8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of report (Date of earliest event reported):
May 22, 2015

Commission File Number	Registrant; State of Incorporation Address; and Telephone Number	IRS Employer Identification No.
001-09057	WISCONSIN ENERGY CORPORATION	39-1391525

(A Wisconsin Corporation)

231 West Michigan Street

P.O. Box 1331

Milwaukee, WI 53201

(414) 221-2345

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

oWritten communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

oSoliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

oPre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

oPre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

WISCONSIN ENERGY CORPORATION

Item 9.01. Financial Statements and Exhibits.

(a)   Financial Statements of Businesses Acquired.

The audited consolidated financial statements as of December 31, 2014 and 2013, and for the years ended December 31, 2014, 2013 and 2012, of Wisconsin Energy Corporation are included in its Annual Report on Form 10-K for the year ended December 31, 2014, filed on February 27, 2015.  The unaudited consolidated financial statements as of March 31, 2015 and 2014, and for the quarters ended March 31, 2015 and 2014, of Wisconsin Energy Corporation are included in its Quarterly Report on Form 10-Q for the quarter ended March 31, 2015, filed on May 7, 2015.

The audited consolidated financial statements and related consolidated financial statement schedules as of December 31, 2014 and 2013, and for the years ended December 31, 2014, 2013 and 2012, of Integrys Energy Group, Inc. (“Integrys”) and the related Reports of Independent Registered Public Accounting Firm are included in its Annual Report on Form 10-K for the year ended December 31, 2014, filed on March 2, 2015, and such consolidated financial statements and related consolidated financial statement schedules, along with the related Report of Independent Registered Public Accounting Firm, are attached hereto as Exhibit 99.1.  The unaudited consolidated financial statements as of March 31, 2015 and 2014, and for the quarters ended March 31, 2015 and 2014, of Integrys are included in its Quarterly Report on Form 10-Q for the quarter ended March 31, 2015, filed on May 5, 2015, and such consolidated financial statements are attached hereto as Exhibit 99.2.

The audited financial statements as of December 31, 2014 and 2013, and for the years ended December 31, 2014, 2013 and 2012, of American Transmission Company LLC (“ATC”) and the related Independent Auditors’ Report are included as Exhibit 99 to Integrys’ Annual Report on Form 10-K for the year ended December 31, 2014, filed on March 2, 2015, and such financial statements, along with the related Independent Auditors’ Report, are attached hereto as Exhibit 99.3.

(b)   Pro Forma Financial Information.

Unaudited pro forma condensed combined consolidated financial information as of June 30, 2014, and for the six months ended June 30, 2014 and the year ended December 31, 2013, was previously included in the Registration Statement on Form S-4 (the “Form S-4”) of Wisconsin Energy Corporation filed on August 13, 2014, amended on September 22, 2014 and October 3, 2014, and declared effective by the Securities and Exchange Commission on October 6, 2014. Unaudited pro forma condensed combined consolidated financial information as of March 31, 2015, and for the three months ended March 31, 2015 and the year ended December 31, 2014, is attached hereto as Exhibit 99.4.  Throughout Exhibit 99.4, references to “this document” shall be references to the Form S-4.

(c)   Exhibits.

The information exhibits are filed herewith.

23.1	Consent of Deloitte & Touche LLP
23.2	Consent of Deloitte & Touche LLP
99.1	Audited consolidated financial statements and related consolidated financial statement schedules as of December 31, 2014 and 2013, and for the years ended December 31, 2014, 2013 and 2012, of Integrys and the related Report of Independent Registered Public Accounting Firm.
99.2	Unaudited consolidated financial statements as of March 31, 2015 and 2014, and for the quarters ended March 31, 2015 and 2014, of Integrys.
99.3	Audited financial statements as of December 31, 2014 and 2013, and for the years ended December 31, 2014, 2013 and 2012, of ATC and the related Independent Auditors’ Report.
99.4	Unaudited Pro Forma Condensed Combined Consolidated Financial Information.

2

SIGNATURES

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 hereunto duly authorized.

	WISCONSIN ENERGY CORPORATION
	(Registrant)
Date: May 22, 2015	/s/ Stephen P. Dickson
	Stephen P. Dickson — Vice President and Controller

3

EXHIBIT INDEX

Exhibit No.	Description
23.1	Consent of Deloitte & Touche LLP
23.2	Consent of Deloitte & Touche LLP
99.1	Audited consolidated financial statements and related consolidated financial statement schedules as of December 31, 2014 and 2013, and for the years ended December 31, 2014, 2013 and 2012, of Integrys Energy Group, Inc. and the related Report of Independent Registered Public Accounting Firm.
99.2	Unaudited consolidated financial statements as of March 31, 2015 and 2014, and for the quarters ended March 31, 2015 and 2014, of Integrys Energy Group, Inc.
99.3	Audited financial statements as of December 31, 2014 and 2013, and for the years ended December 31, 2014, 2013 and 2012, of American Transmission Company LLC and the related Independent Auditors’ Report.
99.4	Unaudited Pro Forma Condensed Combined Consolidated Financial Information.

4

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-199561 on Form S-3, 333-198096 on Form S-4, and 333-161151, and 333-177572 on Form S-8 of our report dated March 2, 2015 relating to the consolidated financial statements and financial statement schedules of Integrys Energy Group, Inc. and subsidiaries, appearing in this Current Report on Form 8-K of Wisconsin Energy Corporation dated May 22, 2015.

/s/ Deloitte & Touche LLP

Milwaukee, Wisconsin

May 22, 2015

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT AUDITORS

WeconsenttotheincorporationbyreferenceinWisconsinEnergyCorporation’sRegistrationStatementNo.333-199561onFormS-3, Registration Statement No. 333-198096 on Form S-4 and Registration Statement Nos. 333-161151 and 333-177572 on Form S-8 of our report dated February 2, 2015, relating to the financial statements of American Transmission Company LLC, appearing in the Current Report on Form 8-K of Wisconsin Energy Corporation dated May 22, 2015.

/s/ DELOITTE & TOUCHE LLP

Milwaukee, Wisconsin

May 22, 2015

EX-99.1

Exhibit 99.1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Integrys Energy Group, Inc.:

We have audited the accompanying consolidated balance sheets of Integrys Energy Group, Inc. and subsidiaries (the “Company”) as of December 31, 2014 and 2013, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2014. Our audits also included the financial statement schedules included herein at Exhibit 99.1. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Integrys Energy Group, Inc. and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

March 2, 2015

1

CONSOLIDATED STATEMENTS OF INCOME

Year Ended December 31
(Millions, except per share data)	2014			2013			2012
Operating revenues	$	4,144.2		$	3,485.5		$	3,012.9
Cost of sales	2,133.0			1,598.7			1,349.1
Operating and maintenance expense	1,199.7			1,086.7			943.0
Depreciation and amortization expense	287.5			263.4			247.3
Taxes other than income taxes	97.0			97.2			94.0
Merger transaction costs	10.4			—			—
Gain on sale of UPPCO, net of transaction costs	(85.4		)	—			—
Gain on abandonment of PDI’s Winnebago Energy Center	(5.0		)	—			—
Operating income	507.0			439.5			379.5
Earnings from equity method investments	88.3			91.5			87.2
Miscellaneous income	31.0			21.9			9.0
Interest expense	154.8			127.4			118.9
Other expense	(35.5		)	(14.0		)	(22.7		)
Income before taxes	471.5			425.5			356.8
Provision for income taxes	193.4			158.0			117.9
Net income from continuing operations	278.1			267.5			238.9
Discontinued operations, net of tax	1.8			87.3			45.4
Net income	279.9			354.8			284.3
Preferred stock dividends of subsidiary	(3.1		)	(3.1		)	(3.1		)
Noncontrolling interest in subsidiaries	0.1			0.1			0.2
Net income attributed to common shareholders	$	276.9		$	351.8		$	281.4
Average shares of common stock
Basic	80.2			79.5			78.6
Diluted	80.7			80.1			79.3
Earnings per common share (basic)
Net income from continuing operations	$	3.43		$	3.33		$	3.00
Discontinued operations, net of tax	0.02			1.10			0.58
Earnings per common share (basic)	$	3.45		$	4.43		$	3.58
Earnings per common share (diluted)
Net income from continuing operations	$	3.41		$	3.30		$	2.98
Discontinued operations, net of tax	0.02			1.09			0.57
Earnings per common share (diluted)	$	3.43		$	4.39		$	3.55

The accompanying notes to the consolidated financial statements are an integral part of these statements.

2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Year Ended December 31
(Millions)	2014			2013			2012
Net income	$	279.9		$	354.8		$	284.3
Other comprehensive income (loss), net of tax:
Cash flow hedges
Unrealized net gains (losses) arising during period, net of tax of an insignificant amount for all periods presented	—			0.7			(0.2		)
Reclassification of net losses (gains) to net income, net of tax of $1.2 million, $3.6 million, and $2.0 million, respectively	(0.1		)	1.4			6.5
Cash flow hedges, net	(0.1		)	2.1			6.3
Defined benefit plans
Pension and other postretirement benefit adjustments arising during period, net of tax of $(3.0) million, $8.9 million, and $(4.4) million, respectively	(6.0		)	13.2			(6.1		)
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, net of tax of $0.8 million, $1.7 million, and $1.0 million, respectively	1.7			2.4			1.4
Defined benefit plans, net	(4.3		)	15.6			(4.7		)
Other comprehensive income (loss), net of tax	(4.4		)	17.7			1.6
Comprehensive income	275.5			372.5			285.9
Preferred stock dividends of subsidiary	(3.1		)	(3.1		)	(3.1		)
Noncontrolling interest in subsidiaries	0.1			0.1			0.2
Comprehensive income attributed to common shareholders	$	272.5		$	369.5		$	283.0

The accompanying notes to the consolidated financial statements are an integral part of these statements.

3

CONSOLIDATED BALANCE SHEETS

At December 31
(Millions, except share and per share data)	2014			2013
Assets
Cash and cash equivalents	$	18.0		$	16.8
Accounts receivable and accrued unbilled revenues, net of reserves of $63.3 and $47.7, respectively	699.8			646.1
Inventories	327.2			218.9
Regulatory assets	118.9			127.4
Assets held for sale	0.7			277.9
Assets of discontinued operations related to IES’s retail energy business	—			815.4
Deferred income taxes	52.4			31.4
Prepaid taxes	136.2			144.4
Other current assets	57.5			55.9
Current assets	1,410.7			2,334.2
Property, plant, and equipment, net of accumulated depreciation of $3,343.1 and $3,221.0, respectively	6,859.8			6,206.2
Regulatory assets	1,513.6			1,361.4
Equity method investments	572.4			540.9
Goodwill	655.4			655.4
Other long-term assets	270.1			145.4
Total assets	$	11,282.0		$	11,243.5
Liabilities and Equity
Short-term debt	$	317.6		$	326.0
Current portion of long-term debt	125.0			100.0
Accounts payable	490.7			401.9
Accrued taxes	87.7			78.9
Regulatory liabilities	153.7			101.1
Liabilities held for sale	—			49.1
Liabilities of discontinued operations related to IES’s retail energy business	—			447.5
Other current liabilities	261.4			218.9
Current liabilities	1,436.1			1,723.4
Long-term debt	2,956.3			2,956.2
Deferred income taxes	1,570.0			1,390.3
Deferred investment tax credits	65.5			57.6
Regulatory liabilities	399.9			383.7
Environmental remediation liabilities	579.9			600.0
Pension and other postretirement benefit obligations	274.6			200.8
Asset retirement obligations	480.2			491.0
Other long-term liabilities	168.7			127.1
Long-term liabilities	6,495.1			6,206.7
Commitments and contingencies
Common stock — $1 par value; 200,000,000 shares authorized; 79,963,091 shares issued; 79,534,171 shares outstanding	80.0			79.9
Additional paid-in capital	2,642.2			2,660.5
Retained earnings	626.0			567.1
Accumulated other comprehensive loss	(27.6		)	(23.2		)
Shares in deferred compensation trust	(20.9		)	(23.0		)
Total common shareholders’ equity	3,299.7			3,261.3
Preferred stock of subsidiary — $100 par value; 1,000,000 shares authorized; 511,882 shares issued; 510,495 shares outstanding	51.1			51.1
Noncontrolling interest in subsidiaries	—			1.0
Total liabilities and equity	$	11,282.0		$	11,243.5

The accompanying notes to the consolidated financial statements are an integral part of these statements.

4

CONSOLIDATED STATEMENTS OF EQUITY

	Integrys Energy Group Common Shareholders’ Equity
(Millions, except per share data)	Shares in Deferred Compensation Trust			Common Stock		Additional Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common Shareholders’ Equity			Preferred Stock of Subsidiary		Non- controlling Interest in Subsidiaries			Total Equity
Balance at December 31, 2011	$	(17.1	)	$	78.3	$	2,579.1		$	363.6		$	(42.5	)	$	2,961.4		$	51.1	$	0.1		$	3,012.6
Net income attributed to common shareholders	—			—		—			281.4			—			281.4			—		(0.2		)	281.2
Other comprehensive income	—			—		—			—			1.6			1.6			—		—			1.6
Stock-based compensation	—			—		(4.1		)	(0.7		)	—			(4.8		)	—		—			(4.8		)
Dividends on common stock (dividends per common share of $2.72)	—			—		—			(211.9		)	—			(211.9		)	—		—			(211.9		)
Shares purchased for the deferred compensation trust	(3.2		)	—		—			—			—			(3.2		)	—		—			(3.2		)
Other	2.6			—		(0.4		)	(0.9		)	—			1.3			—		—			1.3
Balance at December 31, 2012	$	(17.7	)	$	78.3	$	2,574.6		$	431.5		$	(40.9	)	$	3,025.8		$	51.1	$	(0.1	)	$	3,076.8
Net income attributed to common shareholders	—			—		—			351.8			—			351.8			—		(0.1		)	351.7
Other comprehensive income	—			—		—			—			17.7			17.7			—		—			17.7
Issuance of common stock	—			1.5		78.3			—			—			79.8			—		—			79.8
Stock-based compensation	—			—		1.0			(0.7		)	—			0.3			—		—			0.3
Dividends on common stock (dividends per common share of $2.72)	—			—		—			(214.6		)	—			(214.6		)	—		—			(214.6		)
Net contributions from noncontrolling parties	—			—		—			—			—			—			—		1.0			1.0
Shares issued to the deferred compensation trust	(6.3		)	0.1		6.2			—			—			—			—		—			—
Other	1.0			—		0.4			(0.9		)	—			0.5			—		0.2			0.7
Balance at December 31, 2013	$	(23.0	)	$	79.9	$	2,660.5		$	567.1		$	(23.2	)	$	3,261.3		$	51.1	$	1.0		$	3,313.4
Net income attributed to common shareholders	—			—		—			276.9			—			276.9			—		(0.1		)	276.8
Other comprehensive loss	—			—		—			—			(4.4		)	(4.4		)	—		—			(4.4		)
Issuance of common stock	—			0.1		2.3			—			—			2.4			—		—			2.4
Stock-based compensation	—			—		(20.9		)	(0.8		)	—			(21.7		)	—		—			(21.7		)
Dividends on common stock (dividends per common share of $2.72)	—			—		—			(216.3		)	—			(216.3		)	—		—			(216.3		)
Shares purchased for the deferred compensation trust	(0.6		)	—		—			—			—			(0.6		)	—		—			(0.6		)
Other	2.7			—		0.3			(0.9		)	—			2.1			—		(0.9		)	1.2
Balance at December 31, 2014	$	(20.9	)	$	80.0	$	2,642.2		$	626.0		$	(27.6	)	$	3,299.7		$	51.1	$	—		$	3,350.8

The accompanying notes to the consolidated financial statements are an integral part of these statements.

5

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31
(Millions)	2014			2013			2012
Operating Activities
Net income	$	279.9		$	354.8		$	284.3
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization expense	290.2			266.6			252.5
Recoveries and refunds of regulatory assets and liabilities	42.6			44.3			49.9
Net unrealized gains on energy contracts	(21.4		)	(100.5		)	(34.6		)
Bad debt expense	51.6			34.4			26.2
Pension and other postretirement expense	19.0			62.1			62.3
Pension and other postretirement contributions	(108.8		)	(77.0		)	(287.9		)
Deferred income taxes and investment tax credits	165.9			209.8			146.0
Gain on sale of UPPCO	(86.5		)	—			—
Loss on sale of IES’s retail energy business	24.3			—			—
Gain on sale or disposal of other assets	(15.2		)	(1.8		)	(2.7		)
Equity income, net of dividends	(13.3		)	(19.2		)	(17.5		)
Termination of tolling agreement with Fox Energy Company LLC	—			(50.0		)	—
Other	43.5			34.9			25.3
Changes in working capital
Collateral on deposit	(46.5		)	2.3			9.6
Accounts receivable and accrued unbilled revenues	11.2			(358.6		)	(26.2		)
Inventories	(124.4		)	16.8			28.9
Other current assets	(11.6		)	(50.4		)	6.6
Accounts payable	12.7			142.9			21.8
Other current liabilities	88.2			43.5			29.3
Net cash provided by operating activities	601.4			554.9			573.8
Investing Activities
Capital expenditures	(865.0		)	(669.2		)	(594.4		)
Proceeds from the sale of UPPCO, net of cash divested	336.5			—			—
Proceeds from the sale of IES’s retail energy business, net of cash divested	311.6			—			—
Proceeds from the sale or disposal of other assets	26.1			6.6			17.0
Capital contributions to equity method investments	(18.4		)	(13.7		)	(27.4		)
Rabbi trust funding related to potential change in control	(115.5		)	—			—
Acquisition of Fox Energy Company LLC	—			(391.6		)	—
Acquisitions at IES	—			(15.7		)	—
Grant received related to Crane Creek wind project	—			69.0			—
Other	(11.8		)	(8.1		)	2.2
Net cash used for investing activities	(336.5		)	(1,022.7		)	(602.6		)
Financing Activities
Short-term debt, net	(8.4		)	(156.4		)	179.1
Borrowing on term credit facility	—			200.0			—
Repayment of term credit facility	—			(200.0		)	—
Issuance of long-term debt	200.0			1,174.0			428.0
Repayment of long-term debt	(175.0		)	(363.5		)	(305.2		)
Proceeds from stock option exercises	85.8			38.7			55.8
Shares purchased for stock-based compensation	(142.9		)	(2.0		)	(89.9		)
Payment of dividends
Preferred stock of subsidiary	(3.1		)	(3.1		)	(3.1		)
Common stock	(216.3		)	(202.6		)	(211.9		)
Other	(9.3		)	(22.4		)	(24.7		)
Net cash (used for) provided by financing activities	(269.2		)	462.7			28.1
Net change in cash and cash equivalents	(4.3		)	(5.1		)	(0.7		)
Cash and cash equivalents at beginning of year	22.3			27.4			28.1
Cash and cash equivalents at end of year	$	18.0		$	22.3		$	27.4
Cash paid for interest	$	146.8		$	116.1		$	109.7
Cash paid (received) for income taxes	6.3			(4.8		)	(47.6		)

The accompanying notes to the consolidated financial statements are an integral part of these statements.

6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Summary of Significant Accounting Policies

(a) Nature of Operations—We are an energy holding company whose primary wholly owned subsidiaries at December 31, 2014, included MERC, MGU, NSG, PGL, WPS, IBS, ITF, and PDI. Of these subsidiaries, five are natural gas and/or electric utilities (MERC, MGU, NSG, PGL, and WPS). IBS is a centralized service company, ITF is a nonregulated compressed natural gas fueling business, and PDI is a nonregulated distributed solar energy company. In addition, we have an approximate 34% interest in ATC.

In August 2014, we sold UPPCO, and, in November 2014, we sold IES’s retail energy business. See Note 4, Dispositions, for more information on these sales.

(b) Basis of Presentation—As used in these notes, the term “financial statements” refers to the consolidated financial statements. This includes the consolidated statements of income, consolidated statements of comprehensive income, consolidated balance sheets, consolidated statements of equity, and consolidated statements of cash flows, unless otherwise noted.

The financial statements include our accounts and the accounts of all of our majority owned subsidiaries, after eliminating intercompany transactions and balances. These financial statements also reflect our proportionate interests in certain jointly owned utility facilities. The cost method of accounting is used for investments when we do not have significant influence over the operating and financial policies of the investee. Investments in businesses not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method. See Note 10, Equity Method Investments, for more information.

(c) Reclassifications—The assets and liabilities associated with the sale of UPPCO and the sale of eight ITF compressed natural gas fueling stations were reclassified to held for sale on our December 31, 2013, balance sheet. The assets and liabilities related to the sale of IES’s retail energy business were reclassified as assets and liabilities of discontinued operations on our December 31, 2013, balance sheet. In addition, the operations of IES’s retail energy business were reclassified to discontinued operations on our income statements for the years ended December 31, 2013, and 2012. See Note 4, Dispositions, for more information on these sales.

(d) Use of Estimates—We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect assets, liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates.

(e) Cash and Cash Equivalents—Short-term investments with an original maturity of three months or less are reported as cash equivalents.

(f) Revenues and Customer Receivables—Revenues related to the sale of energy are recognized when service is provided or energy is delivered to customers. We accrue estimated amounts of revenues for services provided or energy delivered but not yet billed to customers. Estimated unbilled revenues are calculated using a variety of judgments and assumptions related to customer class, contracted rates, weather, and customer use. At December 31, 2014 and 2013, our unbilled revenues were $269.4 million and $286.4 million, respectively.

We present revenues net of pass-through taxes on the income statements.

Below is a summary of the significant mechanisms our utility subsidiaries had in place in 2014 that allowed them to recover or refund changes in prudently incurred costs from rate case-approved amounts:

·Fuel and purchased power costs were recovered from customers on a one-for-one basis by UPPCO, WPS’s wholesale electric operations, and WPS’s Michigan retail electric operations.

·WPS’s Wisconsin retail electric operations used a “fuel window” mechanism to recover fuel and purchased power costs. Under the fuel window rule, a deferral is required for under or over-collections of actual fuel and purchased power costs that exceed a 2% price variance from the costs included in the rates charged to customers. WPS monitors the deferral of these costs to ensure that it does not cause them to earn a greater return on common equity than authorized by the PSCW.

·The rates for all of our natural gas utilities included one-for-one recovery mechanisms for natural gas commodity costs.

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·The rates of PGL and NSG included riders for cost recovery of both environmental cleanup and energy conservation and management program costs.

·MERC’s rates included a conservation improvement program rider for cost recovery of energy conservation and management program costs as well as a financial incentive for meeting energy savings goals.

·The rates of PGL and NSG included riders for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in customer rates.

·The rates of PGL, NSG, and MERC included decoupling mechanisms. These mechanisms differ by state and allow utilities to recover or refund differences between actual and authorized margins. See Note 25, Regulatory Environment, for more information.

·In 2014, PGL’s rates included a cost recovery mechanism for upgrades to the Illinois natural gas utility infrastructure.

Revenues are also impacted by other accounting policies related to PGL’s natural gas hub and our electric utilities’ participation in the MISO market. Amounts collected from PGL’s wholesale customers that use the natural gas hub are credited to natural gas costs, resulting in a reduction to retail customers’ charges for natural gas and services. WPS sells and purchases power in the MISO market. UPPCO also sold and purchased power in the MISO market until it was sold in August 2014. If WPS or UPPCO was a net seller in a particular hour, the net amount was reported as revenue. If WPS or UPPCO was a net purchaser in a particular hour, the net amount was recorded as utility cost of fuel, natural gas, and purchased power on the income statements.

ITF accounts for revenues from construction management projects using the percentage of completion method. Revenues are recognized based on the percentage of costs incurred to date compared to the total estimated costs of each contract. This method is used because management considers total costs to be the best available measure of progress on these contracts.

We provide regulated electric and natural gas service to customers in Illinois, Michigan, Minnesota, and Wisconsin. The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers’ credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Credit risk exposure at PGL and NSG is mitigated by their rider for cost recovery or refund of uncollectible expense discussed above. As a result, we did not have any significant concentrations of credit risk at December 31, 2014. In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2014.

(g) Inventories—Inventories consist of materials and supplies, natural gas in storage, liquid propane, emission allowances at WPS, and fossil fuels, including coal. Average cost is used to value materials and supplies, fossil fuels, liquid propane, emission allowances at WPS, and natural gas in storage for the utilities, excluding PGL and NSG. PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the Last-in, First-out (LIFO) cost method. Inventories stated on a LIFO basis represented approximately 37% of total inventories at December 31, 2014, and 30% of total inventories at December 31, 2013. The estimated replacement cost of natural gas in inventory at December 31, 2014, and December 31, 2013, exceeded the LIFO cost by $47.7 million and $151.7 million, respectively. In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per dekatherm of $3.04 at December 31, 2014, and $4.77 at December 31, 2013.

(h) Risk Management Activities—As part of our regular operations, we enter into contracts, including options, swaps, futures, forwards, and other contractual commitments, to manage market risks such as changes in commodity prices and interest rates. See Note 6, Risk Management Activities, for more information. Derivative instruments are entered into in accordance with the terms of each subsidiary’s risk management policies approved by their respective Boards of Directors and, if applicable, by their respective regulators.

All derivatives are recognized on the balance sheets at their fair value unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Because most energy-related derivatives at the utilities qualify for regulatory deferral, management believes any gains or losses resulting from the eventual settlement of derivative instruments will be refunded to or collected from customers in rates. As such, any changes in the fair value of these derivatives recorded as either risk management assets or liabilities are offset with regulatory liabilities or assets, as appropriate.

We classify derivative assets and liabilities as current or long-term on the balance sheets based on the maturities of the underlying contracts. We record unrealized gains and losses on derivative instruments that do not qualify for hedge accounting or regulatory deferral as a component of

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margins or operating and maintenance expense, depending on the nature of the transactions. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on the statements of cash flows.

Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On the balance sheets, cash collateral provided to others is reflected in other current assets, and cash collateral received from others is reflected in other current liabilities.

(i) Emission Allowances—WPS accounts for emission allowances as inventory at average cost by vintage year. Charges to income result when allowances are used in operating WPS’s generation plants. These charges are included in the costs subject to the fuel window rules. Gains on sales of allowances at WPS are returned to ratepayers.

(j) Property, Plant, and Equipment—Utility plant is stated at cost, including any associated AFUDC and asset retirement costs. The costs of renewals and betterments of units of property (as distinguished from minor items of property) are capitalized as additions to the utility plant accounts. Maintenance and repair costs, as well as replacement and renewal costs associated with items not qualifying as units of property, are recorded as operating expenses. The utilities record a regulatory liability for cost of removal accruals, which are included in rates. Actual removal costs are charged against the regulatory liability as incurred. Except for land, no gains or losses are recognized in connection with ordinary retirements of utility property units. Ordinary retirements, sales, and other disposals of units of property at the utilities are charged to accumulated depreciation at cost, less salvage value. When it becomes probable that an operating unit will be retired in the near future and substantially in advance of its expected useful life, the cost and corresponding accumulated depreciation of the asset is classified as plant to be retired, net within property, plant, and equipment.

We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the applicable regulators. Annual utility composite depreciation rates are shown below:

Annual Utility Composite Depreciation Rates	2014		2013		2012
MERC (1)	2.49	%	1.88	%	3.07	%
MGU (2)	2.65	%	1.93	%	2.71	%
NSG	2.44	%	2.44	%	2.43	%
PGL	3.20	%	3.19	%	3.16	%
WPS — Electric	2.73	%	2.79	%	2.87	%
WPS — Natural gas	2.17	%	2.19	%	2.21	%

(1)The 2013 depreciation rate reflects the impact of a new depreciation study approved by the MPUC in July 2013. The rates were effective retroactive to January 2012. An approximate $2 million reduction in depreciation expense was recorded in 2013 related to the 2012 impact.

(2)The 2013 depreciation rate includes the impact of a $2.5 million reduction in depreciation expense that was recorded in the first quarter of 2013 as a result of the Michigan Court of Appeals order reversing the MPSC’s previously ordered disallowance associated with the early retirement of certain MGU assets in 2010.

The majority of nonregulated plant is stated at cost, net of impairments recorded, and includes capitalized interest. The costs of renewals, betterments, and major overhauls are capitalized as additions to plant. Nonregulated plant acquired as a result of mergers and acquisitions have been recorded at fair value. The gains or losses associated with ordinary retirements are recorded in the period of retirement. Maintenance and repair costs and minor replacement costs are expensed as incurred. Depreciation is computed for the majority of the nonregulated subsidiaries’ assets using the straight-line method over the assets’ useful lives.

We capitalize certain costs related to software developed or obtained for internal use and amortize those costs to operating expense over the estimated useful life of the related software, which ranges from 3 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement.

We receive grants related to certain renewable generation projects under federal and state grant programs. Our policy is to reduce the depreciable basis of the qualifying project by the grant received. We then reflect the benefit of the grant in income over the life of the related renewable generation project through a reduction in depreciation expense.

See Note 7, Property, Plant, and Equipment, for more information.

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(k) AFUDC and Capitalized Interest—Our utilities and IBS capitalize the cost of funds used for construction using a calculation that includes both internal equity and external debt components, as required by regulatory accounting. The internal equity component is accounted for as other income. The external debt component is accounted for as a decrease to interest expense.

The majority of AFUDC is recorded at WPS. Approximately 50% of WPS’s retail jurisdictional construction work in progress expenditures are subject to the AFUDC calculation. For 2014, WPS’s average AFUDC retail rate was 8.08%, and its average AFUDC wholesale rate was 6.99%. The AFUDC calculation for the other utilities and IBS is determined by their respective state commissions, each with specific requirements. Based on these requirements, the other utilities and IBS did not record significant AFUDC for 2014, 2013, or 2012.

Total AFUDC was as follows for the years ended December 31:

	2014		2013		2012
Allowance for equity funds used during construction	$	12.5	$	10.8	$	2.9
Allowance for borrowed funds used during construction	5.2		4.1		1.0

(l) Regulatory Assets and Liabilities—Regulatory assets represent probable future revenue associated with certain costs or liabilities that have been deferred and are expected to be recovered through rates charged to customers. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or amounts collected in rates for future costs. Recovery or refund of regulatory assets and liabilities is based on specific periods determined by the regulators or occurs over the normal operating period of the assets and liabilities to which they relate. If at any reporting date a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery with the reduction charged to expense in the year the determination is made. See Note 9, Regulatory Assets and Liabilities, for more information.

(m) Investments in Exchange-Traded Funds—We have investments in exchange-traded funds. These investments are held in a rabbi trust to help fund our obligations under our deferred compensation plan and certain non-qualified pension plans. These investments are classified as trading securities for accounting purposes. As we do not intend to sell them in the near term, they are included in other long-term assets on our balance sheets. The net unrealized gains included in earnings related to the investments held at the end of the period were $1.8 million, $1.9 million, and $1.0 million for the years ended December 31, 2014, 2013, and 2012, respectively.

(n) Asset Impairment—Goodwill and other intangible assets with indefinite lives are subject to an annual impairment test. Interim impairment tests are performed when impairment indicators are present. Intangible assets with definite lives are reviewed for impairment on a quarterly basis. Other long-lived assets require an impairment review when events or circumstances indicate that the carrying amount may not be recoverable. We base our evaluation of other long-lived assets on the presence of impairment indicators such as the future economic benefit of the assets, any historical or future profitability measurements, and other external market conditions or factors.

Our reporting units containing goodwill perform annual goodwill impairment tests during the second quarter of each year. The carrying amount of the reporting unit’s goodwill is considered not recoverable if the carrying amount of the reporting unit exceeds the reporting unit’s fair value. An impairment loss is recorded for the excess of the carrying amount of the goodwill over its implied fair value. See Note 11, Goodwill and Other Intangible Assets, for more information on our goodwill and other intangible assets.

The carrying amount of tangible long-lived assets held and used is considered not recoverable if the carrying amount exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. If the carrying amount is not recoverable, the impairment loss is measured as the excess of the asset’s carrying amount over its fair value.

The carrying amount of assets held for sale is not recoverable if the carrying amount exceeds the fair value less estimated costs to sell the asset. An impairment loss is recorded for the excess of the asset’s carrying amount over the fair value less estimated costs to sell.

The carrying amounts of cost and equity method investments are assessed for impairment by comparing the fair values of these investments to their carrying amounts, if a fair value assessment was completed, or by reviewing for the presence of impairment indicators. If an impairment exists and it is determined to be other-than-temporary, a loss is recognized equal to the amount by which the carrying amount exceeds the investment’s fair value.

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(o) Retirement of Debt—Any call premiums or unamortized expenses associated with refinancing utility debt obligations are amortized consistent with regulatory treatment of those items. Any gains or losses resulting from the retirement of utility debt that is not refinanced are amortized over the remaining life of the original debt. Any gains or losses resulting from the retirement of nonutility debt are recorded through current earnings.

(p) Asset Retirement Obligations—We recognize at fair value legal obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction or development, and/or normal operation of the assets. A liability is recorded for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The asset retirement obligations are accreted using a credit-adjusted risk-free interest rate commensurate with the expected settlement dates of the asset retirement obligations; this rate is determined at the date the obligation is incurred. The associated retirement costs are capitalized as part of the related long-lived assets and are depreciated over the useful lives of the assets. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease in the carrying amount of the liability and the associated retirement cost. See Note 15, Asset Retirement Obligations, for more information.

(q) Environmental Remediation Costs— We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party (PRP). Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including former manufactured gas plant sites. See Note 17, Commitments and Contingencies, for more information on our manufactured gas plant sites.

We record environmental remediation liabilities when site assessments indicate remediation is probable and we can reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other PRPs or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation.

Our utilities have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the respective Commission’s approval.

We review our estimated costs of remediation annually for our manufactured gas plant sites and adjust the liabilities and related regulatory assets, as appropriate, to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year.

(r) Income Taxes—We file a consolidated United States income tax return that includes domestic subsidiaries of which our ownership is 80% or more. We and our consolidated subsidiaries are parties to a federal and state tax allocation arrangement under which each entity determines its provision for income taxes on a stand-alone basis. In several states, combined or consolidated filings are required for certain subsidiaries doing business in that state.

Deferred income taxes have been recorded to recognize the expected future tax consequences of events that have been included in the financial statements by using currently enacted tax rates for the differences between the income tax basis of assets and liabilities and the basis reported in the financial statements. We record valuation allowances for deferred income tax assets unless it is more likely than not that the benefit will be realized in the future. Our utilities defer certain adjustments made to income taxes that will impact future rates and record regulatory assets or liabilities related to these adjustments.

We use the deferral method of accounting for investment tax credits (ITCs). Under this method, we record the ITCs as deferred credits and amortize such credits as a reduction to the provision for income taxes over the life of the asset that generated the ITCs. ITCs that do not reduce income taxes payable for the current year are eligible for carryover and recognized as a deferred income tax asset.

We report interest and penalties accrued related to income taxes as a component of provision for income taxes in the income statements, as well as regulatory assets or regulatory liabilities on the balance sheets.

We record excess tax benefits from stock-based compensation awards when the actual tax benefit is realized. We follow the tax law ordering approach to determine when the tax benefit has been realized. Under this approach, the tax benefit is realized in the year it reduces taxable income. Current year stock-based compensation deductions are assumed to be used before any net operating loss carryforwards.

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See Note 16, Income Taxes, for more information regarding accounting for income taxes.

(s) Guarantees—We follow the guidance of the Guarantees Topic of the FASB ASC, which requires that the guarantor recognize, at the inception of the guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. See Note 22, Guarantees, for more information.

(t) Employee Benefits—The costs of pension and other postretirement benefits are expensed over the periods during which employees render service. Our transition obligation related to other postretirement benefit plans was recognized over a 20-year period that began in 1993, and ended in 2012. In computing the expected return on plan assets, we use a market-related value of plan assets, which is estimated using the following approaches by plan. For plans sponsored by IBS and WPS, we use the calculated value approach. For plans sponsored by PELLC, we use the fair market value approach. Changes in realized and unrealized investment gains and losses are recognized over the subsequent five years for plans sponsored by WPS, while differences between actual investment returns and the expected return on plan assets are recognized over a five-year period for plans sponsored by IBS and PELLC. The benefit costs associated with employee benefit plans are allocated among our subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for the utilities’ net periodic benefit cost calculated under GAAP.

We recognize the funded status of defined benefit postretirement plans on the balance sheet, and recognize changes in the plans’ funded status in the year in which the changes occur. Our nonregulated businesses record changes in the funded status in accumulated other comprehensive income. The utilities record changes in the funded status to regulatory asset or liability accounts, pursuant to the Regulated Operations Topic of the FASB ASC.

See Note 18, Employee Benefit Plans, for more information.

(u) Stock-Based Compensation—In May 2014, our shareholders approved the 2014 Omnibus Incentive Compensation Plan (2014 Omnibus Plan). Under the provisions of the 2014 Omnibus Plan, the number of shares of stock that may be issued in satisfaction of plan awards may not exceed 3,000,000 shares, plus any shares forfeited under prior plans. No single employee who is our chief executive officer, chief financial officer, or any one of our other three highest compensated officers (including officers of our subsidiaries) can be granted stock options for more than 1,000,000 shares or receive a payout in excess of 250,000 shares for performance stock rights during any calendar year. Additional awards will not be issued under prior plans, although the plans continue to exist for purposes of the existing outstanding stock-based compensation awards. At December 31, 2014, stock options, performance stock rights, and restricted share units were outstanding under prior plans.

Stock Options

Our stock options have a term not longer than 10 years. The exercise price of each stock option is equal to the fair market value of our stock on the date the stock option is granted.

Effective October 24, 2014, our Board of Directors accelerated the vesting of all unvested stock options held by active employees in order to help mitigate the tax impacts of Section 280G of the Internal Revenue Code on us and certain of our employees. All stock options awarded to active employees also became exercisable as of this date. For retirees, 25% of their stock options granted will continue to become exercisable each year on the anniversary of the grant date.

The fair value of stock option awards granted is estimated using a binomial lattice model. The expected term of option awards is derived from the output of the binomial lattice model and represents the period of time that options are expected to be outstanding. The risk-free interest rate is based on the United States Treasury yield curve. The expected dividend yield incorporates the current and historical dividend rate. Our expected stock price volatility is estimated using the 10-year historical volatility of our stock price.

Performance Stock Rights

Performance stock rights generally vest over a three-year performance period. For accounting purposes, awards granted to retirement-eligible employees vest over a shorter period; however, the distribution of these awards is not accelerated. Effective October 24, 2014, our Board of Directors approved the acceleration of the distribution of certain performance stock rights held by active employees. For those performance stock rights with a performance period ending December 31, 2014, a portion of the estimated distribution was made in December 2014. This change was made to help mitigate the tax impacts of Section 280G of the Internal Revenue Code on us and certain of our employees.

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Performance stock rights are paid out in shares of our common stock, or eligible employees can elect to defer the value of their awards into the deferred compensation plan and choose among various investment options, some of which are ultimately paid out in our common stock and some of which are ultimately paid out in cash. Eligible employees can only elect to defer up to 80% of the value of their awards. The number of shares paid out is calculated by multiplying a performance percentage by the number of outstanding stock rights at the completion of the performance period. The performance percentage is based on the total shareholder return of our common stock relative to the total shareholder return of a peer group of companies. The payout may range from 0% to 200% of target.

Performance stock rights are accounted for as either an equity award or a liability award, depending on their settlement features. Awards that can only be settled in our common stock are accounted for as equity awards. Awards that an employee has elected to defer, or is still able to defer, into the deferred compensation plan are accounted for as liability awards and are recorded at fair value each reporting period.

Six months prior to the end of the performance period, employees can no longer change their election to defer the value of their performance stock rights into the deferred compensation plan. As a result, any awards not elected for deferral at this point in the performance period will be settled in our common stock. This changes the classification of these awards from a liability award to an equity award. The change in classification is accounted for as an award modification. The fair value on the modification date is used to measure these awards for the remaining six months of the performance period. No incremental compensation expense is recorded as a result of this award modification.

The fair values of performance stock rights are estimated using a Monte Carlo valuation model. The risk-free interest rate is based on the United States Treasury yield curve. The expected dividend yield incorporates the current and historical dividend rate. Our expected stock price volatility is estimated using one to three years of historical data.

Restricted Share Units

Restricted share units generally have a four-year vesting period, with 25% of each award vesting on each anniversary of the grant date. For accounting purposes, awards granted to retirement-eligible employees vest over a shorter period; however, the release of shares to these employees is not accelerated. Restricted share unit recipients do not have voting rights, but they receive forfeitable dividend equivalents in the form of additional restricted share units.

Restricted share units are accounted for as either an equity award or a liability award, depending on their settlement features. Awards that can only be settled in our common stock and cannot be deferred into the deferred compensation plan are accounted for as equity awards. Eligible employees can only elect to defer up to 80% of their awards into the deferred compensation plan. Equity awards are measured based on the fair value on the grant date. Awards that an employee has elected to defer into the deferred compensation plan are accounted for as liability awards and are recorded at fair value each reporting period.

Nonemployee Directors Deferred Stock Units

Each nonemployee director is granted deferred stock units (DSUs), typically in January of each year. The number of DSUs granted is calculated by dividing a set dollar amount by our closing common stock price on December 31 of the prior year. DSUs generally vest over one year. Therefore, the expense for these awards is recognized pro-rata over the year in which the grant occurs. Upon vesting, these awards are deferred into the deferred compensation plan; however, their value cannot be diversified among the various investment options. As DSUs can only be settled in our common stock, they are accounted for as equity awards.

(v) Earnings Per Share—Basic earnings per share is computed by dividing net income attributed to common shareholders by the weighted average number of common shares outstanding during the period, adjusted for shares we are obligated to issue under the deferred compensation and restricted share unit plans. Diluted earnings per share is computed in a similar manner, but includes the exercise and/or conversion of all potentially dilutive securities. Such dilutive items include in-the-money stock options, performance stock rights, restricted share units, unvested director DSUs, and certain shares issuable under the deferred compensation plan. As the obligation for the shares issuable under the deferred compensation plan is accounted for as a liability, the numerator is adjusted for any changes in income or loss that would have resulted had it been accounted for as an equity instrument during the period.

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(w) Fair Value—A fair value measurement is required to reflect the assumptions market participants would use in pricing an asset or liability based on the best available information.

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). 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.

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.

When possible, we base the valuations of our risk management assets and liabilities on quoted prices for identical assets in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on observable inputs related to market price risk (commodity or interest rate), price volatility (for option contracts), and price correlation (for cross commodity contracts). 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 primary reasons for a Level 3 classification are as follows:

·Financial contracts used to manage transmission congestion costs in the MISO market are valued using historical prices.

·The valuation for physical coal contracts is based on significant assumptions made to extrapolate prices from the last observable period through the end of the transaction term.

·Certain natural gas contracts are valued using internally-developed inputs due to the absence of available market data for certain locations.

We have established risk oversight committees whose primary responsibility includes directly or indirectly ensuring that all valuation methods are applied in accordance with predefined policies. The development and maintenance of our forward price curves has been assigned to our risk management department, which is part of the corporate treasury function. This group is separate and distinct from any of the supply functions within the organization. To validate the reasonableness of our fair value inputs, our risk management department compares changes in valuation and researches any significant differences in order to determine the underlying cause. Changes to the fair value inputs are made if necessary.

Derivatives are transferred between levels of the fair value hierarchy due to observable pricing becoming available as the remaining contract term becomes shorter. We recognize transfers at the value as of the end of the reporting period.

The fair values of long-term debt instruments are estimated based on the quoted market price for the same or similar issues, or on the current rates offered to us for debt of the same remaining maturity. The fair values of preferred stock are estimated based on quoted market prices when available, or by using a perpetual dividend discount model. The fair values of long-term debt instruments and preferred stock are categorized within Level 2 of the fair value hierarchy. Due to the short-term nature of cash and cash equivalents, accounts receivable, accounts payable, and outstanding commercial paper, the carrying amount for each of these items approximates fair value.

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

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See Note 24, Fair Value, for more information.

(x) New Accounting Pronouncements—

Recently Issued Accounting Guidance Not Yet Effective

In February 2015, the FASB issued ASU 2015-02, “Amendments to the Consolidation Analysis.” The guidance focuses on the consolidation evaluation for companies that are required to evaluate whether they should consolidate certain legal entities. This ASU eliminates the specialized guidance for limited partnerships and similar legal entities. It places more emphasis on risk of loss when determining a controlling financial interest and amends the guidance for assessing how relationships of related parties affect the consolidation analysis of variable interest entities. The guidance is effective for us for the reporting period ending March 31, 2016. We are currently evaluating the impact this guidance will have on our financial statements.

In January 2015, the FASB issued ASU 2015-01, “Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items.” This guidance no longer requires or allows the disclosure of extraordinary items, net of tax, in the income statement after income from continuing operations. The guidance is effective for us for the reporting period ending March 31, 2016. We do not currently have any extraordinary items presented on the income statements. However, this guidance will eliminate the need for us to further assess whether unusual and infrequently occurring transactions qualify as an extraordinary item in the future.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers.” This ASU supersedes the requirements in the Revenue Recognition Topic of the FASB ASC and most industry-specific guidance throughout the ASC. 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. The standard requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and cash flows from customer contracts. The guidance is effective for us for the reporting period ending March 31, 2017. The standard requires either retrospective application by restating each prior period presented in the financial statements, or modified retrospective application by recording the cumulative effect of prior reporting periods to beginning retained earnings in the year that the standard becomes effective. Management is currently evaluating the impact that the adoption of this standard will have on our financial statements.

In April 2014, the FASB issued ASU 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” The guidance raises the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. The guidance applies prospectively to new disposals and new classifications of disposal groups as held for sale after the effective date. Management early adopted this guidance in the third quarter of 2014. See Note 4, Dispositions, for more information.

In January 2014, the FASB issued ASU 2014-01, “Accounting for Investments in Qualified Affordable Housing Projects.” The guidance allows investors to use the proportional amortization method to account for investments in qualified affordable housing projects if certain conditions are met. Under that method, which replaces the effective yield method, an investor amortizes the cost of its investment, in proportion to the tax credits and other tax benefits it receives, to income tax expense. The guidance also requires new disclosures for all investments in these types of projects. The guidance is effective for us for the reporting period ending March 31, 2015. Although we have investments in affordable housing projects, adoption of this guidance is not expected to have a significant impact on our financial statements.

Note 2—Proposed Merger with Wisconsin Energy Corporation

In June 2014, we entered into an Agreement and Plan of Merger (Agreement) with Wisconsin Energy Corporation (Wisconsin Energy). Under this Agreement, upon the close of the transaction our shareholders will receive 1.128 shares of Wisconsin Energy common stock and $18.58 in cash for each share of our common stock then owned. In addition, under the Agreement all of our unvested stock-based compensation awards will fully vest upon the close of the transaction and will be paid out in cash to award recipients. Upon closing of the transaction, our shareholders will own approximately 28% of the combined company, and Wisconsin Energy shareholders will own approximately 72%.

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The combined entity will be named WEC Energy Group, Inc. and will serve more than 4.3 million total natural gas and electric customers across Wisconsin, Illinois, Michigan, and Minnesota.

This transaction was approved unanimously by the Boards of Directors of both companies. It was also approved by the shareholders of both companies. On October 24, 2014, the Department of Justice closed its review of the transaction and the Federal Trade Commission granted early termination of the waiting period under the Hart-Scott-Rodino Act. The transaction is still subject to approvals from the FERC, Federal Communications Commission (FCC), PSCW, ICC, MPSC, and MPUC, as well as other customary closing conditions. We are a party to a contested settlement agreement with the MPSC staff and all but one of the parties in the MPSC approval docket. The settling parties agree that the MPSC should grant approval of the merger contingent on additional transactions, including the sale of the Presque Isle facility currently owned by Wisconsin Energy, as well as the Michigan electric distribution assets of Wisconsin Energy and WPS, to UPPCO. The asset sales require additional approvals, including the MPSC, PSCW, FERC, FCC, and Committee on Foreign Investment in the United States, as well as the requirements of the Hart-Scott-Rodino Act. We expect the merger transaction to close in the second half of 2015.

Note 3—Acquisitions

Agreement to Purchase Alliant Energy Corporation’s Natural Gas Distribution Business in Southeast Minnesota

In September 2013, MERC entered into an agreement to purchase Alliant Energy Corporation’s natural gas distribution business in southeast Minnesota. This transaction was approved by the MPUC. The purchase price will be based on book value as of the closing date, which is expected to approximate $14 million. We anticipate closing on this transaction by the end of the second quarter of 2015. It will not be material to us.

Acquisition of Fox Energy Center

In March 2013, WPS acquired all of the equity interests in Fox Energy Company LLC for $391.6 million. Fox Energy Company LLC was dissolved into WPS immediately after the purchase.

The purchase included the Fox Energy Center, a 593-megawatt combined-cycle electric generating facility located in Wisconsin, along with associated contracts. Fox Energy Center is a dual-fuel facility, equipped to use fuel oil, but being run primarily on natural gas. This plant gives WPS a more balanced mix of owned electric generation, including coal, natural gas, hydroelectric, wind, and other renewable sources. In giving its approval for the purchase, the PSCW stated that the purchase price was reasonable and will benefit ratepayers.

The purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as follows:

(Millions)
Assets acquired (1)
Inventories	$	3.0
Other current assets	0.4
Property, plant, and equipment	374.4
Other long-term assets (2)	15.6
Total assets acquired	$	393.4
Liabilities assumed
Accounts payable	$	1.8
Total liabilities assumed	$	1.8

(1)Relates to the electric utility segment.

(2)Intangible assets recorded for contractual services agreements. See Note 11, Goodwill and Other Intangible Assets, for more information.

Prior to the purchase, WPS supplied natural gas for the facility and purchased 500 megawatts of capacity and the associated energy output under a tolling arrangement. WPS paid $50.0 million for the early termination of the tolling arrangement. This amount was recorded as a regulatory asset, as WPS is authorized recovery by the PSCW. The amount is being amortized over a nine-year period that began on January 1, 2014.

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WPS received regulatory approval to defer incremental costs incurred in 2013 associated with the purchase of the facility. These costs are included in WPS’s 2015 retail electric rate increase. See Note 25, Regulatory Environment, for more information. WPS’s rate order effective January 1, 2014, included the costs of owning and operating the Fox Energy Center.

Pro forma adjustments to our revenues and earnings prior to the date of acquisition would not be meaningful or material. Prior to the acquisition, the Fox Energy Center was a nonregulated plant and sold all of its output to third parties, with most of the output purchased by WPS. The plant is now part of WPS’s regulated fleet, used to serve its customers.

Note 4—Dispositions

Dispositions

Holding Company and Other Segment — Sale of Compressed Natural Gas (CNG) Fueling Stations

In November 2014, ITF sold eight CNG fueling stations to AMP Trillium LLC, a joint venture between ITF and AMP Americas LLC. ITF owns 30% and AMP Americas LLC owns 70% of AMP Trillium LLC. The fair value of the CNG fueling stations was $13.0 million. ITF received cash proceeds of $7.2 million, a $2.7 million note receivable from the buyer with a seven-year term, and a $3.1 million equity interest in the joint venture to maintain its ownership interest. In November 2014, we recorded a pre-tax gain of $1.8 million related to the sale of the CNG fueling stations and deferred a gain of $0.8 million that is being recognized over the lives of the stations sold. The pre-tax gain was reported as a component of operating and maintenance expense on the income statement.

In the third quarter of 2014, we early adopted the guidance in FASB ASU 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” Under this guidance, the results of operations of a component of a business that is sold are only accounted for as discontinued operations if the sale represents a shift in strategy that has (or will have) a major effect on the entity’s operations and financial results. The sale of the CNG stations did not represent a shift in our strategy. Therefore, the results of operations of the CNG fueling stations prior to the sale remain in continuing operations.

Net property, plant, and equipment of $10.4 million was included with the sale on November 1, 2014, which is net of accumulated depreciation of $0.7 million. Net property, plant, and equipment of $5.3 million were classified as held for sale on the balance sheet at December 31, 2013, which was net of accumulated depreciation of $0.3 million.

Electric Utility Segment — Sale of UPPCO

In August 2014, we sold all of the stock of UPPCO to Balfour Beatty Infrastructure Partners LP for $336.7 million. In the third quarter of 2014, we recorded a pre-tax gain of $85.4 million ($51.2 million after-tax) related to the sale of UPPCO, which was net of transaction costs of $1.1 million. Following the sale, we are providing certain administrative and operational services to UPPCO during a transition period of 18 to 30 months.

The sale of UPPCO was evaluated for accounting purposes prior to our early adoption of ASU 2014-08. UPPCO met the criteria in the accounting guidance to qualify as held for sale but did not meet the requirements to qualify as discontinued operations as WPS has significant continuing cash flows related to certain power purchase transactions with UPPCO that continued after the sale. Therefore, UPPCO’s results of operations through the sale date remain in continuing operations.

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The following table shows the carrying values of the major classes of assets and liabilities related to UPPCO:

	As of the Closing Date		Held for Sale at
(Millions)	in August 2014		December 31, 2013
Current assets	$	24.3	$	26.5
Property, plant, and equipment, net of accumulated depreciation of $91.3 and $88.9, respectively	194.4		193.8
Other long-term assets	72.8		51.6
Total assets	$	291.5	$	271.9
Current liabilities	$	12.7	$	16.7
Long-term liabilities	28.6		32.4
Total liabilities	$	41.3	$	49.1

In addition to the amounts in the table above, intercompany payables of $1.6 million at December 31, 2013 related to certain power purchase transactions with WPS that continued after the sale were eliminated during consolidation. As of the closing date, these payables were included in the sale and disclosed in the table above as current liabilities.

Holding Company and Other Segment — Winnebago Energy Center

In May 2014, a fire significantly damaged the Winnebago Energy Center, a landfill-gas-to-electric facility that was owned by PDI. Due to uncertainty surrounding the amount of the insurance settlement, we were unable to determine if we would rebuild or abandon the Winnebago Energy Center in the second quarter of 2014. In the third quarter of 2014, we decided to abandon the facility and received proceeds of $6.1 million for both insurance recovery for the damage caused by the fire and from the sale of miscellaneous parts. As a result, we recorded a pre-tax gain of $5.0 million.

In the third quarter of 2014, we early adopted the guidance in FASB ASU 2014-08, as stated previously. Based on this new guidance, the Winnebago Energy Center did not qualify as discontinued operations since it did not represent a shift in our strategy. Therefore, its results of operations prior to the fire remain in continuing operations.

Discontinued Operations

See Note 5, Cash and Cash Equivalents, for cash flow information related to discontinued operations.

Holding Company and Other Segment — Potential Sale of Combined Locks Energy Center (Combined Locks)

We are currently pursuing the sale of Combined Locks, a natural gas-fired co-generation facility located in Wisconsin. Combined Locks had $0.7 million of assets that were classified as held for sale on the balance sheets at December 31, 2014, and December 31, 2013, which included inventories and property, plant, and equipment. We recorded after-tax losses of $0.5 million, $1.3 million, and $0.6 million in 2014, 2013, and 2012, respectively, in discontinued operations related to Combined Locks.

IES Segment — Sale of IES Retail Energy Business

In November 2014, we sold IES’s retail energy business to Exelon Generation Company, LLC (Exelon) for $333.0 million. The purchase price is subject to adjustments for working capital. We recorded a pre-tax loss on the sale of $28.8 million ($17.3 million after tax), which included transaction costs of $4.5 million in 2014. Included in these costs is an immaterial amount related to severances. As part of the purchase agreement, we will continue to hold certain guarantees supporting the IES retail energy business for up to six months following the sale. Exelon is obligated under the purchase agreement to replace these guarantees with its own credit support for the IES retail energy business. See Note 22, Guarantees, for more information. Following the sale, we are providing certain administrative and operational services to Exelon during a transition period of up to 15 months.

The retail energy business consisted of mostly financial assets and liabilities; therefore, it did not qualify as held for sale under the applicable accounting guidance. In the third quarter of 2014, we early adopted the guidance in FASB ASU 2014-08, as stated previously. The sale of the retail

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energy business is a result of a previously announced shift in our strategy to focus on our regulated businesses. Therefore, its results of operations were classified as discontinued operations beginning in the fourth quarter of 2014.

The following table shows the carrying values of the major classes of assets and liabilities included in the sale:

	As of the Closing Date in
(Millions)	November 2014		December 31, 2013
Cash and cash equivalents	$	7.6	$	5.5
Accounts receivable and accrued unbilled revenues, net of reserves of $1.8 and $1.7, respectively	293.8		390.9
Inventories	52.4		34.2
Current assets from risk management activities	234.8		229.5
Prepaid taxes	—		2.5
Other current assets	75.1		41.5
Property, plant, and equipment, net of accumulated depreciation of $16.6 and $15.6, respectively	4.5		5.2
Long-term assets from risk management activities	106.9		73.4
Goodwill	—		6.7
Other long-term assets	25.5		26.0
Total assets	$	800.6	$	815.4
Accounts payable	$	186.9	$	202.9
Current liabilities from risk management activities	169.7		160.6
Accrued taxes	0.2		2.0
Other current liabilities	6.7		13.1
Long-term liabilities from risk management activities	79.5		61.9
Other long-term liabilities	0.3		7.0
Total liabilities	$	443.3	$	447.5

Included in the sale were commodity contracts that did not meet the GAAP definition of derivative instruments and, therefore, were not reflected on the balance sheets. In accordance with GAAP, expected gains or losses related to nonderivative commodity contracts are not recognized until the contracts are settled.

The following table shows the components of discontinued operations related to the sale of the IES retail energy business recorded on the income statements:

(Millions)	2014			2013			2012
Revenues	$	2,587.1		$	2,150.9		$	1,201.0
Cost of sales	(2,444.7		)	(1,910.7		)	(1,018.9		)
Operating and maintenance expense	(91.5		)	(105.6		)	(88.3		)
Depreciation and amortization expense	(2.7		)	(3.2		)	(3.4		)
Taxes other than income taxes	(4.9		)	(3.2		)	(2.4		)
Goodwill impairment loss	(6.7		)	—			—
Loss on sale of IES retail energy business	(28.8		)	—			—
Miscellaneous income	0.6			7.9			0.3
Interest expense	(0.7		)	(0.8		)	(1.3		)
Income before taxes	7.7			135.3			87.0
Provision for income taxes *	(7.3		)	(52.8		)	(31.9		)
Discontinued operations, net of tax	$	0.4		$	82.5		$	55.1

*See Note 16, Income Taxes, for more information.

The June 2014 announcement of the potential sale triggered an interim goodwill impairment test. Based on the results of the interim goodwill impairment analysis, IES recorded a non-cash goodwill impairment loss in the second quarter of 2014. This goodwill impairment loss reflected the offers received for IES’s retail energy business.

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Holding Company and Other Segment — Sale of WPS Beaver Falls Generation, LLC (Beaver Falls) and WPS Syracuse Generation, LLC (Syracuse)

In March 2013, WPS Empire State, Inc. sold all of the membership interests of Beaver Falls and Syracuse, both of which owned natural gas-fired generation plants located in the state of New York. We recorded a pre-tax impairment loss of $1.1 million ($0.7 million after tax) related to Beaver Falls and Syracuse during 2012 when the assets and liabilities were classified as held for sale. This impairment loss is reflected in operating and maintenance expense in the table below. The sale agreement included a potential annual payment to us for a four-year period following the sale based on a certain level of earnings achieved by the buyer (an earn-out). In September 2014, we entered into an agreement to receive $2.0 million in settlement of this earn-out agreement, which is presented in operating and maintenance expense in the table below.

The following table shows the components of discontinued operations related to Beaver Falls and Syracuse recorded on the income statements:

(Millions)	2014			2013			2012
Revenues	$	—		$	1.2		$	0.6
Cost of sales	—			(0.9		)	(2.0		)
Operating and maintenance expense	2.0			0.4		*	(3.5		)
Depreciation and amortization expense	—			—			(0.6		)
Taxes other than income taxes	—			(0.3		)	(1.4		)
Miscellaneous income	—			—			0.3
Income (loss) before taxes	2.0			0.4			(6.6		)
(Provision) benefit for income taxes	(0.8		)	(0.2		)	2.6
Discontinued operations, net of tax	$	1.2		$	0.2		$	(4.0	)

*Includes a $1.0 million gain on sale at closing.

Holding Company and Other Segment — Uncertain Tax Positions

In 2014, we recorded a $0.7 million after-tax gain at the holding company and other segment when we remeasured an uncertain tax position included in our liability for unrecognized tax benefits due to a lapse in the statute of limitations. During 2013 and 2012, we recorded a $5.9 million after-tax gain and a $1.8 million after-tax gain, respectively, in discontinued operations at the holding company and other segment. We remeasured uncertain tax positions included in our liability for unrecognized tax benefits after effectively settling certain state income tax examinations. We reduced the provision for income taxes related to these remeasurements.

Holding Company and Other Segment — Sale of WPS Westwood Generation, LLC (Westwood)

In November 2012, Sunbury Holdings, LLC, a subsidiary of IES, sold all of the membership interests of Westwood, a waste coal generation plant located in Pennsylvania. We recorded a pre-tax impairment loss of $8.4 million ($5.0 million after tax) related to Westwood during the third quarter of 2012 when the assets and liabilities were classified as held for sale. This impairment loss is reflected in operating and maintenance expense in the table below.

The following table shows the components of discontinued operations related to Westwood recorded on the income statements:

(Millions)	2012
Revenues	$	9.2
Cost of sales	(4.4		)
Operating and maintenance expense	(14.3		)*
Depreciation and amortization expense	(1.0		)
Taxes other than income taxes	(0.2		)
Interest expense	(0.7		)
Loss before taxes	(11.4		)
Benefit for income taxes	4.5
Discontinued operations, net of tax	$	(6.9	)

*Includes a $0.6 million loss on sale at closing.

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Note 5—Cash and Cash Equivalents

Continuing Operations

Significant noncash transactions related to continuing operations were:

(Millions)	2014		2013		2012
Construction costs funded through accounts payable	$	180.5	$	108.5	$	92.4
Accounts receivable converted to notes receivable related to sales of ITF fueling stations constructed on behalf of others	10.9		—		—
Portion of ITF fueling station sale financed with note receivable *	2.7		—		—
Equity interest in joint venture received for a portion of the ITF fueling station sale *	3.1		—		—
Equity issued for employee stock ownership plan	1.7		14.3		—
Equity issued for stock-based compensation plans	—		16.3		—
Equity issued for reinvested dividends	—		12.0		—

*See Note 4, Dispositions, for more information.

At December 31, 2014, restricted cash of $31.3 million was recorded within other long-term assets on our balance sheet. This amount was held in the rabbi trust and was a portion of the required funding for the rabbit trust that was triggered by the announcement of the proposed merger with Wisconsin Energy Corporation. See Note 2, Proposed Merger with Wisconsin Energy Corporation, for more information about the proposed merger. See Note 18, Employee Benefit Plans, for more information on the rabbi trust funding requirements.

Discontinued Operations

Following our early adoption of FASB ASU 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity,” we changed the presentation of our cash flow statement and no longer present cash flows related to discontinued operations separately. Significant noncash transactions and other information related to discontinued operations are disclosed below.

(Millions)	2014			2013			2012
Operating Activities
Depreciation and amortization expense	$	2.7		$	3.3		$	5.3
Net unrealized gains on energy contracts	(22.7		)	(100.3		)	(34.5		)
Deferred income taxes and investment tax credits	36.1			56.1			(0.4		)
Remeasurement of uncertain tax positions included in our liability for unrecognized tax benefits	(0.7		)	(5.9		)	(1.8		)
Loss on sale of IES’s retail energy business *	24.3			—			—
Other	33.4			23.8			21.7
Investing Activities
Capital expenditures	(0.8		)	(2.6		)	(2.0		)
Contingent consideration and payables related to the acquisition of Compass Energy Services	—			7.8			—
Portion of Westwood sale financed with note receivable *	—			—			4.0

*See Note 4, Dispositions, for more information.

See Note 1(x), New Accounting Pronouncements, for more information about the adoption of FASB ASU 2014-08.

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Note 6—Risk Management Activities

The following tables show our assets and liabilities from risk management activities at the utilities and IBS:

		December 31, 2014
(Millions)	Balance Sheet Presentation	Assets from Risk Management Activities		Liabilities from Risk Management Activities
Nonhedge derivatives
Natural gas contracts	Other current	$	1.8	$	37.3
Natural gas contracts	Other long-term	0.5		5.3
Financial transmission rights (FTRs)	Other current	2.2		0.3
Petroleum product contracts	Other current	—		2.7
Petroleum product contracts	Other long-term	—		0.1
Coal contracts	Other current	—		2.4
Coal contracts	Other long-term	—		1.0
	Other current	4.0		42.7
	Other long-term	0.5		6.4
Total		$	4.5	$	49.1

		December 31, 2013
(Millions)	Balance Sheet Presentation	Assets from Risk Management Activities		Liabilities from Risk Management Activities
Nonhedge derivatives
Natural gas contracts	Other current	$	8.3	$	1.0
Natural gas contracts	Other long-term	1.8		0.1
FTRs	Other current	1.5		0.3
Petroleum product contracts	Other current	0.1		—
Coal contracts	Other current	—		1.9
Coal contracts	Other long-term	0.2		0.8
	Other current	9.9		3.2
	Other long-term	2.0		0.9
Total		$	11.9	$	4.1

The following tables show the potential effect on our financial position of netting arrangements for recognized derivative assets and liabilities:

	December 31, 2014
(Millions)	Gross Amount		Potential Effects of Netting, Including Cash Collateral		Net Amount
Derivative assets subject to master netting or similar arrangements	$	3.2	$	1.3	$	1.9
Derivative assets not subject to master netting or similar arrangements	1.3				1.3
Total risk management assets	$	4.5			$	3.2
Derivative liabilities subject to master netting or similar arrangements	$	45.7	$	8.8	$	36.9
Derivative liabilities not subject to master netting or similar arrangements	3.4				3.4
Total risk management liabilities	$	49.1			$	40.3

	December 31, 2013
(Millions)	Gross Amount		Potential Effects of Netting, Including Cash Collateral		Net Amount
Derivative assets subject to master netting or similar arrangements	$	11.7	$	2.1	$	9.6
Derivative assets not subject to master netting or similar arrangements	0.2				0.2
Total risk management assets	11.9				9.8
Derivative liabilities subject to master netting or similar arrangements	$	1.4	$	1.4	$	—
Derivative liabilities not subject to master netting or similar arrangements	2.7				2.7
Total risk management liabilities	$	4.1			$	2.7

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Our master netting and similar arrangements have conditional rights of setoff that can be enforced under a variety of situations, including counterparty default or credit rating downgrade below investment grade. We have trade receivables and trade payables, subject to master netting or similar arrangements, that are not included in the above table. These amounts may offset (or conditionally offset) the net amounts presented in the above table.

Financial collateral received or provided is restricted to the extent that it is required per the terms of the related agreements. The following table shows our cash collateral positions:

(Millions)	December 31, 2014		December 31, 2013
Cash collateral provided to others:
Related to contracts under master netting or similar arrangements	$	11.6	$	3.6
Other	1.1		1.1
Cash collateral received from others related to contracts under master netting or similar arrangements	—		0.7

Certain of our derivative and nonderivative commodity instruments contain provisions that could require “adequate assurance” in the event of a material change in our creditworthiness, or the posting of additional collateral for instruments in net liability positions, if triggered by a decrease in credit ratings. The aggregate fair value of all derivative instruments with specific credit risk-related contingent features that were in a liability position at December 31, 2014, and 2013, was $31.3 million, and $0.6 million, respectively. At December 31, 2014, and 2013, we had not posted any cash collateral related to the credit risk-related contingent features of these commodity instruments.  If all of the credit risk-related contingent features contained in commodity instruments  (including derivatives, nonderivatives, normal purchase and normal sales contracts, and applicable payables and receivables) had been triggered at December 31, 2014, we would have been required to post collateral of $27.1 million. If all of the credit risk-related contingent features contained in commodity instruments had been triggered at December 31, 2013, we would not have been required to post collateral.

Utility Segments

Non-Hedge Derivatives

Utility derivatives include natural gas purchase contracts, coal purchase contracts, financial derivative contracts, and FTRs. The electric utility segment uses FTRs to manage electric transmission congestion costs. The natural gas and electric utility segments use financial derivative contracts to manage the risks associated with the market price volatility of natural gas supply costs. In addition, IBS enters into financial derivative contracts on behalf of the utilities to manage the cost of gasoline and diesel fuel used by utility vehicles.

The notional volumes of outstanding derivative contracts at the utilities and IBS were as follows:

	December 31, 2014			December 31, 2013
(Millions)	Purchases	Sales	Other Transactions	Purchases	Sales	Other Transactions
Natural gas (therms)	1,860.0	—	N/A	3,124.8	29.3	N/A
FTRs (kilowatt-hours)	N/A	N/A	4,287.7	N/A	N/A	3,427.0
Petroleum products (barrels)	0.1	—	N/A	0.1	—	N/A
Coal (tons)	3.0	—	N/A	4.8	—	N/A

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The table below shows the unrealized gains (losses) recorded related to derivative contracts at the utilities and IBS:

(Millions)	Financial Statement Presentation	2014			2013			2012
Natural gas	Balance Sheet — Regulatory assets (current)	$	(38.0	)	$	13.4		$	24.6
Natural gas	Balance Sheet — Regulatory assets (long-term)	(5.2		)	2.3			8.3
Natural gas	Balance Sheet — Regulatory liabilities (current)	(3.9		)	4.6			(7.8		)
Natural gas	Balance Sheet — Regulatory liabilities (long-term)	(0.6		)	0.3			0.3
Natural gas	Income Statement — Cost of sales	—			—			0.2
Natural gas	Income Statement — Operating and maintenance expense	(0.8		)	0.1			—
FTRs	Balance Sheet — Regulatory assets (current)	—			0.2			(0.1		)
FTRs	Balance Sheet — Regulatory liabilities (current)	0.4			(0.3		)	—
Petroleum	Balance Sheet — Regulatory assets (current)	(1.1		)	—			0.1
Petroleum	Balance Sheet — Regulatory liabilities (current)	(0.1		)	0.1			—
Petroleum	Income Statement — Operating and maintenance expense	(1.7		)	0.1			—
Coal	Balance Sheet — Regulatory assets (current)	(1.3		)	(0.9		)	(2.2		)
Coal	Balance Sheet — Regulatory assets (long-term)	—			3.5			0.1
Coal	Balance Sheet — Regulatory liabilities (current)	(0.2		)	(0.2		)	0.3
Coal	Balance Sheet — Regulatory liabilities (long-term)	(0.1		)	(2.0		)	2.2

Holding Company and Other Segment

Cash Flow Hedges

In May 2010, we entered into interest rate swaps that were designated as cash flow hedges to hedge the variability in forecasted interest payments on a debt issuance. These swaps were terminated when the related debt was issued in November 2010. Amounts remaining in accumulated OCI were being reclassified to interest expense over the life of the related debt.

	Loss Reclassified from Accumulated OCI into Income (Effective Portion)
(Millions)	Income Statement Presentation	2014			2013			2012
Settled/Realized
Interest rate swaps	Interest expense	$	(1.1	)	$	(1.1	)	$	(1.1	)

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Note 7—Property, Plant, and Equipment

Property, plant, and equipment consisted of the following utility, nonutility, and nonregulated assets at December 31:

(Millions)	2014		2013
Electric utility	$	3,587.4	$	3,289.2
Natural gas utility	5,811.8		5,428.5
Total utility property, plant, and equipment	9,399.2		8,717.7
Less: Accumulated depreciation	3,185.9		3,073.2
Net	6,213.3		5,644.5
Construction work in progress	351.8		351.5
Plant to be retired, net *	12.5		14.4
Net utility property, plant, and equipment	6,577.6		6,010.4
Nonutility plant	144.6		131.1
Less: Accumulated depreciation	81.1		80.4
Net	63.5		50.7
Construction work in progress	73.9		38.0
Net nonutility property, plant, and equipment	137.4		88.7
PDI energy assets	140.2		109.8
Other nonregulated	33.7		20.7
Total nonregulated property, plant, and equipment	173.9		130.5
Less: Accumulated depreciation	39.5		30.5
Net	134.4		100.0
Construction work in progress	10.4		7.1
Net nonregulated property, plant, and equipment	144.8		107.1
Total property, plant, and equipment	$	6,859.8	$	6,206.2

*In connection with the WPS Consent Decree with the EPA, WPS announced that the Weston 1, Pulliam 5, and Pulliam 6 generating units will be retired early. These units are currently included in rate base, and WPS continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW. The amount presented above is net of accumulated depreciation. See Note 17, Commitments and Contingencies, for more information regarding the Consent Decree.

We evaluate property, plant, and equipment for impairment whenever indicators of impairment exist. See Note 4, Dispositions, for impairment losses recorded in discontinued operations at the holding company and other segment during 2012. The impairments were recorded on property and equipment either sold during 2012 or presented on the balance sheet as assets held for sale.

Note 8—Jointly Owned Utility Facilities

WPS holds a joint ownership interest in certain electric generating facilities. WPS is entitled to its share of generating capability and output of each facility equal to its respective ownership interest. WPS also pays its ownership share of additional construction costs, fuel inventory purchases, and operating expenses, unless specific agreements have been executed to limit its maximum exposure to additional costs. WPS records its proportionate share of significant jointly owned electric generating facilities as property, plant, and equipment on the balance sheets. The amounts were as follows at December 31, 2014:

(Millions, except for percentages and megawatts)	Weston 4			Columbia Energy Center Units 1 and 2			Edgewater Unit 4
Ownership	70.0		%	31.8		%	31.8		%
WPS’s share of rated capacity (megawatts)	374.5			335.2			105.0
In-service date	2008			1975 and 1978			1969
Utility plant	$	581.9		$	390.7		$	42.9
Accumulated depreciation	$	(132.6	)	$	(116.2	)	$	(29.6	)
Construction work in progress	$	2.7		$	10.1		$	0.7

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WPS’s proportionate share of direct expenses for the joint operation of these plants is recorded in operating expenses in the income statements. WPS has supplied its own financing for all jointly owned projects.

Note 9—Regulatory Assets and Liabilities

The following regulatory assets were reflected on our balance sheets as of December 31:

(Millions)	2014		2013		See Note
Regulatory assets (1) (2)
Environmental remediation costs (net of insurance recoveries) (3)	$	635.8	$	652.1	17
Unrecognized pension and other postretirement benefit costs (4)	513.1		382.6		18
Asset retirement obligations	109.4		89.0		15
Merger and acquisition-related pension and other postretirement benefit costs (5)	86.6		98.3
Income tax related items	60.6		55.3		16
Derivatives	55.2		11.7		1(h)
Termination of a tolling agreement with Fox Energy Company LLC	44.6		50.0		3
Crane Creek production tax credits (6)	32.2		33.6
Energy costs recoverable through rate adjustments (7)	22.2		17.0
De Pere Energy Center (8)	21.4		23.8
Unamortized loss on reacquired debt (9)	16.6		16.2		1(o)
Uncollectible expense (10)	13.6		4.7
Energy efficiency programs (11)	2.8		16.8
Pension and other postretirement costs recoverable through rate adjustments (12)	—		9.4		25
Decoupling	—		8.6		25
Other	18.4		19.7
Total regulatory assets	$	1,632.5	$	1,488.8
Balance Sheet Presentation
Current assets	$	118.9	$	127.4
Long-term assets	1,513.6		1,361.4
Total regulatory assets	$	1,632.5	$	1,488.8

(1)Based on prior and current rate treatment, we believe it is probable that our utility subsidiaries will continue to recover from customers the regulatory assets described above.

(2)The following regulatory assets are not earning a return: environmental remediation costs at WPS; unrecognized pension and other postretirement benefit costs at MERC, NSG, and PGL; asset retirement obligations, derivatives, and uncollectible expense at all utilities; merger and acquisition-related pension and other postretirement benefit costs at NSG and PGL; natural gas costs recoverable through rate adjustments at MERC and WPS; unamortized loss on reacquired debt at NSG and PGL; energy efficiency programs at WPS; pension and other postretirement costs recoverable through rate adjustments at WPS; and decoupling at MGU. However, these regulatory assets are expected to be recovered from customers in future rates.

(3)As of December 31, 2014, we had not yet made cash expenditures for $579.9 million of these environmental remediation costs. The recovery of these costs depends on the timing of the actual expenditures.

(4)Represents the unrecognized future pension and other postretirement costs resulting from actuarial gains and losses on defined benefit and other postretirement plans. We are authorized recovery of this regulatory asset over the average future remaining service life of each plan.

(5)Composed of unrecognized benefit costs that existed prior to the PELLC merger and the MERC and MGU acquisitions. MERC and MGU are authorized recovery of this regulatory asset through 2026. PGL and NSG are authorized recovery of the pension portion of this regulatory asset through 2023, and they are authorized recovery of the other postretirement benefit portion through 2019.

(6)In 2012, WPS elected to claim and subsequently received a Section 1603 Grant for the Crane Creek wind project in lieu of the production tax credit. As a result, WPS reversed previously recorded production tax credits. WPS also reduced the depreciable basis of the qualifying facility by the amount of the grant proceeds, which will result in a reduction of depreciation and amortization expense over a 12-year period. WPS recorded a regulatory asset for the deferral of previously recorded production tax credits and is authorized recovery of this net regulatory asset through 2039.

(7)Represents the under-collection of energy costs that will be recovered from customers in the future.

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(8)Prior to WPS purchasing the De Pere Energy Center in 2002, WPS had a long-term power purchase contract with them that was accounted for as a capital lease. As a result of the purchase, the capital lease obligation was reversed, and the difference between the capital lease asset and the purchase price was recorded as a regulatory asset. WPS is authorized recovery of this regulatory asset through 2023.

(9)Amounts are recovered over the term of the replacement debt for NSG and PGL as authorized by the ICC.

(10)Represents amounts recoverable from customers related to uncollectible expense. We are allowed to recover or refund the difference between the rate case authorized uncollectible expense and the actual uncollectible write-offs reported to the applicable commissions each year.

(11)Represents amounts recoverable from customers related to programs at the utility subsidiaries designed to meet energy efficiency standards.

(12)Represents the under-collection of pension and other postretirement costs that will be recovered from customers in the future.

The following regulatory liabilities were reflected on our balance sheets as of December 31:

(Millions)	2014		2013		See Note
Regulatory liabilities
Removal costs (1)	$	334.0	$	318.0
Decoupling	49.4		51.5		25
Unrecognized pension and other postretirement benefit costs (2)	45.2		30.2		18
Energy costs refundable through rate adjustments (3)	44.8		27.1
Energy efficiency programs (4)	21.3		19.6
Derivatives	19.8		6.6		1(h)
Uncollectible expense	15.7		10.1		25
Crane Creek depreciation deferral (5)	8.7		9.0
Fox Energy Center (6)	4.6		5.6		3
Other	10.1		7.1
Total regulatory liabilities	$	553.6	$	484.8
Balance Sheet Presentation
Current liabilities	$	153.7	$	101.1
Long-term liabilities	399.9		383.7
Total regulatory liabilities	$	553.6	$	484.8

(1)Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment.

(2)Represents the unrecognized future other postretirement benefit costs resulting from actuarial gains on other postretirement benefit plans. We will amortize this regulatory liability into net periodic benefit cost over the average remaining service life of each plan.

(3)Represents the over-collection of energy costs that will be refunded to customers in the future.

(4)Represents amounts refundable to customers related to programs at the utility subsidiaries designed to meet energy efficiency standards.

(5)Represents the book depreciation taken on the Crane Creek wind project prior to WPS’s election to claim a Section 1603 Grant for the project in lieu of the production tax credit. See more information in the regulatory assets section above.

(6)Represents the deferral of incremental costs associated with WPS owning and operating the Fox Energy Center, which was purchased in March 2013. In accordance with GAAP, the deferral does not include an allowance for return on equity, which has created the net regulatory liability. This allowance was $22.8 million and $22.1 million, at December 31, 2014, and 2013, respectively.

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Note 10—Equity Method Investments

Investments in corporate joint ventures and other companies accounted for under the equity method at December 31, 2014, and 2013, were as follows:

(Millions)	2014		2013
ATC	$	536.7	$	508.4
INDU Solar Holdings, LLC	21.8		24.7
WRPC	7.7		7.0
AMP Trillium, LLC	5.5		—
Other	0.7		0.8
Equity method investments	$	572.4	$	540.9

ATC

Our electric transmission investment segment consists of WPS Investments LLC’s ownership interest in ATC, which was approximately 34% at December 31, 2014. ATC is a for-profit, transmission-only company regulated by FERC.

The following table shows changes to our investment in ATC during the years ended December 31:

(Millions)	2014		2013		2012
Balance at the beginning of period	$	508.4	$	476.6	$	439.4
Add: Earnings from equity method investment	85.7		89.1		85.3
Add: Capital contributions	17.0		13.7		20.4
Less: Dividends received	74.4		71.0		68.5
Balance at the end of period	$	536.7	$	508.4	$	476.6

ATC is currently named in a complaint filed with the FERC requesting a reduction in the base return on equity (ROE) used by MISO transmission owners to 9.15%. ATC’s current authorized ROE is 12.2%. Although we are currently unable to determine how the FERC may rule in this complaint, we believe it is probable that a refund will be required upon resolution of this issue, based on rulings in a similar complaint. As a result, our equity earnings and corresponding equity method investment in ATC reflected an estimated $6.6 million reduction during 2014.

The electric utilities provide construction and other services to ATC and receive network transmission services from ATC. The related party transactions recorded by the electric utilities during the years ended December 31 were as follows:

(Millions)	2014		2013		2012
Total charges to ATC for services and construction	$	9.9	$	11.3	$	12.5
Total costs for network transmission services provided by ATC	103.8		104.9		100.3

INDU Solar Holdings, LLC

Integrys Solar, LLC, a subsidiary of PDI, owns 50% of INDU Solar Holdings, LLC. INDU Solar Holdings, LLC owns solar energy projects in California, Pennsylvania, New Jersey, Arizona, and Massachusetts that deliver electricity and related products to commercial, government, and utility customers under long-term power purchase agreements.

The following table shows changes to our investment in INDU Solar Holdings, LLC during the years ended December 31:

(Millions)	2014		2013		2012
Balance at the beginning of period	$	24.7	$	27.5	$	28.4
Add: Earnings from equity method investment	1.8		1.3		1.1
Add: Capital contributions	—		—		7.0
Less: Return of capital to partners	4.7		4.1		9.0
Balance at the end of period	$	21.8	$	24.7	$	27.5

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WRPC

WPS owns 50% of the stock of WRPC, which owns two hydroelectric plants and an oil-fired combustion turbine. Half of the energy output of the hydroelectric plants is sold to WPS, and half is sold to Wisconsin Power and Light. The electric power from the combustion turbine is also sold in equal parts to WPS and Wisconsin Power and Light.

The following table shows changes to our investment in WRPC during the years ended December 31:

(Millions)	2014		2013		2012
Balance at the beginning of period	$	7.0	$	7.3	$	7.7
Add: Earnings from equity method investment	0.8		1.0		0.8
Add: Capital contributions	0.5		—		—
Less: Dividends received	0.6		1.3		1.2
Balance at the end of period	$	7.7	$	7.0	$	7.3

WPS provides services to WRPC, purchases energy from WRPC, and receives net proceeds from sales of energy into the MISO market from WRPC. The related party transactions recorded by WPS during the years ended December 31 were as follows:

(Millions)	2014		2013		2012
Charges to WRPC for operations	$	1.4	$	0.9	$	0.8
Purchases of energy from WRPC	3.7		3.7		5.0
Net proceeds from WRPC sales of energy to MISO	—		—		2.9

AMP Trillium, LLC

AMP Trillium, LLC is a joint venture between ITF and AMP Americas, LLC. ITF owns 30% and AMP Americas, LLC owns 70% of this joint venture. AMP Trillium, LLC owns and operates compressed natural gas (CNG) fueling stations. In April 2014, ITF and AMP Americas, LLC restructured this joint venture. Prior to the restructuring, we consolidated AMP Trillium, LLC. However, due to the restructuring, we started accounting for AMP Trillium, LLC as an equity method investment in April 2014. See Note 27, Variable Interest Entities, for more information.

The following table shows changes to our investment in AMP Trillium, LLC during the year ended December 31:

(Millions)	2014
Balance at the beginning of period	$	—
Add: Capital contributions	5.5
Balance at the end of period	$	5.5

ITF sells CNG fueling stations to AMP Trillium, LLC and provides financial support to AMP Trillium, LLC through loans. At December 31, 2014, ITF had $13.8 million of notes receivable due from AMP Trillium, LLC. During 2014, ITF recorded $3.1 million of net proceeds from the sale of CNG fueling stations to AMP Trillium, LLC.

Financial Data

Combined financial data of our significant equity method investments, ATC, INDU Solar Holdings, LLC, WRPC, and AMP Trillium, LLC, are included in the tables below:

(Millions)	2014		2013		2012
Income statement data
Revenues	$	655.6	$	642.0	$	618.3
Operating expenses	323.5		306.2		292.1
Other expense	88.4		83.7		85.1
Net income	$	243.7	$	252.1	$	241.1
Earnings from equity method investments	$	88.3	$	91.4	$	87.2

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(Millions)	December 31, 2014		December 31, 2013
Balance sheet data
Current assets	$	80.7	$	90.2
Noncurrent assets	3,835.9		3,587.2
Total assets	$	3,916.6	$	3,677.4
Current liabilities	$	324.0	$	383.6
Long-term debt	1,721.6		1,559.1
Other noncurrent liabilities	173.2		134.4
Shareholders’ equity	1,697.8		1,600.3
Total liabilities and shareholders’ equity	$	3,916.6	$	3,677.4

Note 11—Goodwill and Other Intangible Assets

The following table shows changes to our goodwill balances by segment during the years ended December 31, 2014, and 2013:

	Natural Gas Utility						Holding Company and Other				Total
(Millions)	2014			2013			2014		2013		2014			2013
Balance as of January 1
Gross goodwill	$	933.5		$	933.5		$	19.6	$	15.8	$	953.1		$	949.3
Accumulated impairment losses	(297.7		)	(297.7		)	—		—		(297.7		)	(297.7		)
Net goodwill as of January 1	635.8			635.8			19.6		15.8		655.4			651.6
Adjustment to ITF intellectual property *	—			—			—		3.8		—			3.8
Balance as of December 31
Gross goodwill	933.5			933.5			19.6		19.6		953.1			953.1
Accumulated impairment losses	(297.7		)	(297.7		)	—		—		(297.7		)	(297.7		)
Net goodwill as of December 31	$	635.8		$	635.8		$	19.6	$	19.6	$	655.4		$	655.4

*An immaterial adjustment was made to the gross goodwill balance at ITF in the second quarter of 2013 due to a correction to the life of certain intangible assets.

In the second quarter of 2014, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of April 1, 2014. No impairments resulted from these tests.

The identifiable intangible assets other than goodwill listed below are part of other long-term assets on the balance sheets.

	December 31, 2014							December 31, 2013
(Millions)	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Amortized intangible assets
Contractual service agreements (1)	$	15.6	$	(4.3	)	$	11.3	$	15.6	$	(1.8	)	$	13.8
Customer-owned equipment modifications (2)	4.0		(1.2		)	2.8		4.0		(0.9		)	3.1
Intellectual property (3)	3.4		(0.8		)	2.6		3.4		(0.5		)	2.9
Nonregulated easements (4)	3.9		(1.4		)	2.5		3.7		(1.1		)	2.6
Compressed natural gas fueling contract assets (5)	5.6		(3.6		)	2.0		5.6		(2.7		)	2.9
Customer-related (6)	1.9		(0.3		)	1.6		1.9		(0.1		)	1.8
Other	0.5		(0.3		)	0.2		0.5		(0.3		)	0.2
Total	$	34.9	$	(11.9	)	$	23.0	$	34.7	$	(7.4	)	$	27.3
Unamortized intangible assets
MGU trade name	$	5.2	$	—		$	5.2	$	5.2	$	—		$	5.2
Trillium trade name (7)	3.5		—			3.5		3.5		—			3.5
Pinnacle trade name (7)	1.5		—			1.5		1.5		—			1.5
Total intangible assets	$	45.1	$	(11.9	)	$	33.2	$	44.9	$	(7.4	)	$	37.5

(1)Represents contractual service agreements that provide for major maintenance and protection against unforeseen maintenance costs related to the combustion turbine generators at the Fox Energy Center. In October 2014, WPS received approval from the PSCW to upgrade the combustion turbine generators at the Fox Energy Center earlier than planned. As a result of this approval, WPS shortened the amortization period of one of its service agreements. The remaining

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weighted-average amortization period for these intangible assets at December 31, 2014, was approximately four years. Since WPS has approval from the PSCW to recover the value of its service agreements from customers over seven years, the increase in amortization due to the shorter amortization period is recorded to a regulatory asset. This regulatory asset will be amortized to reflect the seven-year recovery period.

(2)Relates to modifications made by PDI and ITF to customer-owned equipment. These intangible assets are amortized on a straight-line basis, with a remaining weighted-average amortization period at December 31, 2014, of approximately nine years.

(3)Represents the fair value of intellectual property at ITF related to a system for more efficiently compressing natural gas to allow for faster fueling. An immaterial adjustment was made to the intangible assets balance in the second quarter of 2013 as a result of a correction to the life of the intangible assets. The remaining amortization period at December 31, 2014, was approximately eight years.

(4)Relates to easements supporting a pipeline at PDI. The easements are amortized on a straight-line basis, with a remaining amortization period at December 31, 2014, of approximately nine years.

(5)Represents the fair value of ITF contracts acquired in September 2011. The remaining amortization period at December 31, 2014, was approximately six years.

(6)Represents customer relationship assets associated with ITF’s compressed natural gas fueling operations. The remaining weighted-average amortization period for customer-related intangible assets at December 31, 2014, was approximately 12 years.

(7)Trillium USA (Trillium) and Pinnacle CNG Systems (Pinnacle) are wholly owned subsidiaries of ITF.

The table below shows the amortization recorded during the years ended December 31:

(Millions)	2014		2013		2012
Amortization recorded in cost of sales	$	1.2	$	1.6	$	1.3
Amortization recorded in depreciation and amortization expense	3.0		2.5		1.0
Amortization recorded in regulatory assets	0.3		—		—

Amortization for the next five years is estimated to be:

	For the Year Ending December 31
(Millions)	2015		2016		2017		2018		2019
Amortization to be recorded in cost of sales	$	1.1	$	0.9	$	0.9	$	0.8	$	0.6
Amortization to be recorded in depreciation and amortization expense	3.0		2.9		2.4		1.9		1.9
Amortization to be recorded in regulatory assets	1.0		1.0		0.5		—		—

Note 12—Leases

We lease various property, plant, and equipment. Terms of the operating leases vary, but generally require us to pay property taxes, insurance premiums, and maintenance costs associated with the leased property. Many of our leases contain one of the following options upon the end of the lease term: (a) purchase the property at the current fair market value or (b) exercise a renewal option, as set forth in the lease agreement. Rental expense attributable to operating leases was $14.7 million, $11.2 million, and $11.0 million in 2014, 2013, and 2012, respectively. Future minimum rental obligations under noncancelable operating leases are payable as follows:

Year Ending December 31 (Millions)	Payments
2015	$	4.7
2016	5.0
2017	5.8
2018	5.6
2019	4.7
Later years	47.6
Total	$	73.4

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Note 13—Short-Term Debt and Lines of Credit

Our outstanding short-term borrowings were as follows:

(Millions, except percentages)	2014			2013			2012
Commercial paper
Amount outstanding at December 31 (1)	$	317.6		$	326.0		$	482.4
Average interest rate on amount outstanding at December 31	0.36		%	0.22		%	0.40		%
Average amount outstanding during the year (2)	$	283.0		$	378.4		$	326.3
Short-term notes payable (3)
Average amount outstanding during the year (2)	$	—		$	130.4	(4)	$	—

(1)Maturity dates ranged from January 2, 2015, through January 16, 2015.

(2)Based on daily outstanding balances during the year.

(3)We did not have short-term notes payable outstanding at December 31, 2014, 2013, and 2012.

(4)Average amount outstanding of a $200.0 million loan used for the purchase of Fox Energy Company LLC. This loan was repaid in November 2013. See Note 3, Acquisitions, for more information regarding this purchase.

We manage our liquidity by maintaining adequate external financing commitments. The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing program, including remaining available capacity under these facilities as of December 31:

(Millions)	Maturity	2014		2013
Revolving credit facility (Integrys Energy Group) (1)	05/17/2014	$	—	$	275.0
Revolving credit facility (Integrys Energy Group) (1)	05/17/2016	—		200.0
Revolving credit facility (Integrys Energy Group) (2)	06/13/2017	285.0		635.0
Revolving credit facility (Integrys Energy Group)	05/08/2019	465.0		—
Revolving credit facility (WPS) (1)	05/17/2014	—		135.0
Revolving credit facility (WPS) (3)	05/07/2015	135.0		—
Revolving credit facility (WPS)	06/13/2017	115.0		115.0
Revolving credit facility (PGL)	06/13/2017	250.0		250.0
Total short-term credit capacity		$	1,250.0	$	1,610.0
Less:
Letters of credit issued inside credit facilities		$	3.4	$	52.4
Commercial paper outstanding		317.6		326.0
Available capacity under existing agreements		$	929.0	$	1,231.6

(1)These credit facilities were terminated and replaced with new credit facilities in May 2014.

(2)This credit facility was reduced by $350 million during the fourth quarter of 2014 due to the sale of IES.

(3)We requested approval from the PSCW to extend this facility through May 8, 2019.

Our revolving credit agreements and those of certain of our subsidiaries contain financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%, excluding non-recourse debt. Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations.

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Note 14—Long-Term Debt

				December 31
(Millions)				2014			2013
WPS First Mortgage Bonds (1)
	Series	Year Due
	7.125%	2023		$	0.1		$	0.1
WPS Senior Notes (1)
	Series	Year Due
	6.375%	2015		125.0			125.0
	5.65%	2017		125.0			125.0
	6.08%	2028		50.0			50.0
	5.55%	2036		125.0			125.0
	3.671%	2042		300.0			300.0
	4.752%	2044		450.0			450.0
PGL First and Refunding Mortgage Bonds (2)
	Series	Year Due
	QQ, 4.875%	2038	Mandatory interest reset date on November 1, 2018	—			75.0
	RR, 4.30%	2035	Mandatory interest reset date on June 1, 2016	50.0			50.0
	TT, 8.00%	2018		5.0			5.0
	UU, 4.63%	2019		75.0			75.0
	VV, 3.90%	2030		50.0			50.0
	WW, 2.625%	2033	Mandatory interest reset date on August 1, 2015	50.0			50.0
	XX, 2.21%	2016		50.0			50.0
	YY, 3.98%	2042		100.0			100.0
	ZZ, 4.00%	2033		50.0			50.0
	AAA, 3.96%	2043		220.0			220.0
	BBB, 4.21%	2044		200.0			—
NSG First Mortgage Bonds (3)
	Series	Year Due
	P, 3.43%	2027		28.0			28.0
	Q, 3.96%	2043		54.0			54.0
Integrys Energy Group Unsecured Senior Notes (4)
	Series	Year Due
	7.27%	2014		—			100.0
	8.00%	2016		55.0			55.0
	4.17%	2020		250.0			250.0
Integrys Energy Group Unsecured Junior Subordinated Notes (5)
	Series	Year Due
	6.11%	2066	Interest to become variable on December 1, 2016	269.8			269.8
	6.00%	2073	Mandatory interest reset date on August 1, 2023	400.0			400.0
Total				3,081.9			3,056.9
Unamortized discount on debt				(0.6		)	(0.7		)
Total debt				3,081.3			3,056.2
Less current portion				125.0			100.0
Total long-term debt				$	2,956.3		$	2,956.2

(1)WPS’s First Mortgage Bonds and Senior Notes are subject to the terms and conditions of WPS’s First Mortgage Indenture dated January 1, 1941, as supplemented. Under the terms of the Indenture, substantially all property owned by WPS is pledged as collateral for these outstanding debt securities. All of these debt securities require semi-annual payments of interest. WPS Senior Notes become noncollateralized if WPS retires all of its outstanding First Mortgage Bonds and no new mortgage indenture is put in place.

In December 2015, our 6.375% Senior Notes will mature. As a result, the $125 million balance of these notes was included in the current portion of long-term debt on our balance sheet at December 31, 2014.

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(2)PGL’s First Mortgage Bonds are subject to the terms and conditions of PGL’s First Mortgage Indenture dated January 2, 1926, as supplemented. Under the terms of the Indenture, substantially all property owned by PGL is pledged as collateral for these outstanding debt securities.

PGL has used certain First Mortgage Bonds to secure tax exempt interest rates. The Illinois Finance Authority has issued Tax Exempt Bonds, and the proceeds from the sale of these bonds were loaned to PGL. In return, PGL issued equal principal amounts of certain collateralized First Mortgage Bonds.

In November 2014, PGL issued $200.0 million of 4.21% Series BBB Bonds. These bonds are due in November 2044. A portion of the proceeds was used to redeem PGL’s $75.0 million 4.875% Series QQ Bonds.

(3)NSG’s First Mortgage Bonds are subject to the terms and conditions of NSG’s First Mortgage Indenture dated April 1, 1955, as supplemented. Under the terms of the Indenture, substantially all property owned by NSG is pledged as collateral for these outstanding debt securities.

(4)In June 2014, our $100.0 million of 7.27% Unsecured Senior Notes matured, and the outstanding principal balance was repaid.

(5)The 6.11% Junior Subordinated Notes are considered hybrid instruments with a combination of debt and equity characteristics. Under a replacement capital covenant with the holders of our 4.17% Unsecured Senior Notes due November 1, 2020, prior to December 1, 2036, any amounts redeemed or repurchased in excess of 10% of the principal amount outstanding must first be replaced with a specified amount of proceeds from the sale of qualifying securities that have equity-like characteristics that are the same as, or more equity-like than, the applicable characteristics of the 6.11% Junior Subordinated Notes.

The 6.00% Junior Subordinated Notes are considered hybrid instruments with a combination of debt and equity characteristics. There is no replacement capital covenant associated with these securities.

Our long-term debt obligations, and those of certain of our subsidiaries, contain covenants related to payment of principal and interest when due and various financial reporting obligations. In addition, certain long-term debt obligations contain financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%. Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations.

A schedule of all principal debt payment amounts related to bond maturities is as follows:

(Millions)	Payments
2015	$	125.0
2016	105.0
2017	125.0
2018	5.0
2019	75.0
Later years	2,646.9
Total	$	3,081.9

Note 15—Asset Retirement Obligations

The utility segments have asset retirement obligations primarily related to removal of natural gas distribution mains and service pipes (including asbestos and PCBs); asbestos abatement at certain generation facilities, office buildings, and service centers; dismantling wind generation projects; disposal of PCB-contaminated transformers; closure of fly-ash landfills at certain generation facilities; and removal of above ground storage tanks. The utilities establish regulatory assets and liabilities to record the differences between ongoing expense recognition under the asset retirement obligation accounting rules and the ratemaking practices for retirement costs authorized by the applicable regulators. PDI has asset retirement obligations related to the removal of solar equipment components.

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The following table shows changes to our asset retirement obligations through December 31, 2014:

(Millions)	Utilities			PDI		Total
Asset retirement obligations at December 31, 2011	$	395.8		$	0.5	$	396.3
Accretion	20.3			0.1		20.4
Additions and revisions to estimated cash flows	(2.3		)	1.6		(0.7		)
Settlements	(5.4		)	—		(5.4		)
Asset retirement obligations at December 31, 2012	408.4			2.2		410.6
Accretion	20.8			0.1		20.9
Additions and revisions to estimated cash flows	70.1		*	0.5		70.6
Settlements	(11.1		)	—		(11.1		)
Asset retirement obligations at December 31, 2013	488.2			2.8		491.0
Accretion	24.5			0.1		24.6
Additions and revisions to estimated cash flows	(18.3		)*	0.7		(17.6		)
Settlements	(17.8		)	—		(17.8		)
Asset retirement obligations at December 31, 2014	$	476.6		$	3.6	$	480.2

*Revisions were made to estimated cash flows related to asset retirement obligations primarily due to changes in the weighted average cost to retire natural gas distribution pipe at PGL.

Note 16—Income Taxes

Deferred Income Tax Assets and Liabilities

The principal components of deferred income tax assets and liabilities recognized on the balance sheets as of December 31 are included in the table below. Certain temporary differences are netted in the table when the offsetting amount is recorded as a regulatory asset or liability. This is consistent with regulatory treatment.

(Millions)	2014			2013
Deferred income tax assets
Tax credit carryforwards	$	116.7		$	113.5
Price risk management	—			13.0
Other	77.4			98.5
Total deferred income tax assets	$	194.1		$	225.0
Valuation allowance	(3.6		)	(8.2		)
Net deferred income tax assets	$	190.5		$	216.8
Deferred income tax liabilities
Plant-related	$	1,584.1		$	1,373.8
Regulatory deferrals	55.6			78.8
Employee benefits	45.4			79.6
Other	23.0			43.5
Total deferred income tax liabilities	$	1,708.1		$	1,575.7
Total net deferred income tax liabilities	$	1,517.6		$	1,358.9
Balance sheet presentation
Current deferred income tax assets	$	52.4		$	31.4
Long-term deferred income tax liabilities	1,570.0			1,390.3
Net deferred income tax liabilities	$	1,517.6		$	1,358.9

Deferred tax credit carryforwards at December 31, 2014, included $73.9 million of alternative minimum tax credits, which can be carried forward indefinitely. Other deferred tax credit carryforwards included $32.5 million of general business credits, which have a carryback period of one year and a carryforward period of 20 years. The majority of the general business credit carryforwards will expire in 2034. Deferred tax credit carryforwards also included $6.2 million of foreign tax credits, which have a carryback period of

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one year and a carryforward period of 10 years. The majority of the foreign tax credit carryforwards will expire in 2019. We also had $4.2 million of deferred state tax credit carryforwards, which have a carryforward period of five years. The majority of the state tax credit carryforwards will expire in 2018.

At December 31, 2014, we had deferred income tax assets of $27.0 million reflecting federal operating loss carryforwards, which have a carryback period of two years and a carryforward period of 20 years. We also had deferred income tax assets of $19.2 million reflecting net state operating loss carryforwards. The majority of the state operating loss carryforwards relate to Wisconsin and have a carryforward period of 20 years. Any deferred tax assets that are not used to offset future taxable income will expire between 2020 and 2033 as follows:

(Millions)
2020 through 2025	$	7.6
2026 through 2031	2.9
2032 through 2033	35.7

Valuation allowances are established for certain state operating losses based on our projected ability to realize these benefits by offsetting future taxable income. Realization is dependent on generating sufficient taxable income prior to expiration. As of December 31, 2014, the entire valuation allowance was related to noncurrent deferred income tax assets. The valuation allowance was reduced by $4.6 million in 2014 due to a foreign tax deduction.

Our utilities record certain adjustments related to deferred income taxes to regulatory assets and liabilities. As the related temporary differences reverse, the utilities prospectively refund taxes to, or collect taxes from, customers for which deferred taxes were recorded in prior years at rates potentially different than current rates or upon enactment of changes in tax law. The net regulatory asset for these net recoveries and other regulatory tax effects totaled $58.8 million and $51.6 million at December 31, 2014, and 2013, respectively. See Note 9, Regulatory Assets and Liabilities, for more information.

Income Before Taxes

All income before taxes is domestic income for the years ended December 31, 2014, 2013, and 2012.

Provision for Income Taxes

The components of the provision for income taxes were as follows:

(Millions)	2014			2013			2012
Current provision
Federal	$	19.9		$	1.6		$	(17.4	)
State	25.2			4.7			(1.7		)
Total current provision	45.1			6.3			(19.1		)
Deferred provision
Federal	123.0			134.1			119.8
State	18.7			9.9			17.9
Total deferred provision	141.7			144.0			137.7
Investment tax credits
Deferral	13.2			12.3			17.8
Amortization	(5.2		)	(4.0		)	(12.6		)
Penalties	—			(0.1		)	(0.3		)
Unrecognized tax benefits	0.7			0.4			(2.9		)
Interest	(2.1		)	(0.9		)	(2.7		)
Total provision for income taxes related to continuing operations	193.4			158.0			117.9
Total provision for income taxes related to discontinued operations	7.2			45.9			22.6
Total	$	200.6		$	203.9		$	140.5

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Statutory Rate Reconciliation

The following table presents a reconciliation of the difference between the effective tax rate and the amount computed by applying the statutory federal tax rate to income from continuing operations before taxes.

	2014					2013					2012
(Millions, except for percentages)	Rate		Amount			Rate		Amount			Rate		Amount
Statutory federal income tax	35.0	%	$	165.0		35.0	%	$	148.9		35.0	%	$	124.9
State income taxes, net	7.5	*	35.5		*	3.7		15.9			4.9		17.6
Benefits and compensation	(0.9	)	(4.3		)	(1.0	)	(4.1		)	(2.6	)	(9.3		)
Other differences, net	(0.6	)	(2.8		)	(0.6	)	(2.7		)	(4.3	)	(15.3		)
Effective income tax	41.0	%	$	193.4		37.1	%	$	158.0		33.0	%	$	117.9

*Includes the impact of a $13.0 million expense caused by the remeasurement of deferred taxes related to the sale of IES’s retail energy business.

With the exception of 2014, income taxes on discontinued operations are recorded at rates that are not materially different from the applicable statutory rates. In 2014, the rate varied from the applicable statutory rates primarily because of the impairment of nondeductible goodwill related to IES’s retail energy business.

Unrecognized Tax Benefits

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

(Millions)	2014			2013			2012
Balance at January 1	$	3.6		$	11.3		$	22.4
Increase related to tax positions taken in prior years	—			2.2			0.9
Decrease related to tax positions taken in prior years	(0.1		)	(8.7		)	(6.7		)
Increase related to tax positions taken in current year	0.5			0.3			0.6
Decrease related to settlements	—			(1.5		)	(5.7		)
Decrease related to lapse of statutes	(0.7		)	—			(0.2		)
Balance at December 31	$	3.3		$	3.6		$	11.3

We had accrued interest of $0.3 million and accrued penalties of $0.2 million related to unrecognized tax benefits at December 31, 2014. We had accrued interest of $0.8 million and accrued penalties of $0.4 million related to unrecognized tax benefits at December 31, 2013.

Our effective tax rate could be affected by recognition of $2.2 million of unrecognized tax benefits related to continuing operations in periods after December 31, 2014.

Our subsidiaries file income tax returns in the United States federal jurisdiction, in various state and local jurisdictions, and in Canada.

With a few exceptions, we are no longer subject to federal income tax examinations by the IRS for years prior to 2011.

We file state tax returns based on income in our major state operating jurisdictions of Wisconsin, Illinois, Michigan, and Minnesota. We also file tax returns in other state and local jurisdictions with varying statutes of limitations. With a few exceptions, we are no longer subject to state and local tax examinations for years prior to 2008. As of December 31, 2014, we were subject to examination by state or local tax authorities for the 2008 through 2013 tax years in our major state operating jurisdictions as follows:

State	Year
Illinois	2008
Michigan	2008
Minnesota	2011
Wisconsin	2010

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During 2014, the Michigan taxing authority continued its examination of the 2008 through 2011 tax years and the Illinois taxing authority initiated its examination of the 2008 through 2010 tax years.

As of December 31, 2014, we were subject to examination by foreign income tax authorities for the 2009 through 2013 tax years. With a few exceptions, we are no longer subject to foreign income tax examinations by tax authorities for years prior to 2009.

In the next 12 months, it is reasonably possible that we and our subsidiaries will settle open examinations in multiple taxing jurisdictions related to tax years prior to 2012, resulting in a decrease in unrecognized tax benefits of up to $1.3 million.

Note 17—Commitments and Contingencies

(a) Unconditional Purchase Obligations

We and our subsidiaries routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. The natural gas utilities have obligations to distribute and sell natural gas to their customers, and our electric utility has obligations to distribute and sell electricity to its customers. The utilities expect to recover costs related to these obligations in future customer rates.

The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2014, including those of our subsidiaries.

				Payments Due By Period
(Millions)	Date Contracts Extend Through	Total Amounts Committed		2015		2016		2017		2018		2019		Later Years
Natural gas utility supply and transportation	2028	$	722.6	$	196.6	$	170.4	$	132.9	$	78.2	$	50.9	$	93.6
Electric utility
Purchased power	2029	836.8		122.8		42.8		53.3		55.9		57.0		505.0
Coal supply and transportation	2019	162.8		55.3		31.9		32.6		31.9		11.1		—
Total		$	1,722.2	$	374.7	$	245.1	$	218.8	$	166.0	$	119.0	$	598.6

(b) Environmental Matters

Air Permitting Violation Claims

Weston and Pulliam Clean Air Act (CAA) Issues:

In November 2009, the EPA issued a Notice of Violation (NOV) to WPS alleging violations of the CAA’s New Source Review requirements relating to certain projects completed at the Weston and Pulliam plants from 1994 to 2009. WPS reached a settlement agreement with the EPA regarding this NOV and signed a Consent Decree. This Consent Decree was approved by the U.S. District Court (Court) in March 2013, after a public comment period. The final Consent Decree includes:

·the installation of emission control technology, including ReACT™ on Weston 3,

·changed operating conditions (including refueling, repowering, and/or retirement of units),

·limitations on plant emissions,

·beneficial environmental projects totaling $6.0 million, and

·a civil penalty of $1.2 million.

As mentioned above, the Consent Decree contains a requirement to refuel, repower, and/or retire certain Weston and Pulliam units. WPS announced that certain Weston and Pulliam units mentioned in the Consent Decree will be retired early, in June 2015. WPS received approval from the PSCW in its 2015 rate order to defer and amortize the undepreciated book value of the retired plant associated with Pulliam 5 and 6 and Weston 1 starting with the actual retirement date in 2015 and concluding when the balance is fully amortized. See Note 7, Property, Plant, and Equipment, for more information.

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WPS received approval from the PSCW in its 2014 and 2015 rate orders to recover prudently incurred costs as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty. We also believe that additional prudently incurred costs expected after 2015 will be recoverable from customers based on past precedent with the PSCW.

The majority of the beneficial environmental projects proposed by WPS have been approved by the EPA. Amounts have been accrued and recorded to regulatory assets, excluding costs associated with capital projects.

In May 2010, WPS received from the Sierra Club a Notice of Intent to file a civil lawsuit based on allegations that WPS violated the CAA at the Weston and Pulliam plants. WPS entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended in October 2012, but no further action has been taken by the Sierra Club as of December 31, 2014. It is unknown whether the Sierra Club will take further action in the future.

Columbia and Edgewater CAA Issues:

In December 2009, the EPA issued an NOV to Wisconsin Power and Light (WP&L), the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric and WPS. The NOV alleges violations of the CAA’s New Source Review requirements related to certain projects completed at those plants. WPS, WP&L, and Madison Gas and Electric reached a settlement agreement with the EPA regarding this NOV and signed a Consent Decree. This Consent Decree was approved by the Court in June 2013, after a public comment period. The final Consent Decree includes:

·the installation of emission control technology, including scrubbers at the Columbia plant,

·changed operating conditions (including refueling, repowering, and/or retirement of units),

·limitations on plant emissions,

·beneficial environmental projects, with WPS’s portion totaling $1.3 million, and

·WPS’s portion of a civil penalty and legal fees totaling $0.4 million.

As mentioned above, the Consent Decree contains a requirement to refuel, repower, and/or retire certain of the Columbia and Edgewater units. As of December 31, 2014, no decision had been made on how to address this requirement. Therefore, retirement of the Columbia and Edgewater units mentioned in the Consent Decree was not considered probable.

We believe that significant costs prudently incurred as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty, will be recoverable from customers.

All of the beneficial environmental projects that WPS proposed have been approved by the EPA. Amounts have been accrued and recorded to regulatory assets, excluding costs associated with capital projects.

Weston Title V Air Permit:

In August 2013, the WDNR issued the Weston Title V air permit. In September 2013, WPS challenged various requirements in the permit by filing a contested case proceeding with the WDNR and also filed a Petition for Judicial Review in the Brown County Circuit Court. The Sierra Club and Clean Wisconsin also challenged various aspects of the permit. The WDNR granted all parties’ requests for contested case proceedings. The Petitions for Judicial Review, by all parties, have been stayed pending the resolution of the contested cases. In February 2014, WPS also requested a modification to the construction permit for Weston 4 to remove the mercury Best Available Control Technology (BACT) emission limit requirement. This permit request was denied by the WDNR and WPS challenged this issue as well. At WPS’s request, the permit was modified to resolve several of the petition issues. Those issues have now been voluntarily dismissed from the case, while one new permit change was challenged and added to the case. The administrative law judge (ALJ) recently dismissed some of the petition issues relating to the averaging period and monitoring issues. In May 2014, the WDNR issued an NOV alleging that WPS failed to maintain a minimum sorbent feed rate prior to the Continuous Emissions Monitoring System certification. The WDNR also issued a Notice of Inquiry (NOI) to WPS alleging that WPS failed to comply with reporting requirements related to challenged matters in the 2013 Weston Title V permit. The ALJ recently denied WPS’s request to issue a stay or confirm that a statutory stay applies to the requirements identified in the NOV and NOI. The parties are discussing a briefing schedule, but no hearing date has been set. We do not expect these matters to have a material impact on our financial statements.

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Mercury and Interstate Air Quality Rules

Mercury:

The State of Wisconsin’s mercury rule required a 40% reduction from historical baseline mercury emissions, beginning January 1, 2010, through the end of 2014. Beginning in 2015, electric generating units above 150 megawatts would have been required to further reduce mercury emissions. However, in December 2011, the EPA issued the final Utility Mercury and Air Toxics Standards (MATS), which regulates emissions of mercury and other hazardous air pollutants beginning in April 2015. The State of Wisconsin recently revised the state mercury rule to be consistent with the MATS rule. Projects approved and initiated to address the State of Wisconsin mercury rule are expected to ensure compliance with the mercury limits in the MATS rule.

WPS was in compliance with the State of Wisconsin’s mercury rule at the end of 2014. In addition, WPS is making progress toward compliance with the MATS rule in 2015. WPS estimated capital costs of approximately $9 million for its wholly owned plants to achieve the required reductions for MATS compliance, of which approximately $8 million was expended as of December 31, 2014. The capital costs are expected to be recovered in future rates.

Sulfur Dioxide and Nitrogen Oxide:

In July 2011, the EPA issued a final rule known as the Cross State Air Pollution Rule (CSAPR), which numerous parties, including WPS, challenged in the United States Court of Appeals (Court of Appeals) for the District of Columbia Circuit (D.C. Circuit). The new rule was to become effective in January 2012. However, in December 2011, the CSAPR requirements were stayed by the D.C. Circuit and a previous rule, the Clean Air Interstate Rule (CAIR), was implemented during the stay period. In August 2012, the D.C. Circuit issued their ruling vacating and remanding CSAPR and simultaneously reinstating CAIR pending the issuance of a replacement rule by the EPA. The case was appealed to the United States Supreme Court (Supreme Court), and in April 2014, the Supreme Court upheld the CSAPR rule and remanded the case to the Court of Appeals for the D.C. Circuit. In October 2014, the Court of Appeals granted the EPA’s request to lift the stay on CSAPR and changed the compliance deadlines by three years, so that Phase 1 emissions budgets will apply in 2015 and 2016 and Phase 2 emissions budgets will apply to 2017 and beyond. We do not expect to incur significant costs to comply with either phase of CSAPR and expect to recover any future compliance costs in future rates.

Under CAIR, units affected by the Best Available Retrofit Technology (BART) rule were considered in compliance with BART for sulfur dioxide and nitrogen oxide emissions if they were in compliance with CAIR. This determination was updated when CSAPR was issued (CSAPR satisfied BART). Although particulate emissions also contribute to visibility impairment, the WDNR’s modeling for Pulliam Unit 8, the only unit covered by BART, has shown the impairment to be so insignificant that additional capital expenditures or controls may not be warranted.

Clean Water Act Rule

In August 2014, the EPA issued a final Clean Water Act, which established requirements under Section 316(b) to regulate water intake structures at industrial facilities that use large volumes of surface water as cooling water. The new rule became effective in October 2014 and has been challenged by a number of parties. The cases have been consolidated and will be heard in the United States Court of Appeals for the Second Circuit. To the extent that the rule is upheld, WPS will comply with the rule on the timeline required under the regulation. WPS will evaluate the impact of compliance by conducting the studies required by the rule at its facilities. WPS anticipates that the timing for compliance will be incorporated into future wastewater discharge permit renewals. We do not expect to incur significant costs to comply with the Clean Water Act rule as WPS’s Weston plants are already equipped with cooling towers that assist with meeting these new requirements. We expect to recover any future compliance costs in future rates.

Manufactured Gas Plant Remediation

Our natural gas utilities, their predecessors, and certain former affiliates operated facilities in the past at multiple sites for the purpose of manufacturing and storing manufactured gas. In connection with these activities, waste materials were produced that may have resulted in soil and groundwater contamination at these sites. Under certain laws and regulations relating to the protection of the environment, our natural gas utilities are required to undertake remedial action with respect to some of these materials. The natural gas utilities are coordinating the investigation and cleanup of the sites subject to EPA jurisdiction under what is called a “multisite” program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies.

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Our natural gas utilities are responsible for the environmental remediation of 53 sites, of which 20 have been transferred to the EPA Superfund Alternative Sites Program. Under the EPA’s program, the remedy decisions at these sites will be made using risk-based criteria typically used at Superfund sites. Our balance sheet includes liabilities of $579.7 million that we have estimated and accrued for as of December 31, 2014, for future undiscounted investigation and cleanup costs for all sites. We may adjust these estimates in the future due to remedial technology, regulatory requirements, remedy determinations, and any claims of natural resource damages. As of December 31, 2014, cash expenditures for environmental remediation not yet recovered in rates were $54.6 million. Our balance sheet also includes a regulatory asset of $634.3 million at December 31, 2014, which is net of insurance recoveries, related to the expected recovery through rates of both cash expenditures and estimated future expenditures.

Management believes that any costs incurred for environmental activities relating to former manufactured gas plant operations that are not recoverable through contributions from other entities or from insurance carriers have been prudently incurred and are, therefore, recoverable through rates for MGU, NSG, PGL, and WPS. Accordingly, we do not expect these costs to have a material impact on our financial statements. However, any changes in the approved rate mechanisms for recovery of these costs, or any adverse conclusions by the various regulatory commissions with respect to the prudence of costs actually incurred, could materially affect recovery of such costs through rates.

Note 18—Employee Benefit Plans

Defined Benefit Plans

We and our subsidiaries maintain a noncontributory, qualified pension plan covering the majority of our employees, as well as several unfunded nonqualified retirement plans. In addition, we and our subsidiaries offer multiple other postretirement benefit plans to employees. The benefits for a portion of these plans are funded through irrevocable trusts, as allowed for income tax purposes. We also offer medical, dental, and life insurance benefits to active employees and their dependents. We expense the costs of these benefits as incurred.

The defined benefit pension plans are closed to all new hires. In addition, the service accruals for the defined benefit pension plans were frozen for non-union employees as of January 1, 2013. In March 2014, we remeasured the obligations of certain other postretirement benefit plans as a result of a plan design change to move participants age 65 and older to a Medicare Advantage plan starting January 1, 2015.

In August 2014, we sold UPPCO. The pension and other postretirement plan assets and obligations related to UPPCO employees and retirees transferred with the sale and are disclosed in the table below. The impact of this transfer has been reflected in the measurement of the gain on sale of UPPCO. See Note 4, Dispositions, for more information.

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The following tables provide a reconciliation of the changes in our plans’ benefit obligations and fair value of assets:

(Millions)	Pension Benefits						Other Benefits
Change in benefit obligation	2014			2013			2014			2013
Obligation at January 1	$	1,641.7		$	1,784.9		$	576.3		$	621.0
Service cost	24.8			30.2			21.0			24.9
Interest cost	76.2			71.2			23.5			24.8
Plan amendments	—			—			(90.4		)	0.2
Divestitures - UPPCO	(100.4		)	—			(22.3		)	—
Actuarial loss (gain), net	166.1			(153.1		)	33.1			(73.4		)
Participant contributions	—			—			10.0			10.6
Benefit payments	(102.7		)	(91.5		)	(33.3		)	(34.0		)
Federal subsidy on benefits paid	—			—			2.1			2.2
Obligation at December 31	$	1,705.7		$	1,641.7		$	520.0		$	576.3

Change in fair value of plan assets
Fair value of plan assets at January 1	$	1,527.7		$	1,348.1		$	470.1		$	424.4
Actual return on plan assets	94.6			205.4			18.2			57.8
Employer contributions	98.8			65.7			10.0			11.3
Participant contributions	—			—			10.0			10.6
Divestitures - UPPCO	(122.8		)	—			(27.3		)	—
Benefit payments	(102.7		)	(91.5		)	(33.3		)	(34.0		)
Fair value of plan assets at December 31	$	1,495.6		$	1,527.7		$	447.7		$	470.1
Funded Status at December 31	$	(210.1	)	$	(114.0	)	$	(72.3	)	$	(106.2	)

The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows:

	Pension Benefits						Other Benefits
(Millions)	2014			2013			2014			2013
Long-term assets	$	—		$	—		$	1.5		$	—
Current liabilities	9.1			8.9			0.2			0.2
Liabilities held for sale	—			6.9			—			3.4
Long-term liabilities	201.0			98.2			73.6			102.6
Total net liabilities	$	(210.1	)	$	(114.0	)	$	(72.3	)	$	(106.2	)

The accumulated benefit obligation for the defined benefit pension plans was $1,531.1 million and $1,489.1 million at December 31, 2014, and 2013, respectively.

The following table shows information for the non-qualified pension plans for which we have an accumulated benefit obligation in excess of plan assets. There were no plan assets related to these non-qualified pension plans. Amounts presented are as of December 31:

(Millions)	2014		2013
Projected benefit obligation	$	64.1	$	65.4
Accumulated benefit obligation	61.2		63.0

The following table shows the amounts that had not yet been recognized in our net periodic benefit cost as of December 31:

	Pension Benefits				Other Benefits
(Millions)	2014		2013		2014			2013
Accumulated other comprehensive loss (pre-tax) (1)
Net actuarial loss	$	40.2	$	33.3	$	0.2		$	0.7
Prior service credits	—		—		(0.1		)	(0.2		)
Total	$	40.2	$	33.3	$	0.1		$	0.5
Net regulatory assets (2)
Net actuarial loss	$	501.0	$	356.2	$	50.4		$	6.2
Prior service costs (credits)	1.8		2.4		(85.3		)	(12.4		)
Total	$	502.8	$	358.6	$	(34.9	)	$	(6.2	)

(1)Amounts related to the nonregulated entities are included in accumulated other comprehensive loss.

(2)Amounts related to the utilities are recorded as net regulatory assets or liabilities.

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The following table shows the estimated amounts that will be amortized into net periodic benefit cost during 2015:

(Millions)	Pension Benefits		Other Benefits
Net actuarial loss	$	43.2	$	4.4
Prior service costs (credits)	0.2		(10.3		)
Total 2015 — estimated amortization	$	43.4	$	(5.9	)

The following table shows the components of net periodic benefit cost (including amounts capitalized to our balance sheets) for our benefit plans:

	Pension Benefits									Other Benefits
(Millions)	2014			2013			2012			2014			2013			2012
Service cost	$	24.8		$	30.2		$	46.0		$	21.0		$	24.9		$	20.8
Interest cost	76.2			71.2			78.0			23.5			24.8			28.5
Expected return on plan assets	(112.4		)	(105.5		)	(107.9		)	(33.0		)	(30.6		)	(28.2		)
Loss on plan settlement	0.9			—			—			—			—			—
Amortization of transition obligation	—			—			—			—			—			0.3
Amortization of prior service cost (credit)	0.6			4.0			5.0			(9.4		)	(2.5		)	(3.4		)
Amortization of net actuarial loss	33.3			56.7			34.0			3.2			8.4			6.6
Net periodic benefit cost	$	23.4		$	56.6		$	55.1		$	5.3		$	25.0		$	24.6

Assumptions — Pension and Other Postretirement Benefit Plans

The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31:

	Pension Benefits				Other Benefits
	2014		2013		2014		2013
Discount rate	4.08	%	4.92	%	4.00	%	4.83	%
Rate of compensation increase	4.23	%	4.24	%	N/A		N/A
Assumed medical cost trend rate	N/A		N/A		6.00	%	6.50	%
Ultimate trend rate	N/A		N/A		5.00	%	5.00	%
Year ultimate trend rate is reached	N/A		N/A		2023		2019
Assumed dental cost trend rate	N/A		N/A		5.00	%	5.00	%

The weighted-average assumptions used to determine the net periodic benefit cost for the plans were as follows for the years ended December 31:

	Pension Benefits
	2014		2013		2012
Discount rate	4.92	%	4.07	%	5.10	%
Expected return on assets	8.00	%	8.00	%	8.25	%
Rate of compensation increase	4.23	%	4.25	%	4.25	%

	Other Benefits
	2014		2013		2012
Discount rate	4.65	%	3.96	%	4.94	%
Expected return on assets	8.00	%	8.00	%	8.25	%
Assumed medical cost trend rate (under age 65)	6.50	%	7.00	%	7.00	%
Ultimate trend rate	5.00	%	5.00	%	5.00	%
Year ultimate trend rate is reached	2019		2019		2016
Assumed medical cost trend rate (over age 65)	6.50	%	7.00	%	7.50	%
Ultimate trend rate	5.00	%	5.00	%	5.50	%
Year ultimate trend rate is reached	2019		2019		2016
Assumed dental cost trend rate	5.00	%	5.00	%	5.00	%

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We establish our expected return on assets assumption based on consideration of historical and projected asset class returns, as well as the target allocations of the benefit trust portfolios. For 2015, the expected return on assets assumption for the plans is 7.75%.

Assumed health care cost trend rates have a significant effect on the amounts reported by us for our health care plans. For the year ended December 31, 2014, a one-percentage-point change in assumed health care cost trend rates would have had the following effects:

	One-Percentage-Point
(Millions)	Increase		Decrease
Effect on total of service and interest cost components of net periodic postretirement health care benefit cost	$	6.1	$	(5.0	)
Effect on the health care component of the accumulated postretirement benefit obligation	58.7		(55.1		)

Pension and Other Postretirement Benefit Plan Assets

Our investment policy includes various guidelines and procedures designed to ensure assets are invested in an appropriate manner to meet expected future benefits to be earned by participants. The investment guidelines consider a broad range of economic conditions. The policy is established and administered in a manner that is compliant at all times with applicable regulations.

Central to our policy are target allocation ranges by major asset categories. The objectives of the target allocations are to maintain investment portfolios that diversify risk through prudent asset allocation parameters and to achieve asset returns that meet or exceed the plans’ actuarial assumptions and that are competitive with like instruments employing similar investment strategies. The portfolio diversification provides protection against significant concentrations of risk in the plan assets. In 2014, the pension plan target asset allocation was 70% equity securities and 30% fixed income securities. In December 2014, we changed the pension plan target asset allocation to 60% equity securities and 40% fixed income securities for 2015. The target asset allocation for other postretirement benefit plans that have significant assets is 70% equity securities and 30% fixed income securities. Equity securities primarily include investments in large-cap and small-cap companies. Fixed income securities primarily include corporate bonds of companies from diversified industries, United States government securities, and mortgage-backed securities.

The Board of Directors established the Employee Benefits Administrator Committee (composed of members of management) to manage the operations and administration of all benefit plans and trusts. The committee monitors the asset allocation, and the portfolio is rebalanced when necessary.

Pension and other postretirement benefit plan investments are recorded at fair value. See Note 1(w), Fair Value, for more information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used.

The following tables provide the fair values of our investments by asset class:

	December 31, 2014
	Pension Plan Assets											Other Benefit Plan Assets
(Millions)	Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Asset Class
Cash and cash equivalents	$	—		$	42.3		$	—	$	42.3		$	8.5	$	2.6	$	—	$	11.1
Equity securities:
United States equity	91.0			336.2			—		427.2			20.6		122.8		—		143.4
International equity	92.4			383.9			—		476.3			18.7		117.8		—		136.5
Fixed income securities:
United States government	70.3			21.6			—		91.9			111.1		—		—		111.1
Foreign government	—			20.6			—		20.6			—		—		—		—
Corporate debt	—			425.7			—		425.7			—		—		—		—
Other	—			53.5			—		53.5			1.0		—		—		1.0
	253.7			1,283.8			—		1,537.5			159.9		243.2		—		403.1
401(h) other benefit plan assets invested as pension assets (1)	(7.4		)	(37.2		)	—		(44.6		)	7.4		37.2		—		44.6
Total (2)	$	246.3		$	1,246.6		$	—	$	1,492.9		$	167.3	$	280.4	$	—	$	447.7

(1)Pension trust assets are used to pay other postretirement benefits as allowed under Internal Revenue Code Section 401(h).

(2)Investments do not include accruals or pending transactions that are included in the table reconciling the change in fair value of plan assets.

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	December 31, 2013
	Pension Plan Assets												Other Benefit Plan Assets
(Millions)	Level 1			Level 2			Level 3			Total			Level 1		Level 2		Level 3		Total
Asset Class
Cash and cash equivalents	$	2.0		$	36.6		$	—		$	38.6		$	—	$	4.0	$	—	$	4.0
Equity securities:
United States equity	100.4			445.1			—			545.5			21.4		132.2		—		153.6
International equity	114.1			429.0			—			543.1			19.5		125.5		—		145.0
Fixed income securities:
United States government	—			93.6			—			93.6			121.2		0.7		—		121.9
Foreign government	—			16.9			2.4			19.3			—		—		—		—
Corporate debt	—			250.0			1.3			251.3			—		—		—		—
Asset-backed securities	—			61.8			—			61.8			—		—		—		—
Other	—			17.4			—			17.4			1.0		—		—		1.0
	216.5			1,350.4			3.7			1,570.6			163.1		262.4		—		425.5
401(h) other benefit plan assets invested as pension assets (1)	(6.1		)	(37.9		)	(0.1		)	(44.1		)	6.1		37.9		0.1		44.1
Total (2)	$	210.4		$	1,312.5		$	3.6		$	1,526.5		$	169.2	$	300.3	$	0.1	$	469.6

(1)Pension trust assets are used to pay other postretirement benefits as allowed under Internal Revenue Code Section 401(h).

(2)Investments do not include accruals or pending transactions that are included in the table reconciling the change in fair value of plan assets.

The following tables set forth a reconciliation of changes in the fair value of pension plan assets categorized as Level 3 in the fair value hierarchy:

(Millions)	Foreign Government Debt			Corporate Debt			Total
Beginning balance at January 1, 2014	$	2.4		$	1.3		$	3.7
Sales	(2.4		)	(1.3		)	(3.7		)
Ending balance at December 31, 2014	$	—		$	—		$	—
Net unrealized gains (losses) related to assets still held at the end of the period	$	—		$	—		$	—

(Millions)	Foreign Government Debt			Corporate Debt			Asset-Backed Securities			Total
Beginning balance at January 1, 2013	$	4.1		$	1.0		$	0.1		$	5.2
Net realized and unrealized losses	(0.3		)	(0.4		)	—			(0.7		)
Purchases	0.6			—			—			0.6
Sales	(2.0		)	(0.4		)	—			(2.4		)
Transfers into Level 3	—			1.4			—			1.4
Transfers out of Level 3	—			(0.3		)	(0.1		)	(0.4		)
Ending balance at December 31, 2013	$	2.4		$	1.3		$	—		$	3.7
Net unrealized losses related to assets still held at the end of the period	$	(0.2	)	$	(0.3	)	$	—		$	(0.5	)

Cash Flows Related to Pension and Other Postretirement Benefit Plans

Our funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax purposes. We expect to contribute $9.1 million to the pension plans and $8.7 million to other postretirement benefit plans in 2015, dependent upon various factors affecting us, including our liquidity position and possible tax law changes. In 2015, contributions of $7.0 million will be funded through a transfer of assets from the rabbi trust for certain nonqualified pension plans. See the discussion below in regard to the triggering of the full funding of the rabbi trust.

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The following table shows the payments, reflecting expected future service, that we expect to make for pension and other postretirement benefits.

(Millions)	Pension Benefits		Other Benefits
2015	$	124.6	$	23.7
2016	122.3		26.0
2017	127.6		28.4
2018	126.0		30.6
2019	136.5		33.3
2020 through 2024	644.4		195.8

Rabbi Trust Funding

The Agreement and Plan of Merger entered into with Wisconsin Energy Corporation in June 2014 triggered the potential change in control provisions in the rabbi trust agreement. These provisions required the full funding of the present value of each participant’s total benefit under the deferred compensation program and certain nonqualified pension plans. As a result, $65.0 million was moved to the rabbi trust in June 2014, $64.8 million, consisting of cash and exchange-traded funds, was moved to the rabbi trust in July 2014, and an additional $2.4 million was moved to the rabbi trust in December 2014. These amounts were included in other long-term assets on the balance sheet as of December 31, 2014. See Note 2, Proposed Merger with Wisconsin Energy Corporation, for more information.

Defined Contribution Benefit Plans

We maintain 401(k) Savings Plans for substantially all of our full-time employees. A percentage of employee contributions are matched through an employee stock ownership plan (ESOP) contribution or cash contribution up to certain limits. Certain union employees receive a contribution to their ESOP account regardless of their participation in the 401(k) Savings Plan. The ESOP held 3.9 million shares of our common stock (market value of $303.5 million) at December 31, 2014. Certain employees participate in a defined contribution pension plan, in which certain amounts are contributed to an employee’s account based on the employee’s wages, age, and years of service. Total costs incurred under all of these plans were $35.0 million in 2014, $36.4 million in 2013, and $19.1 million in 2012.

We maintain deferred compensation plans that enable certain key employees and nonemployee directors to defer payment of a portion of their compensation or fees on a pre-tax basis. Nonemployee directors can defer up to 100% of their director fees. Compensation is generally deferred in the form of cash and is indexed to certain investment options or our common stock. The deemed dividends paid on the common stock are automatically reinvested.

The deferred compensation arrangements for which distributions are made solely in our common stock are classified as an equity instrument on the balance sheets. Changes in the fair value of this portion of the deferred compensation obligation are not recognized. The deferred compensation obligation classified as an equity instrument was $24.3 million at December 31, 2014, and $24.8 million at December 31, 2013.

The portion of the deferred compensation obligation that is indexed to various investment options and allows for distributions in cash is classified as a liability on the balance sheets. The liability is adjusted, with a charge or credit to expense, to reflect changes in the fair value of the deferred compensation obligation. The obligation classified within other long-term liabilities was $64.4 million at December 31, 2014, and $53.4 million at December 31, 2013. The costs incurred under this arrangement were $9.5 million in 2014, $6.5 million in 2013, and $3.1 million in 2012.

Historically, the deferred compensation programs were partially funded through shares of our common stock that are held in a rabbi trust. The common stock held in the rabbi trust is classified as a reduction of equity in a manner similar to accounting for treasury stock. The total cost of our common stock held in the rabbi trust was $20.9 million at December 31, 2014, and $23.0 million at December 31, 2013.

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Note 19—Preferred Stock of Subsidiary

Our subsidiary, WPS, has 1,000,000 authorized shares of preferred stock with no mandatory redemption and a $100 par value. Outstanding shares owned by third parties were as follows at December 31:

(Millions, except share amounts)	2014			2013
Series	Shares Outstanding	Carrying Value		Shares Outstanding	Carrying Value
5.00%	130,692	$	13.1	130,692	$	13.1
5.04%	29,898	3.0		29,898	3.0
5.08%	49,905	5.0		49,905	5.0
6.76%	150,000	15.0		150,000	15.0
6.88%	150,000	15.0		150,000	15.0
Total	510,495	$	51.1	510,495	$	51.1

All shares of WPS preferred stock of all series are of equal rank except as to dividend rates and redemption terms. Payment of dividends from any earned surplus or other available surplus is not restricted by the terms of any indenture or other undertaking by WPS. Each series of outstanding preferred stock is redeemable in whole or in part at WPS’s option at any time on 30 days’ notice at the respective redemption prices. WPS may not redeem less than all, nor purchase any, of its preferred stock during the existence of any dividend default.

In the event of WPS’s dissolution or liquidation, the holders of preferred stock are entitled to receive (a) the par value of their preferred stock out of the corporate assets other than profits before any of such assets are paid or distributed to the holders of common stock and (b) the amount of dividends accumulated and unpaid on their preferred stock out of the surplus or net profits before any of such surplus or net profits are paid to the holders of common stock. Thereafter, the remainder of the corporate assets, surplus, and net profits would be paid to the holders of common stock.

The preferred stock has no pre-emptive, subscription, or conversion rights, and has no sinking fund provisions.

Note 20—Common Equity

We had the following changes to issued common stock:

Balance at December 31, 2011	78,287,906
Balance at December 31, 2012 *	78,287,906
Shares issued
Stock-based compensation	972,718
Stock Investment Plan	298,532
Employee Stock Ownership Plan	248,724
Rabbi trust shares	111,296
Balance at December 31, 2013	79,919,176
Shares issued
Stock Investment Plan	12,151
Employee Stock Ownership Plan	31,764
Balance at December 31, 2014	79,963,091

*We did not issue equity during 2012.

The following table provides a summary of common stock activity to meet the requirements of our Stock Investment Plan and certain stock-based employee benefit and compensation plans:

Period	Method of meeting requirements
Beginning 02/05/2014	Purchasing shares on the open market
02/05/2013 – 02/04/2014	Issued new shares
01/01/2012 – 02/04/2013	Purchased shares on the open market

Under the merger agreement with Wisconsin Energy Corporation (Wisconsin Energy), we cannot issue shares of our common stock.

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The following table reconciles common shares issued and outstanding:

	2014			2013
	Shares	Average Cost *		Shares	Average Cost *
Common stock issued	79,963,091			79,919,176
Less:
Deferred compensation rabbi trust	428,920	$	48.73	473,796	$	48.50
Total common shares outstanding	79,534,171			79,445,380

*Based on our stock price on the day the shares entered the deferred compensation rabbi trust. Shares paid out of the trust are valued at the average cost of shares in the trust.

Earnings Per Share

The following table reconciles our computation of basic and diluted earnings per share:

(Millions, except per share amounts)	2014			2013			2012
Numerator:
Net income from continuing operations	$	278.1		$	267.5		$	238.9
Discontinued operations, net of tax	1.8			87.3			45.4
Preferred stock dividends of subsidiary	(3.1		)	(3.1		)	(3.1		)
Noncontrolling interest in subsidiaries	0.1			0.1			0.2
Net income attributed to common shareholders — basic	$	276.9		$	351.8		$	281.4
Effect of dilutive securities
Deferred compensation	—			(0.1		)	—
Net income attributed to common shareholders — diluted	$	276.9		$	351.7		$	281.4
Denominator:
Average shares of common stock — basic	80.2			79.5			78.6
Effect of dilutive securities
Stock-based compensation	0.5			0.4			0.5
Deferred compensation	—			0.2			0.2
Average shares of common stock — diluted	80.7			80.1			79.3
Earnings per common share
Basic	$	3.45		$	4.43		$	3.58
Diluted	3.43			4.39			3.55

The calculation of diluted earnings per share excluded the following weighted-average outstanding securities that had an anti-dilutive effect:

(Millions)	2014	2013	2012
Stock-based compensation	0.2	0.3	0.7
Deferred compensation	0.3	0.1	—

Dividend Restrictions

Our ability as a holding company to pay dividends is largely dependent upon the availability of funds from our subsidiaries. Various laws, regulations, and financial covenants impose restrictions on the ability of certain of our utility subsidiaries to transfer funds to us in the form of dividends. Our utility subsidiaries, with the exception of MGU, are prohibited from loaning funds to us, either directly or indirectly.

The PSCW allows WPS to pay dividends on its common stock of no more than 103% of the previous year’s common stock dividend. WPS may return capital to us if its average financial common equity ratio is at least 51% on a calendar-year basis. WPS must obtain PSCW approval if a return of capital would cause its average financial common equity ratio to fall below this level. Our right to receive dividends on the common stock of WPS is also subject to the prior rights of WPS’s preferred shareholders and to provisions in WPS’s restated articles of incorporation, which limit the amount of common stock dividends that WPS may pay if its common stock and common stock surplus accounts constitute less than 25% of its total capitalization.

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NSG’s long-term debt obligations contain provisions and covenants restricting the payment of cash dividends and the purchase or redemption of its capital stock.

PGL and WPS have short-term debt obligations containing financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%. Failure to comply with these covenants could result in an event of default which could result in the acceleration of their outstanding debt obligations.

As of December 31, 2014, total restricted net assets of consolidated subsidiaries were $1,953.0 million. Our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method was $157.5 million at December 31, 2014.

We also have short-term and long-term debt obligations that contain financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%. Failure to comply with these covenants could result in an event of default which could result in the acceleration of outstanding debt obligations. At December 31, 2014, these covenants did not restrict our retained earnings or the payment of any dividends.

We have the option to defer interest payments on our outstanding Junior Subordinated Notes, from time to time, for one or more periods of up to ten consecutive years per period. During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, purchase, acquire, or make a liquidation payment on, any of our capital stock.

Under the merger agreement with Wisconsin Energy, we may not declare or pay any dividends or distributions on our common stock other than the regular quarterly dividend of $0.68 per share.

Except for the restrictions described above and subject to applicable law, we do not have any other significant dividend restrictions.

Capital Transactions with Subsidiaries

During 2014, capital transactions with subsidiaries were as follows (in millions):

Subsidiary	Dividends To Parent		Return Of Capital To Parent		Equity Contributions From Parent
IBS	$	—	$	—	$	25.0
ITF (1)	—		—		50.3
MERC	—		27.0		20.0
MGU	—		13.0		7.0
PGL(1)	—		—		65.0
UPPCO	—		12.5		94.4
WPS	111.8		—		55.0
WPS Investments, LLC (2)	74.3		—		17.0
Total	$	186.1	$	52.5	$	333.7

(1)ITF and PGL are direct wholly owned subsidiaries of PELLC. As a result, they make distributions to PELLC, and receive equity contributions from PELLC. Subject to applicable law, PELLC does not have any dividend restrictions or limitations on distributions to us.

(2)WPS Investments, LLC is a consolidated subsidiary that is jointly owned by us and WPS. In August 2014, UPPCO’s ownership interest in WPS Investments, LLC was transferred to us as a result of the sale of UPPCO. At December 31, 2014, the ownership interest held by us and WPS was 89.02% and 10.98%, respectively. Distributions from WPS Investments, LLC are made to the owners based on their respective ownership percentages. During 2014, all equity contributions to WPS Investments, LLC were made solely by us.

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Note 21—Accumulated Other Comprehensive Loss

The following table shows the changes, net of tax, to our accumulated other comprehensive loss:

							Accumulated Other
(Millions)	Cash Flow Hedges			Defined Benefit Plans			Comprehensive Loss
Balance at December 31, 2012	$	(5.2	)	$	(35.7	)	$	(40.9	)
Other comprehensive income before reclassifications	0.7			13.2			13.9
Amounts reclassified out of accumulated other comprehensive loss	1.4			2.4			3.8
Net 2013 other comprehensive income	2.1			15.6			17.7
Balance at December 31, 2013	(3.1		)	(20.1		)	(23.2		)
Other comprehensive loss before reclassifications	—			(6.0		)	(6.0		)
Amounts reclassified out of accumulated other comprehensive loss	(0.1		)	1.7			1.6
Net 2014 other comprehensive loss	(0.1		)	(4.3		)	(4.4		)
Balance at December 31, 2014	$	(3.2	)	$	(24.4	)	$	(27.6	)

The following table shows the reclassifications out of accumulated other comprehensive loss during the years ended December 31:

	Amount Reclassified
(Millions)	2014			2013			Affected Line Item in the Statements of Income
Losses (gains) on cash flow hedges
Utility commodity derivative contracts	$	—		$	0.2		Operating and maintenance expense (1) (2)
Nonregulated commodity derivative contracts	—			3.7			Discontinued operations (2)
Interest rate hedges	1.1			1.1			Interest expense
	1.1			5.0			Total before tax
	1.2			3.6			Tax expense
	(0.1		)	1.4			Net of tax
Defined benefit plans
Amortization of prior service costs (credits)	(0.2		)	4.3			(3)
Amortization of net actuarial losses (gains)	2.7			(0.2		)	(3)
	2.5			4.1			Total before tax
	0.8			1.7			Tax expense
	1.7			2.4			Net of tax
Total reclassifications	$	1.6		$	3.8

(1)This item relates to changes in the price of natural gas used to support utility operations.

(2)We no longer designate commodity contracts as cash flow hedges.

(3)These items are included in the computation of net periodic benefit cost. See Note 18, Employee Benefit Plans, for more information.

Note 22—Guarantees

The following table shows our outstanding guarantees:

	Total Amounts Committed		Expiration
(Millions)	at December 31, 2014		Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees supporting commodity transactions of subsidiaries (1)	$	189.3	$	105.1	$	—	$	84.2
Standby letters of credit (2)	1.2		1.1		0.1		—
Surety bonds (3)	25.1		25.0		0.1		—
Other guarantees (4)	73.5		—		—		73.5
Guarantees temporarily retained related to the sale of IES’s retail energy business (5)	279.5		$	248.4	$	1.8	$	29.3
Total guarantees	$	568.6	$	379.6	$	2.0	$	187.0

(1)Consists of (a) $5.0 million to support the business operations of IBS, and (b) $0.4 million, $127.4 million, $44.7 million, and $11.8 million related to natural gas supply at ITF, MERC, MGU, and PDI, respectively. These guarantees are not reflected on our balance sheets.

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(2)At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. This amount consists of $1.2 million issued to support ITF, MERC, MGU, NSG, PDI, PGL, and WPS. These amounts are not reflected on our balance sheets.

(3)Primarily for the construction and operation of compressed natural gas fueling stations, workers compensation self-insurance programs, and obtaining various licenses, permits, and rights-of-way. These guarantees are not reflected on our balance sheets.

(4)Consists of (a) $46.1 million to support PDI’s future payment obligations related to its distributed solar generation projects; (b) $10.0 million related to the sale agreement for IES’s Texas retail marketing business. An insignificant liability was recorded related to the possible imposition of additional miscellaneous gross receipts tax in the event of a change in law or interpretation of the tax law; (c) $11.2 million related to the performance of an operating and maintenance agreement by ITF; and (d) $6.2 million related to other indemnifications primarily for workers compensation coverage. The amounts discussed in items (a), (c), and (d) above are not reflected on our balance sheets.

(5)These guarantees are retained temporarily due to the sale of IES’s retail energy business to Exelon Generation Company, LLC (Exelon). For up to six months after the sale, we will continue to provide these guarantees until either Exelon can replace them or until they expire. Exelon is contractually bound to reimburse us for any payments we make under the outstanding guarantees. These guarantees consist of (a) $267.4 million of guarantees supporting commodity transactions; (b) $6.9 million of standby letters of credit; (c) $3.4 million of surety bonds; and (d) $1.8 million related to the sale of WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC. Following the guidance of the Guarantees Topic of the FASB ASC, an insignificant liability related to these guarantees was recorded at fair value on our balance sheet. Our exposure under these guarantees related to open transactions at December 31, 2014, was $168.9 million.

Note 23—Stock-Based Compensation

The following table reflects the stock-based compensation expense and the related deferred income tax benefit recognized in income for the years ended December 31:

(Millions)	2014		2013		2012
Stock options	$	2.7	$	1.8	$	2.0
Performance stock rights	16.8		2.7		5.0
Restricted share units	9.9		8.6		8.1
Nonemployee director deferred stock units	0.8		0.9		1.0
Total stock-based compensation expense	$	30.2	$	14.0	$	16.1
Deferred income tax benefit	$	12.1	$	5.6	$	6.4

No stock-based compensation cost was capitalized during 2014, 2013, and 2012.

Stock Options

The following table shows the weighted-average fair values per stock option granted along with the assumptions incorporated into the binomial lattice valuation models:

	2014 Grant	2013 Grant	2012 Grant
Weighted-average fair value per stock option	6.70	6.03	6.30
Expected term	8 years	5 years	5 years
Risk-free interest rate	0.12% – 2.88%	0.18% – 2.11%	0.17% – 2.18%
Expected dividend yield	5.28%	5.33%	5.28%
Expected volatility	18%	24%	25%

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A summary of stock option activity for 2014, and information related to outstanding and exercisable stock options at December 31, 2014, is presented below:

	Stock Options		Weighted-Average Exercise Price Per Share		Weighted-Average Remaining Contractual Life (in Years)	Aggregate Intrinsic Value (Millions)
Outstanding at December 31, 2013	1,550,374		$	50.93
Granted	264,332		55.23
Exercised	(1,676,831	)	51.33
Forfeited	(3,858	)	55.23
Outstanding at December 31, 2014	134,017		$	54.31	6.6	$	3.2
Exercisable at December 31, 2014	59,714		$	55.21	5.6	$	1.4

The aggregate intrinsic value for outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they all exercised their options on December 31, 2014. This is calculated as the difference between our closing stock price on December 31, 2014, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during 2014, 2013, and 2012, was $32.0 million, $9.0 million, and $11.0 million, respectively. The actual tax benefit realized for the tax deductions from these option exercises was $12.8 million, $3.6 million, and  $4.4 million during 2014, 2013, and 2012, respectively.

Due to the accelerated vesting of all unvested stock options held by active employees in October 2014, all compensation expense related to outstanding stock options has been recognized at December 31, 2014.

Performance Stock Rights

The table below reflects the assumptions used in the Monte Carlo valuation models to estimate the fair value of the outstanding performance stock rights at December 31:

	2014	2013	2012
Risk-free interest rate	0.21% – 0.63%	0.13% – 1.27%	0.17% – 1.27%
Expected dividend yield	5.25% – 5.33%	5.28% – 5.34%	5.18% – 5.34%
Expected volatility	18% – 22%	15% – 36%	14% – 36%

A summary of the 2014 activity related to performance stock rights accounted for as equity awards is presented below:

	Performance Stock Rights		Weighted-Average  Fair Value (2)
Outstanding at December 31, 2013	85,749		$	46.62
Granted	21,146		44.28
Award modifications	64,612		85.09
Distributed (1)	(74,345	)	77.67
Adjustment for estimated payout and shares not distributed (1)	(28,591	)	52.67
Forfeited	(308	)	44.28
Outstanding at December 31, 2014	68,263		$	58.54

(1)No shares of common stock were distributed for performance stock rights with a performance period ending December 31, 2013, because the performance percentage was below the threshold payout level. In October 2014, our Board of Directors approved the acceleration of a portion of the estimated distribution for those performance stock rights held by active employees with a performance period ending December 31, 2014. This distribution was made in December 2014.

(2)Reflects the weighted-average fair value used to measure equity awards. Equity awards are measured using the grant date fair value or the fair value on the modification date.

The weighted-average grant date fair value of performance stock rights awarded during 2014, 2013, and 2012, was $44.28, $48.50, and $52.70 per performance stock right, respectively.

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A summary of the 2014 activity related to performance stock rights accounted for as liability awards is presented below:

	Performance Stock Rights
Outstanding at December 31, 2013	198,904
Granted	84,529
Award modifications	(64,612	)
Distributed *	(10,760	)
Adjustment for estimated payout and shares not distributed *	(36,519	)
Forfeited	(1,234	)
Outstanding at December 31, 2014	170,308

*No shares of common stock were distributed for performance stock rights with a performance period ending December 31, 2013, because the performance percentage was below the threshold payout level. In October 2014, our Board of Directors approved the acceleration of a portion of the estimated distribution for those performance stock rights held by active employees with a performance period ending December 31, 2014. This distribution was made in December 2014.

The weighted-average fair value of all outstanding performance stock rights accounted for as liability awards as of December 31, 2014, was $108.51 per performance stock right.

As of December 31, 2014, $4.2 million of compensation cost related to unvested and outstanding performance stock rights (equity and liability awards) was expected to be recognized over a weighted-average period of 1.6 years.

The total intrinsic value of performance stock rights distributed during 2014, 2013, and 2012, was $6.4 million, $8.8 million, and $4.7 million, respectively. The actual tax benefit realized for the tax deductions from the distribution of performance stock rights during 2014, 2013, and 2012,  was $2.6 million, $3.6 million, and $1.9 million, respectively.

Restricted Share Units

A summary of the 2014 activity related to all restricted share unit awards (equity and liability awards) is presented below:

	Restricted Share Unit Awards		Weighted-Average Grant Date Fair Value
Outstanding at December 31, 2013	511,301		$	52.24
Granted	214,953		55.23
Dividend equivalents	21,422		54.47
Vested and released	(208,964	)	49.76
Forfeited	(111,407	)	54.62
Outstanding at December 31, 2014	427,305		$	54.45

As of December 31, 2014, $7.3 million of unrecognized compensation cost related to these awards was expected to be recognized over a weighted-average period of 2.3 years.

The total intrinsic value of restricted share unit awards vested and released during 2014, 2013, and 2012, was $11.4 million, $11.7 million, and $10.7 million, respectively. The actual tax benefit realized for the tax deductions from the vesting and release of restricted share units during 2014, 2013, and 2012, was $4.6 million, $4.7 million, and $4.3 million, respectively.

The weighted-average grant date fair value of restricted share units awarded during 2014, 2013, and 2012, was $55.23, $55.93, and $53.24 per unit, respectively.

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Note 24—Fair Value

Fair Value Measurements

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

	December 31, 2014
(Millions)	Level 1		Level 2		Level 3		Total
Assets
Risk Management Assets
Natural gas contracts	$	—	$	2.3	$	—	$	2.3
Financial transmission rights (FTRs)	—		—		2.2		2.2
Coal contracts	—		—		—		—
Total Risk Management Assets	$	—	$	2.3	$	2.2	$	4.5
Investment in Exchange-Traded Funds	$	102.4	$	—	$	—	$	102.4
Liabilities
Risk Management Liabilities
Natural gas contracts	$	4.8	$	31.2	$	6.6	$	42.6
FTRs	—		—		0.3		0.3
Petroleum product contracts	2.8		—		—		2.8
Coal contracts	—		1.2		2.2		3.4
Total Risk Management Liabilities	$	7.6	$	32.4	$	9.1	$	49.1

	December 31, 2013
(Millions)	Level 1		Level 2		Level 3		Total
Assets
Risk Management Assets
Natural gas contracts	$	2.4	$	7.7	$	—	$	10.1
FTRs	—		—		1.5		1.5
Petroleum product contracts	0.1		—		—		0.1
Coal contracts	—		—		0.2		0.2
Total Risk Management Assets	$	2.5	$	7.7	$	1.7	$	11.9
Investment in Exchange-Traded Funds	$	15.9	$	—	$	—	$	15.9
Liabilities
Risk Management Liabilities
Natural gas contracts	$	0.5	$	0.6	$	—	$	1.1
FTRs	—		—		0.3		0.3
Coal contracts	—		—		2.7		2.7
Total Risk Management Liabilities	$	0.5	$	0.6	$	3.0	$	4.1

The risk management assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO market. See Note 6, Risk Management Activities, for more information on derivative instruments.

Transfers between levels of the fair value hierarchy were not significant during 2014. There were no transfers between the levels of the fair value hierarchy during 2013.

The significant unobservable inputs used in the valuations that resulted in categorization within Level 3 were as follows at December 31, 2014. The amounts listed in the table below represent the range of unobservable inputs that individually had a significant impact on the fair value determination and caused a transaction to be classified as Level 3.

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	Fair Value (Millions)
	Assets		Liabilities		Valuation Technique	Unobservable Input	Average or Range
Natural gas contracts	$	—	$	6.6	Income-based	Option volatilities (1)	50.5% – 67.2%
FTRs	2.2		0.3		Market-based	Forward market prices ($/megawatt-month) (2)	$188.16
Coal contracts	—		2.2		Market-based	Forward market prices ($/ton) (3)	$10.89 – $13.60

(1)Represents the range of volatilities used in the valuation of options. Volatilities are derived from an internal model based on volatility curves from third parties.

(2)Represents forward market prices developed using historical cleared pricing data from MISO.

(3)Represents third-party forward market pricing.

Significant changes in option volatilities, historical settlement prices, and forward coal prices would result in a directionally similar significant change in fair value.

The following tables set forth a reconciliation of changes in the fair value of items categorized as Level 3 measurements:

	2014
(Millions)	Natural Gas Contracts			FTRs			Coal Contracts			Total
Balance at the beginning of the period	$	—		$	1.2		$	(2.5	)	$	(1.3	)
Net realized and unrealized gains included in earnings	—			0.2			—			0.2
Net unrealized (losses) gains recorded as regulatory assets or liabilities	(6.6		)	0.4			(1.6		)	(7.8		)
Purchases	—			4.3			—			4.3
Settlements	—			(4.2		)	0.7			(3.5		)
Net transfers out of Level 3	—			—			1.2			1.2
Balance at the end of the period	$	(6.6	)	$	1.9		$	(2.2	)	$	(6.9	)

	2013
(Millions)	FTRs			Coal Contracts			Total
Balance at the beginning of the period	$	1.1		$	(6.5	)	$	(5.4	)
Net realized and unrealized gains included in earnings	3.0			—			3.0
Net unrealized (losses) gains recorded as regulatory assets or liabilities	(0.1		)	0.4			0.3
Purchases	3.2			—			3.2
Sales	(0.2		)	—			(0.2		)
Settlements	(5.8		)	3.6			(2.2		)
Balance at the end of the period	$	1.2		$	(2.5	)	$	(1.3	)

	2012
(Millions)	FTRs			Coal Contracts			Total
Balance at the beginning of the period	$	1.2		$	(6.9	)	$	(5.7	)
Net realized and unrealized gains included in earnings	1.8			—			1.8
Net unrealized (losses) gains recorded as regulatory assets or liabilities	(0.1		)	5.8			5.7
Purchases	2.8			—			2.8
Sales	(0.1		)	—			(0.1		)
Settlements	(4.5		)	(5.4		)	(9.9		)
Balance at the end of the period	$	1.1		$	(6.5	)	$	(5.4	)

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

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Fair Value of Financial Instruments

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

	December 31, 2014				December 31, 2013
(Millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	3,081.3	$	3,271.4	$	3,056.2	$	3,031.6
Preferred stock of subsidiary	51.1		51.8		51.1		61.2

Note 25—Regulatory Environment

Wisconsin

2015 Rates

In December 2014, the PSCW issued a final written order for WPS, effective January 1, 2015. It authorized a net retail electric rate increase of $24.6 million and a net retail natural gas rate decrease of $15.4 million, reflecting a 10.20% return on common equity. The order also included a common equity ratio of 50.28% in WPS’s regulatory capital structure. The PSCW approved a change in rate design for WPS, which includes higher fixed charges to better match the related fixed costs of providing service. The retail electric rate increase included recovery of 2013 deferred costs related to the acquisition of the Fox Energy Center. WPS also received approval from the PSCW to defer and amortize the undepreciated book value of the retired plant associated with Pulliam 5 and 6 and Weston 1 starting with the actual retirement date in 2015 and concluding when the balance is fully amortized. See Note 17, Commitments and Contingencies, for more information. In addition, the PSCW will allow escrow treatment for ATC and MISO network transmission expenses for 2015 and 2016. This allows WPS to defer as a regulatory asset or liability the differences between actual transmission expenses and those included in rates. Finally, the PSCW ordered that 2015 fuel costs should continue to be monitored using a two percent tolerance window. The retail natural gas rate decrease included a refund to customers in 2015 of the 2013 decoupling over-collections.

2014 Rates

In December 2013, the PSCW issued a final written order for WPS, effective January 1, 2014. It authorized a net retail electric rate decrease of $12.8 million and a net retail natural gas rate increase of $4.0 million, reflecting a 10.20% return on common equity. The order also included a common equity ratio of 50.14% in WPS’s regulatory capital structure. The retail electric rate impact consisted of a rate increase, including recovery of the difference between the 2012 fuel refund and the 2013 rate increase discussed below, entirely offset by a portion of estimated fuel cost over-collections from customers in 2013. Retail electric rates were further decreased by 2012 decoupling over-collections to be returned to customers in 2014. The retail natural gas rate impact consisted of a rate decrease, which was more than offset by the positive impact of 2012 decoupling under-collections to be recovered from customers in 2014. Both the retail electric and retail natural gas rate changes included the recovery of pension and other employee benefit increases that were deferred in the 2013 rate case, as discussed below. The PSCW also authorized the recovery of prudently incurred 2014 environmental mitigation project costs related to compliance with a Consent Decree signed in January 2013 related to the Pulliam and Weston sites. See Note 17, Commitments and Contingencies, for more information. Additionally, the order required WPS to terminate its decoupling mechanism, beginning January 1, 2014.

2013 Rates

In December 2012, the PSCW issued a final written order for WPS, effective January 1, 2013. The order included a $28.5 million retail electric rate increase, partially offset by the actual 2012 fuel refund of $20.5 million. The difference between the 2012 fuel refund and the rate increase was deferred for recovery in 2014 rates. As a result, there was no change to customers’ 2013 retail electric rates. The order also included a $3.4 million retail natural gas rate decrease. The order reflected a 10.30% return on common equity and a common equity ratio of 51.61% in WPS’s regulatory capital structure. The rate changes included deferrals of $7.3 million for retail electric and $2.1 million for retail natural gas of pension and other employee benefit costs that are being recovered in 2014 rates. In addition, WPS was authorized recovery of $5.9 million related to income tax amounts previously expensed due to the Federal Health Care Reform Act. As a result, this amount was recorded as a regulatory asset in 2012, and recovery from customers began in 2013. The order also authorized the recovery of direct Cross State Air Pollution Rule costs incurred through the end of 2012. Lastly, the order authorized WPS to switch from production tax credits to Section 1603 Grants for the Crane Creek wind project.

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A decoupling mechanism for natural gas and electric residential and small commercial and industrial customers was approved on a pilot basis as part of the order. The mechanism was based on total rate case-approved margins, rather than being calculated on a per-customer basis. The mechanism did not cover all customer classes, and it included an annual $14.0 million cap for electric service and an annual $8.0 million cap for natural gas service. Amounts recoverable from or refundable to customers were subject to these caps.

Michigan

2015 WPS Rate Case

In October 2014, WPS filed an application with the MPSC to increase retail electric rates $5.7 million, with interim rates expected to be effective in April 2015. WPS’s request reflected a 10.60% return on common equity and a target common equity ratio of 50.48% in WPS’s regulatory capital structure. The proposed retail electric rate increase was primarily driven by the 2013 acquisition of the Fox Energy Center as well as other capital investments associated with the Crane Creek wind farm and environmental upgrades at generating plants. Expenses are expected to increase for line clearance, customer relations, uncollectible expenses, injuries and damages, and general inflation. The proposal included annual rate increases to be implemented over a three-year period.

2014 MGU Rates

In November 2013, the MPSC issued a final written order for MGU, effective January 1, 2014. The order authorized a retail natural gas rate increase of $4.5 million. The rates reflect a 10.25% return on common equity and a common equity ratio of 48.62% in MGU’s regulatory capital structure. Additionally, the order required MGU to terminate its decoupling mechanism after December 31, 2013, and replace it with a new decoupling mechanism based on total margins, beginning January 1, 2015. The new decoupling mechanism does not cover variations in volumes due to actual weather being different from rate case-assumed weather. The rate order also terminated MGU’s uncollectible expense true-up mechanism after December 31, 2013.

MGU Depreciation Case

In January 2013, the Michigan Court of Appeals issued an order reversing the MPSC’s 2010 disallowance of $2.5 million associated with the early retirement of certain MGU assets. As a result, a $2.5 million reduction to depreciation expense was recorded in the first quarter of 2013. In June 2013, the MPSC issued an order related to MGU’s most recent depreciation case. This order also approved a settlement agreement reflecting recovery of these previously disallowed costs.

2014 UPPCO Rates

In December 2013, the MPSC issued a final written order for UPPCO, effective January 1, 2014. The order authorized a retail electric rate increase of $5.8 million. The rates reflected a 10.15% return on common equity and a common equity ratio of 56.74% in UPPCO’s regulatory capital structure. The order required UPPCO to terminate its decoupling mechanism after December 31, 2013. In addition, the order required UPPCO to achieve certain minimum line clearance performance metrics for recovery of costs related to clearing trees and other natural obstructions away from power lines.

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Illinois

2015 Rates

In January 2015, the ICC issued a final written order for PGL and NSG, effective January 28, 2015. The order authorized a retail natural gas rate increase of $74.8 million for PGL and $3.7 million for NSG. In February 2015, the ICC filed an amendatory order that revised the increases to $71.1 million for PGL and $3.5 million for NSG, effective February 26, 2015, to reflect the extension of bonus depreciation in 2014. The rates for PGL reflected a 9.05% return on common equity and a common equity ratio of 50.33% in PGL’s regulatory capital structure. The rates for NSG reflected a 9.05% return on common equity and a common equity ratio of 50.48% in NSG’s regulatory capital structure. The rate orders allowed PGL and NSG to continue the use of their decoupling mechanisms and uncollectible expense true-up mechanisms. In addition, PGL plans to recover a return on certain investments and depreciation expense through the Qualifying Infrastructure Plant rider discussed below, and accordingly, such costs are not subject to PGL’s rate order. In February 2015, the Attorney General and certain intervenors filed requests for rehearing on certain issues, which the ICC will rule on in March 2015.

Qualifying Infrastructure Plant Rider

In July 2013, Illinois Public Act 98-0057 (formerly Senate Bill 2266), The Natural Gas Consumer, Safety & Reliability Act, became law. The Act gave PGL a cost recovery mechanism for prudently incurred costs to upgrade Illinois natural gas infrastructure that are collected through a surcharge on customer bills. This Act eliminated a requirement for PGL and NSG to file biennial rate proceedings under existing Illinois coal-to-gas legislation. In September 2013, PGL filed with the ICC requesting the proposed rider, which was approved in January 2014 and became effective on January 1, 2014.

2013 Rates

In June 2013, the ICC issued a final written order for PGL and NSG, effective June 27, 2013. The order authorized a retail natural gas rate increase of $57.2 million for PGL and $6.6 million for NSG. The rates for PGL reflected a 9.28% return on common equity and a common equity ratio of 50.43% in PGL’s regulatory capital structure. The rates for NSG reflected a 9.28% return on common equity and a common equity ratio of 50.32% in NSG’s regulatory capital structure. The rate order also allowed PGL and NSG to continue the use of their decoupling mechanisms, as affirmed by the Illinois Supreme Court. In addition, the ICC is required to conduct an investigation to monitor the costs and progress of the AMRP.

In August 2013, the ICC granted certain rehearing requests on tax-related issues filed by PGL, NSG, and other intervenors. PGL and NSG asked for a correction of the revenue requirement for deferred tax assets related to tax net operating losses (NOLs) incurred in 2012 and 2013. In the ICC’s order, these deferred tax assets were included in rate base, but computational errors were made. Other intervenors requested the exclusion from rate base of the deferred tax asset related to the 2012 tax NOL. The tax NOLs in question resulted from PGL and NSG claiming accelerated depreciation deductions in 2012 and 2013. In December 2013, the ICC evaluated and approved a correction of the computational errors and rejected the intervenors’ proposed exclusion of the 2012 tax NOL. Customer rates were increased by $2.6 million for PGL and $0.1 million for NSG for the impact of this correction, effective January 1, 2014. In January 2014, the Illinois Attorney General and Citizens Utility Board each filed an appeal with the Illinois Appellate Court (Court). In January 2015, the Citizens Utility Board filed to withdraw its appeal, and the Illinois Attorney General requested an extension of the briefing schedule.

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2012 Decoupling

The ICC issued a final written order, effective January 21, 2012, which approved a permanent decoupling mechanism for PGL and NSG. The Illinois Attorney General and Citizens Utility Board appealed to the Court the ICC’s authority to approve PGL’s and NSG’s decoupling mechanisms and filed a motion to stay the implementation of the permanent decoupling mechanisms or make collections subject to refund. In May 2012, the ICC issued a revised amendatory order granting the Illinois Attorney General’s motion to make revenues collected under the permanent decoupling mechanisms subject to refund. Refunds would have been required if the Court found that the ICC did not have authority to approve decoupling and ordered a refund. As a result, the recovery of amounts related to decoupling in 2012 were uncertain, and PGL and NSG established offsetting reserves equal to decoupling amounts accrued. In March 2013, the Court issued an opinion that affirmed the ICC’s order approving the permanent decoupling mechanisms. As a result, the reserves recorded in 2012 were reversed in the first quarter of 2013. PGL’s and NSG’s permanent decoupling mechanism was in place for 2013. In June 2013, the Illinois Attorney General and Citizens Utility Board petitioned the Illinois Supreme Court to appeal the Court’s decision. In January 2015, the Illinois Supreme Court affirmed the ICC’s authority to approve the permanent decoupling mechanism. As a result, decoupling amounts recorded in 2014 will be refunded to customers in 2015 as planned, and decoupling amounts in the future will continue to be accrued.

Minnesota

2014 Rates

In October 2014, the MPUC issued a final written order, which is expected to become effective in the first half of 2015. The order authorized a retail natural gas rate increase of $7.6 million. The rates reflected a 9.35% return on common equity and a common equity ratio of 50.31% in MERC’s regulatory capital structure. The order allows for a deferral of customer billing system costs, for which the recovery will be requested in a future rate case. A decoupling mechanism with a 10% cap will remain in effect for MERC’s residential and small commercial and industrial customers. The final approved rate increase was lower than the interim rates collected from customers during 2014. Therefore, as of December 31, 2014, $3.1 million is estimated to be refunded to customers during 2015.

2011 Rates Finalized in 2013

In July 2012, the MPUC approved a final written order, effective January 1, 2013. The order authorized a retail natural gas rate increase of $11.0 million. The rates reflected a 9.70% return on common equity and a common equity ratio of 50.48% in MERC’s regulatory capital structure. In addition, the order set recovery of MERC’s 2011 test-year pension expense at 2010 levels. The MPUC also approved a decoupling mechanism for MERC that covers residential and small commercial and industrial customers on a three-year trial basis, effective January 1, 2013. The decoupling mechanism does not adjust for variations in volumes resulting from changes in customer count compared to rate case levels. It includes an annual 10% cap based on distribution revenues approved in the rate case. Amounts recoverable from or refundable to customers are subject to this cap.

Note 26—Miscellaneous Income

Total miscellaneous income was as follows at December 31:

(Millions)	2014		2013		2012
Equity portion of AFUDC	$	12.5	$	10.8	$	2.9
Federal excise tax credit	4.4		4.1		—
Gain on sale of land at the holding company	3.5		—		—
Key executive life insurance income for retired employees	2.9		2.2		2.6
Gains on exchange-traded funds	2.9		2.2		1.3
Other	4.8		2.6		2.2
Total miscellaneous income	$	31.0	$	21.9	$	9.0

Note 27—Variable Interest Entities

In 2012, ITF formed AMP Trillium LLC as a joint venture with AMP Americas LLC. This joint venture was established to own and operate compressed natural gas (CNG) fueling stations. ITF owns 30% and AMP Americas LLC owns 70% of the joint venture. At December 31, 2013, ITF was the primary

59

beneficiary of this variable interest entity, and, as a result, we consolidated the assets, liabilities, and statements of income of the joint venture. However, in April 2014, ITF and AMP Americas LLC restructured this joint venture. Due to the restructuring, our influence over the activities that most significantly impact the variable interest entity’s economic performance decreased. We determined that ITF is no longer the primary beneficiary of this variable interest entity and that we are no longer required to consolidate the joint venture. Therefore, we started accounting for this variable interest entity as an equity method investment in April 2014. At December 31, 2014, and December 31, 2013, our variable interests in the joint venture included an equity investment and receivables. See Note 10, Equity Method Investments, for more information. Our maximum exposure to loss as a result of this joint venture was not significant. In November 2014, ITF sold eight CNG fueling stations to AMP Trillium LLC. See Note 4, Dispositions, for more information.

In 2013, ITF formed EVO Trillium LLC as a joint venture with Environmental Alternative Fuels LLC. ITF owns 15% and Environmental Alternative Fuels LLC owns 85% of the joint venture. This joint venture was established to own and operate CNG fueling stations. We determined that this joint venture is a variable interest entity but that consolidation is not required since we are not its primary beneficiary, as we do not have the power to direct its activities. We instead account for this variable interest entity as an equity method investment. At December 31, 2014, and December 31, 2013, the assets and liabilities on our balance sheets related to our involvement with this variable interest entity consisted of insignificant receivables and payables. Our maximum exposure to loss as a result of involvement with this variable interest entity was also not significant.

Note 28—Segments of Business

At December 31, 2014, we had four segments related to our continuing operations and one segment related to the discontinued operations of IES’s retail energy business. Our reportable segments are described below.

·The natural gas utility segment includes the natural gas utility operations of MERC, MGU, NSG, PGL, and WPS.

·The electric utility segment includes the electric utility operations of UPPCO and WPS. In August 2014, we sold UPPCO to Balfour Beatty Infrastructure Partners LP. See Note 4, Dispositions, for more information on the sale of UPPCO.

·The electric transmission investment segment includes our approximate 34% ownership interest in ATC. ATC is a federally regulated electric transmission company.

·The IES segment includes the nonregulated energy operations of IES’s retail energy business. Since we sold IES’s retail energy business in November 2014, this segment only includes discontinued operations. See Note 4, Dispositions, for more information on the sale of IES’s retail energy business. The remaining energy asset business, PDI, was reclassified to the holding company and other segment.

·The holding company and other segment includes the operations of the Integrys Energy Group holding company, ITF, PDI, and the PELLC holding company, along with any nonutility activities at IBS, MERC, MGU, NSG, PGL, UPPCO, and WPS.

60

All of our operations and assets are located within the United States. The tables below present information related to our reportable segments:

	Regulated Operations											Nonutility and Nonregulated Operations
2014 (Millions)	Natural Gas Utility			Electric Utility			Electric Transmission Investment		Total Regulated Operations			IES		Holding Company and Other			Reconciling Eliminations			Integrys Energy Group Consolidated
Income Statement
External revenues	$	2,748.0		$	1,286.3		$	—	$	4,034.3		$	—	$	109.9		$	—		$	4,144.2
Intersegment revenues	12.4			0.1			—		12.5			—		1.4			(13.9		)	—
Depreciation and amortization expense	149.0			103.0			—		252.0			—		36.0			(0.5		)	287.5
Merger transaction costs	—			—			—		—			—		10.4			—			10.4
Gain on sale of UPPCO, net of transaction costs	—			(85.4		)	—		(85.4		)	—		—			—			(85.4		)
Gain on abandonment of PDI’s Winnebago Energy Center	—			—			—		—			—		(5.0		)	—			(5.0		)
Earnings from equity method investments	—			—			85.7		85.7			—		2.6			—			88.3
Miscellaneous income	1.9			11.1			—		13.0			—		29.8			(11.8		)	31.0
Interest expense	54.4			47.4			—		101.8			—		64.8			(11.8		)	154.8
Provision (benefit) for income taxes	65.6			103.3			34.4		203.3			—		(9.9		)	—			193.4
Net income (loss) from continuing operations	100.7			166.3			51.3		318.3			—		(40.2		)	—			278.1
Discontinued operations	—			—			—		—			0.4		1.4			—			1.8
Preferred stock dividends of subsidiary	(0.5		)	(2.6		)	—		(3.1		)	—		—			—			(3.1		)
Noncontrolling interest in subsidiaries	—			—			—		—			—		0.1			—			0.1
Net income (loss) attributed to common shareholders	100.2			163.7			51.3		315.2			0.4		(38.7		)	—			276.9
Total assets	6,292.5			3,506.9			536.7		10,336.1			—		1,638.1			(692.2		)	11,282.0
Cash expenditures for long-lived assets	456.5			286.6			—		743.1			0.9		121.0			—			865.0

	Regulated Operations											Nonutility and Nonregulated Operations
2013 (Millions)	Natural Gas Utility			Electric Utility			Electric Transmission Investment		Total Regulated Operations			IES		Holding Company and Other			Reconciling Eliminations			Integrys Energy Group Consolidated
Income Statement
External revenues	$	2,094.1		$	1,332.0		$	—	$	3,426.1		$	—	$	59.4		$	—		$	3,485.5
Intersegment revenues	10.9			0.1			—		11.0			—		1.4			(12.4		)	—
Depreciation and amortization expense	136.0			98.6			—		234.6			—		29.3			(0.5		)	263.4
Earnings from equity method investments	—			—			89.1		89.1			—		2.4			—			91.5
Miscellaneous income	1.2			9.8			—		11.0			—		23.3			(12.4		)	21.9
Interest expense	50.2			36.4			—		86.6			—		53.2			(12.4		)	127.4
Provision (benefit) for income taxes	78.9			67.3			35.2		181.4			—		(23.4		)	—			158.0
Net income (loss) from continuing operations	124.0			113.4			53.9		291.3			—		(23.8		)	—			267.5
Discontinued operations	—			—			—		—			82.5		4.8			—			87.3
Preferred stock dividends of subsidiary	(0.6		)	(2.5		)	—		(3.1		)	—		—			—			(3.1		)
Noncontrolling interest in subsidiaries	—			—			—		—			—		0.1			—			0.1
Net income (loss) attributed to common shareholders	123.4			110.9			53.9		288.2			82.5		(18.9		)	—			351.8
Total assets	5,672.0			3,514.4			508.5		9,694.9			815.4		1,519.7			(786.5		)	11,243.5
Cash expenditures for long-lived assets	370.0			615.0			—		985.0			2.6		73.2			—			1,060.8

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	Regulated Operations											Nonutility and Nonregulated Operations
2012 (Millions)	Natural Gas Utility			Electric Utility			Electric Transmission Investment		Total Regulated Operations			IES		Holding Company and Other			Reconciling Eliminations			Integrys Energy Group Consolidated
Income Statement
External revenues	$	1,662.7		$	1,297.4		$	—	$	2,960.1		$	—	$	52.8		$	—		$	3,012.9
Intersegment revenues	9.3			—			—		9.3			—		1.9			(11.2		)	—
Depreciation and amortization expense	131.8			89.0			—		220.8			—		27.0			(0.5		)	247.3
Earnings from equity method investments	—			—			85.3		85.3			—		1.9			—			87.2
Miscellaneous income	0.6			2.6			—		3.2			—		19.9			(14.1		)	9.0
Interest expense	47.3			35.9			—		83.2			—		49.8			(14.1		)	118.9
Provision (benefit) for income taxes	61.4			49.4			32.9		143.7			—		(25.8		)	—			117.9
Net income (loss) from continuing operations	94.0			110.4			52.4		256.8			—		(17.9		)	—			238.9
Discontinued operations	—			—			—		—			55.1		(9.7		)	—			45.4
Preferred stock dividends of subsidiary	(0.6		)	(2.5		)	—		(3.1		)	—		—			—			(3.1		)
Noncontrolling interest in subsidiaries	—			—			—		—			—		0.2			—			0.2
Net income (loss) attributed to common shareholders	93.4			107.9			52.4		253.7			55.1		(27.4		)	—			281.4
Total assets	5,446.2			3,041.3			476.6		8,964.1			493.7		1,523.3			(653.7		)	10,327.4
Cash expenditures for long-lived assets	375.1			163.9			—		539.0			2.0		53.4			—			594.4

Note 29—Quarterly Financial Information (Unaudited)

In November 2014, we sold IES’s retail energy business to Exelon Generation Company, LLC. See Note 4, Dispositions, for more information. Due to the sale, certain previously reported amounts have been retrospectively adjusted as IES’s retail energy business has been reclassified to discontinued operations for all periods presented.

Amounts reflecting IES’s retail energy business in discontinued operations
(Millions, except per share amounts)	First Quarter		Second Quarter			Third Quarter		Fourth Quarter			Total
2014
Operating revenues	$	1,638.0	$	836.8		$	657.1	$	1,012.3		$	4,144.2
Operating income	232.3		23.2			134.6		116.9			507.0
Net income from continuing operations	140.2		8.8			75.3		53.8			278.1
Net income	153.1		8.0			84.0		34.8			279.9
Net income attributed to common shareholders	152.4		7.2			83.3		34.0			276.9
Earnings per common share (basic) *
Net income from continuing operations	$	1.74	$	0.10		$	0.93	$	0.66		$	3.43
Discontinued operations, net of tax	0.16		(0.01		)	0.11		(0.24		)	0.02
Earnings per common share (basic)	1.90		0.09			1.04		0.42			3.45
Earnings per common share (diluted) *
Net income from continuing operations	1.73		0.10			0.91		0.66			3.41
Discontinued operations, net of tax	0.16		(0.01		)	0.11		(0.24		)	0.02
Earnings per common share (diluted)	1.89		0.09			1.02		0.42			3.43
2013
Operating revenues	$	1,136.4	$	708.1		$	622.2	$	1,018.8		$	3,485.5
Operating income	211.8		56.1			41.5		130.1			439.5
Net income from continuing operations	129.6		36.8			26.9		74.2			267.5
Net income (loss)	188.3		(4.7		)	38.8		132.4			354.8
Net income (loss) attributed to common shareholders	187.5		(5.4		)	38.1		131.6			351.8
Earnings (loss) per common share (basic) *
Net income from continuing operations	$	1.64	$	0.45		$	0.33	$	0.91		$	3.33
Discontinued operations, net of tax	0.74		(0.52		)	0.15		0.73			1.10
Earnings (loss) per common share (basic)	2.38		(0.07		)	0.48		1.64			4.43
Earnings (loss) per common share (diluted) *
Net income from continuing operations	1.63		0.45			0.32		0.91			3.30
Discontinued operations, net of tax	0.74		(0.52		)	0.15		0.72			1.09
Earnings (loss) per common share (diluted)	2.37		(0.07		)	0.47		1.63			4.39

*Earnings per share for the individual quarters do not total the year ended earnings per share amount because of changes to the average number of shares outstanding and changes in incremental issuable shares throughout the year.

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Previously reported amounts reflecting IES’s retail energy business in continuing operations
(Millions, except per share amounts)	First Quarter		Second Quarter			Third Quarter			Fourth Quarter		Total
2014
Operating revenues	$	2,924.9	$	1,432.6		$	1,187.9		N/A		N/A
Operating income	253.2		26.1			146.9			N/A		N/A
Net income from continuing operations	153.2		8.1			82.9			N/A		N/A
Net income	153.1		8.0			84.0			N/A		N/A
Net income attributed to common shareholders	152.4		7.2			83.3			N/A		N/A
Earnings per common share (basic) *
Net income from continuing operations	$	1.90	$	0.09		$	1.03		N/A		N/A
Discontinued operations, net of tax	—		—			0.01			N/A		N/A
Earnings per common share (basic)	1.90		0.09			1.04			N/A		N/A
Earnings per common share (diluted) *
Net income from continuing operations	1.89		0.09			1.01			N/A		N/A
Discontinued operations, net of tax	—		—			0.01			N/A		N/A
Earnings per common share (diluted)	1.89		0.09			1.02			N/A		N/A
2013
Operating revenues	$	1,678.2	$	1,116.0		$	1,129.7		$	1,710.7	$	5,634.6
Operating income (loss)	293.1		(6.9		)	55.3			226.2		567.7
Net income (loss) from continuing operations	182.2		(3.9		)	39.4			132.3		350.0
Net income (loss)	188.3		(4.7		)	38.8			132.4		354.8
Net income (loss) attributed to common shareholders	187.5		(5.4		)	38.1			131.6		351.8
Earnings (loss) per common share (basic) *
Net income (loss) from continuing operations	$	2.30	$	(0.06	)	$	0.49		$	1.64	$	4.37
Discontinued operations, net of tax	0.08		(0.01		)	(0.01		)	—		0.06
Earnings (loss) per common share (basic)	2.38		(0.07		)	0.48			1.64		4.43
Earnings (loss) per common share (diluted) *
Net income (loss) from continuing operations	2.29		(0.06		)	0.48			1.63		4.33
Discontinued operations, net of tax	0.08		(0.01		)	(0.01		)	—		0.06
Earnings (loss) per common share (diluted)	2.37		(0.07		)	0.47			1.63		4.39

*Earnings per share for the individual quarters do not total the year ended earnings per share amount because of changes to the average number of shares outstanding and changes in incremental issuable shares throughout the year.

Because of various factors, the quarterly results of operations are not necessarily comparable.

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SCHEDULE I - CONDENSED

PARENT COMPANY FINANCIAL STATEMENTS

INTEGRYS ENERGY GROUP, INC. (PARENT COMPANY ONLY)

A. STATEMENTS OF INCOME

Year Ended December 31
(Millions, except per share data)	2014			2013			2012
Merger transaction costs	$	10.4		$	—		$	—
Operating expense	10.6			8.2			6.0
Gain on sale of UPPCO, net of transaction costs	(85.4		)	—			—
Operating income (loss)	64.4			(8.2		)	(6.0		)
Equity earnings from subsidiaries	303.8			314.6			277.3
Miscellaneous income	23.5			18.5			21.2
Interest expense	63.8			52.1			50.0
Other income	263.5			281.0			248.5
Income before taxes	327.9			272.8			242.5
Provision for income taxes	52.8			8.3			6.5
Net income from continuing operations	275.1			264.5			236.0
Discontinued operations from Parent Company, net of tax	(18.9		)	0.6			1.4
Discontinued operations from subsidiaries, net of tax	20.7			86.7			44.0
Net income attributed to common shareholders	$	276.9		$	351.8		$	281.4
Average shares of common stock
Basic	80.2			79.5			78.6
Diluted	80.7			80.1			79.3
Earnings per common share (basic)
Net income from continuing operations	$	3.43		$	3.33		$	3.00
Discontinued operations, net of tax	0.02			1.10			0.58
Earnings per common share (basic)	$	3.45		$	4.43		$	3.58
Earnings per common share (diluted)
Net income from continuing operations	$	3.41		$	3.30		$	2.98
Discontinued operations, net of tax	0.02			1.09			0.57
Earnings per common share (diluted)	$	3.43		$	4.39		$	3.55

The accompanying notes to the Parent Company financial statements are an integral part of these statements.

1

B. STATEMENTS OF COMPREHENSIVE INCOME

Year Ended December 31
(Millions)	2014			2013			2012
Net income attributed to common shareholders	$	276.9		$	351.8		$	281.4
Other comprehensive income, net of tax:
Cash flow hedges
Unrealized net gains (losses) arising during period, net of tax of $ - million, $ - million, and $0.1 million, respectively	—			0.6			(0.1		)
Reclassification of net (gains) losses to net income, net of tax of $1.2 million, $2.0 million, and $(1.0) million, respectively	(0.1		)	(0.9		)	2.1
Cash flow hedges, net	(0.1		)	(0.3		)	2.0
Defined benefit plans
Pension and other postretirement benefit adjustments arising during period, net of tax of $(5.5) million, $ - million, and $(0.9) million, respectively	(9.6		)	1.1			0.9
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, net of tax of $0.2 million, $0.9 million, and $0.4 million, respectively	0.3			(0.5		)	(0.1		)
Defined benefit pension plans, net	(9.3		)	0.6			0.8
Other comprehensive income (loss) from subsidiaries, net of tax	5.0			17.4			(1.2		)
Other comprehensive income (loss), net of tax	(4.4		)	17.7			1.6
Comprehensive income attributed to common shareholders	$	272.5		$	369.5		$	283.0

The accompanying notes to the Parent Company financial statements are an integral part of these statements.

2

C. BALANCE SHEETS

At December 31
(Millions)	2014		2013
Assets
Cash and cash equivalents	$	5.1	$	0.3
Accounts receivable from related parties	31.2		32.2
Interest receivable from related parties	4.8		4.1
Deferred income taxes	0.4		0.6
Notes receivable from related parties	51.6		84.9
Current portion of long-term notes receivable from related parties	2.5		10.0
Other current assets	49.1		47.8
Current assets	144.7		179.9
Total investments in subsidiaries, at equity	4,015.1		4,268.5
Notes receivable from related parties	180.9		224.3
Property and equipment, net of accumulated depreciation of $1.2 and $1.4, respectively	4.3		4.5
Receivables from related parties	19.2		18.3
Deferred income taxes	9.6		22.3
Other long-term assets	181.2		43.9
Total assets	$	4,555.0	$	4,761.7
Liabilities and Equity
Short-term notes payable to related parties	$	126.2	$	165.7
Short-term debt	7.2		123.2
Current portion of long-term debt	—		100.0
Accounts payable to related parties	5.8		0.9
Accounts payable	2.8		1.2
Deferred income taxes	6.2		6.4
Other current liabilities	43.2		2.8
Current liabilities	191.4		400.2
Long-term debt	974.7		974.7
Deferred income taxes	56.9		110.1
Other long-term liabilities	32.3		15.4
Long-term liabilities	1,063.9		1,100.2
Total common shareholders’ equity	3,299.7		3,261.3
Total liabilities and equity	$	4,555.0	$	4,761.7

The accompanying notes to the Parent Company financial statements are an integral part of these statements.

3

D. STATEMENTS OF CASH FLOWS

Year Ended December 31
(Millions)	2014			2013			2012
Operating Activities
Net income attributed to common shareholders	$	276.9		$	351.8		$	281.4
Adjustments to reconcile net income to net cash provided by operating activities
Equity earnings from subsidiaries	(324.5		)	(401.3		)	(321.3		)
Dividends from subsidiaries	176.5			169.6			163.9
Deferred income taxes and investment tax credits	(46.0		)	26.3			11.0
Gain on sale of UPPCO	(86.5		)	—			—
Loss on sale of IES’s retail energy business	24.3			—			—
Gain on sale of other assets	(4.0		)	—			—
Other	4.9			2.8			(3.7		)
Changes in working capital
Accounts receivable	0.7			(0.7		)	0.4
Accounts receivable from related parties	0.5			0.6			1.0
Other current assets	12.5			(7.9		)	29.0
Accounts payable	1.6			0.6			(0.5		)
Accounts payable to related parties	2.6			(0.2		)	(0.4		)
Other current liabilities	27.6			(2.4		)	0.9
Net cash provided by operating activities	67.1			139.2			161.7
Investing Activities
Short-term notes receivable from related parties	33.3			(50.4		)	(12.1		)
Issuance of long-term notes receivable to related parties	(20.0		)	(35.0		)	—
Repayment of long-term notes receivable from related parties	71.5			44.5			1.3
Equity contributions to subsidiaries	(218.4		)	(234.6		)	(89.9		)
Return of capital from subsidiaries	52.5			75.0			110.5
Proceeds from the sale of UPPCO	336.7			—			—
Proceeds from the sale of IES’s retail energy business	319.2			—			—
Proceeds from the sale of other assets	4.1			—			—
Rabbi trust funding related to potential change in control	(115.5		)	—			—
Net cash provided by (used for) investing activities	463.4			(200.5		)	9.8
Financing Activities
Commercial paper, net	(116.0		)	(85.2		)	115.8
Short-term notes payable to related parties	(45.1		)	(92.3		)	76.2
Repayment of long-term notes payable to related parties	—			—			(21.0		)
Issuance of long-term debt	—			400.0			—
Repayment of long-term debt	(100.0		)	—			(100.0		)
Proceeds from stock option exercises	85.8			38.7			55.8
Shares purchased for stock-based compensation	(127.6		)	—			(75.3		)
Issuance of common stock	2.4			19.2			—
Dividends paid on common stock	(216.3		)	(202.6		)	(211.9		)
Other	(8.9		)	(18.8		)	(10.4		)
Net cash (used for) provided by financing activities	(525.7		)	59.0			(170.8		)
Net change in cash and cash equivalents	4.8			(2.3		)	0.7
Cash and cash equivalents at beginning of year	0.3			2.6			1.9
Cash and cash equivalents at end of year	$	5.1		$	0.3		$	2.6
Cash paid for interest	$	59.4		$	44.4		$	44.4
Cash paid for interest — related parties	0.4			0.7			1.4
Cash paid (received) for income taxes	40.2			(3.0		)	(24.1		)

The accompanying notes to the Parent Company financial statements are an integral part of these statements.

4

SCHEDULE I - CONDENSED

PARENT COMPANY FINANCIAL STATEMENTS

INTEGRYS ENERGY GROUP, INC. (PARENT COMPANY ONLY)

E. NOTES TO PARENT COMPANY FINANCIAL STATEMENTS

SUPPLEMENTAL NOTES

Note 1—Summary of Significant Accounting Policies

(a)  Basis of Presentation—For Parent Company only presentation, investments in subsidiaries are accounted for using the equity method. The condensed Parent Company financial statements and notes should be read in conjunction with the consolidated financial statements and notes of Integrys Energy Group appearing in this Annual Report on Form 10-K. The consolidated income statements of Integrys Energy Group reflect certain businesses as discontinued operations. The condensed Parent Company income statements also report the earnings of these businesses as discontinued operations.

(b)  Cash and Cash Equivalents—Short-term investments with an original maturity of three months or less are reported as cash equivalents.

Note 2—Cash and Cash Equivalents

Significant noncash transactions were:

(Millions)	2014		2013		2012
Equity issued for reinvested dividends	$	—	$	12.0	$	—
Equity issued for stock-based compensation plans	—		16.3		—

The issuance of common stock line item on the Parent Company statements of cash flows does not equal the issuance of common stock line item on the Integrys Energy Group consolidated statements of cash flows. The Parent Company received cash from its subsidiaries and issued common stock to its subsidiaries’ employees to facilitate the employee stock ownership plan. These intercompany amounts were eliminated on the Integrys Energy Group consolidated statements of cash flows.

Note 3—Fair Value of Financial Instruments — Related Parties

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

	2014				2013
(Millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term notes receivable from related parties	$	180.9	$	195.0	$	224.3	$	238.5
Current portion of long-term notes receivable from related parties	2.5		2.8		10.0		10.2

Note 4—Short-Term Notes Receivable — Related Parties

(Millions)	2014		2013
IES	$	—	$	23.5
MGU	26.1		21.8
MERC	11.1		20.5
IBS	14.4		10.2
UPPCO	—		8.9
Total	$	51.6	$	84.9

5

Note 5—Long-Term Notes Receivable — Related Parties

(Millions)	Series		Year Due	2014		2013
WPS Leasing	8.76	%	2015	$	2.0	$	2.4
	7.35	%	2016	3.4		3.9
UPPCO	6.059	%	2017	—		15.0
	3.35	%	2018	—		10.0
	5.041	%	2020	—		15.0
	3.99	%	2023	—		20.0
MERC	6.16	%	2016	29.0		29.0
	6.40	%	2021	29.0		29.0
	3.99	%	2023	29.0		29.0
	3.57	%	2024	20.0		—
MGU	5.76	%	2016	28.0		28.0
	5.98	%	2021	28.0		28.0
	3.00	%	2023	15.0		15.0
IBS	6.865	%	2014	—		10.0
Total notes receivable — related parties				$	183.4	$	234.3
Less current portion				$	2.5	$	10.0
Total long-term notes receivable — related parties				$	180.9	$	224.3

Note 6—Short-term Notes Payable — Related Parties

(Millions)	2014		2013
PELLC	$	43.5	$	165.7
ITF	8.6		—
PDI	74.1		—
Total	$	126.2	$	165.7

6

SCHEDULE II

INTEGRYS ENERGY GROUP, INC.

VALUATION AND QUALIFYING ACCOUNTS

Allowance for Doubtful Accounts

Years Ended December 31, 2014, 2013, and 2012

(In Millions)

			Additions (Subtractions)
Fiscal Year	Balance at Beginning of Year		Charged to Expense		Charged to Other Accounts (1)		Deductions (2)			Balance at End of Year
2012	$	42.5	$	25.9	$	4.0	$	(31.3	)	$	41.1
2013	$	41.1	$	33.7	$	5.5	$	(32.6	)	$	47.7
2014	$	47.7	$	50.3	$	8.0	$	(42.7	)	$	63.3

(1)Represents additions (subtractions) charged to regulatory assets and amounts charged to tax liabilities related to revenue taxes and state use taxes uncollectible from customers.

(2)Represents amounts written off to the reserve, including any adjustments.

7

EX-99.2

Exhibit 99.2

INTEGRYS ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

	Three Months Ended
	March 31
(Millions, except per share data)	2015			2014
Operating revenues	$	1,163.2		$	1,638.0
Cost of sales	577.7			975.6
Operating and maintenance expense	261.0			332.6
Depreciation and amortization expense	74.7			70.6
Taxes other than income taxes	25.6			26.9
Operating income	224.2			232.3
Earnings from equity method investments	17.5			22.9
Miscellaneous income	6.6			5.8
Interest expense	38.2			38.9
Other expense	(14.1		)	(10.2		)
Income before taxes	210.1			222.1
Provision for income taxes	78.9			81.9
Net income from continuing operations	131.2			140.2
Discontinued operations, net of tax	(0.9		)	12.9
Net income	130.3			153.1
Preferred stock dividends of subsidiary	(0.8		)	(0.8		)
Noncontrolling interest in subsidiaries	—			0.1
Net income attributed to common shareholders	$	129.5		$	152.4
Average shares of common stock
Basic	80.2			80.2
Diluted	80.8			80.5
Earnings per common share (basic)
Net income from continuing operations	$	1.62		$	1.74
Discontinued operations, net of tax	(0.01		)	0.16
Earnings per common share (basic)	$	1.61		$	1.90
Earnings per common share (diluted)
Net income from continuing operations	$	1.61		$	1.73
Discontinued operations, net of tax	(0.01		)	0.16
Earnings per common share (diluted)	$	1.60		$	1.89
Dividends per common share declared	$	0.68		$	0.68

The accompanying condensed notes are an integral part of these statements.

1

INTEGRYS ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

	Three Months Ended
	March 31
(Millions)	2015			2014
Net income	$	130.3		$	153.1
Other comprehensive income (loss), net of tax:
Cash flow hedges
Reclassification of net losses (gains) to net income, net of tax of $0.1 million and $0.9 million, respectively	0.1			(0.6		)
Defined benefit plans
Pension and other postretirement benefit costs arising during period, net of tax of an insignificant amount for all periods presented	—			(0.1		)
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, net of tax of $0.5 million and $0.3 million, respectively	0.7			0.3
Defined benefit plans, net	0.7			0.2
Other comprehensive income (loss), net of tax	0.8			(0.4		)
Comprehensive income	131.1			152.7
Preferred stock dividends of subsidiary	(0.8		)	(0.8		)
Noncontrolling interest in subsidiaries	—			0.1
Comprehensive income attributed to common shareholders	$	130.3		$	152.0

The accompanying condensed notes are an integral part of these statements.

2

INTEGRYS ENERGY GROUP, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

	March 31			December 31
(Millions, except share and per share data)	2015			2014
Assets
Cash and cash equivalents	$	86.4		$	18.0
Accounts receivable and accrued unbilled revenues, net of reserves of $58.3 and $63.3, respectively	720.8			699.8
Inventories	179.9			327.2
Regulatory assets	86.2			118.9
Assets held for sale	51.5			52.2
Deferred income taxes	39.8			52.4
Prepaid taxes	51.7			136.2
Other current assets	43.0			57.4
Current assets	1,259.3			1,462.1
Property, plant, and equipment, net of accumulated depreciation of $3,330.2 and $3,322.0, respectively	6,928.8			6,827.7
Regulatory assets	1,507.3			1,513.6
Equity method investments	556.0			550.6
Goodwill	655.4			655.4
Other long-term assets	262.2			272.6
Total assets	$	11,169.0		$	11,282.0
Liabilities and Equity
Short-term debt	$	133.3		$	317.6
Current portion of long-term debt	125.0			125.0
Accounts payable	414.6			490.7
Accrued taxes	108.6			87.7
Regulatory liabilities	171.6			153.7
Liabilities held for sale	13.6			13.8
Other current liabilities	282.1			261.0
Current liabilities	1,248.8			1,449.5
Long-term debt	2,956.3			2,956.3
Deferred income taxes	1,599.5			1,570.0
Deferred investment tax credits	63.6			60.6
Regulatory liabilities	402.4			399.9
Environmental remediation liabilities	573.2			579.9
Pension and other postretirement benefit obligations	271.2			274.6
Asset retirement obligations	485.0			479.1
Other long-term liabilities	155.3			161.3
Long-term liabilities	6,506.5			6,481.7
Commitments and contingencies
Common stock — $1 par value; 200,000,000 shares authorized; 79,963,091 shares issued; 79,534,171 shares outstanding	80.0			80.0
Additional paid-in capital	2,629.2			2,642.2
Retained earnings	701.1			626.0
Accumulated other comprehensive loss	(26.8		)	(27.6		)
Shares in deferred compensation trust	(20.9		)	(20.9		)
Total common shareholders’ equity	3,362.6			3,299.7
Preferred stock of subsidiary — $100 par value; 1,000,000 shares authorized; 511,882 shares issued; 510,495 shares outstanding	51.1			51.1
Total liabilities and equity	$	11,169.0		$	11,282.0

The accompanying condensed notes are an integral part of these statements.

3

INTEGRYS ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

	Three Months Ended
	March 31
(Millions)	2015			2014
Operating Activities
Net income	$	130.3		$	153.1
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization expense	74.7			71.3
Recoveries and refunds of regulatory assets and liabilities	18.1			54.1
Net unrealized gains on energy contracts	(0.5		)	(19.7		)
Bad debt expense	9.2			19.3
Pension and other postretirement expense	7.7			7.2
Pension and other postretirement contributions	(2.9		)	(68.6		)
Deferred income taxes and investment tax credits	45.2			90.3
Equity income, net of dividends	(4.0		)	(3.9		)
Other	(10.9		)	1.1
Changes in working capital
Collateral on deposit	0.6			(37.0		)
Accounts receivable and accrued unbilled revenues	(38.9		)	(531.5		)
Inventories	146.9			121.6
Other current assets	104.9			(65.3		)
Accounts payable	(40.8		)	272.1
Temporary LIFO liquidation credit	33.5			150.9
Other current liabilities	51.1			54.7
Net cash provided by operating activities	524.2			269.7
Investing Activities
Capital expenditures	(208.8		)	(159.6		)
Capital contributions to equity method investments	(1.7		)	(5.1		)
Withdrawal of restricted cash from Rabbi trust for qualifying payments	10.9			—
Other	2.1			1.4
Net cash used for investing activities	(197.5		)	(163.3		)
Financing Activities
Short-term debt, net	(184.3		)	(4.1		)
Shares purchased for stock-based compensation	(17.5		)	(9.8		)
Payment of dividends
Preferred stock of subsidiary	(0.8		)	(0.8		)
Common stock	(54.1		)	(54.1		)
Other	(1.6		)	(3.3		)
Net cash used for financing activities	(258.3		)	(72.1		)
Net change in cash and cash equivalents	68.4			34.3
Cash and cash equivalents at beginning of period	18.0			22.3
Cash and cash equivalents at end of period	$	86.4		$	56.6
Cash paid for interest	$	13.9		$	13.4
Cash received for income taxes	$	(51.1	)	$	(62.7	)

The accompanying condensed notes are an integral part of these statements.

4

INTEGRYS ENERGY GROUP, INC. AND SUBSIDIARIES

CONDENSED NOTES TO FINANCIAL STATEMENTS (Unaudited)

March 31, 2015

Note 1—Basis of Presentation

As used in these notes, the term “financial statements” refers to the condensed consolidated financial statements. This includes the condensed consolidated statements of income, condensed consolidated statements of comprehensive income, condensed consolidated balance sheets, and condensed consolidated statements of cash flows, unless otherwise noted. In this report, when we refer to “us,” “we,” “our,” or “ours,” we are referring to Integrys Energy Group, Inc.

We prepare our financial statements in conformity with the rules and regulations of the SEC for Quarterly Reports on Form 10-Q and in accordance with 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 management’s opinion, these unaudited financial statements include all adjustments necessary for a fair presentation of financial results. All adjustments are normal and recurring, unless otherwise noted. All intercompany transactions have been eliminated in consolidation.

Reclassifications

The assets and liabilities associated with the potential sale of certain PDI solar assets were reclassified as held for sale on our December 31, 2014 balance sheet to be consistent with the current period presentation. In addition, the operations of IES’s retail energy business were reclassified as discontinued operations on our income statement for the three months ended March 31, 2014. See Note 4, Dispositions, for more information on these sales.

Note 2—Proposed Merger with Wisconsin Energy Corporation

In June 2014, we entered into an Agreement and Plan of Merger (Agreement) with Wisconsin Energy Corporation (Wisconsin Energy). Under this Agreement, upon the close of the transaction our shareholders will receive 1.128 shares of Wisconsin Energy common stock and $18.58 in cash for each share of our common stock then owned. In addition, under the Agreement all of our unvested stock-based compensation awards will fully vest upon the close of the transaction and will be paid out in cash to award recipients. Upon closing of the transaction, our shareholders will own approximately 28% of the combined company, and Wisconsin Energy shareholders will own approximately 72%.

The combined entity will be named WEC Energy Group, Inc. and will serve natural gas and electric customers across Wisconsin, Illinois, Michigan, and Minnesota.

This transaction was approved unanimously by the Boards of Directors of both companies. It was also approved by the shareholders of both companies. In October 2014, the Department of Justice closed its review of the transaction and the Federal Trade Commission granted early termination of the waiting period under the Hart-Scott-Rodino Act. In April 2015, the transaction was approved by the Federal Communications Commission, the FERC, and the MPSC. On April 30, 2015, the transaction was verbally approved by the PSCW subject to certain conditions. A final written order is expected from the PSCW in May 2015. The transaction is still subject to approvals from the ICC and the MPUC, as well as other customary closing conditions. We expect the merger transaction to close by the end of this summer.

5

Note 3—Acquisitions

Purchase of Alliant Energy Corporation’s Natural Gas Distribution Business in Southeast Minnesota

On April 30, 2015, MERC acquired Alliant Energy Corporation’s natural gas distribution business in southeast Minnesota for $13.6 million. The purchase price included a cash payment of $11.0 million and the issuance of a promissory note to Alliant Energy Corporation for $2.6 million. The purchase price was based on the estimated book value as of the closing date and is subject to post-closing adjustments. This transaction was not material to us.

Note 4—Dispositions

Discontinued Operations

See Note 5, Cash and Cash Equivalents, for cash flow information related to discontinued operations.

Holding Company and Other Segment — Potential Sale of Combined Locks Energy Center (Combined Locks)

We are currently pursuing the sale of Combined Locks, a natural gas-fired co-generation facility located in Wisconsin. Combined Locks had $0.7 million of assets that were classified as held for sale on the balance sheets at March 31, 2015, and December 31, 2014, which included inventories and property, plant, and equipment. During each of the three months ended March 31, 2015, and 2014, we recorded after-tax losses of $0.1 million in discontinued operations related to Combined Locks.

IES Segment — Sale of IES Retail Energy Business

In November 2014, we sold IES’s retail energy business to Exelon Generation Company, LLC (Exelon) for $331.8 million, which has been updated for a working capital adjustment made in the first quarter of 2015 and reflected in the tables below. As part of the stock purchase agreement, we provided guarantees expiring during the second quarter of 2015, which supported the IES retail energy business. See Note 12, Guarantees, for more information. We are providing certain administrative and operational services to Exelon during a transition period of up to 15 months after the sale date.

The sale of the retail energy business was the result of a previously announced shift in our strategy to focus on our regulated businesses. Therefore, its results of operations were classified as discontinued operations beginning in the fourth quarter of 2014.

The following table shows the carrying values of the major classes of assets and liabilities included in the sale:

	As of the Closing Date in
(Millions)	November 2014
Cash and cash equivalents	$	7.6
Accounts receivable and accrued unbilled revenues, net of reserves of $1.8	293.4
Inventories	52.2
Current assets from risk management activities	234.8
Other current assets	75.1
Property, plant, and equipment, net of accumulated depreciation of $16.6	4.5
Long-term assets from risk management activities	106.9
Other long-term assets	25.5
Total assets	$	800.0
Accounts payable	$	186.9
Current liabilities from risk management activities	169.7
Accrued taxes	0.8
Other current liabilities	6.7
Long-term liabilities from risk management activities	79.5
Other long-term liabilities	0.3
Total liabilities	$	443.9

6

Included in the sale were commodity contracts that did not meet the GAAP definition of derivative instruments and, therefore, were not reflected on the balance sheets. In accordance with GAAP, expected gains or losses related to nonderivative commodity contracts are not recognized until the contracts are settled.

The following table shows the components of discontinued operations related to the sale of the IES retail energy business recorded on the income statements for the three months ended March 31:

(Millions)	2015			2014
Revenues	$	—		$	1,289.6
Cost of sales	—			(1,234.8		)
Operating and maintenance expense	(1.2		)	(32.0		)
Depreciation and amortization expense	—			(0.7		)
Taxes other than income taxes	(0.2		)	(1.2		)
Miscellaneous income	0.1			0.2
Interest expense	—			(0.2		)
(Loss) income before taxes	(1.3		)	20.9
Benefit (provision) for income taxes	0.5			(7.9		)
Discontinued operations, net of tax	$	(0.8	)	$	13.0

Dispositions

Holding Company and Other Segment — Potential Sale of Certain PDI Solar Assets

In the first quarter of 2015, management began implementing a plan to sell certain solar assets owned by PDI. The potential sale of these assets meets the criteria in the accounting guidance to qualify as held for sale but does not meet the requirements to qualify as discontinued operations. The potential sale of these assets does not represent a shift in our corporate strategy and will not have a major effect on our operations and financial results. Therefore, the results of operations of the PDI solar assets will remain in continuing operations.

The following table shows the carrying values of the major classes of assets and liabilities included as held for sale on the balance sheets:

(Millions)	March 31, 2015		December 31, 2014
Property, plant, and equipment, net of accumulated depreciation of $22.1 and $21.1, respectively	$	31.1	$	32.1
Equity method investments	18.5		18.2
Other long-term assets	1.2		1.2
Total assets	$	50.8	$	51.5
Current liabilities	$	0.3	$	0.3
Deferred investment tax credits	4.7		5.0
Asset retirement obligations	1.1		1.1
Other long-term liabilities	7.5		7.4
Total liabilities	$	13.6	$	13.8

Electric Utility Segment — Sale of UPPCO

In August 2014, we sold all of the stock of UPPCO to Balfour Beatty Infrastructure Partners LP for $336.7 million. Following the sale, we are providing certain administrative and operational services to UPPCO during a transition period of 18 to 30 months. The sale of UPPCO was evaluated for accounting purposes prior to our early adoption of ASU 2014-08. UPPCO met the criteria in the accounting guidance to qualify as held for sale but did not meet the requirements to qualify as discontinued operations as WPS has significant continuing cash flows related to certain power purchase transactions with UPPCO that continued after the sale. Therefore, UPPCO’s results of operations through the sale date remain in continuing operations.

Note 5—Cash and Cash Equivalents

Short-term investments with an original maturity of three months or less are reported as cash equivalents.

7

Continuing Operations

Significant noncash transactions related to continuing operations were:

	Three Months Ended March 31
(Millions)	2015		2014
Construction costs funded through accounts payable	$	134.0	$	92.3
ITF fueling station sale financed with note receivable	2.8		—
Equity issued for employee stock ownership plan	—		1.7

At March 31, 2015, restricted cash of $12.5 million was recorded within other long-term assets on our balance sheet. This amount was held in the rabbi trust and represents a portion of the required funding for the rabbi trust that was triggered by the announcement of the proposed merger with Wisconsin Energy Corporation. See Note 2, Proposed Merger with Wisconsin Energy Corporation, for more information about the proposed merger. See Note 13, Employee Benefit Plans, for more information on the rabbi trust funding requirements.

Discontinued Operations

Significant noncash transactions and other information related to discontinued operations are disclosed below. There were no significant investing activities for the periods presented.

	Three Months Ended March 31
(Millions)	2015		2014
Operating Activities
Net unrealized gains on energy contracts	$	—	$	(19.6	)
Deferred income taxes and investment tax credits	—		11.5
Other	1.3		6.7

Note 6—Investment in ATC

Our electric transmission investment segment consists of WPS Investments LLC’s ownership interest in ATC, which was approximately 34% at March 31, 2015. ATC is a for-profit, transmission-only company regulated by FERC.

The following table shows changes to our investment in ATC:

	Three Months Ended March 31
(Millions)	2015		2014
Balance at the beginning of period	$	536.7	$	508.4
Add: Earnings from equity method investment	17.0		22.5
Add: Capital contributions	1.7		5.1
Less: Dividends received	13.6		18.4
Balance at the end of period	$	541.8	$	517.6

ATC is currently named in a complaint filed with the FERC requesting a reduction in the base return on equity (ROE) used by MISO transmission owners to 9.15%. ATC’s current authorized ROE is 12.2%. Although we are currently unable to determine how the FERC may rule in this complaint, we believe it is probable that a refund will be required upon resolution of this issue, based on rulings in a similar complaint. As a result, our equity earnings and corresponding equity method investment in ATC reflect the impact of a reduction to earnings based on this issue. Our equity earnings for the first quarter of 2015 also included a reduction of $4.8 million related to prior years due to a revision to the estimated refund.

Financial data for all of ATC is included in the following tables:

	Three Months Ended March 31
(Millions)	2015		2014
Income statement data
Revenues	$	152.4	$	163.3
Operating expenses	80.0		78.6
Other expense	24.4		21.6
Net income	$	48.0	$	63.1

8

(Millions)	March 31, 2015		December 31, 2014
Balance sheet data
Current assets	$	69.4	$	66.4
Noncurrent assets	3,779.3		3,728.7
Total assets	$	3,848.7	$	3,795.1
Current liabilities	$	325.7	$	313.1
Long-term debt	1,701.0		1,701.0
Other noncurrent liabilities	188.9		163.8
Shareholders’ equity	1,633.1		1,617.2
Total liabilities and shareholders’ equity	$	3,848.7	$	3,795.1

Note 7—Inventories

PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the Last-in, First-out (LIFO) cost method. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. At March 31, 2015, we had a temporary LIFO liquidation credit of $33.5 million recorded within other current liabilities on our balance sheet. Due to seasonality requirements, PGL and NSG expect interim reductions in LIFO layers to be replenished by year end.

Note 8—Goodwill and Other Intangible Assets

We had no changes to the carrying amount of goodwill during the three months ended March 31, 2015, and 2014.

The identifiable intangible assets other than goodwill listed below are part of other long-term assets on the balance sheets.

	March 31, 2015							December 31, 2014
(Millions)	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Amortized intangible assets
Contractual service agreements (1)	$	15.6	$	(5.1	)	$	10.5	$	15.6	$	(4.3	)	$	11.3
Customer-owned equipment modifications (2)	4.0		(1.2		)	2.8		4.0		(1.2		)	2.8
Intellectual property (3)	3.4		(0.9		)	2.5		3.4		(0.8		)	2.6
Nonregulated easements (4)	3.9		(1.5		)	2.4		3.9		(1.4		)	2.5
Compressed natural gas fueling contract assets (5)	5.6		(3.8		)	1.8		5.6		(3.6		)	2.0
Customer-related (6)	1.9		(0.4		)	1.5		1.9		(0.3		)	1.6
Other	0.5		(0.3		)	0.2		0.5		(0.3		)	0.2
Total	$	34.9	$	(13.2	)	$	21.7	$	34.9	$	(11.9	)	$	23.0
Unamortized intangible assets
MGU trade name	$	5.2	$	—		$	5.2	$	5.2	$	—		$	5.2
Trillium trade name (7)	3.5		—			3.5		3.5		—			3.5
Pinnacle trade name (7)	1.5		—			1.5		1.5		—			1.5
Other	0.4		—			0.4		—		—			—
Total intangible assets	$	45.5	$	(13.2	)	$	32.3	$	45.1	$	(11.9	)	$	33.2

(1)Represents contractual service agreements that provide for major maintenance and protection against unforeseen maintenance costs related to the combustion turbine generators at the Fox Energy Center. The remaining weighted-average amortization period for these intangible assets at March 31, 2015, was approximately four years.

(2)Relates to modifications made by PDI and ITF to customer-owned equipment. These intangible assets are amortized on a straight-line basis, with a remaining weighted-average amortization period at March 31, 2015, of approximately nine years.

(3)Represents the fair value of intellectual property at ITF related to a system for more efficiently compressing natural gas to allow for faster fueling. The remaining amortization period for these intangible assets at March 31, 2015, was approximately seven years.

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(4)Relates to easements supporting a pipeline at PDI. The easements are amortized on a straight-line basis, with a remaining amortization period at March 31, 2015, of approximately nine years.

(5)Represents the fair value of ITF contracts acquired in September 2011. The remaining amortization period for these intangible assets at March 31, 2015, was approximately six years.

(6)Represents customer relationship assets associated with ITF’s compressed natural gas fueling operations. The remaining weighted-average amortization period for customer-related intangible assets at March 31, 2015, was approximately 12 years.

(7)Trillium USA (Trillium) and Pinnacle CNG Systems (Pinnacle) are wholly-owned subsidiaries of ITF.

The table below shows the amortization we recorded:

	Three Months Ended March 31
(Millions)	2015		2014
Amortization recorded in cost of sales	$	0.3	$	0.3
Amortization recorded in depreciation and amortization expense	0.7		0.7
Amortization recorded in regulatory assets	0.3		—

The following table shows our estimated amortization for the next five years, including amounts recorded through March 31, 2015:

	For the Year Ending December 31
(Millions)	2015		2016		2017		2018		2019
Amortization to be recorded in cost of sales	$	1.1	$	0.9	$	0.9	$	0.8	$	0.6
Amortization to be recorded in depreciation and amortization expense	3.0		2.9		2.4		1.9		1.9
Amortization to be recorded in regulatory assets	1.0		1.0		0.5		—		—

Note 9—Short-Term Debt and Lines of Credit

Our outstanding short-term borrowings were as follows:

(Millions, except percentages)	March 31, 2015			December 31, 2014
Commercial paper	$	133.3	*	$	317.6
Average interest rate on commercial paper outstanding	0.37		%	0.36		%

*Maturity dates ranged from April 1, 2015, through April 14, 2015.

Our average amount of commercial paper borrowings based on daily outstanding balances during the three months ended March 31, 2015, and 2014, was $189.5 million and $247.1 million, respectively.

We manage our liquidity by maintaining adequate external financing commitments. The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing program, including remaining available capacity under these facilities:

(Millions)	Maturity	March 31, 2015		December 31, 2014
Revolving credit facility (Integrys Energy Group)	06/13/2017	$	285.0	$	285.0
Revolving credit facility (Integrys Energy Group) *	05/08/2019	465.0		465.0
Revolving credit facility (WPS)	05/08/2019	135.0		135.0
Revolving credit facility (WPS)	06/13/2017	115.0		115.0
Revolving credit facility (PGL)	06/13/2017	250.0		250.0
Total short-term credit capacity		$	1,250.0	$	1,250.0
Less:
Letters of credit issued inside credit facilities		$	0.7	$	3.4
Commercial paper outstanding		133.3		317.6
Available capacity under existing agreements		$	1,116.0	$	929.0

*This credit facility was reduced by $200.0 million in April 2015 due to the transfer of the remaining credit support for IES’s retail energy business to Exelon Generation Company, LLC.

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Note 10—Income Taxes

We calculate our interim period provision for income taxes based on our projected annual effective tax rate as adjusted for certain discrete items.

The table below shows our effective tax rates attributable to continuing operations:

	Three Months Ended March 31
	2015		2014
Effective tax rate	37.6	%	36.9	%

Our effective tax rate normally differs from the federal statutory tax rate of 35% due to additional provision for multistate income tax obligations. No other items had a significant impact on our effective tax rates during the three months ended March 31, 2015, and 2014.

During the three months ended March 31, 2015, there was not a significant change in our liability for unrecognized tax benefits.

Note 11—Commitments and Contingencies

(a) Unconditional Purchase Obligations and Purchase Order Commitments

We and our subsidiaries routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. The natural gas utilities have obligations to distribute and sell natural gas to their customers, and our electric utility has obligations to distribute and sell electricity to its customers. The utilities expect to recover costs related to these obligations in future customer rates.

The following table shows our minimum future commitments related to these purchase obligations as of March 31, 2015, including those of our subsidiaries.

				Payments Due By Period
(Millions)	Year Contracts Extend Through	Total Amounts Committed		2015		2016		2017		2018		2019		Later Years
Natural gas utility supply and transportation	2028	$	664.6	$	128.8	$	171.7	$	134.4	$	79.6	$	52.3	$	97.8
Electric utility
Purchased power	2029	806.1		92.1		42.7		53.3		55.9		57.1		505.0
Coal supply and transportation	2019	155.8		44.3		34.8		33.5		32.1		11.1		—
Total		$	1,626.5	$	265.2	$	249.2	$	221.2	$	167.6	$	120.5	$	602.8

(b) Environmental Matters

Air Permitting Violation Claims

Weston and Pulliam Clean Air Act (CAA) Issues:

In November 2009, the EPA issued a Notice of Violation (NOV) to WPS, which alleged violations of the CAA’s New Source Review requirements relating to certain projects completed at the Weston and Pulliam plants from 1994 to 2009. WPS reached a settlement agreement with the EPA regarding this NOV and signed a Consent Decree. This Consent Decree was approved by the U.S. District Court (Court) in March 2013, after a public comment period. The final Consent Decree includes:

·the installation of emission control technology, including ReACT™, at Weston 3,

·changed operating conditions (including refueling, repowering, and/or retirement of units),

·limitations on plant emissions,

·beneficial environmental projects totaling $6.0 million, and

·a civil penalty of $1.2 million.

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As mentioned above, the Consent Decree contains a requirement to refuel, repower, and/or retire certain Weston and Pulliam units. WPS announced that certain Weston and Pulliam units mentioned in the Consent Decree will be retired early, in June 2015. WPS received approval from the PSCW in its 2015 rate order to defer and amortize the undepreciated book value of the retired plant associated with Pulliam 5 and 6 and Weston 1 starting with the actual retirement date in 2015 and concluding by 2023.

WPS received approval from the PSCW in its 2014 and 2015 rate orders to recover prudently incurred costs as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty. We also believe that additional prudently incurred costs expected after 2015 will be recoverable from customers based on past precedent with the PSCW.

The majority of the beneficial environmental projects proposed by WPS have been approved by the EPA. Amounts have been accrued and recorded to regulatory assets, excluding costs associated with capital projects.

In May 2010, WPS received from the Sierra Club a Notice of Intent to file a civil lawsuit based on allegations that WPS violated the CAA at the Weston and Pulliam plants. WPS entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended in October 2012, but no further action has been taken by the Sierra Club as of March 31, 2015. It is unknown whether the Sierra Club will take further action in the future.

Columbia and Edgewater CAA Issues:

In December 2009, the EPA issued an NOV to Wisconsin Power and Light (WP&L), the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric and WPS. The NOV alleged violations of the CAA’s New Source Review requirements related to certain projects completed at those plants. WPS, WP&L, and Madison Gas and Electric reached a settlement agreement with the EPA regarding this NOV and signed a Consent Decree. This Consent Decree was approved by the Court in June 2013, after a public comment period. The final Consent Decree includes:

·the installation of emission control technology, including scrubbers at the Columbia plant,

·changed operating conditions (including refueling, repowering, and/or retirement of units),

·limitations on plant emissions,

·beneficial environmental projects, with WPS’s portion totaling $1.3 million, and

·WPS’s portion of a civil penalty and legal fees totaling $0.4 million.

The Consent Decree contains a requirement to refuel, repower, or retire Edgewater 4, of which WPS is a joint owner, by no later than December 31, 2018. In the first quarter of 2015, management of the joint owners recommended that the Edgewater 4 unit be retired in December 2018. However, a final decision on how to address the requirement for this unit has not yet been made by the joint owners, as early retirement is contingent on various operational and market factors, and other alternatives to retirement are still available.

We believe that significant costs prudently incurred as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty, will be recoverable from customers.

All of the beneficial environmental projects proposed by WPS have been approved by the EPA. Amounts have been accrued and recorded to regulatory assets, excluding costs associated with capital projects.

Weston Title V Air Permit:

In August 2013, the WDNR issued the Weston Title V air permit. In September 2013, WPS challenged various requirements in the permit by filing a contested case proceeding with the WDNR and also filed a Petition for Judicial Review in the Brown County Circuit Court. The Sierra Club and Clean Wisconsin also challenged various aspects of the permit. The WDNR granted all parties’ requests for contested case proceedings. The Petitions for Judicial Review, by all parties, have been stayed pending the resolution of the contested cases. In February 2014, WPS also requested a modification to the construction permit for Weston 4 to remove the mercury Best Available Control Technology (BACT) emission limit requirement. This permit request was denied by the WDNR, and WPS challenged this issue as well. At WPS’s request, the permit was modified to resolve several of the petition issues. Those issues have now been voluntarily dismissed from the case, while a new permit change was challenged and added to the case. The administrative law judge (ALJ) recently dismissed some of the petition issues relating to the averaging period and monitoring issues.

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In May 2014, the WDNR issued an NOV alleging that WPS failed to maintain a minimum sorbent feed rate prior to the Continuous Emissions Monitoring System certification. The WDNR also issued a Notice of Inquiry (NOI) to WPS alleging that WPS failed to comply with reporting requirements related to challenged matters in the 2013 Weston Title V permit. The ALJ denied WPS’s request to issue a stay or confirm that a statutory stay applies to the requirements identified in the NOV and NOI. The contested case is proceeding and certain legal arguments are currently being addressed in the context of summary judgment motions. No hearing date has been set.

We do not expect these matters to have a material impact on our financial statements.

Mercury and Interstate Air Quality Rules

Mercury and Other Hazardous Air Pollutants:

In December 2011, the EPA issued the final Utility Mercury and Air Toxics Standards (MATS), which regulates emissions of mercury and other hazardous air pollutants beginning in April 2015. The State of Wisconsin recently revised the compliance dates in the state mercury rule to be consistent with the MATS rule. Projects approved and initiated to address the State of Wisconsin mercury rule are expected to ensure compliance with the mercury limits in the MATS rule. WPS placed in service capital projects for its wholly owned plants in 2015 to achieve the required reductions for MATS compliance in April 2015. These capital costs are expected to be recovered in future rates.

Sulfur Dioxide and Nitrogen Oxide:

In July 2011, the EPA issued a final rule known as the Cross State Air Pollution Rule (CSAPR), which numerous parties, including WPS, challenged in the United States Court of Appeals (Court of Appeals) for the District of Columbia Circuit (D.C. Circuit). The new rule was to become effective in January 2012. However, in December 2011, the CSAPR requirements were stayed by the D.C. Circuit and a previous rule, the Clean Air Interstate Rule (CAIR), was implemented during the stay period. In August 2012, the D.C. Circuit issued their ruling vacating and remanding CSAPR and simultaneously reinstating CAIR pending the issuance of a replacement rule by the EPA. The case was appealed to the United States Supreme Court (Supreme Court), and in April 2014, the Supreme Court upheld the CSAPR rule and remanded the case to the Court of Appeals for the D.C. Circuit. In October 2014, the Court of Appeals granted the EPA’s request to lift the stay on CSAPR and changed the compliance deadlines by three years, so that Phase 1 emissions budgets apply in 2015 and 2016, and Phase 2 emissions budgets will apply to 2017 and beyond. We do not expect to incur significant costs to comply with either phase of CSAPR and expect to recover any future compliance costs in future rates.

Under CAIR, units affected by the Best Available Retrofit Technology (BART) rule were considered in compliance with BART for sulfur dioxide and nitrogen oxide emissions if they were in compliance with CAIR. This determination was updated when CSAPR was issued (CSAPR satisfied BART). Although particulate emissions also contribute to visibility impairment, the WDNR’s modeling for Pulliam Unit 8, the only unit covered by BART, has shown the impairment to be so insignificant that additional capital expenditures or controls may not be warranted.

Clean Water Act Rule

In August 2014, the EPA issued a final Clean Water Act rule, which established requirements under Section 316(b) to regulate water intake structures at industrial facilities that use large volumes of surface water as cooling water. The new rule became effective in October 2014 and has been challenged by a number of parties. The cases have been consolidated and will be heard in the United States Court of Appeals for the Second Circuit. To the extent that the rule is upheld, WPS will comply with the rule on the timeline required under the regulation. WPS will evaluate the impact of compliance by conducting the studies required by the rule at its facilities. WPS anticipates that the timing for compliance will be incorporated into future wastewater discharge permit renewals. We do not expect to incur significant costs to comply with the Clean Water Act rule at WPS’s Weston plant as this plant already has two units equipped with cooling towers that assist with meeting these new requirements. We expect to recover any future compliance costs in future rates.

Manufactured Gas Plant Remediation

Our natural gas utilities, their predecessors, and certain former affiliates operated facilities in the past at multiple sites for the purpose of manufacturing and storing manufactured gas. In connection with these activities, waste materials were produced that may have resulted in soil and groundwater contamination at these sites. Under certain laws and regulations relating to the protection of the environment, our natural gas utilities are required to undertake remedial action with respect to some of these materials. The natural gas utilities are coordinating the investigation and

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cleanup of the sites subject to EPA jurisdiction under what is called a “multisite” program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies.

Our natural gas utilities are responsible for the environmental remediation of 53 sites, of which 20 have been transferred to the EPA Superfund Alternative Sites Program. Under the EPA’s program, the remedy decisions at these sites will be made using risk-based criteria typically used at Superfund sites. Our balance sheet includes liabilities of $573.0 million that we have estimated and accrued for as of March 31, 2015, for future undiscounted investigation and cleanup costs for all sites. We may adjust these estimates in the future due to remedial technology, regulatory requirements, remedy determinations, and any claims of natural resource damages. As of March 31, 2015, cash expenditures for environmental remediation not yet recovered in rates were $43.1 million. Our balance sheet also includes a regulatory asset of $616.1 million at March 31, 2015, which is net of insurance recoveries, related to the expected recovery through rates of both cash expenditures and estimated future expenditures.

Management believes that any costs incurred for environmental activities relating to former manufactured gas plant operations that are not recoverable through contributions from other entities or from insurance carriers have been prudently incurred and are, therefore, recoverable through rates for MGU, NSG, PGL, and WPS. Accordingly, we do not expect these costs to have a material impact on our financial statements. However, any changes in the approved rate mechanisms for recovery of these costs, or any adverse conclusions by the various regulatory commissions with respect to the prudence of costs actually incurred, could materially affect recovery of such costs through rates.

Note 12—Guarantees

The following table shows our outstanding guarantees:

	Total Amounts Committed at		Expiration
(Millions)	March 31, 2015		Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees supporting commodity transactions of subsidiaries (1)	$	162.5	$	91.2	$	—	$	71.3
Standby letters of credit (2)	1.2		1.1		0.1		—
Surety bonds (3)	25.1		25.1		—		—
Guarantees temporarily retained related to the sale of IES’s retail energy business (4)	55.7		38.6		0.8		16.3
Other guarantees (5)	62.4		—		—		62.4
Total guarantees	$	306.9	$	156.0	$	0.9	$	150.0

(1)Consists of (a) $5.0 million to support each of the business operations of IBS and PDI and (b) $0.4 million, $108.9 million, and $43.2 million related to natural gas supply at ITF, MERC, and MGU, respectively. These guarantees are not reflected on our balance sheets.

(2)At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. This amount consists of standby letters of credit issued to support ITF, MERC, MGU, NSG, PDI, PGL, and WPS. This amount is not reflected on our balance sheets.

(3)Primarily for the construction and operation of compressed natural gas fueling stations, workers compensation self-insurance programs, and obtaining various licenses, permits, and rights-of-way. These guarantees are not reflected on our balance sheets.

(4)These guarantees were retained temporarily due to the sale of IES’s retail energy business to Exelon Generation Company, LLC (Exelon). During the second quarter of 2015, these guarantees will expire. Exelon was contractually bound to reimburse us for any payments made under the outstanding guarantees. At March 31, 2015, these guarantees consisted of (a) $52.1 million of guarantees supporting commodity transactions; (b) $1.2 million of standby letters of credit; (c) $2.1 million of surety bonds; and (d) $0.3 million related to the sale of WPS Beaver Falls Generation, LLC. The liability related to these guarantees was insignificant. Our exposure under these guarantees related to open transactions at March 31, 2015, was $31.5 million.

(5)Consists of (a) $34.2 million to support PDI’s future payment obligations related to its distributed solar generation projects; (b) $10.0 million related to the sale agreement for IES’s Texas retail marketing business. An insignificant liability was recorded related to the possible imposition of additional miscellaneous gross receipts tax in the event of a change in law or interpretation of the law; (c) $11.2 million related to the performance of an operating and maintenance agreement by ITF; and (d) $7.0 million related to other indemnifications primarily for workers compensation coverage. The amounts discussed in items (a), (c), and (d) above are not reflected on our balance sheets.

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Note 13—Employee Benefit Plans

Defined Benefit Plans

The following table shows the components of net periodic benefit cost (including amounts capitalized to our balance sheets) for our benefit plans:

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended March 31						Three Months Ended March 31
(Millions)	2015			2014			2015			2014
Service cost	$	7.6		$	6.6		$	5.8		$	5.9
Interest cost	17.0			19.7			5.3			7.1
Expected return on plan assets	(26.9		)	(28.9		)	(7.9		)	(8.8		)
Loss on plan settlement	0.5			—			—			—
Amortization of prior service cost (credit)	0.1			0.2			(2.6		)	(1.3		)
Amortization of net actuarial loss	10.5			8.4			1.1			0.7
Net periodic benefit cost	$	8.8		$	6.0		$	1.7		$	3.6

Prior service costs (credits) and net actuarial losses that have not yet been recognized as a component of net periodic benefit cost are recorded in accumulated other comprehensive income for our nonregulated entities and as net regulatory assets or liabilities for our regulated utilities.

In March 2014, we remeasured the obligations of certain other postretirement benefit plans as a result of a plan design change to move participants age 65 and older to a Medicare Advantage plan starting January 1, 2015.

Our funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax purposes. During the three months ended March 31, 2015, we contributed $2.8 million to our pension plans and $0.1 million to our other postretirement benefit plans. We expect to contribute an additional $6.3 million to our pension plans and $8.9 million to our other postretirement benefit plans during the remainder of 2015, dependent upon various factors affecting us, including our liquidity position and possible tax law changes. In 2015, contributions of $7.0 million will be funded through a transfer of assets from the rabbi trust for certain nonqualified pension plans, of which $2.2 million was paid to participants through March 31, 2015. See the discussion below in regard to the triggering of the full funding of the rabbi trust.

Rabbi Trust Funding Requirement

The Agreement and Plan of Merger entered into with Wisconsin Energy Corporation in June 2014 triggered the potential change in control provisions in the rabbi trust agreement. These provisions required the full funding of the present value of each participant’s total benefit under the deferred compensation program and certain nonqualified pension plans. As a result, $132.2 million, consisting of cash and exchange-traded funds,  was moved to the rabbi trust during 2014 and was included in other long-term assets on the balance sheet as of March 31, 2015, and December 31, 2014. In 2015, a portion of the amounts contributed to the rabbi trust in 2014 were used to fund participant’s benefits under the deferred compensation program and certain nonqualified pension plans, as discussed above. See Note 2, Proposed Merger with Wisconsin Energy Corporation, for more information on the merger.

Note 14—Stock-Based Compensation

The following table reflects the stock-based compensation expense and the related deferred income tax benefit recognized in income for the three months ended March 31:

	Three Months Ended March 31
(Millions)	2015		2014
Stock options	$	—	$	0.3
Performance stock rights	0.6		0.5
Restricted share units	3.4		2.5
Nonemployee director deferred stock units	0.2		0.2
Total stock-based compensation expense	$	4.2	$	3.5
Deferred income tax benefit	$	1.7	$	1.4

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No stock-based compensation cost was capitalized during the three months ended March 31, 2015, and 2014.

Stock Options

The weighted-average fair value per stock option granted during the three months ended March 31, 2014, was $6.70. No stock options were granted during 2015.

A summary of stock option activity for the three months ended March 31, 2015, and information related to outstanding and exercisable stock options at March 31, 2015, is presented below:

	Stock Options		Weighted-Average Exercise Price Per Share		Weighted-Average Remaining Contractual Life (in Years)	Aggregate Intrinsic Value (Millions)
Outstanding at December 31, 2014	134,017		$	54.31
Exercised	(45,297	)	53.32
Outstanding at March 31, 2015	88,720		$	54.81	6.6	$	1.5
Exercisable at March 31, 2015	53,057		$	54.84	5.9	$	0.9

The aggregate intrinsic value for outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they all exercised their options on March 31, 2015. This is calculated as the difference between our closing stock price on March 31, 2015, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the three months ended March 31, 2015, and 2014 was not significant. Cash received from option exercises during the three months ended March 31, 2015, was $2.7 million, and was not significant for the three months ended March 31, 2014.

Due to the accelerated vesting of all unvested stock options held by active employees in October 2014, all compensation expense related to outstanding stock options has been recognized.

Performance Stock Rights

The fair values of performance stock rights are estimated using a Monte Carlo valuation model. The risk-free interest rate is based on the United States Treasury yield curve. The expected dividend yield incorporates the current and historical dividend rate. The expected stock price volatility is estimated using two to three years of historical data. The table below reflects the assumptions used in the valuation of the outstanding grants at March 31, 2015:

Risk-free interest rate	0.42% – 0.63%
Expected dividend yield	5.25% – 5.33%
Expected volatility	18% – 19%

A summary of the activity for the three months ended March 31, 2015, related to performance stock rights accounted for as equity awards is presented below:

	Performance Stock Rights		Weighted-Average Fair Value *
Outstanding at December 31, 2014	68,263		$	58.54
Distributed	(38,639	)	78.37
Adjustment for payout	12,751		78.37
Outstanding at March 31, 2015	42,375		$	46.42

*Reflects the weighted-average fair value used to measure equity awards. Equity awards are measured using the grant date fair value or the fair value on the modification date.

The weighted-average grant date fair value of performance stock rights awarded during the three months ended March 31, 2014, was $44.28 per performance stock right. No performance stock rights were granted during 2015.

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A summary of the activity for the three months ended March 31, 2015, related to performance stock rights accounted for as liability awards is presented below:

	Performance Stock Rights
Outstanding at December 31, 2014	170,308
Distributed	(1,746	)
Adjustment for payout	831
Outstanding at March 31, 2015	169,393

The weighted-average fair value of all outstanding performance stock rights accounted for as liability awards as of March 31, 2015, was $106.95 per performance stock right.

The total intrinsic value of shares distributed during the three months ended March 31, 2015, was $3.1 million. The actual tax benefit realized for the tax deductions from the distribution of shares during the three months ended March 31, 2015, was not significant. No shares of common stock were distributed for performance stock rights during the three months ended March 31, 2014, because the performance percentage was below the threshold payout level for those rights that were eligible for distribution.

As of March 31, 2015, $3.3 million of compensation cost related to unvested and outstanding performance stock rights (equity and liability awards) was expected to be recognized over a weighted-average period of 1.4 years.

Restricted Share Units

A summary of the activity related to all restricted share unit awards (equity and liability awards) for the three months ended March 31, 2015, is presented below:

	Restricted Share Unit Awards		Weighted-Average Grant Date Fair Value
Outstanding at December 31, 2014	427,305		$	54.45
Granted	224,784		77.17
Dividend equivalents	4,437		65.31
Vested and released	(166,545	)	53.49
Forfeited	(530	)	52.35
Outstanding at March 31, 2015	489,451		$	65.31

The weighted-average grant date fair value of restricted share units awarded during the three months ended March 31, 2015, and 2014, was $77.17 and $55.23 per unit, respectively.

The total intrinsic value of restricted share unit awards vested and released during the three months ended March 31, 2015, and 2014, was $12.8 million and $11.1 million, respectively. The actual tax benefit realized for the tax deductions from the vesting and release of restricted share units during the three months ended March 31, 2015, and 2014, was $5.1 million and $4.4 million, respectively.

As of March 31, 2015, $20.4 million of compensation cost related to unvested and outstanding restricted share units was expected to be recognized over a weighted-average period of 2.2 years.

Note 15—Common Equity

We had no changes to issued common stock during the three months ended March 31, 2015. Under the merger agreement with Wisconsin Energy Corporation (Wisconsin Energy), we cannot issue shares of our common stock.

The following table provides a summary of common stock activity to meet the requirements of our Stock Investment Plan and certain stock-based employee benefit and compensation plans:

Period	Method of meeting requirements
Beginning 02/05/14	Purchasing shares on the open market
02/05/2013 – 02/04/2014	Issued new shares

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The following table reconciles common shares issued and outstanding:

	March 31, 2015			December 31, 2014
	Shares	Average Cost *		Shares	Average Cost *
Common stock issued	79,963,091			79,963,091
Less:
Deferred compensation rabbi trust	428,920	$	48.73	428,920	$	48.73
Total common shares outstanding	79,534,171			79,534,171

*Based on our stock price on the day the shares entered the deferred compensation rabbi trust. Shares paid out of the trust are valued at the average cost of shares in the trust.

Earnings Per Share

Basic earnings per share is computed by dividing net income attributed to common shareholders by the weighted average number of common shares outstanding during the period, adjusted for shares we are obligated to issue under the deferred compensation and restricted share unit plans. Diluted earnings per share is computed in a similar manner, but includes the exercise and/or conversion of all potentially dilutive securities. Such dilutive items include in-the-money stock options, performance stock rights, restricted share units, unvested director deferred stock units, and certain shares issuable under the deferred compensation plan. As the obligation for certain shares issuable under the deferred compensation plan is accounted for as a liability, the numerator is adjusted for any changes in income or loss that would have resulted had it been accounted for as an equity instrument during the period.

The following table reconciles our computation of basic and diluted earnings per share:

	Three Months Ended March 31
(Millions, except per share amounts)	2015			2014
Numerator:
Net income from continuing operations	$	131.2		$	140.2
Discontinued operations, net of tax	(0.9		)	12.9
Preferred stock dividends of subsidiary	(0.8		)	(0.8		)
Noncontrolling interest in subsidiaries	—			0.1
Net income attributed to common shareholders — basic	$	129.5		$	152.4
Effect of dilutive securities
Deferred compensation	(0.6		)	—
Net income attributed to common shareholders — diluted	$	128.9		$	152.4
Denominator:
Average shares of common stock — basic	80.2			80.2
Effect of dilutive securities
Stock-based compensation	0.4			0.3
Deferred compensation	0.2			—
Average shares of common stock — diluted	80.8			80.5
Earnings per common share
Basic	$	1.61		$	1.90
Diluted	1.60			1.89

The calculation of diluted earnings per share excluded the following weighted-average outstanding securities that had an anti-dilutive effect:

	Three Months Ended March 31
(Millions)	2015	2014
Stock-based compensation	—	0.7
Deferred compensation	—	0.3

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Dividend Restrictions

Our ability as a holding company to pay dividends is largely dependent upon the availability of funds from our subsidiaries. Various laws, regulations, and financial covenants impose restrictions on the ability of certain of our regulated utility subsidiaries to transfer funds to us in the form of dividends. Our utility subsidiaries, with the exception of MGU, are prohibited from loaning funds to us, either directly or indirectly.

The PSCW allows WPS to pay dividends on its common stock of no more than 103% of the previous year’s common stock dividend. WPS may return capital to us if its average financial common equity ratio is at least 51% on a calendar-year basis. WPS must obtain PSCW approval if a return of capital would cause its average financial common equity ratio to fall below this level. Our right to receive dividends on the common stock of WPS is also subject to the prior rights of WPS’s preferred shareholders and to provisions in WPS’s restated articles of incorporation, which limit the amount of common stock dividends that WPS may pay if its common stock and common stock surplus accounts constitute less than 25% of its total capitalization.

NSG’s long-term debt obligations contain provisions and covenants restricting the payment of cash dividends and the purchase or redemption of its capital stock.

PGL and WPS have short-term debt obligations containing financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%. Failure to comply with these covenants could result in an event of default which could result in the acceleration of their outstanding debt obligations.

As of March 31, 2015, total restricted net assets of consolidated subsidiaries were $1,872.6 million. Our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method was $158.1 million at March 31, 2015.

We also have short-term and long-term debt obligations that contain financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%. Failure to comply with these covenants could result in an event of default which could result in the acceleration of outstanding debt obligations. At March 31, 2015, these covenants did not restrict our retained earnings or the payment of any dividends.

We have the option to defer interest payments on our outstanding Junior Subordinated Notes, from time to time, for one or more periods of up to ten consecutive years per period. During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, purchase, acquire, or make a liquidation payment on, any of our capital stock.

Under the merger agreement with Wisconsin Energy, we may not declare or pay any dividends or distributions on our common stock other than the regular quarterly dividend of $0.68 per share.

Except for the restrictions described above and subject to applicable law, we do not have any other significant dividend restrictions.

Capital Transactions with Subsidiaries

During the three months ended March 31, 2015, capital transactions with subsidiaries were as follows (in millions):

Subsidiary	Dividends To Parent		Return Of Capital To Parent		Equity Contributions From Parent
ITF (1)	$	—	$	—	$	1.0
MERC	—		10.5		—
MGU	—		13.0		—
NSG (1)	7.5		—		—
WPS	28.8		—		—
WPS Investments, LLC (2)	13.7		—		1.7
Total	$	50.0	$	23.5	$	2.7

(1)ITF and NSG are direct wholly owned subsidiaries of PELLC. As a result, they make distributions to PELLC, and receive equity contributions from PELLC. Subject to applicable law, PELLC does not have any dividend restrictions or limitations on distributions to us.

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(2)WPS Investments, LLC is a consolidated subsidiary that is jointly owned by us and WPS. At March 31, 2015, the ownership interest held by us and WPS was 89.06% and 10.94%, respectively. Distributions from WPS Investments, LLC are made to the owners based on their respective ownership percentages. During 2015, all equity contributions to WPS Investments, LLC were made solely by us.

Note 16—Accumulated Other Comprehensive Loss

The following tables show the changes, net of tax, to our accumulated other comprehensive loss:

Three Months Ended March 31, 2015							Accumulated Other
(Millions)	Cash Flow Hedges			Defined Benefit Plans			Comprehensive Loss
Beginning balance at December 31, 2014	$	(3.2	)	$	(24.4	)	$	(27.6	)
Amounts reclassified out of accumulated other comprehensive loss	0.1			0.7			0.8
Ending balance at March 31, 2015	$	(3.1	)	$	(23.7	)	$	(26.8	)

Three Months Ended March 31, 2014							Accumulated Other
(Millions)	Cash Flow Hedges			Defined Benefit Plans			Comprehensive Loss
Beginning balance at December 31, 2013	$	(3.1	)	$	(20.1	)	$	(23.2	)
Other comprehensive loss before reclassifications	—			(0.1		)	(0.1		)
Amounts reclassified out of accumulated other comprehensive loss	(0.6		)	0.3			(0.3		)
Net current period other comprehensive (loss) income	(0.6		)	0.2			(0.4		)
Ending balance at March 31, 2014	$	(3.7	)	$	(19.9	)	$	(23.6	)

The following table shows the reclassifications out of accumulated other comprehensive loss:

	Amount Reclassified
	Three Months Ended March 31
(Millions)	2015		2014			Affected Line Item in the Statements of Income
Losses (gains) on cash flow hedges
Interest rate hedges	$	0.2	$	0.3		Interest expense
	0.1		0.9			Tax expense
	0.1		(0.6		)	Net of tax
Defined benefit plans
Amortization of prior service costs (credits)	0.3		(0.1		)	*
Amortization of net actuarial losses	0.9		0.7			*
	1.2		0.6			Total before tax
	0.5		0.3			Tax expense
	0.7		0.3			Net of tax
Total reclassifications	$	0.8	$	(0.3	)

*These items are included in the computation of net periodic benefit cost. See Note 13, Employee Benefit Plans, for more information.

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Note 17—Variable Interest Entities

AMP Trillium, LLC

In 2012, ITF formed AMP Trillium, LLC as a joint venture with AMP Americas, LLC. ITF owns 30% and AMP Americas, LLC owns 70% of the joint venture. This joint venture was established to own and operate compressed natural gas (CNG) fueling stations. ITF and AMP Americas, LLC restructured AMP Trillium, LLC in April 2014. We have determined that this joint venture is a variable interest entity but that consolidation is not required since we are not its primary beneficiary, as we do not have the power to direct the activities that most significantly impact its economic performance. We instead account for this variable interest entity as an equity method investment. At March 31, 2015, and December 31, 2014, the assets and liabilities on our balance sheets related to our involvement with this variable interest entity consisted of receivables, payables, and an equity investment. The following table shows the significant assets and liabilities recorded on our balance sheets related to AMP Trillium, LLC:

(Millions)	March 31, 2015		December 31, 2014
Assets
Accounts receivable and accrued unbilled revenues	$	12.1	$	9.5
Other current assets (1)	2.0		2.0
Investment in AMP Trillium, LLC	5.4		5.5
Other long-term assets (1)	11.3		11.8
Liabilities
Accounts payable	2.7		1.4
Other current liabilities (2)	2.1		2.0

(1)Relates to notes receivable due from AMP Trillium, LLC.

(2)Relates to deferred revenue from the sale of CNG fueling stations to AMP Trillium, LLC.

Our maximum exposure to loss as a result of involvement with this variable interest entity was not significant.

EVO Trillium, LLC

In 2013, ITF formed EVO Trillium, LLC as a joint venture with Environmental Alternative Fuels, LLC. ITF owns 15% and Environmental Alternative Fuels, LLC owns 85% of the joint venture. This joint venture was established to own and operate CNG fueling stations. We have determined that this joint venture is a variable interest entity but that consolidation is not required since we are not its primary beneficiary, as we do not have the power to direct the activities that most significantly impact its economic performance. We instead account for this variable interest entity as an equity method investment. At March 31, 2015, and December 31, 2014, the assets and liabilities on our balance sheets related to our involvement with this variable interest entity consisted of receivables and payables. The following table shows the significant assets recorded on our balance sheets related to EVO Trillium, LLC:

(Millions)	March 31, 2015		December 31, 2014
Assets
Accounts receivable and accrued unbilled revenues	$	7.6	$	8.8
Other current assets *	1.1		0.5
Other long-term assets *	4.0		1.7

*Primarily relates to notes receivable due from EVO Trillium, LLC.

Our maximum exposure to loss as a result of involvement with this variable interest entity was not significant.

Note 18—Risk Management Activities

Utility derivatives include natural gas purchase contracts, coal purchase contracts, financial derivative contracts, and financial transmission rights (FTRs). None of these derivatives are designated as hedges for accounting purposes. The electric utility segment uses FTRs to manage electric transmission congestion costs. The natural gas and electric utility segments use financial derivative contracts to manage the risks associated with the market price volatility of natural gas supply costs. In addition, IBS enters into financial derivative contracts on behalf of the utilities to manage the cost of gasoline and diesel fuel used by utility vehicles.

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The following tables show our assets and liabilities from risk management activities at the utilities and IBS:

		March 31, 2015
(Millions)	Balance Sheet Presentation *	Assets from Risk Management Activities		Liabilities from Risk Management Activities
Natural gas contracts	Other current	$	0.5	$	28.0
Natural gas contracts	Other long-term	0.6		5.7
FTRs	Other current	0.7		0.1
Petroleum product contracts	Other current	—		2.1
Coal contracts	Other current	—		4.3
Coal contracts	Other long-term	—		3.1
	Other current	1.2		34.5
	Other long-term	0.6		8.8
Total		$	1.8	$	43.3

*We classify assets and liabilities from risk management activities as current or long-term based on the maturities of the underlying contracts.

		December 31, 2014
(Millions)	Balance Sheet Presentation *	Assets from Risk Management Activities		Liabilities from Risk Management Activities
Natural gas contracts	Other current	$	1.8	$	37.3
Natural gas contracts	Other long-term	0.5		5.3
FTRs	Other current	2.2		0.3
Petroleum product contracts	Other current	—		2.7
Petroleum product contracts	Other long-term	—		0.1
Coal contracts	Other current	—		2.4
Coal contracts	Other long-term	—		1.0
	Other current	4.0		42.7
	Other long-term	0.5		6.4
Total		$	4.5	$	49.1

*We classify assets and liabilities from risk management activities as current or long-term based on the maturities of the underlying contracts.

The following tables show the potential effect on our financial position of netting arrangements for recognized derivative assets and liabilities:

	March 31, 2015
(Millions)	Gross Amount		Potential Effects of  Netting, Including Cash  Collateral		Net Amount
Derivative assets subject to master netting or similar arrangements	$	1.8	$	1.2	$	0.6
Derivative assets not subject to master netting or similar arrangements	—				—
Total risk management assets	$	1.8			$	0.6
Derivative liabilities subject to master netting or similar arrangements	$	35.9	$	5.5	$	30.4
Derivative liabilities not subject to master netting or similar arrangements	7.4				7.4
Total risk management liabilities	$	43.3			$	37.8

	December 31, 2014
(Millions)	Gross Amount		Potential Effects of  Netting, Including Cash  Collateral		Net Amount
Derivative assets subject to master netting or similar arrangements	$	3.2	$	1.3	$	1.9
Derivative assets not subject to master netting or similar arrangements	1.3				1.3
Total risk management assets	$	4.5			$	3.2
Derivative liabilities subject to master netting or similar arrangements	$	45.7	$	8.8	$	36.9
Derivative liabilities not subject to master netting or similar arrangements	3.4				3.4
Total risk management liabilities	$	49.1			$	40.3

Our master netting and similar arrangements have conditional rights of setoff that can be enforced under a variety of situations, including counterparty default or credit rating downgrade below investment grade. We have trade receivables and trade payables, subject to master

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netting or similar arrangements, that are not included in the above tables. These amounts may offset (or conditionally offset) the net amounts presented in the above tables.

Financial collateral provided is restricted to the extent that it is required per the terms of the related agreements. The following table shows our cash collateral positions:

(Millions)	March 31, 2015		December 31, 2014
Cash collateral provided to others: *
Related to contracts under master netting or similar arrangements	$	8.9	$	11.6
Other	1.1		1.1

*Cash collateral provided to others is reflected in other current assets.

Certain of our derivative and nonderivative commodity instruments contain provisions that could require “adequate assurance” in the event of a material change in our creditworthiness, or the posting of additional collateral for instruments in net liability positions, if triggered by a decrease in credit ratings. The aggregate fair value of all derivative instruments with specific credit risk-related contingent features that were in a liability position at March 31, 2015, and December 31, 2014, was $31.4 million and $31.3 million, respectively. At March 31, 2015, and December 31, 2014, we had not posted any cash collateral related to the credit risk-related contingent features of these commodity instruments. If all of the credit risk-related contingent features contained in commodity instruments (including derivatives, nonderivatives, normal purchase and normal sales contracts, and applicable payables and receivables) had been triggered at March 31, 2015, and at December 31, 2014, we would have been required to post collateral of $30.1 million and $27.1 million, respectively.

The notional volumes of outstanding derivative contracts at the utilities and IBS were as follows:

	March 31, 2015		December 31, 2014
(Millions)	Purchases	Other Transactions	Purchases	Other  Transactions
Natural gas (therms)	669.0	N/A	1,860.0	N/A
FTRs (kilowatt-hours)	N/A	2,111.1	N/A	4,287.7
Petroleum products (barrels)	0.1	N/A	0.1	N/A
Coal (tons)	2.6	N/A	3.0	N/A

The table below shows the unrealized gains (losses) recorded related to derivative contracts at the utilities and IBS:

		Three Months Ended March 31
(Millions)	Financial Statement Presentation	2015			2014
Natural gas	Balance Sheet — Regulatory assets (current)	$	10.9		$	0.9
Natural gas	Balance Sheet — Regulatory assets (long-term)	(0.6		)	(0.2		)
Natural gas	Balance Sheet — Regulatory liabilities (current)	(1.5		)	3.4
Natural gas	Balance Sheet — Regulatory liabilities (long-term)	0.1			(0.4		)
Natural gas	Income Statement — Operating and maintenance expense	(0.1		)	0.2
FTRs	Balance Sheet — Regulatory assets (current)	0.2			0.1
FTRs	Balance Sheet — Regulatory liabilities (current)	(0.4		)	(0.1		)
Petroleum	Balance Sheet — Regulatory assets (current)	0.4			—
Petroleum	Income Statement — Operating and maintenance expense	0.4			—
Coal	Balance Sheet — Regulatory assets (current)	(2.6		)	0.2
Coal	Balance Sheet — Regulatory assets (long-term)	(2.0		)	0.4
Coal	Balance Sheet — Regulatory liabilities (long-term)	—			1.6

Note 19—Fair Value

A fair value measurement is required to reflect the assumptions market participants would use in pricing an asset or liability based on the best available information.

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). 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.

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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.

When possible, we base the valuations of our risk management assets and liabilities on quoted prices for identical assets 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 primary reasons for a Level 3 classification are as follows:

·Financial contracts used to manage transmission congestion costs in the MISO market are valued using historical prices.

·The valuations for certain physical coal contracts are based on significant assumptions made to extrapolate prices from the last observable period through the end of the transaction term.

·Certain natural gas contracts are valued using internally-developed inputs due to the absence of available market data for certain locations.

We have established risk oversight committees whose primary responsibility includes directly or indirectly ensuring that all valuation methods are applied in accordance with predefined policies. The development and maintenance of our forward price curves has been assigned to our risk management department, which is part of the corporate treasury function. This department is separate and distinct from any of the supply functions within the organization. To validate the reasonableness of our fair value inputs, our risk management department compares changes in valuation and researches any significant differences in order to determine the underlying cause. Changes to the fair value inputs are made if necessary.

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

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

	March 31, 2015
(Millions)	Level 1		Level 2		Level 3		Total
Assets
Risk Management Assets
Natural gas contracts	$	0.1	$	1.0	$	—	$	1.1
Financial transmission rights (FTRs)	—		—		0.7		0.7
Total Risk Management Assets	$	0.1	$	1.0	$	0.7	$	1.8
Investment in exchange-traded funds	$	112.3	$	—	$	—	$	112.3
Liabilities
Risk Management Liabilities
Natural gas contracts	$	2.3	$	31.4	$	—	$	33.7
Petroleum product contracts	2.1		—		—		2.1
FTRs	—		—		0.1		0.1
Coal contracts	—		1.2		6.2		7.4
Total Risk Management Liabilities	$	4.4	$	32.6	$	6.3	$	43.3

	December 31, 2014
(Millions)	Level 1		Level 2		Level 3		Total
Assets
Risk Management Assets
Natural gas contracts	$	—	$	2.3	$	—	$	2.3
FTRs	—		—		2.2		2.2
Total Risk Management Assets	$	—	$	2.3	$	2.2	$	4.5
Investment in exchange-traded funds	$	102.4	$	—	$	—	$	102.4
Liabilities
Risk Management Liabilities
Natural gas contracts	$	4.8	$	31.2	$	6.6	$	42.6
FTRs	—		—		0.3		0.3
Petroleum product contracts	2.8		—		—		2.8
Coal contracts	—		1.2		2.2		3.4
Total Risk Management Liabilities	$	7.6	$	32.4	$	9.1	$	49.1

The risk management assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO market. See Note 18, Risk Management Activities, for more information.

There were no transfers between the levels of the fair value hierarchy during the three months ended March 31, 2015, and 2014.

The amounts listed in the table below represent the range of unobservable inputs used in the valuations that individually had a significant impact on the fair value determination and caused a derivative to be classified as Level 3 at March 31, 2015:

	Fair Value (Millions)
	Assets		Liabilities		Valuation Technique	Unobservable Input	Average or Range
FTRs	$	0.7	$	0.1	Market-based	Forward market prices ($/megawatt-month) (1)	$159.42
Coal contracts	—		6.2		Market-based	Forward market prices ($/ton) (2)	$9.70 – $12.39

(1)Represents forward market prices developed using historical cleared pricing data from MISO.

(2)Represents third-party forward market pricing.

Significant changes in historical settlement prices or forward coal prices would result in a directionally similar significant change in fair value.

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The following tables set forth a reconciliation of changes in the fair value of items categorized as Level 3 measurements:

Three Months Ended March 31, 2015 (Millions)	Natural Gas  Contracts			FTRs			Coal Contracts			Total
Balance at the beginning of the period	$	(6.6	)	$	1.9		$	(2.2	)	$	(6.9	)
Net realized losses included in earnings	—			(1.2		)	—			(1.2		)
Net unrealized losses recorded as regulatory assets or liabilities	—			(0.2		)	(4.3		)	(4.5		)
Settlements	6.6			0.1			0.3			7.0
Balance at the end of the period	$	—		$	0.6		$	(6.2	)	$	(5.6	)

Three Months Ended March 31, 2014 (Millions)	FTRs			Coal Contracts			Total
Balance at the beginning of the period	$	1.2		$	(2.5	)	$	(1.3	)
Net realized gains included in earnings	0.7			—			0.7
Net unrealized gains recorded as regulatory assets or liabilities	—			2.2			2.2
Purchases	(0.1		)	—			(0.1		)
Settlements	(1.3		)	0.6			(0.7		)
Balance at the end of the period	$	0.5		$	0.3		$	0.8

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

Fair Value of Financial Instruments

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

	March 31, 2015				December 31, 2014
(Millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	3,081.3	$	3,328.0	$	3,081.3	$	3,271.4
Preferred stock of subsidiary	51.1		52.3		51.1		51.8

The fair values of long-term debt instruments are estimated based on the quoted market price for the same or similar issues, or on the current rates offered to us for debt of the same remaining maturity. The fair values of preferred stock are estimated based on quoted market prices when available, or by using a perpetual dividend discount model. The fair values of long-term debt instruments and preferred stock are categorized within Level 2 of the fair value hierarchy.

Due to the short-term nature of cash and cash equivalents, accounts receivable, accounts payable, and outstanding commercial paper, the carrying amount for each of these items approximates fair value.

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Note 20—Regulatory Environment

Wisconsin

2016 Rate Case

In April 2015, WPS filed an application with the PSCW to increase retail electric rates $94.1 million and increase retail natural gas rates $9.4 million, with rates expected to be effective January 1, 2016. WPS’s request reflects a 10.20% return on common equity and a target common equity ratio of 50.52% in WPS’s regulatory capital structure. The proposed retail electric rate increase is primarily driven by the 2016 expected completion of the ReACT™ emission control technology at Weston 3, the System Modernization and Reliability Project, and technology upgrades at the Fox Energy Center. Also included are increases in expenses for electric transmission, customer service, other operating and maintenance, and general inflation. The proposed retail natural gas rate increase is driven by the expiration of a 2015 customer refund related to decoupling, increased operating and maintenance costs, and general inflation.

2015 Rates

In December 2014, the PSCW issued a final written order for WPS, effective January 1, 2015. It authorized a net retail electric rate increase of $24.6 million and a net retail natural gas rate decrease of $15.4 million, reflecting a 10.20% return on common equity. The order also included a common equity ratio of 50.28% in WPS’s regulatory capital structure. The PSCW approved a change in rate design for WPS, which includes higher fixed charges to better match the related fixed costs of providing service.

The primary driver of the increase in retail electric rates was higher costs of fuel for electric generation of approximately $42 million. In addition, 2015 rates include approximately $9 million of lower refunds to customers related to decoupling over-collections. In 2015 rates, WPS is refunding approximately $4 million to customers related to 2013 decoupling over-collections compared with refunding approximately $13 million to customers in 2014 rates related to 2012 decoupling over-collections. Absent these adjustments for electric fuel costs and decoupling refunds, WPS would have realized an electric rate decrease. In addition, WPS received approval from the PSCW to defer and amortize the undepreciated book value associated with Pulliam 5 and 6 and Weston 1 starting with the actual retirement date in 2015 and concluding by 2023. See Note 11, Commitments and Contingencies, for more information. The PSCW is allowing WPS to escrow ATC and MISO network transmission expenses for 2015 and 2016. As a result, WPS defers as a regulatory asset or liability the differences between actual transmission expenses and those included in rates. Finally, the PSCW ordered that 2015 fuel costs should continue to be monitored using a two percent tolerance window.

The retail natural gas rate decrease was driven by the approximate $16 million year-over-year negative impact of decoupling refunds to and collections from customers. In 2015 rates, WPS is refunding approximately $8 million to customers related to 2013 decoupling over-collections compared with recovering approximately $8 million from customers in 2014 rates related to 2012 decoupling under-collections. Absent the adjustment for decoupling refunds to and collections from customers, WPS would have realized a retail natural gas increase.

2014 Rates

In December 2013, the PSCW issued a final written order for WPS, effective January 1, 2014. It authorized a net retail electric rate decrease of $12.8 million and a net retail natural gas rate increase of $4.0 million, reflecting a 10.20% return on common equity. The order also included a common equity ratio of 50.14% in WPS’s regulatory capital structure. The retail electric rate impact consisted of a rate increase, including recovery of the difference between the 2012 fuel refund and the 2013 rate increase, entirely offset by a portion of estimated fuel cost over-collections from customers in 2013. Retail electric rates were further decreased by 2012 decoupling over-collections to be returned to customers in 2014. The retail natural gas rate impact consisted of a rate decrease, which was more than offset by the positive impact of 2012 decoupling under-collections of approximately $8 million to be recovered from customers in 2014. Both the retail electric and retail natural gas rate changes included the recovery of pension and other employee benefit increases that were deferred in the 2013 rate case. The PSCW also authorized the recovery of prudently incurred 2014 environmental mitigation project costs related to compliance with a Consent Decree signed in January 2013 for the Pulliam and Weston sites. See Note 11, Commitments and Contingencies, for more information. Additionally, the order required WPS to terminate its decoupling mechanism, beginning January 1, 2014.

27

Michigan

2015 WPS Rates

In April 2015, the MPSC issued a final written order for WPS, effective April 24, 2015, approving a settlement agreement between WPS and all parties. The order authorized a retail electric rate increase of $4.0 million to be implemented over three years to recover costs for the 2013 acquisition of the Fox Energy Center as well as other capital investments associated with the Crane Creek wind farm and environmental upgrades at generation plants. The rates reflect a 10.20% return on common equity and a target common equity ratio of 50.48% in WPS’s regulatory capital structure. The increase reflects the continued deferral of costs associated with the Fox Energy Center until the second anniversary of the order. The increase also reflects the deferral of Weston 3 ReACT™ environmental project costs. On the second anniversary of the order, WPS will discontinue the deferral of Fox Energy Center costs and will begin amortizing this deferral along with the deferral associated with the termination of a tolling agreement related to the Fox Energy Center. WPS also received approval from the MPSC to defer and amortize the undepreciated book value of the retired plant associated with Pulliam 5 and 6 and Weston 1 starting with the actual retirement date in 2015 and concluding by 2023. Lastly, WPS will not seek to increase retail electric base rates prior to January 1, 2018.

2014 MGU Rates

In November 2013, the MPSC issued a final written order for MGU, effective January 1, 2014. The order authorized a retail natural gas rate increase of $4.5 million. The rates reflected a 10.25% return on common equity and a common equity ratio of 48.62% in MGU’s regulatory capital structure. Additionally, the order required MGU to terminate its decoupling mechanism after December 31, 2013, and replace it with a new decoupling mechanism based on total margins, beginning January 1, 2015. The new decoupling mechanism does not cover variations in volumes due to actual weather being different from rate case-assumed weather. The rate order also terminated MGU’s uncollectible expense true-up mechanism after December 31, 2013.

Illinois

2015 Rates

In January 2015, the ICC issued a final written order for PGL and NSG, effective January 28, 2015. The order authorized a retail natural gas rate increase of $74.8 million for PGL and $3.7 million for NSG. In February 2015, the ICC issued an amendatory order that revised the increases to $71.1 million for PGL and $3.5 million for NSG, effective February 26, 2015, to reflect the extension of bonus depreciation in 2014. The rates for PGL reflect a 9.05% return on common equity and a common equity ratio of 50.33% in PGL’s regulatory capital structure. The rates for NSG reflect a 9.05% return on common equity and a common equity ratio of 50.48% in NSG’s regulatory capital structure. The rate orders allowed PGL and NSG to continue the use of their decoupling mechanisms and uncollectible expense true-up mechanisms. In addition, PGL plans to recover a return on certain investments and depreciation expense through the Qualifying Infrastructure Plant rider discussed below, and accordingly, such costs are not subject to PGL’s rate order. In February 2015, the Attorney General and certain intervenors filed requests for rehearing on certain issues, which the ICC denied in March 2015.

Qualifying Infrastructure Plant Rider

In July 2013, Illinois Public Act 98-0057 (formerly Senate Bill 2266), The Natural Gas Consumer, Safety & Reliability Act, became law. The Act gives PGL a cost recovery mechanism for prudently incurred costs to upgrade Illinois natural gas infrastructure that are collected through a surcharge on customer bills. This Act eliminated a requirement for PGL and NSG to file biennial rate proceedings under existing Illinois coal-to-gas legislation. In September 2013, PGL filed with the ICC requesting the proposed rider, which was approved in January 2014. The rider became effective on January 1, 2014.

28

2013 Rates Amended in 2014

In June 2013, the ICC issued a final written order for PGL and NSG, effective June 27, 2013, which authorized retail natural gas rates for both PGL and NSG. In August 2013, the ICC granted certain rehearing requests on tax-related issues filed by PGL, NSG, and other intervenors. PGL and NSG asked for a correction of the revenue requirement for deferred tax assets related to tax net operating losses (NOLs) incurred in 2012 and 2013. In the ICC’s order, these deferred tax assets were included in rate base, but computational errors were made. Other intervenors requested the exclusion from rate base of the deferred tax asset related to the 2012 tax NOL. The tax NOLs in question resulted from PGL and NSG claiming accelerated depreciation deductions in 2012 and 2013. In December 2013, the ICC evaluated and approved a correction of the computational errors and rejected the intervenors’ proposed exclusion of the 2012 tax NOL. Customer rates were increased by $2.6 million for PGL and $0.1 million for NSG for the impact of this correction, effective January 1, 2014. In January 2014, the Illinois Attorney General and Citizens Utility Board each filed an appeal with the Illinois Appellate Court. In January 2015, the Citizens Utility Board filed to withdraw its appeal, and the Illinois Attorney General requested an extension of the briefing schedule.

Minnesota

2014 Rates

In October 2014, the MPUC issued a final written order, effective April 1, 2015. The order authorized a retail natural gas rate increase of $7.6 million. The rates reflect a 9.35% return on common equity and a common equity ratio of 50.31% in MERC’s regulatory capital structure. The order approved a deferral of customer billing system costs, for which recovery will be requested in a future rate case. A decoupling mechanism with a 10% cap remains in effect for MERC’s residential and small commercial and industrial customers. The final approved rate increase was lower than the interim rates collected from customers during 2014. Therefore, $4.7 million is expected to be refunded to customers beginning in June 2015, and is recorded as a regulatory liability.

Note 21—Segments of Business

At March 31, 2015, we had four segments related to our continuing operations and one segment related to the discontinued operations of IES’s retail energy business. Our reportable segments are described below.

·The natural gas utility segment includes the natural gas utility operations of MERC, MGU, NSG, PGL, and WPS.

·The electric utility segment includes the electric utility operations of WPS, as well as the operations of UPPCO prior to its sale to Balfour Beatty Infrastructure Partners LP in August 2014. See Note 4, Dispositions, for more information on the sale of UPPCO.

·The electric transmission investment segment includes our approximate 34% ownership interest in ATC. ATC is a federally regulated electric transmission company.

·The IES segment includes the nonregulated energy operations of IES’s retail energy business. Since we sold IES’s retail energy business in November 2014, this segment only includes discontinued operations. See Note 4, Dispositions, for more information on the sale of IES’s retail energy business. The remaining energy asset business, PDI, was reclassified to the holding company and other segment.

·The holding company and other segment includes the operations of the Integrys Energy Group holding company, ITF, PDI, and the PELLC holding company, along with any nonutility activities at IBS, MERC, MGU, NSG, PGL, UPPCO, and WPS.

29

The tables below present information related to our reportable segments:

	Regulated Operations											Nonutility and  Nonregulated Operations
(Millions)	Natural Gas Utility			Electric Utility			Electric Transmission Investment		Total Regulated Operations			IES			Holding Company and Other			Reconciling Eliminations			Integrys Energy Group Consolidated
Three Months Ended March 31, 2015
External revenues	$	839.5		$	295.8		$	—	$	1,135.3		$	—		$	27.9		$	—		$	1,163.2
Intersegment revenues	2.6			—			—		2.6			—			0.2			(2.8		)	—
Depreciation and amortization expense	40.6			25.0			—		65.6			—			9.2			(0.1		)	74.7
Earnings from equity method investments	—			—			17.0		17.0			—			0.5			—			17.5
Miscellaneous income	0.7			2.8			—		3.5			—			5.1			(2.0		)	6.6
Interest expense	14.3			10.9			—		25.2			—			15.0			(2.0		)	38.2
Provision (benefit) for income taxes	65.9			16.4			6.7		89.0			—			(10.1		)	—			78.9
Net income (loss) from continuing operations	97.8			28.6			10.3		136.7			—			(5.5		)	—			131.2
Discontinued operations	—			—			—		—			(0.8		)	(0.1		)	—			(0.9		)
Preferred stock dividends of subsidiary	(0.1		)	(0.7		)	—		(0.8		)	—			—			—			(0.8		)
Net income (loss) attributed to common shareholders	97.7			27.9			10.3		135.9			(0.8		)	(5.6		)	—			129.5

	Regulated Operations											Nonutility and  Nonregulated Operations
(Millions)	Natural Gas Utility			Electric Utility			Electric Transmission Investment		Total Regulated Operations			IES		Holding Company and Other			Reconciling Eliminations			Integrys Energy Group Consolidated
Three Months Ended March 31, 2014
External revenues	$	1,267.6		$	349.2		$	—	$	1,616.8		$	—	$	21.2		$	—		$	1,638.0
Intersegment revenues	4.4			—			—		4.4			—		0.4			(4.8		)	—
Depreciation and amortization expense	36.4			25.6			—		62.0			—		8.7			(0.1		)	70.6
Earnings from equity method investments	—			—			22.5		22.5			—		0.4			—			22.9
Miscellaneous income	0.3			3.5			—		3.8			—		5.3			(3.3		)	5.8
Interest expense	13.4			11.7			—		25.1			—		17.1			(3.3		)	38.9
Provision (benefit) for income taxes	66.7			18.1			8.8		93.6			—		(11.7		)	—			81.9
Net income (loss) from continuing operations	99.2			31.8			13.7		144.7			—		(4.5		)	—			140.2
Discontinued operations	—			—			—		—			13.0		(0.1		)	—			12.9
Preferred stock dividends of subsidiary	(0.1		)	(0.7		)	—		(0.8		)	—		—			—			(0.8		)
Noncontrolling interest in subsidiaries	—			—			—		—			—		0.1			—			0.1
Net income (loss) attributed to common shareholders	99.1			31.1			13.7		143.9			13.0		(4.5		)	—			152.4

Note 22—New Accounting Pronouncements

Recently Issued Accounting Guidance Not Yet Effective

In April 2015 the FASB issued ASU 2015-05, “Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement.” The ASU provides guidance for determining whether a cloud computing arrangement includes a software license, which should be accounted for consistent with the acquisition of other software licenses. Cloud computing arrangements that do not include a software license should be accounted for as service contracts. This guidance may be applied either prospectively to new cloud computing arrangements, or retrospectively by restating each prior period presented in the financial statements. The guidance is effective for us for the reporting period ending March 31, 2016. We are currently evaluating the impact that the adoption of this standard will have on our financial statements.

30

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. The standard requires retrospective application by restating each prior period presented in the financial statements. The guidance is effective for us for the reporting period ending March 31, 2016. We are currently evaluating the impact this guidance will have on our financial statements.

In February 2015 the FASB issued ASU 2015-02, “Amendments to the Consolidation Analysis.” The guidance focuses on the consolidation evaluation for companies that are required to evaluate whether they should consolidate certain legal entities. It places more emphasis on risk of loss when determining a controlling financial interest and amends the guidance for assessing how relationships of related parties affect the consolidation analysis of variable interest entities. The guidance is effective for us for the reporting period ending March 31, 2016. We are currently evaluating the impact this guidance will have on our financial statements.

In January 2015 the FASB issued ASU 2015-01, “Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items.” This guidance eliminates the disclosure of extraordinary items, net of tax, in the income statement after income from continuing operations. The guidance is effective for us for the reporting period ending March 31, 2016. We do not currently have any extraordinary items presented on the income statements. However, this guidance will eliminate the need for us to further assess whether unusual and infrequently occurring transactions qualify as extraordinary items in the future.

In May 2014 the FASB issued ASU 2014-09, “Revenue from Contracts with Customers.” This ASU supersedes the requirements in the Revenue Recognition Topic of the FASB ASC and most industry-specific guidance throughout the ASC. 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. The standard requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and cash flows from customer contracts. The guidance is currently effective for us for the reporting period ending March 31, 2017; however, in April 2015 the FASB issued an exposure draft proposing to delay the effective date for one year. The standard requires either retrospective application by restating each prior period presented in the financial statements, or modified retrospective application by recording the cumulative effect of prior reporting periods to beginning retained earnings in the year that the standard becomes effective. We are currently evaluating the impact that the adoption of this standard will have on our financial statements.

31

EX-99.3

Exhibit 99.3

AMERICAN TRANSMISSION COMPANY, LLC

Financial Statements as of December 31, 2014 and 2013 and

for the Years Ended December 31, 2014, 2013 and 2012 and

Independent Auditors’ Report

American Transmission Company, LLC

Table of Contents

Independent Auditors’ Report	3
Financial Statements
Statements of Operations for the Years Ended December 31, 2014, 2013 and 2012	4
Balance Sheets as of December 31, 2014 and 2013	5
Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012	6
Statements of Changes in Members’ Equity for the Years Ended December 31, 2014, 2013 and 2012	7
Notes to Financial Statements as of December 31, 2014 and 2013 and for the Years Ended December 31, 2014, 2013 and 2012	8-35

2

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors of ATC Management Inc.,

Corporate Manager of American Transmission Company, LLC

Pewaukee, Wisconsin

We have audited the accompanying financial statements of American Transmission Company, LLC (the “Company”), which comprise the balance sheets as of December 31, 2014 and 2013, and the related statements of operations, changes in members’ equity, and cash flows for the three years in the period ended December 31, 2014, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America and in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Company’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of American Transmission Company, LLC as of December 31, 2014 and 2013, and the results of their operations and their cash flows for the three years in the period ended December, 31, 2014 in accordance with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Milwaukee, Wisconsin

February 2, 2015

3

American Transmission Company, LLC

Statements of Operations

For the Years Ended December 31, 2014, 2013 and 2012

(In Thousands)

	2014		2013		2012
Operating Revenues
Transmission Service Revenue	$	633,550	$	624,922	$	602,092
Other Operating Revenue	1,483		1,414		1,162
Total Operating Revenues	635,033		626,336		603,254
Operating Expenses
Operations and Maintenance	162,902		161,129		158,271
Depreciation and Amortization	124,074		114,808		107,230
Taxes Other than Income	20,475		19,132		15,769
Income Tax Provision of ATC LLC	—		—		(271		)
Total Operating Expenses	307,451		295,069		280,999
Operating Income	327,582		331,267		322,255
Other Income (Expense), Net	117		831		(2,533		)
Earnings Before Interest and Members’ Income Taxes	327,699		332,098		319,722
Net Interest Expense	88,970		84,484		82,296
Earnings Before Members’ Income Taxes	$	238,729	$	247,614	$	237,426

The accompanying notes are an integral part of these financial statements.

4

American Transmission Company, LLC

Balance Sheets

As of December 31, 2014 and 2013

(In Thousands)

	December 31,			December 31,
ASSETS	2014			2013
Property, Plant and Equipment
Transmission Plant	$	4,400,823		$	4,100,212
General Plant	108,902			106,085
Less- Accumulated Depreciation	(1,022,123		)	(948,024		)
	3,487,602			3,258,273
Construction Work in Progress	180,058			206,530
Net Property, Plant and Equipment	3,667,660			3,464,803
Current Assets
Cash and Cash Equivalents	97			—
Accounts Receivable	55,984			65,779
Prepaid Expenses	6,303			5,363
Current Portion of Regulatory Assets	719			6,443
Other Current Assets	3,307			3,130
Total Current Assets	66,410			80,715
Regulatory and Other Assets
Equity Investment in Unconsolidated Subsidiary	35,317			31,719
Regulatory Assets	9,343			718
Other Assets	16,355			12,277
Total Regulatory and Other Assets	61,015			44,714
Total Assets	$	3,795,085		$	3,590,232
CAPITALIZATION AND LIABILITIES
Capitalization
Members’ Equity (See Note 3 for redemption provisions)	$	1,617,202		$	1,532,598
Long-term Debt (excluding current portion)	1,701,000			1,550,000
Total Capitalization	3,318,202			3,082,598
Current Liabilities
Accounts Payable	11,746			25,150
Accrued Interest	24,198			22,033
Other Accrued Liabilities	42,918			40,063
Current Portion of Regulatory Liabilities	14,299			13,776
Current Maturities of Long-term Debt	100,000			—
Short-term Debt	119,904			280,445
Total Current Liabilities	313,065			381,467
Regulatory and Other Long-term Liabilities
Regulatory Liabilities	146,525			114,890
Other Long-term Liabilities	17,293			11,277
Total Regulatory and Other Long-term Liabilities	163,818			126,167
Commitments and Contingencies (See Note 7)	—			—
Total Capitalization and Liabilities	$	3,795,085		$	3,590,232

The accompanying notes are an integral part of these financial statements.

5

American Transmission Company, LLC

Statements of Cash Flows

For the Years Ended December 31, 2014, 2013 and 2012

(In Thousands)

	2014			2013			2012
Cash Flows from Operating Activities
Earnings Before Members’ Income Taxes	$	238,729		$	247,614		$	237,426
Adjustments to Reconcile Earnings Before Members’ Income Taxes to Net Cash Provided by Operating Activities-
Depreciation and Amortization	124,074			114,808			107,230
Bond Discount and Debt Issuance Cost Amortization	537			488			458
Equity Loss (Earnings) in Unconsolidated Subsidiary Investment	(1,998		)	(1,842		)	1,574
Change in-
Accounts Receivable	9,795			(9,260		)	(5,597		)
Current Assets	5,325			(3,010		)	(679		)
Accounts Payable	(2,545		)	1,576			813
Accrued Liabilities	3,735			6,076			(3,627		)
Other, Net	10,209			9,766			(11,951		)
Total Adjustments	149,132			118,602			88,221
Net Cash Provided by Operating Activities	387,861			366,216			325,647
Cash Flows from Investing Activities
Capital Expenditures for Property, Plant and Equipment	(334,731		)	(328,414		)	(315,808		)
Investment in Unconsolidated Subsidiary	(1,600		)	(32,800		)	(2,350		)
Return of Capital from Unconsolidated Subsidiary	—			3,700			—
Insurance Proceeds Received for Damaged Property, Plant and Equipment	646			—			—
Net Cash Used in Investing Activities	(335,685		)	(357,514		)	(318,158		)
Cash Flows from Financing Activities
Distribution of Earnings to Members	(204,125		)	(195,484		)	(188,246		)
Issuance of Membership Units for Cash	50,000			40,000			60,000
Issuance (Repayment) of Short-term Debt, Net	(160,541		)	113,884			(17,782		)
Issuance of Long-term Debt, Net of Issuance Costs	249,752			—			148,972
Advances Received Under Interconnection Agreements	—			—			2,524
Repayments of Interconnection Agreements	—			—			(12,982		)
Advances Received for Construction	12,797			32,856			—
Other, Net	38			(75		)	(17		)
Net Cash Used in Financing Activities	(52,079		)	(8,819		)	(7,531		)
Net Change in Cash and Cash Equivalents	97			(117		)	(42		)
Cash and Cash Equivalents, Beginning of Period	—			117			159
Cash and Cash Equivalents, End of Period	$	97		$	—		$	117

The accompanying notes are an integral part of these financial statements.

6

American Transmission Company, LLC

Statements of Changes in Members’ Equity

For the Years Ended December 31, 2014, 2013 and 2012

(In Thousands)

Members’ Equity as of December 31, 2011		$	1,331,288
Membership Units Outstanding at December 31, 2011	78,325
Issuance of Membership Units		$	60,000
Earnings Before Members’ Income Taxes		237,426
Distribution of Earnings to Members		(188,246		)
Members’ Equity as of December 31, 2012		$	1,440,468
Membership Units Outstanding at December 31, 2012	82,154
Issuance of Membership Units		$	40,000
Earnings Before Members’ Income Taxes		247,614
Distribution of Earnings to Members		(195,484		)
Members’ Equity as of December 31, 2013		$	1,532,598
Membership Units Outstanding at December 31, 2013	84,614
Issuance of Membership Units		$	50,000
Earnings Before Members’ Income Taxes		238,729
Distribution of Earnings to Members		(204,125		)
Members’ Equity as of December 31, 2014		$	1,617,202
Membership Units Outstanding at December 31, 2014	87,588

The accompanying notes are an integral part of these financial statements.

7

American Transmission Company, LLC

Notes to Financial Statements as of December 31, 2014 and 2013 and for the Years Ended

December 31, 2014, 2013 and 2012

(1)Nature of Operations and Summary of Significant Accounting Policies

(a)General

American Transmission Company, LLC (the “Company”) was organized, as a limited liability company under the Wisconsin Limited Liability Company Act, as a single-purpose, for-profit electric transmission company.  The Company’s purpose is to plan, construct, operate, own and maintain electric transmission facilities to provide an adequate and reliable transmission system that meets the needs of all users on the system and supports equal access to a competitive, wholesale, electric energy market.

The Company currently owns and operates the electric transmission system, under the direction of the Midcontinent Independent System Operator, Inc. (MISO), in parts of Wisconsin, Illinois, Minnesota and the Upper Peninsula of Michigan.  The Company is subject to regulation by the Federal Energy Regulatory Commission (FERC) as to rates, terms of service and financing, and by state regulatory commissions as to other aspects of business, including the construction of electric transmission assets.

The Company’s five largest customers are also members and account for approximately 80% of the Company’s operating revenues.  The rates for these transmission services are subject to review and approval by FERC.  In addition, several members provide operations, maintenance and construction services to the Company.  The agreements under which these services are provided are subject to review and approval by the Public Service Commission of Wisconsin (PSCW).  See Note (8) for details of the various transactions between the Company and its members.

The Company evaluated potential subsequent events through February 2, 2015, which is the date these statements were available to be issued.

(b)Corporate Manager

The Company is managed by a corporate manager, ATC Management Inc. (“Management Inc.”).  The Company and Management Inc. have common ownership and operate as a single functional unit.  Under the Company’s operating agreement, Management Inc. has complete discretion over the business of the Company and provides all management services to the Company at cost.  The Company itself has no employees and no governance structure

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separate from Management Inc.  The Company’s operating agreement establishes that all expenses of Management Inc. are the responsibility of the Company.  These expenses consist primarily of payroll, benefits, payroll-related taxes and other employee-related expenses.  All such expenses are recorded in the Company’s accounts as if they were direct expenses of the Company.

As of December 31, the following net payables to Management Inc. were included in the Company’s balance sheets (in thousands):

	2014		2013
Other Accrued Liabilities	$	14,300	$	13,803
Other Long-term Liabilities	9,436		2,054
Net Amount Payable to Management Inc.	$	23,736	$	15,857

Amounts included in other accrued liabilities are primarily payroll- and benefit-related accruals.  Amounts included in other long-term liabilities relate primarily to certain long-term compensation arrangements covering Management Inc. employees, as described in Note (2), offset by a $14.3 million and $14.5 million receivable as of December 31, 2014 and 2013, respectively, for income taxes paid on Management Inc.’s behalf by the Company.  The income taxes paid are due to temporary differences relating to the tax deductibility of certain employee-related costs.  As these temporary differences reverse in future years, Management Inc. will receive cash tax benefits and will then repay the advances from the Company.

(c)Revenue Recognition

Wholesale electric transmission service for utilities, municipalities, municipal electric companies, electric cooperatives and other eligible entities is provided through the Company’s facilities under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (“MISO Tariff”) regulated by FERC. The Company charges for these services under FERC-approved rates.  The MISO Tariff specifies the general terms and conditions of service on the transmission system and the approved rates set forth the calculation of the amounts to be paid for those services.  The Company does not take ownership of the electricity that it transmits.

The Company’s FERC-approved formula rate tariff (“Company’s Tariff”) for the revenue requirement determined under Attachment O of the MISO Tariff includes a true-up provision that meets the requirements of an alternative revenue program as defined in the Financial Accounting Standards Board’s (FASB) Accounting Standards Codification (ASC) Topic 980, “Regulated Operations.”  Accordingly, revenue is recognized for transmission system access the Company provided during the reporting period based on the revenue requirement formula in the Company’s Tariff.  Annually, the Company prepares a forecast for the upcoming rate year of total operating expenses, projected rate base resulting from planned construction and other capital expenditures, and projected amounts to be received from MISO.  From this forecast, the Company computes an annual projected total revenue requirement for

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the reporting period.  Based on the criteria in the MISO Tariff, the Company also calculates its regional cost-sharing revenue requirements which, in addition to other forecasted revenues from MISO and other sources, are subtracted from the total revenue requirement to determine the Company’s annual network revenue requirement.  The annual network revenue requirement is billed to and collected from network transmission customers in equal monthly installments throughout the rate year.  Subsequent to the rate year, the Company compares actual results from the rate year to the forecast to determine any under- or over-collection of revenue from network and regional customers.  In accordance with ASC Topic 980, the Company accrues or defers revenues that are higher or lower, respectively, than the amounts collected during the reporting period.  An accumulated over-collected true-up balance is classified as a regulatory liability in the balance sheets and an accumulated under-collected true-up balance is classified as a regulatory asset in the balance sheets.  The Company is required to refund any over-collected network amounts, plus interest, within two years subsequent to the rate year, with the option to accelerate all or a portion of any such refund, and is permitted to include any under-collected network amounts, plus interest, in annual network billings two fiscal years subsequent to the rate year.  Under these true-up provisions, the Company refunded to network customers, through their monthly bills, a net amount of $10.4 million in 2014, and $1.3 million and $8.0 million in 2013 and 2012, respectively.  The Company also has FERC-approved true-up provisions for MISO regionally cost-shared revenues to refund over-collections or receive under-collections in the second year following the rate year.  The Company collected, inclusive of interest, a net amount of $2.8 million from regional customers in 2014 and refunded, inclusive of interest, $6.3 million and $5.5 million to regional customers in 2013 and 2012, respectively.  See Note 1(h) for more information on the Company’s true-up provisions.

The Company records a reserve for revenue subject to refund when such refund is probable and can be reasonably estimated.

The Company is currently operating under a settlement agreement approved by FERC in 2004 which limits the rights of interested parties to challenge, through a FERC Section 206 proceeding, the provisions noted above for the term of the agreement.  Certain provisions of the settlement agreement terminated on December 31, 2012; as such, the Company may elect to change, or intervenors may request a change to, the Company’s revenue requirement formula.  A change to the revenue requirement formula could result in lowered rates and have an adverse effect on the Company’s financial position, results of operations and cash flows.  If no filings are made by either the Company or other parties, the current terms of the settlement agreement will continue in effect.

On November 12, 2013, MISO, the Company and numerous other MISO transmission owners were named as respondents in a complaint filed at FERC, pursuant to Section 206 of the Federal Power Act (FPA), by several customer groups located within the MISO service area.  The complaint claims that the respondents’ transmission rates are no longer just and reasonable and seeks, among other things, to reduce the MISO base return on equity (ROE).  The Company and the other MISO transmission owners responded to the complaint with a motion to dismiss and answer objecting to the claims of the complainants.  On October 16, 2014, FERC determined that the complaint raises issues of material fact that cannot be resolved with the information in the record at this point.  As a result,

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FERC put the matter of whether the MISO transmission owner base ROE is unjust and unreasonable to hearing and settlement procedures and established a refund date of November 12, 2013.   However, the settlement process was terminated in December 2014.  FERC ordered hearing proceedings to begin, and an initial decision in the complaint is expected by November 30, 2015.  Further details related to this complaint are discussed in Note 7(a).

(d)Transmission and General Plant and Related Depreciation

Transmission plant is recorded at the original cost of construction.  Assets transferred to the Company primarily by its members, which include investor-owned utilities, municipalities, municipal electric companies and electric cooperatives, have been recorded at their original cost in property, plant and equipment with the related reserves for accumulated depreciation also recorded.

The original cost of construction includes materials, construction overhead and outside contractor costs.  Additions to, and significant replacements of, transmission assets are charged to property, plant and equipment at cost; replacements of minor items are charged to maintenance expense.  The cost of transmission plant is charged to accumulated depreciation when an asset is retired.

The provision for depreciation of transmission assets is an integral part of the Company’s cost of service under FERC-approved rates.  Depreciation rates include estimates for future removal costs and salvage value.  Amounts collected in depreciation rates for future non-legal removal costs are included in regulatory liabilities in the balance sheets, as described in Note 1(h).  Removal costs incurred are charged against the regulatory liability.  Depreciation expense, including a provision for removal costs, as a percentage of average transmission plant was 2.74%, 2.73% and 2.75% in 2014, 2013 and 2012, respectively.

General plant, which includes buildings, office furniture and equipment, and computer hardware and software, is recorded at cost.  Depreciation is recorded at straight-line rates over the estimated useful lives of the assets, which range from five to 60 years.

(e)Asset Retirement Obligations

Consistent with ASC Topic 410, “Asset Retirement and Environmental Obligations,” the Company records a liability at fair value for a legal asset retirement obligation (ARO) in the period in which it is incurred.  When a new legal obligation is recorded, the costs of the liability are capitalized by increasing the carrying amount of the related long-lived asset.  The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset.  In accordance with ASC Topic 980, the Company recognizes regulatory assets or liabilities, as described in Note 1(h), for the timing differences between when it recovers the ARO in rates and when it

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recognizes these costs under ASC Topic 410.  At the end of the asset’s useful life, the Company settles the obligation for its recorded amount and records the gain or loss in the appropriate regulatory account.

The Company has recognized AROs primarily related to asbestos, lead-based paint and polychlorinated biphenyls contained in its electrical equipment.  AROs are recorded as other long-term liabilities in the balance sheets.  The following table describes all changes to AROs for the years ended December 31, 2014 and 2013 (in thousands):

	2014			2013
Asset Retirement Obligations at January 1	$	7,242		$	7,306
Accretion	361			378
Revision to Estimated Cash Flows	—			(333		)
Liabilities Settled	(51		)	(109		)
Asset Retirement Obligations at December 31	$	7,552		$	7,242

(f)Interconnection Agreements

The Company has entered into interconnection agreements with entities planning to build generation facilities.  The Company will construct the interconnection facilities; however, the generator will finance and bear all financial risk of constructing the interconnection facilities under these agreements.  The Company will own and operate the interconnection facilities when the generation facilities become operational and will reimburse the generator for construction costs, plus interest.  If the generation facilities do not become operational, the Company has no obligation to reimburse the generator for costs incurred during construction.

In cases in which the Company is contractually obligated to construct the interconnection facilities, the Company receives cash advances for construction costs from the generators.  During construction, the Company includes actual costs incurred in construction work in progress (CWIP) and records liabilities for the cash advances from the generators, along with accruals for interest.  The accruals for interest are capitalized and included in CWIP.  The construction costs and accrued interest related to interconnection agreements that are included in CWIP are not included as a component of the Company’s rate base until the generation facilities become operational and the Company has reimbursed the generator.

At December 31, 2014 and 2013 the Company had no active projects related to these agreements.  Therefore, at December 31, 2014 and 2013 there were no amounts included in CWIP or liabilities related to cash advances from generator interconnection agreements.

(g)Cash and Cash Equivalents

Cash and cash equivalents include highly liquid investments with original maturities of three months or less.

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The Company paid cash for interest of $85.6 million, $83.5 million and $80.0 million during 2014, 2013 and 2012, respectively.

At December 31, 2014, 2013 and 2012, construction costs funded through accounts payable and accrued liabilities were $24.8 million, $33.8 million and $25.5 million, respectively.  Accordingly, these noncash investing activities are not reported in the statements of cash flows until the period in which the payables are paid.

(h)Regulatory Accounting

The Company’s accounting policies conform to ASC Topic 980.  Accordingly, assets and liabilities that result from the regulated ratemaking process are recorded that would otherwise not be recorded under accounting principles generally accepted in the United States of America for non-regulated companies.  Certain costs are recorded as regulatory assets as incurred and are recognized in the statements of operations at the time they are reflected in rates.  As such, regulatory assets are not included as a component of rate base and do not earn a current return.  Regulatory liabilities represent amounts that have been collected in current rates to recover costs that are expected to be incurred, or refunded to customers, in future periods.

In accordance with ASC Topic 715, “Compensation — Retirement Benefits,” the Company recognizes the funded status of its postretirement benefit plan, measured as the amount by which its accumulated postretirement benefit obligation is less than or greater than the fair value of the assets that fund its plan.  Since the Company expects to refund or recover these amounts in future rates, a regulatory liability or asset has been established for an amount equal to the ASC Topic 715 asset or liability.

In accordance with ASC Topic 980, an accumulated over-collected revenue true-up balance is classified as a regulatory liability in the balance sheets and an accumulated under-collected revenue true-up balance is classified as a regulatory asset in the balance sheets.

The Company recognizes a regulatory asset or liability for the cumulative difference between amounts recognized for AROs under ASC Topic 410 and amounts recovered through depreciation rates related to these obligations.

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As of December 31, regulatory assets included the following amounts (in thousands):

	2014		2013
Revenue True-ups, Including Interest
2012 Network Revenue Collected in 2014	$	—	$	2,062
2012 Multi-Value Projects Revenue Collected in 2014	—		4,381
2013 Regional Cost-sharing Revenue to be Collected	719		718
2014 Multi-Value Projects Revenue to be Collected	1,486		—
2014 Scheduling Revenue to be Collected	4,877		—
Postretirement Benefit Plan Amounts to be Recovered through Future Rates	2,980		—
Total Regulatory Assets	$	10,062	$	7,161

As of December 31, these amounts were classified in the balance sheets as follows (in thousands):

	2014		2013
Current Portion of Regulatory Assets	$	719	$	6,443
Regulatory Assets (long term)	9,343		718
Total Regulatory Assets	$	10,062	$	7,161

As described in Note 1(d), the Company’s depreciation rates include an estimate for future asset removal costs which do not represent AROs.  The cumulative amounts that have been collected for future asset removal costs are reflected as regulatory liabilities.

The Company recorded a regulatory liability of $18.3 million related to the MISO transmission owner complaint discussed in Notes 1(c) and 7(a).

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As of December 31, regulatory liabilities included the following amounts (in thousands):

	2014		2013
Revenue True-ups, Including Interest
2012 Regional Cost-sharing Revenue Refunded in 2014	$	—	$	1,533
2013 Network Revenue to be Refunded	4,739		16,838
2013 Scheduling Revenue to be Refunded	128		122
2013 Multi-Value Projects Revenue to be Refunded	4,469		4,331
2014 Network Revenue to be Refunded	6,638		—
2014 Regional Cost-sharing Revenue to be Refunded	5,733		—
Return on Equity Refund Liability	18,348		—
Recognition of Over-funded Post Retirement Benefit Plan	—		3,949
Non-ARO Removal Costs Collected in Rates	119,047		99,400
Cumulative Difference between ARO Costs Collected in Rates and ARO Recognition under ASC Topic 410	1,722		2,493
Total Regulatory Liabilities	$	160,824	$	128,666

As of December 31, these amounts were classified in the balance sheets as follows (in thousands):

	2014		2013
Current Portion of Regulatory Liabilities	$	14,299	$	13,776
Regulatory Liabilities (long term)	146,525		114,890
Total Regulatory Liabilities	$	160,824	$	128,666

The Company continually assesses whether regulatory assets continue to meet the criteria for probability of future recovery. This assessment includes consideration of factors such as changes in the regulatory environment, recent rate orders to other regulated entities under the same jurisdiction and the status of any pending or potential deregulation legislation.  If the likelihood of future recovery of any regulatory asset becomes less than probable, the affected assets would be written off in the period in which such determination is made.

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(i)Other Assets

As of December 31, other assets included the following (in thousands):

	2014		2013
Unamortized Debt Issuance Costs	$	8,993	$	8,281
Deferred Project Costs	5,155		2,324
Other	2,207		1,672
Total Other Assets	$	16,355	$	12,277

Deferred project costs are expenditures directly attributable to the construction of transmission assets.  These costs are recorded as other assets in the balance sheets until all required regulatory approvals are obtained and construction begins, at which time the costs are transferred to CWIP.  In accordance with its FERC-approved settlement agreement, the Company is allowed to expense and recover in rates, in the year incurred, certain preliminary survey and investigation costs related to study and planning work performed in the early stages of construction projects.  Other costs, such as advance equipment purchases, continue to be deferred as described above.  Approximately $15.5 million, $19.0 million and $14.9 million of preliminary survey and investigation costs were included in operations and maintenance expense for 2014, 2013 and 2012, respectively.

(j)Impairment of Long-lived Assets

The Company reviews the carrying values of long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying values may not be recoverable under ASC Topic 360, “Property, Plant and Equipment.”  Impairment would be determined based upon a comparison of the undiscounted future operating cash flows to be generated during the remaining life of the assets to their carrying amounts.  An impairment loss would be measured as the amount that an asset’s carrying amount exceeds its fair value.  As long as its assets continue to be recovered through the ratemaking process, the Company believes that such impairment is unlikely.

(k)Income Taxes

The Company is a limited liability company that has elected to be treated as a partnership under the Internal Revenue Code and applicable state statutes.  The Company’s members (except certain tax-exempt members) report their share of the Company’s earnings, gains, losses, deductions and tax credits on their respective federal and state income tax returns.  Earnings before members’ income taxes reported in the statements of operations are the net income of the Company.  Accordingly, these financial statements do not include a provision for federal or state income tax expense.  See Note (6) for further discussion of income taxes.

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(l)Construction Agreement

In December 2012, the Company entered into an agreement with the Wisconsin Department of Transportation (WisDOT) to relocate seven overhead 138 kilovolt (kV) transmission lines as part of the WisDOT’s expansion of the interchange between Interstate Highway 894-94 and U.S. Highway 45 in Milwaukee, Wisconsin, known as the Zoo Interchange.  Under the agreement, the WisDOT began making the first of its periodic advances to the Company in January 2013, which the Company used to offset its costs to relocate the seven lines.  The Company received approximately $12.2 million and $32.8 million in advances under the agreement during 2014 and 2013, respectively.  Although the project is ongoing, the Company’s obligation under this agreement is complete and the Company will not receive any additional payments from the WisDOT related to this agreement.

(m)Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to apply policies and make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Estimates are used for items such as depreciable lives of property, plant and equipment, removal costs associated with asset retirements, tax provisions included in rates, actuarially-determined benefit costs, accruals for construction costs and operations and maintenance expenses.  As additional information becomes available, or actual amounts are determined, the recorded estimates are revised.  Consequently, operating results can be affected by revisions to prior accounting estimates.

(n)New Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update No. (ASU) 2014-09, Revenue from Contracts with Customers (ASC Topic 606).  The new recognition and measurement rules introduced by ASU 2014-09 will replace nearly all existing revenue guidance, including most industry-specific guidance, and will, with a few exceptions, apply to all contracts with customers.

Under the guidance in ASU 2014-09, the selling entity is required to perform the following recognition and measurement steps in order to recognize revenue:

·Identify the contract with a customer

·Identify the separate performance obligations within a contract

·Determine the transaction price

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·Allocate the transaction price to the separate performance obligations, typically on the basis of the relative standalone selling prices of each distinct good or service

·Recognize revenue when, or as, each performance obligation is satisfied, either over a period of time or at a point in time.

ASU 2014-09 becomes effective for the Company for the annual reporting period ending December 31, 2018 and interim reporting periods within 2018; but the Company may, at its discretion, adopt ASU 2014-09 effective for the annual reporting period ending December 31, 2017, and interim reporting periods within 2017, in order to align its accounting methods with those of its members who are public companies.  The Company is currently evaluating the impacts of the new standard but does not believe it will have a material impact to its current revenue recognition and measurement practices.

(2)Benefits

Management Inc. sponsors several benefit plans for its employees.  These plans include certain postretirement medical, dental and life insurance benefits (“postretirement healthcare benefits”).  The weighted-average assumptions related to the postretirement medical benefits, as of the measurement date, are as follows:

	2014		2013		2012
Discount Rate	4.12	%	4.95	%	4.12	%
Medical Cost Trend:
Immediate Range	6.60	%	7.50	%	7.00	%
Ultimate Range	4.00	%	4.00	%	4.00	%
Long-term Rate of Return on Plan Assets	5.00	%	6.00	%	6.00	%

The components of Management Inc.’s postretirement healthcare benefit costs for 2014, 2013 and 2012 are as follows (in thousands):

	2014			2013			2012
Service Cost	$	1,111		$	1,426		$	1,562
Interest Cost	1,049			960			977
Amortization of Prior Service Credit	(569		)	(569		)	(569		)
Amortization of Net Actuarial Loss (Gain)	(11		)	308			286
Expected Return on Plan Assets	(1,200		)	(1,375		)	(1,259		)
Net Periodic Postretirement Cost	$	380		$	750		$	997

To recognize the funded status of its postretirement healthcare benefit plans in accordance with ASC Topic 715, the Company recorded a long-term liability of $3.0 million at December 31, 2014 and a long-term asset of $4.0 million at December 31, 2013.  In addition, the Company had the following amounts not yet reflected in net periodic benefit cost and

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included in its regulatory accounts, which the Company believes will be recovered as a component of operating expense in future rates, at December 31 (in thousands):

	2014			2013
Prior Service Credit	$	(3,016	)	$	(3,585	)
Accumulated Loss (Gain)	5,996			(364		)
Regulatory Asset (Liability) for Amounts to be Included in Future Rates	$	2,980		$	(3,949	)

The assumed medical cost trend rates are critical assumptions in determining the service and interest cost and accumulated postretirement healthcare benefit obligation for the Company’s medical and dental plans.

A one-percent change in the medical cost trend rates, holding all other assumptions constant, would have the following effects for 2014 (in thousands):

	One-Percent		One-Percent
	Increase		Decrease
Effect on Total of Service and Interest Cost Components	$	488	$	(375	)
Effect on Postretirement Benefit Obligation at the End of the Year	6,440		(4,892		)

In 2015, the Company will recognize a $569 thousand prior service credit in its net periodic postretirement healthcare benefit cost.

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The funded status of the Company’s postretirement healthcare benefit plans as of December 31 is as follows (in thousands):

	2014			2013
Change in Projected Benefit Obligation:
Accumulated Postretirement Benefit Obligation at January 1	$	21,356		$	23,415
Service Cost	1,111			1,426
Interest Cost	1,049			960
Benefits Paid	(276		)	(421		)
Actuarial Losses (Gains)	5,455			(4,024		)
Benefit Obligation at December 31	$	28,695		$	21,356
Change in Plan Assets:
Fair Value of Plan Assets at January 1	$	25,355		$	24,244
Employer Contributions	290			—
Actual Return on Plan Assets (Net of Expenses)	306			2,461
Net Benefits Paid	(236		)	(1,350		)
Fair Value at December 31	$	25,715		$	25,355
Funded Status at December 31	$	(2,980	)	$	3,999

The funded status of the plan decreased as a result of changes in the assumptions used to calculate the benefit obligation and a lower than expected return on plan assets.  Updated mortality tables reflecting longer life expectancy and use of a lower discount rate were the primary drivers of the increase in the benefit obligation as of December 31, 2014.

The Company anticipates contributing $1.0 million to the plan for postretirement healthcare benefit obligations during 2015.

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The Company anticipates net retiree healthcare benefit payments for the next 10 years to be as follows (in thousands):

2015	$	446
2016	494
2017	561
2018	634
2019	686
2020-2024	4,446
Total	$	7,267

To fund postretirement healthcare benefit obligations, the Company periodically contributes to its Voluntary Employees’ Beneficiary Association (VEBA) trust.  The VEBA trust, along with the 401(h) trust previously established by the Company to fund postretirement healthcare benefits, are discretionary trusts with a long-term investment objective to preserve and enhance the post inflation value of the trusts’ assets, subject to cash flow requirements, while maintaining an acceptable level of volatility.

The composition of the fair value of total plan assets held in the trusts as of December 31, along with targeted allocation percentages for each major category of plan assets in the trusts, is as follows:

2014	Actual		Target		Range
U.S. Equities	38.3	%	32.5	%	+/- 5%
Non-U.S. Equities	28.2	%	32.5	%	+/- 5%
Fixed Income	33.5	%	35.0	%	+/- 5%
	100	%	100	%

2013	Actual		Target		Range
U.S. Equities	48.2	%	50.0	%	+/- 5%
Non-U.S. Equities	13.2	%	15.0	%	+/- 4%
Fixed Income	38.6	%	35.0	%	+/- 5%
	100	%	100	%

The Company appoints a trustee to maintain investment discretion over trust assets.  The trustee is responsible for holding and investing plan assets in accordance with the terms of the Company’s trust agreement, including investing within the targeted allocation percentages.  In late 2014, the Company updated the targeted allocation percentages for the plan assets.  As of December 31, 2014, the trustee was in the process of updating the portfolio to reflect these new targets.  The Company expects that the funds will be within range of the new targets during 2015.

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The asset classes designated above and described below serve as guides for the selection of individual investment vehicles by the trustee:

·U.S. Equities — Strategy of achieving long-term growth of capital and dividend income through investing primarily in common stock of companies in the U.S. stock market with the Wilshire 5000 Index (or a comparable broad U.S. stock index) as the investment benchmark.

·Non-U.S. Equities — Strategy of achieving long-term growth of capital and dividend income through investing primarily in common stock of companies in the non-U.S. stock markets with the Morgan Stanley Capital Index All Country World ex-U.S Index (or a comparable broad non-U.S. stock index) as the investment benchmark.

·Fixed Income — Strategy of achieving total return from current income and capital appreciation by investing in a diversified portfolio of fixed-income securities with the Barclays Capital Aggregate Index (or a comparable broad bond index) as the investment benchmark.

The objective of the investment vehicles is to minimize risk of large losses by effective diversification.  The investment vehicles will attempt to rank better than the median vehicle in their respective peer group.  However, these investments are intended to be viewed over the long term; during the short term, there will be fluctuations in rates of return characteristic of the securities markets.

The Company measures its plan assets at fair value according to the hierarchy set forth in ASC Topic 715.  The three levels of the fair value hierarchy under ASC Topic 715 are:

Level 1Inputs to the valuation methodology are unadjusted quoted prices for identical assets or liabilities in active markets that the Company’s postretirement healthcare benefit plans have the ability to access.

Level 2Inputs to the valuation methodology include:

·Quoted prices for similar assets or liabilities in active markets

·Quoted prices for identical or similar assets or liabilities in inactive markets

·Inputs other than quoted prices that are observable for the asset or liability

·Inputs that are derived principally from, or corroborated by, observable market data by correlation or other means

If the asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability.

Level 3Inputs to the valuation methodology are unobservable and significant to the fair value measurement.

The asset’s or liability’s fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.  Valuation techniques used need to maximize the use of observable inputs and minimize the use of unobservable inputs.

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At December 31, 2014 and 2013, a description of the valuation methodologies used for investments measured at fair value is as follows:

·Money Market Fund:  Valued at cost plus accrued interest, which approximates the fair value of the net asset value of the shares held by the plan at year-end.

·Mutual Funds: Valued at the net asset value of shares held by the plan at year-end.

The following table contains, by level within the fair value hierarchy, the Company’s postretirement healthcare benefit account investments at fair value as of December 31 (in thousands):

2014	Level 1		Level 2		Level 3		Total
U.S. Equity Mutual Funds	$	9,848	$	—	$	—	$	9,848
Non-U.S. Equity Mutual Fund	7,243		—		—		7,243
Fixed Income Mutual Funds	8,376		—		—		8,376
Money Market Fund	—		248		—		248
Total	$	25,467	$	248	$	—	$	25,715

2013	Level 1		Level 2		Level 3		Total
U.S. Equity Mutual Funds	$	12,230	$	—	$	—	$	12,230
Non-U.S. Equity Mutual Fund	3,341		—		—		3,341
Fixed Income Mutual Funds	9,497		—		—		9,497
Money Market Fund	—		287		—		287
Total	$	25,068	$	287	$	—	$	25,355

During 2014 and 2013, the Company had no transfers between Level 1 and Level 2 measurements and no transfers into or out of Level 3 measurements.  Measurements for the Company’s Level 2 inputs are based on inputs other than quoted prices that are observable for these assets.

Management Inc. sponsors a defined contribution money-purchase pension plan, in which substantially all employees participate, and makes contributions to the plan for each participant based on several factors.  Contributions made by Management Inc. to the plan and charged to expense totaled $3.3 million, $3.1 million and $2.8 million in 2014, 2013 and 2012, respectively.

Management Inc. also provides a deferred compensation plan for certain employees.  The plan allows for the elective deferral of a portion of an employee’s base salary and incentive compensation and also contains a supplemental retirement and 401(k) component.  Deferred amounts are taxable to the employee when paid, but the Company

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recognizes compensation expense in the period earned.  As of December 31, 2014 and 2013, $17.7 million and $16.4 million, respectively, were included in other long-term liabilities related to this deferred compensation plan.  Amounts charged to expense, including interest accruals, were $2.0 million, $2.1 million and $2.0 million in 2014, 2013 and 2012, respectively.

(3)Members’ Equity

The Company’s members include investor-owned utilities, municipalities, municipal electric companies and electric cooperatives.

Distribution of earnings to members is at the discretion of Management Inc.  The operating agreement of the Company established a target for distribution of 80% of annual earnings before members’ income taxes.  During 2014, 2013 and 2012, the Company distributed $204 million, $195 million and $188 million, respectively, of its earnings to its members.  On January 28, 2015, the board of directors of Management Inc. approved a distribution for the fourth quarter of 2014, in the amount of $37.1 million, that was paid on January 30, 2015, bringing the total distributions related to 2014 earnings to 80% of earnings before members’ income taxes.

Each of the Company’s members has the right to require the Company to redeem all or a portion of its membership interests, so long as such interests have been outstanding for at least 12 months.  However, the Company is not required to effect the redemption by non-managing members if Management Inc., in its sole discretion as the corporate manager, elects to purchase, in lieu of redemption, such membership interests for either a specified amount of cash or a specified number of shares of its common stock.  After such purchase, Management Inc. shall be deemed the owner of such membership interests.

During 2014, the Company issued 2,974,510 units to members in exchange for $50.0 million in cash.  During 2013 and 2012 the Company issued members 2,459,468 units for $40.0 million in cash and 3,829,479 units for $60.0 million in cash, respectively.

Management Inc. has issued shares of its common stock to each of the Company’s members or their affiliates in proportion to their ownership interests in the Company.  Holders of Management Inc. common stock have the rights of shareholders under Wisconsin law, including the right to elect directors of the corporate manager.

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(4)Debt

(a)Credit Facility

The Company has a $350 million, five-year revolving credit facility, which expires on December 7, 2017.  The facility provides backup liquidity to the Company’s commercial paper program.  While the Company does not intend to borrow under the revolving credit facility, interest rates on outstanding borrowings under the facility would be based on a floating rate plus a margin.  The applicable margin, which is based on the Company’s debt rating of A1/A+ or equivalent, is currently 0.8%.

The revolving credit facility contains restrictive covenants, including restrictions on liens, certain mergers, sales of assets, acquisitions, investments, transactions with affiliates, change of control, conditions on prepayment of other debt and the requirement of the Company to meet certain financial reporting obligations.  The revolving credit facility provides for certain customary events of default, including a targeted total-debt-to-total-capitalization ratio that is not permitted to exceed 65% at any given time.  The Company was not in violation of any financial covenants under its credit facility during the periods covered by these financial statements.

The Company had no outstanding balance under its credit facility as of December 31, 2014 or 2013.

(b)Commercial Paper

The Company currently has a $350 million unsecured, private placement, commercial paper program.  Investors are limited to qualified institutional buyers and institutional accredited investors.  Maturities may be up to 364 days from date of issue, with proceeds to be used for working capital and other capital expenditures.  Pricing is par, less a discount or, if interest-bearing, at par.  The Company had $120 million of commercial paper outstanding as of December 31, 2014 at an average rate of 0.23% and $280 million of commercial paper outstanding as of December 31, 2013 at an average rate of 0.21%.  Commercial paper is included in Short-term Debt in the balance sheets.  As defined by the commercial paper program, no customary events of default took place during the periods covered by the accompanying financial statements.

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(c)Long-term Debt

The following table summarizes the Company’s long-term debt outstanding as of December 31 (in thousands):

	2014			2013
Senior Notes at stated rate of 7.02%, due August 31, 2032	$	50,000		$	50,000
Senior Notes at stated rate of 6.79%, due on dates ranging from August 31, 2024 to August 31, 2043	100,000			100,000
Senior Notes at stated rate of 4.992%, due April 15, 2015	100,000			100,000
Senior Notes at stated rate of 5.59%, due December 1, 2035	100,000			100,000
Senior Notes at stated rate of 5.91%, due August 1, 2037	250,000			250,000
Senior Notes at stated rate of 5.58%, due April 30, 2018	200,000			200,000
Senior Notes at stated rate of 5.40%, due May 15, 2019	150,000			150,000
Senior Notes at stated rate of 4.59%, due February 1, 2022	100,000			100,000
Senior Notes at stated rate of 5.72%, due April 1, 2040	50,000			50,000
Senior Notes at stated rate of 4.17%, due March 14, 2026	75,000			75,000
Senior Notes at stated rate of 4.27%, due March 14, 2026	75,000			75,000
Senior Notes at stated rate of 5.17%, due March 14, 2041	150,000			150,000
Senior Notes at stated rate of 4.37%, due April 18, 2042	150,000			150,000
Senior Notes at stated rate of 3.74%, due January 22, 2029	50,000			—
Senior Notes at stated rate of 4.67%, due January 22, 2044	50,000			—
Senior Notes at stated rate of 3.35%, due December 11, 2024	75,000			—
Senior Notes at stated rate of 3.60%, due December 11, 2029	29,000			—
Senior Notes at stated rate of 4.31%, due December 11, 2044	47,000			—
Total Long-term Debt	$	1,801,000		$	1,550,000
Less: Current Maturities	(100,000		)	—
Net Long-term Debt	$	1,701,000		$	1,550,000

The senior notes rank equivalent in right of payment with all of the Company’s existing and future unsubordinated, unsecured indebtedness and senior in right of payment to all subordinated indebtedness of the Company.

The senior notes contain restrictive covenants, which include restrictions on liens, certain mergers and sales of assets, and the requirement of the Company to meet certain financial reporting obligations.  The senior notes also provide for certain customary events of default, none of which occurred during the periods covered by the accompanying financial statements.

Future maturities of the Company’s senior notes are as follows (in millions):

2015	$	100
2016	—
2017	—
2018	200
2019	150
Thereafter	1,351
	$	1,801

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The senior notes contain an optional redemption provision whereby the Company is required to make the note holders whole on any redemption prior to maturity.  The notes may be redeemed at any time, at the Company’s discretion, at a redemption price equal to the greater of 100% of the principal amount of the notes plus any accrued interest or the present value of the remaining scheduled payments of principal and interest from the redemption date to the maturity date discounted to the redemption date on a semiannual basis at the then-existing Treasury rate plus 30 to 50 basis points, plus any accrued interest.

During November 2014, the Company entered into an agreement with a group of investors, through a private placement offering, to issue $250 million of senior notes to be funded in two traunches.  Closing of the notes and funding of the first $151 million took place on December 11, 2014 with interest due semiannually on June 11 and December 11, beginning on June 11, 2015.  The $151 million is comprised of $75 million of 10-year, unsecured 3.35% senior notes; $29 million of 15-year, unsecured 3.60% senior notes; and $47 million of 30-year, unsecured 4.31% senior notes.  The notes will mature on December 11, 2024, 2029 and 2044, respectively.

The remaining $99 million is expected to fund on April 14, 2015 and is comprised of $50 million of 10-year, unsecured 3.45% senior notes; $21 million of 15-year, unsecured 3.70% senior notes; and $28 million of 30-year, unsecured 4.41% senior notes.  The notes will pay interest semiannually in April and October and will mature in 2025, 2030 and 2045, respectively.

During November 2013, the Company entered into an agreement with a group of investors, through a private placement offering, to issue $50 million of 15-year, unsecured 3.74% senior notes and $50 million of 30-year, unsecured 4.67% senior notes.  The closing and funding of the notes occurred on January 22, 2014.  The notes pay interest semiannually on January 22 and July 22, beginning on July 22, 2014.  The notes will mature on January 22, 2029 and January 22, 2044, respectively.

(5)Fair Value of Financial Instruments

The carrying amount of the Company’s financial instruments included in current assets and current liabilities approximates fair value due to the short maturity of such financial instruments.  The fair value of the Company’s long-term debt is estimated based upon quoted market values 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 Company’s credit ratings.

The carrying amount and the estimated fair value of the Company’s long-term debt at December 31 are as follows (in millions):

	2014		2013
Carrying Amount	$	1,801	$	1,550
Estimated Fair Value	2,152		1,705

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(6)Income Taxes

The Company is allowed to recover in rates, as a component of its cost of service, its income taxes, as well as the amount of income taxes that are the responsibility of its members.  Accordingly, the Company includes a provision for its members’ federal and state current and deferred income tax expenses and amortization of the excess deferred tax reserves and deferred investment tax credits associated with assets transferred to the Company by its members in its regulatory financial reports and rate filings.  For purposes of determining the Company’s revenue requirement under FERC-approved rates, rate base is reduced by an amount equivalent to members’ net accumulated deferred income taxes, including excess deferred income tax reserves.  Such amounts were approximately $568 million, $498 million and $422 million in 2014, 2013 and 2012, respectively, and are primarily related to accelerated tax depreciation and other plant-related differences.  The 2014, 2013 and 2012 revenues include recovery of $103 million, $98.9 million and $95.0 million, respectively, of income tax expense.

On December 17, 2010, President Obama signed the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (“2010 Tax Act”) into law.  One of the elements of the 2010 Tax Act increased bonus depreciation from 50% to 100% on assets placed in service after September 8, 2010 and before January 1, 2012.  The 2010 Tax Act also allowed a transitional 100% bonus depreciation for self-constructed assets that had started construction before December 31, 2011, and were in service by December 31, 2012.  On January 2, 2013, President Obama signed the American Taxpayer Relief Act of 2012 (“2012 Tax Act”), which extended the 50% bonus depreciation through 2013.  The 2012 Tax Act also allowed a transitional 50% bonus depreciation for self-constructed assets that had started construction before December 31, 2013, and were in service by December 31, 2014.  On December 19, 2014, the Tax Increase Prevention Act of 2014 (“2014 Tax Act”) was signed in to law extending the 50% bonus depreciation through 2014.  The 2014 Tax Act allowed a transitional 50% bonus depreciation for self-constructed assets that had started construction before December 31, 2014, and are placed in service by December 31, 2015.

ASC Topic 740, “Income Taxes,” provides guidance on recognition thresholds and measurement of a tax position taken or expected to be taken in a tax return, including whether an entity is taxable in a particular jurisdiction.  This guidance applies to all entities, including pass-through entities such as the Company.  The Company does not consider any of its tax positions to be uncertain, including the Company’s position that it qualifies as a pass-through entity in the federal and Wisconsin tax jurisdictions.  Additionally, the Company had no unrecognized tax benefits and was assessed no material amounts of interest or penalties during 2014, 2013 or 2012.  The Company is no longer subject to examination by the Internal Revenue Service for tax years prior to 2013 or any state jurisdiction for tax years prior to 2010.  In the event the Company would be assessed interest or penalties by a taxing authority related to income taxes, interest would be recorded in interest expense and penalties would be recorded in other expense in the statements of operations.

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(7)Commitments and Contingencies

(a)MISO Return on Equity Complaint

As mentioned above, MISO, the Company and numerous other MISO transmission owners were named as respondents in a complaint filed at FERC, pursuant to FPA Section 206, by several customer groups located within the MISO service area.  These complainants claimed that the following aspects of the respondents’ transmission rates were no longer just and reasonable:  the base 12.38% return on equity (ROE) in MISO and the Company’s 12.2% ROE; hypothetical capital structures that have an equity component greater than 50%; and certain incentive ROE adders used by a limited number of MISO transmission owners, of which the Company is not one.  The Company currently uses a hypothetical 50% debt, 50% equity capital structure, as approved by FERC, in calculating its revenue requirement.  The complainants requested FERC to order the base MISO ROE reset to 9.15%, equity components of hypothetical capital structures be restricted to 50% and that relevant incentive ROE adders be discontinued.  The complainants requested that FERC establish expedited hearing and settlement procedures to address the issues raised, and that FERC grant the effective date of any refund as the date of the complainants filing.  During the first quarter of 2014, the Company and the other MISO transmission owners responded to the complaint with a motion to dismiss and answer objecting to the claims of the complainants, and filed an answer in response to pleadings of the complainants and certain other parties.

On October 16, 2014, FERC issued an order which addressed the base ROE of the MISO transmission owners and the Company.  FERC determined that the complaint regarding the transmission owner base ROE raises issues of material fact that cannot be resolved with the information in the record at this point.  As a result, FERC put the matter of whether the MISO transmission owner base ROE is unjust and unreasonable to hearing and settlement procedures, and established a refund date of November 12, 2013.  However, the settlement process was terminated in December 2014.  FERC ordered formal hearing proceedings to begin, and an initial decision in the complaint is expected by November 30, 2015.  In the October 16, 2014 order, FERC denied the portion of the complaint seeking to restrict the use of capital structures that include more than 50 percent common equity and also denied the portion of the complaint requesting the termination of the incentive ROE adders used by certain transmission owners other than the Company.  FERC indicated that it expects the parties’ evidence and discounted cash flow (DCF) analysis to be guided by FERC’s June 19, 2014, order in the New England Independent System Operator (NE-ISO) Section 206 complaint, which set the precedent for using a two-step DCF analysis for establishing ROEs for electric transmission.  This new method is similar to that used for natural gas pipelines, and incorporates a two-step process utilizing both short-term and long-term growth projections to establish an ROE.  FERC previously used only short-term growth projections.  FERC also issued an order on October 16, 2014, in the NE-ISO transmission owner ROE complaint, confirming that the U.S. gross domestic product growth rate is the appropriate long-term growth rate to use in the two-step DCF methodology.

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The Company believes it is probable that a refund will be required upon ultimate resolution of this matter and has recorded a regulatory liability of $18.3 million as of December 31, 2014, and an offset to transmission service revenue in the statements of operations.  The Company is unable to make a better estimate of probable losses or estimate the range of reasonably possible losses in excess of the amount recorded due to the many variables that could affect the final outcome of this matter.  Therefore, the Company’s ultimate refund amount could be materially higher than the amount recorded.  These variables, include the specific long-term and short-term growth rates to be used in the DCF calculation used by FERC to calculate the zone of reasonableness, the placement of the MISO transmission owners’ ROE within the zone of reasonableness and the composition of the proxy group used to calculate the zone of reasonableness.  Future changes in these variables or the assumptions on which they are based could have a material impact to the Company’s financial position, results of operations and cash flows.

On November 6, 2014, a large group of transmission-owning members of MISO, including the Company, asked FERC to approve a 50 basis-point incentive ROE adder for participating in MISO and voluntarily relinquishing functional control of their transmission facilities to the Regional Transmission Organization (RTO).  FERC approved the incentive request on January 5, 2015, to be effective January 6, 2015.  Although FERC found that the MISO transmission owners are qualified to receive the requested 50-basis-point adder, that adder must be applied to a base ROE that has been shown to be just and reasonable using an updated DCF analysis and must result in an overall ROE that is within the appropriate zone of reasonableness.  As both of those issues are being addressed in response to the complaint mentioned above, FERC made its ruling subject to the outcome of that proceeding.

(b)Operating Leases

The Company leases office space and certain transmission-related equipment under non-cancelable operating leases.  Amounts incurred were approximately $6.5 million in both 2014 and 2013, and approximately $5.9 million during 2012.

Future minimum lease payments under non-cancelable operating leases for the years ending December 31 are as follows (in millions):

2015	$	6.4
2016	6.2
2017	5.7
2018	5.6
2019	5.3
Thereafter	36.5
	$	65.7

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(c)Smart Grid Agreements

On April 20, 2010, the Company entered into two agreements with the U.S. Department of Energy (DOE), accepting investment grants for up to 50% of the cost of the related projects.  The grants, totaling $12.7 million, were used to invest in smart grid technologies incorporated into the Company’s transmission system.  The funds the Company received from the DOE under the grant award agreements reduced the amount of investment in such projects upon which the Company earns a return.  During construction, which was completed in October 2013, the Company invoiced the DOE and received payments under these agreements.  Per the terms of these agreements, the Company completed independent audits of the smart grid projects during 2012, 2013 and 2014, the results of which were submitted to the DOE.  The reports were concluded with no audit findings and, per the Smart Grid agreements, the Company has no further audit requirements related to these projects.

(d)MISO Revenue Distribution

Periodically, the Company receives adjustments to revenues that were allocated to it by MISO in prior periods.  Some of these adjustments may result from disputes filed by transmission customers. The Company does not expect any such adjustments to have a significant impact on its financial position, results of operations or cash flows since adjustments of this nature are typically offset by its true-up provision in the revenue requirement formula.

(e)Interconnection Agreements

The Company has entered into interconnection agreements with entities planning to build generation facilities.  The Company will construct the interconnection facilities; however, the generator will finance and bear all financial risk of constructing the interconnection facilities under these agreements.  The Company will own and operate the interconnection facilities when the generation facilities become operational and will reimburse the generator for construction costs plus interest.  If the generation facilities do not become operational, the Company has no obligation to reimburse the generator for costs incurred during construction.

There may be transmission service requests that require the Company to construct additional, or modify existing, transmission facilities to accommodate such requests.  Whether such additions or upgrades to the Company’s transmission system are required depends on the state of the transmission system at the time the transmission service is requested.  Under these agreements, the Company reimbursed, inclusive of interest, $13.0 million to generators during 2012.  The Company did not make any reimbursements to generators during 2013 or 2014, and does not expect to make any reimbursements to generators in 2015 under such agreements.

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(f)Potential Adverse Legal Proceedings

The Company has been, and will likely in the future become, party to lawsuits, potentially including suits that may involve claims for which it may not have sufficient insurance coverage.  The Company’s liability related to utility activities is limited by FERC-approved provisions of the MISO Tariff that limit potential damages to direct damages caused by the Company’s gross negligence or intentional misconduct.

(g)Environmental Matters

In the future, the Company may become party to proceedings pursuant to federal and/or state laws or regulations related to the discharge of materials into the environment. Such proceedings may involve property the Company acquired from the contributing utilities. Pursuant to the asset purchase agreements executed with the contributing utilities beginning January 1, 2001, the contributing utilities will indemnify the Company for 25 years from such date for any environmental liability resulting from the previous ownership of the property.

(8)Related-Party Transactions

(a)Membership Interests

To maintain its targeted debt-to-capitalization ratio, the Company was authorized by Management Inc.’s board of directors to request up to $50 million of additional capital through voluntary additional capital calls (VACCs) during 2015, including $5 million it received in January 2015.  The Company also received a total of $50 million and $40 million through VACCs in 2014 and 2013, respectively.  The participating members received additional membership units at the current book value per unit at the time of each contribution.  Contributions from capital calls are recognized when received.

(b)Duke-American Transmission Company, LLC

The Company and Duke Energy hold equal equity ownership in the Duke-American Transmission Company, LLC (DATC), which was created to seek opportunities to acquire, build, own and operate new transmission projects that meet potential customers’ capacity and voltage requirements and future needs.  DATC continues to evaluate new projects and opportunities, along with participating in the competitive bidding process on projects it considers to be viable.

DATC owns the Zephyr Power Transmission Project (“Zephyr”) and is continuing the design and development of the proposed 525-mile to 850-mile transmission line, which would deliver wind energy generated in eastern Wyoming to

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California and the southwestern United States.  DATC acquired Zephyr from a subsidiary of Pathfinder Renewable Wind Energy LLC (“Pathfinder”).  The 500 kV high-voltage direct-current project has an estimated cost of $2.5 billion to $3.5 billion.  Pathfinder is developing a wind power project on more than 100,000 acres near Chugwater, Wyoming, and has committed to use at least 2,100 megawatts (MW) of the Zephyr project’s 3,000 MW capacity.  If certain milestones materialize under the project agreement, DATC would be required to pay, directly or indirectly, Pathfinder’s share of regulatory phase project costs of up to $5 million incurred during the years 2012 through 2015; however, DATC has the right to terminate the project at any time prior to January 15, 2016.  DATC has received FERC approval to charge negotiated rates consistent with FERC approvals for Zephyr’s previous owners.

Path 15 is an existing 84-mile, 500 kV transmission line in central California.  DATC owns 72% of the transmission rights of Path 15, which it purchased from Atlantic Power Corporation in April 2013 for approximately $56 million cash and the assumption of approximately $137 million of debt.  Pacific Gas & Electric has an 18% interest in the transmission rights to Path 15 through its ownership and operation of the connecting Los Banos and Gates substations.  The remaining 10% interest in the transmission rights to Path 15 is owned by the Western Area Power Administration, which will continue to operate and maintain the line.  On February 18, 2014, Path 15 filed its 2014 rate case with FERC for the 2014 through 2016 rate period.  During the pending rate case, Path 15 continues to collect the filed rates and those rates are subject to refund, including interest, based on a final order.

On July 18, 2013, DATC secured a $30 million, five-year credit facility from U.S. Bank N.A.  As a stipulation of that facility, the Company and Duke Energy executed a guarantee agreement on that same date with U.S. Bank N.A. to each guarantee 50% of the obligations under the credit facility agreement.  Currently, there is no outstanding balance under the credit facility.

The balance in the Company’s investment in DATC was $35.3 million and $31.7 million at December 31, 2014 and 2013, respectively, and is accounted for under the equity method of accounting.

(c)Operations and Maintenance, Project Services and Common Facilities Agreements

The Company operates under Operation and Maintenance Agreements whereby certain contributing utilities, municipalities and cooperatives provide operational, maintenance and construction services to the Company at a fully-allocated cost.

In an order dated September 1, 2009 and later supplemented in an order dated May 24, 2013, the PSCW approved Project Services Agreements and Common Facilities Agreements, whereby the Company and certain of its affiliates may perform engineering and construction services for each other, subject to the restrictions and reporting requirements specified in the orders.  To prevent cross-subsidization between affiliated entities, the PSCW ordered

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that services be performed at a fully-allocated cost of the party providing services, and be reported annually to the PSCW.

Some operation and maintenance agreements require the Company to utilize a minimum level of service.  To date, the amount of services utilized by the Company has exceeded the minimum in each year.

Under these agreements, the Company was billed approximately $32.8 million, $35.5 million and $35.3 million in 2014, 2013 and 2012, respectively.  Accounts payable and other accrued liabilities include amounts payable to these companies of $2.4 million and $3.4 million at December 31, 2014 and 2013, respectively.

(d)Transmission Service

Revenues from the Company’s members were approximately 90% of the Company’s transmission service revenue for the years ended December 31, 2014, 2013 and 2012.

(e)Agreement with Alliant Energy

The Company has an agreement with Alliant Energy (“Alliant”), under which it provides control center and operation services for Alliant’s 34.5 kV distribution system in the state of Wisconsin.  The agreement automatically renews every two years, unless terminated by either party.  Amounts the Company has received from Alliant for these services are not material to the financial statements.

(f)Management Inc.

As discussed in Note 1(b), Management Inc. manages the Company.  Management Inc. charged the Company approximately $101 million, $96.6 million and $89.4 million in 2014, 2013 and 2012, respectively, primarily for employee-related expenses.  These amounts were charged to the applicable operating expense accounts, or capitalized as CWIP or other assets, as appropriate.  The amounts are recorded in the Company’s accounts in the same categories in which the amounts would have been recorded had the Company incurred the costs directly.

(g)Interconnection Agreements

As discussed in Notes 1(f) and 7(e), the Company has interconnection agreements related to the capital improvements required to connect new generation equipment to the grid.  Some of these agreements are with members or affiliates of members of the Company.  At December 31, 2014 and 2013, there were no outstanding liabilities related to these agreements.  The Company did not make any reimbursements under such agreements in 2013 or 2014 and does not expect to make any reimbursements to members in 2015 under such agreements.

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(9)Quarterly Financial Information (unaudited)

(In Thousands)	Three Months Ended
	2014
	March 31			June 30		September 30		December 31			Total
Operating Revenues	$	163,337		$	159,990	$	163,643	$	148,063		$	635,033
Operating Expenses	78,623			74,405		76,561		77,862			307,451
Operating Income	84,714			85,585		87,082		70,201			327,582
Other Income (Expense), Net	388			322		693		(1,286		)	117
Interest Expense, Net	21,996			22,242		22,204		22,528			88,970
Earnings Before Members’ Income Taxes	$	63,106		$	63,665	$	65,571	$	46,387		$	238,729
	2013
	March 31			June 30		September 30		December 31			Total
Operating Revenues	$	151,737		$	152,128	$	160,480	$	161,991		$	626,336
Operating Expenses	69,770			69,875		77,595		77,829			295,069
Operating Income	81,967			82,253		82,885		84,162			331,267
Other Income (Expense), Net	(448		)	116		917		246			831
Interest Expense, Net	21,044			21,052		21,136		21,252			84,484
Earnings Before Members’ Income Taxes	$	60,475		$	61,317	$	62,666	$	63,156		$	247,614

Because of seasonal factors impacting the Company’s business, particularly the maintenance and construction programs, quarterly results are not necessarily comparable.  In general, due to the Company’s rate formula, revenues and operating income will increase throughout the year, as the Company’s rate base increases through expenditures for CWIP.  The fourth quarter of 2014 decreased as a result of the MISO transmission owner base ROE complaint, discussed in Note 7(a).

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EX-99.4

Exhibit 99.4

SELECTED UNAUDITED PRO FORMA CONDENSED COMBINED CONSOLIDATED
FINANCIAL INFORMATION

The unaudited pro forma condensed combined consolidated income statement information for the three months ended March 31, 2015, and the year ended December 31, 2014, gives effect to the acquisition as if it had occurred on January 1, 2014. The unaudited pro forma condensed combined consolidated balance sheet as of March 31, 2015 gives effect to the acquisition as if it had occurred on March 31, 2015.

We present the unaudited pro forma condensed combined consolidated financial information for illustrative purposes only, and it is not necessarily indicative of the results of operations and financial position that would have been achieved had the pro forma events taken place on the dates indicated. Future results may vary significantly from the results reflected because of various factors, including those discussed in this document under the heading “Risk Factors” beginning on page 32. You should read the following selected unaudited pro forma condensed combined consolidated financial information in conjunction with the “Unaudited Pro Forma Condensed Combined Consolidated Financial Information” and related notes included in this document beginning on page 154.

	Three Months Ended March 31, 2015		Year Ended December 31, 2014
	(in millions, except per share data)
Pro Forma Condensed Combined Consolidated Statements of Income Information:
Operating Revenues	$	2,550.6	$	9,134.0
Net Income From Continuing Operations	329.9		866.1
Earnings Per Share From Continuing Operations (Basic)	1.05		2.75
Earnings Per Share From Continuing Operations (Diluted)	1.04		2.73

	As of March 31, 2015
	(in millions)
Pro Forma Condensed Combined Consolidated Balance Sheet Information:
Cash and Cash Equivalents	$	151.6
Total Assets	28,835.3
Long-Term Debt (excluding current portion)	8,604.4
Total Common Equity	8,758.8
Total Capitalization	17,444.7
Total Liabilities and Capitalization	28,835.3

1

UNAUDITED PRO FORMA CONDENSED COMBINED CONSOLIDATED
FINANCIAL INFORMATION

The Unaudited Pro Forma Condensed Combined Consolidated Financial Statements (pro forma financial statements) have been derived from the historical consolidated financial statements of Wisconsin Energy and Integrys. Upon completion of the transaction, the surviving entity is expected to be named WEC Energy Group, Inc.

The Unaudited Pro Forma Condensed Combined Consolidated Statements of Income (pro forma statements of income) for the three months ended March 31, 2015 and the year ended December 31, 2014 give effect to the merger as if it were completed on January 1, 2014. The Unaudited Pro Forma Condensed Combined Consolidated Balance Sheet (pro forma balance sheet) as of March 31, 2015 gives effect to the merger as if it were completed on March 31, 2015.

The historical consolidated financial information has been adjusted in the pro forma financial statements to give effect to pro forma events that are: (1) directly attributable to the merger; (2) factually supportable; and (3) with respect to the statements of income, expected to have a continuing impact on the combined results of Wisconsin Energy and Integrys. As such, the impact from merger-related expenses is not included in the accompanying pro forma statements of income. However, the impact of these expenses is reflected in the pro forma balance sheet as an increase to accounts payable and other current liabilities and a decrease to retained earnings.

The pro forma financial statements do not reflect any cost savings (or associated costs to achieve such savings) from operating efficiencies or synergies that could result from the merger. Further, the pro forma financial statements do not reflect the effect of any regulatory actions that may impact the pro forma financial statements when the merger is completed.

Accounting standards generally accepted in the United States require that one party to the merger be identified as the acquirer. In accordance with these standards, the merger of Wisconsin Energy and Integrys will be accounted for as an acquisition of Integrys common shares by Wisconsin Energy and will follow the acquisition method of accounting for business combinations. The final purchase price will be determined on the basis of the fair value on the acquisition date of the common shares of Wisconsin Energy issued in the merger. The purchase price for the pro forma financial statements is based on the closing price of Wisconsin Energy common shares on the NYSE on May 15, 2015 of $48.00 per share and the exchange of Integrys’ common shares for the right to receive 1.128 common shares of Wisconsin Energy, plus $18.58 in cash.

Assumptions and estimates underlying the pro forma adjustments are described in the accompanying notes, which should be read in connection with the pro forma financial statements. Since the pro forma financial statements have been prepared based on preliminary estimates, the final amounts recorded at the date of the merger may differ materially from the information presented. These estimates are subject to change pending further review of the assets acquired and liabilities assumed and the final purchase price.

The pro forma financial statements have been presented for illustrative purposes only and are not necessarily indicative of the results of operations and financial position that would have been achieved had the pro forma events taken place on the dates indicated, or the future consolidated results of operations or financial position of the combined company.

The following pro forma financial statements should be read in conjunction with:

· the accompanying notes to the Unaudited Pro Forma Condensed Combined Consolidated Financial Statements;

· the consolidated financial statements of Wisconsin Energy as of and for the year ended December 31, 2014 included in Wisconsin Energy’s Form 10-K;
· the unaudited condensed consolidated financial statements of Wisconsin Energy as of and for the three months ended March 31, 2015 included in Wisconsin Energy’s Form 10-Q;

· the consolidated financial statements of Integrys as of and for the year ended December 31, 2014 included in Integrys’ Form 10-K;

· the unaudited condensed consolidated financial statements of Integrys as of and for the three months ended March 31, 2015 included in Integrys’ Form 10-Q; and
· the other information contained in or incorporated by reference into this document.

2

WEC ENERGY GROUP, INC.
UNAUDITED PRO FORMA CONDENSED COMBINED
CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2015

	Wisconsin Energy		Integrys		Pro Forma Adjustments			Note 3	Pro Forma Combined
	(Millions of Dollars, Except Per Share Amounts)
Operating Revenues	$	1,387.9	$	1,163.2	$	(0.5	)	(b)	$	2,550.6
Operating Expenses
Cost of sales	613.9		577.7		(0.5		)	(b)	1,191.1
Other operations and maintenance	280.7		272.7		(9.4		)	(c)	544.0
Depreciation and amortization	105.1		74.7		—				179.8
Property and revenue taxes	31.9		13.9		—				45.8
Total Operating Expenses	1,031.6		939.0		(9.9		)		1,960.7
Treasury Grant	2.5		—		—				2.5
Operating Income	358.8		224.2		9.4				592.4
Earnings From Equity Method Investments	16.1		17.5		—				33.6
Other Income, net	3.0		6.6		—				9.6
Interest Expense, net	59.7		39.0		8.6			(d)	107.3
Income From Continuing Operations Before Income Taxes	318.2		209.3		0.8				528.3
Income Tax Expense	122.4		78.9		(2.9		)	(e)	198.4
Net Income From Continuing Operations	$	195.8	$	130.4	$	3.7			$	329.9
Earnings Per Share
Basic	$	0.87	$	1.62					$	1.05
Diluted	$	0.86	$	1.61					$	1.04
Weighted Average Common Shares Outstanding (millions)
Basic	225.5		80.2		9.5			(f)	315.2
Diluted	227.3		80.8		8.9			(f)	317.0

See accompanying Notes to the Unaudited Pro Forma Condensed Combined Consolidated Financial Statements, which are an integral part of these statements.

3

WEC ENERGY GROUP, INC.
UNAUDITED PRO FORMA CONDENSED COMBINED
CONSOLIDATED STATEMENTS OF INCOME
For the Year Ended December 31, 2014

	Wisconsin Energy		Integrys		Pro Forma Adjustments			Note 3	Pro Forma Combined
	(Millions of Dollars, Except Per Share Amounts)
Operating Revenues	$	4,997.1	$	4,144.2	$	(7.3	)	(b)	$	9,134.0
Operating Expenses
Cost of sales	2,259.4		2,133.0		(7.3		)	(b)	4,385.1
Other operation and maintenance	1,112.4		1,252.5		(25.0		)	(c)	2,339.9
Depreciation and amortization	408.8		287.5		—				696.3
Property and revenue taxes	121.8		54.6		—				176.4
Total Operating Expenses	3,902.4		3,727.6		(32.3		)		7,597.7
Treasury Grant/Gain on Asset Sales	17.4		90.4		—				107.8
Operating Income	1,112.1		507.0		25.0				1,644.1
Earnings From Equity Method Investments	66.0		88.3		—				154.3
Other Income, net	13.4		31.1		—				44.5
Interest Expense, net	241.5		157.9		29.7			(d)	429.1
Income From Continuing Operations Before Income Taxes	950.0		468.5		(4.7		)		1,413.8
Income Tax Expense	361.7		193.4		(7.4		)	(e)	547.7
Net Income From Continuing Operations	$	588.3	$	275.1	$	2.7			$	866.1
Earnings Per Share
Basic	$	2.61	$	3.43					$	2.75
Diluted	$	2.59	$	3.41					$	2.73
Weighted Average Common Shares Outstanding (millions)
Basic	225.6		80.2		9.5			(f)	315.3
Diluted	227.5		80.7		9.0			(f)	317.2

See accompanying Notes to the Unaudited Pro Forma Condensed Combined Consolidated Financial Statements, which are an integral part of these statements.

4

WEC ENERGY GROUP, INC.
UNAUDITED PRO FORMA CONDENSED COMBINED
CONSOLIDATED BALANCE SHEET
As of March 31, 2015

	Wisconsin Energy		Integrys		Pro Forma Adjustments			Note 3	Pro Forma Combined
	(Millions of Dollars)
Assets
Property, Plant and Equipment, Net	$	11,316.0	$	6,928.8	$	—			$	18,244.8
Investments
Equity method investments	431.1		556.0		—				987.1
Other	33.0		112.3		—				145.3
Total Investments	464.1		668.3		—				1,132.4
Current Assets
Cash and cash equivalents	65.2		86.4		—				151.6
Accounts receivable, net	437.3		513.3		—				950.6
Accrued revenues	221.6		207.5		—				429.1
Materials, supplies and inventories	289.7		179.9		—				469.6
Current deferred tax asset, net	170.3		39.8		32.0			(g)	242.1
Assets held for sale	—		51.5		—				51.5
Prepayments and other	142.3		180.9		—				323.2
Total Current Assets	1,326.4		1,259.3		32.0				2,617.7
Deferred Charges and Other Assets
Regulatory assets	1,270.0		1,507.3		—				2,777.3
Goodwill	441.9		655.4		2,497.5			(h)	3,594.8
Other	317.2		149.9		1.2			(i)	468.3
Total Deferred Charges and Other Assets	2,029.1		2,312.6		2,498.7				6,840.4
Total Assets	$	15,135.6	$	11,169.0	$	2,530.7			$	28,835.3
Capitalization and Liabilities
Capitalization
Common equity	$	4,510.6	$	3,362.6	$	885.6		(j)	$	8,758.8
Preferred stock of subsidiaries	30.4		51.1		—				81.5
Long-term debt	4,169.2		2,956.3		1,478.9			(k)	8,604.4
Total Capitalization	8,710.2		6,370.0		2,364.5				17,444.7
Current Liabilities
Long-term debt due currently	426.8		125.0		—				551.8
Short-term debt	563.0		133.3		151.2			(l)	847.5
Accounts payable	291.9		414.6		37.2			(m)	743.7
Liabilities held for sale	58.8		13.6		—				72.4
Other	219.8		562.3		25.0			(m)	807.1
Total Current Liabilities	1,560.3		1,248.8		213.4				3,022.5
Deferred Credits and Other Liabilities
Regulatory liabilities	820.3		402.4		—				1,222.7
Deferred income taxes - long-term	2,942.4		1,599.5		(47.6		)	(n)	4,494.3
Deferred revenue, net	604.7		—		—				604.7
Pension and other benefit obligations	203.5		271.2		—				474.7
Environmental remediation liabilities	32.6		573.2		—				605.8
Asset retirement obligations	44.2		485.0		—				529.2
Other long-term liabilities	217.4		218.9		0.4			(o)	436.7
Total Deferred Credits and Other Liabilities	4,865.1		3,550.2		(47.2		)		8,368.1
Total Capitalization and Liabilities	$	15,135.6	$	11,169.0	$	2,530.7			$	28,835.3

See accompanying Notes to the Unaudited Pro Forma Condensed Combined Consolidated Financial Statements, which are an integral part of these statements.

5

NOTES TO THE UNAUDITED PRO FORMA CONDENSED
COMBINED CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Basis of Pro Forma Presentation

The pro forma statements of income for the three months ended March 31, 2015 and the year ended December 31, 2014 give effect to the merger as if it were completed on January 1, 2014. The pro forma balance sheet as of March 31, 2015 gives effect to the merger as if it were completed on March 31, 2015.

The pro forma financial statements have been derived from the historical consolidated financial statements of Wisconsin Energy and Integrys. Assumptions and estimates underlying the pro forma adjustments are described in the accompanying notes, which should be read in conjunction with the pro forma financial statements. Since the pro forma financial statements have been prepared based on preliminary estimates, the final amounts recorded at the date of the merger may differ materially from the information presented. These estimates are subject to change pending further review of the assets acquired and liabilities assumed.

The merger is reflected in the pro forma financial statements as being accounted for as an acquisition of Integrys by Wisconsin Energy, based on the guidance provided by accounting standards for business combinations. Under the acquisition method, the total estimated purchase price is calculated as described in Note 2 to the pro forma financial statements. The assets acquired and the liabilities assumed have been measured at estimated fair value. For the purpose of measuring the estimated fair value of the assets acquired and liabilities assumed, Wisconsin Energy has applied the accounting guidance for fair value measurements. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date. The fair value measurements utilize estimates based on key assumptions of the merger, including historical and current market data. The pro forma adjustments included herein are preliminary and will be revised at the time of the merger as additional information becomes available and as additional analyses are performed. The final purchase price allocation will be determined at the time that the merger is completed, and the final amounts recorded for the merger may differ materially from the information presented.

Estimated transaction costs have been excluded from the pro forma statements of income as they reflect non-recurring charges directly related to the merger. However, the anticipated transaction costs are reflected in the pro forma balance sheet as an increase to accounts payable and other current liabilities and a decrease to retained earnings.

The pro forma financial statements do not reflect any cost savings (or associated costs to achieve such savings) from operating efficiencies that could result from the merger. Further, the pro forma financial statements do not reflect the effect of any regulatory actions that may impact the pro forma financial statements when the merger is completed.

Integrys’ regulated operations are comprised of the distribution of electricity and gas. These operations are subject to the retail rate-setting authority of various state regulatory commissions and the Federal Energy Regulatory Commission, which includes provisions in place that provide revenues to recover costs of service, including a carrying charge on most net assets and liabilities. For the net assets and liabilities earning a carrying charge, the carrying values approximate fair values and pro forma adjustments are not required.

Note 2. Preliminary Purchase Price

Wisconsin Energy will acquire all of the outstanding shares of Integrys common stock. Integrys shareholders will be entitled to receive for each share of Integrys common stock 1.128 shares of Wisconsin Energy common stock plus $18.58 in cash.

6

NOTES TO THE UNAUDITED PRO FORMA CONDENSED

COMBINED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2. Preliminary Purchase Price (Continued)

The purchase price for the merger is estimated as follows (shares in thousands):

	Purchase Price Paid in
	Stock		Cash		Total
Integrys shares issued and outstanding as of March 31, 2015 *	79,963		79,963
Exchange ratio	1.128
Wisconsin Energy shares issued for Integrys shares	90,198
Closing price of Wisconsin Energy shares on May 15, 2015	$	48.00
Estimated Fair Value of common stock issued	$	4,329.5			$	4,329.5
Cash paid per share of Integrys share			$	18.58
Estimated Fair Value of cash paid for Integrys shares			$	1,485.7	$	1,485.7
Estimated consideration for Integrys shares					5,815.2
Estimated consideration attributable to settlement of equity awards			$	21.4	$	21.4
Total purchase price (in millions)	$	4,329.5	$	1,507.1	$	5,836.6

* Includes 428.9 thousand shares of Integrys common stock held in a rabbi trust.

The preliminary purchase price reflects the market value of Wisconsin Energy common shares to be issued in connection with the merger based on the closing price of Wisconsin Energy’s common shares on May 15, 2015. The preliminary purchase price will fluctuate with the market price of Wisconsin Energy’s common shares until it is reflected on an actual basis when the merger is completed. An increase or decrease of 10 percent in Wisconsin Energy’s common share price from the $48.00 price used above would increase or decrease the purchase price by approximately $435 million.

Note 3. Adjustments to Pro Forma Financial Statements

The pro forma adjustments included in the pro forma condensed combined financial statements are as follows:

(a)Wisconsin Energy and Integrys historical presentation—Based on the amounts reported in the consolidated statements of income and balance sheets of Wisconsin Energy and Integrys as of and for the three months ended March 31, 2015 and the consolidated statements of income for the year ended December 31, 2014. Certain financial statement line items included in Wisconsin Energy’s and Integrys’ historical presentation have been reclassified to conform to corresponding line items included in Integrys’ and Wisconsin Energy’s historical presentation, respectively. These reclassifications have no material impact on the historical operating income, net income, total assets, liabilities, or shareholders’ equity reported by Wisconsin Energy or Integrys. Additionally, based on a comparison of Integrys’ summary of significant accounting policies disclosed in Integrys’ financial statements with those of Wisconsin Energy and preliminary discussions with Integrys management, the nature and amount of any adjustments to the historical financial statements of Integrys to conform its accounting policies to those of Wisconsin Energy are not expected to be material. Upon completion of the merger, further review of Integrys’ accounting policies and financial statements may result in revisions to Integrys’ policies and classifications to conform to Wisconsin Energy.

7

NOTES TO THE UNAUDITED PRO FORMA CONDENSED

COMBINED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 3. Adjustments to Pro Forma Financial Statements (Continued)

The allocation of the preliminary purchase price to the fair values of assets acquired and liabilities assumed includes pro forma adjustments to reflect the fair values of Integrys’ assets and liabilities. The allocation of the preliminary purchase price is as follows (in millions):

Current Assets	$	1,259.3
Property, Plant and Equipment, Net	6,928.8
Goodwill	3,152.9
Other Long-Term Assets, excluding Goodwill *	2,340.4
Current Liabilities	(1,248.8		)
Other Long-Term Liabilities	(3,509.7		)
Long-term Debt	(3,035.2		)
Preferred Stock of Subsidiary	(51.1		)
Total Purchase Price	$	5,836.6

* Includes $23.2 million related to the 0.5 million shares of Wisconsin Energy common stock held in the Integrys rabbi trust. These shares are being reflected as treasury stock on the pro forma balance sheet.

Adjustments to Pro Forma Condensed Combined Consolidated Statements of Income

(b)Operating Revenues and Cost of Sales—Reflects the elimination of sales and purchases between Wisconsin Energy and Integrys ($0.5 million for the three months ended March 31, 2015 and $7.3 million for the year ended December 31, 2014).

(c)Other Operation and Maintenance—Reflects the elimination of non-recurring transaction costs directly attributable to the merger ($9.4 million for the three months ended March 31, 2015 and $25.0 million for the year ended December 31, 2014).

(d)Interest Expense—Adjustment reflects an increase in interest expense as a result of Wisconsin Energy borrowing an additional $1.5 billion to meet the cash payment requirements of the cash component of the purchase price ($18.58 for each outstanding share of Integrys common stock and the cash settlement of Integrys’ equity awards). The pro forma interest expense associated with the issuance of the $1.5 billion of debt increased interest expense by $9.1 million for the three months ended March 31, 2015 and $36.3 million for the year ended December 31, 2014, and debt issuance costs increased interest expense by $0.4 million for the three months ended March 31, 2015 and $1.8 million for the year ended December 31, 2014. An increase or decrease of one-eighth percent to the U.S. bond yield rate would increase or decrease Wisconsin Energy’s interest expense by $0.5 million for the three months ended March 31, 2015 and $1.9 million for the year ended December 31, 2014.

In addition, the adjustment reflects a reduction in interest expense as a result of the amortization of the pro forma fair value adjustments of Integrys’ parent company debt ($0.5 million and $4.9 million for the three months ended March 31, 2015 and the year ended December 31, 2014, respectively) and the elimination of the amortization of deferred issuance costs related to this debt ($0.4 million for the three months ended March 31, 2015 and $3.5 million for the year ended December 31, 2014). The effect of the fair value adjustment is being amortized over the estimated remaining life of the individual debt issuances, with the longest amortization period extending to the year 2023.

8

NOTES TO THE UNAUDITED PRO FORMA CONDENSED

COMBINED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 3. Adjustments to Pro Forma Financial Statements (Continued)

(e)Income Tax Expense—Reflects the income tax effects of the pro forma adjustments calculated using an estimated statutory income tax rate of 40 percent, modified for any attributable permanent tax effects.

(f)Shares Outstanding—Reflects the elimination of Integrys’ common shares and the issuance of approximately 90.2 million Wisconsin Energy common shares, including 0.5 million shares issued to the Integrys rabbi trust. This share issuance does not consider that fractional shares will be paid in cash and assumes all Integrys stock-based compensation is cashed out at closing. The pro forma weighted average number of basic shares outstanding is calculated by adding Wisconsin Energy’s weighted average number of basic shares outstanding during the three months ended March 31, 2015 and the year ended December 31, 2014, respectively, and the number of Wisconsin Energy shares expected to be issued and outstanding as a result of the merger. The pro forma weighted average number of diluted shares outstanding is calculated by adding Wisconsin Energy’s weighted average number of diluted shares outstanding during the three months ended March 31, 2015 and the year ended December 31, 2014, respectively, and the number of Wisconsin Energy shares expected to be issued and outstanding as a result of the merger.

	Three Months Ended March 31, 2015		Year Ended December 31, 2014
	(Shares in millions)
Basic
Wisconsin Energy weighted average number of basic shares outstanding	225.5		225.6
Equivalent Integrys common shares after exchange*	90.2		90.2
Less: Equivalent shares in rabbi trust	(0.5	)	(0.5	)
	89.7		89.7
	315.2		315.3
Diluted
Wisconsin Energy weighted average number of diluted shares outstanding	227.3		227.5
Equivalent Integrys common shares after exchange*	90.2		90.2
Less: Equivalent shares in rabbi trust	(0.5	)	(0.5	)
	89.7		89.7
	317.0		317.2

*See Note 2 for supporting calculation

9

NOTES TO THE UNAUDITED PRO FORMA CONDENSED

COMBINED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 3. Adjustments to Pro Forma Financial Statements (Continued)

Adjustments to Pro Forma Condensed Combined Consolidated Balance Sheet

(g)Current Deferred Tax Asset, Net—Reflects an increase of $32.0 million related to the expected tax benefits associated with the settlement of Integrys’ equity awards and non-recurring transaction costs.

(h)Goodwill—Reflects the preliminary estimate of the excess of the purchase price paid over the fair value of Integrys’ assets acquired and liabilities assumed. The estimated purchase price of the transaction, based on the closing price of Wisconsin Energy common shares on the NYSE on May 15, 2015, and the excess purchase price over the fair value of the net assets acquired is calculated as follows (in millions):

Purchase price	$	5,836.6
Less: Fair value of net assets acquired	2,683.7
Less: Integrys existing goodwill	655.4
Pro forma goodwill adjustment	$	2,497.5

(i)Other Long-Term Assets—Reflects $9.5 million of capitalized debt issuance costs associated with the $1.5 billion Wisconsin Energy debt issuance, the elimination of $16.3 million of Integrys capitalized debt issuance costs, and an increase of $8.0 million related to the funding of the Integrys rabbi trust.

(j)Common Equity—Reflects additional equity of $4,329.5 million related to the approximately 90.2 million new Wisconsin Energy common shares outstanding, the elimination of Integrys’ historical equity balance (including accumulated other comprehensive loss) of $3,362.6 million, and a reduction to retained earnings totaling $58.1 million, net of taxes, for estimated transaction costs of the combined companies directly related to the merger that would be expensed. It also reflects a reduction in equity of $23.2 million related to common shares held in a rabbi trust.

(k)Long-Term Debt—In connection with the merger agreement, Wisconsin Energy will assume all of Integrys’ outstanding debt. The pro forma adjustment represents the issuance of $1.4 billion of long-term debt by Wisconsin Energy (an additional $100.0 million of short-term debt is also expected to be issued) and a fair value adjustment of $78.9 million to increase Integrys’ parent company debt based on prevailing values for comparable securities as of March 31, 2015. The final fair value determination of the debt will be based on prevailing values for comparable securities at the completion of the merger.

(l)Short-Term Debt—Reflects $100.0 million of short-term debt that is expected to be issued in connection with the $1.5 billion debt offering related to the merger, $56.0 million of additional short-term debt to finance the settlement of Integrys’ equity awards, and a reduction of short-term debt of $4.8 million associated with cash proceeds from the $1.5 billion debt offering.

(m)Accounts Payable and Other Current Liabilities—Represents the accrual for estimated non-recurring transaction costs totaling $62.2 million for the combined companies to be incurred after March 31, 2015.

(n)Deferred Income Taxes—Long-Term—Represents a reduction of the estimated deferred tax liability of $47.6 million. Adjustment is based on the combined companies’ estimated post-merger composite statutory tax rate of 40 percent multiplied by the fair value adjustments recorded to the assets acquired and liabilities assumed, excluding goodwill. This estimated tax rate is different from Wisconsin

10

NOTES TO THE UNAUDITED PRO FORMA CONDENSED

COMBINED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 3. Adjustments to Pro Forma Financial Statements (Continued)

Energy’s effective tax rates for the year ended December 31, 2014 and the three months ended March 31, 2015, which include tax items that vary from the statutory rates. The estimated combined 40 percent tax rate does not take into account any historical or possible future tax events that may impact the combined company.

(o)Other Long-Term Liabilities—Reflects an adjustment of $24.0 million to recognize a net increase to the liabilities recorded by Integrys related to its stock-based compensation plans and deferred compensation plan. Also includes a $23.6 million fair value adjustment to reduce Integrys’ deferred income tax credits related to its solar assets.

Note 4. Investment in the American Transmission Company

Equity method investments include the companies’ combined 60 percent ownership of the American Transmission Company (ATC). Wisconsin Energy has made commitments with respect to its voting rights of the combined ownership of ATC. These commitments are included as enforceable conditions in the orders approving the merger by the Federal Energy Regulatory Commission and the Public Service Commission of Wisconsin. We also expect these voting commitments to be made a part of ATC’s governance documents. We believe that under generally accepted accounting principles in the United States, these commitments will not allow us to consolidate ATC in our financial statements when the merger closes.

11