Three Months Ended September 30
(in millions)	2015		B (W)			2014
Natural Gas Operating Revenues	$	45.3	$	(6.6	)	$	51.9
Cost of Natural Gas Sold	21.4		6.3			27.7
Gross Margin	$	23.9	$	(0.3	)	$	24.2

The following table compares natural gas utility gross margin and natural gas therm deliveries by customer class during the third quarter of 2015 with the third quarter of 2014:



	Three Months Ended September 30
Natural Gas Utility Operations	Gross Margin							Therms
(in millions)	2015		B (W)			2014		2015	B (W)		2014
Customer Class
Residential	$	16.3	$	—		$	16.3	20.4	(1.8	)	22.2
Commercial/Industrial	3.7		(0.1		)	3.8		13.6	(0.8	)	14.4
Interruptible	—		(0.1		)	0.1		0.2	(0.3	)	0.5
Total Retail	20.0		(0.2		)	20.2		34.2	(2.9	)	37.1
Transported natural gas	3.7		0.1			3.6		80.8	15.3		65.5
Other operating	0.2		(0.2		)	0.4		—	—		—
Total	$	23.9	$	(0.3	)	$	24.2	115.0	12.4		102.6

Weather – Degree Days *
Heating (126 Normal)								94	(81	)	175


*	As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.

Our natural gas margins decreased by $0.3 million, or approximately 1.2%, when compared to the third quarter of 2014. Natural gas margins are seasonal and are primarily driven by the heating needs of customers. The third quarter natural gas margins are typically the lowest of the year because of the lack of heating load.

Steam Utility Revenue



	Three Months Ended September 30
(in millions)	2015		B (W)		2014
Steam revenue	$	6.1	$	0.3	$	5.8

Other Operation and Maintenance Expense

Our other operation and maintenance expense increased by $39.5 million, or 12.5%, when compared to the third quarter of 2014. Approximately $5.3 million of this increase relates to increased costs associated with the mines. The remaining increase was primarily driven by increased benefit costs, as well as increased amortizations of regulatory items, which are being recovered through rates.

Depreciation and Amortization Expense

Our depreciation and amortization expense increased by $4.8 million, or 6.7%, when compared to the third quarter of 2014, due to an overall increase in utility plant in service and a decrease in amortization of the Section 1603 Renewable Energy Treasury Grant (Treasury Grant).

For additional information on the Treasury Grant, see Factors Affecting Results, Liquidity and Capital Resources—Accounting Developments in Item 7 of our 2014 Annual Report on Form 10-K.

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Other Income, Net



	Three Months Ended September 30
(in millions)	2015		B (W)		2014
Allowance for funds used during construction (AFUDC) – equity	$	1.7	$	0.5	$	1.2
Other	0.5		0.3		0.2
Other income, net	$	2.2	$	0.8	$	1.4

Interest Expense



	Three Months Ended September 30
(in millions)	2015		B (W)			2014
Interest expense	$	30.4	$	(1.4	)	$	29.0

Our interest expense increased by $1.4 million, or 4.8%, as compared to the third quarter of 2014, primarily due to higher debt levels. In May 2015, we issued $250.0 million of long-term debt. The net proceeds were used to repay short-term debt and for general corporate purposes.

Income Tax Expense



	Three Months Ended September 30
	2015		B (W)		2014
Effective tax rate	36.2	%	1.4	%	37.6	%

The decrease in our effective tax rate was primarily due to increased domestic production activities deductions.

NINE MONTHS ENDED SEPTEMBER 30, 2015

Earnings Summary

The following table compares our consolidated results for the first nine months of 2015 with the first nine months of 2014, including favorable or better, "B", and unfavorable or worse, "W", variances:



	Nine Months Ended September 30
(in millions)	2015		B (W)			2014
Electric operations	$	452.4	$	(10.3	)	$	462.7
Gas operations	45.1		(8.5		)	53.6
Steam operations	5.7		(0.2		)	5.9
Total operating income	503.2		(19.0		)	522.2
Equity in earnings of transmission affiliate	42.1		(4.3		)	46.4
Other income, net	8.7		0.7			8.0
Interest expense	88.6		(1.0		)	87.6
Income before income taxes	465.4		(23.6		)	489.0
Income tax expense	168.4		12.9			181.3
Net income	$	297.0	$	(10.7	)	$	307.7

Preferred stock dividend requirement	$	0.9	$	—		$	0.9
Earnings available for common stockholder	$	296.1	$	(10.7	)	$	306.8

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Electric Utility Revenues and Sales



	Nine Months Ended September 30
	Electric Revenues (in millions)							MWh (in thousands)
Electric Utility Operations	2015		B (W)			2014		2015	B (W)		2014
Customer Class
Residential	$	926.9	$	24.5		$	902.4	5,968.7	(8.4	)	5,977.1
Small Commercial/Industrial	796.5		(1.9		)	798.4		6,738.4	56.1		6,682.3
Large Commercial/Industrial	552.1		66.6			485.5		6,812.2	1,183.6		5,628.6
Other – Retail	16.3		(0.5		)	16.8		107.0	(0.6	)	107.6
Total Retail	2,291.8		88.7			2,203.1		19,626.3	1,230.7		18,395.6
Wholesale – Other	76.9		(25.4		)	102.3		972.2	(457.8	)	1,430.0
Resale – Utilities	169.5		(41.5		)	211.0		6,105.6	1,214.6		4,891.0
Other Operating Revenues	72.1		12.9			59.2		—	—		—
Total	2,610.3		34.7			2,575.6		26,704.1	1,987.5		24,716.6
Electric Customer Choice ⁽¹⁾	1.8		(2.2		)	4.0		383.0	(1,441.1	)	1,824.1
Total, including electric customer choice	$	2,612.1	$	32.5		$	2,579.6

Weather – Degree Days ⁽²⁾
Heating (4,350 Normal)								4,684	(500	)	5,184
Cooling (702 Normal)								620	160		460


⁽¹⁾	Represents distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.


⁽²⁾	As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.

Our electric utility operating revenues increased by $32.5 million, or 1.3%, when compared to the first nine months of 2014. The most significant factors that caused a change in revenues were:

•

Return of the two iron ore mines – On February 1, 2015, the two iron ore mines returned as retail customers. During 2014, these customers were served by an alternative electric supplier pursuant to the electric customer choice program in Michigan. The return of the mines increased retail revenues by approximately $73.9 million. These revenues will not significantly impact earnings because, under an agreement with the PSCW, we are deferring the net revenues (revenues less fuel and transmission costs) from the mines for the benefit of our Wisconsin retail electric customers.


•	Weather – We estimate that our retail revenues during the first nine months of 2015 increased by approximately $24.4 million when compared to the first nine months of 2014 because of weather. As measured by cooling degree days, the first nine months of 2015 were 11.7% cooler than normal, but 34.8% warmer than the same period in 2014.

•

Resale Utilities – These sales are also known as opportunity sales. The net margin (revenues less fuel costs) on these sales flow to the benefit of our retail electric customers. Revenues in the first nine months of 2015 decreased by $41.5 million compared to the same period in 2014. During the first nine months of 2014, the prices for electricity in the MISO Energy Markets were unusually high because of the extreme cold weather and the high cost of natural gas. During 2015, these prices returned to more normal levels. The revenue decrease associated with the decline in MISO Energy Markets prices was partially offset by increased sales due to increased availability of our generating units in 2015.


•	Wholesale Revenues – We experienced a $25.4 million decrease in wholesale revenues, primarily due to volume and pricing decreases.

•

Other Revenues – Other revenues increased by $12.9 million primarily because of the escrow treatment of the SSR revenues in the most recent Wisconsin retail rate case. This was partially offset by the deferral of the net revenues from the mines as described above. We expect this trend to continue for the remainder of 2015. For information on the escrow treatment of the SSR revenues allowed in the 2015 Wisconsin rate case, see Factors Affecting Results, Liquidity, and Capital Resources—Rates and Regulatory Matters.

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Fuel and Purchased Power

Our fuel and purchased power costs decreased by $50.8 million, or 5.3%, when compared to the first nine months of 2014. This decrease was primarily caused by a reduction in our average cost of fuel and purchased power because of lower natural gas prices as compared to the first nine months of 2014, partially offset by an increase in total MWh sales.

Natural Gas Utility Revenues, Gross Margin and Therm Deliveries

A comparison follows of natural gas utility operating revenues, gross margin and natural gas deliveries during the first nine months of 2015 with the first nine months of 2014. We believe gross margin is a better performance indicator than revenues because changes in the cost of natural gas sold flow through to revenue under natural gas cost recovery mechanisms.



	Nine Months Ended September 30
(in millions)	2015		B (W)			2014
Natural Gas Operating Revenues	$	304.5	$	(153.7	)	$	458.2
Cost of Natural Gas Sold	189.1		138.7			327.8
Gross Margin	$	115.4	$	(15.0	)	$	130.4

The following table compares natural gas utility gross margin and natural gas therm deliveries by customer class during the first nine months of 2015 with the first nine months of 2014:



	Nine Months Ended September 30
Natural Gas Utility Operations	Gross Margin							Therms
(in millions)	2015		B (W)			2014		2015	B (W)		2014
Customer Class
Residential	$	77.8	$	(9.3	)	$	87.1	253.2	(26.1	)	279.3
Commercial/Industrial	23.7		(5.2		)	28.9		140.8	(22.3	)	163.1
Interruptible	0.1		(0.2		)	0.3		1.9	(1.5	)	3.4
Total Retail	101.6		(14.7		)	116.3		395.9	(49.9	)	445.8
Transported Natural Gas	12.6		—			12.6		257.7	5.0		252.7
Other	1.2		(0.3		)	1.5		—	—		—
Total	$	115.4	$	(15.0	)	$	130.4	653.6	(44.9	)	698.5

Weather – Degree Days *
Heating (4,350 Normal)								4,684	(500	)	5,184


*	As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.

Our natural gas margin decreased by $15.0 million, or approximately 11.5%, when compared to the first nine months of 2014. This decrease primarily relates to a decrease in retail sales volumes as a result of warmer weather during the first nine months of 2015. We estimate that weather decreased natural gas margins by approximately $6.4 million. As measured by heating degree days, the first nine months of 2015 were 9.6% warmer than the same period in 2014 and 7.7% colder than normal. In addition, natural gas margins were reduced by approximately $7.0 million because of lower natural gas rates that became effective January 1, 2015. For more information on this rate order, see Factors Affecting Results, Liquidity and Capital Resources—Rates and Regulatory Matters.

Steam Utility Revenue



	Nine Months Ended September 30
(in millions)	2015		B (W)			2014
Steam revenues	$	32.1	$	(0.3	)	$	32.4

Other Operation and Maintenance Expense

Our other operation and maintenance expense increased by $68.7 million, or 7.1%, when compared to the first nine months of 2014. Approximately $16.1 million of this increase relates to increased costs associated with the mines. The remaining increase was primarily driven by increased benefit costs, as well as increased amortizations of regulatory assets, which are being recovered through rates.

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Depreciation and Amortization Expense

Our depreciation and amortization expense increased by $15.7 million, or 7.4%, when compared to the first nine months of 2014, due to an overall increase in utility plant in service and a decrease in amortization of the Treasury Grant.

Other Income, Net



	Nine Months Ended September 30
(in millions)	2015		B (W)			2014
AFUDC – equity	$	4.3	$	1.3		$	3.0
Gain on property sales	—		(4.3		)	4.3
Other	4.4		3.7			0.7
Other income, net	$	8.7	$	0.7		$	8.0

Interest Expense



	Nine Months Ended September 30
(in millions)	2015		B (W)			2014
Interest Expense	$	88.6	$	(1.0	)	$	87.6

Our interest expense increased by $1.0 million, or 1.1%, when compared to the first nine months of 2014, primarily due to higher debt levels. In May 2015, we issued $250.0 million of long-term debt. The net proceeds were used to repay short-term debt and for general corporate purposes.

Income Tax Expense



	Nine Months Ended September 30
	2015		B (W)		2014
Effective tax rate	36.2	%	0.9	%	37.1	%

The decrease in our effective tax rate was primarily due to increased domestic production activities deductions.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

The following summarizes our cash flows during the nine months ended September 30:



(in millions)	2015			2014
Cash provided by (used in):
Operating activities	$	508.9		$	768.0
Investing activities	(370.7		)	(399.4		)
Financing activities	(151.5		)	(378.3		)

Operating Activities

During the nine months ended September 30, 2015, net cash provided by operating activities was $508.9 million, compared with $768.0 million for the same period in 2014. The $259.1 million decrease in net cash provided by operating activities was driven primarily by:


•	A $96.5 million increase in contributions to our pension and other postretirement plans in 2015.


•	A $76.2 million period-over-period decrease in cash related to the 2014 receipt of the Treasury Grant associated with the completion of our biomass plant in November 2013.

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•	A $43.0 million decrease in cash related to higher cash paid for income taxes, net of refunds, in 2015.

Investing Activities

During the nine months ended September 30, 2015, net cash used in investing activities was $370.7 million, compared with $399.4 million for the same period in 2014. The $28.7 million decrease in net cash used in investing activities was primarily due to a decrease in capital expenditures in 2015, driven by higher spend during the first nine months of 2014 as compared to the same period in 2015 with respect to the conversion of the fuel source for Valley Power Plant (VAPP) from coal to natural gas.

Financing Activities

During the nine months ended September 30, 2015, net cash used in financing activities was $151.5 million, compared with $378.3 million during the same period in 2014. The $226.8 million decrease in net cash used in financing activities was driven by:


•	The retirement of $300.0 million of long-term debt in 2014.


•	A $150.0 million decrease in dividends paid on common stock in 2015. In 2014, we paid $150.0 million of special dividends to Wisconsin Energy to balance our capital structure.

These decreases in net cash used in financing activities was partially offset by a $221.9 million increase in net repayments of commercial paper in 2015.

Significant Financing Activities

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

For information on long-term debt, see Note 5, Long-Term Debt.

Capital Resources and Requirements

Working Capital

As of September 30, 2015, our current liabilities exceeded our current assets by approximately $99.1 million. We do not expect this to have any impact on our liquidity because we believe we have an adequate back-up line of credit in place for on-going operations. We also have access to the capital markets to finance our construction program and to refinance current maturities of long-term debt, if necessary.

Liquidity

We anticipate meeting our capital requirements during the remainder of 2015 and beyond primarily 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 that provides liquidity support for our obligations with respect to commercial paper and for general corporate purposes. We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. See Note 4, Short-Term Debt and Lines of Credit, for more information on our credit facility.

We are the obligor under two series of tax-exempt pollution control refunding bonds in outstanding principal amount of $147.0 million. In August 2009, we terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. We issued commercial paper to fund the purchase of the bonds. As of September 30,

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2015, the repurchased bonds were still outstanding, but were not reported as long-term debt because they are held by us. Depending on market conditions and other factors, we may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.

Credit Rating Risk

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 August 2015, Fitch Ratings, Inc. affirmed our ratings and stable outlook. During the third quarter of 2015, there were no changes to the credit ratings issued by Moody's Investors Service and Standard & Poor's Ratings Services.

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 agencies only. An explanation of the significance of these ratings may be obtained from each 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.

See Capital Resources and Requirements—Credit Rating Risk in Item 7 of our 2014 Annual Report on Form 10-K for additional information related to our credit rating risk.

Capital Requirements

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.

Capital requirements during the remainder of 2015 are expected to be principally for upgrading our electric and natural gas distribution systems.

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 financial guarantees and letters of credit which support construction projects, commodity contracts and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to our investors. See Note 11, Variable Interest Entities, for more information.

Contractual Obligations/Commercial Commitments

See Contractual Obligations/Commercial Commitments in Item 7 of our 2014 Annual Report on Form 10-K for additional information about our commitments.

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity, and capital resources. The following discussion should be read together with the information under Factors Affecting Results, Liquidity and Capital Resources in Item 7 of our 2014 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, WEC Energy Group's Power the Future strategy, utility rates and regulatory matters, electric system reliability, environmental matters, legal matters, industry restructuring, competition, and other matters.

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Rates and Regulatory Matters

2015 Wisconsin Rate Case

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

•

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


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


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


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


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


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

Our authorized return on equity (ROE) was set at 10.2%, and our common equity component remained at an average of 51%. The electric rates reflect an increased allocation to fixed charges from 7.8% to 13.6% of total electric revenue requirements to more closely reflect our cost structure. The PSCW order also authorized escrow accounting for SSR revenues because of the uncertainty of the actual revenues we will receive under the PIPP SSR agreements. Under escrow accounting, we will record SSR revenues from MISO of $90.7 million a year. If actual SSR payments from MISO exceed $90.7 million a year, the difference will be deferred and returned to customers, with interest, in a future rate case. If actual SSR payments from MISO are less than $90.7 million a year, the difference will be deferred and recovered from customers with interest, in a future rate case.

In January 2015, certain parties appealed a portion of the PSCW's final decision adopting our specific rate design changes, including new charges for customer-owned generation within our service territory. In its oral decision on October 30, 2015, the Dane County Circuit Court held that there was not enough evidence provided in our rate case to support a demand charge for customer-owned generation. We are reviewing our options with respect to the Court's decision. No other rates approved by the PSCW in the rate case are impacted by this decision.

Earnings Sharing Agreement

In May 2015, the PSCW approved Wisconsin Energy's acquisition of Integrys subject to the condition of a three year earnings sharing mechanism for us beginning in 2016. If we earn above our authorized return, 50% of the first 50 basis points of additional utility earnings will be shared with customers through a reduction of our transmission escrow. All utility earnings above the first 50 basis points will be used to reduce the transmission escrow.

See Factors Affecting Results, Liquidity and Capital Resources—Rates and Regulatory Matters in Item 7 of our 2014 Annual Report on Form 10-K for additional information regarding our rates and other regulatory matters.

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Electric Transmission and Energy Markets

Michigan Settlement

In March 2015, we, along with Wisconsin Energy, entered into an Amended and Restated Settlement Agreement with the Attorney General of the State of Michigan, the Staff of the MPSC, and Tilden Mining Company and Empire Iron Mining Partnership to resolve all objections these parties raised at the MPSC to the acquisition of Integrys. See Note 15, Michigan Settlement, for more information regarding the Amended Agreement.

ATC Allowed ROE Complaint

In November 2013, a group of MISO industrial customer organizations filed a complaint with the FERC requesting to reduce the base ROE used by MISO transmission owners, including ATC, to 9.15%. ATC's current authorized ROE is 12.2%. In October 2014, the FERC issued an order to hear the complaint on ROE and set a refund effective date retroactive to November 12, 2013. The FERC conducted hearings in August 2015, and an initial decision is expected by November 30, 2015. In February 2015, a second complaint was filed with the FERC requesting a reduction in the base ROE used by MISO transmission owners, including ATC, to 8.67%, with a refund effective date retroactive to the filing date of the complaint. The FERC expects to conduct hearings in January 2016 with respect to the second complaint, and an initial decision is expected by June 30, 2016.

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

Any change to ATC's ROE could result in lower equity earnings and distributions from ATC in the future. We are currently unable to determine how the FERC may rule in these complaints. However, we believe it is probable that refunds will be required upon resolution of these issues. In the first quarter of 2015, ATC recorded a reserve for anticipated refunds to customers related to this complaint, which has reduced our equity earnings from ATC.

See Item 1A. Risk Factors and Factors Affecting Results, Liquidity and Capital Resources—Industry Restructuring and Competition in Item 7 of our 2014 Annual Report on Form 10-K for additional information regarding electric transmission and energy markets.

Environmental Matters

Air Quality

Sulfur Dioxide (SO₂) National Ambient Air Quality Standards (NAAQS)

The United States Environmental Protection Agency (EPA) issued a revised 1-Hour SO₂ NAAQS that became effective in August 2010. In August 2015, the EPA issued the Data Requirements Rule that established procedures and timelines for implementation of the revised standard.

The rule affords state agencies latitude in rule implementation. States have the option of modeling or monitoring to show attainment (subject to EPA approval for this selection) and make designation recommendations. If a state chooses modeling and an area does not show attainment, and sources do not agree to reductions by 2017 to allow attainment, the area is classified as nonattainment. A plan would need to be developed requiring emission reductions to allow attainment by 2023. Alternatively, if a state opted out of modeling and instead chose monitoring, and subsequently monitored nonattainment, then it would face a 2026 compliance date. A nonattainment designation could have negative impacts for a localized geographic area, including permitting constraints for area sources, and for other new or existing sources in the area.

In March 2015, a Federal Court in the Northern District of California entered a consent decree relating to the implementation of the revised 1-Hour SO₂ standard that Sierra Club and the EPA had agreed upon in May 2014. This consent decree has 1-Hour SO₂

implementation dates that are sooner than the Data Requirements Rule. In light of this consent decree, we worked closely with the state of Michigan to determine that the Marquette area is in attainment with the revised standard. In September 2015, the state of Michigan sent a letter with this recommendation to the EPA. We expect the EPA to act on this recommendation in early 2016.

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We believe our fleet is well positioned to meet this regulation once it is finalized.

8-Hour Ozone NAAQS

The EPA completed its review of the 2008 8-hour ozone standard in November 2014, and announced a proposal to lower the NAAQS. In October 2015, the EPA released the final rule, which effectively 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. We will be required to comply with the new reduction requirements 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 Mercury and Air Toxics Standards (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 mercury rules that require a 90% reduction of mercury. In June 2015, the United States Supreme Court ruled on a challenge to the MATS rule and remanded the case back to the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court of Appeals), ruling that the EPA failed to appropriately consider the cost of the regulation. The MATS rule remains in effect pending action by the D.C. Circuit Court of Appeals, which has the option to vacate the rule while the EPA completes its cost evaluation. If the rule is stayed or revoked, the Wisconsin and Michigan mercury rules are likely to be the governing standard for our units.

Our compliance plans currently include modifications for PIPP to achieve the required reductions for MATS and the state mercury rules. We are working on the addition of a dry sorbent injection system for further control of mercury and acid gases at PIPP. In April 2013, we received a one year MATS compliance extension for PIPP through April 2016 from the Michigan Department of Environmental Quality (MDEQ).

Climate Change

In August 2015, the EPA issued the Clean Power Plan, a final rule regulating greenhouse gas (GHG) emissions from existing generating units, a proposed federal plan as an alternative to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. The final rule for existing fossil generating units seeks to achieve state-specific GHG emission reduction goals by 2030, and requires states to submit plans as early as September 2016. States submitting initial plans and requesting an extension would be required to submit final plans by September 2018, either alone or in conjunction with other states. States will be required to meet interim goals over the period from 2022 through 2029, and a final goal in 2030, with the goal of reducing nationwide GHG emissions by 32% from 2005 levels. The rule is seeking GHG emission reductions in Wisconsin and Michigan of 41% and 39%, respectively, below 2012 levels by 2030. The building blocks used by the EPA to determine each state's emission reduction requirements include a combination of improving power plant efficiency, increasing reliance on combined cycle natural gas units, and adding new renewable energy resources.

We are in the process of reviewing the final rule for existing 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. In October 2015, following publication of the final rule, 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. Any state or federal compliance plans that are developed could be subject to change based upon the outcome of this litigation.

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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. Impacts are both from entrainment (larvae, eggs, and small fry being drawn into cooling water systems) and impingement (larger fish being pinned against cooling water intake structures). The rule became effective in October 2014, and applies to all of our existing generating facilities with cooling water intake structures, except for the Oak Creek expansion units, which were permitted under the rules governing new facilities.

Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities, except for VAPP Units 1 and 2, satisfy the IM BTA requirements. For VAPP Unit 2, a project to install fish protection screens to meet the IM BTA standard was completed in October 2015. The same types of screens are scheduled to be installed on VAPP Unit 1 starting in September 2016.

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

During 2015-2017, we plan to complete studies and evaluate options to address the EM BTA requirements at our plants. With the exception of Pleasant Prairie Power Plant (plant has existing cooling towers that meet EM BTA requirements) and VAPP, we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at our facilities. In addition, the rule allows the EM BTA requirements to be waived in cases of pending facility retirements, which we are currently considering for PIPP. Based on discussions with the MDEQ, if we submit a signed certification with our next National Pollutant Discharge Elimination System permit application stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2022), then the EM BTA requirements will be waived.

Steam Electric Effluent Guidelines

In September 2015, the EPA issued the final steam electric effluent guidelines rule, which governs discharges of wastewater from our power plant processes in Wisconsin and Michigan. 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 likely require additional biological 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 also required by the new rule, and modifications will be required at Oak Creek Units 5 and 6, the Pleasant Prairie units, and PIPP Units 5 through 9.

Paris Generating Station Issues

In November 2014, the WDNR reissued the Wisconsin Pollutant Discharge Elimination System (WPDES) permit for the Paris Generating Station. We believed that the WDNR imposed unreasonable permit conditions with respect to temperature monitoring, the control of water treatment additive, and phosphorus discharges. To address these permit conditions, we filed a petition for a contested case hearing with the WDNR in January 2015. On the same day, we also filed a request to be covered by the statewide phosphorus variance to address one of our concerns with the permit. We reached an agreement with the WDNR with respect to the permit conditions for temperature monitoring and for restrictions related to the use of a water treatment additive. In March 2015, the WDNR issued a final WPDES permit with agreed upon modifications, and we withdrew our petition for a contested case hearing. In July 2015, the Milwaukee County Circuit Court entered a stipulation and Order for Judgment between the WDNR and Wisconsin Department of Justice. This order resolves the litigation by allowing us to maintain the ability to apply for and be covered by the statewide phosphorus variance.

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Land Quality

Coal Combustion Residuals Rule

In April 2015, the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals From Electric Utilities final rule was entered into the Federal Register. The final rule regulates the disposal of coal combustion residuals as a non-hazardous waste. We do not expect the compliance costs will be significant because we currently have a program of beneficial utilization for most of our coal combustion products. If needed, we have landfill capacity that meets the rule requirements for our remaining coal combustion product sources.

See Factors Affecting Results, Liquidity and Capital Resources—Environmental Matters in Item 7 of our 2014 Annual Report on Form 10-K for additional information regarding environmental matters affecting our operations.

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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, 2014. 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.

Internal Control Over Financial Reporting

There has not been any change 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 fiscal quarter to which this report relates that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

On June 29, 2015, our parent company, Wisconsin Energy, acquired Integrys. WEC Energy Group is currently in the process of integrating and aligning the operations, processes, and internal controls of the combined company. See Note 2, Acquisition, for more information regarding the acquisition.

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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 2014 Annual Report on Form 10-K.

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

Other than the risks set forth below, there were no material changes in the risk factors presented in Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2014.

Risks Related to the Integrys Acquisition

The acquisition of Integrys may not achieve its anticipated results, and WEC Energy Group may be unable to integrate our operations as expected.

The agreement to acquire Integrys was entered into with the expectation that the acquisition will result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the acquisition is subject to a number of uncertainties, including whether the businesses of WEC Energy Group and Integrys can be integrated in an efficient, effective, and timely manner.

It is possible that the integration process could take longer than anticipated and could result in the loss of valuable employees; the disruption of each company's ongoing businesses, processes, and systems; or inconsistencies in standards, controls, procedures, practices, policies, and compensation arrangements, any of which could adversely affect the combined company's ability to achieve the anticipated benefits of the transaction as and when expected. WEC Energy Group and Integrys may have difficulty addressing possible differences in corporate cultures and management philosophies. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect our future business, financial condition, operating results, and prospects.

The acquisition of Integrys may adversely affect our ability to attract and retain key employees.

Current and prospective employees may experience uncertainty about their future roles with us as a result of the transaction. In addition, current and prospective employees may determine that they do not desire to work for the combined company for a variety of possible reasons. These factors may adversely affect our ability to attract and retain key management and other personnel.

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ITEM 6. EXHIBITS



Exhibit No.		Description
12		Statements Regarding Computation of Ratios

12.1		Statement of Computation of Ratio of Earnings to Fixed Charges

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 6, 2015	William J. Guc
		Vice President and Controller

		(Duly Authorized Officer and Chief Accounting Officer)