UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~March~~June 3130, 2015

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________ to __________

Commission File Number		Registrant; State of Incorporation; Address; and Telephone Number		IRS EmployerIdentification No.
1-11337		INTEGRYS ~~ENERGY GROUP~~HOLDING, INC.(successor to Integrys Energy Group, Inc.)(A Wisconsin Corporation)~~200~~231 ~~East~~West ~~Randolph~~Michigan Street ~~Chicago~~Milwaukee, ILWI ~~60601-6207~~53201 (~~312~~414) ~~228~~221-~~5400~~2345		3947-~~1775292~~1477787

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

Yes [X] No [ ]

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

Yes [X] No [ ]

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

Large accelerated filer [X] Accelerated filer [ ]

Non-accelerated filer [ ] Smaller reporting company [ ]

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

Yes [ ] No [X]

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

Common stock, $10.01 par value,

791,~~963,091~~000 shares outstanding at

~~May~~August 45, 2015

Table of Contents

INTEGRYS ~~ENERGY GROUP~~HOLDING, INC.

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended ~~March~~June 3130, 2015

TABLE OF CONTENTS

				Page
	Forward-Looking Statements			1
PART I.	FINANCIAL INFORMATION			2
Item 1.	Financial Statements (Unaudited)			2
	Condensed Consolidated Statements of Income			2
	Condensed Consolidated Statements of Comprehensive Income			3
	Condensed Consolidated Balance Sheets			4
	Condensed Consolidated Statements of Cash Flows			5
	Condensed Notes to Financial Statements			6
			Page
	Note 1	Basis of Presentation	6
	Note 2	~~Proposed~~WEC Merger ~~with Wisconsin Energy Corporation~~	67
	Note 3	~~Acquisitions~~Dispositions	67
	Note 4	~~Dispositions~~Cash and Cash Equivalents	68
	Note 5	~~Cash~~Investment ~~and~~in ~~Cash Equivalents~~ATC	89
	Note 6	~~Investment in ATC~~Inventories	910
	Note 7	~~Inventories~~Goodwill and Other Intangible Assets	10
	Note 8	~~Goodwill~~Short-Term Debt and ~~Other~~Lines ~~Intangible~~of ~~Assets~~Credit	10
	Note 9	~~Short~~Long-Term Debt ~~and Lines of Credit~~	11
	Note 10	Income Taxes	11
	Note 11	Commitments and Contingencies	12
	Note 12	Guarantees	1415
	Note 13	Employee Benefit Plans	15
	Note 14	Stock-Based Compensation	1516
	Note 15	Common Equity	1716
	Note 16	Accumulated Other Comprehensive Loss	1917
	Note 17	~~Variable~~Risk ~~Interest~~Management ~~Entities~~Activities	2017
	Note 18	~~Risk~~Fair ~~Management Activities~~Value	2119
	Note 19	~~Fair~~Regulatory ~~Value~~Environment	23
	Note 20	~~Regulatory~~Segments ~~Environment~~of Business	25
	Note 21	~~Segments~~New ofAccounting ~~Business~~Pronouncements	27
	Note 22	New Accounting Pronouncements	28
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			28
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			30
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk			45
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk			42
ITEM 4.	Controls and Procedures			46
ITEM 4.	Controls and Procedures			43
PART II.	OTHER INFORMATION			47
PART II.	OTHER INFORMATION			44
ITEM 1.	Legal Proceedings			47
ITEM 1.	Legal Proceedings			44
ITEM 1A.	Risk Factors			48
ITEM 1A.	Risk Factors			45
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds			49
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds			46
ITEM 6.	Exhibits			49
ITEM 6.	Exhibits			46
Signature				50
Signature				47
EXHIBIT INDEX				51
EXHIBIT INDEX				48

Table of Contents

Acronyms Used in this Quarterly Report on Form 10-Q

~~AFUDC Allowance for Funds Used During Construction~~ AMRP Accelerated Natural Gas Main Replacement Program ASC Accounting Standards Codification ASU Accounting Standards Update ATC American Transmission Company LLC EPA United States Environmental Protection Agency FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission GAAP United States Generally Accepted Accounting Principles ~~IBS Integrys Business Support, LLC~~ ICC Illinois Commerce Commission IES Integrys Energy Services, Inc. IRS United States Internal Revenue Service ITF Integrys Transportation Fuels, LLC (doing business as Trillium CNG) MERC Minnesota Energy Resources Corporation MGU Michigan Gas Utilities Corporation MISO Midcontinent Independent System Operator, Inc. MPSC Michigan Public Service Commission MPUC Minnesota Public Utilities Commission N/A Not Applicable NSG North Shore Gas Company ~~PDI~~PDL WPS Power Development, LLC (formerly known as WPS Power Development, Inc.) PELLC Peoples Energy, LLC (formerly known as Peoples Energy Corporation) PGL The Peoples Gas Light and Coke Company PSCW Public Service Commission of Wisconsin SEC United States Securities and Exchange Commission UPPCO Upper Peninsula Power Company WBS WEC Business Services, LLC (formerly known as Integrys Business Support, LLC) WDNR Wisconsin Department of Natural Resources WEC WEC Energy Group, Inc. WPS Wisconsin Public Service Corporation

Table of Contents

Forward-Looking Statements

In this report, we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. These statements are "forward-looking statements" within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements are not guarantees of future results and conditions. Although we believe that these forward-looking statements and the underlying assumptions are reasonable, we cannot provide assurance that such statements will prove correct.

Forward-looking statements involve a number of risks and uncertainties. Some risks and uncertainties that could cause actual results to differ materially from those expressed or implied in forward-looking statements include those described in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2014, as may be amended or supplemented in Part II, Item 1A of our subsequently filed Quarterly Reports on Form 10-Q (including this report), and those identified below:


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


•	Federal and state legislative and regulatory changes, including deregulation and restructuring of the electric and natural gas utility industries, financial reform, health care reform, energy efficiency mandates, reliability standards, pipeline integrity and safety standards, and changes in tax and other laws and regulations to which we and our subsidiaries are subject;

• The possibility that the proposed merger with Wisconsin Energy Corporation does not close (including, but not limited to, due to the failure to satisfy the closing conditions), disruption from the proposed merger making it more difficult to maintain our business and operational relationships, and the risk that unexpected costs will be incurred during this process;


•	The risk of terrorism or cyber security attacks, including the associated costs to protect our assets and respond to such events;


•	The risk of failure to maintain the security of personally identifiable information, including the associated costs to notify affected persons and to mitigate their information security concerns;


•	The timely completion of capital projects within estimates, as well as the recovery of those costs through established mechanisms;


•	Unusual weather and other natural phenomena, including related economic, operational, and/or other ancillary effects of any such events;


•	The impact of unplanned facility outages;


•	The risks associated with changing commodity prices, particularly natural gas and electricity, and the available sources of fuel, natural gas, and purchased power, including their impact on margins, working capital, and liquidity requirements;


•	The effects of political developments, as well as changes in economic conditions and the related impact on customer energy use, customer growth, and our ability to adequately forecast energy use for our customers;


•	Federal and state legislative and regulatory changes relating to the environment, including climate change and other environmental regulations impacting generation facilities and renewable energy standards;


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


•	Changes in credit ratings and interest rates caused by volatility in the financial markets and actions of rating agencies and their impact on our and our subsidiaries' liquidity and financing efforts;

• The terms and conditions of the governmental and regulatory approvals of the WEC Merger could reduce anticipated benefits, and the ability to ~~retain~~successfully ~~market-based~~integrate ~~rate~~our ~~authority~~operations with Wisconsin Energy Corporation;


•	The effects, extent, and timing of competition or additional regulation in the markets in which our subsidiaries operate;


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


•	The ability to use tax credit, net operating loss, and/or charitable contribution carryforwards;


•	The investment performance of employee benefit plan assets and related actuarial assumptions, which impact future funding requirements;


•	The risk associated with the value of goodwill or other intangible assets and their possible impairment;


•	Potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed timely or within budgets;


•	Changes in technology, particularly with respect to new, developing, or alternative sources of generation;


•	The financial performance of ATC and its corresponding contribution to our earnings;


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


•	The effectiveness of risk management strategies, the use of financial and derivative instruments, and the related recovery of these costs from customers in rates;


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


•	Other factors discussed elsewhere herein and in other reports we file with the SEC.

Except to the extent required by the federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

INTEGRYS ~~ENERGY GROUP~~HOLDING, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)	Three Months Ended						Six Months Ended
	March 31
	June 30						June 30
(Millions, except per share data)	2015			2014
(Millions)	2015			2014			2015			2014
Operating revenues	$	~~1,163~~638.23		$	~~1,638~~837.01		$	1,801.8		$	2,475.4
Cost of sales	~~577~~217.71			~~975~~400.62			790.2			1,373.1
Operating and maintenance expense	~~261~~268.0			~~332~~318.60			540.1			662.4
Depreciation and amortization expense	7472.71			7072.68			147.5			144.2
Taxes other than income taxes	25.6			26.9
Property and revenue taxes	17.9			17.2			36.1			34.7
Operating income	224.2			232.3
Merger costs	59.3			5.9			60.0			5.9
Earnings from equity method investments	17.5			22.9
Impairment loss on property, plant, and equipment at PDL	10.7			—			10.7			—
Miscellaneous income	6.6			5.8
Gain on sale of certain PDL solar power generation plants	(5.2		)	—			(5.2		)	—
Interest expense	38.2			38.9
Operating (loss) income	(1.6		)	23.0			222.4			255.1
Other expense	(14.1		)	(10.2		)
Equity in earnings of transmission affiliate	22.4			23.0			39.4			45.5
Income before taxes	210.1			222.1
Miscellaneous income	1.8			5.8			9.1			12.3
Provision for income taxes	78.9			81.9
Interest expense	40.0			39.3			79.0			79.0
Net income from continuing operations	131.2			140.2
Other expense	(15.8		)	(10.5		)	(30.5		)	(21.2		)
Discontinued operations, net of tax	(0.9		)	12.9
(Loss) income before taxes	(17.4		)	12.5			191.9			233.9
Net income	130.3			153.1
(Benefit) provision for income taxes	(8.1		)	4.5			70.9			86.4
Preferred stock dividends of subsidiary	(0.8		)	(0.8		)
Net (loss) income from continuing operations	(9.3		)	8.0			121.0			147.5
Noncontrolling interest in subsidiaries	—			0.1
Discontinued operations, net of tax	—			(0.8		)	(0.8		)	12.1
Net income attributed to common shareholders	$	129.5		$	152.4
Net (loss) income	$	(9.3	)	$	7.2		$	120.2		$	159.6
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.

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INTEGRYS ~~ENERGY GROUP~~HOLDING, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)	Three Months Ended						Six Months Ended
	March 31
	June 30						June 30
(Millions)	2015			2014			2015		2014
Net income	$	130.3		$	153.1
Net (loss) income	$	(9.3	)	$	7.2		$	120.2	$	159.6
Other comprehensive income (loss), net of tax:
Other comprehensive income, 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		)
Reclassification of net losses (gains) to net income, net of tax of $0.1 million, $ – million, $0.2 million, and $0.9 million, respectively	0.2			0.2			0.3		(0.4		)
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		)
Pension and other postretirement benefit adjustments arising during period, net of tax of $0.4 million, $ – million, $0.4 million, and $(0.1) million, respectively	0.7			—			0.7		(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
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, net of tax of $0.6 million, $0.2 million, $1.1 million, and $0.5 million, respectively	0.9			0.5			1.6		0.8
Defined benefit plans, net	01.76			0.25			2.3		0.7
Other comprehensive income (loss), net of tax	0.8			(0.4		)
Other comprehensive income, net of tax	1.8			0.7			2.6		0.3
Comprehensive income	131.1			152.7
Comprehensive (loss) income	$	(7.5	)	$	7.9		$	122.8	$	159.9
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.

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INTEGRYS ~~ENERGY GROUP~~HOLDING, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)	~~March~~June 3130			December 31
(Millions, except share and per share data)	2015			2014
Assets
Cash and cash equivalents	$	86156.43		$	18.0
Accounts receivable and accrued unbilled revenues, net of reserves of $58.3 and $63.3, respectively	720.8			699.8
Accounts receivable, net of reserves of $55.2 and $60.3, respectively	341.6			480.7
Inventories	179.9			327.2
Receivables from related parties	27.3			—
Regulatory assets	86.2			118.9
Accrued unbilled revenues	110.6			266.4
Assets held for sale	51.5			52.2
Materials, supplies, and inventories	234.1			327.7
Deferred income taxes	39.8			52.4
Assets held for sale	—			51.5
Prepaid taxes	51.7			136.2
Deferred income taxes	119.4			52.4
Other current assets	43.0			57.4
Prepaid taxes	77.2			136.2
Current assets	1,259.3			1,462.1
Other current assets	80.7			57.4
Property, plant, and equipment, net of accumulated depreciation of $3,330.2 and $3,322.0, respectively	6,928.8			6,827.7
Current assets	1,147.2			1,390.3
Regulatory assets	1,507.3			1,513.6
Property, plant, and equipment, net of accumulated depreciation of $3,227.2 and $3,322.0, respectively	7,098.2			6,827.9
Equity method investments	556.0			550.6
Regulatory assets	1,582.0			1,585.3
Equity investment in transmission affiliate	552.0			536.7
Goodwill	655.4			655.4
Other long-term assets	~~262~~276.26			~~272~~286.64
Total assets	$	11,~~169~~311.04		$	11,282.0
Liabilities and Equity
Short-term debt	$	~~133~~314.34		$	317.6
Current portion of long-term debt	~~125~~180.0			125.0
Accounts payable	~~414~~435.61			490.7
Accrued taxes	108.6			87.7
Payables to related parties	1.8			—
Regulatory liabilities	171.6			153.7
Energy costs refundable through rate adjustments	69.0			44.8
Liabilities held for sale	~~13.6~~—			13.8
Other current liabilities	~~282~~303.18			~~261~~348.07
Current liabilities	1,~~248~~304.81			1,~~449~~340.56
Long-term debt	2,~~956~~901.3			2,956.3
Deferred income taxes	1,~~599~~692.59			1,570.0
Deferred investment tax credits	6365.60			60.6
Regulatory liabilities	~~402~~492.46			~~399~~508.98
Environmental remediation liabilities	~~573~~576.2			579.9
Pension and other postretirement benefit obligations	~~271~~275.26			274.6
Asset retirement obligations	~~485~~491.0			479.1
Other long-term liabilities	~~155~~189.32			161.3
Long-term liabilities	6,~~506~~683.58			6,~~481~~590.76
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
Common stock – $0.01 par value; 1,000 shares authorized, issued, and outstanding at June 30, 2015 and $1 par value; 200,000,000 shares authorized; 79,963,091 shares issued; 79,534,171 shares outstanding at December 31, 2014	—			80.0
Additional paid-in capital	2,~~629~~699.23			2,642.2
Retained earnings	~~701~~619.19			626.0
Accumulated other comprehensive loss	(2625.80		)	(27.6		)
Shares in deferred compensation trust	(2021.98		)	(20.9		)
Total common shareholders’ equity	3,~~362~~272.64			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~~311.04		$	11,282.0

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

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INTEGRYS ~~ENERGY GROUP~~HOLDING, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	~~Three~~Six Months Ended
	March 31
	June 30
(Millions)	2015			2014
Operating Activities
Net income	$	~~130~~120.32		$	~~153~~159.16
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization expense	74149.79			71147.39
Recoveries and refunds of regulatory assets and liabilities	18.1			54.1
Deferred income taxes and investment tax credits, net	58.3			83.4
Net unrealized gains on energy contracts	(0.5		)	(19.7		)
Pension and other postretirement contributions	(6.2		)	(69.5		)
Bad debt expense	9.2			19.3
Goodwill impairment loss	—			6.7
Pension and other postretirement expense	7.7			7.2
Impairment loss on property, plant, and equipment at PDL	10.7			—
Pension and other postretirement contributions	(2.9		)	(68.6		)
Gain on sale of certain PDL solar power generation plants	(6.1		)	—
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	274.2			136.1
Accounts receivable and accrued unbilled revenues	(38.9		)	(531.5		)
Inventories	97.4			30.9
Inventories	146.9			121.6
Other current assets	26.4			96.3
Other current assets	104.9			(65.3		)
Accounts payable	(67.5		)	(15.8		)
Accounts payable	(40.8		)	272.1
Other current liabilities	47.0			0.3
Temporary LIFO liquidation credit	33.5			150.9
Other, net	(30.7		)	15.2
Other current liabilities	51.1			54.7
Net cash provided by operating activities	673.6			591.1
Net cash provided by operating activities	524.2			269.7
Investing Activities
Capital expenditures	(~~208~~424.85		)	(~~159~~337.69		)
Capital contributions to equity method investments	(1.7		)	(5.1		)
Investment in transmission affiliate	(3.4		)	(10.2		)
Withdrawal of restricted cash from Rabbi trust for qualifying payments	10.9			—
Cost of removal, net of salvage	(7.0		)	(6.4		)
Other	2.1			1.4
Rabbi trust funding related to change in control	(14.3		)	(65.0		)
Net cash used for investing activities	(197.5		)	(163.3		)
Withdrawal of restricted cash from Rabbi trust for qualifying payments	14.1			—
Proceeds from sale of certain PDL solar power generation plants	47.6			—
Purchase of natural gas distribution business in Minnesota	(11.0		)	—
Other, net	2.8			(10.3		)
Net cash used for investing activities	(395.7		)	(429.8		)
Financing Activities
Short-term debt, net	(184.3		)	(4.1		)
Exercise of stock options	4.1			11.9
Shares purchased for stock-based compensation	(17.5		)	(9.8		)
Purchase of common stock	(23.9		)	(29.3		)
Payment of dividends
Dividends paid on common stock	(108.2		)	(108.2		)
Preferred stock of subsidiary	(0.8		)	(0.8		)
Retirement of long-term debt	—			(100.0		)
Common stock	(54.1		)	(54.1		)
Change in short-term debt	(3.2		)	94.7
Other	(1.6		)	(3.3		)
Other, net	(8.4		)	(7.7		)
Net cash used for financing activities	(~~258~~139.36		)	(72138.16		)
Net change in cash and cash equivalents	68138.43			3422.37
Cash and cash equivalents at beginning of period	18.0			22.3
Cash and cash equivalents at end of period	$	86156.43		$	5645.60
Cash paid for interest	$	1374.9		$	1374.45
Cash received for income taxes	$	(5145.14	)	$	(6259.72	)

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

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INTEGRYS ~~ENERGY GROUP~~HOLDING, INC. ~~AND SUBSIDIARIES~~

CONDENSED NOTES TO FINANCIAL STATEMENTS (Unaudited)

~~March~~June 3130, 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 Holding, Inc. When we refer to the "WEC Merger," we are referring to the acquisition of Integrys Energy Group, Inc. by Wisconsin Energy Corporation, which was completed on June 29, 2015.

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.

Our balance sheet reflects the historical basis of our assets and liabilities as we did not elect pushdown accounting for the WEC Merger. This is consistent with how our financial statements are viewed by our regulators.

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~~As ~~assets~~a ~~and~~result ~~liabilities~~of ~~associated with~~ the ~~potential~~WEC ~~sale~~Merger, ofwe ~~certain~~adopted ~~PDI~~the ~~solar~~financial ~~assets~~statement ~~were~~presentation ~~reclassified~~policies asof ~~held~~our ~~for~~parent ~~sale~~company. onSee ~~our December~~Note 312, ~~2014~~WEC ~~balance~~Merger, ~~sheet~~for tomore beinformation ~~consistent~~on ~~with~~ the ~~current period presentation~~merger. InThe ~~addition,~~previously ~~the~~reported ~~operations~~items ofbelow ~~IES's retail energy business~~ were reclassified asto ~~discontinued~~conform ~~operations~~to ~~on our income statement for~~ the ~~three~~current ~~months~~period ~~ended March 31, 2014~~presentation. ~~See~~Only ~~Note 4,~~material ~~Dispositions,~~reclassifications ~~for~~are ~~more~~quantified ~~information on these sales~~below.

~~Note~~Statements ~~2—Proposed~~of ~~Merger with Wisconsin Energy Corporation~~ Income:

In• ~~June~~Certain ~~2014,~~amortizations ~~we entered into an Agreement and Plan~~ of ~~Merger~~regulatory ~~(Agreement)~~deferrals ~~with~~were ~~Wisconsin~~reclassified ~~Energy~~from ~~Corporation~~operating ~~(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~~maintenance inexpense ~~cash~~to ~~for~~cost ~~each share~~ of ~~our common stock then owned. In addition~~sales, ~~under~~depreciation ~~the Agreement all of our unvested stock-based compensation awards will fully vest upon the close of the transaction~~ and ~~will~~amortization ~~be paid out in cash to award recipients. Upon closing of the transaction~~expense, ~~our shareholders will own approximately 28% of the combined company,~~ and ~~Wisconsin~~miscellaneous ~~Energy shareholders will own approximately 72%~~income.

~~The~~• ~~combined~~Payroll ~~entity~~taxes ~~will~~of be$7.0 ~~named~~million ~~WEC~~and ~~Energy Group, Inc~~$16.4 ~~and~~million ~~will~~for ~~serve~~the ~~natural~~three ~~gas~~ and ~~electric~~six ~~customers~~months ~~across~~ended ~~Wisconsin~~June 30, ~~Illinois~~2014, ~~Michigan~~respectively, were reclassified from taxes other than income taxes to operating and ~~Minnesota~~maintenance expense. The taxes other than income taxes line item was also renamed to property and revenue taxes.

~~This~~• ~~transaction~~Certain ~~was~~expenses ~~approved~~in ~~unanimously~~cost ~~by the Boards~~ of ~~Directors~~sales ofwere ~~both~~reclassified ~~companies.~~to Itoperating ~~was also approved by the shareholders of both companies. In October 2014~~revenues, ~~the~~operating ~~Department of Justice closed its review of the transaction~~ and ~~the~~maintenance ~~Federal Trade Commission granted early termination of the waiting period under the Hart-Scott-Rodino Act. In April 2015~~expense, ~~the~~and ~~transaction~~depreciation ~~was approved by the Federal Communications Commission, the FERC,~~ and ~~the~~amortization ~~MPSC~~expense. OnThe ~~April~~amounts ~~30,~~reclassified ~~2015, the transaction was verbally approved by the PSCW subject~~ to ~~certain~~operating ~~conditions.~~and Amaintenance ~~final~~expense ~~written~~were ~~order is expected from the PSCW in May 2015~~$3.4 ~~The~~million ~~transaction is still subject to approvals from the ICC~~ and ~~the MPUC, as well as other customary closing conditions~~$7.1 Wemillion ~~expect~~for the ~~merger~~three ~~transaction~~and tosix ~~close~~months byended ~~the~~June ~~end~~30, of2014, ~~this summer~~respectively.

~~Note~~• ~~3—Acquisitions~~Equity in earnings of transmission affiliate is now shown separately on the statements of income. Earnings from our other equity method investments were reclassified to miscellaneous income.

~~Purchase~~• ofPreferred ~~Alliant~~stock ~~Energy~~dividends ~~Corporation's~~of ~~Natural~~subsidiary ~~Gas~~were ~~Distribution~~reclassified ~~Business~~to ininterest ~~Southeast Minnesota~~expense.

On• ~~April~~Noncontrolling ~~30,~~interest ~~2015, MERC acquired Alliant Energy Corporation's natural gas distribution business~~ in ~~southeast~~subsidiaries ~~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~~reclassified ~~on the estimated book value as of the closing date and is subject~~ to ~~post-closing~~miscellaneous ~~adjustments~~income. ~~This transaction was not material to us.~~

~~Note~~Balance ~~4—Dispositions~~Sheets:

~~Discontinued~~• ~~Operations~~Current regulatory assets of $47.2 million and $71.7 million were reclassified to accounts receivable and long-term regulatory assets, respectively.

~~See~~• ~~Note 5,~~Equity ~~Cash~~investment ~~and~~in ~~Cash~~transmission ~~Equivalents,~~affiliate ~~for~~is ~~cash~~now ~~flow~~shown ~~information~~separately ~~related~~on the balance sheets. Our other equity method investments of $13.9 million were reclassified to ~~discontinued~~other ~~operations~~long-term assets.


•	Current regulatory liabilities of $44.8 million and $108.9 million were reclassified to energy costs refundable through rate adjustments and long-term regulatory liabilities, respectively.


•	Noncontrolling interest in subsidiaries was reclassified to other long-term liabilities.

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~~Holding~~Statements ~~Company and Other Segment – Potential Sale~~ of ~~Combined~~Cash ~~Locks~~Flows: ~~Energy Center (Combined Locks)~~

We• ~~are~~Preferred ~~currently~~stock ~~pursuing~~dividend ~~the~~payments ~~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~~reclassified asfrom ~~held~~financing ~~for~~activities 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~~operating ~~Locks~~activities.

~~IES~~• ~~Segment~~Various –other ~~Sale~~line ofitems ~~IES~~within ~~Retail~~the ~~Energy~~operating, ~~Business~~investing, and financing activities sections were reclassified; however, there was no impact on the total cash flows of these sections.

InWe ~~November~~also ~~2014,~~reorganized weour ~~sold IES's retail energy~~ business tosegments ~~Exelon~~during ~~Generation Company, LLC (Exelon) for $331.8 million, which has been updated for a working capital adjustment made in~~ the ~~first~~second quarter of 2015 ~~and reflected in the tables below~~. AsAll ~~part~~prior ofperiod ~~the~~amounts ~~stock~~impacted ~~purchase~~by ~~agreement,~~this wechange ~~provided~~were ~~guarantees~~reclassified ~~expiring~~to ~~during~~conform ~~the~~to ~~second quarter of 2015, which supported~~ the ~~IES~~new ~~retail energy business~~presentation. See Note 1220, ~~Guarantees~~Segments of Business, for more information. Weon ~~are~~our ~~providing~~business ~~certain administrative and operational services to Exelon during a transition period of up to 15 months after the sale date~~segments.

The ~~sale~~assets ofassociated ~~the~~with ~~retail~~PDL's ~~energy~~Combined ~~business~~Locks ~~was~~Energy ~~the~~Center ~~result~~were ofreclassified aout ~~previously~~of ~~announced~~held ~~shift~~for insale ~~our strategy to focus~~ on our ~~regulated~~December ~~businesses. Therefore~~31, ~~its~~2014 ~~results~~balance ~~of operations were classified as discontinued operations beginning in the fourth quarter of 2014~~sheet.

~~The~~Note ~~following~~2—WEC ~~table~~Merger ~~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

On June 29, 2015, the WEC Merger was completed and we became a wholly owned subsidiary of WEC. Our shareholders received 1.128 shares of Wisconsin Energy common stock and $18.58 in cash for each share of our common stock. In addition, all of our unvested stock-based compensation awards became fully vested upon the close of the transaction. All outstanding awards were either paid out in cash to award recipients or the value of the awards was deferred into a deferred compensation plan. The total purchase price was approximately $5.6 billion.

~~Included~~In inconnection with the ~~sale~~merger, ~~were~~we ~~commodity~~recognized ~~contracts~~after-tax ~~that~~merger-related ~~did~~costs ~~not~~of ~~meet~~$38.4 ~~the~~million ~~GAAP~~and ~~definition~~$39.0 ofmillion ~~derivative~~during ~~instruments~~the three and six months ended June 30, ~~therefore~~2015, ~~were~~respectively, ~~not~~and ~~reflected~~$4.1 onmillion during the ~~balance~~three ~~sheets.~~and Insix ~~accordance~~months ~~with~~ended ~~GAAP~~June 30, ~~expected~~2014. ~~gains~~Included orin ~~losses~~the 2015 costs was $26.6 million of after-tax expense related to ~~nonderivative~~the ~~commodity~~accelerated ~~contracts~~vesting ~~are~~of ~~not~~our ~~recognized~~outstanding ~~until~~stock-based ~~the~~compensation ~~contracts~~awards ~~are~~and ~~settled~~change-in-control payments. Our balance sheet as of June 30, 2015 included receivables from and payables to WEC of $27.3 million and $1.8 million, respectively. These balances primarily relate to the cash payments made for our outstanding stock-based compensation awards.

The ~~following~~merger ~~table~~was ~~shows~~subject to the ~~components~~approvals of ~~discontinued~~various ~~operations~~government ~~related~~agencies, toincluding the ~~sale~~FERC, ofFederal Communications Commission, PSCW, ICC, MPSC, and MPUC. Approvals were obtained from all agencies subject to several conditions. The PSCW order requires that any future electric generation projects affecting Wisconsin ratepayers submitted by WEC or its subsidiaries will first consider the ~~IES~~extent ~~retail~~to which existing intercompany resources can meet energy ~~business~~and ~~recorded~~capacity onneeds. Additionally, the ~~income~~ICC ~~statements~~order included a base rate freeze for PGL and NSG effective for two years after the ~~three~~close ~~months~~of ~~ended~~the ~~March~~merger. ~~31:~~We do not believe that the conditions set forth in the various regulatory orders approving the merger will have a material impact on our operations or financial results.

(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

On July 24, 2015, the Citizens Utility Board, the City of Chicago, and the Illinois State Attorney General's office asked the ICC to rehear the merger order. The parties seek additional conditions previously requested during the approval process. The ICC has until August 13, 2015 to accept or deny the request. We believe the ICC's decision to approve the merger was correct and supported by sound principles and an extensive body of evidence.

Note 3—Dispositions

Discontinued Operations

Corporate and Other 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 includes a working capital adjustment recorded during the first quarter of 2015. As part of the stock purchase agreement, we provided guarantees supporting the IES retail energy business. During the second quarter of 2015, the majority of these guarantees expired. 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.

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The following table shows the components of discontinued operations related to the sale of IES's retail energy business recorded on the income statements. No activity was recorded for IES's retail energy business during the three months ended June 30, 2015.



	Three Months Ended			Six Months Ended June 30
(Millions)	June 30, 2014			2015			2014
Revenues	$	596.3		$	—		$	1,885.9
Cost of sales	(556.7		)	—			(1,791.5		)
Operating and maintenance expense	(27.7		)	(1.2		)	(60.5		)
Depreciation and amortization expense	(0.8		)	—			(1.5		)
Property and revenue taxes	(0.7		)	(0.2		)	(1.1		)
Goodwill impairment loss *	(6.7		)	—			(6.7		)
Transaction costs	(0.8		)	—			(0.8		)
Miscellaneous income	0.3			0.1			0.5
Interest expense	(0.2		)	—			(0.4		)
Income (loss) before taxes	3.0			(1.3		)	23.9
(Provision) benefit for income taxes	(3.7		)	0.5			(11.6		)
Discontinued operations, net of tax	$	(0.7	)	$	(0.8	)	$	12.3


*	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.

Dispositions

~~Holding~~Corporate ~~Company~~ and Other Segment – ~~Potential~~ Sale of Certain ~~PDI~~PDL Solar ~~Assets~~Power Generation Plants

In ~~the~~June ~~first~~2015, ~~quarter~~we ofsold ~~2015,~~48 ~~management~~solar ~~began~~power ~~implementing~~generation aplants ~~plan~~owned by PDL to ~~sell~~TerraForm ~~certain~~Power, ~~solar~~Inc. ~~assets~~(TerraForm) ~~owned~~for by$47.8 ~~PDI~~million. The ~~potential~~purchase ~~sale~~price ofis ~~these~~subject ~~assets~~to ~~meets~~adjustments ~~the~~for ~~criteria~~working incapital. ~~the~~These ~~accounting~~solar ~~guidance~~plants towere ~~qualify~~located asthroughout ~~held~~Arizona, ~~for~~California, ~~sale~~Connecticut, ~~but~~Massachusetts, ~~does~~New ~~not~~Jersey, ~~meet~~and Pennsylvania. During the ~~requirements~~second toquarter ~~qualify~~of as2015, ~~discontinued~~we ~~operations~~recorded a pre-tax gain on the sale of $5.2 million, which included transaction costs of $0.9 million. The ~~potential~~results ~~sale~~of operations of these solar assets ~~does~~through ~~not~~the ~~represent~~sale adate ~~shift~~remain in ~~our~~continuing ~~corporate~~operations. ~~strategy~~In ~~and~~connection ~~will~~with ~~not~~the ~~have~~sale, awe ~~major~~entered ~~effect~~into onan ~~our~~asset ~~operations~~management ~~and~~agreement ~~financial~~with ~~results.~~TerraForm ~~Therefore,~~related to the ~~results~~majority of ~~operations of~~ the ~~PDI~~remaining solar assets owned by PDL. Under this agreement, TerraForm will ~~remain~~perform inthe ~~continuing~~day-to-day ~~operations~~management of these remaining solar assets.

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

(Millions)	March 31, 2015		December 31, 2014
	As of the Closing Date		Held for Sale at
Property, plant, and equipment, net of accumulated depreciation of $22.1 and $21.1, respectively	$	31.1	$	32.1
(Millions)	in June 2015		December 31, 2014
Equity method investments	18.5		18.2
Cash and cash equivalents	$	0.3	$	—
Other long-term assets	1.2		1.2
Accounts receivable	0.7		—
Total assets	$	50.8	$	51.5
Property, plant, and equipment, net of accumulated depreciation of $22.1 and $21.1, respectively	31.1		32.1
Other long-term assets	17.9		19.4
Total assets	$	50.0	$	51.5
Current liabilities	$	0.3	$	0.3
Deferred investment tax credits	4.76		5.0
Asset retirement obligations	1.1		1.1
Other long-term liabilities	76.58		7.4
Total liabilities	$	1312.68	$	13.8

~~Electric~~Other ~~Utility~~States Segment – Sale of UPPCO

In August 2014, we sold all of the common 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 54—Cash and Cash Equivalents

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

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.

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Continuing Operations

Significant noncash transactions related to continuing operations were:



	Six Months Ended June 30
(Millions)	2015		2014
Construction costs funded through accounts payable	$	139.5	$	123.3
ITF fueling station sale financed with note receivable	2.8		—
Purchase of a natural gas distribution business in Minnesota financed with note payable	2.6		—
Equity issued for employee stock ownership plan	—		1.7

At June 30, 2015, restricted cash of $30.2 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 WEC Merger. See Note 2, WEC Merger, for more information about the 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 were:

	Three Months Ended March 31
	Six Months Ended June 30
(Millions)	2015		2014
Operating Activities
Net unrealized gains on energy contracts	$	—	$	(19.6	)
Deferred income taxes and investment tax credits, net	$	—	$	15.5
Deferred income taxes and investment tax credits	—		11.5
Depreciation and amortization expense	—		1.6
Other	1.3		6(3.71		)

Note 65—Investment in ATC

~~Our~~We ~~electric~~own ~~transmission investment segment consists of WPS Investments LLC’s ownership interest in ATC, which was~~ approximately 34% atof ~~March 31~~ATC, ~~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
	Three Months Ended June 30				Six Months Ended June 30
(Millions)	2015		2014		2015		2014
Balance at the beginning of period	$	~~536~~541.78	$	~~508~~517.46	$	536.7	$	508.4
Add: Earnings from equity method investment	1722.04		2223.50		39.4		45.5
Add: Capital contributions	1.7		5.1		3.4		10.2
Less: Dividends received	13.69		18.4		27.5		36.8
Balance at the end of period	$	~~541~~552.80	$	~~517~~527.63	$	552.0	$	527.3

~~ATC~~Summarized isfinancial ~~currently~~data ~~named~~for ~~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%.~~included ~~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~~following 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.tables:

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



	Three Months Ended June 30				Six Months Ended June 30
(Millions)	2015		2014		2015		2014
Income statement data
Revenues	$	165.1	$	160.0	$	317.5	$	323.3
Operating expenses	80.3		74.4		160.3		153.0
Other expense	24.2		21.9		48.6		43.5
Net income	$	60.6	$	63.7	$	108.6	$	126.8

	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

(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

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Note 7—Inventories



(Millions)	June 30, 2015		December 31, 2014
Balance sheet data
Current assets	$	78.1	$	66.4
Noncurrent assets	3,835.2		3,728.7
Total assets	$	3,913.3	$	3,795.1

Current liabilities	$	255.7	$	313.1
Long-term debt	1,800.0		1,701.0
Other noncurrent liabilities	197.7		163.8
Shareholders’ equity	1,659.9		1,617.2
Total liabilities and shareholders’ equity	$	3,913.3	$	3,795.1

~~PGL~~Note 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.6—Inventories

~~Note~~PGL ~~8—Goodwill~~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 ~~Other~~the ~~Intangible~~LIFO ~~Assets~~cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. The amounts were as follows at June 30, 2015:

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



		June 30, 2015
(Millions)	Balance Sheet Presentation	PGL		NSG
Temporary LIFO liquidation debit	Other current assets	$	21.0	$	—
Temporary LIFO liquidation credit	Other current liabilities	—		5.2

Due to seasonality requirements, PGL and NSG expect these interim reductions in LIFO layers to be replenished by year end.

Note 7—Goodwill and Other Intangible Assets

We had no changes to the carrying amount of goodwill during the six months ended June 30, 2015, and 2014.

In the second quarter of 2015, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of April 1,

2015. 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.

	March 31, 2015							December 31, 2014
	June 30, 2015							December 31, 2014
(Millions)	Gross ~~CarryingAmount~~Carrying Amount		~~AccumulatedAmortization~~Accumulated Amortization			Net ~~CarryingAmount~~Carrying Amount		Gross ~~CarryingAmount~~Carrying Amount		AccumulatedAmortization			Net CarryingAmount
Amortized intangible assets
Amortized intangible assets (1)	$	27.1	$	(11.6	)	$	15.5	$	34.9	$	(11.9	)	$	23.0
Contractual service agreements (1)	$	15.6	$	(5.1	)	$	10.5	$	15.6	$	(4.3	)	$	11.3
Unamortized intangible assets (2)	10.7		—			10.7		10.2		—			10.2
Customer-owned equipment modifications (2)	4.0		(1.2		)	2.8		4.0		(1.2		)	2.8
Total intangible assets	$	37.8	$	(11.6	)	$	26.2	$	45.1	$	(11.9	)	$	33.2
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~~Primarily relates to 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~~our amortized intangible assets at ~~March~~June 3130, 2015, was approximately ~~four~~five years.

(2) ~~Relates~~Consists toprimarily ~~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~~trade ~~nine years~~names.

~~(3)~~Note ~~Represents~~8—Short-Term ~~the~~Debt ~~fair~~and ~~value~~Lines 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.Credit

~~(4)~~Our ~~Relates~~outstanding ~~to easements supporting a pipeline at PDI. The easements are amortized on a straight~~short-~~line~~term ~~basis,~~borrowings ~~with~~were aas ~~remaining amortization period at March 31, 2015, of approximately nine years.~~follows:

(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.



(Millions, except percentages)	June 30, 2015				December 31, 2014
Commercial paper	$	314.4		*	$	317.6
Average interest rate on commercial paper outstanding	0.37		%		0.36		%

~~(6)~~* ~~Represents~~Maturity ~~customer~~dates ~~relationship~~ranged ~~assets~~from ~~associated~~July ~~with ITF's compressed natural gas fueling operations. The remaining weighted-average amortization period for customer-related intangible assets at March 31~~1, 2015, ~~was~~through ~~approximately~~July 1214, ~~years~~2015.

~~(7)~~Our ~~Trillium~~average ~~USA~~amount ~~(Trillium)~~of ~~and~~commercial ~~Pinnacle~~paper ~~CNG~~borrowings ~~Systems~~based ~~(Pinnacle)~~on ~~are~~daily ~~wholly-owned~~outstanding ~~subsidiaries~~balances ofduring ~~ITF~~the six months ended June 30, 2015, and 2014, was $165.3 million and $215.6 million, respectively.

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		—

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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~~June 3130, 2015		December 31, 2014
Revolving credit facility (Integrys Energy Group)	06/13/2017	$	285.0	$	285.0
Revolving credit facility (Integrys Holding)	06/13/2017	$	285.0	$	285.0
Revolving credit facility (Integrys Energy Group) *	05/08/2019	465.0		465.0
Revolving credit facility (Integrys Holding)	05/08/2019	265.0		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 (WPS)	05/08/2019	135.0		135.0
Revolving credit facility (PGL)	06/13/2017	250.0		250.0
Total short-term credit capacity		$	1,~~250~~050.0	$	1,250.0
Less:
Letters of credit issued inside credit facilities		$	0.7	$	3.4
Commercial paper outstanding		~~133~~314.34		317.6
Available capacity under existing agreements		$	~~1,116~~734.09	$	929.0

*Note ~~This~~9—Long-Term ~~credit~~Debt ~~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.~~



(Millions)	June 30, 2015			December 31, 2014
WPS	$	1,175.1		$	1,175.1
PGL ⁽¹⁾	850.0			850.0
NSG	82.0			82.0
Integrys Holding	974.8			974.8
Total	3,081.9			3,081.9
Unamortized discount on debt	(0.6		)	(0.6		)
Total debt	3,081.3			3,081.3
Less current portion ⁽²⁾	180.0			125.0
Total long-term debt	$	2,901.3		$	2,956.3


⁽¹⁾	On August 1, 2015, the interest rate on PGL's $50.0 million of 2.625% Series WW Bonds was reset. The new interest rate is 1.875%. The new mandatory interest reset date is August 1, 2020. The final maturity of these bonds is February 1, 2033.


⁽²⁾	In July 2015, we offered to buy back $55.0 million of 8.00% Senior Notes due June 1, 2016. The $55.0 million balance of these notes was included in the current portion of long-term debt on our balance sheet at June 30, 2015.

Note 10—Income Taxes

We calculate our interim period provision for, or benefit from 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
	Three Months Ended June 30				Six Months Ended June 30
	2015		2014		2015		2014
Effective tax rate	3746.6	%	36.90	%	36.9	%	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. NoOther ~~other~~significant items that had aan ~~significant~~ impact on our effective tax rates ~~during~~are ~~the~~noted ~~three months ended March 31, 2015, and 2014~~below.

~~During~~Our effective tax rate for the three months ended ~~March~~June 3130, 2015, ~~there~~ was ~~not~~higher than the 35% federal statutory rate primarily due to the accelerated recognition of unamortized investment tax credits driven by the sale of solar assets at PDL. This increased our benefit from income taxes due to a pre-tax loss for the quarter. No other items had a significant ~~change~~impact inon our ~~liability~~effective tax rates for ~~unrecognized~~the ~~tax~~three ~~benefits~~and six months ended June 30, 2015 and 2014.

During the three and six months ended June 30, 2015, there was not a significant change in our liability for unrecognized tax benefits.

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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~~June 3130, 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
Wisconsin Operations
Electric utility
Natural gas supply and transportation	2024	$	218.9	$	20.7	$	43.8	$	42.9	$	42.4	$	27.1	$	42.0
Purchased power	2029	806.1		92.1		42.7		53.3		55.9		57.1		505.0
Electric
Coal supply and transportation	2019	155.8		44.3		34.8		33.5		32.1		11.1		—
Purchased power	2029	816.3		61.4		78.9		54.1		56.8		58.1		507.0
Total		$	1,626.5	$	265.2	$	249.2	$	221.2	$	167.6	$	120.5	$	602.8
Coal supply and transportation	2019	154.0		35.6		39.0		34.9		33.4		11.1		—
Illinois Operations
Natural gas supply and transportation	2022	$	191.3	$	39.5	$	76.7	$	49.2	$	14.1	$	4.0	$	7.8
Other States Operations
Natural gas supply and transportation	2028	$	215.5	$	26.2	$	52.9	$	43.4	$	23.7	$	21.2	$	48.1
Total		$	1,596.0	$	183.4	$	291.3	$	224.5	$	170.4	$	121.5	$	604.9

(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.

As mentioned above, the Consent Decree contains a requirement to refuel, repower, and/or retire certain Weston and Pulliam units. ~~WPS~~Effective ~~announced~~June 1, ~~that~~2015, ~~certain~~WPS retired Weston Unit 1 and Pulliam ~~units~~Units ~~mentioned~~5 inand ~~the~~6 ~~Consent~~and ~~Decree~~recorded ~~will~~a beregulatory ~~retired~~asset ~~early,~~of in$11.5 ~~June~~million ~~2015~~for the undepreciated book value. 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~~these 5units ~~and~~starting 6June ~~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~~June 3130, 2015. It is unknown whether the Sierra Club will take further action in the future.

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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),

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•	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 Unit 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 Unit 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.

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~~and ~~WDNR~~included ~~also~~an ~~issued~~issue arelated ~~Notice~~to ofreporting ~~Inquiry~~nitrogen ~~(NOI)~~oxide emissions from the Weston 4 auxiliary boiler. In June 2015, the WDNR issued an NOV to WPS alleging that WPS failed to comply with mercury 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~~imposes stringent limitations on emissions of mercury and other hazardous air pollutants from coal and oil-fired electric generating units beginning in April 2015. ~~The~~In ~~State~~addition, of Wisconsin ~~recently~~has ~~revised~~mercury rules with the same compliance ~~dates~~deadline inthat ~~the~~require ~~state~~a 90% reduction of mercury. ~~rule~~In toJune be2015, ~~consistent~~the ~~with~~United States Supreme Court (Supreme Court) ruled on a challenge to the MATS rule. ~~Projects~~and ~~approved~~remanded ~~and~~the ~~initiated~~case back to ~~address~~the United States Court of Appeals for the ~~State~~District of ~~Wisconsin~~Columbia ~~mercury~~Circuit ~~rule~~(D.C. ~~are~~Circuit ~~expected~~Court toof ~~ensure~~Appeals), ~~compliance~~ruling ~~with~~that the ~~mercury~~EPA ~~limits~~failed into appropriately consider the cost of the regulation. The MATS rule remains in effect pending action by the D.C ~~WPS~~Circuit ~~placed~~Court inof ~~service~~Appeals, ~~capital~~which ~~projects~~has ~~for~~the option to vacate the rule while the EPA completes its ~~wholly~~cost ~~owned~~evaluation. ~~plants~~If inthe ~~2015~~rule is stayed or revoked, the Wisconsin Mercury Rule is likely to ~~achieve~~be the ~~required~~governing ~~reductions~~standard for ~~MATS~~the ~~compliance~~WPS inunits. ~~April~~At ~~2015.~~this ~~These~~time, ~~capital~~it ~~costs~~is ~~are~~too ~~expected~~early to bedetermine ~~recovered~~what ineffect, ~~future~~if ~~rates~~any, this ruling will have on our compliance plans.

~~Sulfur~~WPS ~~Dioxide~~initiated ~~and~~certain ~~Nitrogen~~capital ~~Oxide:~~projects for its wholly owned plants to achieve the required reductions for MATS or the Wisconsin Mercury Rule. These capital costs are expected to be recovered in future rates.

InSulfur 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. Dioxide:

~~Under~~The ~~CAIR,~~EPA ~~units~~issued ~~affected~~a by1-Hour ~~the~~Sulfur ~~Best~~Dioxide ~~Available Retrofit Technology~~ (~~BART~~SO2) ~~rule~~National ~~were~~Ambient ~~considered~~Air inQuality ~~compliance~~Standard ~~with~~(NAAQS) ~~BART~~that ~~for~~became ~~sulfur~~effective ~~dioxide~~in ~~and~~August ~~nitrogen~~2010. In ~~oxide~~May ~~emissions~~2014, ifthe ~~they~~EPA ~~were~~issued inthe ~~compliance~~proposed ~~with~~Data ~~CAIR.~~Requirements ~~This~~Rule ~~determination~~that ~~was~~would ~~updated~~establish ~~when~~procedures ~~CSAPR~~and ~~was~~timelines ~~issued~~for ~~(CSAPR~~implementation ~~satisfied~~of ~~BART)~~the standard. ~~Although~~The ~~particulate~~proposed ~~emissions~~rule ~~also~~describes ~~contribute to visibility impairment,~~ the ~~WDNR~~EPA's ~~modeling~~plans for ~~Pulliam~~allowing ~~Unit 8,~~ the ~~only~~states ~~unit covered by BART, has shown the impairment~~ to beuse soeither ~~insignificant~~monitoring ~~that additional capital expenditures~~ or ~~controls~~modeling ~~may~~to ~~not~~make ~~be warranted~~designations.

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~~Clean~~As ~~Water~~proposed, ~~Act~~the ~~Rule~~rule affords state agencies latitude in rule implementation. States would have the option of modeling or monitoring to show attainment (subject to EPA approval for this selection). If the state chooses modeling and the sources in an area do not make reductions by 2017, and as a consequence the area is classified as nonattainment, then they would have to make emission reductions by 2023. Alternatively, if a state opted out of modeling and instead chose monitoring, and subsequently monitored nonattainment, then it would face a 2026 compliance date. A nonattainment designation could have negative impacts for a localized geographic area, including permitting constraints for area sources and for other new or existing sources in the area.

In ~~August~~March ~~2014~~2015, ~~the EPA issued~~ a ~~final~~Federal ~~Clean~~Court ~~Water~~in ~~Act~~the ~~rule,~~Northern ~~which~~District ~~established requirements under Section 316(b) to regulate water intake structures at industrial facilities that use large volumes~~ of ~~surface~~California ~~water~~entered ~~as cooling water. The new rule became effective in October 2014 and has been challenged by~~ a ~~number~~consent ofdecree ~~parties.~~relating ~~The~~to ~~cases have been consolidated and will be heard in~~ the ~~United~~implementation ~~States Court~~ of ~~Appeals for~~ the ~~Second~~revised ~~Circuit.~~1-Hour ToSO2 ~~the~~standard ~~extent~~ that ~~the~~Sierra ~~rule~~Club isand ~~upheld,~~EPA ~~WPS~~had ~~will~~agreed ~~comply~~upon ~~with~~in ~~the~~May ~~rule on the timeline required under the regulation~~2014. ~~WPS~~This ~~will~~consent ~~evaluate~~decree ~~the~~has ~~impact~~1-Hour ofSO2 ~~compliance~~implementation bydates ~~conducting~~that ~~the~~are ~~studies~~sooner ~~required~~than by the ~~rule~~proposed atData ~~its~~Requirements ~~facilities~~Rule. ~~WPS~~The ~~anticipates~~EPA ~~that~~has ~~the timing for compliance will be incorporated into future wastewater discharge permit renewals. We do~~ not ~~expect~~yet toindicated ~~incur~~how, ~~significant~~in ~~costs~~light toof ~~comply with the Clean Water Act rule at WPS's Weston plant as~~ this ~~plant~~consent ~~already~~decree, ~~has~~the ~~two~~Data ~~units~~Requirements ~~equipped~~Rule ~~with~~will ~~cooling~~be ~~towers that assist with meeting these new requirements~~finalized. ~~We expect to recover any future compliance costs in future rates.~~

We believe our fleet, with the exception of WPS’s Pulliam plant, is well positioned to meet this regulation once it is finalized. The Pulliam plant is located in Brown County, which has been preliminarily determined to be in nonattainment with the standard based on monitoring data from 2012 through 2014. The WDNR has indicated that additional modeling and monitoring data will be required prior to final attainment designations being made in 2017 and 2020. We are currently working closely with the state of Wisconsin as they determine the attainment status of the areas and the effect, if any, on the Pulliam plant.

Land Quality

Coal Combustion Residuals (CCR) Rule:

In April 2015, the EPA published the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities final rule in the Federal Register. The final rule regulates the disposal of coal combustion byproducts, primarily fly ash and bottom ash, as a nonhazardous waste. The rules are intended to address risks related to groundwater impacts, catastrophic failures, and air emissions. There will be additional requirements for recordkeeping, groundwater monitoring, and structural integrity, including ongoing inspections and hazard assessments. There will also be more locational restrictions to protect wetlands and seismic impact zones. The rule will affect how WPS operates the Weston plant's bottom ash basins and an offsite landfill. However, we have landfill capacity that meets the rule requirements, if needed, for our coal combustion product sources. We do not expect the compliance costs to be significant because we currently have a program of beneficial utilization for most of our coal combustion byproducts and expect to recover these costs in future rates.

Water Quality

Clean Water Act Rule:

In August 2014, the EPA issued a final Clean Water Act rule under Section 316(b), which requires that the location, design, construction and capacity of cooling water intake structures reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts. The rule became effective in October 2014 and applies to the Weston and Pulliam plants at WPS.

Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. BTA determinations must also be made to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. The rule requires state permitting agencies, including the WDNR, to make BTA determinations for IM and EM over the next several years, subject to EPA oversight, when facility permits are reissued. Based on our assessment, we believe that existing technologies at Weston Units 3 and 4 satisfy the IM and EM requirements by virtue of their existing cooling towers. In addition, it is expected that the WDNR will determine that no modifications will be required at Weston Unit 2 due to low projected utilization. However, Pulliam Units 7 and 8 do not have the technologies to satisfy the IM and EM BTA requirements.

During 2015-18, we plan to complete studies to address the EM BTA requirements and evaluate the available IM options for Pulliam Units 7 and 8. We also expect limited studies to support WDNR BTA determinations to be conducted at the Weston facility. We cannot yet determine what, if any, intake structure or operational modifications will be required to meet the EM BTA requirements for Pulliam Units 7 and 8. We expect to recover any future compliance costs in future rates.

Manufactured Gas Plant Remediation

~~Our~~We ~~natural~~have ~~gas~~identified ~~utilities,~~several ~~their~~sites ~~predecessors,~~at ~~and~~which ~~certain~~our ~~former~~utilities, ~~affiliates~~or ~~operated~~a ~~facilities~~predecessor incompany, ~~the~~owned ~~past~~or atoperated ~~multiple~~a ~~sites for the purpose of manufacturing and storing~~ manufactured gas plant. InThese ~~connection~~sites ~~with~~are ~~these~~at ~~activities,~~various ~~waste~~stages ~~materials~~of ~~were~~investigation, ~~produced~~monitoring ~~that may have resulted in soil~~ and ~~groundwater contamination at these sites~~remediation. ~~Under~~We ~~certain~~have ~~laws~~also ~~and~~identified ~~regulations~~other ~~relating~~sites tothat ~~the~~may ~~protection~~have ofbeen ~~the~~impacted ~~environment,~~by ~~our~~historical ~~natural~~manufactured gas ~~utilities~~plant ~~are required to undertake remedial action with respect to some of these materials~~activities. ~~The~~Our natural gas utilities are ~~coordinating~~responsible for the ~~investigation~~environmental ~~and~~remediation ~~cleanup~~ of ~~the~~these 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~~some ~~and approval~~ of ~~documents~~which ~~common~~are toin ~~all of~~ the ~~sites,~~EPA ~~and~~Superfund ~~use~~Alternative ofSites ~~a consistent approach in selecting remedies~~Program.

~~Our~~The ~~natural~~future ~~gas~~costs ~~utilities~~for ~~are~~detailed ~~responsible~~site ~~for~~investigation ~~the~~and ~~environmental~~future remediation ofare 53dependent ~~sites,~~upon ofseveral ~~which~~variables 20including, ~~have~~among ~~been~~other ~~transferred to the EPA Superfund Alternative Sites Program. Under the EPA's program~~things, the ~~remedy~~extent ~~decisions at these sites will be made using risk-based criteria typically used at Superfund sites. Our balance sheet includes liabilities~~ of ~~$573.0~~remediation, ~~million~~changes ~~that~~in ~~we have estimated and accrued for as of March 31~~technology, ~~2015, for future undiscounted investigation~~ and ~~cleanup~~changes ~~costs~~in ~~for all sites~~regulation. WeHistorically, ~~may adjust~~our ~~these~~regulators ~~estimates~~have inallowed ~~the~~us ~~future due~~ to ~~remedial~~recover ~~technology,~~incurred ~~regulatory requirements~~costs, ~~remedy~~net ~~determinations, and any claims~~ of ~~natural~~insurance ~~resource damages. As of March 31~~recoveries, ~~2015,~~associated ~~cash~~with ~~expenditures~~the ~~for environmental~~ remediation ~~not~~of ~~yet~~manufactured ~~recovered~~gas inplant ~~rates were $43~~sites.1 ~~million.~~Accordingly, ~~Our~~we ~~balance~~have ~~sheet~~established ~~also includes a~~ regulatory ~~asset~~assets offor ~~$616.1~~costs ~~million~~associated atwith ~~March 31,~~these ~~2015, which is net of insurance recoveries, related to the expected recovery through rates of both cash expenditures and estimated future expenditures~~sites.

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.

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~~(5)~~We ~~Consists~~established ~~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~~following ~~agreement~~reserves 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~~regulatory ~~agreement~~assets ~~by ITF; and (d) $7.0 million~~ related to ~~other~~manufactured ~~indemnifications~~gas ~~primarily~~plant ~~for workers compensation coverage. The amounts discussed in items (a), (c), and (d) above are not reflected on our balance sheets.~~sites:



(Millions)	June 30, 2015		December 31, 2014
Regulatory assets	$	625.4	$	634.3
Reserves for future remediation	576.0		579.7

Note 12—Guarantees

The following table shows our outstanding guarantees:



	Total Amounts Committed at		Expiration
(Millions)	June 30, 2015		Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees supporting commodity transactions of subsidiaries ⁽¹⁾	$	156.4	$	83.4	$	—	$	73.0
Standby letters of credit⁽²⁾	1.2		1.1		0.1		—
Surety bonds⁽³⁾	32.2		32.2		—		—
Guarantees temporarily retained related to the sale of IES's retail energy business ⁽⁴⁾	0.6		0.6		—		—
Other guarantees⁽⁵⁾	62.7		—		0.1		62.6
Total guarantees	$	253.1	$	117.3	$	0.2	$	135.6


⁽¹⁾	Consists of (a) $5.0 million and $6.0 million to support the business operations of WBS and PDL, respectively, and (b) $1.1 million, $109.3 million, and $35.0 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. These amounts consist of standby letters of credit issued to support ITF, MERC, MGU, NSG, PDL, 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 by ITF, workers compensation self-insurance programs, and obtaining various licenses, permits, and rights-of-way. These amounts 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). Exelon is contractually bound to reimburse us for any payments made under the outstanding guarantees. At June 30, 2015, these guarantees consisted of standby letters of credit. The liability related to these guarantees was insignificant. Our exposure under these guarantees related to open transactions at June 30, 2015, was $0.6 million.

⁽⁵⁾

Consists of (a) $34.6 million to support PDL'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; (c) $11.2 million related to the performance of an operating and maintenance agreement by ITF; and (d) $6.9 million related to other indemnifications, primarily for workers compensation coverage. The amounts discussed in items (a), (c), and (d) are not reflected on our balance sheets. An insignificant liability was recorded for item (b) related to the possible imposition of additional miscellaneous gross receipts tax in the event of a change in law or interpretation of the law.

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~~						Other Postretirement Benefits
	Three Months Ended March 31						Three Months Ended March 31
	Three Months Ended June 30						Six Months Ended June 30						Three Months Ended June 30						Six Months Ended June 30
(Millions)	2015			2014			2015			2014			2015			2014			2015			2014
Service cost	$	7.61		$	65.69		$	514.87		$	512.95		$	5.4		$	4.8		$	11.2		$	10.7
Interest cost	1716.07			19.73			533.37			739.10			5.1			5.2			10.4			12.3
Expected return on plan assets	(2625.98		)	(28.95		)	(752.97		)	(857.84		)	(7.9		)	(7.9		)	(15.8		)	(16.7		)
Loss on plan settlement	0.57			—0.9			—1.2			—0.9			—			—			—			—
Amortization of prior service cost (credit)	~~0.1~~—			0.21			(20.61		)	(10.3		)	(2.5		)	(2.8		)	(5.1		)	(4.1		)
Amortization of net actuarial loss	1012.51			8.46			122.16			017.70			0.8			0.8			1.9			1.5
Net periodic benefit cost	$	810.8		$	6.03		$	119.76		$	312.63		$	0.9		$	0.1		$	2.6		$	3.7

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

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

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~~Stock~~Rabbi ~~Options~~Trust Funding Requirement

The ~~weighted-average~~Agreement ~~fair~~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 ~~per~~of ~~stock~~each ~~option~~participant's ~~granted~~total ~~during~~benefit under the ~~three~~deferred ~~months~~compensation ~~ended~~program ~~March 31~~and certain nonqualified pension plans. In 2015, a portion of the amounts contributed to the rabbi trust in 2014, ~~was~~and $62015 were used to fund participant's benefits under the deferred compensation program and certain nonqualified pension plans.~~70.~~ NoSee ~~stock~~Note 2, ~~options~~WEC ~~were~~Merger, ~~granted~~for ~~during~~more ~~2015~~information on the merger.

ANote ~~summary~~14—Stock-Based ~~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:~~Compensation

	Stock Options		Weighted-AverageExercise Price PerShare		Weighted-AverageRemaining Contractual Life(in Years)	AggregateIntrinsic 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

Per the WEC Merger Agreement, immediately prior to completion of the merger, all of our outstanding stock-based compensation awards became fully vested and were canceled in exchange for the right to be paid out in cash to award recipients. The additional expense associated with the accelerated vesting of these awards totaled $22.7 million and was included with merger costs on the statement of income. See Note 2, WEC Merger, for more information regarding the merger.

The ~~aggregate~~ intrinsic ~~value~~values ~~for~~of ~~outstanding and exercisable options in~~ the ~~above~~awards ~~table~~canceled ~~represents~~due ~~the~~to ~~total pre-tax intrinsic value that would have been received by~~ the ~~option~~merger ~~holders~~were ~~had~~$26.0 ~~they~~million ~~all~~and ~~exercised their options on March 31, 2015~~$34.8 ~~This~~million isfor ~~calculated~~performance ~~as the difference between our closing~~ stock ~~price~~rights ~~on March 31, 2015,~~ and ~~the~~restricted ~~option~~stock ~~exercise price~~units, ~~multiplied by the number of in-the-money stock options~~respectively. The intrinsic value of stock options ~~exercised~~canceled ~~during~~was ~~the~~not ~~three~~significant. ~~months~~The ~~ended~~actual ~~March 31,~~tax ~~2015,~~benefit ~~and~~realized ~~2014~~for ~~was~~the ~~not~~tax ~~significant.~~deductions ~~Cash received~~ from ~~option~~the ~~exercises~~payment ~~during~~of the ~~three~~canceled ~~months~~awards ~~ended March 31, 2015,~~ was $210.70 million, and ~~was~~$12.3 ~~not~~million ~~significant~~ for ~~the~~performance ~~three~~stock ~~months~~rights ~~ended~~and ~~March~~restricted 31stock units, ~~2014~~respectively.

~~Due~~The tofollowing ~~the~~table ~~accelerated~~reflects ~~vesting~~the ~~of all unvested~~ stock-based ~~options~~compensation ~~held~~expense byand ~~active~~the ~~employees~~related indeferred ~~October~~income ~~2014,~~tax ~~all~~benefit ~~compensation~~recognized ~~expense~~in ~~related~~income tofor ~~outstanding~~the ~~stock~~three ~~options~~and ~~has~~six ~~been~~months ~~recognized.~~ended June 30:

Performance Stock Rights



	Three Months Ended June 30				Six Months Ended June 30
(Millions)	2015		2014		2015		2014
Stock options	$	—	$	0.5	$	—	$	0.8
Performance stock rights	2.7		9.2		3.3		9.7
Restricted share units	4.8		2.6		8.2		5.1
Nonemployee director deferred stock units	0.7		0.2		0.9		0.4
Total stock-based compensation expense	$	8.2	$	12.5	$	12.4	$	16.0
Deferred income tax benefit	$	3.3	$	5.0	$	5.0	$	6.4

~~The~~A ~~fair~~summary ~~values~~ of ~~performance~~the ~~stock~~activity ~~rights~~for ~~are~~our ~~estimated using a Monte Carlo valuation model. The risk~~stock-~~free interest rate is~~ based oncompensation ~~the~~awards ~~United~~for ~~States Treasury yield curve. The expected dividend yield incorporates~~ the ~~current~~six ~~and~~months ~~historical~~ended ~~dividend~~June 30, ~~rate.~~2015, ~~The expected stock price volatility~~ is ~~estimated~~presented ~~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%
	Stock Options		Performance Stock Rights		Restricted Stock Units
Expected dividend yield	5.25% – 5.33%
Outstanding at December 31, 2014	134,017		238,571		427,305
Expected volatility	18% – 19%
Granted	—		—		224,784
Dividend equivalents	N/A		N/A		9,154
Exercised (1)/Distributed (2)/Vested and Released (3)	(70,692	)	(40,385	)	(166,681	)
Adjustment for performance stock rights distributed or canceled	N/A		169,379		N/A
Forfeited	—		—		(948	)
Canceled due to WEC Merger	(63,325	)	(367,565	)	(493,614	)
Outstanding at June 30, 2015	—		—		—

A(1) The ~~summary~~intrinsic value of ~~the activity for the three months ended March 31, 2015, related to performance~~ stock ~~rights~~options ~~accounted~~exercised ~~for~~was asnot ~~equity~~significant. ~~awards is presented below:~~

	PerformanceStock 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

⁽²⁾ The intrinsic value of shares distributed for performance stock rights was $3.1 million. The actual tax benefit realized for the tax deductions from the distribution of performance stock rights was not significant.

*(3) The ~~Reflects~~intrinsic ~~the~~value ~~weighted-average~~of ~~fair~~restricted ~~value~~share ~~used~~unit toawards ~~measure~~vested ~~equity~~and ~~awards~~released was $12.8 ~~Equity~~million. ~~awards~~The ~~are~~actual ~~measured~~tax ~~using~~benefit ~~the~~realized ~~grant~~for ~~date~~the ~~fair~~tax ~~value~~deductions orfrom the ~~fair~~vesting ~~value~~and onrelease ~~the~~of ~~modification~~restricted ~~date~~share units was $5.1 million.

~~The~~Note ~~weighted-average~~15—Common ~~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.~~Equity

AOn ~~summary~~June ~~of the activity for the three months ended March 31~~29, 2015, ~~related~~all toof ~~performance~~our ~~stock~~outstanding ~~rights~~common ~~accounted~~shares ~~for~~were asacquired ~~liability~~by ~~awards~~WEC. ~~is presented below:~~

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

Our ability to pay dividends or return capital to WEC 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 ~~weighted-average~~PSCW ~~fair~~allows ~~value~~WPS ofto ~~all~~pay ~~outstanding~~dividends ~~performance~~on ~~stock~~its ~~rights~~common ~~accounted~~stock ~~for~~of asno ~~liability~~more ~~awards~~than as103% of ~~March 31,~~the ~~2015,~~previous ~~was~~year’s ~~$106~~common stock dividend.95 ~~per~~WPS ~~performance~~may ~~stock~~return ~~right~~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

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~~The~~capital ~~total~~would ~~intrinsic~~cause ~~value~~its ofaverage ~~shares~~financial ~~distributed~~common ~~during~~equity ~~the~~ratio ~~three~~to ~~months~~fall ~~ended~~below ~~March 31,~~this ~~2015, was $3~~level.1 ~~million.~~Our ~~The~~right ~~actual~~to ~~tax~~receive ~~benefit~~dividends ~~realized~~on ~~for~~ the ~~tax~~common ~~deductions~~stock ~~from~~of ~~the~~WPS ~~distribution~~is ofalso ~~shares~~subject ~~during~~to the ~~three~~prior ~~months~~rights ~~ended~~of ~~March 31,~~WPS’s ~~2015,~~preferred ~~was~~shareholders ~~not~~and ~~significant.~~to Noprovisions ~~shares~~in ofWPS’s ~~common~~restated ~~stock~~articles ~~were~~of ~~distributed~~incorporation, ~~for~~which ~~performance~~limit ~~stock~~the ~~rights~~amount ~~during~~of ~~the~~common ~~three~~stock ~~months~~dividends ~~ended~~that ~~March 31,~~WPS ~~2014,~~may ~~because~~pay ~~the~~if ~~performance~~its ~~percentage~~common ~~was~~stock ~~below~~and ~~the~~common ~~threshold~~stock ~~payout~~surplus ~~level~~accounts ~~for~~constitute ~~those~~less ~~rights~~than ~~that~~25% ~~were~~of ~~eligible~~its ~~for~~total ~~distribution~~capitalization.

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.

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

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.

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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

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.~~

18As of June 30, 2015, total restricted net assets of consolidated subsidiaries were $1,893.8 million. Our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method was $166.7 million at June 30, 2015.

~~Table~~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%. At June 30, 2015, these covenants did not restrict our retained earnings or the payment of ~~Contents~~any dividends.

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 ContributionsFrom 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.

(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
	Three Months Ended June 30, 2015									Six Months Ended June 30, 2015
(Millions)	Cash Flow Hedges			Defined Benefit Plans			Accumulated Other Comprehensive Loss			Cash Flow Hedges			Defined Benefit Plans			Accumulated Other Comprehensive Loss
Beginning balance at December 31, 2014	$	(3.2	)	$	(24.4	)	$	(27.6	)
Balance at the beginning of period	$	(3.1	)	$	(23.7	)	$	(26.8	)	$	(3.2	)	$	(24.4	)	$	(27.6	)
Amounts reclassified out of accumulated other comprehensive loss	0.1			0.7			0.8
Other comprehensive income before reclassifications	—			0.7			0.7			—			0.7			0.7
Ending balance at March 31, 2015	$	(3.1	)	$	(23.7	)	$	(26.8	)
Amounts reclassified out of accumulated other comprehensive loss	0.2			0.9			1.1			0.3			1.6			1.9
Net current period other comprehensive income	0.2			1.6			1.8			0.3			2.3			2.6
Balance at the end of period	$	(2.9	)	$	(22.1	)	$	(25.0	)	$	(2.9	)	$	(22.1	)	$	(25.0	)

Three Months Ended March 31, 2014							Accumulated Other
	Three Months Ended June 30, 2014									Six Months Ended June 30, 2014
(Millions)	Cash Flow Hedges			Defined Benefit Plans			Accumulated Other Comprehensive Loss			Cash Flow Hedges			Defined Benefit Plans			Accumulated Other Comprehensive Loss
Beginning balance at December 31, 2013	$	(3.1	)	$	(20.1	)	$	(23.2	)
Balance at the beginning of period	$	(3.7	)	$	(19.9	)	$	(23.6	)	$	(3.1	)	$	(20.1	)	$	(23.2	)
Other comprehensive loss before reclassifications	—			~~(0.1~~—		)	~~(0.1~~—		)	—			(0.1		)	(0.1		)
Amounts reclassified out of accumulated other comprehensive loss	(0.62		)	0.35			(0.37		)	(0.4		)	0.8			0.4
Net current period other comprehensive (loss) income	(0.6		)	0.2			(0.4		)
Net current period other comprehensive income (loss)	0.2			0.5			0.7			(0.4		)	0.7			0.3
Ending balance at March 31, 2014	$	(3.7	)	$	(19.9	)	$	(23.6	)
Balance at the end of period	$	(3.5	)	$	(19.4	)	$	(22.9	)	$	(3.5	)	$	(19.4	)	$	(22.9	)

19Note 17—Risk Management Activities

Our 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. We use financial derivative contracts to manage the risks associated with the market price volatility of natural gas supply costs, coal transportation costs, and the cost of gasoline and diesel fuel used by utility vehicles. We use FTRs to manage electric transmission congestion costs in the MISO market.

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The following ~~table~~tables ~~shows~~show ~~the~~our ~~reclassifications~~assets ~~out~~and ofliabilities ~~accumulated~~from ~~other~~risk ~~comprehensive~~management ~~loss~~activities:

	Amount Reclassified
			June 30, 2015
	Three Months Ended March 31								Affected Line Item in the Statements of Income
(Millions)	Balance Sheet Presentation *		Assets fromRisk Management Activities				Liabilities fromRisk Management Activities
(Millions)	2015				2014
Natural gas contracts	Other current		$	2.6			$	19.5
Losses (gains) on cash flow hedges
Natural gas contracts	Other long-term		1.0				2.9
Interest rate hedges	$	0.2			$	0.3			Interest expense
FTRs	Other current		4.1				—
	0.1				0.9				Tax expense
Petroleum product contracts	Other current		—				0.9
	0.1				(0.6		)		Net of tax
Coal contracts	Other current		—				4.1
Defined benefit plans
Coal contracts	Other long-term		—				2.1
Amortization of prior service costs (credits)	0.3				(0.1		)		*
	Other current		6.7				24.5
Amortization of net actuarial losses	0.9				0.7				*
	Other long-term		1.0				5.0
	1.2				0.6				Total before tax
Total			$	7.7			$	29.5
	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.

Note 17—Variable Interest Entities

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.

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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.

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 fromRisk Management Activities		Liabilities fromRisk 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.

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

	March 31, 2015
	June 30, 2015
(Millions)	Gross Amount		Potential Effects of Netting, Including Cash Collateral		Net Amount
Derivative assets subject to master netting or similar arrangements	$	17.87	$	13.20	$	04.67
Derivative assets not subject to master netting or similar arrangements	—				—
Total risk management assets	$	17.87			$	04.67
Derivative liabilities subject to master netting or similar arrangements	$	3522.91	$	54.5	$	3017.46
Derivative liabilities not subject to master netting or similar arrangements	7.4				7.4
Total risk management liabilities	$	4329.35			$	3725.80



	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 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:~~18

(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

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~~The~~Financial ~~table~~collateral ~~below~~provided ~~shows~~is restricted to the ~~unrealized~~extent ~~gains~~that ~~(losses)~~it ~~recorded~~is ~~related~~required toper ~~derivative~~the ~~contracts~~terms atof the ~~utilities~~related ~~and~~agreements. ~~IBS~~The following table shows our cash collateral positions:

			Three Months Ended March 31
(Millions)	June 30, 2015				December 31, 2014
(Millions)	Financial Statement Presentation		2015				2014
Cash collateral provided to others: *
Natural gas	Balance Sheet — Regulatory assets (current)		$	10.9			$	0.9
Related to contracts under master netting or similar arrangements	$	19.0			$	11.6
Natural gas	Balance Sheet — Regulatory assets (long-term)		(0.6		)		(0.2		)
Other	1.1				1.1
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~~Cash ~~Value~~collateral provided to others is reflected in other current assets on our balance sheets.

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 June 30, 2015, and December 31, 2014, was $19.8 million and $31.3 million, respectively. At June 30, 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 June 30, 2015, and at December 31, 2014, we would have been required to post collateral of $18.6 million and $27.1 million, respectively.

The notional volumes of our outstanding derivative contracts were as follows:

June 30, 2015

December 31, 2014

(Millions)

Purchases

Other Transactions

Purchases

Other Transactions

Natural gas (therms)

774.7

N/A

1,860.0

N/A

FTRs (kilowatt-hours)

N/A

8,577.9

N/A

4,287.7

Petroleum products (barrels)

0.1

N/A

0.1

N/A

Coal (tons)

2.2

N/A

3.0

N/A

The table below shows the unrealized gains (losses) recorded related to our derivative contracts:



		Three Months Ended June 30				Six Months Ended June 30
(Millions)	Financial Statement Presentation	2015		2014		2015		2014
Natural gas	Balance Sheet — Regulatory assets	11.9		(1.0	)	22.2		(0.3	)
Natural gas	Balance Sheet — Regulatory liabilities	0.8		(3.3	)	(0.6	)	(0.3	)
Natural gas	Income Statement — Operating and maintenance expense	0.2		(0.1	)	0.1		0.1
FTRs	Balance Sheet — Regulatory assets	(7.2	)	(1.0	)	(7.0	)	(0.9	)
FTRs	Balance Sheet — Regulatory liabilities	2.4		1.1		2.0		1.0
Petroleum	Balance Sheet — Regulatory assets	0.5		—		0.9		—
Petroleum	Income Statement — Operating and maintenance expense	0.6		0.1		1.0		0.1
Coal	Balance Sheet — Regulatory assets	0.6		(0.1	)	(4.0	)	0.5
Coal	Balance Sheet — Regulatory liabilities	—		0.9		—		2.5

Note 18—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.

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

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

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
	June 30, 2015
(Millions)	Level 1		Level 2		Level 3		Total
Assets
Risk Management Assets
Natural gas contracts	$	0.1.4	$	12.02	$	—	$	13.16
Financial transmission rights (FTRs)	—		—		04.71		04.71
Total Risk Management Assets	$	0.1.4	$	12.02	$	04.71	$	17.87
Investment in exchange-traded funds	$	~~112~~107.35	$	—	$	—	$	~~112~~107.35
Liabilities
Risk Management Liabilities
Natural gas contracts	$	21.34	$	3121.40	$	—	$	3322.74
Petroleum product contracts	20.19		—		—		20.19
FTRs	—		—		0.1		0.1
Coal contracts	—		0.8		5.4		6.2
Coal contracts	—		1.2		6.2		7.4
Total Risk Management Liabilities	$	2.3	$	21.8	$	5.4	$	29.5
Total Risk Management Liabilities	$	4.4	$	32.6	$	6.3	$	43.3

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	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 1817, Risk Management Activities, for more information.

There were no transfers between the levels of the fair value hierarchy during the three or six months ended ~~March~~June 3130, 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~~June 3130, 2015:

Fair Value (Millions)

Assets

Liabilities

Valuation Technique

Unobservable Input

Average or Range

FTRs

04.71

~~0.1~~—

Market-based

Forward market prices ($/megawatt-month) (1)

$~~159~~172.4271

Coal contracts

—

65.24

Market-based

Forward market prices ($/ton) (2)

$9.7086 – $1213.3923


⁽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.

2421

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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
Three Months Ended June 30, 2015
(Millions)				FTRs			Coal Contracts			Total
Balance at the beginning of the period				$	0.6		$	(6.2	)	$	(5.6	)
Net realized losses included in earnings				(1.2		)	—			(1.2		)
Net unrealized (losses) gains recorded as regulatory assets or liabilities				(4.8		)	0.3			(4.5		)
Purchases				9.8			—			9.8
Settlements				(0.3		)	0.5			0.2
Balance at the end of the period				$	4.1		$	(5.4	)	$	(1.3	)
Three Months Ended June 30, 2014
(Millions)				FTRs			Coal Contracts			Total
Balance at the beginning of the period				$	0.5		$	0.3		$	0.8
Net realized gains included in earnings				0.1			—			0.1
Net unrealized gains recorded as regulatory assets or liabilities				0.1			0.8			0.9
Purchases				4.4			—			4.4
Settlements				(1.1		)	(0.2		)	(1.3		)
Balance at the end of the period				$	4.0		$	0.9		$	4.9
Six Months Ended June 30, 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	—			(1.2.4		)	—			(1.2.4		)
Net unrealized losses recorded as regulatory assets or liabilities	—			(05.20		)	(4.30		)	(49.50		)
Settlements	6.6			0.1			0.3			7.0
Purchases	—			9.8			—			9.8
Balance at the end of the period	$	—		$	0.6		$	(6.2	)	$	(5.6	)
Settlements	6.6			(0.2		)	0.8			7.2
Three Months Ended March 31, 2014
Balance at the end of the period	$	—		$	4.1		$	(5.4	)	$	(1.3	)
Six Months Ended June 30, 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				0.78			—			0.78
Net unrealized gains recorded as regulatory assets or liabilities				—0.1			23.20			23.21
Purchases				(04.13		)	—			(04.13		)
Settlements				(12.34		)	0.64			(02.70		)
Balance at the end of the period				$	04.50		$	0.39		$	04.89

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
	June 30, 2015				December 31, 2014
(Millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	3,081.3	$	3,~~328~~112.09	$	3,081.3	$	3,271.4
Preferred stock of subsidiary	51.1		5253.31		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.

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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.

Note 2019—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~~higher ~~expiration~~operating ofand amaintenance ~~2015~~costs, ~~customer~~general ~~refund~~inflation, ~~related~~and toan ~~decoupling,~~increase ~~increased~~in ~~operating~~the ~~and~~amount ~~maintenance~~of ~~costs,~~outstanding ~~and~~equity ~~general~~supporting ~~inflation~~construction projects.

In May 2015, WPS filed a revised application with the PSCW adjusting its requested retail electric rate increase to $96.9 million and its requested retail natural gas rate increase to $9.1 million. The revised requests are primarily driven by revisions to retail electric and natural gas revenues and employee benefit costs.

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.

25The primary driver of the increase in retail electric rates was higher costs of fuel for electric generation of approximately $42.0 million. In addition, 2015 rates include approximately $9.0 million of lower refunds to customers related to decoupling over-collections. In 2015 rates, WPS is refunding approximately $4.0 million to customers related to 2013 decoupling over-collections compared with refunding approximately $13.0 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.

~~Table~~The retail natural gas rate decrease was driven by the approximate $16.0 million year-over-year negative impact of ~~Contents~~decoupling refunds to and collections from customers. In 2015 rates, WPS is refunding approximately $8.0 million to customers related to 2013 decoupling over-collections compared with recovering approximately $8.0 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 rate increase.

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 $8.0 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.

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Michigan

2016 MGU Rate Case

In June 2015, MGU filed an application with the MPSC to increase retail natural gas rates $6.7 million, with rates expected to be effective January 1, 2016. MGU's request reflects a 10.50% return on common equity and a target common equity ratio of 50.40% in MGU's regulatory capital structure. The proposed retail natural gas rate increase is driven by upgrades to MGU's natural gas transmission and distribution systems as well as a higher cost of capital. Also included are increases in costs for new employees, natural gas main maintenance, stand-by employee agreements, new customer service functions, and general inflation. MGU is requesting authority from the MPSC to continue the use of its currently authorized decoupling mechanism.

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. No appeals were filed related to the rehearing requests.

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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.

2013 Rates Amended in 2014

In June 2013, the ICC issued a final written order for PGL and NSG, effective June 27, 2013,. ~~which~~The order authorized a retail natural gas ~~rates~~rate ~~for~~increase ~~both~~of $57.2 million for PGL and $6.6 million for 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.

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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 April 2015, the Citizens Utility Board appeal was withdrawn, and, in May 2015, the Illinois Appellate Court dismissed the appeal from the Illinois Attorney General.

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, MERC expects to refund $4.7 million ~~is expected~~ to becustomers ~~refunded~~in to2015, ~~customers~~of ~~beginning~~which in$3.5 ~~June~~million ~~2015,~~was ~~and~~refunded isduring ~~recorded~~the asfirst ahalf ~~regulatory~~of ~~liability~~2015.

Note 2120—Segments of Business

AtWe ~~March 31,~~reorganized ~~2015,~~our webusiness ~~had~~segments ~~four~~during ~~segments~~the ~~related~~second quarter of 2015 to reflect our ~~continuing~~new ~~operations~~internal organization and ~~one~~management structure. We use net income to measure segment ~~related~~profitability and allocate resources to ~~the~~our ~~discontinued~~businesses. ~~operations~~All ofprior ~~IES's~~period ~~retail~~amounts ~~energy~~impacted ~~business~~by this change were reclassified to conform to the new presentation. ~~Our~~At ~~reportable~~June 30, 2015, we reported five segments, which are described below.

• The ~~natural~~Wisconsin ~~gas utility~~ segment includes the electric and natural gas utility and nonutility operations of ~~MERC, MGU, NSG, PGL, and~~ WPS.

• The ~~electric~~Illinois ~~utility~~ segment includes the ~~electric~~natural gas utility ~~operations~~and ofnonutility ~~WPS, as well as the~~ operations of ~~UPPCO~~NSG ~~prior~~and ~~to its sale to Balfour Beatty Infrastructure Partners LP in August 2014~~PGL. ~~See Note 4, Dispositions, for more information on the sale of UPPCO.~~

• The ~~electric~~Other ~~transmission~~States ~~investment~~ segment includes ~~our~~the ~~approximate~~natural ~~34%~~gas ~~ownership~~utility ~~interest~~and nonutility operations of MERC and MGU, as well as the operations of UPPCO prior to its sale to Balfour Beatty Infrastructure Partners LP in ~~ATC~~August 2014. ~~ATC~~See isNote a3, ~~federally~~Dispositions, ~~regulated~~for ~~electric~~more ~~transmission~~information ~~company~~on the sale of UPPCO.

• The ~~IES~~Electric ~~segment~~Transmission ~~includes~~Investment ~~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~~our ~~operations.~~approximate ~~See~~34% ~~Note~~ownership 4,interest ~~Dispositions,~~in ~~for more information on the sale of IES's retail energy business~~ATC. ~~The~~ATC ~~remaining~~is ~~energy~~a ~~asset~~federally ~~business,~~regulated ~~PDI,~~electric ~~was~~transmission ~~reclassified to the holding~~ company ~~and other segment~~.

• The ~~holding~~Corporate ~~company~~ and ~~other~~Other segment includes the operations of the ~~Integrys Energy Group~~ holding company, ITF, ~~PDI~~PDL, ~~and~~ the PELLC holding company, ~~along~~and ~~with~~ any nonutility activities at ~~IBS~~WBS, ~~MERC,~~as ~~MGU,~~well ~~NSG~~as the operations of IES's retail energy business prior to its sale in November 2014 to Exelon Generation Company, ~~PGL~~LLC. See Note 3, ~~UPPCO~~Dispositions, ~~and~~for ~~WPS~~more information on the sale of IES's retail energy business.

The tables below present information related to our reportable segments:



	Regulated Operations
(Millions)	Wisconsin		Illinois		Other States		Electric Transmission Investment		Total Regulated Operations		Corporate and Other			Reconciling Eliminations			Integrys Holding Consolidated
Three Months Ended
June 30, 2015
External revenues	$	330.2	$	218.6	$	67.9	$	—	$	616.7	$	21.6		$	—		$	638.3
Depreciation and amortization expense	30.2		30.8		4.8		—		65.8		6.3			—			72.1
Merger costs	—		—		—		—		—		59.3			—			59.3
Impairment loss on property, plant, and equipment at PDL	—		—		—		—		—		10.7			—			10.7
Gain on sale of certain PDL solar power generation plants	—		—		—		—		—		(5.2		)	—			(5.2		)
Equity in earnings of transmission affiliate	—		—		—		22.4		22.4		—			—			22.4
Miscellaneous income (expense)	4.3		0.2		—		—		4.5		(0.2		)	(2.5		)	1.8
Interest expense	14.5		9.9		2.7		—		27.1		15.4			(2.5		)	40.0
Provision (benefit) for income taxes	13.0		3.6		0.6		8.9		26.1		(34.2		)	—			(8.1		)
Net income (loss)	21.0		4.7		0.9		13.5		40.1		(49.4		)	—			(9.3		)

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	Regulated Operations												~~Nonutility and Nonregulated Operations~~
(Millions)	~~Natural GasUtility~~Wisconsin			~~ElectricUtility~~Illinois			~~ElectricTransmissionInvestment~~Other States			~~TotalRegulatedOperations~~Electric TransmissionInvestment			~~IES~~Total RegulatedOperations			~~HoldingCompanyand~~Corporate and Other			ReconcilingEliminations			~~IntegrysEnergy~~Integrys ~~GroupConsolidated~~HoldingConsolidated
Three Months Ended
March 31, 2015
June 30, 2014
External revenues	$	~~839~~353.51		$	~~295~~351.80		$	—106.5		$	~~1,135.3~~—		$	—810.6		$	2726.95		$	—		$	~~1,163~~837.21
Intersegment revenues	25.68			—			—			~~2.6~~—			—5.8			~~0.2~~—			(25.8		)	—
Depreciation and amortization expense	4029.60			2528.04			—6.6			~~65.6~~—			—64.0			98.28			~~(0.1~~—		)	7472.78
Earnings from equity method investments	—			—			17.0			17.0			—			0.5			—			17.5
Merger costs	—			—			—			—			—			5.9			—			5.9
Miscellaneous income	0.7			2.8			—			3.5			—			5.1			(2.0		)	6.6
Equity in earnings of transmission affiliate	—			—			—			23.0			23.0			—			—			23.0
Interest expense	14.3			10.9			—			25.2			—			15.0			(2.0		)	38.2
Miscellaneous income (expense)	4.2			(0.5		)	—			—			3.7			5.2			(3.1		)	5.8
Provision (benefit) for income taxes	65.9			16.4			6.7			89.0			—			(10.1		)	—			78.9
Interest expense	15.1			8.2			3.1			—			26.4			16.0			(3.1		)	39.3
Net income (loss) from continuing operations	97.8			28.6			10.3			136.7			—			(5.5		)	—			131.2
Provision (benefit) for income taxes	9.9			(3.8		)	(2.2		)	9.2			13.1			(8.6		)	—			4.5
Discontinued operations	—			—			—			—			(0.8		)	(0.1		)	—			(0.9		)
Net income (loss) from continuing operations	15.5			(5.4		)	(2.6		)	13.8			21.3			(13.3		)	—			8.0
Preferred stock dividends of subsidiary	(0.1		)	(0.7		)	—			(0.8		)	—			—			—			(0.8		)
Discontinued operations	—			—			—			—			—			(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
Net income (loss)	15.5			(5.4		)	(2.6		)	13.8			21.3			(14.1		)	—			7.2

	Regulated Operations											~~Nonutility and Nonregulated Operations~~
(Millions)	~~Natural GasUtility~~Wisconsin			~~ElectricUtility~~Illinois			~~ElectricTransmissionInvestment~~Other States		~~TotalRegulatedOperations~~Electric TransmissionInvestment			~~IES~~Total RegulatedOperations		~~HoldingCompanyand~~Corporate and Other			ReconcilingEliminations			~~IntegrysEnergy~~Integrys ~~GroupConsolidated~~HoldingConsolidated
Three Months Ended
Six Months Ended
March 31, 2014
June 30, 2015
External revenues	$	~~1,267~~755.63		$	~~349~~750.2		$	—250.4	$	~~1,616.8~~—		$	—1,755.9	$	2145.29		$	—		$	1,~~638~~801.08
Intersegment revenues	4.4			—			—		4.4			—		0.4			(4.8		)	—
Depreciation and amortization expense	60.1			62.5			9.5		—			132.1		15.4			—			147.5
Depreciation and amortization expense	36.4			25.6			—		62.0			—		8.7			(0.1		)	70.6
Merger costs	—			—			—		—			—		60.0			—			60.0
Earnings from equity method investments	—			—			22.5		22.5			—		0.4			—			22.9
Impairment loss on property, plant, and equipment at PDL	—			—			—		—			—		10.7			—			10.7
Miscellaneous income	0.3			3.5			—		3.8			—		5.3			(3.3		)	5.8
Gain on sale of certain PDL solar power generation plants	—			—			—		—			—		(5.2		)	—			(5.2		)
Interest expense	13.4			11.7			—		25.1			—		17.1			(3.3		)	38.9
Equity in earnings of transmission affiliate	—			—			—		39.4			39.4		—			—			39.4
Provision (benefit) for income taxes	66.7			18.1			8.8		93.6			—		(11.7		)	—			81.9
Miscellaneous income	8.8			0.9			—		—			9.7		3.9			(4.5		)	9.1
Net income (loss) from continuing operations	99.2			31.8			13.7		144.7			—		(4.5		)	—			140.2
Interest expense	29.2			19.4			5.0		—			53.6		29.9			(4.5		)	79.0
Discontinued operations	—			—			—		—			13.0		(0.1		)	—			12.9
Provision (benefit) for income taxes	35.1			52.3			12.3		15.6			115.3		(44.4		)	—			70.9
Preferred stock dividends of subsidiary	(0.1		)	(0.7		)	—		(0.8		)	—		—			—			(0.8		)
Net income (loss) from continuing operations	58.6			76.2			18.3		23.8			176.9		(55.9		)	—			121.0
Noncontrolling interest in subsidiaries	—			—			—		—			—		0.1			—			0.1
Discontinued operations	—			—			—		—			—		(0.8		)	—			(0.8		)
Net income (loss) attributed to common shareholders	99.1			31.1			13.7		143.9			13.0		(4.5		)	—			152.4
Net income (loss)	58.6			76.2			18.3		23.8			176.9		(56.7		)	—			120.2
	Regulated Operations
(Millions)	Wisconsin			Illinois			Other States		Electric TransmissionInvestment			Total RegulatedOperations		Corporate and Other			ReconcilingEliminations			Integrys HoldingConsolidated
Six Months Ended
June 30, 2014
External revenues	$	903.7		$	1,127.8		$	399.7	$	—		$	2,431.2	$	44.2		$	—		$	2,475.4
Intersegment revenues	11.2			—			—		—			11.2		—			(11.2		)	—
Depreciation and amortization expense	57.4			56.4			13.1		—			126.9		17.3			—			144.2
Merger costs	—			—			—		—			—		5.9			—			5.9
Equity in earnings of transmission affiliate	—			—			—		45.5			45.5		—			—			45.5
Miscellaneous income (expense)	9.2			(0.2		)	—		—			9.0		9.8			(6.5		)	12.3
Interest expense	29.9			16.5			6.5		—			52.9		32.6			(6.5		)	79.0
Provision (benefit) for income taxes	38.7			35.6			14.1		18.0			106.4		(20.0		)	—			86.4
Net income (loss) from continuing operations	64.3			52.3			22.0		27.5			166.1		(18.6		)	—			147.5
Discontinued operations	—			—			—		—			—		12.1			—			12.1
Net income (loss)	64.3			52.3			22.0		27.5			166.1		(6.5		)	—			159.6

~~Note 22—New Accounting Pronouncements~~26

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Note 21—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.

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.

28In 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 was originally effective for us for the reporting period ending March 31, 2017; however, in July 2015 the FASB decided to delay the effective date for one year. Companies can still elect to adopt the standard as of the original effective date. 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.

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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.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read in conjunction with the accompanying financial statements and related notes and our Annual Report on Form 10-K for the year ended December 31, 2014.

SUMMARY

On June 29, 2015, the WEC Merger was completed and we became a wholly owned subsidiary of WEC. We are an energy holding company with natural gas and electric utility operations (serving customers in Illinois, Michigan, Minnesota, and Wisconsin), an approximate 34% equity ownership interest in ATC (a federally regulated electric transmission company), and nonregulated energy operations.

In the second quarter of 2015, we changed our reportable segments. See Note 20, Segments of Business, for more information

RESULTS OF OPERATIONS

Earnings Summary

	Three Months Ended March 31						Change in 2015 Over 2014
	Three Months Ended June 30						Change in 2015 Over 2014		Six Months Ended June 30						Change in 2015 Over 2014
(Millions, except per share amounts)	2015			2014
(Millions)	2015			2014					2015			2014
Natural gas utility operations	$	97.7		$	99.1		(1.4	)%
Wisconsin operations	$	21.0		$	15.5		35.5	%	$	58.6		$	64.3		(8.9	)%
Electric utility operations	27.9			31.1			(10.3	)%
Illinois operations	4.7			(5.4		)	N/A		76.2			52.3			45.7	%
Electric transmission investment	10.3			13.7			(24.8	)%
Other states operations	0.9			(2.6		)	N/A		18.3			22.0			(16.8	)%
IES’s retail energy business - discontinued operations	(0.8		)	13.0			N/A
Electric transmission investment	13.5			13.8			(2.2	)%	23.8			27.5			(13.5	)%
Holding company and other operations	(5.6		)	(4.5		)	24.4	%
Corporate and other operations	(49.4		)	(14.1		)	250.4	%	(56.7		)	(6.5		)	772.3	%
Net income attributed to common shareholders	$	129.5		$	152.4		(15.0	)%
Net income	$	(9.3	)	$	7.2		N/A		$	120.2		$	159.6		(24.7	)%
Basic earnings per share	$	1.61		$	1.90		(15.3	)%
Diluted earnings per share	$	1.60		$	1.89		(15.3	)%
Average shares of common stock
Basic	80.2			80.2			—	%
Diluted	80.8			80.5			0.4	%

~~First~~Second Quarter 2015 Compared with ~~First~~Second Quarter 2014

The $2216.95 million decrease in our earnings was driven by:

• A $1334.83 million after-tax ~~decrease~~increase in ~~earnings~~merger-related ~~from~~costs. ~~discontinued~~Included ~~operations~~in the 2015 costs was $26.6 million of after-tax expense related to ~~IES's~~the ~~retail~~accelerated ~~energy~~vesting ~~business.~~of ~~See~~our ~~Note~~outstanding 4,stock-based ~~Dispositions,~~compensation ~~for~~awards ~~more~~and ~~information~~change-in-control payments.

• AnA ~~approximate~~ $126.4 million after-tax ~~decrease~~impairment inloss ~~margins~~recorded aton ~~our existing utilities due to variances related to sales volumes~~property, ~~net of decoupling~~plant, ~~driven~~and byequipment ~~warmer~~at ~~quarter-over-quarter~~PDL ~~weather. Although weather was colder than normal~~ in ~~the first quarter of~~ 2015~~, it was warmer than the extreme cold of 2014~~.

• An approximate $42.0 million after-tax net decrease in ~~earnings~~margins at our existing utilities due to ~~the~~variances ~~sale~~related ofto ~~UPPCO~~sales involumes, ~~August~~net ~~2014~~of decoupling. ~~See~~The ~~Note~~decrease 4,was ~~Dispositions,~~driven ~~for~~by ~~more~~lower ~~information~~use per residential customer at our Wisconsin segment and warmer weather in the second quarter of 2015.

• AAn approximate $32.40 million after-tax decrease in earnings ~~from~~due ~~our approximate 34% ownership interest in ATC. ATC's 2015 earnings included a reserve for an anticipated refund~~ to ~~customers related to a complaint filed with~~ the ~~FERC~~sale ~~requesting~~of aUPPCO ~~lower~~in ~~return~~August ~~on equity for certain transmission owners~~2014. ~~The~~See ~~reserve~~Note ~~included~~3, anDispositions, ~~after-tax~~for ~~adjustment~~more ~~of $2~~information.~~9 million related to prior years due to a revision to the estimated refund.~~

These decreases ~~were partially offset by an $11.0 million after-tax decrease~~ in ~~operating~~earnings ~~expenses~~were atpartially ~~our existing utilities, excluding items directly~~ offset ~~in margins, driven~~ by ~~lower repairs and maintenance expense.~~:


•	The approximate $14.0 million after-tax positive impact of rate orders at our utilities.


•	A $9.1 million after-tax decrease in operating expenses at our existing utilities, excluding items directly offset in margins, driven by lower repairs and maintenance expense.


•	A $5.5 million after-tax gain on the sale of certain PDL solar power generation plants in 2015.

Six Months 2015 Compared with Six Months 2014

The $39.4 million decrease in our earnings was driven by:


•	A $34.9 million after-tax increase in merger-related costs. Included in the 2015 costs was $26.6 million of after-tax expense related to the accelerated vesting of our outstanding stock-based compensation awards and change-in-control payments.


•	A $12.9 million after-tax decrease in earnings from discontinued operations driven by the sale of IES's retail energy business in November 2014. See Note 3, Dispositions, for more information.

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•	An approximate $13.0 million after-tax decrease in margins at our existing utilities due to variances related to sales volumes, net of decoupling, driven by warmer weather in 2015.


•	An approximate $6.0 million after-tax decrease in earnings due to the sale of UPPCO in August 2014. See Note 3, Dispositions, for more information.


•	A $6.4 million after-tax impairment loss recorded on property, plant, and equipment at PDL in 2015.


•	A $3.7 million after-tax decrease in earnings from our approximate 34% ownership interest in ATC. ATC's earnings for the six months ended June 30, 2015 included a reserve for an anticipated refund to customers related to a complaint filed with the FERC requesting a lower return on equity for certain transmission owners.

These decreases in earnings were partially offset by:


•	A $19.0 million after-tax decrease in operating expenses at our existing utilities, excluding items directly offset in margins, driven by lower repairs and maintenance expense.


•	The approximate $15.0 million after-tax positive net impact of rate orders at our utilities.


•	A $5.5 million after-tax gain on the sale of certain PDL solar power generation plants in 2015.

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Wisconsin Segment Operations



	Three Months Ended June 30						Change in 2015 Over 2014		Six Months Ended June 30						Change in 2015 Over 2014
(Millions, except degree days)	2015			2014			Change in 2015 Over 2014		2015			2014			Change in 2015 Over 2014
Revenues	$	330.2		$	358.9		(8.0	)%	$	755.3		$	914.9		(17.4	)%
Cost of sales	120.4			147.7			(18.5	)%	321.0			450.7			(28.8	)%
Margins	209.8			211.2			(0.7	)%	434.3			464.2			(6.4	)%

Operating and maintenance expense	125.1			135.4			(7.6	)%	239.6			262.5			(8.7	)%
Depreciation and amortization expense	30.2			29.0			4.1	%	60.1			57.4			4.7	%
Property and revenue taxes	10.3			10.5			(1.9	)%	20.5			20.6			(0.5	)%
Operating income	44.2			36.3			21.8	%	114.1			123.7			(7.8	)%

Miscellaneous income	4.3			4.2			2.4	%	8.8			9.2			(4.3	)%
Interest expense	14.5			15.1			(4.0	)%	29.2			29.9			(2.3	)%
Other expense	(10.2		)	(10.9		)	(6.4	)%	(20.4		)	(20.7		)	(1.4	)%

Income before taxes	$	34.0		$	25.4		33.9	%	$	93.7		$	103.0		(9.0	)%

Retail throughput in therms
Residential	33.1			39.9			(17.0	)%	161.2			181.8			(11.3	)%
Commercial and industrial	20.5			24.9			(17.7	)%	94.7			112.1			(15.5	)%
Other	8.2			4.7			74.5	%	15.4			14.6			5.5	%
Total retail throughput in therms	61.8			69.5			(11.1	)%	271.3			308.5			(12.1	)%

Transport throughput in therms
Commercial and industrial	78.9			79.8			(1.1	)%	192.7			200.6			(3.9	)%

Total throughput in therms	140.7			149.3			(5.8	)%	464.0			509.1			(8.9	)%

Sales in kilowatt-hours
Residential	588.5			627.5			(6.2	)%	1,350.6			1,446.3			(6.6	)%
Commercial and industrial	1,977.9			1,969.6			0.4	%	3,947.0			3,926.2			0.5	%
Wholesale	629.1			665.3			(5.4	)%	1,264.6			1,331.5			(5.0	)%
Opportunity sales	124.1			156.0			(20.4	)%	426.1			269.5			58.1	%
Other	6.3			6.4			(1.6	)%	15.5			15.8			(1.9	)%
Total sales in kilowatt-hours	3,325.9			3,424.8			(2.9	)%	7,003.8			6,989.3			0.2	%

Weather *
Actual heating degree days	840			1,020			(17.6	)%	4,786			5,535			(13.5	)%
Normal heating degree days	981			975			0.6	%	4,643			4,621			0.5	%
Actual cooling degree days	98			109			(10.1	)%	98			109			(10.1	)%
Normal cooling degree days	137			141			(2.8	)%	137			141			(2.8	)%


*	Normal heating and cooling degree days are based on a 20-year average of monthly temperatures from the Green Bay Weather Station.

Second Quarter 2015 Compared with Second Quarter 2014

Electric Margins

Electric margins are defined as electric operating revenues less fuel and purchased power costs. Management believes that electric margins provide a more meaningful basis for evaluating electric operations than electric operating revenues. To the extent changes in fuel and purchased power costs are passed through to customers, the changes are offset by comparable changes in operating revenues.

Electric margins decreased $3.1 million, driven by:


•	An approximate $5.0 million decrease in margins related to sales volume variances. Margins from residential customers decreased, driven by lower use per customer and warmer weather in the second quarter of 2015.

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~~Natural~~• ~~Gas~~A ~~Utility~~partially ~~Segment~~offsetting ~~Operations~~approximate $2.0 million increase in margins related to rates, driven by:

	Three Months Ended March 31						Change in 2015 Over 2014
(Millions, except degree days)	2015			2014
Revenues	$	842.1		$	1,272.0		(33.8	)%
Purchased natural gas costs	447.1			830.4			(46.2	)%
Margins	395.0			441.6			(10.6	)%
Operating and maintenance expense	165.6			215.4			(23.1	)%
Depreciation and amortization expense	40.6			36.4			11.5	%
Taxes other than income taxes	11.5			10.8			6.5	%
Operating income	177.3			179.0			(0.9	)%
Miscellaneous income	0.7			0.3			133.3	%
Interest expense	14.3			13.4			6.7	%
Other expense	(13.6		)	(13.1		)	3.8	%
Income before taxes	$	163.7		$	165.9		(1.3	)%
Retail throughput in therms
Residential	793.2			927.2			(14.5	)%
Commercial and industrial	255.7			301.4			(15.2	)%
Other	18.7			23.9			(21.8	)%
Total retail throughput in therms	1,067.6			1,252.5			(14.8	)%
Transport throughput in therms
Residential	143.2			135.4			5.8	%
Commercial and industrial	600.3			618.9			(3.0	)%
Total transport throughput in therms	743.5			754.3			(1.4	)%
Total throughput in therms	1,811.1			2,006.8			(9.8	)%
Weather
Average actual heating degree days	3,779			4,174			(9.5	)%
Average normal heating degree days	3,425			3,371			1.6	%


◦	An increase of approximately $3.0 million related to fuel and purchased power cost over-collections as compared with approved rates in 2015, as opposed to under-collections as compared with approved rates in 2014. Under the fuel rule, WPS can only defer under or over-collections of certain fuel and purchased power costs that exceed a 2% price variance from the costs included in rates.

~~Natural~~◦ ~~gas~~This ~~utility~~increase ~~margins~~was ~~are~~partially ~~defined~~offset asby ~~natural~~a ~~gas~~decrease ~~utility~~in ~~operating~~margins ~~revenues~~of ~~less~~approximately ~~purchased natural gas costs~~$1.0 ~~Management~~million ~~believes~~as ~~that natural gas utility margins provide~~ a ~~more~~result ~~meaningful~~of ~~basis~~the ~~for~~PSCW ~~evaluating~~rate ~~natural~~order ~~gas~~and ~~utility~~rate ~~operations~~design, ~~than~~effective ~~natural~~January ~~gas utility revenues~~1, ~~since~~2015. ~~prudently~~Although ~~incurred~~the ~~natural~~PSCW ~~gas~~approved ~~commodity costs are passed through to our customers in current rates. There was~~ an ~~approximate~~electric ~~36%~~rate ~~decrease~~increase, in the ~~average~~majority ~~per-unit cost~~ of ~~natural~~the ~~gas~~increase ~~sold~~related ~~during~~to ~~the~~higher ~~three~~costs ~~months~~of ~~ended~~fuel ~~March~~for ~~31,~~electric ~~2015~~generation, which ~~had~~has no impact on margins. See Note 19, Regulatory Environment, for more information.

~~First~~Natural ~~Quarter~~Gas ~~2015 Compared with First Quarter 2014~~ Margins

~~Margins~~Natural gas margins are defined as natural gas operating revenues less purchased natural gas costs. Management believes that natural gas margins provide a more meaningful basis for evaluating natural gas operations than natural gas revenues, since prudently incurred natural gas commodity costs are passed through to our customers in current rates. There was an approximate 31% and 39% decrease in the average per-unit cost of natural gas sold during the three and six months ended June 30, 2015, which had no impact on margins.

Natural gas ~~utility segment~~ margins ~~decreased~~increased $461.67 million, driven by:

• AAn approximate $394.10 million ~~decrease~~increase in margins related to ~~certain~~the ~~riders~~PSCW atrate ~~NSG~~order, ~~and~~effective ~~PGL~~January ~~and~~1, ~~certain~~2015. ~~energy~~Although ~~efficiency~~the ~~programs~~PSCW atapproved ~~four~~a ~~of our~~ natural gas ~~utilities.~~rate ~~This~~ decrease, the increase in margins in the second quarter of 2015 was ~~offset~~driven by anrate ~~equal~~design ~~decrease~~changes. inThe ~~operating~~approved ~~expenses~~rate design increased fixed charges but lowered volumetric charges to customers to better match the fixed costs of providing service. As a result, ~~resulting~~this rate design provides for higher cost recovery in noperiods of low sales volumes. Some of this impact onis ~~earnings~~expected to reverse in future quarters with changes in sales volumes. See Note 19, Regulatory Environment, for more information.

◦• ~~Our~~A ~~natural~~partially ~~gas~~offsetting ~~utilities recovered~~ $242.50 million ~~less~~decrease ~~from~~in ~~customers~~margins ~~for~~related ~~energy~~to ~~efficiency~~sales ~~programs~~volume atvariances. ~~MERC,~~Margins ~~MGU,~~from ~~NSG~~residential customers decreased, driven by warmer weather and ~~PGL~~lower use per customer in the second quarter of 2015.

◦Operating ~~PGL and NSG recovered $8.4 million less from their customers through their bad debt rider mechanisms, driven by lower natural gas costs in 2015, and a decrease in sales volumes.~~Income

◦Operating ~~PGL~~income ~~and~~at ~~NSG~~the ~~recovered~~Wisconsin asegment ~~net~~increased $67.29 million. ~~less~~This ~~from~~increase ~~their~~was ~~customers~~driven ~~for~~by ~~environmental~~a ~~cleanup costs at their former manufactured gas plant sites~~$9.3 ~~Recovery~~million ~~rates at PGL were lower due to a~~ decrease in ~~remediation~~operating ~~costs~~expenses, ~~net~~partially ofoffset ~~insurance~~by ~~settlements~~the ~~received,~~combined ~~and~~$1.4 ~~sales~~million ~~volumes~~net ~~were~~decrease ~~lower~~in atelectric ~~both PGL~~ and ~~NSG.~~natural ~~See Note 11, Commitments and Contingencies, for more information about the manufactured~~ gas ~~plant~~margins ~~sites~~discussed above.

The decrease in operating expenses was primarily due to a $13.0 million decrease in maintenance expense, primarily at the Fox Energy Center, Pulliam, and our jointly-owned plants in 2015. Maintenance costs were also lower in the second quarter of 2015 due to a planned major outage at the Weston plant in 2014. This decrease was partially offset by a $1.8 million increase in electric transmission expenses.

Six Months 2015 Compared with Six Months 2014

Electric Margins

Electric margins decreased $11.5 million, driven by:


•	An approximate $10.0 million decrease in margins related to sales volume variances. Margins from residential customers decreased, driven by warmer weather and lower use per customer in 2015.


•	An approximate $1.0 million decrease in margins related to rates.


◦	Margins decreased approximately $7.0 million as a result of the PSCW rate order and rate design, effective January 1, 2015. Although the PSCW approved an electric rate increase, the majority of the increase related to higher costs of fuel for electric generation, which has no impact on margins. See Note 19, Regulatory Environment, for more information.

◦

These decreases in margins were partially offset by an increase of approximately $6.0 million related to fuel and purchased power cost over-collections as compared with approved rates in 2015, as opposed to under-collections as compared with approved rates in 2014. Under the fuel rule, WPS can only defer under or over-collections of certain fuel and purchased power costs that exceed a 2% price variance from the costs included in rates.


•	An approximate $1.0 million decrease in wholesale margins driven by a reduction in sales volumes. Certain wholesale customers have provisions in their contracts which allow them to reduce the amount of energy we provide to them.

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•Natural AnGas approximate $14 million decrease in margins from the combined effect of warmer weather quarter over quarter, lower weather-normalized volumes, and the partially offsetting impact of our decoupling mechanisms at MERC, MGU, NSG, and PGL. Margins for certain customer classes in both years, including all of WPS's customers, were sensitive to volume variances as they were not covered by decoupling mechanisms. See Note 20, Regulatory Environment, for more information on our decoupling mechanisms.

•Natural ~~These~~gas ~~decreases were partially offset by an approximate $6 million net increase in~~ margins ~~due~~decreased ~~to rate orders~~$18.4 ~~See Note 20~~million, ~~Regulatory~~driven ~~Environment, for more information.~~by:

◦• ~~The~~An ~~rate~~approximate ~~increases~~$12.0 atmillion ~~NSG~~decrease ~~and~~in ~~PGL,~~margins ~~effective~~due ~~January~~to ~~28,~~the ~~2015,~~PSCW ~~and~~rate ~~updated~~order, effective ~~February~~January 261, 2015, ~~had~~including an approximate $193.0 million ~~positive~~negative impact ondue ~~margins~~to rate design changes. The approved rate design increased fixed charges but lowered volumetric charges to customers to better match the fixed costs of providing service. As a result, this rate design provides for lower cost recovery in periods of high sales volumes. Some of this impact is expected to reverse in future quarters with changes in sales volumes. See Note 19, Regulatory Environment, for more information.

◦• ~~Increased~~An ~~revenues~~approximate at$7.0 ~~PGL~~million ~~for~~decrease ~~its~~in ~~Qualifying~~margins ~~Infrastructure~~related ~~Plant~~to ~~rider~~sales ~~had~~volume anvariances, ~~approximate~~driven $2by ~~million~~warmer ~~positive~~weather ~~impact~~in ~~on margins~~2015.

◦ These increases were partially offset by an approximate $15 million decrease in margins at WPS due to a rate decrease, effective January 1, 2015, including an approximate $5 million negative impact due to rate design changes. The 2015 rate order changed our rate design by increasing fixed charges but lowering volumetric charges to customers to better match the fixed costs of providing service. As a result, this rate design provides for lower cost recovery in periods of high sales volumes. Some of this impact is expected to reverse in future quarters with changes in sales volumes. See Note 20, Regulatory Environment, for more information.

Operating Income

Operating income at the ~~natural~~Wisconsin ~~gas utility~~ segment decreased $19.76 million. This decrease was driven by the $4629.69 million decrease in electric and gas margins discussed above, partially offset by a $4420.93 million decrease in operating expenses.

The decrease in operating expenses was primarily due to:

• A $2420.89 million ~~net~~ decrease in ~~energy~~maintenance ~~efficiency~~expense, ~~program~~primarily ~~expenses~~due atto ~~our~~planned ~~natural~~major ~~gas~~outages ~~utilities.~~at ~~For~~ the ~~majority~~Pulliam of8 ~~this~~plant ~~decrease~~and Weston 4 plant in ~~expenses~~2014, ~~margins~~as ~~decreased~~well byas anlower ~~equal~~maintenance ~~amount,~~at ~~resulting~~the inFox noEnergy ~~impact~~Center onand ~~earnings~~our jointly-owned plants in 2015.

• A $9.3.6 million decrease in ~~bad~~asset ~~debt~~usage ~~expense,~~charges ~~driven~~from ~~by lower natural gas costs in 2015 and a decrease in sales volumes~~WBS. ~~The majority of the decrease in bad debt expense was related to PGL and NSG and had no impact on earnings since it was offset by lower rates through a rider mechanism, resulting in lower margins.~~

• A $6.0 million net decrease driven by lower amortization of regulatory assets at certain of our natural gas utilities related to environmental cleanup costs for manufactured gas plant sites. This net decrease in expenses was more than offset by a related decrease in margins.

• A $4.5 million decrease in natural gas distribution costs, primarily at PGL. The decrease in costs at PGL was driven by reduced repair and maintenance activity.

These decreases were partially offset by:

• A $43.26 million increase in ~~depreciation~~electric ~~and~~transmission ~~amortization expense~~expenses. ~~This increase was driven by continued investment in property and equipment, primarily the AMRP at PGL.~~


•	A $2.7 million increase in depreciation and amortization expense, mainly due to the installation of scrubbers at the Columbia plant in April 2014.

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~~Electric~~Illinois ~~Utility~~ Segment Operations

In August 2014, we sold all of the stock of UPPCO to Balfour Beatty Infrastructure Partners LP. See Note 4, Dispositions, for more information.



	Three Months Ended June 30						Change in 2015 Over 2014		Six Months Ended June 30						Change in 2015 Over 2014
(Millions, except degree days)	2015			2014			Change in 2015 Over 2014		2015			2014			Change in 2015 Over 2014
Revenues	$	218.6		$	351.0		(37.7	)%	$	750.2		$	1,127.8		(33.5	)%
Cost of sales	53.4			187.7			(71.6	)%	295.2			660.7			(55.3	)%
Margins	165.2			163.3			1.2	%	455.0			467.1			(2.6	)%

Operating and maintenance expense	111.8			132.3			(15.5	)%	236.3			298.7			(20.9	)%
Depreciation and amortization expense	30.8			28.4			8.5	%	62.5			56.4			10.8	%
Property and revenue taxes	4.6			3.1			48.4	%	9.2			7.4			24.3	%
Operating income (loss)	18.0			(0.5		)	N/A		147.0			104.6			40.5	%

Miscellaneous income (expense)	0.2			(0.5		)	N/A		0.9			(0.2		)	N/A
Interest expense	9.9			8.2			20.7	%	19.4			16.5			17.6	%
Other expense	(9.7		)	(8.7		)	11.5	%	(18.5		)	(16.7		)	10.8	%

Income (loss) before taxes	$	8.3		$	(9.2	)	N/A		$	128.5		$	87.9		46.2	%

Retail throughput in therms
Residential	116.6			141.8			(17.8	)%	629.3			748.7			(15.9	)%
Commercial and industrial	24.6			31.8			(22.6	)%	131.7			159.5			(17.4	)%
Total retail throughput in therms	141.2			173.6			(18.7	)%	761.0			908.2			(16.2	)%

Transport throughput in therms
Residential	35.9			34.0			5.6	%	169.2			154.2			9.7	%
Commercial and industrial	111.9			117.9			(5.1	)%	383.6			403.9			(5.0	)%
Total transport throughput in therms	147.8			151.9			(2.7	)%	552.8			558.1			(0.9	)%

Total throughput in therms	289.0			325.5			(11.2	)%	1,313.8			1,466.3			(10.4	)%

Weather *
Actual heating degree days	704			696			1.1	%	4,294			4,566			(6.0	)%
Normal heating degree days	703			718			(2.1	)%	3,878			3,811			1.8	%

	Three Months Ended March 31						Change in 2015 Over 2014
(Millions, except degree days)	2015			2014
Revenues	$	295.8		$	349.2		(15.3	)%
Fuel and purchased power costs	115.1			136.7			(15.8	)%
Margins	180.7			212.5			(15.0	)%
Operating and maintenance expense	91.7			116.0			(20.9	)%
Depreciation and amortization expense	25.0			25.6			(2.3	)%
Taxes other than income taxes	10.9			12.8			(14.8	)%
Operating income	53.1			58.1			(8.6	)%
Miscellaneous income	2.8			3.5			(20.0	)%
Interest expense	10.9			11.7			(6.8	)%
Other expense	(8.1		)	(8.2		)	(1.2	)%
Income before taxes	$	45.0		$	49.9		(9.8	)%
Sales in kilowatt-hours
Residential	762.1			898.3			(15.2	)%
Commercial and industrial	1,969.1			2,077.9			(5.2	)%
Wholesale	635.5			571.2			11.3	%
Opportunity sales	302.0			113.6			165.8	%
Other	9.2			10.6			(13.2	)%
Total sales in kilowatt-hours	3,677.9			3,671.6			0.2	%
Weather
WPS:
Actual heating degree days	3,946			4,515			(12.6	)%
Normal heating degree days	3,662			3,646			0.4	%


*	Normal heating degree days are based on a 12-year average of monthly total heating degree days at Chicago's O'Hare Airport.

~~Electric~~Natural ~~utility~~gas margins are defined as ~~electric~~natural ~~utility~~gas operating revenues less ~~fuel and~~ purchased ~~power~~natural gas costs. Management believes that ~~electric~~natural ~~utility~~gas margins provide a more meaningful basis for evaluating ~~electric~~natural ~~utility~~gas operations than ~~electric~~natural ~~utility~~gas ~~operating~~ revenues., Tosince ~~the~~prudently ~~extent~~incurred ~~changes~~natural ingas ~~fuel~~commodity ~~and purchased power~~ costs are passed through to our customers, ~~the~~in ~~changes~~current ~~are~~rates. ~~offset~~There bywas ~~comparable~~an ~~changes~~approximate 66% and 46% decrease in ~~operating~~the ~~revenues~~average per-unit cost of natural gas sold during the three and six months ended June 30, 2015, respectively, which had no impact on margins.

~~First~~Second Quarter 2015 Compared with ~~First~~Second Quarter 2014

Margins

~~Electric~~Illinois ~~utility~~ segment margins ~~decreased~~increased $311.89 million, driven by:

• An approximate $2217.0 million ~~decrease~~increase in margins ~~related~~due to ~~the~~rate ~~sale of UPPCO at the end of August 2014~~orders. See Note 419, ~~Dispositions~~Regulatory Environment, for more information.

•◦ AnThe ~~approximate~~rate $5increases ~~million~~at ~~decrease~~our inIllinois ~~margins~~utilities, ateffective ~~WPS~~January ~~related~~28, to2015, ~~sales~~and ~~volume~~updated ~~variances.~~effective ~~Margins~~February ~~from~~26, ~~residential~~2015, ~~customers~~had ~~decreased,~~an ~~driven~~approximate by$16.0 ~~the~~million ~~warmer~~positive ~~weather~~impact inon ~~2015~~margins.

•◦ AnIncreased ~~approximate~~revenues ~~$4 million decrease in margins~~ at ~~WPS~~PGL ~~related~~for toits ~~the~~Qualifying ~~PSCW~~Infrastructure ~~rate~~Plant ~~order,~~rider ~~effective~~had ~~January~~an 1,approximate ~~2015~~$1.0 ~~Although~~million ~~the~~positive ~~PSCW approved an electric rate increase, the majority of the increase related to higher costs of fuel for electric generation, which has no~~ impact on margins. ~~See Note 20, Regulatory Environment, for more information.~~

◦• ~~Margins~~This atincrease ~~WPS~~was ~~decreased~~partially ~~approximately~~offset by a $613.8 million asdecrease ain ~~result~~margins ofrelated ~~the~~to ~~PSCW~~certain ~~rate~~riders. ~~order~~This ~~and~~decrease ~~rate~~was ~~design~~offset by an equal decrease in operating expenses, resulting in no impact on earnings.

◦ ~~Margins~~Our atIllinois ~~WPS~~utilities ~~were~~recovered ~~negatively impacted by approximately~~ $15.9 million ~~due~~less tofrom ~~higher~~their ~~fuel~~customers ~~costs~~through ~~not~~their ~~included~~bad indebt ~~the~~rider ~~fuel~~mechanisms, ~~rule~~driven ~~recovery~~by ~~mechanism.~~lower ~~The~~natural ~~majority~~gas ofcosts ~~this~~in ~~was~~2015, ~~higher~~and ~~fly~~a ~~ash~~decrease ~~disposal costs~~ in ~~2015~~sales volumes.

◦ ~~These~~Our ~~decreases~~Illinois inutilities ~~margins~~recovered ~~were partially offset by an increase of approximately~~ $34.8 million ~~related~~less tofrom ~~fuel~~customers ~~and~~for ~~purchased~~energy ~~power~~efficiency ~~cost~~programs ~~over-collections at WPS~~ in 2015~~, compared with under-collections in 2014~~. ~~Under the fuel rule, WPS can only defer under or over-collections of certain fuel and purchased power costs that exceed a 2% price variance from the costs included in rates.~~

Table of Contents

◦

Our Illinois utilities recovered $3.1 million less from their customers for environmental cleanup costs at their former manufactured gas plant sites due to lower recovery rates driven by a decrease in remediation costs, net of insurance settlements received, and the impact of lower sales volumes. See Note 11, Commitments and Contingencies, for more information about the manufactured gas plant sites.

Operating Income

Operating income at the ~~electric~~Illinois ~~utility~~ segment ~~decreased~~increased $518.05 million. The ~~decrease~~increase was ~~primarily~~due ~~driven~~to bya ~~the~~ $3116.86 million decrease in ~~margins~~operating ~~discussed~~expenses ~~above,~~and ~~partially~~the ~~offset by a~~ $261.89 million ~~decrease~~increase in ~~operating~~margins ~~expenses~~discussed above.

The decrease in operating expenses was driven by:

• A $14.39 million decrease in ~~operating~~natural ~~expenses~~gas ~~related~~distribution tocosts ~~the sale of UPPCO~~ at ~~the~~PGL, ~~end~~driven ofby ~~August~~reduced ~~2014.~~repair ~~See~~and ~~Note~~maintenance ~~4, Dispositions, for more information~~activity.

• A $75.9 million decrease in ~~maintenance~~bad debt expense, atdriven ~~WPS,~~by ~~primarily~~lower ~~due~~natural togas acosts ~~planned~~in ~~major~~2015 ~~outage~~and ata ~~the~~decrease ~~Pulliam~~in ~~plant~~sales volumes. This decrease in ~~2014,~~bad asdebt ~~well~~expense ashad no impact on earnings since it was offset by lower ~~maintenance~~rates atthrough ~~our~~a ~~jointly-owned~~rider ~~plants~~mechanism, resulting in ~~2015~~lower margins.

• A $24.57 million decrease in ~~asset~~energy ~~usage~~efficiency ~~charges~~program ~~from~~expenses. ~~IBS~~For the majority of this decrease in expenses, margins decreased by an equal amount, resulting in no impact on earnings.

• A $13.61 million ~~net~~ decrease indriven ~~employee~~by ~~benefit~~lower amortization of regulatory assets related to environmental cleanup costs atfor ~~WPS,~~manufactured ~~driven~~gas byplant ~~amortization~~sites. This decrease in ~~2014~~expense ofwas offset by a ~~prior~~related ~~year~~decrease ~~deferral~~in ofmargins, ~~certain~~resulting ~~employee~~in ~~benefit~~no ~~costs~~impact on earnings.

These decreases were partially offset by: ~~a $1.5 million increase in depreciation and amortization expense at WPS, mainly due to the installation of scrubbers at the Columbia plant in April 2014.~~

	Three Months Ended March 31				Change in 2015 Over 2014
(Millions)	2015		2014
Earnings from equity method investment	$	17.0	$	22.5	(24.4	)%


•	Accrued expense of $5.0 million at PGL for future contributions into the "Share the Warmth" program requested by the ICC as a condition for the approval of the WEC Merger. These costs will not be recovered from ratepayers.

~~First~~• ~~Quarter~~A ~~2015~~$2.4 ~~Compared~~million ~~with~~increase ~~First~~in ~~Quarter~~depreciation ~~2014~~and amortization expense. This increase was driven by continued investment in property and equipment, primarily the AMRP at PGL.

~~Earnings~~• ~~from~~A ~~our approximate 34% ownership interest in ATC decreased~~ $52.54 million. ~~ATC's~~net ~~2015~~increase ~~earnings~~in ~~included~~employee abenefit ~~reserve~~costs ~~for~~partially andriven ~~anticipated~~by ~~refund~~higher topension ~~customers~~and ~~related~~postretirement tocosts aas ~~complaint~~well ~~filed~~as ~~with~~higher ~~the~~employee ~~FERC~~medical ~~requesting a lower return on equity for certain transmission owners~~costs. ~~The reserve included an adjustment of $4.8 million related to prior years due to a revision to the estimated refund.~~

~~Holding~~• ~~Company~~A $1.5 million increase in property and ~~Other~~revenue ~~Segment~~taxes, ~~Operations~~driven by the Illinois invested capital tax. This tax is based on an entity's equity and long-term debt balances.

	Three Months Ended March 31						Change in 2015 Over 2014
(Millions)	2015			2014
Operating loss	$	(6.2	)	$	(4.8	)	29.2	%
Other expense	(9.4		)	(11.4		)	(17.5	)%
Loss before taxes	$	(15.6	)	$	(16.2	)	(3.7	)%

Six Months 2015 Compared with Six Months 2014

~~First Quarter 2015 Compared with First Quarter 2014~~ Margins

Illinois segment margins decreased $12.1 million, driven by:


•	A $47.3 million decrease in margins related to certain riders. This decrease was offset by an equal decrease in operating expenses, resulting in no impact on earnings.


◦	Our Illinois utilities recovered $23.7 million less from customers for energy efficiency programs in 2015.


◦	Our Illinois utilities recovered $14.3 million less from their customers through their bad debt rider mechanisms, driven by lower natural gas costs in 2015, and a decrease in sales volumes.

◦

Our Illinois utilities recovered $9.3 million less from their customers for environmental cleanup costs at their former manufactured gas plant sites due to lower recovery rates driven by a decrease in remediation costs, net of insurance settlements received, and the impact of lower sales volumes. See Note 11, Commitments and Contingencies, for more information about the manufactured gas plant sites.


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