10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period EndedJune 30, 2016

Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	IRS Employer Identification No.
001-09057	WEC ENERGY GROUP, INC.	39-1391525
	(A Wisconsin Corporation)
	231 West Michigan Street
	P.O. Box 1331
	Milwaukee, WI 53201
	(414) 221-2345

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

Yes [X]    No [  ]

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

Yes [X]    No [  ]

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

Large accelerated filer [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, $.01 Par Value,

315,619,968 shares outstanding at

June 30, 2016

WEC ENERGY GROUP, INC.

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended June 30, 2016

TABLE OF CONTENTS

				Page
	CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION			1
PART I.	FINANCIAL INFORMATION			3
ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)			3
	Condensed Consolidated Income Statements			3
	Condensed Consolidated Statements of Comprehensive Income			4
	Condensed Consolidated Balance Sheets			5
	Condensed Consolidated Statements of Cash Flows			6
	Notes to Condensed Consolidated Financial Statements			7
			Page
	Note 1	General Information	7
	Note 2	Acquisition	7
	Note 3	Dispositions	9
	Note 4	Common Equity	10
	Note 5	Short-Term Debt and Lines of Credit	10
	Note 6	Long-Term Debt	11
	Note 7	Materials, Supplies, and Inventories	11
	Note 8	Fair Value Measurements	11
	Note 9	Derivative Instruments	13
	Note 10	Guarantees	15
	Note 11	Employee Benefits	15
	Note 12	Goodwill	16
	Note 13	Investment in American Transmission Company	16
	Note 14	Segment Information	17
	Note 15	Variable Interest Entities	19
	Note 16	Commitments and Contingencies	20
	Note 17	Supplemental Cash Flow Information	25
	Note 18	Regulatory Environment	25
	Note 19	New Accounting Pronouncements	27
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			28
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			47
ITEM 4.	CONTROLS AND PROCEDURES			48
PART II.	OTHER INFORMATION			49
ITEM 1.	LEGAL PROCEEDINGS			49
ITEM 1A.	RISK FACTORS			49
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			49
ITEM 6.	EXHIBITS			50
SIGNATURE				51

06/30/2016 Form 10-Q i WEC Energy Group, Inc.

GLOSSARY OF TERMS AND ABBREVIATIONS

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

Subsidiaries and Affiliates
ATC	American Transmission Company LLC
Integrys	Integrys Holding, Inc. (previously known as Integrys Energy Group, Inc.)
ITF	Integrys Transportation Fuels, LLC
MERC	Minnesota Energy Resources Corporation
MGU	Michigan Gas Utilities Corporation
NSG	North Shore Gas Company
PDL	WPS Power Development, LLC
PGL	The Peoples Gas Light and Coke Company
WBS	WEC Business Services LLC
WE	Wisconsin Electric Power Company
We Power	W.E. Power, LLC
WG	Wisconsin Gas LLC
Wisvest	Wisvest LLC
WPS	Wisconsin Public Service Corporation
Federal and State Regulatory Agencies
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
ICC	Illinois Commerce Commission
MDEQ	Michigan Department of Environmental Quality
MPSC	Michigan Public Service Commission
MPUC	Minnesota Public Utilities Commission
PSCW	Public Service Commission of Wisconsin
SEC	United States Securities and Exchange Commission
WDNR	Wisconsin Department of Natural Resources
Accounting Terms
AFUDC	Allowance for Funds Used During Construction
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
FASB	Financial Accounting Standards Board
GAAP	United States Generally Accepted Accounting Principles
LIFO	Last-In, First-Out
OPEB	Other Postretirement Employee Benefits
Environmental Terms
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CSAPR	Cross-State Air Pollution Rule
GHG	Greenhouse Gas
MATS	Mercury and Air Toxics Standards
NAAQS	National Ambient Air Quality Standards
NOV	Notice of Violation
NOx	Nitrogen Oxide
SO2	Sulfur Dioxide
Measurements
Btu	British Thermal Units
Dth	Dekatherm (One Dth equals one million Btu)
MW	Megawatt (One MW equals one million Watts)
MWh	Megawatt-hour

06/30/2016 Form 10-Q ii WEC Energy Group, Inc.

Other Terms and Abbreviations
6.11% Junior Notes	Integrys's 2006 6.11% Junior Subordinated Notes Due 2066
ALJ	Administrative Law Judge
AMRP	Accelerated Natural Gas Main Replacement Program
CNG	Compressed Natural Gas
D.C. Circuit Court of Appeals	United States Court of Appeals for the District of Columbia Circuit
Exchange Act	Securities Exchange Act of 1934, as amended
FTRs	Financial Transmission Rights
MCPP	Milwaukee County Power Plant
MISO	Midcontinent Independent System Operator, Inc.
MISO Energy Markets	MISO Energy and Operating Reserves Markets
N/A	Not Applicable
PIPP	Presque Isle Power Plant
ROE	Return on Equity
SSR	System Support Resource
Supreme Court	United States Supreme Court
VAPP	Valley Power Plant

06/30/2016 Form 10-Q iii WEC Energy Group, Inc.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of capital projects, sales and customer growth, rate actions and related filings with regulatory authorities, environmental and other regulations and associated compliance costs, legal proceedings, dividend payout ratios, effective tax rate, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, liquidity and capital resources, and other matters.

Forward-looking statements are subject to a number of risks and uncertainties that could cause our actual results to differ materially from those expressed or implied in the statements. These risks and uncertainties include those described in risk factors as set forth in this report and our Annual Report on Form 10-K for the year ended December 31, 2015, and those identified below:

• Factors affecting utility operations such as catastrophic weather-related damage, environmental incidents, unplanned facility outages and repairs and maintenance, and electric transmission or natural gas pipeline system constraints;

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

• The timing, resolution, and impact of rate cases and negotiations, including recovery of deferred and current costs and adjustments to the ROE at any of our utilities and/or ATC, and other regulatory decisions impacting our regulated operations;

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

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

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

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

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

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

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

• Restrictions imposed by various financing arrangements and regulatory requirements on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans or advances;

06/30/2016 Form 10-Q 1 WEC Energy Group, Inc.

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

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

• The direct or indirect effect on our business resulting from terrorist incidents, the threat of terrorist incidents, and cyber intrusion, including the failure to maintain the security of personally identifiable information, the associated costs to protect our assets and personal information, and the costs to notify affected persons to mitigate their information security concerns;

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

• The investment performance of our employee benefit plan assets, as well as unanticipated changes in related actuarial assumptions, which could impact future funding requirements;

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

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

• The terms and conditions of the governmental and regulatory approvals of the acquisition of Integrys that could reduce anticipated benefits and our ability to successfully integrate the operations of the combined company;

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

• Potential business strategies to acquire and dispose of assets or businesses, which cannot be assured to be completed timely or within budgets, and legislative or regulatory restrictions or caps on non-utility acquisitions, investments, or projects, including the state of Wisconsin's public utility holding company law;

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

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

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

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

06/30/2016 Form 10-Q 2 WEC Energy Group, Inc.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited)	Three Months Ended						Six Months Ended
	June 30						June 30
(in millions, except per share amounts)	2016			2015			2016			2015
Operating revenues	$	1,602.0		$	991.2		$	3,796.8		$	2,379.1
Operating expenses
Cost of sales	508.3			353.0			1,347.2			966.9
Other operation and maintenance	522.0			337.0			1,053.5			617.7
Depreciation and amortization	190.0			103.5			377.9			206.1
Property and revenue taxes	49.6			31.9			96.8			63.8
Total operating expenses	1,269.9			825.4			2,875.4			1,854.5
Operating income	332.1			165.8			921.4			524.6
Equity in earnings of transmission affiliate	30.9			14.3			69.4			30.4
Other income, net	32.4			26.1			65.1			29.1
Interest expense	100.1			61.8			201.0			121.2
Other expense	(36.8		)	(21.4		)	(66.5		)	(61.7		)
Income before income taxes	295.3			144.4			854.9			462.9
Income tax expense	113.6			63.2			326.7			185.6
Net income	181.7			81.2			528.2			277.3
Preferred stock dividends of subsidiary	0.3			0.3			0.6			0.6
Net income attributed to common shareholders	$	181.4		$	80.9		$	527.6		$	276.7
Earnings per share
Basic	$	0.57		$	0.36		$	1.67		$	1.22
Diluted	$	0.57		$	0.35		$	1.66		$	1.21
Weighted average common shares outstanding
Basic	315.6			227.5			315.6			226.5
Diluted	317.0			229.1			317.0			228.2
Dividends per share of common stock	$	0.4950		$	0.8629		$	0.9900		$	1.2854

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

06/30/2016 Form 10-Q 3 WEC Energy Group, Inc.

WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)	Three Months Ended						Six Months Ended
	June 30						June 30
(in millions)	2016			2015			2016			2015
Net income	$	181.7		$	81.2		$	528.2		$	277.3
Other comprehensive income (loss), net of tax
Derivatives accounted for as cash flow hedges
Gains on settlement, net of tax of $7.6	—			11.4			—			11.4
Reclassification of gains to net income, net of tax	(0.3		)	(0.1		)	(0.6		)	(0.1		)
Cash flow hedges, net	(0.3		)	11.3			(0.6		)	11.3
Defined benefit plans
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax	0.4			—			0.4			—
Other comprehensive income (loss), net of tax	0.1			11.3			(0.2		)	11.3
Comprehensive income	181.8			92.5			528.0			288.6
Preferred stock dividends of subsidiary	0.3			0.3			0.6			0.6
Comprehensive income attributed to common shareholders	$	181.5		$	92.2		$	527.4		$	288.0

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

06/30/2016 Form 10-Q 4 WEC Energy Group, Inc.

WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts)	June 30, 2016			December 31, 2015
Assets
Property, plant, and equipment
In service	$	26,690.7		$	26,249.5
Accumulated depreciation	(8,049.1		)	(7,919.1		)
	18,641.6			18,330.4
Construction work in progress	723.7			822.9
Leased facilities, net	33.6			36.4
Net property, plant, and equipment	19,398.9			19,189.7
Investments
Equity investment in transmission affiliate	1,425.0			1,380.9
Other	88.0			85.8
Total investments	1,513.0			1,466.7
Current assets
Cash and cash equivalents	32.1			49.8
Accounts receivable and unbilled revenues, net of reserves of $109.4 and $113.3, respectively	914.9			1,028.6
Materials, supplies, and inventories	494.5			687.0
Assets held for sale	—			96.8
Prepayments	235.3			285.8
Other	89.1			58.8
Total current assets	1,765.9			2,206.8
Deferred charges and other assets
Regulatory assets	3,031.4			3,064.6
Goodwill	3,046.2			3,023.5
Other	419.9			403.9
Total deferred charges and other assets	6,497.5			6,492.0
Total assets	$	29,175.3		$	29,355.2
Capitalization and liabilities
Capitalization
Common stock – $.01 par value; 325,000,000 shares authorized; 315,619,968 and 315,683,496 shares outstanding, respectively	$	3.2		$	3.2
Additional paid in capital	4,310.9			4,347.2
Retained earnings	4,515.0			4,299.8
Accumulated other comprehensive income	4.4			4.6
Preferred stock of subsidiary	30.4			30.4
Long-term debt	8,902.1			9,124.1
Total capitalization	17,766.0			17,809.3
Current liabilities
Current portion of long-term debt	95.8			157.7
Short-term debt	927.8			1,095.0
Accounts payable	620.5			815.4
Accrued payroll and benefits	134.5			169.7
Other	358.5			471.2
Total current liabilities	2,137.1			2,709.0
Deferred credits and other liabilities
Regulatory liabilities	1,469.7			1,392.2
Deferred income taxes	4,938.3			4,622.3
Deferred revenue, net	572.3			579.4
Pension and OPEB obligations	541.9			543.1
Environmental remediation	617.9			628.2
Other	1,132.1			1,071.7
Total deferred credits and other liabilities	9,272.2			8,836.9
Commitments and contingencies (Note 16)
Total capitalization and liabilities	$	29,175.3		$	29,355.2

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

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WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Six Months Ended
	June 30
(in millions)	2016			2015
Operating Activities
Net income	$	528.2		$	277.3
Reconciliation to cash provided by operating activities
Depreciation and amortization	386.0			215.1
Deferred income taxes and investment tax credits, net	307.1			121.7
Contributions and payments related to pension and OPEB plans	(19.5		)	(106.1		)
Equity income in transmission affiliate, net of distributions	(22.7		)	(9.2		)
Change in –
Accounts receivable and unbilled revenues	130.1			134.5
Materials, supplies, and inventories	193.5			72.2
Other current assets	66.7			16.7
Accounts payable	(112.4		)	27.4
Accrued taxes, net	(51.3		)	10.5
Other current liabilities	(87.7		)	(1.2		)
Other, net	(93.9		)	(42.4		)
Net cash provided by operating activities	1,224.1			716.5
Investing Activities
Capital expenditures	(618.7		)	(368.0		)
Business acquisition, net of cash acquired of $156.3	—			(1,329.4		)
Investment in transmission affiliate	(12.1		)	(2.6		)
Proceeds from the sale of assets and businesses	161.0			21.2
Withdrawal of restricted cash from Rabbi trust for qualifying payments	22.5			—
Other, net	(1.8		)	(0.4		)
Net cash used in investing activities	(449.1		)	(1,679.2		)
Financing Activities
Exercise of stock options	35.0			12.2
Purchase of common stock	(94.2		)	(32.0		)
Dividends paid on common stock	(312.4		)	(190.5		)
Issuance of long-term debt	—			1,450.0
Retirement of long-term debt	(241.8		)	(11.6		)
Change in short-term debt	(167.2		)	(105.7		)
Other, net	(12.1		)	(7.2		)
Net cash (used in) provided by financing activities	(792.7		)	1,115.2
Net change in cash and cash equivalents	(17.7		)	152.5
Cash and cash equivalents at beginning of period	49.8			61.9
Cash and cash equivalents at end of period	$	32.1		$	214.4

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

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WEC ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

June 30, 2016

NOTE 1—GENERAL INFORMATION

On June 29, 2015, Wisconsin Energy Corporation acquired Integrys and changed its name to WEC Energy Group, Inc. WEC Energy Group serves approximately 1.6 million electric customers and 2.8 million natural gas customers, and it owns approximately 60% of ATC. See Note 2, Acquisition, for more information.

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

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2015. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and six months ended June 30, 2016, are not necessarily indicative of expected results for 2016 due to seasonal variations and other factors.

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

Reclassifications

On the income statements for the three and six months ended June 30, 2015, we reclassified $2.2 million and $4.7 million, respectively, from treasury grant to depreciation and amortization. We also reclassified an insignificant amount from interest expense to preferred stock dividends of subsidiary on the income statements for the three and six months ended June 30, 2015. These reclassifications were made to be consistent with the current period presentation.

On the statement of cash flows for the six months ended June 30, 2015, we reclassified $1.7 million from depreciation and amortization to other operating activities. In addition, we reclassified $6.1 million of non-qualified pension and OPEB contributions from other operating activities to contributions and payments related to pension and OPEB plans. We also reclassified $11.5 million from other investing activities to capital expenditures on the statement of cash flows for the six months ended June 30, 2015. An insignificant amount of preferred stock dividends of subsidiary was also reclassified from other financing activities to net income. These reclassifications were made to be consistent with the current period presentation.

During the third quarter of 2015, following the acquisition of Integrys, we reorganized our business segments. All prior period amounts impacted by this change were reclassified to conform to the new presentation. See Note 14, Segment Information, for more information on our business segments.

NOTE 2—ACQUISITION

On June 29, 2015, Wisconsin Energy Corporation acquired 100% of the outstanding common shares of Integrys and changed its name to WEC Energy Group, Inc.

Allocation of Purchase Price

The Integrys assets acquired and liabilities assumed were measured at estimated fair value in accordance with the accounting guidance under the Business Combinations Topic in the FASB ASC. Substantially all of Integrys's operations are subject to the rate-setting authority of federal and state regulatory commissions. These operations are accounted for following the accounting guidance under the Regulated Operations Topic of the FASB ASC. The underlying assets and liabilities of ATC are also regulated by the FERC. The fair values of Integrys's assets and liabilities subject to rate-setting provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair values of these assets and liabilities equal their

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carrying values. Accordingly, neither the assets and liabilities acquired, nor the pro forma financial information, reflect any adjustments related to these amounts.

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. The goodwill reflects the value paid for the increased scale and efficiencies as a result of the combination. The goodwill recognized is not deductible for income tax purposes, and as such, no deferred taxes have been recorded related to goodwill. See Note 12, Goodwill, for the allocation of goodwill to our reportable segments.

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. In 2016, adjustments were made to the estimated fair values of the assets acquired and liabilities assumed, primarily in connection with the sale of ITF and reserves recorded for likely settlements of certain legal and regulatory matters.

(in millions)
Current assets	$	1,060.1
Net property, plant, and equipment	7,107.4
Investments *	1,072.0
Goodwill	2,604.3
Deferred charges and other assets, excluding goodwill	1,758.5
Current liabilities, including current maturities of long-term debt	(1,320.7		)
Deferred credits and other liabilities	(3,703.8		)
Long-term debt	(2,943.6		)
Preferred stock of subsidiary	(51.1		)
Total purchase price	$	5,583.1

* Includes equity method goodwill related to Integrys's investment in ATC.

Pro Forma Information

The following unaudited pro forma financial information reflects the consolidated results and amortization of purchase price adjustments as if the acquisition had taken place on January 1, 2014. The unaudited pro forma financial information is presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or our future consolidated results.

The pro forma financial information does not reflect any potential cost savings from operating efficiencies resulting from the acquisition and does not include certain acquisition-related costs.

(in millions, except per share amounts)	Three Months Ended June 30, 2015		Six Months Ended June 30, 2015
Unaudited Pro Forma Financial Information
Operating revenues	$	1,629.2	$	4,180.1
Net income	$	159.1	$	488.7
Earnings per share (Basic)	$	0.50	$	1.55
Earnings per share (Diluted)	$	0.50	$	1.54

Impact of Acquisition

In connection with the acquisition, WEC Energy Group and its subsidiaries recorded pre-tax acquisition costs of $65.0 million and $73.7 million during the three and six months ended June 30, 2015, respectively. These costs consisted of employee-related expenses, professional fees, and other miscellaneous costs. They were recorded in other operation and maintenance on our income statements. Acquisition costs incurred during the three and six months ended June 30, 2016 were not significant.

Our revenues for the three and six months ended June 30, 2015 did not include any revenues attributable to Integrys. Included in our net income for the three and six months ended June 30, 2015, is a net loss attributable to Integrys of $26.6 million related to acquisition costs that were incurred post-acquisition.

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NOTE 3—DISPOSITIONS

Wisconsin Segment – Sale of Milwaukee County Power Plant

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

Corporate and Other Segment

Sale of Certain Assets of Wisvest

In April 2016, as part of the MCPP sale transaction, we sold the chilled water generation and distribution assets of Wisvest, which are used to provide chilled water services to the Milwaukee Regional Medical Center hospitals and other campus buildings. During the second quarter of 2016, we recorded a pre-tax gain on the sale of $19.6 million ($11.8 million after tax), which is included in other income, net on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations associated with these assets remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.

Sale of Integrys Transportation Fuels

Through a series of transactions in the fourth quarter of 2015 and the first quarter of 2016, we sold ITF, a provider of CNG fueling services and a single-source provider of CNG fueling facility design, construction, operation, and maintenance. There was no gain or loss recorded on the sales, as ITF's assets and liabilities were adjusted to fair value through purchase accounting. The sale of ITF met the criteria to qualify as held for sale at December 31, 2015, but did not meet the requirements to qualify as a discontinued operation. The results of operations of ITF remained in continuing operations through the sale date as the sale of ITF did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results. The pre-tax profit or loss of this component was not material through the sale date in 2016.

The following table shows the carrying values of the major classes of assets and liabilities included as held for sale on our balance sheet at December 31:

(in millions)	2015
Property, plant, and equipment	$	37.2
Accounts receivable and unbilled revenues	34.9
Materials, supplies, and inventories	18.4
Other current assets	2.6
Other long-term assets	3.7
Total assets	$	96.8
Accounts payable	$	12.9
Accrued payroll and benefits	2.4
Other current liabilities	4.5
Pension and OPEB obligations	1.2
Other long-term liabilities	0.6
Total liabilities *	$	21.6

* Included in other current liabilities on our balance sheet.

06/30/2016 Form 10-Q 9 WEC Energy Group, Inc.

NOTE 4—COMMON EQUITY

Stock-Based Compensation Plans

During the six months endedJune 30, 2016, the Compensation Committee of our Board of Directors awarded the following stock-based compensation awards to our directors, officers, and certain other key employees:

Award Type	Number of Awards
Stock options (1)	794,764
Restricted shares (2)	146,941
Performance units	297,397

⁽¹⁾  Stock options awarded had a weighted-average exercise price of $52.15 and a weighted-average grant date fair value of $5.14 per option.

⁽²⁾  Restricted shares awarded had a weighted-average grant date fair value of $53.69 per share.

Restrictions

Our ability as a holding company to pay common stock dividends primarily depends on the availability of funds received from our utility subsidiaries and our non-utility subsidiary, We Power. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans, or advances. All of our utility subsidiaries, with the exception of MGU, are prohibited from loaning funds to us, either directly or indirectly. See Note 11, Common Equity, in our 2015 Annual Report on Form 10-K for additional information on these and other restrictions.

We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.

NOTE 5—SHORT-TERM DEBT AND LINES OF CREDIT

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

(in millions, except percentages)	June 30, 2016			December 31, 2015
Commercial paper
Amount outstanding	$	927.8		$	1,095.0
Weighted-average interest rate on amounts outstanding	0.66		%	0.68		%

Our average amount of commercial paper borrowings based on daily outstanding balances during the six months ended June 30, 2016, was $903.5 million with a weighted-average interest rate during the period of 0.61%.

The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing programs, including remaining available capacity under these facilities:

(in millions)	Maturity	June 30, 2016
WEC Energy Group	December 2020	$	1,050.0
WE	December 2020	500.0
WPS	December 2020	250.0
WG	December 2020	350.0
PGL	December 2020	350.0
Total short-term credit capacity		$	2,500.0
Less:
Letters of credit issued inside credit facilities		$	26.0
Commercial paper outstanding		927.8
Available capacity under existing agreements		$	1,546.2

06/30/2016 Form 10-Q 10 WEC Energy Group, Inc.

In May 2016, WPS received approval from the PSCW to extend the maturity date of its revolving credit facility from December 2016 to December 2020.

NOTE 6—LONG-TERM DEBT

In June 2016, PGL issued commercial paper to redeem at par, its $50.0 million of 4.30% Series RR First and Refunding Mortgage Bonds that were due in 2035.

In June 2016, Integrys's $50.0 million of 8.00% unsecured senior notes matured and were repaid with the proceeds from commercial paper issued by WEC Energy Group.

In February 2016, Integrys repurchased and retired $154.9 million aggregate principal amount of its 6.11% Junior Notes for a purchase price of $128.6 million, plus accrued and unpaid interest, through a modified “dutch auction” tender offer. The gain associated with this repurchase is included in other income, net on our income statement. Effective December 1, 2016, the remaining $114.9 million aggregate principal amount of the 6.11% Junior Notes will bear interest at the three-month London Interbank Offered Rate plus 2.12% and will reset quarterly. In connection with this transaction, Integrys issued approximately $66.4 million of additional common stock to WEC Energy Group in satisfaction of its obligations under a replacement capital covenant relating to the 6.11% Junior Notes.

NOTE 7—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:

(in millions)	June 30, 2016		December 31, 2015
Materials and supplies	$	217.3	$	219.2
Fossil fuel	156.6		183.7
Natural gas in storage	120.6		284.1
Total	$	494.5	$	687.0

PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the 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 June 30, 2016, we had a temporary LIFO liquidation debit of $28.8 million recorded within other current assets on our balance sheet. Due to seasonality requirements, PGL and NSG expect these interim reductions in LIFO layers to be replenished by year end.

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

NOTE 8—FAIR VALUE MEASUREMENTS

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

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

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

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

06/30/2016 Form 10-Q 11 WEC Energy Group, Inc.

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

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

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

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

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

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

	June 30, 2016
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	10.1	$	12.4	$	—	$	22.5
FTRs	—		—		13.4		13.4
Petroleum products contracts	0.4		—		—		0.4
Coal contracts	—		1.3		—		1.3
Total derivative assets	$	10.5	$	13.7	$	13.4	$	37.6
Investments held in rabbi trust	$	42.8	$	—	$	—	$	42.8
Derivative liabilities
Natural gas contracts	$	0.5	$	5.4	$	—	$	5.9
Petroleum products contracts	1.4		—		—		1.4
Coal contracts	—		12.6		—		12.6
Total derivative liabilities	$	1.9	$	18.0	$	—	$	19.9

	December 31, 2015
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	1.6	$	1.5	$	—	$	3.1
FTRs	—		—		3.6		3.6
Petroleum products contracts	1.2		—		—		1.2
Coal contracts	—		2.0		—		2.0
Total derivative assets	$	2.8	$	3.5	$	3.6	$	9.9
Investments held in rabbi trust	$	39.8	$	—	$	—	$	39.8
Derivative liabilities
Natural gas contracts	$	16.5	$	25.3	$	—	$	41.8
Petroleum products contracts	4.9		—		—		4.9
Coal contracts	—		12.3		—		12.3
Total derivative liabilities	$	21.4	$	37.6	$	—	$	59.0

06/30/2016 Form 10-Q 12 WEC Energy Group, Inc.

The derivative assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy Markets.

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

	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2016			2015			2016			2015
Balance at the beginning of the period	$	1.1		$	3.3		$	3.6		$	7.0
Realized and unrealized losses	—			—			(0.2		)	—
Purchases	15.2			3.9			15.2			3.9
Sales	(0.1		)	—			(0.2		)	—
Settlements	(2.8		)	(3.6		)	(5.0		)	(7.3		)
Acquisition of Integrys	—			(1.3		)	—			(1.3		)
Balance at the end of the period	$	13.4		$	2.3		$	13.4		$	2.3

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

Fair Value of Financial Instruments

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

	June 30, 2016				December 31, 2015
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock	$	30.4	$	29.7	$	30.4	$	27.3
Long-term debt, including current portion *	$	8,952.6	$	9,984.8	$	9,221.9	$	9,681.0

* The carrying amount of long-term debt excludes capital lease obligations of $45.3 million and $59.9 million at June 30, 2016, and

December 31, 2015, respectively.

Due to the short-term nature of cash and cash equivalents, net accounts receivable, accounts payable, and short-term borrowings, the carrying amount of each such item approximates fair value. The fair value of our preferred stock is estimated based on the quoted market value for the same issue, or by using a perpetual dividend discount model. The fair value of our long-term debt is estimated based upon the quoted market value for the same issue, similar issues, or upon the quoted market prices of United States Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows. The fair values of our long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.

NOTE 9—DERIVATIVE INSTRUMENTS

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

We record derivative instruments on our balance sheets as an asset or liability measured at fair value unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities.

06/30/2016 Form 10-Q 13 WEC Energy Group, Inc.

The following table shows our derivative assets and derivative liabilities:

	June 30, 2016				December 31, 2015
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	19.3	$	5.9	$	2.6	$	38.5
Petroleum products contracts	0.3		1.4		0.9		3.8
FTRs	13.4		—		3.6		—
Coal contracts	1.3		9.8		1.7		6.7
Total other current *	$	34.3	$	17.1	$	8.8	$	49.0
Other long-term
Natural gas contracts	$	3.2	$	—	$	0.5	$	3.3
Petroleum products contracts	0.1		—		0.3		1.1
Coal contracts	—		2.8		0.3		5.6
Total other long-term *	$	3.3	$	2.8	$	1.1	$	10.0
Total	$	37.6	$	19.9	$	9.9	$	59.0

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

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

	Three Months Ended June 30, 2016				Three Months Ended June 30, 2015
(in millions)	Volume	Gains (Losses)			Volume	Gains (Losses)
Natural gas contracts	32.7 Dth	$	(20.0	)	10.0 Dth	$	(5.9	)
Petroleum products contracts	3.6 gallons	(1.0		)	0.8 gallons	0.1
FTRs	7.4 MWh	1.6			5.9 MWh	0.8
Total		$	(19.4	)		$	(5.0	)
	Six Months Ended June 30, 2016				Six Months Ended June 30, 2015
(in millions)	Volume	Gains (Losses)			Volume	Gains (Losses)
Natural gas contracts	82.8 Dth	$	(53.5	)	23.3 Dth	$	(13.0	)
Petroleum products contracts	6.6 gallons	(2.1		)	1.7 gallons	—
FTRs	15.0 MWh	4.6			12.1 MWh	2.9
Total		$	(51.0	)		$	(10.1	)

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At June 30, 2016, and December 31, 2015, we had posted cash collateral of $22.4 million and $42.3 million, respectively, in our margin accounts. These amounts were recorded on the balance sheets in other current assets.

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

	June 30, 2016						December 31, 2015
(in millions)	Derivative Assets			Derivative Liabilities			Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	37.6		$	19.9		$	9.9		$	59.0
Gross amount not offset on the balance sheet *	(4.2		)	(4.2		)	(3.0		)	(22.5		)
Net amount	$	33.4		$	15.7		$	6.9		$	36.5

* Includes cash collateral posted of $19.5 million as of December 31, 2015. There was no cash collateral included at June 30, 2016.

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 was $3.1 million and $23.8 million at June 30, 2016, and December 31, 2015,

06/30/2016 Form 10-Q 14 WEC Energy Group, Inc.

respectively. At June 30, 2016, and December 31, 2015, 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 derivative instruments in a net liability position had been triggered at June 30, 2016, and December 31, 2015, we would have been required to post collateral of $1.3 million and $18.0 million, respectively.

NOTE 10—GUARANTEES

The following table shows our outstanding guarantees:

	Total Amounts Committed at		Expiration
(in millions)	June 30, 2016		Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees
Guarantees supporting commodity transactions of subsidiaries (1)	$	147.1	$	68.1	$	5.0	$	74.0
Standby letters of credit (2)	36.4		36.0		0.2		0.2
Surety bonds (3)	11.2		11.2		—		—
Other guarantees (4)	38.5		0.7		6.8		31.0
Total guarantees	$	233.2	$	116.0	$	12.0	$	105.2

⁽¹⁾  Consists of (a) $5.0 million and $10.0 million to support the business operations of WBS and PDL, respectively; and (b) $99.3 million and $32.8 million related to natural gas supply at MERC and MGU, respectively. These amounts 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 are not reflected on our balance sheets.

⁽³⁾  Primarily for workers compensation self-insurance programs and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets.

⁽⁴⁾  Consists of (a) $19.1 million to support PDL's future payment obligations related to its distributed solar generation projects, of which $6.6 million is covered by a reciprocal guarantee from a third party that is not reflected on our balance sheets; (b) $10.0 million related to the sale of a nonregulated retail marketing business previously owned by Integrys, of which an insignificant liability was recorded; and (c) $9.4 million related to other indemnifications, of which a liability of $8.8 million related to workers compensation coverage was recorded.

NOTE 11—EMPLOYEE BENEFITS

The following tables show the components of net periodic pension and OPEB costs for our benefit plans. Our pension and OPEB costs for the three and six months ended June 30, 2016, include costs attributable to the Integrys pension and OPEB plans. The terms and conditions of the legacy company plans have not changed materially since the acquisition.

	Pension Costs
	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2016			2015			2016			2015
Service cost	$	10.7		$	3.9		$	22.0		$	7.8
Interest cost	33.0			15.1			66.2			30.3
Expected return on plan assets	(49.0		)	(25.6		)	(98.0		)	(51.4		)
Loss on plan settlement	14.1			—			14.1			—
Amortization of prior service cost	0.8			0.5			1.7			1.0
Amortization of net actuarial loss	20.2			11.4			40.7			23.0
Net periodic benefit cost	$	29.8		$	5.3		$	46.7		$	10.7

06/30/2016 Form 10-Q 15 WEC Energy Group, Inc.

	OPEB Costs
	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2016			2015			2016			2015
Service cost	$	6.4		$	2.1		$	13.1		$	4.7
Interest cost	9.3			3.9			18.5			8.1
Expected return on plan assets	(13.3		)	(5.9		)	(26.4		)	(11.8		)
Amortization of prior service credit	(2.4		)	(0.3		)	(4.7		)	(0.6		)
Amortization of net actuarial loss	1.9			0.5			4.2			1.0
Net periodic benefit cost	$	1.9		$	0.3		$	4.7		$	1.4

We did not make any contributions to our qualified pension plans during the first six months of 2016. During the six months ended June 30, 2016, we made payments of $17.0 million related to our non-qualified pension plans and $2.5 million to our OPEB plans. We expect to make payments of $6.0 million related to our pension plans and $15.2 million related to our OPEB plans during the remainder of 2016, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

NOTE 12—GOODWILL

Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. The following table shows changes to our goodwill balances by segment during the six months ended June 30, 2016:

(in millions)	Wisconsin				Illinois			Other States			Total
Goodwill balance as of January 1, 2016	$	2,109.5			$	731.2		$	182.8		$	3,023.5
Adjustment to Integrys purchase price allocation	(5.2		)		27.5			0.4			22.7
Goodwill balance as of June 30, 2016 (1)	$	2,104.3		(2)	$	758.7	(3)	$	183.2	(3)	$	3,046.2

⁽¹⁾  We had no accumulated impairment losses related to our goodwill as of June 30, 2016.

⁽²⁾  Of this amount, $1,662.4 million relates to the acquisition of Integrys.

⁽³⁾  Total amount relates to the acquisition of Integrys.

Due to the acquisition of Integrys, we changed the date of our annual goodwill impairment test from August 31 to July 1. As a result, we are in the process of performing the test for all of our reporting units that carried a goodwill balance as of July 1, 2016. We are not currently aware of any impairment indicators.

NOTE 13—INVESTMENT IN AMERICAN TRANSMISSION COMPANY

Due to the acquisition of Integrys on June 29, 2015, our ownership of ATC increased from 26.2% to approximately 60%. ATC is a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. The following table shows changes to our investment in ATC:

	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2016				2015		2016				2015
Balance at beginning of period	$	1,422.5			$	431.1	$	1,380.9		(1)	$	424.1
Add: Earnings from equity method investment	30.9				14.3		69.4				30.4
Add: Capital contributions	3.1				1.2		12.1				2.5
Add: Acquisition of Integrys's investment in ATC	(1.0		)	(2)	552.0		(1.0		)	(2)	552.0
Add: Adjustment to equity method goodwill	1.1				—		10.4				—
Less: Distributions received	31.6				10.8		46.7				21.2
Less: Other	—				—		0.1				—
Balance at end of period	$	1,425.0			$	987.8	$	1,425.0			$	987.8

⁽¹⁾  Equity method goodwill of $395.8 million from the acquisition of Integrys was recorded in the fourth quarter of 2015.

⁽²⁾  Amount reflects an adjustment to the allocation of the purchase price made in the second quarter of 2016.

06/30/2016 Form 10-Q 16 WEC Energy Group, Inc.

We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed to us by ATC. We are required to pay the cost of needed transmission infrastructure upgrades for new generation projects while the projects are under construction. ATC reimburses us for these costs when the new generation is placed in service.

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

	Three Months Ended June 30				Six Months Ended June 30
(in millions)	2016		2015		2016		2015
Charges to ATC for services and construction	$	4.3	$	2.5	$	8.4	$	5.0
Charges from ATC for network transmission services	91.1		59.6		182.1		119.2

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

(in millions)	June 30, 2016		December 31, 2015
Accounts receivable
Services provided to ATC	$	1.4	$	1.0
Accounts payable
Services received from ATC	30.3		28.3

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

	Three Months Ended June 30				Six Months Ended June 30
(in millions)	2016		2015		2016		2015
Income statement data
Revenues	$	154.3	$	165.1	$	318.5	$	317.5
Operating expenses	81.7		80.3		160.8		160.3
Other expense	23.7		24.2		47.7		48.6
Net income	$	48.9	$	60.6	$	110.0	$	108.6

(in millions)	June 30, 2016		December 31, 2015
Balance sheet data
Current assets	$	83.9	$	80.5
Noncurrent assets	4,104.6		3,948.3
Total assets	$	4,188.5	$	4,028.8
Current liabilities	$	382.5	$	330.3
Long-term debt	1,791.0		1,790.7
Other noncurrent liabilities	293.8		245.0
Shareholders' equity	1,721.2		1,662.8
Total liabilities and shareholders' equity	$	4,188.5	$	4,028.8

NOTE 14—SEGMENT INFORMATION

At June 30, 2016, we reported six segments, which are described below.

• The Wisconsin segment includes the electric and natural gas utility operations of WE, WG, and WPS, including WE's and WPS's electric and natural gas operations in the state of Michigan.

• The Illinois segment includes the natural gas utility and non-utility operations of PGL and NSG.

• The other states segment includes the natural gas utility and non-utility operations of MERC and MGU.

• The electric transmission segment includes our approximate 60% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions.

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• The We Power segment includes our nonregulated entity that owns and leases generating facilities to WE.

• The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the Peoples Energy, LLC holding company, Wispark LLC, Bostco LLC, Wisvest, Wisconsin Energy Capital Corporation, WBS, PDL, and ITF. The sale of ITF was completed in the first quarter of 2016. In the second quarter of 2016, we sold Wisvest's assets. See Note 3, Dispositions, for more information on these sales.

All of our operations are located within the United States. The following tables show summarized financial information concerning our reportable segments for the three and six months ended June 30, 2016 and 2015:

	Regulated Operations
(in millions)	Wisconsin		Illinois		Other States		Electric Transmission		Total Regulated Operations		We Power		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Three Months Ended
June 30, 2016
External revenues	$	1,304.5	$	222.8	$	64.0	$	—	$	1,591.3	$	6.3	$	4.4		$	—		$	1,602.0
Intersegment revenues	0.2		—		—		—		0.2		107.6		—			(107.8		)	—
Other operation and maintenance	487.8		116.2		29.4		—		633.4		2.7		(6.3		)	(107.8		)	522.0
Depreciation and amortization	122.7		33.1		5.2		—		161.0		17.0		12.0			—			190.0
Operating income (loss)	214.7		22.6		2.3		—		239.6		94.1		(1.6		)	—			332.1
Equity in earnings of transmission affiliate	—		—		—		30.9		30.9		—		—			—			30.9
Interest expense	44.4		9.8		2.1		—		56.3		15.6		30.2			(2.0		)	100.1

	Regulated Operations
(in millions)	Wisconsin		Illinois		Other States		Electric Transmission		Total Regulated Operations		We Power		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Three Months Ended
June 30, 2015
External revenues	$	978.5	$	—	$	—	$	—	$	978.5	$	9.6	$	3.1		$	—		$	991.2
Intersegment revenues	1.4		—		—		—		1.4		103.1		—			(104.5		)	—
Other operation and maintenance	368.3		—		—		—		368.3		2.7		70.1			(104.1		)	337.0
Depreciation and amortization	86.3		—		—		—		86.3		16.9		0.3			—			103.5
Operating income (loss)	140.4		—		—		—		140.4		93.2		(67.8		)	—			165.8
Equity in earnings of transmission affiliate	—		—		—		14.3		14.3		—		—			—			14.3
Interest expense	32.1		—		—		—		32.1		15.9		14.0			(0.2		)	61.8

06/30/2016 Form 10-Q 18 WEC Energy Group, Inc.

	Regulated Operations
(in millions)	Wisconsin		Illinois		Other States		Electric Transmission		Total Regulated Operations		We Power		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Six Months Ended
June 30, 2016
External revenues	$	2,884.3	$	671.3	$	212.4	$	—	$	3,768.0	$	12.5	$	16.3		$	—		$	3,796.8
Intersegment revenues	0.3		—		—		—		0.3		212.1		—			(212.4		)	—
Other operation and maintenance	979.1		234.1		59.4		—		1,272.6		3.1		(9.8		)	(212.4		)	1,053.5
Depreciation and amortization	245.6		65.9		10.3		—		321.8		34.0		22.1			—			377.9
Operating income (loss)	542.2		159.6		34.1		—		735.9		187.4		(1.9		)	—			921.4
Equity in earnings of transmission affiliate	—		—		—		69.4		69.4		—		—			—			69.4
Interest expense	88.9		19.5		4.6		—		113.0		31.2		61.5			(4.7		)	201.0

	Regulated Operations
(in millions)	Wisconsin		Illinois		Other States		Electric Transmission		Total Regulated Operations		We Power		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Six Months Ended
June 30, 2015
External revenues	$	2,355.0	$	—	$	—	$	—	$	2,355.0	$	20.7	$	3.4		$	—		$	2,379.1
Intersegment revenues	1.8		—		—		—		1.8		201.7		—			(203.5		)	—
Other operation and maintenance	737.4		—		—		—		737.4		3.1		80.2			(203.0		)	617.7
Depreciation and amortization	171.7		—		—		—		171.7		33.7		0.7			—			206.1
Operating income (loss)	416.9		—		—		—		416.9		185.7		(78.0		)	—			524.6
Equity in earnings of transmission affiliate	—		—		—		30.4		30.4		—		—			—			30.4
Interest expense	63.5		—		—		—		63.5		31.8		26.2			(0.3		)	121.2

NOTE 15—VARIABLE INTEREST ENTITIES

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

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

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

American Transmission Company

We own approximately 60% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. We have determined that ATC is a variable interest entity but that consolidation is not required since we are not ATC's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC's economic performance. We account for ATC as an equity method investment. See Note 13, Investment in American Transmission Company, for more information.

06/30/2016 Form 10-Q 19 WEC Energy Group, Inc.

The significant assets and liabilities related to ATC recorded on our balance sheets included our equity investment and accounts payable. At June 30, 2016 and December 31, 2015, our equity investment was $1,425.0 million and $1,380.9 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC. In addition, we had $30.3 million and $28.3 million of accounts payable due to ATC at June 30, 2016 and December 31, 2015, respectively, for network transmission services.

Purchased Power Agreement

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

We have approximately $107.9 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under this contract for the six months ended June 30, 2016 and 2015 were $26.9 million and $26.8 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

NOTE 16—COMMITMENTS AND CONTINGENCIES

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

Energy Related Purchased Power Agreements

Our natural gas utilities have obligations to distribute and sell natural gas to their customers, and our electric utilities have obligations to distribute and sell electricity to their customers. The utilities expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of June 30, 2016, including those of our subsidiaries, were $12,345.8 million.

Environmental Matters

Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as SO₂, NOx, fine particulates, mercury, and GHGs; water discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.

Air Quality

Sulfur Dioxide National Ambient Air Quality Standards

The EPA issued a revised 1-Hour SO₂ NAAQS that became effective in August 2010. The EPA issued a final rule in August 2015 describing the implementation requirements and established a compliance timeline for the revised standard. The final rule affords state agencies some latitude in rule implementation. A nonattainment designation could have negative impacts for a localized geographic area, including additional permitting requirements for new or existing sources in the area.

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

06/30/2016 Form 10-Q 20 WEC Energy Group, Inc.

Marquette area be designated as attainment. In July 2016, the EPA finalized its recommendation and published a notice in the Federal Register designating Marquette County, Michigan, as unclassified/attainment, effective in September 2016.

In June 2016, we provided modeling to the WDNR that shows the area around the Weston Power Plant to be in compliance. Based upon the submittal, we believe the WDNR will recommend by January 2017 that the area be designated attainment. We expect that the EPA will consider the WDNR's recommendation and finalize their own recommendation by the end of 2017.

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

8-Hour Ozone National Ambient Air Quality Standards

The EPA completed its review of the 2008 8-hour ozone standard in November 2014, and announced a proposal to tighten (lower) the NAAQS. In October 2015, the EPA released the final rule, which lowered the limit for ground-level ozone. This is expected to cause nonattainment designations for some counties in Wisconsin with potential future impacts for our fossil-fueled power plant fleet. For nonattainment areas, the state will have to develop a state implementation plan to bring the areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020 and are in the process of reviewing and determining potential impacts resulting from this rule.

Mercury and Other Hazardous Air Pollutants

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

We believe that the WE and WPS fleets are well positioned to comply with this regulation. Controls for acid gases and mercury are already in operation at the Pulliam units, and our compliance plans currently include capital projects for WPS's jointly owned plants to achieve the required reductions for MATS. In April 2013, WE received a one year MATS compliance extension from the MDEQ for PIPP through April 2016. The addition of a dry sorbent injection system for further control of mercury and acid gases at PIPP was placed into service in March 2016, and PIPP is now in compliance with MATS. Although WPS received a one year MATS compliance extension from the WDNR for Weston Unit 3 through April 2016, this unit is on a planned outage to complete the construction and start-up of the ReACT^TM system. Construction of the ReACT^TM multi-pollutant control system at Weston Unit 3 is complete and startup/commissioning work is underway with an expected in-service date in 2016. Once Weston Unit 3 comes back on line, it is expected to be in compliance with the MATS emission requirements.

Climate Change

In 2015, the EPA issued the Clean Power Plan, a final rule regulating GHG emissions from existing generating units, a proposed federal plan and model trading rules as alternatives or guides to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In October 2015, following publication of the final rule for existing fossil-fueled generating units, numerous states (including Wisconsin and Michigan), trade associations, and private parties filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but in February 2016, the Supreme Court stayed the effectiveness of the rule until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that review is sought, at the Supreme Court. In addition, in February 2016, the Governor of Wisconsin issued Executive Order 186, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan.

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

06/30/2016 Form 10-Q 21 WEC Energy Group, Inc.

The goal of the final rule is to reduce nationwide GHG emissions by 32% from 2005 levels. The rule is seeking GHG emission reductions in Wisconsin and Michigan of 41% and 39%, respectively, below 2012 levels by 2030. Interim goals starting in 2022 would require states to achieve about two-thirds of the 2030 required reduction. The building blocks used by the EPA to determine each state's emission reduction requirements include a combination of improving power plant efficiency, increasing reliance on combined cycle natural gas units, and adding new renewable energy resources. We are in the process of reviewing the final rule for existing fossil-fueled generating units to determine the potential impacts to our operations. The rule could result in significant additional compliance costs, including capital expenditures, could impact how we operate our existing fossil-fueled power plants and biomass facility, and could have a material adverse impact on our operating costs.

Draft Federal Plan and Model Trading Rules were also published in October 2015 for use in developing state plans or for use in states where a plan is not submitted or approved. In December 2015, the state of Wisconsin submitted petitions for reconsideration of the EPA's final standards for existing, as well as new, modified, and reconstructed generating units. A petition for reconsideration of the EPA's final standards for existing generating units was also submitted jointly by the Wisconsin utilities. Among other things, the petitions narrowly ask the EPA to consider revising the state goal for existing units to reflect the 2013 retirement of the Kewaunee Power Station, which could lower the state's carbon dioxideequivalent reduction goal by about 10%. In May 2016, the EPA denied the state of Wisconsin's petition for reconsideration related to new, modified, and reconstructed generating units, except that the EPA deferred the portion related to the treatment of biomass. In addition, the EPA has not issued decisions yet regarding the above referenced petitions for reconsideration of the final EPA standards for existing generating units. In December 2015, Michigan state agencies announced modeling results that suggest that the state will be able to meet existing source requirements until 2025, based on planned coal plant retirements, along with a continuation of state renewable standards and current levels of energy efficiency.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act, which requires that the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts from both impingement and entrainment. The rule became effective in October 2014, and applies to all of our existing generating facilities with cooling water intake structures, except for the Oak Creek expansion units, which were permitted under the rules governing new facilities.

Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities, except for VAPP Unit 1, Pulliam Units 7 and 8, and Weston Unit 2, satisfy the IM BTA requirements. For VAPP Unit 2, a project to install fish protection screens to meet the IM BTA standard was completed in 2015. The same types of screens are scheduled to be installed on VAPP Unit 1 starting in the third quarter of 2016. We plan to evaluate the available IM options for Pulliam Units 7 and 8. We also expect that limited studies will be required to support the future WDNR BTA determinations for Weston Unit 2. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the IM BTA requirements based on low capacity use of the unit.

BTA determinations must also be made by the WDNR and MDEQ to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. We have received an EM BTA determination by the WDNR, with EPA concurrence, for our proposed intake modification at VAPP. BTA determinations for EM will be made in future permit reissuances for Pulliam Units 7 and 8, Weston Units 2 through 4, Port Washington Generating Station, Pleasant Prairie Power Plant, PIPP, and Oak Creek Power Plant Units 5 through 8. 

During 2016–2018, we will be completing studies and evaluating options to address the EM BTA requirements at our plants. With the exception of Pleasant Prairie Power Plant and Weston Units 3 and 4 (which all have existing cooling towers that meet EM BTA requirements), and VAPP, we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at our facilities. We also expect that limited studies to support WDNR BTA determinations will be conducted at the Weston facility. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the EM BTA requirements based on low capacity use of the unit. In addition, the rule allows the EM BTA requirements to be waived in cases of pending facility retirements, which we are currently considering for PIPP. Based on discussions with the MDEQ, if we submit a signed certification with our next National Pollutant Discharge Elimination System permit application stating that PIPP will be retired no later than the end of the next permit cycle

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(assumed to be October 1, 2022), we believe the EM BTA requirements will be waived. Entrainment studies are currently being conducted at Pulliam Units 7 and 8 and are also underway at PIPP.

Steam Electric Effluent Guidelines

The EPA's final steam electric effluent guidelines rule took effect in January 2016 and applies to discharges of wastewater from our power plant processes in Wisconsin and Michigan. Unless pending challenges to the final guidelines are successful, the WDNR and MDEQ will modify the state rules and incorporate the new requirements into our facility permits, which are renewed every five years. We expect the new requirements to be phased in between 2018 and 2023 as our permits are renewed. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, these standards will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use. The final rule phases in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. New requirements for wet scrubber wastewater treatment will require additional zero liquid discharge or other advanced treatment capital improvements for the Oak Creek and Pleasant Prairie facilities. The rule also requires dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are required by the new rule, and modifications will be required at Oak Creek Units 7 and 8, the Pleasant Prairie units, the PIPP units, Pulliam Units 7 and 8, and Weston Unit 3. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $95 million to $130 million for these advanced treatment and bottom ash transport systems.

Valley Power Plant Wisconsin Pollutant Discharge Elimination System Permit

The WDNR issued a Wisconsin Pollutant Discharge Elimination System (WPDES) permit for VAPP that became effective in January 2013. The permit contains several additional requirements including effluent toxicity testing and monitoring for additional parameters (phosphorous, mercury, and ammonia-nitrogen), and a new heat addition limit from the cooling water discharges that all took effect immediately. Other long-term compliance requirements include thermal discharge studies, phosphorous evaluation and feasibility for reduction, mercury minimization planning, and the installation of new cooling water intake fish protection screens. Installation of wedge wire screens for fish protection on the VAPP Unit 2 cooling water intake structure was completed in 2015. An identical modification for VAPP Unit 1 is scheduled to begin in 2016. We are also working on updating the WPDES permit to reflect acceptance of VAPP process wastewater by the Milwaukee Metropolitan Sewage District, which addresses the permit conditions for phosphorous, mercury, and ammonia-nitrogen.

Manufactured Gas Plant Remediation

We have identified sites at which our utilities or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Our natural gas utilities are responsible for the environmental remediation of these sites, some of which are in the EPA Superfund Program. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure.

In addition, we are coordinating the investigation and cleanup of some of these sites subject to the jurisdiction of the EPA under what is called a "multisite" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.

The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites.

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

(in millions)	June 30, 2016		December 31, 2015
Regulatory assets	$	686.6	$	697.0
Reserves for future remediation	617.7		628.0

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Enforcement and Litigation Matters

We and our subsidiaries are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material effect on our financial condition or results of operations.

Weston Title V Air Permit

In May 2014, the WDNR issued a NOV alleging that WPS failed to maintain a minimum sorbent feed rate prior to the Continuous Emissions Monitoring System certification and included an issue related to reporting NOx emissions from the Weston Unit 4 auxiliary boiler. In June 2015, the WDNR issued a NOV alleging that WPS failed to comply with mercury reporting requirements related to challenged matters in the 2013 Weston Title V permit. In June 2016, the WDNR issued a letter closing both the May 2014 and June 2015 NOVs with no further action.

Consent Decrees

Wisconsin Electric Power Company Consent Decree

In April 2003, WE entered into a Consent Decree with the EPA, in which it agreed to significantly reduce air emissions from its coal-fired power plants. Under the terms of the Consent Decree, WE could request its termination after December 31, 2015. WE made this termination request in March 2016. In July 2016, the United States informed WE that neither the EPA nor the State of Michigan objected to the termination request. WE, along with the United States and the State of Michigan, intend to request formal termination of the Consent Decree by the court shortly.

Wisconsin Public Service Corporation Consent Decree – Weston and Pulliam

In November 2009, the EPA issued a 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 entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Eastern District of Wisconsin in March 2013.

The Consent Decree contains requirements to refuel, repower, and/or retire certain Weston and Pulliam units. Effective June 1, 2015, WPS retired Weston Unit 1 and Pulliam Units 5 and 6. In March 2016, WPS submitted a proposed revision to the EPA to update requirements reflecting the conversion of Weston Unit 2 from coal to natural gas fuel, and also proposed revisions to the list of beneficial environmental projects required by the Consent Decree. These proposed revisions were approved by the EPA in May 2016. The revisions to the environmental projects are not expected to materially impact the overall cost required of $6.0 million.

WPS received approval from the PSCW in its 2015 rate order to defer and amortize the undepreciated book value of the retired plant related to Weston Unit 1 and Pulliam Units 5 and 6 starting June 1, 2015, and concluding by 2023. Therefore, in June 2015, WPS recorded a regulatory asset of $11.5 million for the undepreciated book value. In addition, WPS received approval from the PSCW in its rate orders to recover prudently incurred costs as a result of complying with the terms of the Consent Decree, with the exception of a $1.2 million civil penalty.

Also, 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 June 30, 2016. It is unknown whether the Sierra Club will take further action in the future.

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Joint Ownership Power Plants Consent Decree – Columbia and Edgewater

In December 2009, the EPA issued a NOV to Wisconsin Power and Light, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric, WE (former co-owner of an Edgewater unit), and WPS. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. WPS, along with Wisconsin Power and Light, Madison Gas and Electric, and WE, entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013. WE paid an immaterial portion of the assessed penalty but has no further obligations under the Consent Decree.

The Consent Decree contains a requirement to, among other things, 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 Edgewater Unit 4 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.

NOTE 17—SUPPLEMENTAL CASH FLOW INFORMATION

	Six Months Ended June 30
(in millions)	2016			2015
Cash (paid) for interest, net of amount capitalized	$	(209.2	)	$	(116.3	)
Cash received (paid) for income taxes, net of (payments) refunds	7.4			(3.0		)
Significant non-cash transactions
Accounts payable related to construction costs	114.0			3.5
Amortization of deferred revenue	12.3			20.7

At June 30, 2016, and December 31, 2015, restricted cash of $94.4 million and $118.4 million, respectively, was recorded within other long-term assets on our balance sheets. The majority of this amount was held in the Integrys rabbi trust and represents a portion of the required funding that was triggered by the announcement of the Integrys acquisition.

NOTE 18—REGULATORY ENVIRONMENT

Wisconsin Public Service Corporation

2016 Wisconsin Rate Order

In April 2015, WPS initiated a rate proceeding with the PSCW. In December 2015, the PSCW issued a final written order for WPS, effective January 1, 2016. The order, which reflects a 10.0% ROE and a common equity component average of 51.0%, authorized a net retail electric rate decrease of $7.9 million (-0.8%) and a net retail natural gas rate decrease of $6.2 million (-2.1%). The decrease in retail electric rates was due to lower monitored fuel costs in 2016 compared to 2015. Absent the adjustment for electric fuel costs, WPS would have realized an electric rate increase. Based on the order, the PSCW will continue to allow WPS to escrow ATC and MISO network transmission expenses through 2016. In addition, future SSR payments will continue to be escrowed until a future rate proceeding. The order directs WPS to defer as a regulatory asset or liability the differences between actual transmission expenses and those included in rates. In addition, the PSCW approved a deferral for ReACT™, which requires WPS to defer the revenue requirement of ReACT™ costs above the authorized $275.0 million level through 2016. Fuel costs will continue to be monitored using a 2% tolerance window.

In March 2016, WPS requested extensions from the PSCW through 2017 for the deferral of the revenue requirement of ReACT™ costs above the authorized $275.0 million level as well as escrow accounting of ATC and MISO network transmission expenses. In April 2016, WPS also requested to extend through 2017 the previously approved deferral of the revenue requirement difference between the Real Time Market Pricing and the standard tariffed rates for any of WPS's current large commercial and industrial customers who entered into a service agreement with WPS under Real Time Market Pricing prior to April 15, 2016. These requests were approved by the PSCW in June 2016. The amounts deferred related to these items as of June 30, 2016, were not material.

06/30/2016 Form 10-Q 25 WEC Energy Group, Inc.

The Peoples Gas Light and Coke Company and North Shore Gas Company

Illinois Investigations

In March 2015, the ICC opened a docket, naming PGL as respondent, to investigate the veracity of certain allegations included in anonymous letters that the ICC staff received regarding PGL's Gas System Modernization Program (previously known as AMRP). This matter is still pending.

In November 2015, the ICC initiated an investigation into whether we, PGL, or Integrys knowingly misled or withheld material information from the ICC at its open meeting on May 20, 2015. The investigation relates to the ICC Staff's presentation of independent audit findings reached for PGL's Gas System Modernization Program. The Illinois Attorney General conducted an inquiry into this matter, as well as the veracity of certain allegations included in anonymous letters that the ICC staff received regarding PGL's Gas System Modernization Program. In May 2016, PGL entered into settlement agreements that fully resolved and settled all contested issues with the ICC, the Illinois Attorney General, and the Citizens Utility Board regarding the ICC's investigation of the May 20, 2015, open meeting and all pending Illinois Attorney General inquiries. As part of the settlements, PGL agreed to make payments totaling $18.5 million, the majority of which consisted of voluntary contributions to certain public utility funds, low-income customer funds, and credits to customers.

In December 2015, the ICC ordered a series of stakeholder workshops to evaluate PGL's Gas System Modernization Program. This ICC action did not impact PGL's ongoing work to modernize and maintain the safety of its natural gas distribution system, but it instead provided the ICC with an opportunity to analyze long-term elements of the program through the stakeholder workshops. The workshops are expected to result in an ICC order with final and binding recommendations for PGL's Gas System Modernization Program. The workshops that commenced in January 2016 were completed in March 2016. The ICC staff submitted a report on the workshop process in May 2016. In July 2016, the ICC initiated a proceeding to review, among other things, the planning, reporting and monitoring of the program, including what the target end date for the program should be. This proceeding is expected to result in a final order by the ICC in the first quarter of 2017. We are currently unable to determine what, if any, long-term impact there will be on PGL's Gas System Modernization Program.

Minnesota Energy Resources Corporation

2016 Minnesota Rate Case

In September 2015, MERC initiated a rate proceeding with the MPUC to increase retail natural gas rates $14.8 million (5.5%). MERC's request reflects a 10.3% ROE and a common equity component average of 50.32%. The proposed retail natural gas rate increase is primarily driven by higher construction and capital expenditures, general inflation, and improvements to customer service programs. The request also includes increases in costs related to the acquisition of Alliant Energy Corporation's Minnesota natural gas operations in April 2015. MERC is requesting authority from the MPUC to continue the use of its currently authorized decoupling mechanism.

In November 2015, the MPUC approved an interim rate order, effective January 1, 2016, authorizing a retail natural gas rate increase for MERC of $9.7 million (3.7%). The interim rates reflect a 9.35% ROE and a common equity component average of 50.32%. The interim rate increase is subject to refund pending the final rate order, which is expected by the end of 2016.

Upper Michigan Energy Resources Corporation

In June 2016, we filed a proposal with the MPSC and the PSCW to form Upper Michigan Energy Resources Corporation, a stand-alone utility in the Upper Peninsula of Michigan. This utility will include the electric and natural gas distribution assets of WE and WPS located in the Upper Peninsula. The proposal was filed pursuant to the MPSC's approval of our acquisition of Integrys, whereby we agreed to form a separate Michigan utility company. If approved, we anticipate that the new utility will be created effective January 1, 2017.

06/30/2016 Form 10-Q 26 WEC Energy Group, Inc.

NOTE 19—NEW ACCOUNTING PRONOUNCEMENTS

Revenue Recognition

In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and can either be applied retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently assessing the effects this guidance may have on our financial statements.

Classification and Measurement of Financial Instruments

In January 2016, the FASB issued ASU 2016-01, Classification and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. We are currently assessing the effects this guidance may have on our financial statements.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, and will be applied using a modified retrospective approach. We are currently assessing the effects this guidance may have on our financial statements.

Stock-Based Compensation

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. We are currently assessing the effects this guidance may have on our financial statements.

Financial Instruments Credit Losses

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. We are currently assessing the effects this guidance may have on our financial statements.

06/30/2016 Form 10-Q 27 WEC Energy Group, Inc.

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

CORPORATE DEVELOPMENTS

The following discussion should be read in conjunction with the accompanying financial statements and related notes and our Annual Report on Form 10-K for the year ended December 31, 2015.

Introduction

We are a diversified holding company with natural gas and electric utility operations (serving customers in Wisconsin, Illinois, Michigan, and Minnesota), an approximately 60% equity ownership interest in ATC (a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions), and non-utility electric operations through our We Power business.

Corporate Strategy

Our goal is to continue to create long-term value for our shareholders and our customers by focusing on the following:

Reliability

We have made significant reliability-related investments in recent years, and plan to continue making significant capital investments to strengthen and modernize the reliability of our generation and distribution networks. Below are a few examples of reliability projects that are currently underway.

• PGL is continuing to work on its Gas System Modernization Program, which primarily involves replacing old cast and ductile iron gas pipes and facilities in the city of Chicago’s natural gas delivery system with modern polyethylene pipes to reinforce the long-term safety and reliability of the system.

• WPS continues work on its System Modernization and Reliability Project, which involves modernizing parts of its electric distribution system by burying or upgrading lines. The project focuses on electric lines that currently have the lowest reliability in its system, primarily in rural areas that are heavily forested.

Operating Efficiency

We continually look for ways to optimize the operating efficiency of our company. For example, we received approval from the PSCW to make changes at the Oak Creek Expansion plant to enable the facility to burn coal from the Powder River Basin (PRB) located in the western United States. The coal plant was originally designed to burn coal mined from the eastern United States. This project is expected to create flexibility and should enable the plant to operate at lower costs, placing it in a better position to be called upon in the MISO Energy Markets, resulting in lower fuel costs for our customers.

Financial Discipline

A strong adherence to financial discipline is essential to meeting our earnings projections and maintaining a strong balance sheet, stable cash flows, attractive dividends, and quality credit ratings.

We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plant, and equipment and entire business units, that are no longer strategic to operations, are not performing as intended or have an unacceptable risk profile.

• See Note 2, Acquisition, for information about our acquisition of Integrys.

• Our primary investment opportunities are in three areas: our regulated utility business; our investment in ATC; and our generation plants within our We Power segment. In addition to the projects discussed above, other ongoing projects are discussed in more detail within Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.

06/30/2016 Form 10-Q 28 WEC Energy Group, Inc.

• See Note 3, Dispositions, for information on the sale of ITF and the MCPP.

Exceptional Customer Care

Our approach is driven by an intense focus on delivering exceptional customer care every day. We strive to provide the best value for our customers by embracing constructive change, leveraging our capabilities and expertise, and using creative solutions to meet or exceed our customers’ expectations.

One example of how we obtain feedback from our customers is through our "We Care" calls, where employees of our utility subsidiaries contact customers after a completed service call. This program began many years ago at We Energies (the trade name of WE and WG), and is now being rolled out to the Integrys utilities. Customer satisfaction is a priority, and making "We Care" calls is one of the main methods we use to gauge our performance in order to improve customer satisfaction and minimize customer dissatisfaction.

RESULTS OF OPERATIONS

THREE MONTHS ENDED JUNE 30, 2016

Consolidated Earnings

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

	Three Months Ended June 30
(in millions, except per share data)	2016			2015			B (W)
Wisconsin	$	214.7		$	140.4		$	74.3
Illinois	22.6			—			22.6
Other states	2.3			—			2.3
We Power	94.1			93.2			0.9
Corporate and other	(1.6		)	(67.8		)	66.2
Total operating income	332.1			165.8			166.3
Electric transmission	30.9			14.3			16.6
Other income, net	32.4			26.1			6.3
Interest expense	100.1			61.8			(38.3		)
Income before income taxes	295.3			144.4			150.9
Income tax expense	113.6			63.2			(50.4		)
Preferred stock dividends of subsidiary	0.3			0.3			—
Net income attributed to common shareholders	$	181.4		$	80.9		$	100.5
Diluted earnings per share	$	0.57		$	0.35		$	0.22

Earnings increased $100.5 million during the second quarter of 2016, driven by a $96.4 million increase in earnings due to the inclusion of Integrys's results in 2016 and acquisition costs incurred in 2015. Integrys was acquired on June 29, 2015.

06/30/2016 Form 10-Q 29 WEC Energy Group, Inc.

Wisconsin Segment Contribution to Operating Income

For the periods presented in this Quarterly Report on Form 10-Q, our Wisconsin operations included operations for both WE and WG for all periods and operations for WPS only in 2016, due to the acquisition of Integrys and its subsidiaries on June 29, 2015.

	Three Months Ended June 30
(in millions)	2016		2015		B (W)
Electric revenues	$	1,097.2	$	821.7	$	275.5
Fuel and purchased power	343.1		273.9		(69.2		)
Total electric margins	754.1		547.8		206.3
Natural gas revenues	207.5		158.2		49.3
Cost of natural gas sold	95.3		79.3		(16.0		)
Total natural gas margins	112.2		78.9		33.3
Other operation and maintenance	487.8		368.3		(119.5		)
Depreciation and amortization	122.7		86.3		(36.4		)
Property and revenue taxes	41.1		31.7		(9.4		)
Operating income	$	214.7	$	140.4	$	74.3

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

	Three Months Ended June 30
	MWh (in thousands)
Electric Sales Volumes	2016	2015	B (W)
Customer Class
Residential	2,455.3	1,691.9	763.4
Small commercial and industrial	3,161.4	2,132.6	1,028.8
Large commercial and industrial	3,394.5	2,352.9	1,041.6
Other	40.1	33.8	6.3
Total retail	9,051.3	6,211.2	2,840.1
Wholesale	897.3	286.6	610.7
Resale	1,862.2	1,887.8	(25.6	)
Total sales in MWh	11,810.8	8,385.6	3,425.2
Electric Customer Choice*	75.0	66.7	8.3

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

	Three Months Ended June 30
	Therms (in millions)
Natural Gas Sales Volumes	2016	2015	B (W)
Customer Class
Residential	160.4	103.7	56.7
Commercial and industrial	100.9	62.3	38.6
Total retail	261.3	166.0	95.3
Transport	291.0	176.2	114.8
Total sales in therms	552.3	342.2	210.1

06/30/2016 Form 10-Q 30 WEC Energy Group, Inc.

	Three Months Ended June 30
	Degree Days
Weather	2016	2015	B(W)
WE and WG (1)
Heating (951 normal)	926	934	(8	)
Cooling (157 normal)	196	99	97
WPS (2)
Heating (970 normal)	964	N/A	N/A
Cooling (130 normal)	142	N/A	N/A

⁽¹⁾  Normal heating and cooling degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin.

⁽²⁾  Normal heating and cooling degree days are based on a 20-year moving average of monthly temperatures from the Green Bay, Wisconsin Weather Station.

Electric Utility Margins

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

Electric utility margins at the Wisconsin segment increased $206.3 million in the second quarter of 2016, related to a $191.2 million margin contribution from WPS and a $15.1 million increase in margins at WE.

The most significant factor impacting the $15.1 million higher electric utility margins at WE was an increase related to higher sales volumes during the second quarter of 2016, primarily driven by warmer weather. As measured by cooling degree days, the second quarter of 2016 was 98.0% warmer than the same period in 2015.

Natural Gas Utility Margins

Natural gas utility margins are defined as natural gas revenues less the cost of natural gas sold. We believe that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues, since prudently incurred natural gas commodity costs are passed through to our customers in current rates. The average per-unit cost of natural gas sold for our Wisconsin natural gas utilities decreased 25.0% quarter over quarter, which had no impact on margins.

Natural gas utility margins at the Wisconsin segment increased $33.3 million during the second quarter of 2016, related to a $26.5 million margin contribution from WPS and a $6.8 million increase in margins at WE and WG.

The significant factors impacting the $6.8 million higher natural gas utility margins at WE and WG were:

• A $4.5 million increase related to higher sales volumes in the second quarter of 2016, partially driven by higher use per customer.

• A $3.2 million margin increase as a result of increased rates, effective January 1, 2016, in the WG PSCW rate order.

Operating Income

Operating income at the Wisconsin segment increased $74.3 million during the second quarter of 2016. This increase was driven by the $239.6 million increase in margins discussed above and was partially offset by $165.3 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes). Higher operating expenses were driven by $166.2 million of operating expenses from WPS, partially offset by a $0.9 million decrease in operating expenses at WE and WG in the second quarter of 2016.

06/30/2016 Form 10-Q 31 WEC Energy Group, Inc.

The most significant factor impacting the $0.9 million decrease in operating expenses at WE and WG was a $10.9 million gain on the sale of the MCPP, which was sold in April 2016. See Note 3, Dispositions, for more information. Without this gain, operating expenses would have increased $10.0 million, driven by an increase in benefit costs, related in part to stock-based compensation.

Illinois Segment Contribution to Operating Income

	Three Months Ended
(in millions)	June 30, 2016
Natural gas revenues	$	222.8
Cost of natural gas sold	46.2
Total natural gas margins	176.6
Other operation and maintenance	116.2
Depreciation and amortization	33.1
Property and revenue taxes	4.7
Operating income	$	22.6

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

	Therms (in millions)
	Three Months Ended
Natural Gas Sales Volumes	June 30, 2016
Customer Class
Residential	138.6
Commercial and industrial	27.2
Total retail	165.8
Transport	156.7
Total sales in therms	322.5

	Degree Days
	Three Months Ended
Weather *	June 30, 2016
Heating (689 Normal)	756

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

We did not have any operations in Illinois until our acquisition of Integrys on June 29, 2015. Since the majority of PGL and NSG customers use natural gas for heating, operating income is sensitive to weather and is generally higher during the winter months.

PGL and NSG recover certain operating expenses directly through separate riders, resulting in no impact on operating income as increases in operating expenses are offset by equal increases in margins. The following table shows the impact of these riders on margins and operating expenses:

	Three Months Ended
(in millions)	June 30, 2016
Environmental cleanup costs	$	4.8
Energy efficiency program	3.8
Bad debt rider	4.1
Total increase in margins and operating expenses	$	12.7

06/30/2016 Form 10-Q 32 WEC Energy Group, Inc.

Other States Segment Contribution to Operating Income

	Three Months Ended
(in millions)	June 30, 2016
Natural gas revenues	$	64.0
Cost of natural gas sold	23.6
Total natural gas margins	40.4
Other operation and maintenance	29.4
Depreciation and amortization	5.2
Property and revenue taxes	3.5
Operating income	$	2.3

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

	Therms (in millions)
	Three Months Ended
Natural Gas Sales Volumes	June 30, 2016
Customer Class
Residential	41.7
Commercial and industrial	27.8
Total retail	69.5
Transport	157.1
Total sales in therms	226.6

	Degree Days
	Three Months Ended
Weather *	June 30, 2016
Heating (865 Normal)	848

* Normal heating degree days for MERC and MGU are based on a 20-year moving average and 15-year moving average, respectively, of monthly temperatures from various weather stations throughout their respective service territories.

We did not have any operations in this segment until our acquisition of Integrys on June 29, 2015. Since the majority of MERC and MGU customers use natural gas for heating, operating income is sensitive to weather and is generally higher during the winter months.

We Power Segment Contribution to Operating Income

	Three Months Ended June 30
(in millions)	2016		2015		B (W)
Operating income	$	94.1	$	93.2	$	0.9

Corporate and Other Segment Contribution to Operating Income

	Three Months Ended June 30
(in millions)	2016			2015			B (W)
Operating loss	$	(1.6	)	$	(67.8	)	$	66.2

The operating loss at the corporate and other segment decreased $66.2 million when compared to the second quarter of 2015, driven by $65.0 million of acquisition costs incurred in the second quarter of 2015.

Electric Transmission Segment Operations

	Three Months Ended June 30
(in millions)	2016		2015		B (W)
Equity in earnings of transmission affiliate	$	30.9	$	14.3	$	16.6

06/30/2016 Form 10-Q 33 WEC Energy Group, Inc.

Earnings from our ownership interest in ATC increased $16.6 million when compared to the second quarter of 2015, driven by the increase in our ownership interest from 26.2% to approximately 60% as a result of the acquisition of Integrys. However, as a result of certain ALJ decisions, we recognized lower earnings during the second quarter of 2016 from our investment in ATC as compared to the same period in 2015. See American Transmission Company Allowed Return on Equity Complaints below for more information on the ALJ decisions.

Consolidated Other Income, Net

	Three Months Ended June 30
(in millions)	2016		2015		B (W)
AFUDC – Equity	$	7.0	$	2.3	$	4.7
Gain on asset sales	19.6		20.8		(1.2		)
Other, net	5.8		3.0		2.8
Other income, net	$	32.4	$	26.1	$	6.3

Other income, net increased by $6.3 million when compared to the second quarter of 2015. The increase was primarily driven by higher AFUDC due to the inclusion of AFUDC from the Integrys companies subsequent to the acquisition in June 2015. Partially offsetting this increase was a $19.6 million gain recorded in April 2016 from the sale of the chilled water generation and distribution assets of Wisvest, compared with a $20.8 million gain from the sale of Minergy LLC and its remaining financial assets in June 2015. See Note 3, Dispositions, for more information on our asset sales.

Consolidated Interest Expense

	Three Months Ended June 30
(in millions)	2016		2015		B (W)
Interest expense	$	100.1	$	61.8	$	(38.3	)

Interest expense increased by $38.3 million, or 62.0%, as compared to the second quarter of 2015. The increase was primarily driven by $33.7 million of interest expense from Integrys and its subsidiaries in 2016. Additionally, we issued $1.2 billion of long-term debt in June 2015 to finance a portion of the cash consideration for the acquisition of Integrys.

Consolidated Income Tax Expense

	Three Months Ended June 30
	2016		2015		B (W)
Effective tax rate	38.5	%	43.8	%	5.3	%

The decrease in our effective tax rate was primarily related to a one-time charge of $10.4 million in the second quarter of 2015 to remeasure our state deferred income taxes as a result of the acquisition of Integrys.

06/30/2016 Form 10-Q 34 WEC Energy Group, Inc.

SIX MONTHS ENDED JUNE 30, 2016

Consolidated Earnings

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

	Six Months Ended June 30
(in millions, except per share data)	2016			2015			B (W)
Wisconsin	$	542.2		$	416.9		$	125.3
Illinois	159.6			—			159.6
Other states	34.1			—			34.1
We Power	187.4			185.7			1.7
Corporate and other	(1.9		)	(78.0		)	76.1
Total operating income	921.4			524.6			396.8
Electric transmission	69.4			30.4			39.0
Other income, net	65.1			29.1			36.0
Interest expense	201.0			121.2			(79.8		)
Income before income taxes	854.9			462.9			392.0
Income tax expense	326.7			185.6			(141.1		)
Preferred stock dividends of subsidiary	0.6			0.6			—
Net income attributed to common shareholders	$	527.6		$	276.7		$	250.9
Diluted Earnings Per Share	$	1.66		$	1.21		$	0.45

Earnings increased $250.9 million during the first six months of 2016, driven by a $262.9 million increase in earnings due to the inclusion of Integrys's results in 2016 and acquisition costs incurred in 2015. Integrys was acquired on June 29, 2015.

Wisconsin Segment Contribution to Operating Income

	Six Months Ended June 30
(in millions)	2016		2015		B (W)
Electric revenues	$	2,214.4	$	1,708.4	$	506.0
Fuel and purchased power	679.4		571.8		(107.6		)
Total electric margins	1,535.0		1,136.6		398.4
Natural gas revenues	670.2		648.4		21.8
Cost of natural gas sold	356.9		395.5		38.6
Total natural gas margins	313.3		252.9		60.4
Other operation and maintenance	979.1		737.4		(241.7		)
Depreciation and amortization	245.6		171.7		(73.9		)
Property and revenue taxes	81.4		63.5		(17.9		)
Operating income	$	542.2	$	416.9	$	125.3

06/30/2016 Form 10-Q 35 WEC Energy Group, Inc.

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

	Six Months Ended June 30
	MWh (in thousands)
Electric Sales Volumes	2016	2015	B (W)
Customer Class
Residential	5,110.6	3,700.2	1,410.4
Small commercial and industrial	6,348.4	4,357.8	1,990.6
Large commercial and industrial	6,712.8	4,512.0	2,200.8
Other	87.6	72.8	14.8
Total retail	18,259.4	12,642.8	5,616.6
Wholesale	1,753.4	706.6	1,046.8
Resale	4,094.5	3,992.5	102.0
Total sales in MWh	24,107.3	17,341.9	6,765.4
Electric Customer Choice*	139.3	316.7	(177.4	)

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

	Six Months Ended June 30
	Therms (in millions)
Natural Gas Sales Volumes	2016	2015	B (W)
Customer Class
Residential	638.2	530.9	107.3
Commercial and industrial	371.7	308.0	63.7
Total retail	1,009.9	838.9	171.0
Transport	671.5	444.1	227.4
Total sales in therms	1,681.4	1,283.0	398.4

	Six Months Ended June 30
	Degree Days
Weather	2016	2015	B(W)
WE and WG (1)
Heating (4,290 normal)	4,031	4,590	(559	)
Cooling (158 normal)	196	99	97
WPS (2)
Heating (4,687 normal)	4,402	N/A	N/A
Cooling (131 normal)	142	N/A	N/A

⁽¹⁾  Normal heating and cooling degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin.

⁽²⁾  Normal heating and cooling degree days are based on a 20-year moving average of monthly temperatures from the Green Bay, Wisconsin Weather Station.

Electric Utility Margins

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

Electric utility margins at the Wisconsin segment increased $398.4 million during the first six months of 2016, related to a $386.4 million margin contribution from WPS and a $12.0 million increase in margins at WE.

06/30/2016 Form 10-Q 36 WEC Energy Group, Inc.

The significant factors impacting the $12.0 million higher electric utility margins at WE were:

• The expiration of $6.1 million of bill credits refunded to customers in 2015 related to the treasury grant WE received in connection with its biomass facility.

• A $5.8 million decrease in fly ash removal and fuel handling costs during the first six months of 2016.

Natural Gas Utility Margins

Natural gas utility margins are defined as natural gas revenues less the cost of natural gas sold. We believe that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues, since prudently incurred natural gas commodity costs are passed through to our customers in current rates. The average per-unit cost of natural gas sold for our Wisconsin natural gas utilities decreased 25.5% period over period, which had no impact on margins.

Natural gas utility margins at the Wisconsin segment increased $60.4 million during the first six months of 2016, related to a $63.6 million margin contribution from WPS, partially offset by a $3.2 million decrease in margins at WE and WG.

The most significant factor impacting the $3.2 million lower natural gas utility margins at WE and WG was a $13.2 million decrease related to lower sales volumes during the first six months of 2016, primarily driven by warmer weather. As measured by heating degree days, the first six months of 2016 were 12.2% warmer than the same period in 2015. This decrease in margins related to sales volumes was partially offset by a $12.9 million margin increase as a result of increased rates, effective January 1, 2016, in the WG PSCW rate order.

Operating Income

Operating income at the Wisconsin segment increased $125.3 million during the first six months of 2016. The increase was driven by the $458.8 million increase in margins discussed above and was partially offset by $333.5 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes). Higher operating expenses were driven by $321.6 million of operating expenses from WPS and an $11.9 million increase in operating expenses at WE and WG in the first six months of 2016.

Significant factors impacting the $11.9 million increase in operating expenses at WE and WG were:

• A $15.1 million increase in benefit costs, related in part to stock-based compensation.

• A $12.9 million increase in depreciation and amortization, driven by an overall increase in utility plant in service. In November 2015, WG completed the Western Gas lateral project, and WE completed the conversion of the fuel source for VAPP from coal to natural gas.

These increases in operating expenses were partially offset by a $10.9 million gain on the sale of the MCPP, which was sold in April 2016. See Note 3, Dispositions, for more information.

Illinois Segment Contribution to Operating Income

	Six Months Ended
(in millions)	June 30, 2016
Natural gas revenues	$	671.3
Cost of natural gas sold	203.5
Total natural gas margins	467.8
Other operation and maintenance	234.1
Depreciation and amortization	65.9
Property and revenue taxes	8.2
Operating income	$	159.6

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

	Therms (in millions)
	Six Months Ended
Natural Gas Sales Volumes	June 30, 2016
Customer Class
Residential	570.2
Commercial and industrial	115.6
Total retail	685.8
Transport	502.6
Total sales in therms	1,188.4

	Degree Days
	Six Months Ended
Weather *	June 30, 2016
Heating (3,905 Normal)	3,664

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

We did not have any operations in Illinois until our acquisition of Integrys on June 29, 2015. Since the majority of PGL and NSG customers use natural gas for heating, operating income is sensitive to weather and is generally higher during the winter months.

PGL and NSG recover certain operating expenses directly through separate riders, resulting in no impact on operating income as increases in operating expenses are offset by equal increases in margins. The following table shows the impact of these riders on margins and operating expenses:

	Six Months Ended
(in millions)	June 30, 2016
Environmental cleanup costs	$	15.6
Energy efficiency program	12.6
Bad debt rider	7.6
Total increase in margins and operating expenses	$	35.8

Other States Segment Contribution to Operating Income

	Six Months Ended
(in millions)	June 30, 2016
Natural gas revenues	$	212.4
Cost of natural gas sold	102.0
Total natural gas margins	110.4
Other operation and maintenance	59.4
Depreciation and amortization	10.3
Property and revenue taxes	6.6
Operating income	$	34.1

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

	Therms (in millions)
	Six Months Ended
Natural Gas Sales Volumes	June 30, 2016
Customer Class
Residential	183.7
Commercial and industrial	115.4
Total retail	299.1
Transport	384.2
Total sales in therms	683.3

	Degree Days
	Six Months Ended
Weather *	June 30, 2016
Heating (4,476 Normal)	4,079

* Normal heating degree days for MERC and MGU are based on a 20-year moving average and 15-year moving average, respectively, of monthly temperatures from various weather stations throughout their respective service territories.

We did not have any operations in this segment until our acquisition of Integrys on June 29, 2015. Since the majority of MERC and MGU customers use natural gas for heating, operating income is sensitive to weather and is generally higher during the winter months.

We Power Segment Contribution to Operating Income

	Six Months Ended June 30
(in millions)	2016		2015		B (W)
Operating income	$	187.4	$	185.7	$	1.7

Corporate and Other Segment Contribution to Operating Income

	Six Months Ended June 30
(in millions)	2016			2015			B (W)
Operating loss	$	(1.9	)	$	(78.0	)	$	76.1

The operating loss at the corporate and other segment decreased $76.1 million when compared to the first six months of 2015, driven by $72.7 million of acquisition costs incurred during the first six months of 2015.

Electric Transmission Segment Operations

	Six Months Ended June 30
(in millions)	2016		2015		B (W)
Equity in earnings of transmission affiliate	$	69.4	$	30.4	$	39.0

Earnings from our ownership interest in ATC increased $39.0 million when compared to the first six months of 2015, primarily driven by the increase in our ownership interest from 26.2% to approximately 60% as a result of the acquisition of Integrys. However, as a result of certain ALJ decisions, we recognized lower earnings during the first six months of 2016 from our investment in ATC as compared to the same period in 2015. See American Transmission Company Allowed Return on Equity Complaints below for more information on the ALJ decisions.

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Consolidated Other Income, Net

	Six Months Ended June 30
(in millions)	2016		2015		B (W)
AFUDC – Equity	14.0		4.0		10.0
Gain on repurchase of notes	23.6		—		23.6
Gain on asset sales	19.6		20.8		(1.2		)
Other, net	7.9		4.3		3.6
Other income, net	$	65.1	$	29.1	$	36.0

Other income, net increased by $36.0 million when compared to the first six months of 2015. The increase was primarily due to the repurchase of a portion of Integrys's 6.11% Junior Notes at a discount in February 2016, as well as higher AFUDC due to the inclusion of AFUDC from the Integrys companies subsequent to the acquisition in June 2015. See Note 6, Long-Term Debt, for more information on the repurchase. Partially offsetting this increase was a $19.6 million gain recorded in April 2016 from the sale of the chilled water generation and distribution assets of Wisvest, compared with a $20.8 million gain from the sale of Minergy LLC and its remaining financial assets in June 2015. See Note 3, Dispositions, for more information on our asset sales.

Consolidated Interest Expense

	Six Months Ended June 30
(in millions)	2016		2015		B (W)
Interest expense	$	201.0	$	121.2	$	(79.8	)

Interest expense increased by $79.8 million, or 65.8%, as compared to the first six months of 2015. The increase was primarily driven by $68.5 million of interest expense from Integrys and its subsidiaries in 2016. Additionally, we issued $1.2 billion of long-term debt in June 2015 to finance a portion of the cash consideration for the acquisition of Integrys.

Consolidated Income Tax Expense

	Six Months Ended June 30
	2016		2015		B (W)
Effective tax rate	38.2	%	40.1	%	1.9	%

The decrease in our effective tax rate was primarily related to a one-time charge of $10.4 million in the second quarter of 2015 to remeasure our state deferred income taxes as a result of the acquisition of Integrys. We expect our 2016 annual effective tax rate to be between 37.5% and 38.5%.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

The following table summarizes our cash flows during the six months ended June 30:

(in millions)	2016			2015			Change in 2016 Over 2015
Cash provided by (used in)
Operating activities	$	1,224.1		$	716.5		$	507.6
Investing activities	(449.1		)	(1,679.2		)	1,230.1
Financing activities	(792.7		)	1,115.2			(1,907.9		)

Operating Activities

Net cash provided by operating activitiesincreased$507.6 million during the first six months of 2016. This increase was driven by $466.6 million of net cash flows from the operating activities of Integrys, which excludes payments related to the WEC Energy Group income tax allocation agreement. See Note 2, Acquisition, for more information on the acquisition of Integrys.

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The remaining $41.0 millionincrease in net cash provided by operating activities was related to the legacy Wisconsin Energy Corporation companies and was driven by:

• A $200.3 million increase in cash from lower payments for natural gas and fuel and purchased power, due to lower commodity prices and warmer weather during the 2016 heating season.

• An $88.5 milliondecrease in contributions and payments to our pension and OPEB plans. We did not make any contributions to our qualified pension plans during the first six months of 2016, compared with contributions of $100.0 million during the same period in 2015.

The increase in net cash provided by operating activities from the legacy Wisconsin Energy Corporation companies was partially offset by a $260.5 million decrease in cash related to lower overall collections from customers. Collections from customers decreased because of lower commodity prices and warmer weather during the 2016 heating season.

Investing Activities

Net cash used in investing activitiesdecreased$1,230.1 million during the first six months of 2016, driven by:

• An investment of $1,329.4 million in June 2015 related to the acquisition of Integrys, which is net of cash acquired of $156.3 million. See Note 2, Acquisition, for more information.

• A $139.8 million increase in the proceeds received from the sale of certain assets and businesses during the first six months of 2016. See Note 3, Dispositions, for more information.

These decreases in net cash used in investing activities were partially offset by a $250.7 million increase in capital expenditures, which is discussed in more detail below.

Capital Expenditures

Capital expenditures by segment for the six months ended June 30 were as follows:

Reportable Segment (in millions)	2016		2015		Change in 2016 Over 2015
Wisconsin	$	400.5	$	356.6	$	43.9
Illinois	137.1		—		137.1
Other states	22.7		—		22.7
We Power	24.3		5.8		18.5
Corporate and other	34.1		5.6		28.5
Total capital expenditures	$	618.7	$	368.0	$	250.7

The increase in cash paid for capital expenditures at the Wisconsin segment during the first six months of 2016 was due to the inclusion of WPS. WPS's capital expenditures of $154.1 million during the first six months of 2016 related to the ReACT^TM emission control technology project at Weston Unit 3, a combustion turbine project at the Fox Energy Center, and the System Modernization and Reliability Project. Partially offsetting this increase were lower capital expenditures for WG's Western Gas Lateral project and WE's coal to natural gas conversion project at VAPP, both of which were completed in November 2015.

The cash paid for capital expenditures at the Illinois segment include PGL's and NSG's projects during the first sixmonths of 2016. PGL continues to incur significant capital expenditures related to PGL's Gas System Modernization Program.

The cash paid for capital expenditures at the other states segment include MERC's and MGU's projects during the first sixmonths of 2016.

The increase in cash paid for capital expenditures at the corporate and other segment during the first six months of 2016 was driven by an information technology project created to improve the billing, call center, and credit collection functions of the Integrys subsidiaries and a project to implement a new enterprise resource planning system.

See Significant Capital Projects below for more information.

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Financing Activities

Net cash from financing activities decreased $1,907.9 million during the first six months of 2016, driven by:

• Long-term debt issuances of $1,450.0 million during the first six months of 2015, of which $1,200.0 million related to the acquisition of Integrys.

• A $230.2 million increase in the retirement of long-term debt during the first six months of 2016, primarily at Integrys and its subsidiaries. In February 2016, we repurchased a portion of Integrys's 6.11% Junior Notes at a discount.

• A $121.9 millionincrease in dividends paid on common stock during the first six months of 2016 due to the issuance of 90.2 million shares of our common stock in June 2015 as a result of the Integrys acquisition and increases to our quarterly dividend rate.

• A $62.2 millionincrease in cash used to purchase shares of our common stock during the first six months of 2016 to satisfy requirements of certain stock-based employee benefit and compensation plans.

• A $61.5 millionincrease in the repayment of commercial paper during the first six months of 2016.

Significant Financing Activities

For more information on our financing activities, see Note 5, Short-Term Debt and Lines of Credit, and Note 6, Long-Term Debt.

Capital Resources and Requirements

Capital Resources

Liquidity

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

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

WEC Energy Group, WE, WG, WPS, and PGL maintain bank back-up credit facilities, which provide liquidity support for each company's obligations with respect to commercial paper and for general corporate purposes. We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. See Note 5, Short-Term Debt and Lines of Credit, for more information about these credit facilities.

The following table shows our capitalization structure as of June 30, 2016, as well as an adjusted capitalization structure that we believe is consistent with how the rating agencies currently view our 2007 6.25% Series A Junior Subordinated Notes due 2067, Integrys's 6.11% Junior Notes, and Integrys's 2013 6.00% Junior Subordinated Notes due 2073 (collectively, Junior Notes):

(in millions)	Actual			Adjusted
Common equity	$	8,833.5		$	9,340.9
Preferred stock of subsidiary	30.4			30.4
Long-term debt (including current portion)	8,997.9			8,490.5
Short-term debt	927.8			927.8
Total capitalization	$	18,789.6		$	18,789.6
Total debt	$	9,925.7		$	9,418.3
Ratio of debt to total capitalization	52.8		%	50.1		%

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Included in long-term debt on our balance sheet as of June 30, 2016, is $1,014.9 million aggregate principal amount of Junior Notes. The adjusted presentation attributes $507.4 million of the Junior Notes to common equity and $507.5 million to long-term debt. We believe this presentation is consistent with the 50% equity credit that the majority of rating agencies currently attribute to the Junior Notes.

The adjusted presentation of our consolidated capitalization structure is presented as a complement to our capitalization structure presented in accordance with GAAP. Management evaluates and manages our capitalization structure, including our total debt to total capitalization ratio, using the GAAP calculation as adjusted by the rating agency treatment of the Junior Notes. Therefore, we believe the non-GAAP adjusted presentation reflecting this treatment is useful and relevant to investors in understanding how management and the rating agencies evaluate our capitalization structure.

In February 2016, Integrys repurchased and retired approximately $154.9 million aggregate principal amount of its 6.11% Junior Notes for a purchase price of $128.6 million, plus accrued and unpaid interest, through a modified “dutch auction” tender offer.

See Note 6, Long-Term Debt, for more information on our long-term debt.

As of June 30, 2016, WE was the obligor under two series of tax-exempt pollution control refunding bonds with a combined outstanding principal amount of $147.0 million. In August 2009, WE terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. WE purchased the bonds at par plus accrued interest to the date of purchase. As of June 30, 2016, the repurchased bonds were still outstanding but were not reported in our long-term debt since they were held by WE. One of the bond series, with an outstanding principal amount of $67.0 million, matured on August 1, 2016. Depending on market conditions and other factors, WE may change the method used to determine the interest rate on the other bond series and have it remarketed to third parties.

Working Capital

As of June 30, 2016, our current liabilities exceeded our current assets by approximately $371.2 million. We do not expect this to have any impact on our liquidity since we believe we have adequate back-up lines of credit in place for our ongoing operations. We also can access the capital markets to finance our construction programs and to refinance current maturities of long-term debt, if necessary.

Credit Rating Risk

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

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

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

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

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Capital Requirements

Significant Capital Projects

We have several capital projects that will require significant capital expenditures over the next three years and beyond. All projected capital requirements are subject to periodic review and may vary significantly from estimates, depending on a number of factors. These factors include environmental requirements, regulatory restraints and requirements, changes in tax laws and regulations, acquisition and development opportunities, market volatility, and economic trends. Our estimated capital expenditures for the next three years are as follows:

(in millions)	2016		2017		2018
Wisconsin	$	943.4	$	1,108.5	$	1,055.2
Illinois	398.5		567.3		387.0
Other states	63.7		88.4		64.0
We Power	42.3		55.7		38.5
Corporate and other	112.4		90.0		5.3
Total	$	1,560.3	$	1,909.9	$	1,550.0

WPS is constructing a multi-pollutant control technology known as ReACT^TM as part of Weston Unit 3. The control technology will enable the plant to meet the requirements of a Consent Decree agreed to between WPS and the EPA. The cost of the project is estimated at approximately $345 million, excluding AFUDC, and it is expected to be placed in service in 2016.

WPS is also continuing work on the System Modernization and Reliability Project. This project includes converting more than 1,000 miles of overhead distribution power lines to underground in northern Wisconsin and adding distribution automation equipment on 400 miles of lines. WPS expects to invest approximately $45 million annually through 2018.

PGL is continuing work on the Gas System Modernization Program, a project under which PGL is replacing approximately 2,000 miles of Chicago's aging natural gas pipeline infrastructure. PGL currently recovers these costs through a surcharge on customer bills pursuant to an ICC approved qualifying infrastructure plant rider, which is in effect through 2023. PGL expects to invest between $250 million and $280 million annually through 2018.

We expect to provide total capital contributions to ATC (not included in the above table) of approximately $317 million from 2016 through 2018.

Common Stock Dividends

Our current quarterly dividend rate is $0.4950 per share, which equates to an annual dividend of $1.98 per share.

Off-Balance Sheet Arrangements

We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit that support construction projects, commodity contracts, and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see Note 5, Short-Term Debt and Lines of Credit, Note 10, Guarantees, and Note 15, Variable Interest Entities.

Contractual Obligations

For additional information about our commitments, see Contractual Obligations in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Requirements in our 2015 Annual Report on Form 10-K.

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FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity, and capital resources. The following discussion should be read together with the information in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources of our 2015 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, industry restructuring, environmental matters, critical accounting policies and estimates, and other matters.

Market Risks and Other Significant Risks

We are exposed to market and other significant risks as a result of the nature of our businesses and the environments in which those businesses operate. These risks include, but are not limited to, the regulatory recovery risk described below. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in our 2015 Annual Report on Form 10-K for a discussion of other significant risks applicable to us.

Regulatory Recovery

Regulated entities are allowed to defer certain costs that would otherwise be charged to expense if the regulated entity believes the recovery of those costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by our regulators. Recovery of these deferred costs in future rates is subject to the review and approval by those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of these deferred costs, including those referenced below, is not approved by our regulators, the costs would be charged to income in the current period. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities.

We expect to request or have requested recovery of the costs related to the following projects discussed in recent or pending rate proceedings, orders, and investigations involving our utilities:

• In June 2016, the PSCW approved deferral of costs related to WPS's ReACT™ project above the originally authorized $275.0 million level through 2017. WPS will be required to obtain a separate approval for collection of these deferred costs. See Significant Capital Projects for more information on ReACT™.

• Prior to the acquisition, Integrys initiated an information technology project with the goal of improving the customer experience at its subsidiaries. Specifically, the project is expected to provide functional and technological benefits to the billing, call center, and credit collection functions. As of June 30, 2016, none of the costs for this project have been disallowed in rate proceedings. We will be required to obtain approval for the recovery of additional costs incurred through the completion of this long-term project.

• In January 2014, the ICC approved PGL's use of the Qualifying Infrastructure Plant rider as a recovery mechanism for costs incurred related to investments in qualifying infrastructure plant. This rider is subject to an annual audit proceeding whereby costs are reviewed for accuracy and prudency. No schedule has been set for the 2015 audit proceeding. The ALJ has placed the 2014 audit proceeding on a stay, pending resolution of the ICC ordered stakeholder workshops and the ICC investigative docket regarding anonymous letters it received, both related to PGL's Gas System Modernization Program. Although schedules have not been set for the audit proceedings, discovery continues for both the 2014 and 2015 audits. As of June 30, 2016, there can be no assurance that all costs incurred under the Qualifying Infrastructure Plant rider will be recoverable.

See Note 18, Regulatory Environment, for more information regarding recent and pending rate proceedings, orders, and investigations involving our utilities.

Environmental Matters

Cross-State Air Pollution Rule

In July 2011, the EPA issued the CSAPR, which replaced a previous rule, the CAIR. The purpose of the CSAPR was to limit the interstate transport of emissions of NOx and SO₂ that contribute to fine particulate matter and ozone nonattainment in downwind

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states through a proposed allocation plan and allowance trading scheme. The rule was to become effective in January 2012. However, in December 2011, the CSAPR requirements were stayed by the D.C. Circuit Court of Appeals, and CAIR was implemented during the stay period. In August 2012, the D.C. Circuit Court of Appeals issued a ruling vacating and remanding CSAPR and simultaneously reinstating CAIR pending the issuance of a replacement rule by the EPA. The case was appealed to the Supreme Court. In April 2014, the Supreme Court issued a decision largely upholding CSAPR and remanded it to the D.C. Circuit Court of Appeals for further proceedings. In October 2014, the D.C. Circuit Court of Appeals issued a decision that allowed the EPA to begin implementing CSAPR on January 1, 2015. Phase I emissions budgets applied in 2015 and also apply in 2016, and Phase 2 emissions budgets will apply to 2017 and beyond.

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

See Note 16, Commitments and Contingencies, for a discussion of additional environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change.

Other Matters

American Transmission Company Allowed Return on Equity Complaints

In November 2013, a group of MISO industrial customer organizations filed a complaint with the FERC requesting to reduce the base ROE used by MISO transmission owners, including ATC, to 9.15%. ATC's current authorized ROE is 12.2%. In October 2014, the FERC issued an order to hear the complaint on ROE and set a refund effective date retroactive to November 12, 2013. The FERC conducted hearings in August 2015, and the ALJ issued an initial decision in December 2015. The ALJ's initial decision recommended that ATC and all other MISO transmission owners be authorized to collect a base ROE of 10.32%, as well as the 0.5% incentive adder approved by the FERC in January 2015 for MISO transmission owners. The ALJ's recommendation is not binding on the FERC and applies to revenues collected from November 12, 2013, through February 11, 2015. A FERC order related to this complaint is expected during the fourth quarter of 2016.

In February 2015, a second complaint was filed with the FERC requesting a reduction in the base ROE used by MISO transmission owners, including ATC, to 8.67%, with a refund effective date retroactive to February 12, 2015. The FERC conducted hearings in February 2016 with respect to this second complaint, and the ALJ issued an initial decision in June 2016. The ALJ's initial decision recommended that ATC and all other MISO transmission owners be authorized to collect a base ROE of 9.7%, as well as the 0.5% incentive adder approved for MISO transmission owners. The ALJ's initial decision is not binding on the FERC and applies to revenues collected from February 12, 2015, through May 11, 2016. A FERC order related to this complaint is expected during the second quarter of 2017.

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

Any change to ATC's ROE could result in lower equity earnings and distributions from ATC in the future. Based on the ALJ initial decisions, we recognized lower earnings during the first six months of 2016 from our investment in ATC as compared with the same period in 2015.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes related to market risk from the disclosures presented in our Annual Report on Form 10-K for the year ended December 31, 2015. In addition to the Form 10-K disclosures, see Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in Item 2 of Part I of this report, as well as Note 8, Fair Value Measurements, Note 9, Derivative Instruments, and Note 10, Guarantees, in this report for information concerning our market risk exposures.

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ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the second quarter of 2016 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

06/30/2016 Form 10-Q 48 WEC Energy Group, Inc.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The following should be read in conjunction with Item 3. Legal Proceedings in Part I of our 2015 Annual Report on Form 10-K. See Note 16, Commitments and Contingencies, and Note 18, Regulatory Environment, in this report for more information on material legal proceedings and matters related to us and our subsidiaries.

In addition to those legal proceedings discussed below and in our reports to the SEC, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these legal proceedings cannot be predicted with certainty, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material effect on our financial statements.

Environmental Matters

Sheboygan River Matter

We were contacted by the United States Department of Justice in March 2016 to commence discussions between WPS and the federal natural resource trustees to resolve WPS's alleged liability for natural resources damages (NRD) in the Sheboygan River related to the former Camp Marina manufactured gas plant site. WPS was originally notified about this claim in September 2012, but the WDNR chose not to be a party to the NRD claim negotiation in February 2014. However, the National Oceanic and Atmospheric Administration has co-equal trusteeship with the WDNR over the impacted Sheboygan River natural resources and is now pursuing the NRD claim. We are currently in settlement discussions with the Department of Justice, but we do not expect this matter to have a material impact on our financial statements. Substantial remediation of the uplands at the legacy Sheboygan Camp Marina manufactured gas plant site has already occurred.

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors presented in our Annual Report on Form 10-K for the year ended December 31, 2015. See Item 1A. Risk Factors in Part I of our 2015 Annual Report on Form 10-K for a discussion of certain risk factors applicable to us.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table sets forth information regarding the purchases of our equity securities made by or on behalf of us or any affiliated purchaser (as defined in Exchange Act Rule 10b-18) during the three months ended June 30, 2016:

Issuer Purchases of Equity Securities

2016	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
April 1 – April 30	—	$	—	—	$	—
May 1 – May 31 *	23,400	58.33		—	$	—
June 1 – June 30	—	—		—	$	—
Total	23,400	$	58.33	—

* All shares reported during May were surrendered by employees to satisfy tax withholding obligations upon vesting of restricted stock.

06/30/2016 Form 10-Q 49 WEC Energy Group, Inc.

ITEM 6. EXHIBITS

Number	Exhibit
10	Material Contracts
	10.1	Integrys Energy Group, Inc. Deferred Compensation Plan, as Amended and Restated Effective January 1, 2016.
	10.2	Integrys Energy Group, Inc. Pension Restoration and Supplemental Retirement Plan, as Amended and Restated Effective January 1, 2016.
31	Rule 13a-14(a) / 15d-14(a) Certifications
	31.1	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Section 1350 Certifications
	32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101	Interactive Data File

06/30/2016 Form 10-Q 50 WEC Energy Group, Inc.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		WEC ENERGY GROUP, INC.
		(Registrant)
		/s/ WILLIAM J. GUC
Date:	August 5, 2016	William J. Guc
		Vice President and Controller
		(Duly Authorized Officer and Chief Accounting Officer)

06/30/2016 Form 10-Q 51 WEC Energy Group, Inc.

EX-10.1

Exhibit 10.1

INTEGRYS ENERGY GROUP, INC.

DEFERRED COMPENSATION PLAN

As Amended and Restated Effective January 1, 2016

Exhibit 10.1

TABLE OF CONTENTS

	Page
ARTICLE I. DEFINITIONS AND CONSTRUCTION	2
Section 1.01. Definitions	2
Section 1.02. Construction and Applicable Law	5
ARTICLE II. PARTICIPATION	7
Section 2.01. Eligibility	7
ARTICLE III. EMPLOYEE DEFERRED COMPENSATION	8
Section 3.01. Application	8
Section 3.02. Deferrals Of Base Compensation	8
Section 3.03. Deferrals of Annual Incentive Awards	8
Section 3.04. Deferral of LTIP Awards	9
Section 3.05. Matching Contribution Credits	9
Section 3.06. Defined Contribution Restoration and Age/Service Point Credits	10
Section 3.07. SERP Credits	11
Section 3.08. Other Deferrals and Credits	12
Section 3.09. Involuntary Termination of Deferral Elections	12
ARTICLE IV. DIRECTOR DEFERRED COMPENSATION	13
Section 4.01. Application	13
Section 4.02. Deferrals Of Director Fees	13
Section 4.03. Director Deferred Stock Units	13
Section 4.04. Involuntary Termination of Deferral Elections	14
ARTICLE V. PARTICIPANT ACCOUNTS, RESERVE ACCOUNT A, RESERVE ACCOUNT B, AND STOCK UNITS ACCOUNTS	15
Section 5.01. Participant Accounts	15
Section 5.02. Reserve Account A	15
Section 5.03. Reserve Account B	16
Section 5.04. Stock Units	16
Section 5.05. Special Rules Applicable to Restricted Stock or Stock Unit Deferrals	19
ARTICLE VI. ACCOUNTING AND HYPOTHETICAL INVESTMENT ELECTIONS	20
Section 6.01. Hypothetical Investment of Participant Accounts	20
Section 6.02. Accounts are For Record Keeping Purposes Only	22
Section 6.03. Merger with Wisconsin Energy Corporation and Cancellation of Stock Units	22
ARTICLE VII. DISTRIBUTION OF PRE-2005 ACCOUNT	23
Section 7.01. Distribution Election	23
Section 7.02. Modified Distribution Election	24
Section 7.03. Calculation of Annual Distribution Amount	24
Section 7.04. Time of Distribution	25
Section 7.05. Single Sum Distribution at the Committee’s Option	25
ARTICLE VIII. DISTRIBUTION OF POST-2004 ACCOUNT	26
Section 8.01. Distribution Election	26
Section 8.02. Modified Distribution Election	27
Section 8.03. Calculation of Annual Distribution Amount	27

i

Exhibit 10.1

Section 8.04. Time of Distribution	28
Section 8.05. Automatic Single Sum Distribution	28
Section 8.06. Distributions For Employment Tax Obligations	28
ARTICLE IX. RULES WITH RESPECT TO INTEGRYS STOCK AND INTEGRYS STOCK UNITS	29
Section 9.01. Application	29
Section 9.02. Relationship to Shares Authorized Under Omnibus Plan	29
Section 9.03. Transactions Affecting Integrys Stock	29
Section 9.04. No Shareholder Rights With Respect to Stock Units	29
ARTICLE X. SPECIAL RULES APPLICABLE IN THE EVENT OF A CHANGE IN CONTROL OF THE COMPANY	30
Section 10.01. Application	30
Section 10.02. Definitions	30
Section 10.03. Amendments in Connection with a Change in Control	31
Section 10.04. Acceleration of Certain Vesting	33
Section 10.05. Maximum Payment Limitation	33
Section 10.06. Resolution of Disputes	34
ARTICLE XI. GENERAL PROVISIONS	35
Section 11.01. Administration	35
Section 11.02. Restrictions to Comply with Applicable Law	35
Section 11.03. Claims Procedures	35
Section 11.04. Participant Rights Unsecured	36
Section 11.05. Income Tax Withholding	37
Section 11.06. Amendment or Termination of Plan	37
Section 11.07. Administrative Expenses	38
Section 11.08. Effect on Other Employee Benefit Plans	38
Section 11.09. Successors and Assigns	38
Section 11.10. Right of Offset	38
Section 11.11. Amounts Accumulated Under Peoples Energy Plans	38
Section 11.12. Miscellaneous Distribution Rules	39

ii

Exhibit 10.1

INTEGRYS ENERGY GROUP, INC.

DEFERRED COMPENSATION PLAN

The purpose of the Integrys Energy Group, Inc. Deferred Compensation Plan (the “Plan”) has been to promote the best interests of Integrys Energy Group, Inc., the predecessor of Integrys Holding, Inc. (the “Company”), and its stockholders by attracting and retaining key management employees and non-employee directors possessing a strong interest in the successful operation of the Company and its subsidiaries or affiliates and encouraging their continued loyalty, service and counsel to the Company and its subsidiaries or affiliates. The Plan is amended and restated effective January 1, 2016, as set forth herein.

Except as expressly provided herein, the Plan, as herein amended and restated, applies to (i) those employees who are actively employed by the Company or a Participating Employer on or after January 1, 2005 (the effective date of Internal Revenue Code Section 409A), and who are eligible to participate in the Plan, and (ii) non-employee directors of the Company and designated subsidiaries and affiliates with service as a director on or after January 1, 2005. Except as expressly provided herein, distribution of benefits to an employee who retired from or terminated employment with the Company and its Affiliates prior to January 1, 2005, or a director whose service with the Company and its Affiliates terminated prior to January 1, 2005, shall be governed by the terms of the Plan (or predecessor plan) as in effect on the date of the employee’s or director’s retirement or termination of employment or service.

Effective January 1, 2017, no new individuals shall become eligible to participate in the Plan. Except as expressly provided herein, deferrals and credits under the Plan shall not be made on compensation, awards or other remuneration earned for services performed after December 31, 2016.

Exhibit 10.1

ARTICLE I. DEFINITIONS AND CONSTRUCTION

Section 1.01. Definitions. The following terms have the meanings indicated below unless the context in which the term is used clearly indicates otherwise:

(a)    Account: The record keeping account or accounts maintained to record the interest of each Participant under Section 5.01 of the Plan.

(b)    Act: The Securities Act of 1933, as interpreted by regulations and rules issued pursuant thereto, all as amended and in effect from time to time. Any reference to a specific provision of the Act shall be deemed to include reference to any successor provision thereto.

(c)    Age/Service Point Contributions: The non-elective contributions that (i) are made by the Company or an Affiliate to the Qualified Defined Contribution Plan, (ii) are not contingent upon the Participant having made contributions to such plan, and (iii) the amount of which are based on the sum of the Participant’s age and years of service.

(d)    Affiliate: Except as otherwise provided in Section 10.02 for purposes of applying the provisions of Article X, a corporation, trade or business that, with the Company, forms part of a controlled group of corporations or group of trades or businesses under common control within the meaning of Code Section 414(b) and (c); provided that Code Section 414(b) and (c) shall be applied by substituting “at least fifty percent (50%)” for “at least eighty percent (80%)” each place it appears.

(e)    Annual Incentive Deferral: A deferral of a portion of an Eligible Employee’s annual incentive award in accordance with Section 3.03.

(f)    Base Compensation: The base salary or wage payable by a Participating Employer to an Eligible Employee for services performed prior to reduction for contributions by the Eligible Employee to this Plan or pre-tax or after-tax contributions by the Eligible Employee to any other employee benefit plan maintained by a Participating Employer, but exclusive of extraordinary payments such as overtime, bonuses, incentive pay, meal allowances, reimbursed expenses, termination pay, moving pay, commuting expenses, severance pay, non-elective deferred compensation payments or accruals, stock options or other equity grants or awards, or the value of employer-provided fringe benefits or coverage, all as determined in accordance with such uniform rules, regulations or standards as may be prescribed by the Committee.

(g)    Base Compensation Deferral: A deferral of a portion of an Eligible Employee’s Base Compensation in accordance with Section 3.02.

(h)    Beneficiary: The person or entity designated by a Participant to be his or her beneficiary for purposes of this Plan. If a Participant designates his or her spouse as a beneficiary, such beneficiary designation automatically shall become null and void, with respect to any undistributed portion of the Participant’s Account, on the date that the Committee obtains actual written notice of the Participant’s divorce or legal separation from such spouse; provided that neither the Plan nor the Committee shall be liable to any Beneficiary for the payments that have been made to such spouse prior to the date the Committee is notified in writing of such divorce or legal separation from such spouse. If a valid designation of beneficiary is not in effect at the time of the Participant’s death, the estate of the Participant is deemed to be the sole beneficiary. If a beneficiary dies while entitled to receive distributions from the Plan, any remaining payments shall be paid to the estate of that beneficiary. Beneficiary designations shall be in writing, filed with the Committee, and in such form as the Committee may prescribe for this purpose.

(i)    Board: The Board of Directors of the Company.

(j)    Cause: Termination by the Company or an Affiliate of a Participant’s employment in connection with or following a Change in Control shall be limited to the following:

2

Exhibit 10.1

(A)    the engaging by the Participant in intentional conduct not taken in good faith which has caused demonstrable and serious financial injury to the Company and/or an Affiliate, as evidenced by a determination in a binding and final judgment, order or decree of a court or administrative agency of competent jurisdiction, in effect after exhaustion or lapse of all rights of appeal, in an action, suit or proceeding, whether civil, criminal, administrative or investigative;

(B)    conviction of a felony (as evidenced by binding and final judgment, order or decree of a court of competent jurisdiction, in effect after exhaustion of all rights of appeal) which substantially impairs the Participant’s ability to perform his duties or responsibilities;

(C)    continuing willful and unreasonable refusal by the Participant to perform the Participant’s duties or responsibilities (unless significantly changed without the Participant’s consent); or

(D)    material violation of the Company’s Code of Conduct.

(k)    Chief Executive Officer: The Chief Executive Officer of WEC Energy Group, Inc.

(l)    Code: The Internal Revenue Code of 1986, as interpreted by regulations and rulings issued pursuant thereto, all as amended and in effect from time to time. Any reference to a specific provision of the Code shall be deemed to include reference to any successor provision thereto.

(m)    Committee: An internal administrative committee appointed by the Chief Executive Officer to administer the Plan in accordance with Article XI. Prior to the Merger Date, the Committee was the Compensation Committee of the Board.

(n)    Company: Integrys Holding, Inc. and any successor to all or substantially all of the Company's assets or business. Prior to the Merger Date, the Company was known as Integrys Energy Group, Inc. Prior to February 21, 2007, the Company was known as WPS Resources Corporation.

(o)    Defined Contribution Restoration Credits: See Section 3.06(b).

(p)    Director: A non-employee member of the Board, a non-employee member of the board of directors of an Affiliate who is designated for participation by the Board, and where the context so requires, a former director entitled to receive a benefit hereunder.

(q)    Director Deferral: A deferral by a Director of a portion of his or her Director Fees in accordance with Section 4.02.

(r)    Director Fees: Those fees that are payable in cash to a Director for services rendered on the Board (including attendance fees and fees for serving as a committee chair) or for service on the board of directors of an Affiliate. The term Director Fees does not include fees that are automatically credited to the Director in the form of Stock Units pursuant to Section 4.03 of this Plan or pursuant to the Omnibus Plan

(s)    Disability: The inability of a Participant to engage in any substantial gainful activity by reason of a medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months, as determined by the Committee.

(t)    Eligible Employee: A common law employee of a Participating Employer who is classified as eligible for pay grade 16 or above and, where the context so requires, a former employee entitled to receive a benefit hereunder. Prior to the Merger Date, an Eligible Employee was a common law employee of a Participating Employer who was designated by the Committee as being eligible to participate in the Plan.

3

Exhibit 10.1

(u)    ERISA: The Employee Retirement Income Security Act of 1974, as interpreted by regulations and rulings issued pursuant thereto, all as amended and in effect from time to time. Any reference to a specific provision of ERISA shall be deemed to include reference to any successor provision thereto.

(v)    ESOP: The Integrys Energy Group Employee Stock Ownership Plan as amended from time to time, or any successor to such plan..

(w)    Exchange Act: The Securities Exchange Act of 1934, as interpreted by regulations and rules issued pursuant thereto, all as amended and in effect from time to time. Any reference to a specific provision of the Exchange Act shall be deemed to include reference to any successor provision thereto.

(x)    Integrys Stock: The common stock, $1.00 par value, of Integrys Energy Group, Inc.

(y)    Investment Options: The hypothetical investment accounts described in Article V and such other investment options as the Committee may from time to time determine (which may, but need not, be based upon one or more of the investment options available under a defined contribution plan sponsored by the Company or an Affiliate). Effective on or after the Merger Date, Stock Units are not an available Investment Option under the Plan, except for Locked Stock Units.

(z)    Long-Term Incentive Plan Deferral or LTIP Deferral: A deferral of a portion of the performance units, restricted stock, restricted stock unit, dividends or other stock-based compensation awarded to an Eligible Employee under the Omnibus Plan or the Performance Unit Plan, in accordance with Section 3.04.

(aa)    Matching Contribution Credits: See Section 3.05.

(bb)    Merger Date: The date of the closing of the Agreement and Plan of Merger dated as of June 22, 2014, between Integrys Energy Group, Inc. and Wisconsin Energy Corporation, which is June 29, 2015.

(cc)    Omnibus Plan: The WEC Energy Group Omnibus Stock Incentive Plan, as amended from time to time, and any successor to such plan. Prior to the Merger Date, Omnibus Plan referred to the Integrys Energy Group, Inc. 2014 Omnibus Incentive Compensation Plan, the Integrys Energy Group, Inc. 2010 Omnibus Incentive Compensation Plan, or as required by the context, any predecessor or successor to such plan.

(dd)    Participant: An Eligible Employee, or as required by the context, a Director or former Eligible Employee with an undistributed Account balance under the Plan.

(ee)    Participating Employer: The Company and each Affiliate that, with the consent of the Committee, participates in the Plan for the benefit of one or more Participants. Effective as of the Merger Date, the following Affiliates are Participating Employers: Peoples Energy LLC, The Peoples Gas Light and Coke Company, North Shore Gas Company, WEC Business Services, LLC (with respect to only former employees of Integrys Business Support, LLC), Michigan Gas Utilities Corporation, Minnesota Energy Resources Corporation, Wisconsin Public Service Corporation, Integrys Transportation Fuels, LLC.

(ff)    Pension Restoration Plan: The Integrys Energy Group, Inc. Pension Restoration and Supplemental Retirement Plan, as amended and in effect from time to time.

(gg)    Pre-2005 Account: See Section 5.01.

(hh)    Post-2004 Account: See Section 5.01.

(ii)    Performance Unit Plan: The WEC Energy Group Performance Unit Plan, as amended from time to time, or any successor to such plan.

(jj)    Qualified Defined Contribution Plan: The Integrys Energy Group 401(k) Plan for Administrative Employees, as amended from time to time, or any successor to such plan.

4

Exhibit 10.1

(kk)    Separation from Service: A Participant’s Separation from Service shall occur when the Company (and its Affiliates) and the Participant reasonably anticipate that no further services (either as an employee or as an independent contractor) will be performed by the Participant for the Company (or an Affiliate) after a certain date, or that the level of bona fide services the Participant will perform for the Company (or the Affiliate) after such date (either as an employee or as an independent contractor) will permanently decrease to no more than twenty percent (20%) of the average level of bona fide services performed by the Participant (whether as an employee or independent contractor) for the Company or an Affiliate over the immediately preceding thirty-six (36) month period (or such lesser period of actual service). A Participant is not considered to have incurred a Separation from Service if the Participant is absent from active employment due to military leave, sick leave or other bona fide leave of absence and if the period of such leave does not exceed the greater of (i) six (6) months, or (ii) the period during which the Participant’s right to reemployment by the Company or an Affiliate is provided either by statute or by contract; provided that if the leave of absence is due to a medically determinable physical or mental impairment that can be expected to result in death or last for a continuous period of not less than six (6) months, where such impairment causes the Participant to be unable to perform the duties of his or her position of employment or any substantially similar position of employment, the leave may be extended for up to twenty-nine (29) months without causing a Separation from Service.

(ll)    SERP Credits: See Section 3.07.

(mm)    Special Defined Contribution Credits: In the case of a Participant who is in the limited class of Participants who are eligible for participation in the Supplemental Retirement Benefit Component of the Pension Restoration Plan, the credits made to a Participant’s Account under Sections 3.05, 3.06 and 3.07 of this Plan with respect to the 2013 -2017 calendar years, together with investment gains or losses thereon. Special Defined Contribution Credits are determined by reference to the calendar year to which the Special Defined Contribution Credit relates, which might be different than the calendar year in which the Special Defined Contribution Credit is physically allocated to the Participant’s Account, e.g., the age/service restoration credit for the 2012 calendar year is not a Special Defined Contribution Credit even though the credit was physically allocated in early 2013, and conversely, the age/service restoration credit for the 2017 calendar year will be a Special Defined Contribution Credit even though the credit will be physically allocated in early 2018. Effective as of January 1, 2016, Special Defined Contribution Credits are no longer made under the Plan because the limited class of Participants eligible for these credits have terminated employment with the Company and its Affiliates.

(nn)    Stock: WEC Energy Group, Inc. common stock. Prior to the Merger Date, Stock means Integrys Stock.

(oo)    Stock Units: The hypothetical shares of Stock that are credited to a Participant’s Stock Unit Accounts in accordance with Section 5.04. A Participant’s Stock Units are further classified as Locked Stock Units or Discretionary Stock Units, in accordance with Section 5.04.

(pp)    Stock Unit Account: The portion of a Participant’s overall Account that is deemed to be invested in Stock Units, as described in Section 5.04.

(qq)    Trust: Any fund created by a rabbi trust agreement established by the Company referencing the Plan, as amended from time to time.

(rr)    Valuation Date: Each day that the New York Stock Exchange is open for business or at such other times as the Committee may prescribe.

Section 1.02. Construction and Applicable Law.

(a)    Wherever any words are used in the masculine, they shall be construed as though they were used in the feminine in all cases where they would so apply; and wherever any words are use in the singular or the plural, they shall be construed as though they were used in the plural or the singular, as the case may be, in all cases where they would so apply. Titles of articles and sections are for general information only, and the Plan is not to be construed by reference to such items.

5

Exhibit 10.1

(b)    This Plan is intended to be a plan of deferred compensation maintained for a select group of management or highly compensated employees as that term is used in ERISA, and shall be interpreted so as to comply with the applicable requirements thereof. In all other respects, the Plan is to be construed and its validity determined according to the laws of the State of Wisconsin, without regard to the principle of conflict of law, to the extent such state laws are not preempted by federal law. In case any provision of the Plan is held illegal or invalid for any reason, the illegality or invalidity will not affect the remaining part of the Plan, but the Plan shall, to the extent possible, be construed and enforced as if the illegal or invalid provision had never been inserted.

6

Exhibit 10.1

ARTICLE II. PARTICIPATION

Section 2.01. Eligibility.

(a)    A Director shall be eligible to participate in the Plan only if the Director was a Participant on the Merger Date. Prior to the Merger Date, a Director became eligible to participate in the Plan immediately upon becoming a member of the Board.

(b)    An employee shall be eligible to participate in the Plan only if the employee is employed by a Participating Employer and if the employee is either (i) an Eligible Employee on the Merger Date, or (ii) classified as eligible for pay grade 16 or above. Prior to the Merger Date, an employee was eligible to participate in the Plan only if the employee was employed by a Participating Employer and the employee was designated as an Eligible Employee by the Committee, in its sole discretion, for participation in the entire Plan or any part thereof.

7

Exhibit 10.1

ARTICLE III. EMPLOYEE DEFERRED COMPENSATION

Section 3.01. Application. This Article III applies to Participants other than Directors.

Section 3.02. Deferrals Of Base Compensation.

(a)    Amount. No Participant may defer Base Compensation paid on or after January 1, 2017. Prior to January 1, 2017, a Participant may elect, in such form and manner as the Committee may prescribe, to defer payment of a portion of the Base Compensation that would otherwise be paid to the Participant. A Participant’s election shall specify the percentage (in increments of one percent (1%) to a maximum of eighty percent (80%)) of the Participant’s Base Compensation that the Participant wishes to defer; provided that with respect to periods prior to January 1, 2011, the amount deferred was subject to the maximum deferral limitations set forth in the Plan at the time of the Participant’s deferral election.

(b)    Initial Deferral Election. In the case of a Participant who has been designated for participation for the first time (and who has not previously been designated as being eligible for participation in another deferred compensation plan that is required to be aggregated with this Plan for purposes of Code Section 409A) and who completes a deferral election within thirty (30) days of becoming eligible to participate in the Plan, the Participant’s validly executed deferral election shall become effective with respect to services to be performed starting with the first pay period commencing after the date the election is filed with the Committee.If the Participant does not submit a deferral election during the initial thirty (30) day election period, the Participant may thereafter elect to defer payment of Base Compensation by submitting a validly executed deferral election to the Committee, but the election shall become effective and shall apply only to Base Compensation for the calendar year following the calendar year during which the election is received and accepted by the Committee. A Participant’s deferral election, once effective, shall remain in effect until modified by the Participant in accordance with subsection (c) below or otherwise revoked in accordance with Plan rules.

(c)    Revised Deferral Election. Except to the extent that the Committee is permitted (and elects) to give earlier effect to a Participant’s revocation or revision to his or her deferral election in accordance with regulations promulgated by the Secretary of the Treasury under Code Section 409A, a Participant’s deferral election, once effective with respect to a calendar year, may not be revoked or modified with respect to Base Compensation for that calendar year. A Participant may modify his or her then current deferral election by filing a revised deferral election form, properly completed and signed, with the Committee. However, except to the extent that the Committee is permitted (and elects) to give earlier effect to a Participant’s revised election in accordance with regulations promulgated by the Secretary of the Treasury under Code Section 409A, the revised election will be effective only with respect to Base Compensation for the calendar year following the calendar year during which the revised election is received and accepted by the Committee. A Participant’s revised deferral election, once effective, shall remain in effect until again modified by the Participant under this subsection (c) or otherwise revoked in accordance with Plan rules.

(d)    Base Compensation Paid Following Year End For the Payroll Period That Includes December 31. For purposes of applying a Participant’s deferral election, Base Compensation paid after December 31 of a calendar year that is attributable solely to services performed during the payroll period that includes December 31, if paid in accordance with the normal timing arrangement by which a Participating Employer compensates employees for services rendered, is treated as Base Compensation for services performed in the subsequent calendar year, even though part or all of the Participant’s services might have been performed in the prior calendar year.

Section 3.03. Deferrals of Annual Incentive Awards. No Participant may defer an annual incentive award paid with respect to a calendar year ending after December 31, 2016. For calendar years beginning prior to January 1, 2017, a Participant may elect, in such form and manner as the Committee may prescribe, to defer payment of a portion of the annual cash incentive that is awarded and that would otherwise be paid to the Participant with respect to any year. A Participant’s election shall specify the percentage (in increments of one percent (1%) to a maximum of eighty percent (80%)) of the Participant’s annual cash incentive that the Participant wishes to defer; provided that with respect to periods prior to January 1, 2011, the amount deferred was subject to the maximum deferral limitations set forth in the Plan at the time of the Participant’s deferral election. In the case of any award

8

Exhibit 10.1

that is not performance-based compensation for purposes of Code Section 409A, a validly executed deferral election shall be effective only if the deferral election is received and accepted by the Committee prior to the last day of the calendar year preceding the calendar year for which the annual incentive is paid, or by such other time as provided in regulations promulgated by the Secretary of the Treasury. In the case of any award that is performance-based compensation for purposes of Code Section 409A, a validly executed deferral election shall become effective with respect to the annual incentive that may be awarded to the Participant with respect to a calendar year if the Participant’s deferral election is received and accepted by the Committee at least six (6) months prior to the end of the performance period for the annual incentive, or by such earlier (but not later) date as the Committee may establish. A Participant’s election to defer part of an annual incentive award becomes irrevocable at the end of the permitted elected period, and the Participant may not thereafter revoke or modify his or her election. A Participant’s election to defer part of an annual incentive award shall be effective only for the annual incentive to which the election relates, and shall not carry over from year to year or from incentive payment to incentive payment.

Section 3.04. Deferral of LTIP Awards. A Participant may elect, in such form and manner as the Committee may prescribe, to defer payment of a portion of any performance unit, restricted stock, restricted stock unit, dividends or other stock-based compensation awarded to the Participant prior to January 1, 2017 under the Omnibus Plan or the Performance Unit Plan. A Participant’s election shall specify the whole number of units (up to eighty percent (80%) of the Participant’s award) that the Participant wishes to defer; provided that with respect to periods prior to January 1, 2011, the amount deferred was subject to the maximum deferral limitations set forth in the Plan at the time of the Participant’s deferral election. In the case of any award that is not performance-based compensation for purposes of Code Section 409A, a validly executed deferral election shall be effective only if the deferral election is received and accepted by the Committee in accordance with rules established by the Committee pursuant to Code Section 409A. In the case of any award that is performance-based compensation for purposes of Code Section 409A, a validly executed deferral election shall become effective with respect to units to be earned by the Participant with respect to any Omnibus Plan or Performance Unit Plan performance period if the Participant’s deferral election is received and accepted by the Committee at least six (6) months prior to the end of such performance period or by such earlier (but not later) date as the Committee may establish. A Participant’s election to defer part of an LTIP award becomes irrevocable at the end of the permitted elected period, and the Participant may not thereafter revoke or modify his or her election. A Participant’s election to defer an award shall be effective only for the Omnibus Plan or Performance Unit Plan award (as applicable), service period or performance period to which the election relates, and a Participant’s election does not carry over from award to award, performance period to performance period or from service period to service period.

Section 3.05. Matching Contribution Credits.

(a)    Allocation of Credits. No Matching Contribution Credits shall be allocated to a Participant's Account for calendar years ending after December 31, 2016. For calendar years beginning before January 1, 2017, a Participant who is a participant in the Qualified Defined Contribution Plan and who makes Base Compensation Deferrals and/or Annual Incentive Deferrals under this Plan, shall be entitled to a Matching Contribution Credit if the Participant’s election to make Base Compensation Deferrals and/or Annual Incentive Deferrals under this Plan in any year cause the Participant to receive a smaller matching contribution under the ESOP than the matching contribution that the Participant would have received under the ESOP for that year if the Participant had instead elected not to defer any portion of the Participant’s Base Compensation or annual incentive award. The Matching Contribution Credit will be determined annually and will be allocated to the Participant’s Account as of December 31 of each year. The Matching Contribution Credit will equal the difference (if any) between:

(i) The value of the matching contribution that the Participant would have received under the ESOP for the calendar year, based on amounts actually contributed to the Qualified Defined Contribution Plan, if Base Compensation Deferrals and Annual Incentive Deferrals made by the Participant under this Plan were instead treated as “compensation” under the ESOP for purposes of calculating the Participant’s maximum matching contribution under the ESOP; provided that all limits and restrictions otherwise imposed under the Qualified Defined Contribution Plan and the ESOP, including the maximum

9

Exhibit 10.1

compensation limit under Section 401(a)(17) of the Code, shall continue to apply; and

(ii) The value of the matching contribution actually received by the Participant for that year under the ESOP.

Notwithstanding anything to the contrary, a Participant will not be eligible for Matching Contribution Credits if (x) the Participant has been specifically excluded by the Committee, or (y) the Participant is covered under an employment contract or agreement that excludes the Participant from receiving pension restoration, supplemental retirement or similar restoration benefits or credits, or (z) the Participant is covered under an employment contract or agreement that references the Participant’s participation in the Plan generally but does not specifically provide for the Participant as being eligible for pension restoration, supplemental retirement or similar restoration benefits or credits.

(b)    Investment of Credits. Matching Contribution Credits with respect to periods prior to January 1, 2008 will be credited to the Participant in the form of Locked Stock Units under Section 5.04(b). Matching Contribution Credits with respect to periods after December 31, 2007 shall be credited to the Participant’s Account in accordance with the Participant’s investment direction under Section 6.01(a).

Section 3.06. Defined Contribution Restoration and Age/Service Point Credits.

(a)    Eligibility. No Defined Contribution Restoration Credits or Age/Service Point Credits shall be allocated to a Participant's Account for calendar years ending after December 31, 2016. For calendar years beginning before January 1, 2017, a Participant who is eligible to make contributions to the Qualified Defined Contribution Plan may be eligible to receive an additional credit to his or her Account for each year, in accordance with the rules of this Section. Notwithstanding the foregoing, a Participant will not be eligible for Defined Contribution Restoration Credits or Age/Service Point Credits if (i) the Participant has been specifically excluded by the Committee, or (ii) the Participant is covered under an employment contract or agreement that excludes the Participant from receiving pension restoration, supplemental retirement or similar restoration benefits or credits, or (iii) the Participant is covered under an employment contract or agreement that references the Participant’s participation in the Plan generally but does not specifically provide for the Participant as being eligible for pension restoration, supplemental retirement or similar restoration benefits or credits.

(b)    Amount of Additional Credits.

(i) Defined Contribution Credits. Effective January 1, 2013, if the Participant for any year is eligible to make Participant elective deferral or other contributions to the Qualified Defined Contribution Plan and to receive a matching contribution under the ESOP with respect to such amounts, the Participant shall receive a Defined Contribution Restoration Credit under this Plan equal to five percent (5%) of the Participant’s compensation for the year in excess of the Code Section 401(a)(17) limitation in effect for such year. For this purpose, the Participant’s compensation shall be the Participant’s compensation as defined in the Qualified Defined Contribution Plan, except that Base Compensation Deferrals and Annual Incentive Deferrals made by the Participant under this Plan shall be treated as if they had been paid to the Participant in cash. This credit is to approximately reflect the matching contribution that the Participant could have received under ESOP if the Participant had been permitted to make contributions to the Qualified Defined Contribution Plan without being subject to the limitations under Code Sections 401(a)(17), 402(g), 415 or any limitation under the Code. The Defined Contribution Restoration Credit will be determined annually and will be allocated to the Participant’s Account as of December 31 of each year.

10

Exhibit 10.1

(ii) Age/Service Point Contribution Credit. If the Participant for any year is eligible for and receives an Age/Service Point Contribution under the Qualified Defined Contribution Plan and if the Participant’s allocation under the Qualified Defined Contribution Plan is limited because of the limitations of Code Section 401(a)(17) or 415, the Participant shall receive an additional credit under this Plan equal to the difference between (A) the Age/Service Point Contribution that would have been allocated to the Participant for the year under the Qualified Defined Contribution Plan if the Code Section 401(a)(17) and 415 limitations did not apply and if Base Compensation and Annual Incentive Deferrals made by the Participant under this Plan during such year are treated as if they had been paid to the Participant in cash, and (B) the Age/Service Point Contribution to which the Participant is actually entitled for such year under the Qualified Defined Contribution Plan. The Age/Service Point Contribution credit will be determined annually and will be allocated to the Participant’s Account no later than the end of the first quarter of the calendar year following the year for which the credit is being determined.

(c)    Vesting. A Participant will have a vested and non-forfeitable right to the credits made under this Section, and any deemed investment gains or losses, if the Participant terminates employment with the Company and its Affiliates after having completed at least three (3) years of service. If the Participant terminates employment prior to completing three (3) years of service, the Participant’s credits under this Section, together with all deemed investment gains or losses, shall be forfeited.

Section 3.07. SERP Credits.

(a)    Eligibility. Effective as of January 1, 2016, SERP Credits are no longer made under the Plan. Prior to January 1, 2016, this Section was limited to Participants who have been specifically selected by the Committee to receive SERP Credits under this Section. Even though the Committee may have designated an employee as being generally eligible for the Plan, or even though an employee’s employment contract or agreement may refer to the employee as being generally eligible for the Plan, the employee shall not be eligible for SERP Credits described in this Section unless the Committee has specifically designated the employee as being eligible for such credits

(b)    Amount of SERP Credit. If the Committee has designated a Participant as being eligible to receive a SERP Credit under this Section, the Committee shall also designate the percentage of the Participant’s base salary and annual incentive that is to be credited to the Participant’s Account as a SERP Credit; provided that if the Committee designates a Participant as being eligible to receive a SERP Credit under this Section but the Committee does not affirmatively designate the applicable percentage of the Participant’s base salary and annual incentive to be credited, the applicable percentage shall be twelve percent (12%) until the Committee affirmatively designates a different percentage. For this purpose, any Base Compensation and Annual Incentive Deferrals made by the Participant under this Plan are treated as if they had been paid to the Participant in cash, i.e., the SERP Credit is calculated based upon the Participant’s base salary and annual incentive prior to reduction for any Base Compensation and Annual Incentive Deferrals made by the Participant. The Committee may from time to time change the amount of the SERP Credit applicable to any Participant, and the fact that a Participant receives a SERP Credit for any year (or portion of a year) does not provide the Participant with any right or entitlement to a SERP Credit with respect to any other period. Any changes in the SERP Credit to which a Participant receives shall be made in accordance with the requirements of Code Section 409A. The SERP Credit will be determined annually and will be allocated to the Participant’s Account no later than the end of the first quarter of the calendar year following the year for which the credit is being determined.

(c)    Vesting. A Participant will have a vested and non-forfeitable right to the credits made under this Section, and any deemed investment gains or losses, if the Participant terminates employment with the Company and its Affiliates after having completed at least five (5) years of service. If the Participant terminates employment

11

Exhibit 10.1

prior to completing five (5) years of service, the Participant’s credits under this Section, together with all deemed investment gains or losses, shall be forfeited.

Section 3.08. Other Deferrals and Credits. The Committee, in its discretion, may, with respect to any Participant, determine that the Participant is eligible to make deferrals with respect to additional components of the Participant’s remuneration or receive employer contribution credits in addition to the credits described herein. In no event, however, shall the Committee authorize such additional deferrals or credits unless the Committee has first determined that the deferrals or credits have been elected or authorized in a manner that will not result in the imposition of tax under Code Section 409A.

Section 3.09. Involuntary Termination of Deferral Elections. A Participant’s deferral elections shall be automatically revoked upon the Participant’s termination of employment from the Participating Employers, unless the Committee determines otherwise in accordance with the requirements of Code Section 409A. In addition, and subject to Code Section 409A, a Participant’s deferral election will terminate if the Committee determines that the Participant is no longer eligible to participate in the Plan or that revocation of a Participant’s eligibility is necessary or desirable in order for the Plan to qualify under ERISA as a plan of deferred compensation for a select group of management or highly compensated employees.

12

Exhibit 10.1

ARTICLE IV. DIRECTOR DEFERRED COMPENSATION

Section 4.01. Application. This Article IV applies prior to the Merger Date and only to Directors. A Director shall participate in the Plan only if the Director was a Participant on the Merger Date. Effective on and after the Merger Date, no deferrals of Director Fees or Stock Units granted to Directors are permitted under the Plan.

Section 4.02. Deferrals Of Director Fees.

(a)    Amount. A Director may elect, in such form and manner as the Committee may prescribe, to defer payment of a portion of the Director Fees that would otherwise be paid in cash to the Director. A Director’s election shall specify the percentage (in increments of one percent (1%) to a maximum of one hundred percent (100%)) of the Director Fees that the Director wishes to defer.

(b)    Initial Deferral Election. In the case of a Director who has become eligible for participation in the Plan for the first time (and who has not previously been designated as being eligible for participation in another deferred compensation plan that is required to be aggregated with this Plan for purposes of Code Section 409A), and who completes a deferral election within thirty (30) days of becoming eligible to participate in the Plan, the Director’s validity executed deferral election shall become effective with respect to services to be performed starting with the first pay period commencing after the date the election is filed with the Committee. If the Director does not submit an initial deferral election during the initial thirty (30) day election period, the Director may thereafter elect to defer the payment of Director Fees by submitting a validly executed deferral election to the Committee, but the election shall become effective and shall apply only to Directors Fees for the calendar year following the calendar year in which the election is received and accepted by the Committee. A Director’s deferral election, once effective, shall remain in effect until modified by the Director in accordance with subsection (c) below or otherwise revoked in accordance with Plan rules.

(c)    Revised Deferral Election. Except to the extent that the Committee is permitted (and elects) to give earlier effect to a Director’s revocation or revision to his or her deferral election in accordance with regulations promulgated by the Secretary of the Treasury under Code Section 409A, a Director’s deferral election, once effective with respect to a calendar year, may not be modified or revoked with respect to Director Fees for that calendar year. A Director may modify his or her then current deferral election by filing a revised deferral election form, properly completed and signed, with the Committee. However, except to the extent that the Committee is permitted (and elects) to give earlier effect to a Participants revision to his or her deferral election in accordance with regulations promulgated by the Secretary of the Treasury under Code Section 409A, the revised election will be effective with respect to Director Fees for the calendar year following the calendar year during which the revised election is received and accepted by the Committee. A Director’s revised deferral election, once effective, shall remain in effect until again modified by the Director in accordance with this subsection (c) or otherwise revoked in accordance with Plan rules.

(d)    Director Fees Paid Following Year End For the Period That Includes December 31. For purposes of applying a Director’s deferral election, Director Fees paid after December 31 of a calendar year that are attributable solely to services performed during the period that includes December 31, if paid in accordance with the normal timing arrangement by which a Participating Employer compensates Directors for services rendered, is treated as Director Fees for services performed in the subsequent calendar year, even though part or all of the Director’s services might have been performed in the prior calendar year.

Section 4.03. Director Deferred Stock Units.

(a)    The Board may from time to time direct that a portion of the remuneration to be earned by a Director for service on the Board shall be credited under this Plan in the form of Stock Units. Effective January 1, 2011, any such grant of Stock Units under this Section 4.03 shall be made under the Omnibus Plan, shall be subject to all of the rules of the Omnibus Plan and shall be charged against the pool of shares available under the Omnibus Plan, but unless otherwise determined by the Board at the time of grant, shall be credited (for record-keeping purposes) under this Plan and shall be subject to the distribution provisions of this Plan. Except to the extent that the Committee is permitted (and elects) to give earlier effect to a direction in accordance with regulations promulgated

13

Exhibit 10.1

by the Secretary of the Treasury under Code Section 409A, any such direction shall be effective with respect to remuneration to be earned by the Director on and after January 1 of the calendar year following the date of such direction, and shall continue in effect through December 31 of the calendar year in which modified or revoked by a subsequent direction of the Board. The provisions of this Section 4.03 shall not apply to Stock Units credited as a result of a Director’s deferral of cash fees pursuant to Section 4.02.

Section 4.04. Involuntary Termination of Deferral Elections. A Director’s deferral elections shall be automatically revoked upon the Director’s termination of service with the Participating Employers, unless the Committee determines otherwise in accordance with Code Section 409A.

14

Exhibit 10.1

ARTICLE V. PARTICIPANT ACCOUNTS, RESERVE ACCOUNT A, RESERVE ACCOUNT B, AND STOCK UNITS ACCOUNTS

Section 5.01. Participant Accounts. A record keeping Account will be maintained to record the interest of each Participant under the Plan. An Account is established for record keeping purposes only and not to reflect the physical segregation of assets on the Participant’s behalf. A Participant’s Account will consist of separate balances to record a Participant’s interest in each of the Investment Options, and to record the portion of a Participant’s overall Account that is attributable to deferrals and contribution credits made and vested prior to January 1, 2005, together with any earnings or loss thereon through the date of distribution from the Plan (the “Pre-2005 Account”), and the portion of the Participant’s overall Account that is attributable to deferrals and contribution credits made or vested after December 31, 2004, together with any earnings or loss thereon through the date of distribution from the Plan (the “Post-2004 Account”). Further, a Participant’s Account will consistent of separate balances to record the portion (if any) of a Participant’s overall Account that is attributable to Special Contribution Credits (the account for such portion is subject to additional rules described in Sections 6.01(c) and 8.01(c)) or that is attributable to credits that are subject to a vesting schedule. The Committee (or its delegate) may direct that a Participant’s Account include such additional sub-accounts and balances as the Committee (or its delegate) may determine to be necessary or appropriate.

Section 5.02. Reserve Account A.

(a)    Limited Purpose Account. Reserve Account A is limited to compensation or director fees attributable to employment or service with Wisconsin Public Service Corporation and that were deferred by a Participant prior to January 1, 1996, together with attributed earnings on such deferrals. Except for attributed earnings as described below, no further deferrals, contributions or credits of any kind will be made to this account on behalf of a Participant, nor may a Participant transfer amounts from another Investment Option to Reserve Account A. A Participant may transfer amounts credited to Reserve Account A to another available Investment Option, but the transferred amount may not subsequently be transferred back to Reserve Account A.

(b)    Crediting of Interest Equivalent. Reserve Account A will be credited with an interest equivalent on the balance in the account from time to time during the year. Unless the Committee prescribes an alternate method, the annual interest equivalent rate (on a non-compounded basis) will be the greater of:

(i) six percent (6.0%); or

(ii) a rate equal to the consolidated return on common shareholders’ equity of the Company and all consolidated subsidiaries (ROE); provided, however, that unless the Committee determines otherwise, this Paragraph (ii) will not apply to a Participant following termination of employment if the Participant’s termination of employment with the Company and its Affiliates occurs prior to attainment of age fifty-five (55) and prior to the occurrence of a Change in Control (as defined in Section 10.02). For the months of April through September, ROE means the consolidated return on equity of the Company and all consolidated subsidiaries for the twelve (12) months ended on the preceding February 28 (or 29) as calculated pursuant to the Company’s standard accounting procedure for financial reporting to shareholders. For the months October through March, ROE means return on equity as described above for the twelve (12) months ended on the preceding August 31.

(c)    Revised Rate. Subject to Article X, the Committee may revise the interest equivalent rate or the manner in which it is calculated, but in no event shall the rate be less than six percent (6%) per annum. Any such revised rate shall be effective with the calendar month following such action by the Committee.

15

Exhibit 10.1

Section 5.03. Reserve Account B.

(a)    Availability. Reserve Account B is an available Investment Option only with respect to eligible deferrals or contribution credits made prior to April 1, 2008. Effective April 1, 2008, Reserve Account B is closed to new deferrals, contribution credits, or transfers from another Investment Option. A Participant may transfer amounts credited to Reserve Account B to another available Investment Option, but the transferred amount may not subsequently be transferred back to Reserve Account B.

(b)    Crediting of Interest Equivalent. Reserve Account B will be credited with an interest equivalent on the balance in the account from time to time during the year. Unless the Committee prescribes an alternate method, the annual interest equivalent rate (on a non-compounded basis) will be the greater of:

(i) six percent (6.0%); or

(ii) a rate equal to seventy percent (70%) of the consolidated return on common shareholders’ equity of the Company and all consolidated subsidiaries (ROE); provided, however, that unless the Committee determines otherwise, this Paragraph (ii) will not apply to a Participant following termination of employment if the Participant’s termination of employment with the Company and its Affiliates occurs prior to attainment of age fifty-five (55) and prior to the occurrence of a Change in Control (as defined in Section 10.02). For the months of April through September, ROE means the consolidated return on equity of the Company and all consolidated subsidiaries for the twelve (12) months ended on the preceding February 28 (or 29) as calculated pursuant to the Company’s standard accounting procedure for financial reporting to shareholders. For the months October through March, ROE means return on equity as described above for the twelve (12) months ended on the preceding August 31.

(c)    Revised Rate. Subject to Article X, the Committee may revise the interest equivalent rate or the manner in which it is calculated, but in no event shall the rate be less than six percent (6%) per annum. Any such revised rate shall be effective with the calendar month following such action by the Committee.

Section 5.04. Stock Units.

(a)    Locked and Discretionary Stock Units. For purposes of the Plan, the term “Locked Stock Units” refers to the portion of a Participant’s Account that has been credited to the Plan in the form of Stock Units with respect to which the Participant is not able to exercise investment discretion or otherwise cause such amounts to be transferred to an alternate Investment Option. The term “Discretionary Stock Units” refers to the portion of a Participant’s Account that, at any point in time, is deemed to be invested in Stock Units, but the Participant is permitted, in accordance with the rules of the Plan, to exercise investment discretion with respect to such amounts or to cause such amounts to be transferred to an alternate Investment Option. The Locked Stock Units are described in subsection (b) below. The Discretionary Stock Units are all Stock Units credited to the Participant’s Account, other than the Locked Stock Units. All Discretionary Stock Units and Locked Stock Units as of the Merger Date were canceled and converted into cash in accordance with Section 6.03. Effective after the Merger Date, Discretionary Stock Units are no longer available under the Plan and Locked Stock Units are limited to deferrals of restricted stock as described in subsection (b) below.

(b)    Locked Stock Units. Effective after the Merger Date, Stock Units attributable to deferral of Omnibus Plan restricted stock with vesting dates after the Merger Date are Locked Stock Units. Such Locked Stock Units consist of only Stock Units that may be credited to the Participant’s Account from this source; the deemed payment of dividends or other distributions on such Stock Units shall not be treated as additional Stock Units under the Plan. Prior to the Merger Date and the cancellation of all Stock Units under the Plan as of the Merger Date, these provisions applied: The following are Locked Stock Units, meaning that the Participant is not able to exercise investment discretion, either with respect to the Stock Units that may be credited to the Participant’s Account from

16

Exhibit 10.1

these sources, or with respect to any additional Stock Units that are credited as a result of the deemed payment of dividends or other distributions on such Stock Units:

(i) Stock Units attributable to deferrals or contribution credits made prior to June 30, 2001 that, at the time of the deferral or contribution credits, were allocated to a Stock Unit Account (“Prior Plan Stock Units”).

(ii) Stock Units attributable to Annual Incentive Deferrals made after June 30, 2001 and prior to April 1, 2008, if the Participant received the five percent (5%) premium for Annual Incentive Awards irrevocably directed to a Stock Unit Account (“Incentive Stock Units”).

(iii) Stock Units attributable to deferral of Omnibus Plan performance shares the final award for which was made after June 30, 2001 and prior to April 1, 2008 (“Incentive Stock Units”).

(iv) Stock Units attributable to deferral of Omnibus Plan restricted stock that became vested prior to April 1, 2008 (“Restricted Stock Units”).

(v) Stock Units attributable to deferral of Omnibus Plan restricted stock with vesting dates after March 31, 2008, but only until the date on which the Participant becomes vested in such Stock Units. When the Participant’s interest in the Stock Units becomes vested, such Stock Units will become Discretionary Stock Units.

(vi) Stock Units attributable to Matching Contribution Credits made with respect to periods prior to January 1, 2008 under Section 3.05 (“Matching Contribution Stock Units”).

(vii) Stock Units attributable to the portion of a Director’s compensation that, in accordance with Section 4.03, is automatically deemed to be invested in Stock Units with no ability on a part of an individual Director to elect an alternate form of deemed investment (“Director Stock Units”).

(viii) Any amounts credited in the form of Stock Units under a predecessor deferred compensation plan (including, without limitation, the deferred compensation plans of Peoples Energy Corporation, the predecessor to Peoples Energy, LLC), if the Participant did not have the right, under such predecessor plan, to direct that the amount be transferred to an alternate deemed investment.

(ix) Any other Stock Units that the Committee directs be treated as Locked Stock Units or that are required to be treated as Locked Stock Units pursuant to the terms of the employment contract, incentive program or other plan that sets forth the Participant’s entitlement to be credited with Stock Units under the Plan.

(c)    Crediting of Stock Units.

(i) Awards or Credits Already Expressed in the Form of Stock. With respect to any amount that is being credited under the Plan in the form of Stock Units and that, immediately prior to being credited to the Participant’s Stock Unit Account, is already expressed as an award of shares of Stock, e.g., Omnibus Plan performance shares or restricted

17

Exhibit 10.1

stock awards, the Participant will be credited, on a one-for-one basis, with a number of Stock Units equal to the number of shares of Stock that are being deferred or credited under the Plan.

(ii) Conversion of Other Awards or Credits to Stock Units. With respect to any amount that is being credited under the Plan in the form of Stock Units and that, immediately prior to being credited to the Participant’s Stock Unit Account, is not expressed in the form of shares of Stock, the amount of the deferral or credit shall be converted, for record-keeping purposes, into whole and fractional Stock Units, with fractional units calculated to four decimal places. Except as provided in subparagraph (iii) below with respect to Director Stock Units under Section 4.03, the conversion shall be accomplished by dividing the amount of the deferral or credit by the closing price of a share of Stock on the date on which the deferral or credit would otherwise have been paid to the Participant, as reported in the Wall Street Journal’s New York Stock Exchange Composite Transaction listing.

(iii) Special Rule for Certain Director Stock Units. All Stock Unit amounts directed by the Board in accordance with Section 4.03, for which the Director is not able to elect an alternate form of deemed investment, shall be credited to the Director’s Account in the form of Stock Units. If the Board directs that a Director be credited with a prescribed number of Stock Units, the number of units so prescribed shall be credited to the Director’s Account as of January 1 of the calendar year following the date of the Board’s direction or at such other time as the Board may prescribe consistent with Code Section 409A. If the Board directs that the Director be credited with Stock Units with a prescribed value, the amount or value prescribed by the Board will be converted, for record keeping purposes, into whole and fractional Stock Units as of January 1 of the calendar year following the date of the Board’s direction, or at such other time as the Board may prescribe consistent with Code Section 409A, with fractional units calculated to four decimal places. The conversion shall be accomplished by dividing the amount or value designated by the Board by the closing price of a share of Integrys Stock on the business day immediately preceding the January 1 crediting date, as reported in the Wall Street Journal’s New York Stock Exchange Composite Transactions listing; provided that if the Board directs, consistent with Code Section 409A, that the Stock Units should be determined as of a date other than January 1, the conversion of the amount or value designated by the Board shall be determined based upon the closing price of a share of Integrys Stock on the date designated by the Board, or if that date is not a business day, on the immediately preceding business day.

(d)    Crediting of Additional Stock Units For Deemed Dividends and Similar Distributions. Any dividends (or similar distribution) occurring on or after the Merger Date, that would have been payable on the Stock Units credited to a Participant’s Stock Unit Account had such Stock Units been actual shares of Stock shall be credited to the Participant's Account and allocated to the Wells Fargo Stable Return Fund, or other similar fund designated by the Committee and shall not be treated as additional Stock Units under the Plan. Prior to the Merger Date, such dividends (or similar distribution) were credited as additional Stock Units and, if not already expressed in the form of shares of Integrys Stock or shares in another entity, were converted, for record keeping purposes, into whole and fractional Stock Units, with fractional units calculated to four decimal places. The conversion was accomplished by dividing the amount of the dividend or distribution by the closing price of a share of Integrys Stock on the payment date for the dividend or distribution.

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Exhibit 10.1

(e)    Conversion from Stock Units to Another Investment Option. If a Participant elects under Section 6.01(d) to transfer all or any portion of his or her Discretionary Stock Units to an alternate Investment Option, the Stock Units to which such election relates shall be converted, for record keeping purposes, from Stock Units into an amount that is equal to the product obtained by multiplying the number of such Stock Units that are being transferred by the closing price of a share of Stock, on the effective date of such investment transfer, as reported in the Wall Street Journal’s New York Stock Exchange Composite Transaction listing.

(f)    Securities Law Restrictions. Notwithstanding anything to the contrary herein, all transfer elections under Section 6.01(d) by a Participant who is subject to Section 16 of the Exchange Act are subject to review by the Committee prior to implementation. Further, the following transfer transactions under Section 6.01(d) by a Participant who is subject to Section 16 of the Exchange Act are prohibited: (i) elections to transfer the deemed investment of the affected Participant’s Account into Stock Units within six (6) months of an election to reallocate deemed investments out of Stock Units; and (ii) elections to transfer the deemed investment of the affected Participant’s Account out of Stock Units within six (6) months of an election to reallocate deemed investments into Stock Units (collectively, “Prohibited Transactions”). All Prohibited Transactions are void. In accordance with Section 11.02, the Committee may restrict additional transactions, or impose other rules and procedures, to the extent deemed desirable by the Committee in order to comply with the Exchange Act, including, without limitation, application of the review and approval provisions of this Section 5.04(f) to Participants who are not subject to Section 16 of the Exchange Act.

Section 5.05. Special Rules Applicable to Restricted Stock or Stock Unit Deferrals. Unless otherwise determined by the Committee, the Participant’s interest in Stock Units attributable to a deferral of an Omnibus Plan restricted stock or restricted stock unit award shall be subject to the same vesting or forfeiture conditions to which the Participant would have been subject if the Participant had received the restricted stock directly rather than electing to defer delivery of such shares. Effective on or after the Merger Date, dividend (or other distribution) credits with respect to restricted stock shall be allocated to the Wells Fargo Stable Return Fund, or other similar Investment Option designated by the Committee. Prior to the Merger Date, except with respect to dividend (or other distribution) credits that the Committee has determined are at all times fully vested and therefore are to be credited to a special Restricted Stock Dividend Account, the dividend (or distribution) credit was credited to the Participant in the form of additional Stock Units, in accordance with Section 5.04(d), and such additional Stock Units were subject to the same vesting or forfeiture conditions as apply with respect to the underlying Stock Units on which the dividend (or distribution) credit is based.

19

Exhibit 10.1

ARTICLE VI. ACCOUNTING AND HYPOTHETICAL INVESTMENT ELECTIONS

Section 6.01. Hypothetical Investment of Participant Accounts.

(a)    Deemed Investment of All Deferrals and Contribution Credits Other Than Deferrals of Restricted Stock.

(i) Participant Investment Elections and Deemed Investment Elections. In accordance with uniform rules prescribed by the Committee, each Participant shall designate how deferrals and other authorized contribution credits (including Special Defined Contribution Credits) made while the designation is in effect, other than LTIP Deferrals of restricted stock or restricted stock units, are credited among the Investment Options when such deferrals or credits are initially allocated to the Participant’s Account. When selecting more than one Investment Option, the Participant shall designate, in whole multiples of one percent (1%) or such other percentage determined by the Committee, the percentage to be credited to each of the available Investment Options. If the Participant fails to make a timely and complete investment designation, the deferrals or other contribution credits for which there is not a valid investment election shall be credited to the same “lifecycle” fund that is or would be the default investment option for the Participant under the qualified defined contribution plan in which the Participant is eligible, or is such other Investment Option specified by the Committee for this purpose.

(ii) Rules Applicable to LTIP Deferrals of Plan Performance Awards.Effective on or after the Merger Date, only Locked Stock Units may be allocated to Stock Units. For purposes of crediting a Participant’s deferral of an Omnibus Plan performance unit award, or other award that is expressed in shares of Stock, among the Investment Options, the following rules shall apply. With respect to the portion of the award that the Participant allocates into Stock Units prior to the Merger Date, the Participant will be credited with Stock Units, on a one-for-one basis, in accordance with Section 5.04(c)(i). With respect to the portion of the award that the Participant allocates to Investment Option(s) other than Stock Units, the amount to be credited to each Investment Option other than Stock Units will be determined by multiplying the number of shares of Stock that corresponds to the portion of the award that the Participant has allocated to that Investment Option by the closing price of a share of Stock on the date on which the deferral or credit would otherwise have been paid to the Participant, as reported in the Wall Street Journal’s New York Exchange Composite Transaction listing.

(iii) Effectiveness of Investment Election or Deemed Investment Election.A Participant’s investment election or deemed investment election shall become effective for deferrals and other contribution credits beginning with the first payroll period commencing or payment date occurring on or after the date on which the election is received and accepted by the Committee, or such other date established by the Committee for this purpose, and shall remain in effect for all future deferrals and contribution credits unless and until modified by a subsequent election that becomes effective in accordance with the rules of this subsection. The Participant’s election under this Section 6.01(a) governs the deemed investment of deferrals and contribution credits (including

20

Exhibit 10.1

Special Defined Contribution Credits) made while the Participant’s election is in effect. A Participant’s ability to transfer amounts that are deemed to be invested in one Investment Option to another Investment Option is governed by Section 6.01(d).

(iv) Participant May Have Only One Investment Election or Deemed Investment Election. A Participant may have in effect at any time only one investment election or deemed investment election under this Section that will apply to all covered deferrals and contribution credits that are made while the election or deemed election is in effect. A Participant is not permitted to make separate investment elections or deemed investment elections with respect to particular contribution sources, e.g., a Participant may not make one investment election for Base Compensation Deferrals and a separate investment election or deemed investment election for Special Contribution Credits.

(b)    Deemed Investment of LTIP Deferrals of Restricted Stock or Restricted Stock Unit. Restricted stock or restricted stock unit deferrals are credited to the Plan in the form of Locked Stock Units and shall remain Locked Stock Units until the amounts attributable to the Participant's Stock Unit Account are distributed from the Plan. Prior to the Merger Date, Locked Stock Units became Discretionary Stock Units when the Locked Stock Units were vested. The Participant is not permitted to make an investment election with respect to Locked Stock Units or to cause Locked Stock Units to be transferred to an alternate Investment Option. Prior to the Merger Date, a Participant could transfer Discretionary Stock Units to an alternate Investment Option in accordance with Section 6.01(d).

(c)    Allocation of Deemed Investment Gain or Loss.

(i) In General. On each Valuation Date, the Account of each Participant will be credited (or charged) based upon the investment gain (or loss) that the Participant would have realized with respect to his or her Account since the immediately preceding Valuation Date had the Account been invested in accordance with the terms of the Plan and where applicable, the Participant’s election. Subject to the special rules set forth in Article V with respect to Reserve Account A, Reserve Account B, and Stock Units, the credit (or charge) shall be the sum, separately calculated for each of the Investment Options, of the product obtained by multiplying (i) the portion (if any) of the Participant’s Account as of the immediately prior Valuation Date that is deemed to have been invested in each Investment Option, and (ii) the rate of return experienced by that Investment Option since the immediately preceding Valuation Date. The Committee, in its discretion, may prescribe alternate rules for the valuation of Participant Accounts, including, without limitation, the application of unit accounting principles.

(ii) Additional Rules for Special Contribution Credits. As described in Section 8.01, the portion of a Participant’s Account that is attributable to Special Contribution Credits, is distributed in accordance with the Participant’s actual or deemed distribution election under the Pension Restoration Plan.

(A) If the Participant has elected (or is deemed to have elected) a single sum payment under the Pension Restoration Plan, the Participant’s Special Contribution Credits will continue to be invested in accordance with the Participant’s investment election or deemed investment election under this Plan, and will be credited or charged with investment gain or loss under this Plan,

21

Exhibit 10.1

through the Valuation Date immediately preceding the date on which the distribution is processed for payment.

(B) If the Participant has elected (or is deemed to have elected) a 180 month period certain installment benefit or monthly annuity payments under the Pension Restoration Plan, the Participant’s Special Contribution Credits will continue to be invested in accordance with the Participant’s investment election or deemed investment election under this Plan, and will be credited or charged with investment gain or loss under this Plan, through the Valuation Date that coincides with or immediately precedes the Calculation Date (as defined in the Pension Restoration Plan) applicable to the Participant. The Participant’s Special Defined Contribution Credits as of such Calculation Date converted into an actuarially equivalent benefit in the selected payment form, and investment gains or losses after the Calculation Date are not relevant to the determination of the Participant’s benefit attributable to Special Defined Contribution Credits.

(d)    Reallocation of Account. Subject to such restrictions as may be in effect or implemented pursuant to Section 5.04(f), and in accordance with rules prescribed by the Committee (which may include limitations on the timing or frequency of reallocation transactions initiated by some or all Participants), each Participant may elect to reallocate his or her Account (other than Locked Stock Units) among the available Investment Options; provided that no amounts may be allocated to Reserve Account A or Reserve Account B. When selecting more than one Investment Option, the Participant shall designate, in whole multiples of one percent (1%) or such other percentage determined by the Committee, the percentage of his or her available Account that is deemed to be invested in each available Investment Option after the investment reallocation is given effect. Once effective, a Participant’s reallocation shall remain in effect unless and until modified by a subsequent election that becomes effective in accordance with the rules prescribed by the Committee. Other than a reallocation of a Participant’s Account pursuant to a revised investment election submitted by the Participant, the deemed investment allocation of a Participant will not be adjusted to reflect differences in the relative investment return realized by the various hypothetical Investment Options that the Participant has designated.

Section 6.02. Accounts are For Record Keeping Purposes Only. Plan Accounts and the record keeping procedures described herein serve solely as a device for determining the amount of benefits accumulated by a Participant under the Plan, and shall not constitute or imply an obligation on the part of a Participating Employer to fund such benefits. Each Participating Employer shall record on its books the amount of deferrals of compensation made hereunder (as adjusted for gains and losses thereon) by a Participant that are attributable to the services performed by such Participant for such Participating Employer and the Participating Employer shall be responsible for the payment thereof. In any event, a Participating Employer may, in its discretion, set aside assets and/or contribute to the Trust assets equal to part or all of such account balances that are attributable to it and invest such assets in Stock, life insurance or any other investment deemed appropriate. Any such assets held by a Participating Employer or the Trust shall be and remain the sole property of the Participating Employer or the Trust, as applicable, and except to the extent that the Trust authorizes a Participant to direct the trustee with respect to the voting of Stock held in the Trust, a Participant shall have no proprietary rights of any nature whatsoever with respect to such assets.

Section 6.03. Merger with Wisconsin Energy Corporation and Cancellation of Stock Units. Each Stock Unit in the Participant's Account immediately prior to the Merger Date was deemed fully vested and was cancelled as of the Merger Date. For each cancelled Stock Unit, the Participant's Account was credited with cash equal to the equity award consideration provided for under the Agreement and Plan of Merger dated as of June 22, 2014, between Integrys Energy Group, Inc. and Wisconsin Energy Corporation. Such cash amounts were allocated to the applicable Vanguard “lifecycle” fund based on the Participant's age. A Participant may elect to reallocate amounts credited to the Participant's Account among the available Investment Options in accordance with Section 6.01(d), provided that such amounts may not be reallocated to Stock Units under the Plan.

22

Exhibit 10.1

ARTICLE VII. DISTRIBUTION OF PRE-2005 ACCOUNT

Section 7.01. Distribution Election.

(a)    Election. A Participant, at the time he or she commenced participation in the Plan, made a distribution election with respect to his or her Pre-2005 Account. The election specified the distribution commencement date, the distribution period, and the distribution method applicable following the Participant’s death. Any such election was required to be consistent with the following rules (or if the Participant failed to make a selection with respect to a particular item, in accordance with the default rules set forth below):

(i) Distribution Commencement Date. Unless the Participant has selected a later commencement date, which in no event shall be later than the first distribution period following the Participant’s attainment of age seventy two (72), distribution of a Participant’s Pre-2005 Account will commence either (A) within sixty (60) days following the end of the calendar year in which the Participant terminates employment or service from the Company and all Affiliates, or (B) if determined by the Committee to be consistent with the “grand-father” rules of Code Section 409A and if directed by the Committee for purposes of creating administratively consistency between the distribution provisions of Articles VII and VIII, within sixty (60) days following the end of the calendar year in which occurs the six (6) month anniversary of the date on which the Participant terminates employment or service from the Company and all Affiliates. For purposes of this Plan, a Participant who is Disabled shall be deemed to have retired or terminated at the conclusion of benefits under all disability income plans sponsored by a Participating Employer or to which a Participating Employer contributes, unless otherwise determined by the Committee.

(ii) Distribution Period. Distributions will be made in one (1) to fifteen (15) annual installments, as elected by the Participant.

(iii) Distribution of Remaining Account Following Participant’s Death. In the event of the Participant’s death, the Participant’s remaining undistributed interest will be distributed to the Participant’s Beneficiary in accordance with the distribution election (single sum payment or installments) elected by the Participant. If the Participant had elected a single sum, the payment shall be made no later than March 1 following the calendar year in which occurs the Participant’s death. If the Participant had elected an installment distribution, (A) any installments previously commenced to the Participant shall continue to the Beneficiary and (B) if installment distributions had not commenced as of the date of the Participant’s death, payments over the installment period elected by the Participant shall commence to the Beneficiary no later than March 1 following the calendar year in which occurs the Participant’s death.

(b)    Effectiveness of Election. A distribution election shall be deemed made only when it is received and accepted as complete by the Committee, and shall remain in effect until modified by the Participant in accordance with Section 7.02 below or otherwise revoked in accordance with Plan rules.

23

Exhibit 10.1

Section 7.02. Modified Distribution Election. A Participant may from time to time modify his or her distribution election by filing a revised distribution election, properly completed and signed, with the Committee. However, a revised distribution election will be given effect only if the Participant remains employed by a Participating Employer for twelve (12) consecutive months following the date that the revised election is received and accepted as complete by the Committee.

Section 7.03. Calculation of Annual Distribution Amount.

(a)    Pre-2001 Retirees. For any Participant who retired or terminated employment or service prior to January 1, 2001, distribution of the Participant’s Account will be calculated and made under the distribution provisions of the Plan applicable to the Participant on the date of the Participant’s retirement or termination of employment or service.

(b)    Post-2000 Retirees. For a Participant who retires or terminates employment or service after December 31, 2000, the annual distribution amount for the Pre-2005 Account, unless the Committee specifies a different or alternate method and such different or alternate method does not result in the imposition of tax under Code Section 409A, shall be calculated as follows:

(i) The annual distribution amount for the Participant’s Pre-2005 Account, other than the portion of the Pre-2005 Account that is deemed to be invested in Stock Units (the “Distributable Account”), shall be determined by dividing (A) the aggregate balance in the Distributable Account as of January 1 of the year for which the distribution is being made, by (B) the number of installment payments remaining to be made under the distribution period selected by the Participant. Distributions shall be made in cash. The amount of any distribution under this Paragraph (i) will be charged pro-rata against the Participant’s interest in each Investment Option comprising the Distributable Account. Notwithstanding the foregoing, the last installment payment of the Distributable Account shall be adjusted to take into account deemed investment gains or losses for the period between the January 1 valuation date and the date of actual payment according to such methods and procedures adopted by the Committee.

(ii) Effective as of the Merger Date, no portion of the Pre-2005 Account shall be deemed to be invested in Stock Units. Prior to the Merger Date, the following provisions applied: The annual distribution amount for the portion of the Participant’s Pre-2005 Account that is credited in the form of Stock Units shall be determined on a share basis by dividing (A) the number of Stock Units as of January 1 of the year for which the distribution is being made (subject to subsequent adjustment under Section 9.03), by (B) the number of installment payments remaining to be made under the distribution period selected by the Participant. The Participant will receive shares of Integrys Stock equal to the annual distribution amount, subject only to the distribution of cash in lieu of any fractional Stock Unit. The cash payment for any fractional Stock Unit shall be determined based upon the closing price of a share of Integrys Stock on January 21 of the year in which the distribution is being made, as such share price is reported in the Wall Street Journal’s New York Stock Exchange Composite Transactions listing. If January 21 falls on a Saturday, Sunday or holiday, the calculation of the cash portion of the distribution will be made based upon the closing price as reported for the immediately preceding business day.

24

Exhibit 10.1

Section 7.04. Time of Distribution. Distributions shall be made as soon as administratively feasible, but no later than March 1 of the year for which the distribution is being made. Prior to the Merger Date, the following provisions applied: Subject to the provisions of Sections 9.03 and 10.03, each distribution of Integrys Stock made to a Participant (or Beneficiary) shall be distributed on January 22 (or if January 22 falls on a Saturday, Sunday or holiday, the following business day). For distribution and tax reporting purposes, the value of Integrys Stock distributed shall equal the number of shares distributed multiplied by the closing price of Integrys Stock on January 21 (or if January 21 falls on a Saturday, Sunday or holiday, the preceding business day) of the year in which the distribution is being made as reported in the Wall Street Journal’s New York Stock Exchange Composite Transaction listing. The cash portion of any distribution will be made no later than March 1 of the year for which the distribution is being made.

Section 7.05. Single Sum Distribution at the Committee’s Option.

(a)    In the case of a Participant whose employment with the Company and its Affiliates is involuntarily terminated by the Company or an Affiliate, or whose employment with the Company and its Affiliates is mutually terminated in accordance with a separation agreement and release between the Company or an Affiliate and such Participant, the Committee may (but need not) direct that the Participant’s Pre-2005 Account be distributed in the form of a single sum payment in lieu of distribution over any installment distribution period that would otherwise apply. If so directed by the Committee, the single sum distribution shall be made in cash and/or shares of Integrys Stock (as determined in accordance with Section 7.03 for distributions prior to the Merger Date) and shall be made at the time specified in Section 7.04.

(b)    In the case of any other Participant or Beneficiary whose Pre-2005 Account has a value of one hundred thousand dollars ($100,000) or less as of the valuation date that immediately precedes the date on which distribution would first be made to the Participant or Beneficiary, the Committee may (but need not) direct that the Participant’s Pre-2005 Account be distributed in the form of a single sum payment in lieu of any installment distribution period that would otherwise apply. If so directed by the Committee, the single sum distribution shall be made in cash and/or shares of Integrys Stock (as determined in accordance with Section 7.03 for distributions prior to the Merger Date) and shall be made at the time specified in Section 7.04.

25

Exhibit 10.1

ARTICLE VIII. DISTRIBUTION OF POST-2004 ACCOUNT

Section 8.01. Distribution Election.

(a)    Election. A Participant, on or before December 31, 2008 or if later, at the time he or she commences participation in the Plan, shall make a distribution election with respect to his or her Post-2004 Account (other than the portion of the Post-2004 Account, if any, that is attributable to Special Defined Contribution Credits as described in subsection (c) below). The election shall be in such form as the Committee shall prescribe, and shall specify the distribution commencement date, the distribution period, and the distribution method applicable following the Participant’s death. Any such election shall be consistent with the following rules (or if the Participant fails to make a selection with respect to a particular item, in accordance with the default rules set forth below):

(i) Distribution Commencement Date. Unless the Participant has selected a later commencement date, distribution of a Participant’s Post-2004 Account will commence within sixty (60) days following the end of the calendar year in which occurs the six (6) month anniversary of the Participant’s Separation from Service.

(ii) Distribution Period. Distributions will be made in one (1) to fifteen (15) annual installments, as elected by the Participant. The default is one (1) annual installment. For purposes of applying the rules of Code Section 409A, a Participant’s election of annual installments is treated as an election of a single form of payment rather than an election of multiple separate payments.

(iii) Distribution of Remaining Account Following Participant’s Death. In the event of the Participant’s death, the Participant’s remaining undistributed interest in his or her Post-2004 Account will be distributed to the Participant’s Beneficiary in accordance with the distribution election (single sum payment or installments) elected by the Participant. If the Participant had elected a single sum, the payment shall be made no later than March 1 following the calendar year in which occurs the Participant’s death. If the Participant had elected an installment distribution, (A) any installments previously commenced to the Participant shall continue to the Beneficiary and (B) if installment distributions had not commenced as of the date of the Participant’s death, payments over the installment period elected by the Participant shall commence to the Beneficiary no later than March 1 following the calendar year in which occurs the Participant’s death.

(b)    Effectiveness of Election. A distribution election shall be deemed made only when it is received and accepted as complete by the Committee, and shall remain in effect until modified by the Participant in accordance with Section 8.02 below or otherwise revoked in accordance such circumstances as the Plan is permitted (and elects) to accept without resulting in the imposition of tax under Code Section 409A.

(c)    Coordination With Distributions Under Pension Restoration Plan. In the case of a Participant who receives credits under this Plan that constitute Special Defined Contribution Credits, the Participant’s actual or deemed distribution election under this Plan shall not apply to the portion of the Participant’s Post-2004 Account that is attributable to Special Defined Contribution Credits (together with any earnings or loss thereon through the date determined under Section 6.01(c)). The portion of a Participant’s Post-2004 Account that is attributable to Special Defined Contribution Credits (together with applicable earnings or loss thereon) will be distributed in accordance with the Participant’s actual or deemed distribution election under the Pension Restoration Plan. With respect to any Participant who receives Special Contribution Credits, any references in this Article VIII to the Participant’s Post-2004 Account shall mean the Participant’s Post-2004 Account, exclusive of such Special Contribution Credits (and applicable earnings or loss thereon). If the Participant has elected (or is deemed to have

26

Exhibit 10.1

elected) a 180 month period certain installment benefit or monthly annuity payments under the Pension Restoration Plan, the Participant’s Special Contribution Credits (together with applicable earnings or loss thereon) will be converted into an actuarially equivalent benefit in the selected payment form under the Pension Restoration Plan such that, as of the Participant’s Calculation Date (as defined in the Pension Restoration Plan), there is no longer a benefit under this Plan attributable to the Special Defined Contribution Credits (and applicable earnings or loss thereon); accordingly, for any such Participant, the portion of the Participant’s Post-2004 Account that is attributable to Special Defined Contribution Credits (and applicable earnings or loss thereon) will be eliminated from the Participant’s Post-2004 Account as of such Calculation Date.

Section 8.02. Modified Distribution Election. A Participant may from time to time modify his or her distribution election with respect to his or her Post-2004 Account by filing a revised distribution election, properly completed and signed, with the Committee. However, except to the extent permitted under regulations promulgated by the Secretary of the Treasury under Code Section 409A, a revised distribution election must comply with the following rules:

(a)    The revised distribution election may not accelerate the time of payment in violation of Code Section 409A. For example, a revised distribution election may not elect a distribution commencement date earlier than the distribution commencement date applicable under the Participant’s prior distribution election. A revised election that does not comply with these rules will be null and void, and will be disregarded by the Plan.

(b)    The revised distribution election may (i) change the form of payment from a single sum payment to installment distributions, (ii) from installment distributions to a single sum distribution, (iii) from one installment period to a different installment period, or (iv) defer the distribution commencement date, and such a revised election will be given effect twelve (12) months after the date on which the election is made, but only if (i) the revised election is made at least twelve (12) months prior to the date on which payment would be made or commence in the absence of the revised election, and (ii) in the case of any election other than one related to payment on account of Disability or death, the first payment that is made pursuant to the revised election is deferred for at least five (5) years from the date payment would otherwise have been made. For purposes of Code Section 409A, the installment payment option is considered to be a single form of payment rather than a series of independent payments. A revised election that does not comply with these rules will be null and void, and will be disregarded by the Plan.

Section 8.03. Calculation of Annual Distribution Amount. The annual distribution amount for the Post-2004 Account shall be calculated as follows:

(a)    The annual distribution amount for the Participant’s Post-2004 Account, other than the portion of the Post-2004 Account that is deemed to be invested in Stock Units (the “Distributable Account”), shall be determined by dividing (A) the aggregate balance in the Distributable Account as of January 1 of the year for which the distribution is being made, by (B) the number of installment payments remaining to be made under the distribution period selected by the Participant. Distributions shall be made in cash. The amount of any distribution under this subsection (a) will be charged pro-rata against the Participant’s interest in each Investment Option comprising the Distributable Account. Notwithstanding the foregoing, the last installment payment of the Distributable Account shall be adjusted to take into account deemed investment gains or losses for the period between the January 1 valuation date and the date of actual payment according to such methods and procedures adopted by the Committee.

(b)    The annual distribution amount for the portion of the Participant’s Post-2004 Account that is credited in the form of Stock Units shall be determined on a share basis by dividing (A) the number of Stock Units as of January 1 of the year for which the distribution is being made, by (B) the number of installment payments remaining to be made under the distribution period selected by the Participant. The Participant will receive distribution of cash in lieu of Stock Units. The cash payment shall be determined based upon the closing price of a share of Stock on December 31 of the year prior to the year in which the distribution is being made, as such share price is reported in the Wall Street Journal’s New York Stock Exchange Composite Transactions listing. If December 31 falls on a Saturday, Sunday or holiday, the calculation of the cash distribution will be made based upon the closing price as reported for the immediately preceding business day. Prior to the Merger Date, the following provisions applied: The annual distribution amount for the portion of the Participant’s Post-2004 Account

27

Exhibit 10.1

that is credited in the form of Stock Units shall be determined on a share basis by dividing (A) the number of Stock Units as of January 1 of the year for which the distribution is being made (subject to subsequent adjustment under Section 9.03), by (B) the number of installment payments remaining to be made under the distribution period selected by the Participant. The Participant will receive shares of Integrys Stock equal to the annual distribution amount, subject only to the distribution of cash in lieu of any fractional Stock Unit. The cash payment for any fractional Stock Unit shall be determined based upon the closing price of a share of Integrys Stock on January 21 of the year in which the distribution is being made, as such share price is reported in the Wall Street Journal’s New York Stock Exchange Composite Transactions listing. If January 21 falls on a Saturday, Sunday or holiday, the calculation of the cash portion of the distribution will be made based upon the closing price as reported for the immediately preceding business day.

Section 8.04. Time of Distribution. Distributions shall be made as soon as administratively feasible, but no later than March 1 of the year for which the distribution is being made. Prior to the Merger Date, the following provisions applied: Subject to the provisions of Sections 9.03 and 10.03, each distribution of Integrys Stock made to a Participant (or Beneficiary) shall be distributed on January 22 (or if January 22 falls on a Saturday, Sunday or holiday, the immediately following business day). For distribution and tax reporting purposes, the value of Integrys Stock distributed shall equal the number of shares distributed multiplied by the closing price of Integrys Resources Stock on January 21 (or if January 21 falls on a Saturday, Sunday or holiday, the immediately preceding business day) of the year in which the distribution is being made as reported in the Wall Street Journal’s New York Stock Exchange Composite Transaction listing. The cash portion of any distribution will be made no later than March 1 of the year for which the distribution is being made.

Section 8.05. Automatic Single Sum Distribution. In the case of any Participant or Beneficiary whose Post-2004 Account has a value equal to or less than the applicable dollar amount under Code Section 402(g)(1)(B), the Participant’s Post-2004 Account will be distributed in the form of a single sum payment on the date on which distributions would otherwise commence, and such single sum payment shall be in lieu of any installment distribution period that would otherwise apply. Unless otherwise directed by the Committee, the single sum distribution shall be made in cash and/or shares of Integrys Stock (as determined in accordance with Section 8.03 prior to the Merger Date). The foregoing rule shall apply only if (a) the payment results in the termination of liquidation of the Participant’s entire interest in his or her Post-2004 Account and his or her entire interest in all other plans, programs or arrangements that are required to be aggregated with the Participant’s Post-2004 Account for purposes of Code Section 409A, and (b) the payment is not greater than the applicable dollar amount under Code Section 402(g)(1)(B).

Section 8.06. Distributions For Employment Tax Obligations.

(a)    Notwithstanding the time or schedule of payments otherwise applicable to the Participant, the Committee may direct that distribution from a Participant’s Account be made (i) to pay the Federal Insurance Contributions Act (“FICA”) tax imposed under Code Sections 3101, 3121(a) and 3121(v)(2) with respect to compensation deferred under the Plan, (ii) to pay the income tax at source on wages imposed under Code Section 3401 or the corresponding withholding provisions of applicable state, local, or foreign tax laws as a result of the payment of FICA taxes, and (iii) to pay the additional income tax at source on wages attributable to the “pyramiding” of Code Section 3401 wages and taxes; provided that the total amount distributed under this provision must not exceed the aggregate of the FICA tax and the income tax withholding related to such FICA tax. In addition or in the alternative, the Committee may direct that all FICA taxes owed in connection with any allocation hereunder be withheld from other compensation owed to the Participant.

(b)    The amount actually distributed to the Participant in accordance with the time or schedule of payments applicable to the Participant will be reduced by applicable tax withholding except to the extent such withholding requirements previously were satisfied in accordance with subsection (a) above.

28

Exhibit 10.1

ARTICLE IX. RULES WITH RESPECT TO INTEGRYS STOCK
AND INTEGRYS STOCK UNITS

Section 9.01. Application. Effective as of the Merger Date, Stock Units consisting of shares of Integrys Stock were cancelled and converted to cash in accordance with Section 6.03 and distributions of shares of Integrys Stock under the Plan ceased. The provisions in this Article IX applied prior to the Merger Date.

Section 9.02. Relationship to Shares Authorized Under Omnibus Plan. Distribution of shares of Integrys Stock that are attributable to LTIP Deferrals that relate to an award that was made under the Omnibus Plan (or that relate to Director Deferred Stock Units granted on or after January 1, 2011 under Section 4.03) will be charged against the pool of available shares under the Omnibus Plan, i.e., the plan under which the share award was originally granted and from which the share award would have been paid except for the Participant’s election (or the Board’s direction) to defer delivery of the shares.

Section 9.03. Transactions Affecting Integrys Stock. In the event of any merger, share exchange, reorganization, consolidation, recapitalization, stock dividend or stock split involving Integrys Stock, or other event in which Integrys Stock is subdivided or combined, or a cash dividend the amount of which, on a per share basis, exceeds, fifteen percent (15%) of the fair market value of a share of Integrys Stock at the time the dividend is declared, or the Company shall effect any other dividend or other distribution of Integrys Stock that the Board determines by resolution is extraordinary or special in nature or that is in connection with a transaction that the Company characterizes publicly as a recapitalization or reorganization of Integrys Stock or words of similar import, or any other event shall occur, which, in the judgment of the Committee necessitates an adjustment to prevent dilution or enlargement of the benefits or potential benefits intended to be made available under this Plan, the Committee shall make appropriate equitable adjustments with respect to the Stock Units (if any) credited to the Account of each Participant. The nature of any such adjustment shall be determined by the Committee, in its discretion.

Section 9.04. No Shareholder Rights With Respect to Stock Units. Participants shall have no rights as a stockholder pertaining to Stock Units credited to their Accounts. No Stock Unit nor any right or interest of a Participant under the Plan in any Stock Unit may be assigned, encumbered, or transferred, except by will or the laws of descent and distribution. The rights of a Participant hereunder with respect to any Stock Unit are exercisable during the Participant’s lifetime only by the Participant or his or her guardian or legal representative.

29

Exhibit 10.1

ARTICLE X. SPECIAL RULES APPLICABLE IN THE EVENT OF A CHANGE IN CONTROL OF THE COMPANY

Section 10.01. Application. Effective as of the Merger Date, a Change in Control has occurred and the provisions in this Article X effective upon a Change in Control shall apply to the Plan.

Section 10.02. Definitions. For purposes of this Article X, the following terms shall have the following respective meanings:

(a)    An “Affiliate” of, or a person “affiliated” with, a specified person is a person that directly, or indirectly through one or more intermediaries, controls, or is controlled by, or is under common control with, the person specified and the term “Associate” used to indicate a relationship with any person, means (i) any corporation or organization (other than the registrant or a majority-owned subsidiary of the registrant) of which such person is an officer or partner or is, directly or indirectly, the beneficial owner of ten percent (10%) or more of any class of equity securities, (ii) any trust or other estate in which such person has a substantial beneficial interest or as to which such person serves as trustee or in a similar fiduciary capacity, and (iii) any relative or spouse of such person, or any relative of such spouse, who has the same home as such person or who is a director or officer of the registrant or any of its parents or subsidiaries.

(b)    A person shall be deemed to be the “Beneficial Owner” of any securities:

(i) which such Person or any of such Person’s Affiliates or Associates has the right to acquire (whether such right is exercisable immediately or only after the passage of time) pursuant to any agreement, arrangement, or understanding, or upon the exercise of conversion rights, exchange rights, or other rights, warrants or options, or otherwise; provided, however, that a Person shall not be deemed the Beneficial Owner of, or to beneficially own, (A) securities tendered pursuant to a tender or exchange offer made by or on behalf of such Person or any of such Person’s Affiliates or Associates until such tendered securities are accepted for purchase or (B) securities issuable upon exercise of any rights agreement that the Company may have in effect at any time before the issuance of such securities;

(ii) which such Person or any of such Person’s Affiliates or Associates, directly or indirectly, has the right to vote or dispose of or has “beneficial ownership” of (as determined pursuant to Rule 13d-3 of the General Rules and Regulations under the Act), including pursuant to any agreement, arrangement or understanding; provided, however, that a Person shall not be deemed the Beneficial Owner of, or to beneficially own, any security under this subparagraph (ii) as a result of an agreement, arrangement or understanding to vote such security if the agreement, arrangement or understanding: (A) arises solely from a revocable proxy or consent given to such Person in response to a public proxy or consent solicitation made pursuant to, and in accordance with, the applicable rules and regulations under the Act and (B) is not also then reportable on a Schedule 13D under the Act (or any comparable or successor report); or

(iii) which are beneficially owned, directly or indirectly, by any other Person with which such Person or any of such Person’s Affiliates or Associates has any agreement, arrangement or understanding for the purpose of acquiring, holding, voting (except pursuant to a revocable proxy as described in Paragraph (ii) above) or disposing of any voting securities of the Company.

30

Exhibit 10.1

(c)    A “Change in Control” shall be deemed to have occurred if:

(i) any Person (other than any employee benefit plan of the Company or any subsidiary of the Company, any Person organized, appointed or established pursuant to the terms of any such benefit plan or any trustee, administrator or fiduciary of such a plan) is or becomes the Beneficial Owner of securities of the Company representing at least thirty percent (30%) of the combined voting power of the Company’s then outstanding securities;

(ii) one-half or more of the members of the Board are not Continuing Directors;

(iii) there shall be consummated any merger, consolidation, or reorganization of the Company with any other corporation as a result of which less than fifty percent (50%) of the outstanding voting securities of the surviving or resulting entity are owned by the former shareholders of the Company other than a shareholder who is an Affiliate or Associate of any party to such consolidation or merger;

(iv) there shall be consummated any merger of the Company or share exchange involving the Company in which the Company is not the continuing or surviving corporation other than a merger of the Company in which each of the holders of the Company’s common stock immediately prior to the merger have the same proportionate ownership of common stock of the surviving corporation immediately after the merger;

(v) there shall be consummated any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, of the assets of the Company to a Person which is not a wholly owned subsidiary of the Company; or

(vi) the shareholders of the Company approve any plan or proposal for the liquidation or dissolution of the Company.

(d)    “Continuing Directors” means (i) any member of the Board of Directors of the Company who was a member of such Board on the effective date of this amendment and restatement, (ii) any successor of a Continuing Director who is recommended to succeed a Continuing Director by a majority of the Continuing Directors then on such Board, and (iii) additional directors elected or recommended for membership by a majority of the Continuing Directors then on such Board.

(e)    “Person” means any individual, firm, partnership, corporation or other entity, including any successor (by merger or otherwise) of such entity, or a group of any of the foregoing acting in concert; provided, that in the case of a merger, consolidation or reorganization of the Company with any other corporation or a share exchange involving the Company, the shareholders of the other corporation that is a party to the merger, consolidation, reorganization or share exchange shall not be considered to be acting in concert for purposes of Section 10.02(c)(i).

Section 10.03. Amendments in Connection with a Change in Control.

(a)    Board Authority to Amend Plan. Prior to the occurrence of a Change in Control, the Board may exercise its authority under Section 11.06 to amend the Plan, including, to the extent deemed necessary or desirable by the Board in anticipation of a Change in Control, to amend the Plan to eliminate Stock Units and cause the value of such units as of the Amendment Date (such value to be determined under Section 5.04(e)) to be reallocated to an

31

Exhibit 10.1

alternate Investment Option that is then available for new investments and that is most similar to a fixed income fund. The term “Amendment Date” means the date on which an amendment to the Plan is validly adopted or the date on which the amendment is or purports to be effective, whichever is later.

(b)    Automatic Amendments. The Plan shall automatically be amended upon a Change in Control to provide that:

(i) the rate of interest equivalent to be credited with respect to Reserve Account A for each month following the Change in Control shall be the greater of (A) the rate of interest equivalent otherwise applicable with respect to Reserve Account A if such amount were calculated based upon the consolidated return on common shareholders’ equity of the Company (including for this purpose any successor corporation that is the survivor of a merger with the Company or any successor to that corporation) and all consolidated subsidiaries, or (B) a rate equal to two (2) percentage points above the prime lending rate at US Bank Milwaukee, Milwaukee, Wisconsin (or any successor thereto) as of the last business day of that month; and

(ii) the rate of interest equivalent to be credited with respect to Reserve Account B for each month following the Change in Control shall be the greater of (A) the rate of interest equivalent otherwise applicable with respect to Reserve Account B if such amount were calculated based upon the consolidated return on common shareholders’ equity of the Company (including for this purpose any successor corporation that is the survivor of a merger with the Company or any successor to that corporation) and all consolidated subsidiaries, or (B) a rate equal to two (2) percentage points above the prime lending rate at US Bank Milwaukee, Milwaukee, Wisconsin (or any successor thereto) as of the last business day of that month. The minimum rate of interest equivalent under clause (B) shall cease to apply on the third anniversary of the Change in Control in the event that the Participant is actively employed by the Company (including for this purpose any successor corporation or entity that is the survivor of a merger with the Company), or by any subsidiary or affiliate of the Company or such successor, on such date.

(c)    Prohibition on Certain Amendments. Notwithstanding the foregoing, on or after a Change in Control, the Board or Company (including for this purpose any successor corporation or entity that is the survivor of a merger with the Company or to which sponsorship of the Plan is transferred following a Change in Control, or the board of directors or other managing body of any such entity) may not, without the written consent of the affected Participant (or in the case of a deceased Participant, the Participant’s Beneficiary) amend the Plan or take an action to terminate the Plan that would:

(i) Result in a decrease in the number of, or a change in the type of, Investment Options that were made available under the Plan immediately prior to the Change in Control; provided that the Plan may be amended to eliminate Stock Units as an Investment Option so long as the value of the Participant’s Stock Units are immediately credited to the Participant’s Account for investment in one or more of the remaining Investment Options as elected by the Participant, or

(ii) Cause the Accounts to be valued under Section 6.01(c) less frequently than quarterly; or

32

Exhibit 10.1

(iii) Impair or otherwise limit a Participant’s rights to reallocate his or her Accounts under Section 6.01(d) as in effect on the date immediately prior to the Change in Control; or

(iv) Decrease the interest rate credited under Reserve Account A or Reserve Account B as determined pursuant to subsection (b) above, except as specifically provided therein;

(v) Eliminate or reduce the distribution options made available under Articles VII and VIII or otherwise terminate any distribution elections then in effect; or

(vi) Modify the provisions of Article X in a manner detrimental or potentially detrimental to a Participant (or Beneficiary), except and only to the extent that modification is necessary to comply with applicable law.

Section 10.04. Acceleration of Certain Vesting. If a Change in Control occurs and the Participant’s employment or service with the Company and its Affiliates is involuntarily terminated for any reason other than Cause (or, in the case of a Participant who has in effect an employment, retention, change in control, severance or similar agreement with the Company or any Affiliate that provides for “good reason” termination and the Participant, in accordance with such agreement, terminates employment or service for “good reason”) within two years following the date of the Change in Control, then the Participant shall be fully vested in the portion of the Participant’s Account that is not otherwise vested at the time of the Participant’s termination of employment.

Section 10.05. Maximum Payment Limitation.

(a)    Limit on Payments. Except as provided in subsection (b) below, if any portion of the payments or benefits described in this Plan or under any other agreement with or plan of the Company or its Affiliates (in the aggregate, “Total Payments”), would constitute an “excess parachute payment” that is subject to the tax imposed by Section 4999 of the Code, then the Total Payments to be made to the Participant shall be reduced such that the value of the aggregate Total Payments that the Participant is entitled to receive shall be one dollar ($1) less than the maximum amount which the Participant may receive without becoming subject to the tax imposed by Section 4999 of the Code; provided that this Section shall not apply in the case of a Participant who has in effect a valid employment contract providing that the Total Payments to the Participant shall be determined without regard to the maximum amount allowable under Section 280G of the Code. The terms “excess parachute payment” and “parachute payment” shall have the meanings assigned to them in Section 280G of the Code, and such “parachute payments” shall be valued as provided therein. Present value shall be calculated in accordance with Section 280G(d)(4) of the Code. Within forty (40) days following delivery of notice by the Company to the Participant of its belief that there is a payment or benefit due the Participant which will result in an excess parachute payment as defined in Section 280G of the Code, the Participant and the Company, at the Company’s expense, shall obtain the opinion (which need not be unqualified) of nationally recognized tax counsel selected by the Company’s independent auditors and acceptable to the Participant in the Participant’s sole discretion (which may be regular outside counsel to the Company), which opinion sets forth (A) the amount of the base period income, (B) the amount and present value of Total Payments and (C) the amount and present value of any excess parachute payments determined without regard to the limitations of this Section. As used in this Section, the term “base period income” means an amount equal to the Participant’s “annualized includible compensation for the base period” as defined in Section 280G(d)(1) of the Code. For purposes of such opinion, the value of any noncash benefits or any deferred payment or benefit shall be determined by the Company’s independent auditors in accordance with the principles of Sections 280G(d)(3) and (4) of the Code, which determination shall be evidenced in a certificate of such auditors addressed to the Company and the Participant. Such opinion shall be addressed to the Company and the Participant and shall be binding upon the Company and the Participant. If such opinion determines that there would be an excess parachute payment, the payments hereunder that are includible in Total Payments or any other payment or benefit determined by such counsel to be includible in Total Payments shall be reduced or eliminated so that there will be no excess parachute payment. Such reduction will be achieved by reducing or eliminating payments or benefits in the manner that produces the highest economic value to the Participant; provided that in the

33

Exhibit 10.1

event it is determined that the foregoing methodology for reduction would violate Section 409A of the Code, the reduction shall be made pro rata among the benefits and/or payments (on the basis of the relative present value of the parachute payments). If such legal counsel so requests in connection with the opinion required by this Section, the Participant and the Company shall obtain, at the Company’s expense, and the legal counsel may rely on in providing the opinion, the advice of a firm of recognized executive compensation consultants as to the reasonableness of any item of compensation to be received by the Participant. If the provisions of Sections 280G and 4999 of the Code (or any successor provisions) are repealed without succession, then this Section shall be of no further force or effect.

(b)    Employment Contract Governs. The provisions of subsection (a) above shall not apply to a Participant whose employment is governed by an employment contract that provides for Total Payments in excess of the limitation described in subsection (a) above.

Section 10.06. Resolution of Disputes. If, after a Change in Control, (a) a dispute arises with respect to the enforcement of the Participant’s rights under the Plan, or (b) any legal proceeding shall be brought to enforce or interpret any provision contained in the Plan or to recover damages for breach of the Plan, in either case so long as the Participant is not acting in bad faith or otherwise pursuing a course of action that a reasonable person would determine to be frivolous, the Participant shall recover from the Company any reasonable attorneys’ fees and necessary costs and disbursements incurred as a result of such dispute or legal proceeding (“Expenses”), and prejudgment interest on any money judgment obtained by the Participant calculated at the rate of interest announced by US Bank Milwaukee, Milwaukee, Wisconsin (or any successor thereto), from time to time as its prime or base lending rate from the date that payments to the Participant should have been made under this Plan. Within ten (10) days after the Participant’s written request therefore and reasonable substantiation that such Expense has been incurred, (but in no event later than the end of the calendar year following the calendar year in which such Expense is incurred), the Company shall pay to the Participant, or such other person or entity as the Participant may designate in writing to the Company, the Participant’s Expenses in advance of the final disposition or conclusion of any such dispute or legal proceeding. In the case of a deceased Participant, this Section shall apply with respect to the Participant’s Beneficiary or estate.

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Exhibit 10.1

ARTICLE XI. GENERAL PROVISIONS

Section 11.01. Administration. The Committee shall administer and interpret the Plan and supervise preparation of Participant elections, forms, and any amendments thereto. The Committee may, in its discretion, delegate any or all of its authority and responsibility; provided that the Committee shall not delegate authority and responsibility with respect to non-ministerial functions that relate to the participation by Participants who are subject to Section 16 of the Exchange Act at the time any such delegated authority or responsibility is exercised. To the extent of any such delegation, any references herein to the Committee shall be deemed references to such delegee. Interpretation of the Plan shall be within the sole discretion of the Committee and shall be final and binding upon each Participant and Beneficiary. The Committee has the discretionary authority to adopt and modify rules and regulations relating to the Plan, interpret and construe the Plan and make determinations regarding eligibility and benefits, as it deems necessary or advisable for the administration of the Plan; any such action, interpretation, construction or determination shall be final and binding on all Participants and Beneficiaries unless determined by a court of competent jurisdiction to be arbitrary and capricious. If any delegee of the Committee shall also be a Participant or Beneficiary, any determinations affecting the delegee’s participation in the Plan shall be made by the Committee. The Plan shall be interpreted to comply with the requirements of Section 409A of the Code with respect to any benefit that is subject to the requirements of such Section of the Code.

Section 11.02. Restrictions to Comply with Applicable Law.

(a)    General Restrictions. Notwithstanding any other provision of the Plan, the Company shall have no liability to deliver any shares of Integrys Stock under the Plan or make any payment unless such delivery or payment would comply with all applicable laws and the applicable requirements of any securities exchange or similar entity (and all applicable requirements of the Omnibus Plan, with respect to any shares of Integrys Stock that relate to awards made under that plan). In addition, transactions under the Plan are intended to comply with all applicable conditions of Rule 16b-3 under the Exchange Act. The Committee shall administer the Plan so that transactions under the Plan will be exempt from Section 16 of the Exchange Act, and shall have the right to restrict any transaction, or impose other rules and requirements, to the extent it deems necessary or desirable for such exemption to be met.

(b)    Restriction on Transfer. Shares of Integrys Stock issued under the Plan may not be sold or otherwise disposed of except (i) pursuant to an effective registration statement under the Act, or in a transaction which, in the opinion of counsel for the Company, is exempt from registration under the Act; and (ii) in compliance with state securities laws. Further, as a condition to issuance of shares of Integrys Stock under the Plan (including shares of Integrys Stock originally granted under the Omnibus Plan but distributed under this Plan), the Participant, his or her Beneficiary or his or her heirs, legatees or legal representatives, as the case may be, shall, if the Committee deems it necessary, execute and deliver to the Company a restrictive stock transfer agreement in such form, and subject to such terms and conditions, as shall be reasonably determined or approved by the Committee, which agreement, among other things, may impose certain restrictions on the sale or other disposition of any shares of stock acquired under the Plan. The Committee may waive the foregoing restrictions, in whole or in part, in any particular case or cases or may terminate such restrictions whenever the Committee determines that such restrictions afford no substantial benefit to the Company.

(c)    Additional Restrictions; Legends. All shares of Integrys Stock delivered under the Plan (including shares of Integrys Stock originally granted under the Omnibus Plan but distributed under this Plan) shall be subject to such stock transfer orders and other restrictions as the Committee may deem advisable under the Plan, the Omnibus Plan, and any applicable federal or state securities laws, and the Committee may cause a legend or legends to be put on any certificates to make appropriate references to such restrictions.

Section 11.03. Claims Procedures.

(a)    If a Participant or Beneficiary (the “claimant”) believes that he is entitled to a benefit under the Plan that is not provided, the claimant or his or her legal representative shall file a written claim for such benefit with the Committee no later than ninety (90) days after the first payment is made (or should have been made) in accordance with the terms of the Plan or under Regulations issued by the Secretary of the Treasury under Code Section 409A. If the Committee denies the claim, it shall deliver to the claimant, within one hundred thirty five

35

Exhibit 10.1

(135) days of the date the first payment to the Participant was made (or should have been made) in accordance with the terms of the Plan or under Regulations issued by the Secretary of the Treasury under Code Section 409A, a written notice to the claimant of such denial. The written notice shall include the specific reason(s) for the denial; reference to specific Plan provisions upon which the denial is based; a description of any additional material or information necessary for the claimant to perfect the claim and an explanation of why such material or information is necessary; and a description of the Plan’s review procedures (as set forth in subsection (b)) and the time limits applicable to such procedures, including a statement of the claimant’s right to bring a civil action under section 502(a) of ERISA following an adverse determination upon review.

(b)    The claimant has the right to appeal the Committee’s decision by filing a written appeal with the Committee. Notice of the appeal must be received by the Committee no later than one hundred eighty (180) days after the first payment is made (or should have been made) in accordance with the terms of the Plan or under Regulations issued by the Secretary of the Treasury under Code Section 409A. The claimant will have the opportunity, upon request and free of charge, to have reasonable access to and copies of all documents, records and other information relevant to the claimant’s appeal. The claimant may submit written comments, documents, records and other information relating to his or her claim with the appeal. The Committee will review all comments, documents, records and other information submitted by the claimant relating to the claim, regardless of whether such information was submitted or considered in the initial claim determination. The Committee shall make a determination on the appeal within sixty (60) days after receiving the claimant’s written appeal; provided that the Committee may determine that an additional sixty (60)-day extension is necessary due to circumstances beyond the Committee’s control, in which event the Committee shall notify the claimant prior to the end of the initial period that an extension is needed, the reason therefore and the date by which the Committee expects to render a decision. If the claimant’s appeal is denied in whole or part, the Committee shall provide written notice to the claimant of such denial. The written notice shall include the specific reason(s) for the denial; reference to specific Plan provisions upon which the denial is based; a statement that the claimant is entitled to receive, upon request and free of charge, reasonable access to and copies of all documents, records, and other information relevant to the claimant’s claim; and a statement of the claimant’s right to bring a civil action under section 502(a) of ERISA.

(c)    Notwithstanding anything in the Plan to the contrary, and as a condition of participating in the Plan, a Participant agrees, on behalf of the Participant and all persons or entities that may claim through the Participant, that (1) any claim for benefits or other legal action or legal proceeding concerning the Plan may be brought more than one (1) year after the later of (A) the last date on which the act or omission giving rise to the claim, legal action or other legal proceeding occurred, or (B) the date the individual or entity bringing such claim, legal action or other legal proceeding had knowledge (or reasonably should have had knowledge) of the act or omission, and (2) that any legal action or legal proceeding concerning the Plan may only be heard in a “bench” trial and that any right to a jury trial is waived.

Section 11.04. Participant Rights Unsecured.

(a)    Unsecured Claim. With respect to deferrals of compensation for services performed for a Participating Employer (as adjusted for gains or losses thereon), the right of a Participant or the Participant’s Beneficiary to receive a distribution hereunder shall be an unsecured claim with respect to such Participating Employer, and neither the Participant nor any Beneficiary shall have any rights in or against any amount credited to his or her Account with respect thereto or any other specific assets of a Participating Employer. The right of a Participant or Beneficiary to the payment of benefits under this Plan shall not be assigned, encumbered, or transferred, except by will or the laws of descent and distribution. The rights of a Participant hereunder are exercisable during the Participant’s lifetime only by the Participant or his or her guardian or legal representative.

(b)    Contractual Obligation. The Company may authorize the creation of a trust or other arrangements to assist it in meeting the obligations created under the Plan, subject to the restrictions on funding imposed by Code Section 409A(b)(3). However, any liability to any person with respect to the Plan shall be based solely upon any contractual obligations that may be created pursuant to the Plan. No obligation of a Participating Employer shall be deemed to be secured by any pledge of, or other encumbrance on, any property of a Participating Employer. Nothing contained in this Plan and no action taken pursuant to its terms shall create or be construed to create a trust of any kind, or a fiduciary relationship between a Participating Employer and any Participant or Beneficiary, or any other person, or as providing a Participant with a right to continue employment with a Participating Employer.

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Exhibit 10.1

Section 11.05. Income Tax Withholding. The amount actually distributed to the Participant will be reduced by applicable income tax withholding (if any). Unless the Participant has made a contrary election with the consent of the Committee, income tax on the entire annual distribution amount will be withheld from the cash portion of the distribution, and Stock will be used to satisfy withholding obligations only to the extent that the cash portion of the distribution is insufficient for this purpose. No later than the date as of which an amount first becomes includible in the income of the Participant for employment tax purposes, the Participant shall pay or make arrangements satisfactory to the Committee regarding the payment of any such tax. In addition, if prior to the date of distribution of any amount hereunder, the Federal Insurance Contributions Act (FICA) tax imposed under Code Sections 3101, 3121(a) and 3121(v)(2), where applicable, becomes due, the Company may direct that the Participant’s benefit be reduced to reflect the amount needed to pay the Participant’s portion of such tax.

Section 11.06. Amendment or Termination of Plan.

(a)    There shall be no time limit on the duration of the Plan.

(b)    Except as otherwise limited pursuant to Section 10.03 on or after a Change in Control, the Company may at any time amend the Plan by action of the Board or the Committee, including but not limited to modifying the terms and conditions applicable to (or otherwise eliminating) deferrals or contribution credits to be made on or after the amendment date; provided, however, that no amendment or termination may reduce or eliminate any Account balance accrued to the date of such amendment or termination (except as such Account balance may be reduced as a result of investment losses allocable to such Account). Further, the Committee is authorized to amend the Plan to the extent that such amendment is determined to be necessary or desirable in order to comply or facilitate compliance with the requirements of Code Section 409A or other applicable law; or that is otherwise desirable to promote efficient Plan administration; provided that any such amendment shall not increase Plan benefits or result in non-ministerial action that is prohibited under Section 11.01.

(c)    The Board may terminate the Plan (or the Plan shall automatically terminate) in accordance with the following provisions. Upon termination of the Plan, Accounts may be paid to Participants and Beneficiaries, but only if the following are met:

(i) The Board terminates the Plan within twelve (12) months of a corporate dissolution taxed under Code Section 331, or with the approval of a bankruptcy court pursuant to 11 U.S.C. §503(b)(1)(A), and the amounts accrued under the Plan but not yet paid are distributed to the Participants or Beneficiaries, as applicable, in a single sum payment, regardless of any distribution election then in effect, by the latest of: (A) the last day of the calendar year in which the Plan termination and liquidation occurs, (B) the last day of the calendar year in which the amount is no longer subject to a substantial risk of forfeiture, or (C) the last day of the first calendar year in which payment is administratively practicable.

(ii) The Board terminates the Plan at any time during the period that begins thirty (30) days prior and ends twelve (12) months following a Change in Control Event (as defined for purposes of Code Section 409A), provided that all arrangements required to be aggregated with this Plan under Code Section 409A are terminated and liquidated with respect to each Participant that experienced the Change in Control Event, so that all participants under similar arrangements are required to receive all amounts of compensation deferred under the terminated arrangements within twelve (12) months of the date of termination of the arrangements.

(iii) The Board terminates the Plan at any other time, provided that such termination does not occur proximate to a downturn in the financial health of the Company or an Affiliate. In such event, all amounts

37

Exhibit 10.1

accrued under the Plan but not yet paid will be distributed to all Participants or Beneficiaries, as applicable, in a single sum payment no earlier than twelve (12) months (and no later than twenty-four (24) months) after the date of termination, regardless of any distribution election then in effect. This provision shall not be effective unless all other plans required to be aggregated with this Plan under Code Section 409A are also terminated and liquidated. Notwithstanding the foregoing, any payment that would otherwise be paid during the twelve (12)-month period beginning on the Plan termination date pursuant to the terms of the Plan shall be paid in accordance with such terms. In addition, the Company or any Affiliate shall be prohibited from adopting a similar arrangement within three (3) years following the date of the Plan’s termination, unless any individual who was a Participant under this Plan is excluded from participating thereunder for such three (3) year period.

(iv) Except as provided in Paragraphs (i), (ii) and (iii) above or as otherwise permitted in regulations promulgated by the Secretary of the Treasury under Code Section 409A, any action that purports to terminate the Plan shall instead be construed as an amendment to discontinue further benefit accruals, but the Plan will continue to operate, in accordance with its terms as from time to time amended and in accordance with applicable Participant elections, with respect to the Participant’s benefit accrued through the date of termination, and in no event shall any such action purporting to terminate the Plan form the basis for accelerating distributions to Participants and Beneficiaries.

Section 11.07. Administrative Expenses. Costs of establishing and administering the Plan will be paid by the Participating Employers.

Section 11.08. Effect on Other Employee Benefit Plans. Deferrals credited to a Participant’s Account under this Plan shall not be considered “compensation” for the purpose of computing benefits under any qualified retirement plan maintained by a Participating Employer, but shall be considered compensation for welfare benefit plans, such as life and disability insurance programs sponsored by a Participating Employer, unless otherwise provided by the terms of such plan.

Section 11.09. Successors and Assigns. This Plan shall be binding upon and inure to the benefit of the Participating Employers, their successors and assigns and the Participants and their heirs, executors, administrators, and legal representatives.

Section 11.10. Right of Offset. The Company shall have the right to offset from the benefits payable hereunder any amount that the Participant owes to the Company or Affiliate or other entity in which the Company or an Affiliate maintains an ownership interest. The Company may effectuate the offset without the consent of the Participant (or the Participant’s spouse or Beneficiary, in the event of the Participant’s death).

Section 11.11. Amounts Accumulated Under Peoples Energy Plans. Notwithstanding anything in the Plan to the contrary, the following rules apply with respect to accounts originally credited under the Peoples Energy Corporation Executive Deferred Compensation Plan, the Peoples Energy Corporation Directors Deferred Compensation Plan and/or the Peoples Energy Corporation Directors Stock and Option Plan (collectively, the “Peoples Plans”) and transferred to this Plan. Peoples Energy, LLC, an Affiliate of the Company, is the successor to Peoples Energy Corporation.

(a)    Amounts held under the Peoples Plans as Stock Units and transferred to this Plan will continue to be held as Stock Units. The transferred Stock Units will be Locked Stock Units; provided that in lieu of the rules described in Section 5.04(d), any dividends (or similar distribution) that would have been payable on the Stock Units had such Stock Units been actual shares of Integrys Stock, if not already expressed in the form of shares of Integrys

38

Exhibit 10.1

Stock, shall be converted, for record keeping purposes, into whole and fractional Stock Units, with fractional units calculated to four decimal places. The conversion shall be accomplished by dividing the amount of the dividend or distribution by the mean price of a share of Integrys Stock on the payment date for the dividend or distribution.

(b)    “Cash accounts” transferred from the Peoples Plans shall continue to be credited with interest equivalent based on the rate specified in the Peoples Plan (the “Prime Rate Investment”), unless the Participant is offered the opportunity and elects to transfer such portion of the Participant’s Account to another Investment Option in accordance with Section 6.01(d). If a Participant elects to transfer to an alternate Investment Option, the transferred amounts may not be subsequently transferred back to the Prime Rate Investment.

(c)    Distribution of the portion of the Participant’s overall Account that is attributable to participation in the Peoples Plans will be made in accordance with the terms of the applicable Peoples Plan (and if applicable, the Participant’s distribution election); provided that, in accordance with Internal Revenue Service transition rules under Code Section 409A, on before December 31, 2008, a Participant may elect to have the portion of the benefit that was accrued and vested after December 31, 2004 distributed in accordance with the Participant’s distribution election under Article VIII of this Plan (Distribution of Post-2004 Account). An election in accordance with the Internal Revenue Service transition rules shall not operate to accelerate into the year in which the election is made amounts that would otherwise be distributed in a subsequent year, or to defer distribution of amounts that would otherwise be paid in the year in which the election is made into a subsequent year.

(d)    The shares of stock authorized for issuance under the predecessor Peoples Plans are not available for new grants under this Plan. However, grants previously made under the Peoples Plan and now held under this Plan will be charged against the pool of available shares for the predecessor Peoples Plans.

Section 11.12. Miscellaneous Distribution Rules.

(a)    Accelerated Distribution Following Section 409A Failure. If an amount under this Plan is required to be included in a Participant’s income under Code Section 409A prior to the date such amount is actually distributed, the Participant shall receive a distribution, in a lump sum, within ninety (90) days after the date it is finally determined that the Plan fails to meet the requirements of Code Section 409A. The distribution shall equal the amount required to be included in the Participant’s income as a result of such failure.

(b)    Permitted Delay in Payment. If a distribution required under the terms of this Plan would jeopardize the ability of the Company or of an Affiliate to continue as a going concern, the Company or the Affiliate shall not be required to make such distribution. Rather, the distribution shall be delayed until the first date that making the distribution does not jeopardize the ability of the Company or of an Affiliate to continue as a going concern. Further, if any distribution pursuant to the Plan will violate the terms of Section 16(b) of the Securities Exchange Act of 1934 or other Federal securities laws, or any other applicable law, then the distribution shall be delayed until the earliest date on which making the distribution will not violate such law.

33584577v4

39

EX-10.2

Exhibit 10.2

INTEGRYS ENERGY GROUP, INC.

PENSION RESTORATION AND

SUPPLEMENTAL RETIREMENT PLAN

As Amended and Restated Effective January 1, 2016

Exhibit 10.2

TABLE OF CONTENTS

	Page
ARTICLE I. DEFINITIONS AND CONSTRUCTION	2
Section 1.01. Definitions.	2
Section 1.02. Construction and Applicable Law.	6
ARTICLE II. PAYMENT ELECTIONS	7
Section 2.01. General Rules.	7
Section 2.02. Participant Payment Election.	7
ARTICLE III. PENSION RESTORATION BENEFIT	9
Section 3.01. Eligibility.	9
Section 3.02. Pension Restoration Benefit Formula.	9
Section 3.03. Distribution of Single Sum Benefits.	9
Section 3.04. Distribution of 180 Month Period Certain Installment Benefit.	10
Section 3.05. Distribution of Annuity Benefits.	10
Section 3.06. Death Benefits.	12
ARTICLE IV. SUPPLEMENTAL RETIREMENT BENEFIT	13
Section 4.01. Eligibility.	13
Section 4.02. Final Average Earnings.	13
Section 4.03. Supplemental Retirement Benefit Formula.	13
Section 4.04. Distribution of Single Sum Benefits.	15
Section 4.05. Distribution of 180 Month Period Certain Installment Benefit.	15
Section 4.06. Distribution of Annuity Benefits.	15
Section 4.07. Death Benefits.	16
ARTICLE V. SPECIAL DEFINED CONTRIBUTION CREDITS	18
Section 5.01. Application.	18
Section 5.02. Distribution In Accordance With This Plan.	18
Section 5.03. Distribution of Single Sum Benefits.	18
Section 5.04. Distribution of 180 Month Period Certain Installment Benefit.	18
Section 5.05. Distribution of Annuity Benefits.	19
Section 5.06. Death Benefits.	19
ARTICLE VI. SPECIAL RULES APPLICABLE IN THE EVENT OF A CHANGE IN CONTROL OF THE COMPANY	21
Section 6.01. Application.	21
Section 6.02. Definitions	21
Section 6.03. Special Provisions Following Change in Control.	22
Section 6.04. Maximum Payment Limitation.	24
Section 6.05. Resolution of Disputes.	25
ARTICLE VII. GENERAL PROVISIONS	26
Section 7.01. Administration.	26
Section 7.02. Claims Procedures.	26
Section 7.03. Participant Rights Unsecured.	27
Section 7.04. Tax Withholding.	27
Section 7.05. Amendment or Termination of Plan.	27
Section 7.06. Administrative Expenses.	28
Section 7.07. Effect on Other Employee Benefit Plans.	28
Section 7.08. Successor and Assigns.	29
Section 7.09. Additional Section 409A Provisions.	29
Section 7.10. Offset.	29

i

Exhibit 10.2

INTEGRYS ENERGY GROUP, INC.

PENSION RESTORATION AND

SUPPLEMENTAL RETIREMENT PLAN

The Integrys Energy Group, Inc. Pension Restoration and Supplemental Retirement Plan (the “Plan”) was originally adopted effective January 1, 2001 as the WPS Resources Corporation Pension Restoration and Supplemental Retirement Plan. The Plan name was changed to reflect the change in the name of the plan sponsor from WPS Resources Corporation to Integrys Energy Group, Inc., the predecessor of Integrys. Holding, Inc. (the “Company”). The purpose of the Plan is to promote the best interests of the Company and its stockholders by attracting and retaining key management employees possessing a strong interest in the successful operation of the Company and its affiliates and by encouraging their continued loyalty, service and counsel to the Company and its affiliates. Effective April 1, 2008, no additional Employees will become Participants in the Supplemental Retirement Benefit component of the Plan. Effective January 1, 2018, no additional Employees will become eligible for the Pension Restoration Benefit component of the Plan.

The Plan is amended and restated effective January 1, 2016, as set forth herein.

1

Exhibit 10.2

ARTICLE I. DEFINITIONS AND CONSTRUCTION

Section 1.01. Definitions. The following terms have the meanings indicated below unless the context in which the term is used clearly indicates otherwise:

(a)    Actuarial Equivalent or Actuarially Equivalent: A benefit of equivalent actuarial value, determined by assuming payment made or commencing on the Calculation Date and determined on the basis of the following interest and mortality assumptions:

(1)    Pension Restoration Benefit.

(A) For purposes of converting from a single sum payment to a single life annuity without survivor benefits ("SLA"), or from a SLA to a single sum payment, the interest rate and mortality table specified under Part A or C of the Retirement Plan (whichever is applicable to the Participant) that is determined pursuant to Code Section 417(e)(3) and that is used under the Retirement Plan for purposes of converting a SLA into a single sum benefit amount or a single sum benefit amount into a SLA (the “417(e)(3) Rates”).

(B) For purposes of converting from a SLA to a one hundred eighty (180) month period certain installment benefit, a seven percent (7%) interest rate and the 1983 Group Annuity Mortality Table (Unisex).

(C) For purposes of converting from a SLA to a joint and fifty percent (50%) surviving Spouse annuity or to any optional form of annuity distribution that is available to the Participant, the interest, mortality or other factors that would be used for such purposes if the Pension Restoration Benefit were being paid under Part A or Part C of the Retirement Plan (whichever is applicable to the Participant).

(2)    Supplemental Retirement Benefit.

(A) For purposes of calculating the offset under Section 4.03(a)(2)(B), the 417(e)(3) Rates.

(B) For purposes of converting from the one hundred eighty (180) month period certain installment benefit to a single sum benefit, the interest rate component of the 417(e)(3) Rates, but with no mortality assumption or adjustment.

(C) For purposes of converting from the one hundred eighty (180) month period certain installment benefit to an annuity benefit, or for purposes of the early commence reduction described in Section 6.03(a)(2)(B), a seven percent (7%) interest rate and the 1983 Group Annuity Mortality Table (Unisex).

(3)    Defined Contribution Restoration and SERP Benefit.

(A) For purposes of converting from a single sum benefit to a SLA, the 417(e)(3) Rates.

2

Exhibit 10.2

(B) For purposes of converting from a SLA to another form of annuity payment or to a one hundred eighty (180) month period certain installment benefit, a seven percent (7%) interest rate and the 1983 Group Annuity Mortality Table (Unisex).

(b)    Affiliate: For all purposes of the Plan other than Article VI, a corporation, trade or business that, with the Company, constitutes a controlled group of corporations or a group of trades or businesses under common control within the meaning of Code Section 414(b) and (c); provided that Code Section 414(b) and (c) shall be applied by substituting “at least fifty percent (50%)” for “at least eighty percent (80%)” each place it appears therein.

(c)     Age/Service Point Contributions: The non-elective contributions that (i) are made by the Company or an Affiliate to the Qualified Defined Contribution Plan, (ii) are not contingent upon the Participant having made contributions to such plan, and (iii) the amount of which is based on the sum of the Participant’s age and years of service.

(d)    Beneficiary: The person or entity designated by a Participant to be his or her beneficiary for purposes any death benefit that may become payable under Sections 3.06 or 4.07. If a Participant designates his or her Spouse as a beneficiary, such beneficiary designation (to the extent it relates to the Spouse) shall become null and void on the date the Committee obtains actual written notice of the Participant’s divorce or legal separation from such Spouse; provided that neither the Plan nor Committee shall be liable to any Beneficiary for the payments that have been made to such spouse prior to the date the Committee is notified in writing of such divorce or legal separation from such spouse. If a valid designation of beneficiary is not in effect at the time of the Participant’s death, the estate of the Participant is deemed to be the sole beneficiary. If a beneficiary dies while entitled to receive distributions, any remaining payments shall be paid to the contingent beneficiary designated by the Participant. If payments have been made to a beneficiary or beneficiaries following the Participant’s death and all beneficiaries and contingent beneficiaries designated by the Participant die prior to receiving all of the benefits payable on behalf of the Participant, any remaining payments due in accordance with the terms of the Plan shall be paid to the estate of the beneficiary or contingent beneficiary who last received payments under the Plan. If all beneficiaries and contingent beneficiaries designated by the Participant die prior to receiving any payments from the Plan, any benefits payable on behalf of the Participant shall be paid to the estate of the Participant. Beneficiary designations shall be in writing, filed with the Committee, and in such form as the Committee may prescribe for this purpose.

(e)    Board: The Board of Directors of the Company.

(f)    Calculation Date: The first day of the month following the month in which occurs the Participant’s Separation from Service.

(g)    Cause: Termination by the Company or an Affiliate of a Participant’s employment in connection with or following a Change in Control of the Company (as defined in Section 6.02) shall be limited to the following:

(i) the engaging by the Participant in intentional conduct not taken in good faith which has caused demonstrable and serious financial injury to the Company and/or an Affiliate, as evidenced by a determination in a binding and final judgment, order or decree of a court or administrative agency of competent jurisdiction, in effect after exhaustion or lapse of all rights of appeal, in an action, suit or proceeding, whether civil, criminal, administrative or investigative;

(ii) conviction of a felony (as evidenced by binding and final judgment, order or decree of a court of competent jurisdiction, in effect after exhaustion of all rights of appeal) which substantially impairs the Participant’s ability to perform his or her duties or responsibilities;

3

Exhibit 10.2

(iii) continuing willful and unreasonable refusal by the Participant to perform the Participant’s duties or responsibilities (unless significantly changed without the Participant’s consent); or

(iv) material violation of the Company’s Code of Conduct.

(h)    Chief Executive Officer: The Chief Executive Officer of WEC Energy Group, Inc.

(i)    Code: The Internal Revenue Code of 1986, as interpreted by regulations and rulings issued pursuant thereto, all as amended and in effect from time to time. Any reference to a specific provision of the Code shall be deemed to include a reference to any successor provision thereto.

(j)    Committee: An internal administrative committee appointed by the Chief Executive Officer to administer the Plan in accordance with Article VII. Prior to the Merger Date, the Committee was the Compensation Committee of the Board.

(k)    Company: Integrys Holding, Inc. and any successor to all or substantially all of the Company's assets or business. Prior to the Merger Date, the Company was known as Integrys Energy Group, Inc. Prior to February 21, 2007, the Company was known as WPS Resources Corporation.

(l)    Credited Service: A Participant’s credited service for benefit accrual purposes that (1) with respect to periods prior to January 1, 2013, is recognized under the Retirement Plan for purposes of calculating the amount of the Participant’s benefit under that plan, and (2) with respect to periods after December 31, 2012 and before January 1, 2018, would have been recognized under the Retirement Plan if the Retirement Plan had continued to recognize benefit accrual service. Employment after December 31, 2017 will not be recognized as Credited Service for purposes of this Plan.

(m)    Deferred Compensation Plan: The Integrys Energy Group, Inc. Deferred Compensation Plan, as amended and in effect from time to time, or any successor to such plan.

(n)    Employee: A common law employee of a Participating Employer who is a management or highly compensated employee, as those terms are defined for purposes of the “top-hat” rules of ERISA.

(o)    ERISA: The Employee Retirement Income Security Act of 1974, as interpreted by regulations and rulings issued pursuant thereto, all as amended and in effect from time to time. Any reference to a specific provision of ERISA shall be deemed to include a reference to any successor provision thereto.

(p)    Merger Date: The date of the closing of the Agreement and Plan of Merger dated as of June 22, 2014, between Integrys Energy Group, Inc. and Wisconsin Energy Corporation, which is June 29, 2015.

(q)    Offset Amount: The sum of (i) the Participant’s qualified and non-qualified plan balances, as of the Calculation Date applicable to the Participant, that are attributable to Age/Service Point Contributions (but not employer matching contributions) to the Qualified Defined Contribution Plan and all Special Defined Contribution Credits allocated to the Participant under the Deferred Compensation Plan with respect to the 2013 – 2017 calendar years, in all cases including any investment gains or losses through the Calculation Date on such contributions or credits, and (ii) any Age/Service Point Contributions to the Qualified Defined Contribution Plan and any Special Defined Contribution Credits to the Deferred Compensation Plan that will be allocated after the Calculation Date but the amount of which is determinable as of the Calculation Date (without any adjustment for investment gains or losses on such amounts).

(r)    Participant: An Employee who is eligible to participate in the Deferred Compensation Plan (or any successor plan thereto); provided (i) that the Pension Restoration Benefit Component of the Plan is limited to those Participants who are covered under the Retirement Plan, (ii) except as otherwise provided by the Committee, an Employee of Integrys Energy Services, Inc. (or a subsidiary thereof) who is employed in a non-officer position, even though designated for participation in the Deferred Compensation Plan, shall not be eligible for the Pension

4

Exhibit 10.2

Restoration Benefit Component of the Plan if the Employee is covered under an employment contract or agreement that excludes the Employee from receiving pension restoration, supplemental retirement or similar restoration benefits or credits, or the Employee is covered under an employment contract or agreement that references the Employee’s eligibility for deferred compensation generally but that does not specifically provide for the Participant as being eligible for pension restoration, supplemental retirement or similar restoration benefits or credits, and (iii) the Supplemental Retirement Benefit component of the Plan is limited to those Employees who were designated for participation for that component prior to April 1, 2008. Effective for the 2017 calendar year only, an Employee shall become eligible to participate in the Pension Restoration Benefit component of the Plan only if the Employee (i) was hired prior to January 1, 2008; and (ii) is either eligible to participate in the WEC Energy Group Short-Term Performance Plan or is eligible for a Group B award under the WEC Energy Group Annual Incentive Pay Plan for Non-Executives. Effective April 1, 2008, no additional Employees will become Participants in the Supplemental Retirement Benefit component of the Plan. Effective January 1, 2018, no additional Employees will become Participants in the Pension Restoration Benefit component of the Plan.

(s)    Participating Employer: The Company and each Affiliate that participates in the Plan for the benefit of one or more Participants. Effective as of the Merger Date, the following Affiliates are Participating Employers: Peoples Energy LLC, The Peoples Gas Light and Coke Company, North Shore Gas Company, WEC Business Services, LLC (with respect to only former employees of Integrys Business Support, LLC), Michigan Gas Utilities Corporation, Minnesota Energy Resources Corporation, Wisconsin Public Service Corporation, Integrys Transportation Fuels, LLC.

(t)    Payment Date: The last business day of the seventh month following the month in which the Participant’s Separation from Service occurs. This is the date on which payment of a Participant’s vested benefit is made (if paid as a single sum) or commences (if paid in installments or as a monthly annuity). All benefits are paid on the last business day of the month.

(u)    Pension Restoration Benefit: The benefit described in Article III.

(v)    Plan: The Integrys Energy Group, Inc. Pension Restoration and Supplemental Retirement Plan, as from time to time amended and in effect.

(w)    Qualified Defined Contribution Plan: The Integrys Energy Group 401(k) Plan for Administrative Employees, as amended and in effect from time to time, or any successor to such plan.

(x)    Regular Monthly Payment: A Participant’s normal monthly installment or annuity payment amount determined as of the Calculation Date in accordance with the terms of the Plan, without regard to the Retroactive Benefit Payment or interest on the Retroactive Benefit Payment.

(y)    Retirement Plan: Part A or C (whichever is applicable to the Participant) of the Integrys Energy Group Retirement Plan, as amended and in effect from time to time, or any successor thereto.

(z)    Retroactive Benefit Payment: The sum of the Regular Monthly Payments that would have been made, if monthly benefit payments had commenced with a payment on the last day of the month in which occurs the Calculation Date, during the period beginning with the month in which occurs the Calculation Date and ending with the month preceding the month in which occurs the Payment Date.

(aa)    Separation from Service: A Participant’s Separation from Service occurs when the Company (and its Affiliates) and the Participant reasonably anticipate that no further services (either as an employee or as an independent contractor) will be performed by the Participant for the Company (or an Affiliate) after a certain date, or that the level of bona fide services the Participant will perform for the Company (or the Affiliate) after such date (either as an employee or as an independent contractor) will permanently decrease to no more than twenty percent (20%) of the average level of bona fide services performed by the Participant (whether as an employee or independent contractor) for the Company or an Affiliate over the immediately preceding thirty-six (36) month period (or such lesser period of actual services). A Participant is not considered to have incurred a Separation from Service if the Participant is absent from active employment due to military leave, sick leave or other bona fide leave

5

Exhibit 10.2

of absence and if the period of such leave does not exceed the greater of (i) six (6) months, or (ii) the period during which the Participant’s right to reemployment by the Company or an Affiliate is provided either by statute or by contract; provided that if the leave of absence is due to a medically determinable physical or mental impairment that can be expected to result in death or last for a continuous period of not less than six (6) months, where such impairment causes the Participant to be unable to perform the duties of his or her position of employment or any substantially similar position of employment, the leave may be extended for up to twenty-nine (29) months without causing a Separation from Service.

(bb)    Special Defined Contribution Credits: In the case of a Participant who is in the limited class of Participants who are eligible for participation in the Supplemental Retirement Benefit component of the Plan, the credits made to a Participant’s account under Sections 3.05, 3.06 and 3.07 of the Deferred Compensation Plan with respect to the 2013-2017 calendar years, together with investment gains or losses thereon. Special Defined Contribution Credits are determined by reference to the calendar year to which the Special Defined Contribution Credit relates, which might be different than the calendar year in which the Special Defined Contribution Credit is physically allocated to the Participant’s account, e.g., the age/service restoration credit for the 2012 calendar year is not a Special Defined Contribution Credit even though the credit was physically allocated in early 2013, and conversely, the age/service restoration credit for the 2017 calendar year will be a Special Defined Contribution Credit even though the credit will be physically allocated in early 2018. Effective as of January 1, 2016, Special Defined Contribution Credits are no longer made under the Plan because the limited class of Participants eligible for these credits have terminated employment with the Company and its Affiliates.

(cc)    Spouse: A person to whom the Participant is legally married.

(dd)    Supplemental Retirement Benefit: The benefit described in Article IV.

(ee)    Trust: Any fund created by a rabbi trust agreement established by the Company referencing this Plan, as amended from time to time.

Section 1.02. Construction and Applicable Law.

(a)    Wherever any words are used in the masculine, they shall be construed as though they were used in the feminine in all cases where they would so apply; and wherever any words are use in the singular or the plural, they shall be construed as though they were used in the plural or the singular, as the case may be, in all cases where they would so apply. Titles of articles and sections are for general information only, and the Plan is not to be construed by reference to such items.

(b)    This Plan is intended to be a plan of deferred compensation maintained for a select group of management or highly compensated employees as that term is used in ERISA, and shall be interpreted so as to comply with the applicable requirements thereof. In all other respects, the Plan is to be construed and its validity determined according to the laws of the State of Wisconsin, without regard to the principle of conflict of laws, to the extent such laws are not preempted by federal law. Any action for benefits under the Plan or to enforce the terms of the Plan shall be heard in the State of Wisconsin by the court with jurisdiction over the claim. In case any provision of the Plan is held illegal or invalid for any reason, the illegality or invalidity will not affect the remaining parts of the Plan, but the Plan shall, to the extent possible, be construed and enforced as if the illegal or invalid provision had never been inserted.

6

Exhibit 10.2

ARTICLE II. PAYMENT ELECTIONS

Section 2.01. General Rules.

(a)    Participant Payment Elections. A Participant’s vested benefits are distributed based upon the Participant’s payment election (or deemed payment election).

(b)    Coordinated Distribution of Pension Restoration Benefit, Supplemental Retirement Benefit and Certain Deferred Compensation Benefits. With respect to any Participant who has been designated for participation in both the Pension Restoration Benefit and the Supplemental Retirement Benefit components of the Plan, the Participant makes a single benefit payment election (or deemed election) that governs the form and time of distribution of (1) the Pension Restoration Benefit, (2) the Supplemental Retirement Benefit, and (3) the Special Defined Contribution Credits. The Participant is not able to make separate elections with respect to each of these benefits.

Section 2.02. Participant Payment Election.

(a)    Payment Election as to Form of Payment. Each Participant who became a Participant prior to January 1, 2009 and whose participation is limited to the Pension Restoration Benefit Component of the Plan shall make a payment election whether to receive his or her vested Pension Restoration Benefit either as (i) a single sum cash payment, or (ii) an annuity distribution. Each Participant who became a Participant prior to January 1, 2009 and who participates in both the Pension Restoration Benefit and the Supplemental Retirement Benefit components of the Plan shall make a single payment election whether to receive his or her vested benefits either as (i) a single sum cash payment, (ii) a one hundred eighty (180) month period certain installment payment, or (ii) an annuity distribution. The Participant’s single payment election will govern the distribution of the Participant’s vested Pension Restoration Benefit, the Participant’s vested Supplemental Retirement Benefit, and if the Participant has received Special Defined Contribution Credits, the portion of the Participant’s vested Account balance that is attributable to Special Defined Contribution Credits. A Participant who becomes a Participant after December 31, 2008 shall be deemed to have elected a single sum distribution, and such a Participant may not otherwise make a payment election.

(b)    Annuity Distribution. A Participant who has elected (or is deemed to have elected) the annuity payment option is not required to elect the specific form of annuity at the time of making the payment election, so long as the available forms of annuity distribution are actuarially equivalent for purposes of Code Section 409A. If the available forms of annuity distribution are actuarially equivalent for purposes of Code Section 409A, the Participant may choose the specific form of monthly annuity at any time prior to the Calculation Date, in accordance with rules prescribed by the Committee. Additional rules regarding annuity benefit distribution are set forth in Sections 3.05 and 4.06.

(c)    Date of Payment Election. In the case of an Employee who becomes a Participant prior to January 1, 2009, the payment election must be made on or before December 31, 2008. The election on file (or deemed to be on file) for such Participant at December 31, 2008 will be the Participant’s payment election. All payment elections must be made in such form and in accordance with such rules prescribed by the Committee or its delegate.

(d)    Default Payment Election. If a Participant fails to make such a payment election within the prescribed period, the Participant will be deemed to have elected to receive a single sum distribution; provided that in the case of a Participant who participates in both the Pension Restoration Benefit and the Supplemental Retirement Benefit components of the Plan, the Participant’s benefit election on file at December 31, 2008, even if originally made only with respect to the Pension Restoration Benefit, shall be deemed to be the Participant’s payment election both with respect to the Pension Restoration Benefit and the Supplemental Retirement Benefit (and if the Participant has received Special Defined Contribution Credits, the portion of the Participant’s vested Account balance that is attributable to Special Defined Contribution Credits).

7

Exhibit 10.2

(e)    Irrevocability of Payment Election. A Participant’s payment election (or deemed payment election) is irrevocable.

8

Exhibit 10.2

ARTICLE III. PENSION RESTORATION BENEFIT

Section 3.01. Eligibility. An Employee is eligible for the Pension Restoration Benefit if:

(a)    The Employee is eligible for participation in the Pension Restoration Benefit component of the Plan and the Employee, in accordance with Section 1.01(r), has become a Participant in the Pension Restoration Benefit component of the Plan; and

(b)    The Participant is covered under and has a vested entitlement to a retirement benefit from the Retirement Plan.

Section 3.02. Pension Restoration Benefit Formula. The Pension Restoration Benefit accrued by an eligible Participant is determined as of the Calculation Date and, when expressed in the form of a life annuity without survivor benefits commencing with a payment for the month in which occurs the Calculation Date, is equal to the difference between (a) and (b) below:

(a)    The monthly retirement benefit that would be payable to the Participant under the Retirement Plan if the benefit were determined by applying all of the terms and conditions of the Retirement Plan, except for the following modifications or assumptions:

(1)    The benefit is paid in the form of a life annuity without survivor benefits, regardless of the form of benefit actually elected by the Participant under the Retirement Plan;

(2)    The benefit is paid commencing with a payment for the month in which occurs the Calculation Date, regardless of the Participant’s actual date of benefit commencement under the Retirement Plan and regardless of the Payment Date applicable to the Participant under this Plan;

(3)    The benefit is calculated as if base salary and annual incentive (but not long-term incentive) amounts deferred by the Participant under the Deferred Compensation Plan (or a different nonqualified deferred compensation plan sponsored by an Affiliate) had been paid to the Participant as current compensation in the year of the deferral;

(4)    The benefit is calculated as if the compensation limitation of Section 401(a)(17) of the Code and the maximum benefit limitation of Section 415 of the Code did not apply.

(b)    The monthly retirement benefit that would be payable to the Participant under the Retirement Plan if the benefit were determined in accordance with the modifications or assumptions described in Section 3.02(a)(1) and (2) above, but otherwise applying all of the terms and conditions of the Retirement Plan. For this purpose, the Participant’s benefit under the Retirement Plan shall be determined by attributing to the Participant any portion of the Retirement Plan benefit that is assigned to an alternate payee pursuant to a domestic relations order.

Section 3.03. Distribution of Single Sum Benefits. If the Participant’s Pension Restoration Benefit is payable in a single sum, distribution will be made in accordance with the following rules:

(a)    Time of Payment. The single sum payment will be calculated as of the Calculation Date but paid on the Payment Date.

(b)    Amount of Single Sum Benefit. The single sum cash payment shall be equal to the sum of (1) an amount that, as of the Calculation Date, is Actuarially Equivalent to the Participant’s Pension Restoration Benefit as calculated under Section 3.02 above. For a married Participant, the single sum benefit does not include the value of

9

Exhibit 10.2

any surviving Spouse benefit that would be paid if the Participant had instead elected an annuity benefit, i.e., the single sum benefit is Actuarially Equivalent to the single life annuity with no survivor benefits. The payment to be made on the Payment Date will equal the sum of (1) the single sum amount determined, as of the Calculation Date, in accordance with the preceding sentence, and (2) interest on the single sum amount from the last day of the month in which occurs the Calculation Date through the Payment Date.Interest under clause (2) above, for the period through the last day of the month in which occurs the six (6) month anniversary of the Participant’s Separation from Service, shall be determined at the 417(e)(3) Rate (first segment rate) in effect under the Retirement Plan for the calendar year in which occurs the Calculation Date.

(c)    Death Prior to Payment Date. This Section 3.03 applies only if the Participant is alive on the Payment Date. If the Participant dies prior to the Payment Date, the benefits (if any) payable following the Participant’s death shall be determined in accordance with Section 3.06.

Section 3.04. Distribution of 180 Month Period Certain Installment Benefit. If the Participant’s Pension Restoration Benefit is payable as a one hundred eighty (180) month period certain installment benefit (in accordance with Section 2.02, only certain Participants are eligible for this form of payment), distribution will be made in accordance with the following rules:

(a)    Time of Payment. The one hundred eighty (180) month period certain installment benefit will be calculated as of the Calculation Date but paid beginning on the Payment Date.

(b)    Amount of Each Installment. The amount of each monthly installment shall be determined by converting the Participant’s Pension Restoration Benefit as calculated under Section 3.02 above into an Actuarially Equivalent one hundred eighty (180) month period certain installment benefit. For a married Participant, the one hundred eighty (180) month period certain installment benefit does not include the value of any surviving Spouse benefit that would be paid if the Participant had instead elected an annuity benefit, i.e., the one hundred eighty (180) month period certain installment benefit is Actuarially Equivalent to the single life annuity with no survivor benefits. The payment made on the Payment Date will include (1) the Regular Monthly Payment for the month in which occurs the Payment Date, (2) the Retroactive Benefit Payment, and (3) interest on each monthly installment that constitutes part of the Retroactive Benefit Payment for the period from the date on which such installment would have been paid had monthly payments commenced with a payment on the last day of the month that includes the Calculation Date through the Payment Date. Following the payment on the Payment Date, payments to the eligible Participant in an amount equal to the Regular Monthly Payment shall continue until a total of one hundred eighty (180) monthly payments have been made; provided that for purposes of determining whether a total of one hundred eighty (180) monthly payments have been made, the payment made on the Payment Date will be treated as consisting of seven (7) payments. Interest under clause (3) above, for the period through the last day of the month in which occurs the six (6) month anniversary of the Participant’s Separation from Service, shall be determined at the 417(e)(3) Rate (first segment rate) in effect under the Retirement Plan for the calendar year in which occurs the Calculation Date. For example, if the Participant incurs a Separation from Service on December 31, 2009, the Calculation Date is January 1, 2010, the first payment would have been made on January 31, 2010 if payment had commenced with a payment for the month that includes the Calculation Date, and the Payment Date will be July 31, 2010. Interest on each monthly installment that constitutes part of the Retroactive Benefit Payment for the period from the date on which the monthly installment otherwise would have been paid through the Payment Date will be credited at the 2010 417(e)(3) Rate (first segment rate) in effect under the Retirement Plan.

(c)    Death Prior to Payment Date. This Section 3.04 applies only if the Participant is alive on the Payment Date. If the Participant dies prior to the Payment Date, the benefits (if any) payable following the Participant’s death shall be determined in accordance with Section 3.06.

Section 3.05. Distribution of Annuity Benefits. If the Participant’s Pension Restoration Benefit is payable as an annuity, distribution will be made in accordance with the following rules:

(a)    Normal Form of Distribution. If the Participant has elected (or is deemed to have elected) an annuity form of distribution, then payment for an unmarried Participant will be made in accordance with subsection (a)(1) below, and payment for a married Participant, unless the Participant has validly elected payment in an alternate form

10

Exhibit 10.2

of annuity payment in accordance with subsection (b) below, will be made in accordance with subsection (a)(2) below:

(1)    Unmarried Participant. If the Participant is not married on the Calculation Date, distribution will be in the form of a monthly single life annuity in the amount determined under Section 3.02. Monthly payments will commence on the Payment Date applicable to the Participant and will continue until and including a payment for the month in which occurs the Participant’s death.

(2)    Married Participant. If the Participant is married on the Calculation Date, distribution will be in the form of a joint and fifty percent (50%) survivor annuity with the Participant’s Spouse as of the Calculation Date as the sole contingent annuitant. Monthly payments under the joint and fifty percent (50%) survivor annuity will commence on the Payment Date applicable to the Participant and will continue until and including a payment for the month in which occurs the Participant’s death. If the Participant predeceases the Spouse to whom he or she was married on the Calculation Date, fifty percent (50%) of the Regular Monthly Payment Amount applicable to the Participant during his or her lifetime shall continue during the remaining lifetime of such Spouse. The Regular Monthly Payment Amount payable to the Participant during his or her lifetime will be the amount determined under Section 3.02 reduced, in order to reflect the cost of the survivor benefit, in the same manner as the benefit would be reduced under Part A or Part C of the Retirement Plan (whichever is applicable to the Participant) if the benefit were being paid under the Retirement Plan.

(b)    Alternate Forms of Annuity Distribution. In lieu of the normal form of payment applicable under subsection (a) above, a Participant who participates in Part A of the Retirement Plan, who is married on the Calculation Date, and who has in effect an election of the annuity payment method, may elect, in accordance with such conditions as may be established by the Committee, to receive payment in an alternate form of annuity that would be available to the Participant under Part A of the Retirement Plan if the Pension Restoration Benefit were being paid under Part A of the Retirement Plan rather than under this Plan. In lieu of the normal form of payment applicable under subsection (a) above, a Participant who participates in Part C of the Retirement Plan and who has in effect an election of the annuity payment method, may elect, in accordance with such conditions as may be established by the Committee, to receive payment in an alternate form of annuity that would be available to the Participant under Part C of the Retirement Plan if the Pension Restoration Benefit were being paid under Part C of the Retirement Plan rather than under this Plan. The alternate form of annuity distribution shall be calculated by converting the monthly benefit amount determined under Section 3.02 into a payment in such alternate annuity form, with the conversion accomplished by using the adjustment factors that would be used under the Retirement Plan for purposes of converting from the normal form of benefit to an alternate form of annuity if the Pension Restoration Benefit were being paid under Part A of Part C of the Retirement Plan, whichever is applicable to the Participant. If the Participant elects payment in an alternate form of annuity that provides surviving Spouse benefits following the Participant’s death, the surviving Spouse benefits will be paid to the Spouse to whom the Participant is married on the Calculation Date. The Participant’s election of an alternate form of annuity must be made prior to the Calculation Date, and becomes irrevocable on the Calculation Date; provided that if the Participant is covered under Part A of the Retirement Plan and is not married on the Calculation Date, any prior election of payment in an alternate form of annuity shall be null and void.

(c)    Regular Monthly Payments and the Retroactive Benefit Payment. The payment made on the Payment Date will include (1) the Regular Monthly Payment for the month in which occurs the Payment Date, (2) the Retroactive Benefit Payment, and (3) interest on each monthly installment that constitutes part of the Retroactive Benefit Payment for the period from the date on which such installment would have been paid had monthly payments commenced with a payment on the last day of the month that includes the Calculation Date through the Payment Date. Each subsequent monthly payment to the Participant will be an amount equal to the Regular Monthly Payment. Interest under clause (3) above, for the period through the last day of the month in which occurs

11

Exhibit 10.2

the six (6) month anniversary of the Participant’s Separation from Service, shall be determined at the 417(e)(3) Rate (first segment rate) in effect under the Retirement Plan for the calendar year in which occurs the Calculation Date.

(d)    Death Prior to Payment Date. This Section 3.05 applies only if the Participant is alive on the Payment Date. If the Participant dies prior to the Payment Date, the benefits (if any) payable following the Participant’s death shall be determined in accordance with Section 3.06.

Section 3.06. Death Benefits. The form and time of benefit distribution is irrevocably established at the earlier to occur of (1) the Payment Date (which, in accordance with Section 1.409A-3(b) of the Income Tax Regulations, is an objectively determinable and nondiscretionary date that is based upon the Participant’s Separation from Service and that is fixed at the time of the Participant’s Separation from Service), and (2) the date of the Participant’s death.

(a)    Death Prior to Payment Date. If a Participant who is eligible for a Pension Restoration Benefit dies prior to the Payment Date (including a Participant who is eligible for a Pension Restoration Benefit who dies during employment), the Participant’s Beneficiary will receive a single sum payment equal to the single sum payment to which the Participant would have been entitled to as of the Calculation Date if the Participant had in effect a single sum payment election under Article II (regardless of the election actually made by the Participant), together with interest, at the 417(e)(3) Rate (first segment rate) from the last day of the month in which occurs the Calculation Date through the last day of the month preceding the month in which payment to the Beneficiary is made.

(b)    Death on or After the Payment Date.

(1)    Death After Commencement of Installment Payments. If the Participant’s benefit is being distributed as a one hundred eighty (180) month period certain installment benefit and the Participant dies on or after the Payment Date, i.e., on or after the date on which installment distributions to the Participant have begun, but prior to the date on which one hundred eighty (180) payments have been made, monthly installment distributions to the Beneficiary (at the same time as payments to the Participant would have been made) shall continue until the total number of monthly installments paid to the Beneficiary, when aggregated with the number of monthly installments paid to the Participant prior to his or her death, equals one hundred eighty (180).

(2)    Death After Commencement of Annuity Payments. If the Participant’s benefit is being distributed as an annuity and the Participant dies on or after the Payment Date, i.e., on or after the date on which payment of Plan benefits has actually begun, the only benefits payable following the Participant’s death shall be those (if any) payable under the form of annuity distribution in which the Participant’s benefit was being paid. Thus, for example, if the Participant was receiving payments in the form of a single life annuity, no further benefits are payable following the Participant’s death. Similarly, if the Participant was receiving benefits in the form of a joint and fifty percent (50%) surviving Spouse annuity, the only benefits payable following the Participant’s death shall be those payable pursuant to the fifty percent (50%) survivor feature of the annuity benefit, to the Spouse (if still living) to whom the Participant was married on the Calculation Date. There is no guarantee that the total amount of benefits received by the Participant (and if applicable, the Participant’s surviving Spouse) under an annuity form of distribution will be at least equal to the amount that would have been paid to the Participant if the Participant had elected distribution in a single sum or in installments.

12

Exhibit 10.2

ARTICLE IV. SUPPLEMENTAL RETIREMENT BENEFIT

Section 4.01. Eligibility. Except as provided in Section 6.03(c), an Employee is eligible for the Supplemental Retirement Benefit if:

(a)    The Committee, prior to April 1, 2008, has designated the Employee for participation in the Supplemental Retirement Benefit component of the Plan, and the Employee, in accordance with Section 1.01(r), has become a Participant in the Supplemental Retirement Benefit component of the Plan; and

(b)    Except as provided in Section 4.07 with respect to a Participant whose Separation from Service is caused by the Participant’s death, the Participant’s Separation from Service occurs after the Participant has attained fifty-five (55) years of age and after the Participant has completed at least ten (10) years of Credited Service.

Section 4.02. Final Average Earnings.

(a)    For purposes of calculating a Participant’s Supplemental Retirement Benefit, “Final Average Earnings” means one thirty-sixth (1/36th) of the base salary and annual (but not long-term) incentive, determined prior to reduction for contributions made at the Participant’s election to a plan or arrangement under Section 125 or 401(k) of the Code and prior to reduction for elective deferral contributions under the Deferred Compensation Plan (or a different nonqualified deferred compensation plan sponsored by an Affiliate), paid to the Participant by the Company or a participating Affiliate during whichever of the following periods produces the higher average:

(1)    The month during which occurs the Participant’s Separation from Service and the immediately preceding thirty-five (35) months; or

(2)    the three calendar years preceding the calendar year in which occurs the Participant’s Separation from Service.

(b)    Notwithstanding subsection (a), the Committee, in its sole discretion, may adjust a Participant’s Final Average Earnings if the Committee determines that such action is necessary or desirable in order to effectuate the intent of this Plan, including, without limitation, an adjustment to exclude one or more annual incentive payments from the calculation of the Participant’s Final Average Earnings where application of the foregoing definition would result in the Participant receiving credit for more than three annual incentive awards in the calculation of Final Average Earnings as a result of differences in the timing of payments of such awards.

(c)    Notwithstanding subsections (a) and (b), for any Participant who continues to be employed by the Company or a participating Affiliate on and after December 31, 2017, the Participant’s Final Average Earnings will be determined as of December 31, 2017 as if the Participant had incurred a Separation from Service on that date. Salary, incentive or other compensation paid to the Participant after December 31, 2017 will not be recognized.

Section 4.03. Supplemental Retirement Benefit Formula.

(a)    Participants With 15 or More Years of Credited Service. The Supplemental Retirement Benefit for a Participant who satisfies the eligibility requirements of Section 4.01 and who has fifteen (15) or more years of Credited Service as of the date of Separation from Service is determined as of the Calculation Date and, when expressed in the form of a one hundred eighty (180) month period certain installment benefit, is equal to the difference between (1) and (2) below:

(1)    Sixty percent (60%) of the Participant’s Final Average Earnings, minus

(2)    The sum of (A) and (B):

13

Exhibit 10.2

(A) The monthly aggregate annuity benefit (not including any temporary Pension Supplement) that the Participant is or would be entitled to receive under the Retirement Plan and the Pension Restoration Benefit component of this Plan if such benefits were paid, commencing with a payment for the month in which occurs the Calculation Date, in the form of a single life annuity without survivor benefits, i.e., the Participant’s actual benefit election, and the form in which and time at which those benefits under those plans are actually payable, shall be disregarded. For purposes of this paragraph (A), the monthly aggregate annuity benefit that the Participant is or would be entitled to receive under the Retirement Plan and the Pension Benefit Restoration component of this Plan shall be determined by attributing to the Participant any portion of the benefit that is assigned to an alternate payee pursuant to a domestic relations order; and

(B) The monthly annuity benefit that could be purchased if the Participant’s Offset Amount is converted into an Actuarially Equivalent single life annuity, without survivor benefits, commencing with a payment for the month in which occurs the Calculation Date. For purposes of this paragraph (B), the monthly annuity benefit that could be purchased with the Participant’s Offset Amount shall be determined by attributing to the Participant any portion of the Offset Amount that has been assigned to an alternate payee pursuant to a domestic relations order.

(b)    Participants With 10 But Less Than 15 Years of Credited Service. The Supplemental Retirement Benefit of a Participant who satisfies the eligibility requirements of Section 4.01 and who has at least ten (10) but less than fifteen (15) years of Credited Service shall be determined in accordance with subsection (a) above, with the exception that the benefit percentage used in subsection (a)(1) above shall be reduced from sixty percent (60%) to the percentage determined in accordance with the following schedule:

Full Years of Credited Service	Applicable Benefit Percentage
14 13 12 11 10	56% 52% 48% 44% 40%

(c)    Reduction for Early Commencement. If the Calculation Date applicable to the Participant’s Supplemental Retirement Benefit is prior to the Participant’s attainment of age sixty-two (62), the monthly benefit as calculated under this Section 4.03 shall be reduced by one quarter of one percent (0.25%) for each month by which the Calculation Date precedes the month in which the Participant will attain sixty-two (62) years of age.

14

Exhibit 10.2

Section 4.04. Distribution of Single Sum Benefits. If the Participant’s Supplemental Retirement Benefit is payable in a single sum, distribution will be made in accordance with the following rules:

(a)    Time of Payment. The single sum payment will be calculated as of the Calculation Date but paid on the Payment Date.

(b)    Amount of Single Sum Benefit. The single sum cash payment shall be equal to the sum of (1) an amount that, as of the Calculation Date, is Actuarially Equivalent to the Participant’s one hundred eighty (180) month period certain installment Supplemental Retirement Benefit as calculated under Section 4.03 above. The payment to be made on the Payment Date will equal the sum of (1) the single sum amount determined, as of the Calculation Date, in accordance with the preceding sentence, and (2) interest on the single sum amount from the last day of the month in which occurs the Calculation Date through the Payment Date.Interest under clause (2) above, for the period through the last day of the month in which occurs the six (6) month anniversary of the Participant’s Separation from Service, shall be determined at the 417(e)(3) Rate (first segment rate) in effect under the Retirement Plan for the calendar year in which occurs the Calculation Date.

(c)    Death Prior to Payment Date. This Section 4.04 applies only if the Participant is alive on the Payment Date. If the Participant dies prior to the Payment Date, the benefits (if any) payable following the Participant’s death shall be determined in accordance with Section 4.07.

Section 4.05. Distribution of 180 Month Period Certain Installment Benefit. If the Participant’s Supplemental Retirement Benefit is payable as a one hundred eighty (180) month period certain installment benefit, distribution will be made in accordance with the following rules:

(a)    Time of Payment. The one hundred eighty (180) month period certain installment benefit will be calculated as of the Calculation Date but paid beginning on the Payment Date.

(b)    Amount of Each Installment. The amount of each monthly installment shall be the amount determined under Section 4.03 above. The payment made on the Payment Date will include (1) the Regular Monthly Payment for the month in which occurs the Payment Date, (2) the Retroactive Benefit Payment, and (3) interest on each monthly installment that constitutes part of the Retroactive Benefit Payment for the period from the date on which such installment would have been paid had monthly payments commenced with a payment on the last day of the month that includes the Calculation Date through the Payment Date. Following the payment on the Payment Date, payments to the eligible Participant in an amount equal to the Regular Monthly Payment shall continue until a total of one hundred eighty (180) monthly payments have been made; provided that for purposes of determining whether a total of one hundred eighty (180) monthly payments have been made, the payment made on the Payment Date will be treated as consisting of seven (7) payments. Interest under clause (3) above, for the period through the last day of the month in which occurs the six (6) month anniversary of the Participant’s Separation from Service, shall be determined at the 417(e)(3) Rate (first segment rate) in effect under the Retirement Plan for the calendar year in which occurs the Calculation Date.

(c)    Death Prior to Payment Date. This Section 4.05 applies only if the Participant is alive on the Payment Date. If the Participant dies prior to the Payment Date, the benefits (if any) payable following the Participant’s death shall be determined in accordance with Section 4.07.

Section 4.06. Distribution of Annuity Benefits. If the Participant’s Supplemental Retirement Benefit is payable as an annuity, distribution will be made in accordance with the following rules:

(a)    Calculation of Monthly Annuity Amount. The amount of the monthly annuity benefit is determined, as of the Calculation Date, by converting the one hundred eighty (180) month period certain installment benefit under Section 4.03 into an Actuarially Equivalent annuity benefit in the form of annuity applicable to the Participant (the same form of annuity in which the Participant’s Pension Restoration Benefit will be distributed). If the Participant is married and receiving payment in the form of a joint and survivor annuity, the Supplemental Retirement Plan survivor benefit is not actuarially subsidized, even though the Participant may receive an actuarial subsidy with respect to the Pension Restoration Benefit survivor benefit.

15

Exhibit 10.2

(b)    Regular Monthly Payments and the Retroactive Benefit Payment. The payment made on the Payment Date will include (1) the Regular Monthly Payment for the month in which occurs the Payment Date, (2) the Retroactive Benefit Payment, and (3) interest on each monthly installment that constitutes part of the Retroactive Benefit Payment for the period from the date on which such installment would have been paid had monthly payments commenced with a payment on the last day of the month that includes the Calculation Date through the Payment Date. Each subsequent monthly payment to the Participant will be an amount equal to the Regular Monthly Payment. Interest under clause (3) above, for the period through the last day of the month in which occurs the six (6) month anniversary of the Participant’s Separation from Service, shall be determined at the 417(e)(3) Rate (first segment rate) in effect under the Retirement Plan for the calendar year in which occurs the Calculation Date.

(c)    Death Prior to Payment Date. This Section 4.06 applies only if the Participant is alive on the Payment Date. If the Participant dies prior to the Payment Date, the benefits (if any) payable following the Participant’s death shall be determined in accordance with Section 4.07.

Section 4.07. Death Benefits. The form and time of benefit distribution is irrevocably established at the earlier to occur of (1) the Payment Date (which, in accordance with Section 1.409A-3(b) of the Income Tax Regulations, is an objectively determinable and nondiscretionary date that is based upon the Participant’s Separation from Service and that is fixed at the time of the Participant’s Separation from Service), and (2) the date of the Participant’s death.

(a)    Death Prior to Payment Date. If a Participant who has been designated for participation in the Supplemental Retirement Benefit component of the Plan dies prior to the Payment Date (including a Participant who dies during employment) but after having completed ten (10) or more years of Credited Service, the Participant’s Beneficiary will receive a single sum payment equal to the single sum payment to which the Participant would have been entitled to as of the Calculation Date if the Participant had in effect a single sum payment election under Article II (regardless of the election actually made by the Participant), together with interest, at the 417(e)(3) Rate (first segment rate), from the last day of the month in which occurs the Calculation Date through the last day of the month preceding the month in which payment to the Beneficiary is made. If a Participant who has been designated for participation in the Supplemental Retirement Benefit component of the Plan dies prior to the Payment Date (including a Participant who dies during employment) and prior to completing ten (10) or more years of Credited Service, no benefit is payable.

(b)    Death on or After the Payment Date.

(1)    Death After Commencement of Installment Payments. If the Participant’s benefit is being distributed as a one hundred eighty (180) month period certain installment benefit and the Participant dies on or after the Payment Date, i.e., on or after the date on which installment distributions to the Participant have begun, but prior to the date on which one hundred eighty (180) payments have been made, monthly installment distributions to the Beneficiary (at the same time as payments to the Participant would have been made) shall continue until the total number of monthly installments paid to the Beneficiary, when aggregated with the number of monthly installments paid to the Participant prior to his or her death, equals one hundred eighty (180).

(2)    Death After Commencement of Annuity Payments. If the Participant’s benefit is being distributed as an annuity and the Participant dies on or after the Payment Date, i.e., on or after the date on which payment of Plan benefits has actually begun, the only benefits payable following the Participant’s death shall be those (if any) payable under the form of annuity distribution in which the Participant’s benefit was being paid. Thus, for example, if the Participant was receiving payments in the form of a single life annuity, no further benefits are payable following the Participant’s death. Similarly, if the Participant was receiving benefits in the form of a joint and fifty percent (50%) surviving Spouse annuity, the only benefits payable following the Participant’s death shall be those payable pursuant to the fifty percent (50%) survivor feature

16

Exhibit 10.2

of the annuity benefit, to the Spouse (if still living) to whom the Participant was married on the Calculation Date. There is no guarantee that the total amount of benefits received by the Participant (and if applicable, the Participant’s surviving Spouse) under an annuity form of distribution will be at least equal to the amount that would have been paid to the Participant if the Participant had elected distribution in a single sum or installments.

17

Exhibit 10.2

ARTICLE V. SPECIAL DEFINED CONTRIBUTION CREDITS

Section 5.01. Application. Effective as of January 1, 2016, Special Defined Contribution Credits are no longer made under the Plan because the limited class of Participants eligible for these credits have terminated employment with the Company and its Affiliates.

Section 5.02. Distribution In Accordance With This Plan. If a Participant has a vested benefit attributable to Special Defined Contribution Credits, that benefit will be distributed in accordance with the terms of this Plan and the Participant’s payment election (or deemed payment election) under this Plan, even though the Special Defined Contribution Credits are, for record-keeping purposes, credited under the Deferred Compensation Plan.

Section 5.03. Distribution of Single Sum Benefits. If the Participant’s vested account balance that is attributable to Special Defined Contribution Credits is payable in a single sum, distribution will be made in accordance with the following rules:

(a)    Time of Payment. The single sum payment will be paid on the Payment Date.

(b)    Amount of Single Sum Benefit. The single sum cash payment shall be equal to the Participant’s vested account balance under the Deferred Compensation Plan that is attributable to Special Defined Contribution Credits, including all investment gain or loss under the Deferred Compensation Plan through the Valuation Date (as defined in the Deferred Compensation Plan) immediately preceding the date on which the distribution is processed for payment.

(c)    Death Prior to Payment Date. This Section 5.03 applies only if the Participant is alive on the Payment Date. If the Participant dies prior to the Payment Date, the benefits (if any) payable following the Participant’s death shall be determined in accordance with Section 5.06.

Section 5.04. Distribution of 180 Month Period Certain Installment Benefit. If the Participant’s vested account balance that is attributable to Special Defined Contribution Credits is payable as a one hundred eighty (180) month period certain installment benefit, distribution will be made in accordance with the following rules:

(a)    Time of Payment. The one hundred eighty (180) month period certain installment benefit will be calculated as of the Calculation Date but paid beginning on the Payment Date.

(b)    Amount of Each Installment. The amount of the monthly annuity benefit is determined, as of the Calculation Date, by converting the Participant’s vested account balance, as of the Calculation Date, under the Deferred Compensation Plan that is attributable to Special Defined Contribution Credits, into an Actuarially Equivalent one hundred eighty (180) month period certain installment benefit. The actuarial conversion shall be accomplished by first converting the Participant’s vested account balance into a single life annuity without survivor benefits, and then converting the single life annuity into a one hundred eighty (180) month period certain installment benefit. The payment made on the Payment Date will include (1) the Regular Monthly Payment for the month in which occurs the Payment Date, (2) the Retroactive Benefit Payment, and (3) interest on each monthly installment that constitutes part of the Retroactive Benefit Payment for the period from the date on which such installment would have been paid had monthly payments commenced with a payment on the last day of the month that includes the Calculation Date through the Payment Date. Following the payment on the Payment Date, payments to the eligible Participant in an amount equal to the Regular Monthly Payment shall continue until a total of one hundred eighty (180) monthly payments have been made; provided that for purposes of determining whether a total of one hundred eighty (180) monthly payments have been made, the payment made on the Payment Date will be treated as consisting of seven (7) payments. Interest under clause (3) above, for the period through the last day of the month in which occurs the six (6) month anniversary of the Participant’s Separation from Service, shall be determined at the 417(e)(3) Rate (first segment rate) in effect under the Retirement Plan for the calendar year in which occurs the Calculation Date. Because the amount of each installment payment is calculated on an Actuarially Equivalent basis as of the Calculation Date, and because interest is paid on each monthly installment that constitutes the Retroactive

18

Exhibit 10.2

Benefit Payment, the Participant’s Special Defined Contribution Account under the Deferred Contribution Plan is not credited with investment gain or loss under the Deferred Compensation Plan after the Calculation Date.

(c)    Death Prior to Payment Date. This Section 5.04 applies only if the Participant is alive on the Payment Date. If the Participant dies prior to the Payment Date, the benefits (if any) payable following the Participant’s death shall be determined in accordance with Section 5.06.

Section 5.05. Distribution of Annuity Benefits. If the Participant’s vested account balance that is attributable to Special Defined Contribution Credits is payable as an annuity, distribution will be made in accordance with the following rules:

(a)    Calculation of Monthly Annuity Amount. The amount of the monthly annuity benefit is determined, as of the Calculation Date, by converting the Participant’s vested account balance, as of the Calculation Date, under the Deferred Compensation Plan that is attributable to Special Defined Contribution Credits into an Actuarially Equivalent annuity benefit in the form of annuity applicable to the Participant (the same form of annuity in which the Participant’s Pension Restoration Benefit will be distributed). The actuarial conversion shall be accomplished by first converting the Participant’s vested account balance into a single life annuity without survivor benefits, and then, if the Participant’s benefit is being paid in a form of annuity other than a single life annuity without survivor benefits, converting the single life annuity into such other form of annuity in which the Participant’s benefit will be paid. If the Participant is married and receiving payment in the form of a joint and survivor annuity, the Supplemental Retirement Plan survivor benefit is not actuarially subsidized, even though the Participant may receive an actuarial subsidy with respect to the Pension Restoration Benefit survivor benefit.

(b)    Regular Monthly Payments and the Retroactive Benefit Payment. The payment made on the Payment Date will include (1) the Regular Monthly Payment for the month in which occurs the Payment Date, (2) the Retroactive Benefit Payment, and (3) interest on each monthly installment that constitutes part of the Retroactive Benefit Payment for the period from the date on which such installment would have been paid had monthly payments commenced with a payment on the last day of the month that includes the Calculation Date through the Payment Date. Each subsequent monthly payment to the Participant will be an amount equal to the Regular Monthly Payment. Interest under clause (3) above, for the period through the last day of the month in which occurs the six (6) month anniversary of the Participant’s Separation from Service, shall be determined at the 417(e)(3) Rate (first segment rate) in effect under the Retirement Plan for the calendar year in which occurs the Calculation Date. Because the amount of the monthly payment is calculated on an Actuarially Equivalent basis as of the Calculation Date, and because interest is paid on each monthly payment that constitutes the Retroactive Benefit Payment, the Participant’s Special Defined Contribution Account under the Deferred Contribution Plan is not credited with investment gain or loss under the Deferred Compensation Plan after the Calculation Date.

(c)    Death Prior to Payment Date. This Section 5.05 applies only if the Participant is alive on the Payment Date. If the Participant dies prior to the Payment Date, the benefits (if any) payable following the Participant’s death shall be determined in accordance with Section 5.06.

Section 5.06. Death Benefits. The form and time of benefit distribution is irrevocably established at the earlier to occur of (1) the Payment Date (which, in accordance with Section 1.409A-3(b) of the Income Tax Regulations, is an objectively determinable and nondiscretionary date that is based upon the Participant’s Separation from Service and that is fixed at the time of the Participant’s Separation from Service), and (2) the date of the Participant’s death.

(a)    Death Prior to Payment Date. If a Participant who has a vested benefit attributable to Special Defined Contribution Credits dies prior to the Payment Date (including a Participant who is eligible for such benefits and who dies during employment), the Participant’s Beneficiary will receive a single sum payment equal to the single sum payment to which the Participant would have been entitled to if the Participant had in effect a single sum payment election under Article II (regardless of the election actually made by the Participant).

19

Exhibit 10.2

(b)    Death on or After the Payment Date.

(1)    Death After Commencement of Installment Payments. If the Participant’s benefit is being distributed as a one hundred eighty (180) month period certain installment benefit and the Participant dies on or after the Payment Date, i.e., on or after the date on which installment distributions to the Participant have begun, but prior to the date on which one hundred eighty (180) payments have been made, monthly installment distributions to the Beneficiary (at the same time as payments to the Participant would have been made) shall continue until the total number of monthly installments paid to the Beneficiary, when aggregated with the number of monthly installments paid to the Participant prior to his or her death, equals one hundred eighty (180).

(2)    Death After Commencement of Annuity Payments. If the Participant’s benefit is being distributed as an annuity and the Participant dies on or after the Payment Date, i.e., on or after the date on which payment of Plan benefits has actually begun, the only benefits payable following the Participant’s death shall be those (if any) payable under the form of annuity distribution in which the Participant’s benefit was being paid. Thus, for example, if the Participant was receiving payments in the form of a single life annuity, no further benefits are payable following the Participant’s death. Similarly, if the Participant was receiving benefits in the form of a joint and fifty percent (50%) surviving Spouse annuity, the only benefits payable following the Participant’s death shall be those payable pursuant to the fifty percent (50%) survivor feature of the annuity benefit, to the Spouse (if still living) to whom the Participant was married on the Calculation Date. There is no guarantee that the total amount of benefits received by the Participant (and if applicable, the Participant’s surviving Spouse) under an annuity form of distribution will be at least equal to the amount that would have been paid to the Participant if the Participant had elected distribution in a single sum or in installments.

20

Exhibit 10.2

ARTICLE VI. SPECIAL RULES APPLICABLE IN THE EVENT OF A CHANGE IN CONTROL OF THE COMPANY

Section 6.01. Application. Effective as of the Merger Date, a Change in Control has occurred and the provisions in this Article VI effective upon a Change in Control shall apply to the Plan.

Section 6.02. Definitions

For purposes of this Article VI, the following terms shall have the following respective meanings:

(a)    The “Act” means the Securities Exchange Act of 1934, as amended.

(b)    An “Affiliate” of, or a person “affiliated” with, a specified person is a person that directly, or indirectly through one or more intermediaries, controls, or is controlled by, or is under common control with, the person specified and the term “Associate” used to indicate a relationship with any person, means (1) any corporation or organization (other than the registrant or a majority-owned subsidiary of the registrant) of which such person is an officer or partner or is, directly or indirectly, the beneficial owner of 10 percent or more of any class of equity securities, (2) any trust or other estate in which such person has a substantial beneficial interest or as to which such person serves as trustee or in a similar fiduciary capacity, and (3) any relative or Spouse of such person, or any relative of such Spouse, who has the same home as such person or who is a director or officer of the registrant or any of its parents or subsidiaries.

(c)    A person shall be deemed to be the “Beneficial Owner” of any securities:

(1)    which such Person or any of such Person’s Affiliates or Associates has the right to acquire (whether such right is exercisable immediately or only after the passage of time) pursuant to any agreement, arrangement, or understanding, or upon the exercise of conversion rights, exchange rights, warrants or options, or otherwise; provided, however, that a Person shall not be deemed the Beneficial Owner of, or to beneficially own, (A) securities tendered pursuant to a tender or exchange offer made by or on behalf of such Person or any of such Person’s Affiliates or Associates until such tendered securities are accepted for purchase or (B) securities issuable upon exercise of any rights agreement that the Company may have in effect at any time before the issuance of such securities.

(2)    which such Person or any of such Person’s Affiliates or Associates, directly or indirectly, has the right to vote or dispose of or has “beneficial ownership” of (as determined pursuant to Rule 13d-3 of the General Rules and Regulations under the Act, including pursuant to any agreement, arrangement or understanding; provided, however, that a Person shall not be deemed the Beneficial Owner of, or to beneficially own, any security under this subparagraph (2) as a result of an agreement, arrangement or understanding to vote such security if the agreement, arrangement or understanding: (A) arises solely from a revocable proxy or consent given to such Person in response to a public proxy or consent solicitation made pursuant to, and in accordance with, the applicable rules and regulations under the Act and (B) is not also then reportable on a Schedule 13D under the Act (or any comparable or successor report); or

(3)    which are beneficially owned, directly or indirectly, by any other Person with which such Person or any of such Person’s Affiliates or Associates has any agreement, arrangement or understanding for the purpose of

21

Exhibit 10.2

acquiring, holding, voting (except pursuant to a revocable proxy as described in Section 6.02(c)(2) above) or disposing of any voting securities of the Company.

(d)    A “Change in Control of the Company” shall be deemed to have occurred if:

(1)    any Person (other than any employee benefit plan of the Company or any subsidiary of the Company, any Person organized, appointed or established pursuant to the terms of any such benefit plan or any trustee, administrator or fiduciary of such a plan) is or becomes the Beneficial Owner of securities of the Company representing at least 30% of the combined voting power of the Company’s then outstanding securities;

(2)    one-half or more of the members of the Board are not Continuing Directors;

(3)    there shall be consummated any merger, consolidation, or reorganization of the Company with any other corporation as a result of which less than 50% of the outstanding voting securities of the surviving or resulting entity are owned by the former shareholders of the Company other than a shareholder who is an Affiliate or Associate of any party to such consolidation or merger;

(4)    there shall be consummated any merger of the Company or share exchange involving the Company in which the Company is not the continuing or surviving corporation other than a merger of the Company in which each of the holders of the Company’s common stock immediately prior to the merger have the same proportionate ownership of common stock of the surviving corporation immediately after the merger;

(5)    there shall be consummated any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, of the assets of the Company to a Person which is not a wholly owned subsidiary of the Company; or

(6)    the shareholders of the Company approve any plan or proposal for the liquidation or dissolution of the Company.

(e)    “Continuing Directors” means (1) any member of the Board of Directors of the Company who was a member of such Board on the effective date of this amendment and restatement, (2) any successor of a Continuing Director who is recommended to succeed a Continuing Director by a majority of the Continuing Directors then on such Board, and (3) additional directors elected or recommended for membership by a majority of the Continuing Directors then on such Board.

(f)    “Person” means any individual, firm, partnership, corporation or other entity, including any successor (by merger or otherwise) of such entity, or a group of any of the foregoing acting in concert; provided that in the case of a merger, consolidation or reorganization of the Company with any other corporation or a share exchange involving the Company, the shareholder of the other corporation that is a party to the merger, consolidation, reorganization or share exchange shall not be considered to be acting in concert for purposes of applying subsection (d)(1).

Section 6.03. Special Provisions Following Change in Control. Upon and following the occurrence of a Change in Control of the Company, the provisions of this Section 6.03 shall be operative, notwithstanding any provision of the Plan to the contrary.

22

Exhibit 10.2

(a)    A Participant who (1) has been designated as being eligible to participate in the Supplemental Retirement Benefit component of the Plan, but (2) the Participant’s employment with the Company and its Affiliates is involuntarily terminated for other than Cause (or, in the case of a Participant who has in effect an employment, retention, change in control, severance or similar agreement with the Company or any Affiliate that provides for “good reason” termination and the Participant, in accordance with such agreement, terminates employment or service for “good reason”) within two years following the date of the Change in Control by the Company prior to becoming eligible for a Supplemental Retirement Benefit under Article IV, shall nevertheless be entitled to a Supplemental Retirement Benefit if (1) the Participant has a vested benefit entitlement under the Retirement Plan, and (2) the Participant has completed five (5) or more years of Credited Service as of the date of his or her Separation from Service.

(1)    If the Participant has attained age fifty-five (55) as of the date of his or her Separation from Service, the benefit shall be calculated and paid as described in Articles II and IV, with the exception that with respect to any Participant who has completed at least five (5) but fewer than ten (10) years of Credited Service, the applicable benefit percentage for purposes of Section 4.03(a)(1) shall be determined in accordance with the schedule set forth in subparagraph (3) below.

(2)    If the Participant has not attained age fifty-five (55) as of the date of his or her Separation from Service, the benefit shall be calculated and paid as described in Articles II and IV, with the exception that:

(A) With respect to any Participant who has completed at least five (5) but fewer than ten (10) years of Credited Service, the applicable benefit percentage for purposes of Section 4.03(a)(1) shall be determined in accordance with the schedule set forth in subparagraph (3) below;

(B) In addition to the early commencement reduction specified in Section 4.03(c) that applies between the ages of fifty-five (55) and sixty-two (62), the benefit calculated under Section 4.03 shall be further reduced to an Actuarially Equivalent amount to reflect benefit commencement prior to the Participant’s attainment of age fifty-five (55). This is the benefit amount if the benefit is paid in the form of a one hundred eighty (180) month period certain installment benefit; and

(C) If the benefit is paid other than as a one hundred eighty (180) month period certain installment benefit, the benefit shall be further adjusted to convert the one hundred eighty (180) month period certain installment benefit into an Actuarial Equivalent benefit is the form of distribution applicable to the Participant under Article II.

(3)    If the Participant has completed at least five (5) but less than ten (10) years of Credited Service as of the date of his or her termination of employment, the applicable benefit percentage for purposes of Section 4.03(a)(1) shall be determined in accordance with the following schedule:

Full Years of Credited Service	Applicable Benefit Percentage
9 8 7 6	36% 32% 28% 24%

23

Exhibit 10.2

5 20%

(4)    For purposes of applying Section 4.07, the reference to “ten (10) years of Credited Service” shall be replaced with the phrase “five (5) years of Credited Service” each place it appears.

(b)    The Board or the Committee may at any time amend the Plan consistent with Section 7.05to modify the terms and conditions applicable to (or otherwise eliminate) benefits that would otherwise accrue on or after the Amendment Date.

(c)    Prior to the occurrence of a Change in Control, the Board or the Committee may exercise its authority under Section 7.05 to amend or terminate the Plan. This may include, without limitation, the passage of a resolution that terminates the Plan, regardless of whether such resolution is adopted in anticipation of a Change in Control. On or after the date on which a Change in Control, any amendment to the Plan or action to terminate the Plan that is not described in subsection (b) above shall be effective only with the written consent of the Participant (or in the case of a deceased Participant, the Participant’s Beneficiary).

(d)    The term “Amendment Date” means the date on which an amendment to the Plan is validly adopted or the date on which the amendment is or purports to be effective, whichever is later.

Section 6.04. Maximum Payment Limitation.

(a)    Except as provided in subsection (b) below, if any portion of the payments or benefits described in this Plan or under any other agreement with or plan of the Company or its Affiliates (in the aggregate, “Total Payments”), would constitute an “excess parachute payment” that is subject to the tax imposed by Section 4999 of the Code, then the Total Payments to be made to the Participant shall be reduced such that the value of the aggregate Total Payments that the Participant is entitled to receive shall be one dollar ($1) less than the maximum amount which the Participant may receive without becoming subject to the tax imposed by Section 4999 of the Code. The terms “excess parachute payment” and “parachute payment” shall have the meanings assigned to them in Section 280G of the Code, and such “parachute payments” shall be valued as provided therein. Present value shall be calculated in accordance with Section 280G(d)(4) of the Code. Within forty (40) days following delivery of notice by the Company to the Participant of its belief that there is a payment or benefit due the Participant which will result in an excess parachute payment as defined in Section 280G of the Code, the Participant and the Company, at the Company’s expense, shall obtain the opinion (which need not be unqualified) of nationally recognized tax counsel selected by the Company’s independent auditors and acceptable to the Participant in the Participant’s sole discretion (which may be regular outside counsel to the Company), which opinion sets forth (A) the amount of the base period income, (B) the amount and present value of Total Payments and (C) the amount and present value of any excess parachute payments determined without regard to the limitations of this Section. As used in this Section, the term “base period income” means an amount equal to the Participant’s “annualized includible compensation for the base period” as defined in Section 280G(d)(1) of the Code. For purposes of such opinion, the value of any noncash benefits or any deferred payment or benefit shall be determined by the Company’s independent auditors in accordance with the principles of Sections 280G(d)(3) and (4) of the Code, which determination shall be evidenced in a certificate of such auditors addressed to the Company and the Participant. Such opinion shall be addressed to the Company and the Participant and shall be binding upon the Company and the Participant. If such opinion determines that there would be an excess parachute payment, the payments hereunder that are includible in Total Payments or any other payment or benefit determined by such counsel to be includible in Total Payments shall be reduced or eliminated so that there will be no excess parachute payment. Such reduction will be achieved by reducing or eliminating payments or benefits in the manner that produces the highest economic value to the Participant; provided that in the event it is determined that the foregoing methodology for reduction would violate Section 409A of the Code, the reduction shall be made pro rata among the benefits and/or payments (on the basis of the relative present value of the parachute payments). If such legal counsel so requests in connection with the opinion required by this Section, the Participant and the Company shall obtain, at the Company’s expense, and the legal counsel may rely on in providing the opinion, the advice of a firm of recognized executive compensation consultants as to the reasonableness of any item of compensation to be received by the Participant. If the provisions of Sections 280G and 4999 of the Code are repealed without succession, then this Section shall be of no further force or effect.

24

Exhibit 10.2

(b)    The provisions of subsection (a) above shall not apply to a Participant whose employment is governed by an employment contract that provides for Total Payments in excess of the limitation described in subsection (a) above.

Section 6.05. Resolution of Disputes. If, after a Change in Control, (1) a dispute arises with respect to the enforcement of the Participant’s rights under the Plan, or (2) any legal proceeding shall be brought to enforce or interpret any provision contained in the Plan or to recover damages for breach of the Plan, in either case so long as the Participant is not acting in bad faith or otherwise pursuing a course of action that a reasonable person would determine to be frivolous, the Participant shall recover from the Company any reasonable attorneys’ fees and necessary costs and disbursements incurred as a result of such dispute or legal proceeding (“Expenses”), and prejudgment interest on any money judgment obtained by the Participant calculated at the rate of interest announced by US Bank Milwaukee, Milwaukee, Wisconsin (or any successor thereto), from time to time as its prime or base lending rate from the date that payments to the Participant should have been made under this Plan. Within ten (10) days after the Participant’s written request therefore and reasonable substantiation that such expenses have been incurred (but in no event later than the end of the calendar year following the calendar year in which such Expense is incurred), the Company shall pay to the Participant, or such other person or entity as the Participant may designate in writing to the Company, the Participant’s Expenses. The reimbursement shall be made even though a final disposition or conclusion of the dispute or legal proceeding has not been entered. In the case of a deceased Participant, this Section shall apply with respect to the Participant’s Beneficiary or estate.

25

Exhibit 10.2

ARTICLE VII. GENERAL PROVISIONS

Section 7.01. Administration. The Committee shall administer and interpret the Plan and supervise preparation of Participant elections, forms, and any amendments thereto. The Committee may, in its discretion, delegate any or all of its authority and responsibility. To the extent of any such delegation, any references herein to the Committee shall be deemed references to such delegee. Interpretation of the Plan shall be within the sole discretion of the Committee and shall be final and binding upon each Participant and Beneficiary. The Committee may adopt and modify rules and regulations relating to the Plan as it deems necessary or advisable for the administration of the Plan. If any delegee of the Committee shall also be an eligible Participant or Beneficiary, any determinations affecting the delegee’s participation in the Plan shall be made by the Committee. The Plan shall be interpreted to comply with the requirements of Section 409A of the Code with respect to any benefit that is subject to the requirements of such Section of the Code.

Section 7.02. Claims Procedures.

(a)    If a Participant, Spouse or Beneficiary (the “claimant”) believes that he is entitled to a benefit under the Plan that is not provided, the claimant or his or her legal representative shall file a written claim for such benefit with the Committee no later than ninety (90) days after the first payment is made (or should have been made) in accordance with the terms of the Plan or under Regulations issued by the Secretary of the Treasury under Code Section 409A. If the Committee denies the claim, it shall deliver to the claimant, within one hundred thirty-five (135) days of the date the first payment to the Participant was made (or should have been made) in accordance with the terms of the Plan or under Regulations issued by the Secretary of the Treasury under Code Section 409A, a written notice to the claimant of such denial. The written notice shall include the specific reason(s) for the denial; reference to specific Plan provisions upon which the denial is based; a description of any additional material or information necessary for the claimant to perfect the claim and an explanation of why such material or information is necessary; and a description of the Plan’s review procedures (as set forth in subsection (b)) and the time limits applicable to such procedures, including a statement of the claimant’s right to bring a civil action under section 502(a) of ERISA following an adverse determination upon review.

(b)    The claimant has the right to appeal the Committee’s decision by filing a written appeal with the Committee. Notice of the appeal must be received by the Committee no later than one hundred eighty (180) days after the first payment is made (or should have been made) in accordance with the terms of the Plan or under Regulations issued by the Secretary of the Treasury under Code Section 409A. The claimant will have the opportunity, upon request and free of charge, to have reasonable access to and copies of all documents, records and other information relevant to the claimant’s appeal. The claimant may submit written comments, documents, records and other information relating to his or her claim with the appeal. The Committee will review all comments, documents, records and other information submitted by the claimant relating to the claim, regardless of whether such information was submitted or considered in the initial claim determination. The Committee shall make a determination on the appeal within sixty (60) days after receiving the claimant’s written appeal; provided that the Committee may determine that an additional sixty (60)-day extension is necessary due to circumstances beyond the Committee’s control, in which event the Committee shall notify the claimant prior to the end of the initial period that an extension is needed, the reason therefore and the date by which the Committee expects to render a decision. If the claimant’s appeal is denied in whole or part, the Committee shall provide written notice to the claimant of such denial. The written notice shall include the specific reason(s) for the denial; reference to specific Plan provisions upon which the denial is based; a statement that the claimant is entitled to receive, upon request and free of charge, reasonable access to and copies of all documents, records, and other information relevant to the claimant’s claim; and a statement of the claimant’s right to bring a civil action under section 502(a) of ERISA.

(c)    Notwithstanding anything in the Plan to the contrary, and as a condition of participating in the Plan, a Participant agrees, on behalf of the Participant and all persons or entities that may claim through the Participant, that (1) any claim for benefits or other legal action or legal proceeding concerning the Plan may be brought more than one (1) year after the later of (A) the last date on which the act or omission giving rise to the claim, legal action or other legal proceeding occurred, or (B) the date the individual or entity bringing such claim, legal action or other legal proceeding had knowledge (or reasonably should have had knowledge) of the act or omission, and (2) that any

26

Exhibit 10.2

legal action or legal proceeding concerning the Plan may only be heard in a “bench” trial and that any right to a jury trial is waived.

Section 7.03. Participant Rights Unsecured.

(a)    The right of a Participant or his or her Beneficiary to receive a distribution hereunder shall be an unsecured claim, and neither the Participant nor any Beneficiary shall have any rights in or against any amount credited to his or her Account or any other specific assets of the Company or an Affiliate. The right of a Participant or Beneficiary to the payment of benefits under this Plan shall not be assigned, encumbered, or transferred, except by will or the laws of descent and distribution. The rights of a Participant hereunder are exercisable during the Participant’s lifetime only by the Participant or the Participant’s guardian or legal representative.

(b)    The Company may set aside assets in the Trust or authorize the creation of another trust or other arrangements to assist in meeting the obligations created under the Plan, subject to the restrictions on funding imposed on such trusts by Code § 409A(b)(3). However, any liability to any person with respect to the Plan shall be based solely upon any contractual obligations that may be created pursuant to the Plan. No obligation of the Company or an Affiliate shall be deemed to be secured by any pledge of, or other encumbrance on, any property of the Company or an Affiliate. Nothing contained in this Plan and no action taken pursuant to its terms shall create or be construed to create a trust of any kind, or a fiduciary relationship between the Company or an Affiliate and any Participant or Beneficiary, or any other person, or as providing a Participant with a right to continue employment with the Company or any Affiliate.

Section 7.04. Tax Withholding. The Participant shall pay or make arrangements satisfactory to the Committee regarding the payment or withholding of, any Federal, state, local or foreign taxes of any kind required by law to be withheld with respect to such amount. In addition, if prior to the date of distribution of any amount hereunder, the Federal Insurance Contributions Act (FICA) tax imposed under Code Sections 3101, 3121(a) and 3121(v)(2), where applicable, becomes due, the Company may direct that the Participant’s benefit be reduced by an Actuarially Equivalent amount to reflect the amount needed to pay the Participant’s portion of such tax.

Section 7.05. Amendment or Termination of Plan.

(a)    There shall be no time limit on the duration of the Plan.

(b)    Except as otherwise limited pursuant to Section 6.03, the Company may at any time amend the Plan by action of the Board or the Committee, including but not limited to modifying the terms and conditions applicable to (or otherwise eliminating) benefit accruals on or after the Amendment Date (as defined in Section 6.03); provided, however, that no amendment or termination may reduce or eliminate any benefit accrued to the date of such amendment. Further, the Company’s Committee is authorized to amend the Plan to the extent that such amendment is determined to be necessary or desirable in order to comply or facilitate compliance with the requirements of Code Section 409A or other applicable law; or that is otherwise desirable to promote efficient Plan administration; provided that any such amendment shall not increase Plan benefits or result in non-ministerial action that is prohibited under Section 7.01.

(c)    Subject to Section 6.03, the Board may terminate the Plan in accordance with and subject to the following provisions. Upon termination of the Plan, future accrual of benefits shall cease.

(1)    The Board terminates the Plan within twelve (12) months of a corporate dissolution taxed under Code Section 331, or with the approval of a bankruptcy court pursuant to 11 U.S.C. §503(b)(1)(A), and the amounts accrued under the Plan but not yet paid are distributed to the Participants, Spouses or beneficiaries, as applicable, in a single sum payment, regardless of any distribution election then in effect, by the latest of: (A) the last day of the calendar year in which the Plan termination and liquidation occurs, (B) the last day of the calendar year in which the amount is no longer subject to a substantial

27

Exhibit 10.2

risk of forfeiture, or (C) the last day of the first calendar year in which payment is administratively practicable.

(2)    The Board terminates the Plan at any time during the period that begins thirty (30) days prior and ends twelve (12) months following a Change in Control Event (as defined for purposes of Code Section 409A), provided that all arrangements required to be aggregated with this Plan under Code Section 409A are terminated and liquidated with respect to each Participant that experienced the Change in Control Event, so that all participants under similar arrangements are required to receive all amounts of compensation deferred under the terminated arrangements within twelve (12) months of the date of termination of the arrangements.

(3)    The Board terminates the Plan at any other time, provided that such termination does not occur proximate to a downturn in the financial health of the Company or an Affiliate. In such event, all amounts accrued under the Plan but not yet paid will be distributed to all Participants, Spouses or beneficiaries, as applicable, in a single sum payment no earlier than twelve (12) months (and no later than twenty-four (24) months) after the date of termination, regardless of any distribution election then in effect. This provision shall not be effective unless all other plans required to be aggregated with this Plan under Code Section 409A are also terminated and liquidated. Notwithstanding the foregoing, any payment that would otherwise be paid during the twelve (12)-month period beginning on the Plan termination date pursuant to the terms of the Plan shall be paid in accordance with such terms. In addition, the Company or any Affiliate shall be prohibited from adopting a similar arrangement within three (3) years following the date of the Plan’s termination, unless any individual who was a Participant under this Plan is excluded from participating thereunder for such three (3) year period.

(4)    Except as provided in Paragraphs (1), (2) and (3) above or as otherwise permitted in regulations promulgated by the Secretary of the Treasury under Code Section 409A, any action that purports to terminate the Plan shall instead be construed as an amendment to discontinue further benefit accruals, but the Plan will continue to operate, in accordance with its terms as from time to time amended in accordance with Sections 6.02 and 7.05, and in accordance with applicable Participant elections, with respect to the Participant’s benefit accrued through the date of termination, and in no event shall any such action purporting to terminate the Plan form the basis for accelerating distributions to Participants and Beneficiaries.

(5)    If single sum payments are made in accordance with this Section 7.05, the single sum distribution amount applicable to Participant’s Pension Restoration Benefit and Supplemental Retirement Benefit shall be determined in accordance with Sections 3.03 and 4.04 as if the date on which the Plan will make the single sum distributions is the Calculation Date (and the single sum distribution amount attributable to the Participant’s Special Defined Contribution Credits will be equal to the value of the Participant’s account immediately prior to distribution).

Section 7.06. Administrative Expenses. Costs of establishing and administering the Plan will be paid by the Company and its Affiliates.

Section 7.07. Effect on Other Employee Benefit Plans. Benefits accrued by a Participant under this Plan shall not be considered “compensation” for the purpose of computing benefits under any employee benefit plan maintained by the Company or an Affiliate.

28

Exhibit 10.2

Section 7.08. Successor and Assigns. This Plan shall be binding upon and inure to the benefit of the Company and its Affiliates, their successors and assigns and the Participants and their heirs, executors, administrators, and legal representatives.

Section 7.09. Additional Section 409A Provisions.

(a)    Accelerated Distribution Following Section 409A Failure. If an amount under this Plan is required to be included in a Participant’s income under Code Section 409A prior to the date such amount is actually distributed, the Participant shall receive a distribution, in a lump sum, within ninety (90) days after the date it is finally determined that the Plan fails to meet the requirements of Code Section 409A. The distribution shall equal the amount required to be included in the Participant’s income as a result of such failure.

(b)    Permitted Delay in Payment. If a distribution required under the terms of this Plan would jeopardize the ability of the Company or of an Affiliate to continue as a going concern, the Company or the Affiliate shall not be required to make such distribution. Rather, the distribution shall be delayed until the first date that making the distribution does not jeopardize the ability of the Company or of an Affiliate to continue as a going concern. Further, if any distribution pursuant to the Plan will violate the terms of Section 16(b) of the Securities Exchange Act of 1934 or other Federal securities laws, or any other applicable law, then the distribution shall be delayed until the earliest date on which making the distribution will not violate such law.

(c)    Compliance With Section 409A Transition Rules. With respect to a Participant whose benefit is paid or commences to be paid on or before December 31, 2008, taking into account the required six month delay in the payment commencement date under Code Section 409A(a)(2)(B), the form and time of distribution applicable to the Participant shall be determined in accordance with the terms of the Plan as in effect on March 31, 2008, i.e., in accordance with the Internal Revenue Service transition rules under Code Section 409A, the April 1, 2008 amendment and restatement of the Plan shall not affect the form and time of distribution for a Participant whose benefit is paid (or commences to be paid) in 2008.

Section 7.10. Offset. The Company shall have the right to offset, without the requirement of obtaining the consent of the Participant (or his Spouse or Beneficiary, in the event of the Participant’s death), from the benefits payable hereunder any amount (up to the maximum amount that may be deducted without violating Code Section 409A) that the Participant owes to the Company or any Affiliate.

33689815v4

29

EX-31.1

Exhibit 31.1

Certification Pursuant to

Rule 13a-14(a) or 15d-14(a),

as Adopted Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002

I, Allen L. Leverett, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of WEC Energy Group, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an Annual Report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:    August 5, 2016

/s/ ALLEN L. LEVERETT

Allen L. Leverett

Chief Executive Officer and President

(Principal Executive Officer)

EX-31.2

Exhibit 31.2

Certification Pursuant to

Rule 13a-14(a) or 15d-14(a),

as Adopted Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002

I, Scott J. Lauber, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of WEC Energy Group, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an Annual Report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:    August 5, 2016

/s/ SCOTT J. LAUBER

Scott J. Lauber

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-32.1

Exhibit 32.1

Certification Pursuant to

18 U.S.C. Section 1350,

As Adopted Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of WEC Energy Group, Inc. (the "Company") on Form 10-Q for the quarter ended June 30, 2016, as filed with the Securities and Exchange Commission on August 5, 2016 (the "Report"), I, Allen L. Leverett, Chief Executive Officer and President of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ ALLEN L. LEVERETT  

Allen L. Leverett

Chief Executive Officer and President

August 5, 2016

EX-32.2

Exhibit 32.2

Certification Pursuant to

18 U.S.C. Section 1350,

As Adopted Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of WEC Energy Group, Inc. (the "Company") on Form 10-Q for the quarter ended June 30, 2016, as filed with the Securities and Exchange Commission on August 5, 2016 (the "Report"), I, Scott J. Lauber, Executive Vice President and Chief Financial Officer of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ SCOTT J. LAUBER  

Scott J. Lauber

Executive Vice President and Chief Financial Officer

August 5, 2016

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Document and Enttity Information	6 Months Ended
	Jun. 30, 2016 shares
Document and Entity Information [Abstract]
Entity Registrant Name	WEC Energy Group, Inc.
Entity Central Index Key	0000783325
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding	315,619,968

XML

Condensed Consolidated Income Statements (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Income Statement [Abstract]
Operating revenues	$ 1,602.0	$ 991.2	$ 3,796.8	$ 2,379.1
Operating expenses
Cost of sales	508.3	353.0	1,347.2	966.9
Other operation and maintenance	522.0	337.0	1,053.5	617.7
Depreciation and amortization	190.0	103.5	377.9	206.1
Property and revenue taxes	49.6	31.9	96.8	63.8
Total operating expenses	1,269.9	825.4	2,875.4	1,854.5
Operating income	332.1	165.8	921.4	524.6
Equity in earnings of transmission affiliate	30.9	14.3	69.4	30.4
Other income, net	32.4	26.1	65.1	29.1
Interest expense	100.1	61.8	201.0	121.2
Other expense	(36.8)	(21.4)	(66.5)	(61.7)
Income before income taxes	295.3	144.4	854.9	462.9
Income tax expense	113.6	63.2	326.7	185.6
Net income	181.7	81.2	528.2	277.3
Preferred stock dividends of subsidiary	0.3	0.3	0.6	0.6
Net income attributed to common shareholders	$ 181.4	$ 80.9	$ 527.6	$ 276.7
Earnings per share
Basic (in dollars per share)	$ 0.57	$ 0.36	$ 1.67	$ 1.22
Diluted (in dollars per share)	$ 0.57	$ 0.35	$ 1.66	$ 1.21
Weighted average common shares outstanding
Basic (in shares)	315.6	227.5	315.6	226.5
Diluted (in shares)	317.0	229.1	317.0	228.2
Dividends per share of common stock (in dollars per share)	$ 0.4950	$ 0.8629	$ 0.9900	$ 1.2854

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Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Statement of Comprehensive Income [Abstract]
Net income	$ 181.7	$ 81.2	$ 528.2	$ 277.3
Derivatives accounted for as cash flow hedges
Gains on settlement, net of tax of $7.6	0.0	11.4	0.0	11.4
Reclassification of gains to net income, net of tax	(0.3)	(0.1)	(0.6)	(0.1)
Cash flow hedges, net	(0.3)	11.3	(0.6)	11.3
Defined benefit plans
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax	0.4	0.0	0.4	0.0
Other comprehensive income (loss), net of tax	0.1	11.3	(0.2)	11.3
Comprehensive income	181.8	92.5	528.0	288.6
Preferred stock dividends of subsidiary	0.3	0.3	0.6	0.6
Comprehensive income attributed to common shareholders	$ 181.5	$ 92.2	$ 527.4	$ 288.0

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Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2015
Derivatives accounted for as cash flow hedges
Gains on settlement, tax	$ 7.6	$ 7.6

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Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Property, plant, and equipment
In service	$ 26,690.7	$ 26,249.5
Accumulated depreciation	(8,049.1)	(7,919.1)
In service, net	18,641.6	18,330.4
Construction work in progress	723.7	822.9
Leased facilities, net	33.6	36.4
Net property, plant, and equipment	19,398.9	19,189.7
Investments
Equity investment in transmission affiliate	1,425.0	1,380.9
Other	88.0	85.8
Total investments	1,513.0	1,466.7
Current assets
Cash and cash equivalents	32.1	49.8
Accounts receivable and unbilled revenues, net of reserves of $109.4 and $113.3, respectively	914.9	1,028.6
Materials, supplies, and inventories	494.5	687.0
Assets held for sale	0.0	96.8
Prepayments	235.3	285.8
Other	89.1	58.8
Total current assets	1,765.9	2,206.8
Deferred charges and other assets
Regulatory assets	3,031.4	3,064.6
Goodwill	3,046.2	3,023.5
Other	419.9	403.9
Total deferred charges and other assets	6,497.5	6,492.0
Total assets	29,175.3	29,355.2
Capitalization
Common stock – $.01 par value; 325,000,000 shares authorized; 315,619,968 and 315,683,496 shares outstanding, respectively	3.2	3.2
Additional paid in capital	4,310.9	4,347.2
Retained earnings	4,515.0	4,299.8
Accumulated other comprehensive income	4.4	4.6
Preferred Stock, Value, Issued	30.4	30.4
Long-term debt	8,902.1	9,124.1
Total capitalization	17,766.0	17,809.3
Current liabilities
Current portion of long-term debt	95.8	157.7
Short-term debt	927.8	1,095.0
Accounts payable	620.5	815.4
Accrued payroll and benefits	134.5	169.7
Other	358.5	471.2
Total current liabilities	2,137.1	2,709.0
Deferred credits and other liabilities
Regulatory liabilities	1,469.7	1,392.2
Deferred income taxes	4,938.3	4,622.3
Deferred revenue, net	572.3	579.4
Pension and OPEB obligations	541.9	543.1
Environmental remediation	617.9	628.2
Other	1,132.1	1,071.7
Total deferred credits and other liabilities	9,272.2	8,836.9
Commitments and contingencies (Note 16)
Total capitalization and liabilities	$ 29,175.3	$ 29,355.2

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Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Allowance for Doubtful Accounts Receivable, Current	$ 109.4	$ 113.3
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	325,000,000	325,000,000
Common Stock, Shares, Outstanding	315,619,968	315,683,496

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Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Operating Activities
Net income	$ 528.2	$ 277.3
Reconciliation to cash provided by operating activities
Depreciation and amortization	386.0	215.1
Deferred income taxes and investment tax credits, net	307.1	121.7
Contributions and payments related to pension and OPEB plans	(19.5)	(106.1)
Equity income in transmission affiliate, net of distributions	(22.7)	(9.2)
Change in -
Accounts receivable and unbilled revenues	130.1	134.5
Materials, supplies, and inventories	193.5	72.2
Other current assets	66.7	16.7
Accounts payable	(112.4)	27.4
Accrued taxes, net	(51.3)	10.5
Other current liabilities	(87.7)	(1.2)
Other, net	(93.9)	(42.4)
Net cash provided by operating activities	1,224.1	716.5
Investing Activities
Capital expenditures	(618.7)	(368.0)
Business acquisition, net of cash acquired of $156.3	0.0	(1,329.4)
Investment in transmission affiliate	(12.1)	(2.6)
Proceeds from the sale of assets and businesses	161.0	21.2
Withdrawal of restricted cash from Rabbi trust for qualifying payments	22.5	0.0
Other, net	(1.8)	(0.4)
Net cash used in investing activities	(449.1)	(1,679.2)
Financing Activities
Exercise of stock options	35.0	12.2
Purchase of common stock	(94.2)	(32.0)
Dividends paid on common stock	(312.4)	(190.5)
Issuance of long-term debt	0.0	1,450.0
Retirement of long-term debt	(241.8)	(11.6)
Change in short-term debt	(167.2)	(105.7)
Other, net	(12.1)	(7.2)
Net cash (used in) provided by financing activities	(792.7)	1,115.2
Net change in cash and cash equivalents	(17.7)	152.5
Cash and cash equivalents at beginning of period	49.8	61.9
Cash and cash equivalents at end of period	$ 32.1	$ 214.4

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Condensed Consolidated Statements of Cash Flows (Unaudited) (Parenthetical) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Investing Activities
Business acquisition, cash acquired	$ 0.0	$ 156.3

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General Information

6 Months Ended

Jun. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

GENERAL INFORMATION

GENERAL INFORMATION

On June 29, 2015, Wisconsin Energy Corporation acquired Integrys and changed its name to WEC Energy Group, Inc. WEC Energy Group serves approximately 1.6 million electric customers and 2.8 million natural gas customers, and it owns approximately 60% of ATC. See Note 2, Acquisition, for more information.

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

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2015. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and six months ended June 30, 2016, are not necessarily indicative of expected results for 2016 due to seasonal variations and other factors.

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

Reclassifications

On the income statements for the three and six months ended June 30, 2015, we reclassified $2.2 million and $4.7 million, respectively, from treasury grant to depreciation and amortization. We also reclassified an insignificant amount from interest expense to preferred stock dividends of subsidiary on the income statements for the three and six months ended June 30, 2015. These reclassifications were made to be consistent with the current period presentation.

On the statement of cash flows for the six months ended June 30, 2015, we reclassified $1.7 million from depreciation and amortization to other operating activities. In addition, we reclassified $6.1 million of non-qualified pension and OPEB contributions from other operating activities to contributions and payments related to pension and OPEB plans. We also reclassified $11.5 million from other investing activities to capital expenditures on the statement of cash flows for the six months ended June 30, 2015. An insignificant amount of preferred stock dividends of subsidiary was also reclassified from other financing activities to net income. These reclassifications were made to be consistent with the current period presentation.

During the third quarter of 2015, following the acquisition of Integrys, we reorganized our business segments. All prior period amounts impacted by this change were reclassified to conform to the new presentation. See Note 14, Segment Information, for more information on our business segments.

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Acquisition

6 Months Ended

Jun. 30, 2016

Business Combinations [Abstract]

ACQUISITION

ACQUISITION

On June 29, 2015, Wisconsin Energy Corporation acquired 100% of the outstanding common shares of Integrys and changed its name to WEC Energy Group, Inc.

Allocation of Purchase Price

The Integrys assets acquired and liabilities assumed were measured at estimated fair value in accordance with the accounting guidance under the Business Combinations Topic in the FASB ASC. Substantially all of Integrys's operations are subject to the rate-setting authority of federal and state regulatory commissions. These operations are accounted for following the accounting guidance under the Regulated Operations Topic of the FASB ASC. The underlying assets and liabilities of ATC are also regulated by the FERC. The fair values of Integrys's assets and liabilities subject to rate-setting provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair values of these assets and liabilities equal their carrying values. Accordingly, neither the assets and liabilities acquired, nor the pro forma financial information, reflect any adjustments related to these amounts.

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. The goodwill reflects the value paid for the increased scale and efficiencies as a result of the combination. The goodwill recognized is not deductible for income tax purposes, and as such, no deferred taxes have been recorded related to goodwill. See Note 12, Goodwill, for the allocation of goodwill to our reportable segments.

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. In 2016, adjustments were made to the estimated fair values of the assets acquired and liabilities assumed, primarily in connection with the sale of ITF and reserves recorded for likely settlements of certain legal and regulatory matters.

(in millions)
Current assets	$	1,060.1
Net property, plant, and equipment	7,107.4
Investments *	1,072.0
Goodwill	2,604.3
Deferred charges and other assets, excluding goodwill	1,758.5
Current liabilities, including current maturities of long-term debt	(1,320.7		)
Deferred credits and other liabilities	(3,703.8		)
Long-term debt	(2,943.6		)
Preferred stock of subsidiary	(51.1		)
Total purchase price	$	5,583.1

* Includes equity method goodwill related to Integrys's investment in ATC.

Pro Forma Information

The following unaudited pro forma financial information reflects the consolidated results and amortization of purchase price adjustments as if the acquisition had taken place on January 1, 2014. The unaudited pro forma financial information is presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or our future consolidated results.

The pro forma financial information does not reflect any potential cost savings from operating efficiencies resulting from the acquisition and does not include certain acquisition-related costs.

(in millions, except per share amounts)	Three Months Ended June 30, 2015		Six Months Ended June 30, 2015
Unaudited Pro Forma Financial Information
Operating revenues	$	1,629.2	$	4,180.1
Net income	$	159.1	$	488.7
Earnings per share (Basic)	$	0.50	$	1.55
Earnings per share (Diluted)	$	0.50	$	1.54

Impact of Acquisition

In connection with the acquisition, WEC Energy Group and its subsidiaries recorded pre-tax acquisition costs of $65.0 million and $73.7 million during the three and six months ended June 30, 2015, respectively. These costs consisted of employee-related expenses, professional fees, and other miscellaneous costs. They were recorded in other operation and maintenance on our income statements. Acquisition costs incurred during the three and six months ended June 30, 2016 were not significant.

Our revenues for the three and six months ended June 30, 2015 did not include any revenues attributable to Integrys. Included in our net income for the three and six months ended June 30, 2015, is a net loss attributable to Integrys of $26.6 million related to acquisition costs that were incurred post-acquisition.

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Dispositions

6 Months Ended

Jun. 30, 2016

Discontinued Operations and Disposal Groups [Abstract]

DISPOSITIONS

DISPOSITIONS

Wisconsin Segment – Sale of Milwaukee County Power Plant

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

Corporate and Other Segment

Sale of Certain Assets of Wisvest

In April 2016, as part of the MCPP sale transaction, we sold the chilled water generation and distribution assets of Wisvest, which are used to provide chilled water services to the Milwaukee Regional Medical Center hospitals and other campus buildings. During the second quarter of 2016, we recorded a pre-tax gain on the sale of $19.6 million ($11.8 million after tax), which is included in other income, net on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations associated with these assets remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.

Sale of Integrys Transportation Fuels

Through a series of transactions in the fourth quarter of 2015 and the first quarter of 2016, we sold ITF, a provider of CNG fueling services and a single-source provider of CNG fueling facility design, construction, operation, and maintenance. There was no gain or loss recorded on the sales, as ITF's assets and liabilities were adjusted to fair value through purchase accounting. The sale of ITF met the criteria to qualify as held for sale at December 31, 2015, but did not meet the requirements to qualify as a discontinued operation. The results of operations of ITF remained in continuing operations through the sale date as the sale of ITF did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results. The pre-tax profit or loss of this component was not material through the sale date in 2016.

The following table shows the carrying values of the major classes of assets and liabilities included as held for sale on our balance sheet at December 31:

(in millions)	2015
Property, plant, and equipment	$	37.2
Accounts receivable and unbilled revenues	34.9
Materials, supplies, and inventories	18.4
Other current assets	2.6
Other long-term assets	3.7
Total assets	$	96.8
Accounts payable	$	12.9
Accrued payroll and benefits	2.4
Other current liabilities	4.5
Pension and OPEB obligations	1.2
Other long-term liabilities	0.6
Total liabilities *	$	21.6

* Included in other current liabilities on our balance sheet.

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Common Equity

6 Months Ended

Jun. 30, 2016

Stockholders' Equity Note [Abstract]

COMMON EQUITY

COMMON EQUITY

Stock-Based Compensation Plans

During the six months endedJune 30, 2016, the Compensation Committee of our Board of Directors awarded the following stock-based compensation awards to our directors, officers, and certain other key employees:

Award Type	Number of Awards
Stock options (1)	794,764
Restricted shares (2)	146,941
Performance units	297,397

⁽¹⁾  Stock options awarded had a weighted-average exercise price of $52.15 and a weighted-average grant date fair value of $5.14 per option.

⁽²⁾  Restricted shares awarded had a weighted-average grant date fair value of $53.69 per share.

Restrictions

Our ability as a holding company to pay common stock dividends primarily depends on the availability of funds received from our utility subsidiaries and our non-utility subsidiary, We Power. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans, or advances. All of our utility subsidiaries, with the exception of MGU, are prohibited from loaning funds to us, either directly or indirectly. See Note 11, Common Equity, in our 2015 Annual Report on Form 10-K for additional information on these and other restrictions.

We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.

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Short-term Debt and Lines of Credit

6 Months Ended

Jun. 30, 2016

Short-term Debt [Abstract]

SHORT-TERM DEBT AND LINES OF CREDIT

SHORT-TERM DEBT AND LINES OF CREDIT

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

(in millions, except percentages)	June 30, 2016			December 31, 2015
Commercial paper
Amount outstanding	$	927.8		$	1,095.0
Weighted-average interest rate on amounts outstanding	0.66		%	0.68		%

Our average amount of commercial paper borrowings based on daily outstanding balances during the six months ended June 30, 2016, was $903.5 million with a weighted-average interest rate during the period of 0.61%.

The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing programs, including remaining available capacity under these facilities:

(in millions)	Maturity	June 30, 2016
WEC Energy Group	December 2020	$	1,050.0
WE	December 2020	500.0
WPS	December 2020	250.0
WG	December 2020	350.0
PGL	December 2020	350.0
Total short-term credit capacity		$	2,500.0
Less:
Letters of credit issued inside credit facilities		$	26.0
Commercial paper outstanding		927.8
Available capacity under existing agreements		$	1,546.2

In May 2016, WPS received approval from the PSCW to extend the maturity date of its revolving credit facility from December 2016 to December 2020.

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Long Term Debt

6 Months Ended

Jun. 30, 2016

Long-term Debt, Unclassified [Abstract]

Long Term Debt

LONG-TERM DEBT

In June 2016, PGL issued commercial paper to redeem at par, its $50.0 million of 4.30% Series RR First and Refunding Mortgage Bonds that were due in 2035.

In June 2016, Integrys's $50.0 million of 8.00% unsecured senior notes matured and were repaid with the proceeds from commercial paper issued by WEC Energy Group.

In February 2016, Integrys repurchased and retired $154.9 million aggregate principal amount of its 6.11% Junior Notes for a purchase price of $128.6 million, plus accrued and unpaid interest, through a modified “dutch auction” tender offer. The gain associated with this repurchase is included in other income, net on our income statement. Effective December 1, 2016, the remaining $114.9 million aggregate principal amount of the 6.11% Junior Notes will bear interest at the three-month London Interbank Offered Rate plus 2.12% and will reset quarterly. In connection with this transaction, Integrys issued approximately $66.4 million of additional common stock to WEC Energy Group in satisfaction of its obligations under a replacement capital covenant relating to the 6.11% Junior Notes.

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Materials, Supplies, and Inventories

6 Months Ended

Jun. 30, 2016

Inventory Disclosure [Abstract]

MATERIALS, SUPPLIES, AND INVENTORIES

MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:

(in millions)	June 30, 2016		December 31, 2015
Materials and supplies	$	217.3	$	219.2
Fossil fuel	156.6		183.7
Natural gas in storage	120.6		284.1
Total	$	494.5	$	687.0

PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the 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 June 30, 2016, we had a temporary LIFO liquidation debit of $28.8 million recorded within other current assets on our balance sheet. Due to seasonality requirements, PGL and NSG expect these interim reductions in LIFO layers to be replenished by year end.

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

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Fair Value Measurements

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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

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

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

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

	June 30, 2016
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	10.1	$	12.4	$	—	$	22.5
FTRs	—		—		13.4		13.4
Petroleum products contracts	0.4		—		—		0.4
Coal contracts	—		1.3		—		1.3
Total derivative assets	$	10.5	$	13.7	$	13.4	$	37.6
Investments held in rabbi trust	$	42.8	$	—	$	—	$	42.8
Derivative liabilities
Natural gas contracts	$	0.5	$	5.4	$	—	$	5.9
Petroleum products contracts	1.4		—		—		1.4
Coal contracts	—		12.6		—		12.6
Total derivative liabilities	$	1.9	$	18.0	$	—	$	19.9

	December 31, 2015
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	1.6	$	1.5	$	—	$	3.1
FTRs	—		—		3.6		3.6
Petroleum products contracts	1.2		—		—		1.2
Coal contracts	—		2.0		—		2.0
Total derivative assets	$	2.8	$	3.5	$	3.6	$	9.9
Investments held in rabbi trust	$	39.8	$	—	$	—	$	39.8
Derivative liabilities
Natural gas contracts	$	16.5	$	25.3	$	—	$	41.8
Petroleum products contracts	4.9		—		—		4.9
Coal contracts	—		12.3		—		12.3
Total derivative liabilities	$	21.4	$	37.6	$	—	$	59.0

The derivative assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy Markets.

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

	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2016			2015			2016			2015
Balance at the beginning of the period	$	1.1		$	3.3		$	3.6		$	7.0
Realized and unrealized losses	—			—			(0.2		)	—
Purchases	15.2			3.9			15.2			3.9
Sales	(0.1		)	—			(0.2		)	—
Settlements	(2.8		)	(3.6		)	(5.0		)	(7.3		)
Acquisition of Integrys	—			(1.3		)	—			(1.3		)
Balance at the end of the period	$	13.4		$	2.3		$	13.4		$	2.3

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

Fair Value of Financial Instruments

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

	June 30, 2016				December 31, 2015
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock	$	30.4	$	29.7	$	30.4	$	27.3
Long-term debt, including current portion *	$	8,952.6	$	9,984.8	$	9,221.9	$	9,681.0

* The carrying amount of long-term debt excludes capital lease obligations of $45.3 million and $59.9 million at June 30, 2016, and

December 31, 2015, respectively.

Due to the short-term nature of cash and cash equivalents, net accounts receivable, accounts payable, and short-term borrowings, the carrying amount of each such item approximates fair value. The fair value of our preferred stock is estimated based on the quoted market value for the same issue, or by using a perpetual dividend discount model. The fair value of our long-term debt is estimated based upon the quoted market value for the same issue, similar issues, or upon the quoted market prices of United States Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows. The fair values of our long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.

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Derivative Instruments

6 Months Ended

Jun. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS

DERIVATIVE INSTRUMENTS

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

We record derivative instruments on our balance sheets as an asset or liability measured at fair value unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities.

The following table shows our derivative assets and derivative liabilities:

	June 30, 2016				December 31, 2015
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	19.3	$	5.9	$	2.6	$	38.5
Petroleum products contracts	0.3		1.4		0.9		3.8
FTRs	13.4		—		3.6		—
Coal contracts	1.3		9.8		1.7		6.7
Total other current *	$	34.3	$	17.1	$	8.8	$	49.0
Other long-term
Natural gas contracts	$	3.2	$	—	$	0.5	$	3.3
Petroleum products contracts	0.1		—		0.3		1.1
Coal contracts	—		2.8		0.3		5.6
Total other long-term *	$	3.3	$	2.8	$	1.1	$	10.0
Total	$	37.6	$	19.9	$	9.9	$	59.0

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

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

	Three Months Ended June 30, 2016				Three Months Ended June 30, 2015
(in millions)	Volume	Gains (Losses)			Volume	Gains (Losses)
Natural gas contracts	32.7 Dth	$	(20.0	)	10.0 Dth	$	(5.9	)
Petroleum products contracts	3.6 gallons	(1.0		)	0.8 gallons	0.1
FTRs	7.4 MWh	1.6			5.9 MWh	0.8
Total		$	(19.4	)		$	(5.0	)
	Six Months Ended June 30, 2016				Six Months Ended June 30, 2015
(in millions)	Volume	Gains (Losses)			Volume	Gains (Losses)
Natural gas contracts	82.8 Dth	$	(53.5	)	23.3 Dth	$	(13.0	)
Petroleum products contracts	6.6 gallons	(2.1		)	1.7 gallons	—
FTRs	15.0 MWh	4.6			12.1 MWh	2.9
Total		$	(51.0	)		$	(10.1	)

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At June 30, 2016, and December 31, 2015, we had posted cash collateral of $22.4 million and $42.3 million, respectively, in our margin accounts. These amounts were recorded on the balance sheets in other current assets.

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

	June 30, 2016						December 31, 2015
(in millions)	Derivative Assets			Derivative Liabilities			Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	37.6		$	19.9		$	9.9		$	59.0
Gross amount not offset on the balance sheet *	(4.2		)	(4.2		)	(3.0		)	(22.5		)
Net amount	$	33.4		$	15.7		$	6.9		$	36.5

* Includes cash collateral posted of $19.5 million as of December 31, 2015. There was no cash collateral included at June 30, 2016.

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 was $3.1 million and $23.8 million at June 30, 2016, and December 31, 2015, respectively. At June 30, 2016, and December 31, 2015, 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 derivative instruments in a net liability position had been triggered at June 30, 2016, and December 31, 2015, we would have been required to post collateral of $1.3 million and $18.0 million, respectively.

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Guarantees

6 Months Ended

Jun. 30, 2016

Guarantees [Abstract]

GUARANTEES

GUARANTEES

The following table shows our outstanding guarantees:

	Total Amounts Committed at		Expiration
(in millions)	June 30, 2016		Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees
Guarantees supporting commodity transactions of subsidiaries (1)	$	147.1	$	68.1	$	5.0	$	74.0
Standby letters of credit (2)	36.4		36.0		0.2		0.2
Surety bonds (3)	11.2		11.2		—		—
Other guarantees (4)	38.5		0.7		6.8		31.0
Total guarantees	$	233.2	$	116.0	$	12.0	$	105.2

⁽¹⁾  Consists of (a) $5.0 million and $10.0 million to support the business operations of WBS and PDL, respectively; and (b) $99.3 million and $32.8 million related to natural gas supply at MERC and MGU, respectively. These amounts 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 are not reflected on our balance sheets.

⁽³⁾  Primarily for workers compensation self-insurance programs and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets.

⁽⁴⁾  Consists of (a) $19.1 million to support PDL's future payment obligations related to its distributed solar generation projects, of which $6.6 million is covered by a reciprocal guarantee from a third party that is not reflected on our balance sheets; (b) $10.0 million related to the sale of a nonregulated retail marketing business previously owned by Integrys, of which an insignificant liability was recorded; and (c) $9.4 million related to other indemnifications, of which a liability of $8.8 million related to workers compensation coverage was recorded.

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Employee Benefits

6 Months Ended

Jun. 30, 2016

Compensation and Retirement Disclosure [Abstract]

EMPLOYEE BENEFITS

EMPLOYEE BENEFITS

The following tables show the components of net periodic pension and OPEB costs for our benefit plans. Our pension and OPEB costs for the three and six months ended June 30, 2016, include costs attributable to the Integrys pension and OPEB plans. The terms and conditions of the legacy company plans have not changed materially since the acquisition.

	Pension Costs
	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2016			2015			2016			2015
Service cost	$	10.7		$	3.9		$	22.0		$	7.8
Interest cost	33.0			15.1			66.2			30.3
Expected return on plan assets	(49.0		)	(25.6		)	(98.0		)	(51.4		)
Loss on plan settlement	14.1			—			14.1			—
Amortization of prior service cost	0.8			0.5			1.7			1.0
Amortization of net actuarial loss	20.2			11.4			40.7			23.0
Net periodic benefit cost	$	29.8		$	5.3		$	46.7		$	10.7

	OPEB Costs
	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2016			2015			2016			2015
Service cost	$	6.4		$	2.1		$	13.1		$	4.7
Interest cost	9.3			3.9			18.5			8.1
Expected return on plan assets	(13.3		)	(5.9		)	(26.4		)	(11.8		)
Amortization of prior service credit	(2.4		)	(0.3		)	(4.7		)	(0.6		)
Amortization of net actuarial loss	1.9			0.5			4.2			1.0
Net periodic benefit cost	$	1.9		$	0.3		$	4.7		$	1.4

We did not make any contributions to our qualified pension plans during the first six months of 2016. During the six months ended June 30, 2016, we made payments of $17.0 million related to our non-qualified pension plans and $2.5 million to our OPEB plans. We expect to make payments of $6.0 million related to our pension plans and $15.2 million related to our OPEB plans during the remainder of 2016, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

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Goodwill

6 Months Ended

Jun. 30, 2016

Goodwill and Intangible Assets Disclosure [Abstract]

GOODWILL

GOODWILL

Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. The following table shows changes to our goodwill balances by segment during the six months ended June 30, 2016:

(in millions)	Wisconsin				Illinois			Other States			Total
Goodwill balance as of January 1, 2016	$	2,109.5			$	731.2		$	182.8		$	3,023.5
Adjustment to Integrys purchase price allocation	(5.2		)		27.5			0.4			22.7
Goodwill balance as of June 30, 2016 (1)	$	2,104.3		(2)	$	758.7	(3)	$	183.2	(3)	$	3,046.2

⁽¹⁾  We had no accumulated impairment losses related to our goodwill as of June 30, 2016.

⁽²⁾  Of this amount, $1,662.4 million relates to the acquisition of Integrys.

⁽³⁾  Total amount relates to the acquisition of Integrys.

Due to the acquisition of Integrys, we changed the date of our annual goodwill impairment test from August 31 to July 1. As a result, we are in the process of performing the test for all of our reporting units that carried a goodwill balance as of July 1, 2016. We are not currently aware of any impairment indicators.

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Investment in American Transmission Company

6 Months Ended

Jun. 30, 2016

Equity Method Investments and Joint Ventures [Abstract]

INVESTMENT IN AMERICAN TRANSMISSION COMPANY

INVESTMENT IN AMERICAN TRANSMISSION COMPANY

Due to the acquisition of Integrys on June 29, 2015, our ownership of ATC increased from 26.2% to approximately 60%. ATC is a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. The following table shows changes to our investment in ATC:

	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2016				2015		2016				2015
Balance at beginning of period	$	1,422.5			$	431.1	$	1,380.9		(1)	$	424.1
Add: Earnings from equity method investment	30.9				14.3		69.4				30.4
Add: Capital contributions	3.1				1.2		12.1				2.5
Add: Acquisition of Integrys's investment in ATC	(1.0		)	(2)	552.0		(1.0		)	(2)	552.0
Add: Adjustment to equity method goodwill	1.1				—		10.4				—
Less: Distributions received	31.6				10.8		46.7				21.2
Less: Other	—				—		0.1				—
Balance at end of period	$	1,425.0			$	987.8	$	1,425.0			$	987.8

⁽¹⁾  Equity method goodwill of $395.8 million from the acquisition of Integrys was recorded in the fourth quarter of 2015.

⁽²⁾  Amount reflects an adjustment to the allocation of the purchase price made in the second quarter of 2016.

We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed to us by ATC. We are required to pay the cost of needed transmission infrastructure upgrades for new generation projects while the projects are under construction. ATC reimburses us for these costs when the new generation is placed in service.

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

	Three Months Ended June 30				Six Months Ended June 30
(in millions)	2016		2015		2016		2015
Charges to ATC for services and construction	$	4.3	$	2.5	$	8.4	$	5.0
Charges from ATC for network transmission services	91.1		59.6		182.1		119.2

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

(in millions)	June 30, 2016		December 31, 2015
Accounts receivable
Services provided to ATC	$	1.4	$	1.0
Accounts payable
Services received from ATC	30.3		28.3

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

	Three Months Ended June 30				Six Months Ended June 30
(in millions)	2016		2015		2016		2015
Income statement data
Revenues	$	154.3	$	165.1	$	318.5	$	317.5
Operating expenses	81.7		80.3		160.8		160.3
Other expense	23.7		24.2		47.7		48.6
Net income	$	48.9	$	60.6	$	110.0	$	108.6

(in millions)	June 30, 2016		December 31, 2015
Balance sheet data
Current assets	$	83.9	$	80.5
Noncurrent assets	4,104.6		3,948.3
Total assets	$	4,188.5	$	4,028.8
Current liabilities	$	382.5	$	330.3
Long-term debt	1,791.0		1,790.7
Other noncurrent liabilities	293.8		245.0
Shareholders' equity	1,721.2		1,662.8
Total liabilities and shareholders' equity	$	4,188.5	$	4,028.8

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Segment Information

6 Months Ended

Jun. 30, 2016

Segment Reporting [Abstract]

SEGMENT INFORMATION

SEGMENT INFORMATION

At June 30, 2016, we reported six segments, which are described below.

• The Wisconsin segment includes the electric and natural gas utility operations of WE, WG, and WPS, including WE's and WPS's electric and natural gas operations in the state of Michigan.

• The Illinois segment includes the natural gas utility and non-utility operations of PGL and NSG.

• The other states segment includes the natural gas utility and non-utility operations of MERC and MGU.

• The electric transmission segment includes our approximate 60% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions.

• The We Power segment includes our nonregulated entity that owns and leases generating facilities to WE.

• The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the Peoples Energy, LLC holding company, Wispark LLC, Bostco LLC, Wisvest, Wisconsin Energy Capital Corporation, WBS, PDL, and ITF. The sale of ITF was completed in the first quarter of 2016. In the second quarter of 2016, we sold Wisvest's assets. See Note 3, Dispositions, for more information on these sales.

All of our operations are located within the United States. The following tables show summarized financial information concerning our reportable segments for the three and six months ended June 30, 2016 and 2015:

	Regulated Operations
(in millions)	Wisconsin		Illinois		Other States		Electric Transmission		Total Regulated Operations		We Power		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Three Months Ended
June 30, 2016
External revenues	$	1,304.5	$	222.8	$	64.0	$	—	$	1,591.3	$	6.3	$	4.4		$	—		$	1,602.0
Intersegment revenues	0.2		—		—		—		0.2		107.6		—			(107.8		)	—
Other operation and maintenance	487.8		116.2		29.4		—		633.4		2.7		(6.3		)	(107.8		)	522.0
Depreciation and amortization	122.7		33.1		5.2		—		161.0		17.0		12.0			—			190.0
Operating income (loss)	214.7		22.6		2.3		—		239.6		94.1		(1.6		)	—			332.1
Equity in earnings of transmission affiliate	—		—		—		30.9		30.9		—		—			—			30.9
Interest expense	44.4		9.8		2.1		—		56.3		15.6		30.2			(2.0		)	100.1

	Regulated Operations
(in millions)	Wisconsin		Illinois		Other States		Electric Transmission		Total Regulated Operations		We Power		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Three Months Ended
June 30, 2015
External revenues	$	978.5	$	—	$	—	$	—	$	978.5	$	9.6	$	3.1		$	—		$	991.2
Intersegment revenues	1.4		—		—		—		1.4		103.1		—			(104.5		)	—
Other operation and maintenance	368.3		—		—		—		368.3		2.7		70.1			(104.1		)	337.0
Depreciation and amortization	86.3		—		—		—		86.3		16.9		0.3			—			103.5
Operating income (loss)	140.4		—		—		—		140.4		93.2		(67.8		)	—			165.8
Equity in earnings of transmission affiliate	—		—		—		14.3		14.3		—		—			—			14.3
Interest expense	32.1		—		—		—		32.1		15.9		14.0			(0.2		)	61.8

	Regulated Operations
(in millions)	Wisconsin		Illinois		Other States		Electric Transmission		Total Regulated Operations		We Power		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Six Months Ended
June 30, 2016
External revenues	$	2,884.3	$	671.3	$	212.4	$	—	$	3,768.0	$	12.5	$	16.3		$	—		$	3,796.8
Intersegment revenues	0.3		—		—		—		0.3		212.1		—			(212.4		)	—
Other operation and maintenance	979.1		234.1		59.4		—		1,272.6		3.1		(9.8		)	(212.4		)	1,053.5
Depreciation and amortization	245.6		65.9		10.3		—		321.8		34.0		22.1			—			377.9
Operating income (loss)	542.2		159.6		34.1		—		735.9		187.4		(1.9		)	—			921.4
Equity in earnings of transmission affiliate	—		—		—		69.4		69.4		—		—			—			69.4
Interest expense	88.9		19.5		4.6		—		113.0		31.2		61.5			(4.7		)	201.0

	Regulated Operations
(in millions)	Wisconsin		Illinois		Other States		Electric Transmission		Total Regulated Operations		We Power		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Six Months Ended
June 30, 2015
External revenues	$	2,355.0	$	—	$	—	$	—	$	2,355.0	$	20.7	$	3.4		$	—		$	2,379.1
Intersegment revenues	1.8		—		—		—		1.8		201.7		—			(203.5		)	—
Other operation and maintenance	737.4		—		—		—		737.4		3.1		80.2			(203.0		)	617.7
Depreciation and amortization	171.7		—		—		—		171.7		33.7		0.7			—			206.1
Operating income (loss)	416.9		—		—		—		416.9		185.7		(78.0		)	—			524.6
Equity in earnings of transmission affiliate	—		—		—		30.4		30.4		—		—			—			30.4
Interest expense	63.5		—		—		—		63.5		31.8		26.2			(0.3		)	121.2

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Variable Interest Entities

6 Months Ended

Jun. 30, 2016

Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Determination Methodology and Factors [Abstract]

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES

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

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

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

American Transmission Company

We own approximately 60% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. We have determined that ATC is a variable interest entity but that consolidation is not required since we are not ATC's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC's economic performance. We account for ATC as an equity method investment. See Note 13, Investment in American Transmission Company, for more information.

The significant assets and liabilities related to ATC recorded on our balance sheets included our equity investment and accounts payable. At June 30, 2016 and December 31, 2015, our equity investment was $1,425.0 million and $1,380.9 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC. In addition, we had $30.3 million and $28.3 million of accounts payable due to ATC at June 30, 2016 and December 31, 2015, respectively, for network transmission services.

Purchased Power Agreement

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

We have approximately $107.9 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under this contract for the six months ended June 30, 2016 and 2015 were $26.9 million and $26.8 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

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

Energy Related Purchased Power Agreements

Our natural gas utilities have obligations to distribute and sell natural gas to their customers, and our electric utilities have obligations to distribute and sell electricity to their customers. The utilities expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of June 30, 2016, including those of our subsidiaries, were $12,345.8 million.

Environmental Matters

Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as SO₂, NOx, fine particulates, mercury, and GHGs; water discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.

Air Quality

Sulfur Dioxide National Ambient Air Quality Standards

The EPA issued a revised 1-Hour SO₂ NAAQS that became effective in August 2010. The EPA issued a final rule in August 2015 describing the implementation requirements and established a compliance timeline for the revised standard. The final rule affords state agencies some latitude in rule implementation. A nonattainment designation could have negative impacts for a localized geographic area, including additional permitting requirements for new or existing sources in the area.

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

In June 2016, we provided modeling to the WDNR that shows the area around the Weston Power Plant to be in compliance. Based upon the submittal, we believe the WDNR will recommend by January 2017 that the area be designated attainment. We expect that the EPA will consider the WDNR's recommendation and finalize their own recommendation by the end of 2017.

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

8-Hour Ozone National Ambient Air Quality Standards

The EPA completed its review of the 2008 8-hour ozone standard in November 2014, and announced a proposal to tighten (lower) the NAAQS. In October 2015, the EPA released the final rule, which lowered the limit for ground-level ozone. This is expected to cause nonattainment designations for some counties in Wisconsin with potential future impacts for our fossil-fueled power plant fleet. For nonattainment areas, the state will have to develop a state implementation plan to bring the areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020 and are in the process of reviewing and determining potential impacts resulting from this rule.

Mercury and Other Hazardous Air Pollutants

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

We believe that the WE and WPS fleets are well positioned to comply with this regulation. Controls for acid gases and mercury are already in operation at the Pulliam units, and our compliance plans currently include capital projects for WPS's jointly owned plants to achieve the required reductions for MATS. In April 2013, WE received a one year MATS compliance extension from the MDEQ for PIPP through April 2016. The addition of a dry sorbent injection system for further control of mercury and acid gases at PIPP was placed into service in March 2016, and PIPP is now in compliance with MATS. Although WPS received a one year MATS compliance extension from the WDNR for Weston Unit 3 through April 2016, this unit is on a planned outage to complete the construction and start-up of the ReACT^TM system. Construction of the ReACT^TM multi-pollutant control system at Weston Unit 3 is complete and startup/commissioning work is underway with an expected in-service date in 2016. Once Weston Unit 3 comes back on line, it is expected to be in compliance with the MATS emission requirements.

Climate Change

In 2015, the EPA issued the Clean Power Plan, a final rule regulating GHG emissions from existing generating units, a proposed federal plan and model trading rules as alternatives or guides to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In October 2015, following publication of the final rule for existing fossil-fueled generating units, numerous states (including Wisconsin and Michigan), trade associations, and private parties filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but in February 2016, the Supreme Court stayed the effectiveness of the rule until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that review is sought, at the Supreme Court. In addition, in February 2016, the Governor of Wisconsin issued Executive Order 186, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan.

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

The goal of the final rule is to reduce nationwide GHG emissions by 32% from 2005 levels. The rule is seeking GHG emission reductions in Wisconsin and Michigan of 41% and 39%, respectively, below 2012 levels by 2030. Interim goals starting in 2022 would require states to achieve about two-thirds of the 2030 required reduction. The building blocks used by the EPA to determine each state's emission reduction requirements include a combination of improving power plant efficiency, increasing reliance on combined cycle natural gas units, and adding new renewable energy resources. We are in the process of reviewing the final rule for existing fossil-fueled generating units to determine the potential impacts to our operations. The rule could result in significant additional compliance costs, including capital expenditures, could impact how we operate our existing fossil-fueled power plants and biomass facility, and could have a material adverse impact on our operating costs.

Draft Federal Plan and Model Trading Rules were also published in October 2015 for use in developing state plans or for use in states where a plan is not submitted or approved. In December 2015, the state of Wisconsin submitted petitions for reconsideration of the EPA's final standards for existing, as well as new, modified, and reconstructed generating units. A petition for reconsideration of the EPA's final standards for existing generating units was also submitted jointly by the Wisconsin utilities. Among other things, the petitions narrowly ask the EPA to consider revising the state goal for existing units to reflect the 2013 retirement of the Kewaunee Power Station, which could lower the state's carbon dioxideequivalent reduction goal by about 10%. In May 2016, the EPA denied the state of Wisconsin's petition for reconsideration related to new, modified, and reconstructed generating units, except that the EPA deferred the portion related to the treatment of biomass. In addition, the EPA has not issued decisions yet regarding the above referenced petitions for reconsideration of the final EPA standards for existing generating units. In December 2015, Michigan state agencies announced modeling results that suggest that the state will be able to meet existing source requirements until 2025, based on planned coal plant retirements, along with a continuation of state renewable standards and current levels of energy efficiency.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act, which requires that the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts from both impingement and entrainment. The rule became effective in October 2014, and applies to all of our existing generating facilities with cooling water intake structures, except for the Oak Creek expansion units, which were permitted under the rules governing new facilities.

Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities, except for VAPP Unit 1, Pulliam Units 7 and 8, and Weston Unit 2, satisfy the IM BTA requirements. For VAPP Unit 2, a project to install fish protection screens to meet the IM BTA standard was completed in 2015. The same types of screens are scheduled to be installed on VAPP Unit 1 starting in the third quarter of 2016. We plan to evaluate the available IM options for Pulliam Units 7 and 8. We also expect that limited studies will be required to support the future WDNR BTA determinations for Weston Unit 2. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the IM BTA requirements based on low capacity use of the unit.

BTA determinations must also be made by the WDNR and MDEQ to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. We have received an EM BTA determination by the WDNR, with EPA concurrence, for our proposed intake modification at VAPP. BTA determinations for EM will be made in future permit reissuances for Pulliam Units 7 and 8, Weston Units 2 through 4, Port Washington Generating Station, Pleasant Prairie Power Plant, PIPP, and Oak Creek Power Plant Units 5 through 8. 

During 2016–2018, we will be completing studies and evaluating options to address the EM BTA requirements at our plants. With the exception of Pleasant Prairie Power Plant and Weston Units 3 and 4 (which all have existing cooling towers that meet EM BTA requirements), and VAPP, we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at our facilities. We also expect that limited studies to support WDNR BTA determinations will be conducted at the Weston facility. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the EM BTA requirements based on low capacity use of the unit. In addition, the rule allows the EM BTA requirements to be waived in cases of pending facility retirements, which we are currently considering for PIPP. Based on discussions with the MDEQ, if we submit a signed certification with our next National Pollutant Discharge Elimination System permit application stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2022), we believe the EM BTA requirements will be waived. Entrainment studies are currently being conducted at Pulliam Units 7 and 8 and are also underway at PIPP.

Steam Electric Effluent Guidelines

The EPA's final steam electric effluent guidelines rule took effect in January 2016 and applies to discharges of wastewater from our power plant processes in Wisconsin and Michigan. Unless pending challenges to the final guidelines are successful, the WDNR and MDEQ will modify the state rules and incorporate the new requirements into our facility permits, which are renewed every five years. We expect the new requirements to be phased in between 2018 and 2023 as our permits are renewed. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, these standards will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use. The final rule phases in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. New requirements for wet scrubber wastewater treatment will require additional zero liquid discharge or other advanced treatment capital improvements for the Oak Creek and Pleasant Prairie facilities. The rule also requires dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are required by the new rule, and modifications will be required at Oak Creek Units 7 and 8, the Pleasant Prairie units, the PIPP units, Pulliam Units 7 and 8, and Weston Unit 3. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $95 million to $130 million for these advanced treatment and bottom ash transport systems.

Valley Power Plant Wisconsin Pollutant Discharge Elimination System Permit

The WDNR issued a Wisconsin Pollutant Discharge Elimination System (WPDES) permit for VAPP that became effective in January 2013. The permit contains several additional requirements including effluent toxicity testing and monitoring for additional parameters (phosphorous, mercury, and ammonia-nitrogen), and a new heat addition limit from the cooling water discharges that all took effect immediately. Other long-term compliance requirements include thermal discharge studies, phosphorous evaluation and feasibility for reduction, mercury minimization planning, and the installation of new cooling water intake fish protection screens. Installation of wedge wire screens for fish protection on the VAPP Unit 2 cooling water intake structure was completed in 2015. An identical modification for VAPP Unit 1 is scheduled to begin in 2016. We are also working on updating the WPDES permit to reflect acceptance of VAPP process wastewater by the Milwaukee Metropolitan Sewage District, which addresses the permit conditions for phosphorous, mercury, and ammonia-nitrogen.

Manufactured Gas Plant Remediation

We have identified sites at which our utilities or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Our natural gas utilities are responsible for the environmental remediation of these sites, some of which are in the EPA Superfund Program. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure.

In addition, we are coordinating the investigation and cleanup of some of these sites subject to the jurisdiction of the EPA under what is called a "multisite" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.

The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites.

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

(in millions)	June 30, 2016		December 31, 2015
Regulatory assets	$	686.6	$	697.0
Reserves for future remediation	617.7		628.0

Enforcement and Litigation Matters

We and our subsidiaries are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material effect on our financial condition or results of operations.

Weston Title V Air Permit

In May 2014, the WDNR issued a NOV alleging that WPS failed to maintain a minimum sorbent feed rate prior to the Continuous Emissions Monitoring System certification and included an issue related to reporting NOx emissions from the Weston Unit 4 auxiliary boiler. In June 2015, the WDNR issued a NOV alleging that WPS failed to comply with mercury reporting requirements related to challenged matters in the 2013 Weston Title V permit. In June 2016, the WDNR issued a letter closing both the May 2014 and June 2015 NOVs with no further action.

Consent Decrees

Wisconsin Electric Power Company Consent Decree

In April 2003, WE entered into a Consent Decree with the EPA, in which it agreed to significantly reduce air emissions from its coal-fired power plants. Under the terms of the Consent Decree, WE could request its termination after December 31, 2015. WE made this termination request in March 2016. In July 2016, the United States informed WE that neither the EPA nor the State of Michigan objected to the termination request. WE, along with the United States and the State of Michigan, intend to request formal termination of the Consent Decree by the court shortly.

Wisconsin Public Service Corporation Consent Decree – Weston and Pulliam

In November 2009, the EPA issued a 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 entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Eastern District of Wisconsin in March 2013.

The Consent Decree contains requirements to refuel, repower, and/or retire certain Weston and Pulliam units. Effective June 1, 2015, WPS retired Weston Unit 1 and Pulliam Units 5 and 6. In March 2016, WPS submitted a proposed revision to the EPA to update requirements reflecting the conversion of Weston Unit 2 from coal to natural gas fuel, and also proposed revisions to the list of beneficial environmental projects required by the Consent Decree. These proposed revisions were approved by the EPA in May 2016. The revisions to the environmental projects are not expected to materially impact the overall cost required of $6.0 million.

WPS received approval from the PSCW in its 2015 rate order to defer and amortize the undepreciated book value of the retired plant related to Weston Unit 1 and Pulliam Units 5 and 6 starting June 1, 2015, and concluding by 2023. Therefore, in June 2015, WPS recorded a regulatory asset of $11.5 million for the undepreciated book value. In addition, WPS received approval from the PSCW in its rate orders to recover prudently incurred costs as a result of complying with the terms of the Consent Decree, with the exception of a $1.2 million civil penalty.

Also, 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 June 30, 2016. It is unknown whether the Sierra Club will take further action in the future.

Joint Ownership Power Plants Consent Decree – Columbia and Edgewater

In December 2009, the EPA issued a NOV to Wisconsin Power and Light, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric, WE (former co-owner of an Edgewater unit), and WPS. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. WPS, along with Wisconsin Power and Light, Madison Gas and Electric, and WE, entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013. WE paid an immaterial portion of the assessed penalty but has no further obligations under the Consent Decree.

The Consent Decree contains a requirement to, among other things, 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 Edgewater Unit 4 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.

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Supplemental Cash Flow Information

6 Months Ended

Jun. 30, 2016

Supplemental Cash Flow Information [Abstract]

SUPPLEMENTAL CASH FLOW INFORMATION

SUPPLEMENTAL CASH FLOW INFORMATION

	Six Months Ended June 30
(in millions)	2016			2015
Cash (paid) for interest, net of amount capitalized	$	(209.2	)	$	(116.3	)
Cash received (paid) for income taxes, net of (payments) refunds	7.4			(3.0		)
Significant non-cash transactions
Accounts payable related to construction costs	114.0			3.5
Amortization of deferred revenue	12.3			20.7

At June 30, 2016, and December 31, 2015, restricted cash of $94.4 million and $118.4 million, respectively, was recorded within other long-term assets on our balance sheets. The majority of this amount was held in the Integrys rabbi trust and represents a portion of the required funding that was triggered by the announcement of the Integrys acquisition.

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Regulatory Environment

6 Months Ended

Jun. 30, 2016

Regulated Operations [Abstract]

REGULATORY ENVIRONMENT

REGULATORY ENVIRONMENT

Wisconsin Public Service Corporation

2016 Wisconsin Rate Order

In April 2015, WPS initiated a rate proceeding with the PSCW. In December 2015, the PSCW issued a final written order for WPS, effective January 1, 2016. The order, which reflects a 10.0% ROE and a common equity component average of 51.0%, authorized a net retail electric rate decrease of $7.9 million (-0.8%) and a net retail natural gas rate decrease of $6.2 million (-2.1%). The decrease in retail electric rates was due to lower monitored fuel costs in 2016 compared to 2015. Absent the adjustment for electric fuel costs, WPS would have realized an electric rate increase. Based on the order, the PSCW will continue to allow WPS to escrow ATC and MISO network transmission expenses through 2016. In addition, future SSR payments will continue to be escrowed until a future rate proceeding. The order directs WPS to defer as a regulatory asset or liability the differences between actual transmission expenses and those included in rates. In addition, the PSCW approved a deferral for ReACT™, which requires WPS to defer the revenue requirement of ReACT™ costs above the authorized $275.0 million level through 2016. Fuel costs will continue to be monitored using a 2% tolerance window.

In March 2016, WPS requested extensions from the PSCW through 2017 for the deferral of the revenue requirement of ReACT™ costs above the authorized $275.0 million level as well as escrow accounting of ATC and MISO network transmission expenses. In April 2016, WPS also requested to extend through 2017 the previously approved deferral of the revenue requirement difference between the Real Time Market Pricing and the standard tariffed rates for any of WPS's current large commercial and industrial customers who entered into a service agreement with WPS under Real Time Market Pricing prior to April 15, 2016. These requests were approved by the PSCW in June 2016. The amounts deferred related to these items as of June 30, 2016, were not material.

The Peoples Gas Light and Coke Company and North Shore Gas Company

Illinois Investigations

In March 2015, the ICC opened a docket, naming PGL as respondent, to investigate the veracity of certain allegations included in anonymous letters that the ICC staff received regarding PGL's Gas System Modernization Program (previously known as AMRP). This matter is still pending.

In November 2015, the ICC initiated an investigation into whether we, PGL, or Integrys knowingly misled or withheld material information from the ICC at its open meeting on May 20, 2015. The investigation relates to the ICC Staff's presentation of independent audit findings reached for PGL's Gas System Modernization Program. The Illinois Attorney General conducted an inquiry into this matter, as well as the veracity of certain allegations included in anonymous letters that the ICC staff received regarding PGL's Gas System Modernization Program. In May 2016, PGL entered into settlement agreements that fully resolved and settled all contested issues with the ICC, the Illinois Attorney General, and the Citizens Utility Board regarding the ICC's investigation of the May 20, 2015, open meeting and all pending Illinois Attorney General inquiries. As part of the settlements, PGL agreed to make payments totaling $18.5 million, the majority of which consisted of voluntary contributions to certain public utility funds, low-income customer funds, and credits to customers.

In December 2015, the ICC ordered a series of stakeholder workshops to evaluate PGL's Gas System Modernization Program. This ICC action did not impact PGL's ongoing work to modernize and maintain the safety of its natural gas distribution system, but it instead provided the ICC with an opportunity to analyze long-term elements of the program through the stakeholder workshops. The workshops are expected to result in an ICC order with final and binding recommendations for PGL's Gas System Modernization Program. The workshops that commenced in January 2016 were completed in March 2016. The ICC staff submitted a report on the workshop process in May 2016. In July 2016, the ICC initiated a proceeding to review, among other things, the planning, reporting and monitoring of the program, including what the target end date for the program should be. This proceeding is expected to result in a final order by the ICC in the first quarter of 2017. We are currently unable to determine what, if any, long-term impact there will be on PGL's Gas System Modernization Program.

Minnesota Energy Resources Corporation

2016 Minnesota Rate Case

In September 2015, MERC initiated a rate proceeding with the MPUC to increase retail natural gas rates $14.8 million (5.5%). MERC's request reflects a 10.3% ROE and a common equity component average of 50.32%. The proposed retail natural gas rate increase is primarily driven by higher construction and capital expenditures, general inflation, and improvements to customer service programs. The request also includes increases in costs related to the acquisition of Alliant Energy Corporation's Minnesota natural gas operations in April 2015. MERC is requesting authority from the MPUC to continue the use of its currently authorized decoupling mechanism.

In November 2015, the MPUC approved an interim rate order, effective January 1, 2016, authorizing a retail natural gas rate increase for MERC of $9.7 million (3.7%). The interim rates reflect a 9.35% ROE and a common equity component average of 50.32%. The interim rate increase is subject to refund pending the final rate order, which is expected by the end of 2016.

Upper Michigan Energy Resources Corporation

In June 2016, we filed a proposal with the MPSC and the PSCW to form Upper Michigan Energy Resources Corporation, a stand-alone utility in the Upper Peninsula of Michigan. This utility will include the electric and natural gas distribution assets of WE and WPS located in the Upper Peninsula. The proposal was filed pursuant to the MPSC's approval of our acquisition of Integrys, whereby we agreed to form a separate Michigan utility company. If approved, we anticipate that the new utility will be created effective January 1, 2017.

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New Accounting Pronouncements

6 Months Ended

Jun. 30, 2016

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

NEW ACCOUNTING PRONOUNCEMENTS

NEW ACCOUNTING PRONOUNCEMENTS

Revenue Recognition

In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and can either be applied retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently assessing the effects this guidance may have on our financial statements.

Classification and Measurement of Financial Instruments

In January 2016, the FASB issued ASU 2016-01, Classification and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. We are currently assessing the effects this guidance may have on our financial statements.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, and will be applied using a modified retrospective approach. We are currently assessing the effects this guidance may have on our financial statements.

Stock-Based Compensation

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. We are currently assessing the effects this guidance may have on our financial statements.

Financial Instruments Credit Losses

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. We are currently assessing the effects this guidance may have on our financial statements.

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General Information (Policies)

6 Months Ended

Jun. 30, 2016

Accounting policies

Basis of Accounting

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2015. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and six months ended June 30, 2016, are not necessarily indicative of expected results for 2016 due to seasonal variations and other factors.

Reclassifications

Reclassifications

On the income statements for the three and six months ended June 30, 2015, we reclassified $2.2 million and $4.7 million, respectively, from treasury grant to depreciation and amortization. We also reclassified an insignificant amount from interest expense to preferred stock dividends of subsidiary on the income statements for the three and six months ended June 30, 2015. These reclassifications were made to be consistent with the current period presentation.

On the statement of cash flows for the six months ended June 30, 2015, we reclassified $1.7 million from depreciation and amortization to other operating activities. In addition, we reclassified $6.1 million of non-qualified pension and OPEB contributions from other operating activities to contributions and payments related to pension and OPEB plans. We also reclassified $11.5 million from other investing activities to capital expenditures on the statement of cash flows for the six months ended June 30, 2015. An insignificant amount of preferred stock dividends of subsidiary was also reclassified from other financing activities to net income. These reclassifications were made to be consistent with the current period presentation.

During the third quarter of 2015, following the acquisition of Integrys, we reorganized our business segments. All prior period amounts impacted by this change were reclassified to conform to the new presentation. See Note 14, Segment Information, for more information on our business segments.

Fair Value Measurement

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

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

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

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

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

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

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

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

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

Derivative Instruments

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

We record derivative instruments on our balance sheets as an asset or liability measured at fair value unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities.

New Accounting Pronouncements

Revenue Recognition

In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and can either be applied retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently assessing the effects this guidance may have on our financial statements.

Classification and Measurement of Financial Instruments

In January 2016, the FASB issued ASU 2016-01, Classification and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. We are currently assessing the effects this guidance may have on our financial statements.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, and will be applied using a modified retrospective approach. We are currently assessing the effects this guidance may have on our financial statements.

Stock-Based Compensation

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. We are currently assessing the effects this guidance may have on our financial statements.

Financial Instruments Credit Losses

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. We are currently assessing the effects this guidance may have on our financial statements.

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Acquisition (Tables)

6 Months Ended

Jun. 30, 2016

Business Combinations [Abstract]

Allocation of Purchase Price

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. In 2016, adjustments were made to the estimated fair values of the assets acquired and liabilities assumed, primarily in connection with the sale of ITF and reserves recorded for likely settlements of certain legal and regulatory matters.

(in millions)
Current assets	$	1,060.1
Net property, plant, and equipment	7,107.4
Investments *	1,072.0
Goodwill	2,604.3
Deferred charges and other assets, excluding goodwill	1,758.5
Current liabilities, including current maturities of long-term debt	(1,320.7		)
Deferred credits and other liabilities	(3,703.8		)
Long-term debt	(2,943.6		)
Preferred stock of subsidiary	(51.1		)
Total purchase price	$	5,583.1

* Includes equity method goodwill related to Integrys's investment in ATC.

Pro Forma Financial Information

The following unaudited pro forma financial information reflects the consolidated results and amortization of purchase price adjustments as if the acquisition had taken place on January 1, 2014. The unaudited pro forma financial information is presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or our future consolidated results.

The pro forma financial information does not reflect any potential cost savings from operating efficiencies resulting from the acquisition and does not include certain acquisition-related costs.

(in millions, except per share amounts)	Three Months Ended June 30, 2015		Six Months Ended June 30, 2015
Unaudited Pro Forma Financial Information
Operating revenues	$	1,629.2	$	4,180.1
Net income	$	159.1	$	488.7
Earnings per share (Basic)	$	0.50	$	1.55
Earnings per share (Diluted)	$	0.50	$	1.54

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Dispositions (Tables)

6 Months Ended

Jun. 30, 2016

Corporate and Other | ITF

Dispositions

Schedule of assets and liabilities included in held for sale

The following table shows the carrying values of the major classes of assets and liabilities included as held for sale on our balance sheet at December 31:

(in millions)	2015
Property, plant, and equipment	$	37.2
Accounts receivable and unbilled revenues	34.9
Materials, supplies, and inventories	18.4
Other current assets	2.6
Other long-term assets	3.7
Total assets	$	96.8
Accounts payable	$	12.9
Accrued payroll and benefits	2.4
Other current liabilities	4.5
Pension and OPEB obligations	1.2
Other long-term liabilities	0.6
Total liabilities *	$	21.6

* Included in other current liabilities on our balance sheet.

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Common Equity (Tables)

6 Months Ended

Jun. 30, 2016

Stockholders' Equity Note [Abstract]

Schedule of stock-based compensation awards granted

During the six months endedJune 30, 2016, the Compensation Committee of our Board of Directors awarded the following stock-based compensation awards to our directors, officers, and certain other key employees:

Award Type	Number of Awards
Stock options (1)	794,764
Restricted shares (2)	146,941
Performance units	297,397

⁽¹⁾  Stock options awarded had a weighted-average exercise price of $52.15 and a weighted-average grant date fair value of $5.14 per option.

⁽²⁾  Restricted shares awarded had a weighted-average grant date fair value of $53.69 per share.

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Short-term Debt and Lines of Credit (Tables)

6 Months Ended

Jun. 30, 2016

Short-term Debt [Abstract]

Short-term notes payable balances and their corresponding weighted average interest rate

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

(in millions, except percentages)	June 30, 2016			December 31, 2015
Commercial paper
Amount outstanding	$	927.8		$	1,095.0
Weighted-average interest rate on amounts outstanding	0.66		%	0.68		%

Schedule of revolving credit facilities and remaining available capacity

The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing programs, including remaining available capacity under these facilities:

(in millions)	Maturity	June 30, 2016
WEC Energy Group	December 2020	$	1,050.0
WE	December 2020	500.0
WPS	December 2020	250.0
WG	December 2020	350.0
PGL	December 2020	350.0
Total short-term credit capacity		$	2,500.0
Less:
Letters of credit issued inside credit facilities		$	26.0
Commercial paper outstanding		927.8
Available capacity under existing agreements		$	1,546.2

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Materials, Supplies, and Inventories (Tables)

6 Months Ended

Jun. 30, 2016

Inventory Disclosure [Abstract]

Schedule of inventory

Our inventory consisted of:

(in millions)	June 30, 2016		December 31, 2015
Materials and supplies	$	217.3	$	219.2
Fossil fuel	156.6		183.7
Natural gas in storage	120.6		284.1
Total	$	494.5	$	687.0

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

Fair value of assets and liabilities measured on a recurring basis, categorized by level within the fair value hierarchy

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

	June 30, 2016
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	10.1	$	12.4	$	—	$	22.5
FTRs	—		—		13.4		13.4
Petroleum products contracts	0.4		—		—		0.4
Coal contracts	—		1.3		—		1.3
Total derivative assets	$	10.5	$	13.7	$	13.4	$	37.6
Investments held in rabbi trust	$	42.8	$	—	$	—	$	42.8
Derivative liabilities
Natural gas contracts	$	0.5	$	5.4	$	—	$	5.9
Petroleum products contracts	1.4		—		—		1.4
Coal contracts	—		12.6		—		12.6
Total derivative liabilities	$	1.9	$	18.0	$	—	$	19.9

	December 31, 2015
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	1.6	$	1.5	$	—	$	3.1
FTRs	—		—		3.6		3.6
Petroleum products contracts	1.2		—		—		1.2
Coal contracts	—		2.0		—		2.0
Total derivative assets	$	2.8	$	3.5	$	3.6	$	9.9
Investments held in rabbi trust	$	39.8	$	—	$	—	$	39.8
Derivative liabilities
Natural gas contracts	$	16.5	$	25.3	$	—	$	41.8
Petroleum products contracts	4.9		—		—		4.9
Coal contracts	—		12.3		—		12.3
Total derivative liabilities	$	21.4	$	37.6	$	—	$	59.0

Reconciliation of changes in fair value of items categorized as level 3 measurements

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

	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2016			2015			2016			2015
Balance at the beginning of the period	$	1.1		$	3.3		$	3.6		$	7.0
Realized and unrealized losses	—			—			(0.2		)	—
Purchases	15.2			3.9			15.2			3.9
Sales	(0.1		)	—			(0.2		)	—
Settlements	(2.8		)	(3.6		)	(5.0		)	(7.3		)
Acquisition of Integrys	—			(1.3		)	—			(1.3		)
Balance at the end of the period	$	13.4		$	2.3		$	13.4		$	2.3

Schedule of carrying value and estimated fair value of financial instruments not recorded at fair value

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

	June 30, 2016				December 31, 2015
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock	$	30.4	$	29.7	$	30.4	$	27.3
Long-term debt, including current portion *	$	8,952.6	$	9,984.8	$	9,221.9	$	9,681.0

* The carrying amount of long-term debt excludes capital lease obligations of $45.3 million and $59.9 million at June 30, 2016, and

December 31, 2015, respectively.

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Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative assets and derivative liabilities

The following table shows our derivative assets and derivative liabilities:

	June 30, 2016				December 31, 2015
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	19.3	$	5.9	$	2.6	$	38.5
Petroleum products contracts	0.3		1.4		0.9		3.8
FTRs	13.4		—		3.6		—
Coal contracts	1.3		9.8		1.7		6.7
Total other current *	$	34.3	$	17.1	$	8.8	$	49.0
Other long-term
Natural gas contracts	$	3.2	$	—	$	0.5	$	3.3
Petroleum products contracts	0.1		—		0.3		1.1
Coal contracts	—		2.8		0.3		5.6
Total other long-term *	$	3.3	$	2.8	$	1.1	$	10.0
Total	$	37.6	$	19.9	$	9.9	$	59.0

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

Estimated notional volumes and gain (losses)

Our estimated notional sales volumes and gains (losses) were as follows:

	Three Months Ended June 30, 2016				Three Months Ended June 30, 2015
(in millions)	Volume	Gains (Losses)			Volume	Gains (Losses)
Natural gas contracts	32.7 Dth	$	(20.0	)	10.0 Dth	$	(5.9	)
Petroleum products contracts	3.6 gallons	(1.0		)	0.8 gallons	0.1
FTRs	7.4 MWh	1.6			5.9 MWh	0.8
Total		$	(19.4	)		$	(5.0	)
	Six Months Ended June 30, 2016				Six Months Ended June 30, 2015
(in millions)	Volume	Gains (Losses)			Volume	Gains (Losses)
Natural gas contracts	82.8 Dth	$	(53.5	)	23.3 Dth	$	(13.0	)
Petroleum products contracts	6.6 gallons	(2.1		)	1.7 gallons	—
FTRs	15.0 MWh	4.6			12.1 MWh	2.9
Total		$	(51.0	)		$	(10.1	)

Offsetting assets and liabilities

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

	June 30, 2016						December 31, 2015
(in millions)	Derivative Assets			Derivative Liabilities			Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	37.6		$	19.9		$	9.9		$	59.0
Gross amount not offset on the balance sheet *	(4.2		)	(4.2		)	(3.0		)	(22.5		)
Net amount	$	33.4		$	15.7		$	6.9		$	36.5

* Includes cash collateral posted of $19.5 million as of December 31, 2015. There was no cash collateral included at June 30, 2016.

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Guarantees (Tables)

6 Months Ended

Jun. 30, 2016

Guarantees [Abstract]

Schedule of outstanding guarantees

The following table shows our outstanding guarantees:

	Total Amounts Committed at		Expiration
(in millions)	June 30, 2016		Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees
Guarantees supporting commodity transactions of subsidiaries (1)	$	147.1	$	68.1	$	5.0	$	74.0
Standby letters of credit (2)	36.4		36.0		0.2		0.2
Surety bonds (3)	11.2		11.2		—		—
Other guarantees (4)	38.5		0.7		6.8		31.0
Total guarantees	$	233.2	$	116.0	$	12.0	$	105.2

⁽¹⁾  Consists of (a) $5.0 million and $10.0 million to support the business operations of WBS and PDL, respectively; and (b) $99.3 million and $32.8 million related to natural gas supply at MERC and MGU, respectively. These amounts 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 are not reflected on our balance sheets.

⁽³⁾  Primarily for workers compensation self-insurance programs and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets.

⁽⁴⁾  Consists of (a) $19.1 million to support PDL's future payment obligations related to its distributed solar generation projects, of which $6.6 million is covered by a reciprocal guarantee from a third party that is not reflected on our balance sheets; (b) $10.0 million related to the sale of a nonregulated retail marketing business previously owned by Integrys, of which an insignificant liability was recorded; and (c) $9.4 million related to other indemnifications, of which a liability of $8.8 million related to workers compensation coverage was recorded.

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Employee Benefits (Tables)

6 Months Ended

Jun. 30, 2016

Compensation and Retirement Disclosure [Abstract]

Schedule of the components of net periodic benefit cost

The following tables show the components of net periodic pension and OPEB costs for our benefit plans. Our pension and OPEB costs for the three and six months ended June 30, 2016, include costs attributable to the Integrys pension and OPEB plans. The terms and conditions of the legacy company plans have not changed materially since the acquisition.

	Pension Costs
	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2016			2015			2016			2015
Service cost	$	10.7		$	3.9		$	22.0		$	7.8
Interest cost	33.0			15.1			66.2			30.3
Expected return on plan assets	(49.0		)	(25.6		)	(98.0		)	(51.4		)
Loss on plan settlement	14.1			—			14.1			—
Amortization of prior service cost	0.8			0.5			1.7			1.0
Amortization of net actuarial loss	20.2			11.4			40.7			23.0
Net periodic benefit cost	$	29.8		$	5.3		$	46.7		$	10.7

	OPEB Costs
	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2016			2015			2016			2015
Service cost	$	6.4		$	2.1		$	13.1		$	4.7
Interest cost	9.3			3.9			18.5			8.1
Expected return on plan assets	(13.3		)	(5.9		)	(26.4		)	(11.8		)
Amortization of prior service credit	(2.4		)	(0.3		)	(4.7		)	(0.6		)
Amortization of net actuarial loss	1.9			0.5			4.2			1.0
Net periodic benefit cost	$	1.9		$	0.3		$	4.7		$	1.4

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Goodwill (Tables)

6 Months Ended

Jun. 30, 2016

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of changes to our goodwill balances by segment

The following table shows changes to our goodwill balances by segment during the six months ended June 30, 2016:

(in millions)	Wisconsin				Illinois			Other States			Total
Goodwill balance as of January 1, 2016	$	2,109.5			$	731.2		$	182.8		$	3,023.5
Adjustment to Integrys purchase price allocation	(5.2		)		27.5			0.4			22.7
Goodwill balance as of June 30, 2016 (1)	$	2,104.3		(2)	$	758.7	(3)	$	183.2	(3)	$	3,046.2

⁽¹⁾  We had no accumulated impairment losses related to our goodwill as of June 30, 2016.

⁽²⁾  Of this amount, $1,662.4 million relates to the acquisition of Integrys.

⁽³⁾  Total amount relates to the acquisition of Integrys.

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Investment in American Transmission Company (Tables) - ATC

6 Months Ended

Jun. 30, 2016

Investment in ATC

Schedule of changes to our investment in ATC

The following table shows changes to our investment in ATC:

	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2016				2015		2016				2015
Balance at beginning of period	$	1,422.5			$	431.1	$	1,380.9		(1)	$	424.1
Add: Earnings from equity method investment	30.9				14.3		69.4				30.4
Add: Capital contributions	3.1				1.2		12.1				2.5
Add: Acquisition of Integrys's investment in ATC	(1.0		)	(2)	552.0		(1.0		)	(2)	552.0
Add: Adjustment to equity method goodwill	1.1				—		10.4				—
Less: Distributions received	31.6				10.8		46.7				21.2
Less: Other	—				—		0.1				—
Balance at end of period	$	1,425.0			$	987.8	$	1,425.0			$	987.8

⁽¹⁾  Equity method goodwill of $395.8 million from the acquisition of Integrys was recorded in the fourth quarter of 2015.

⁽²⁾  Amount reflects an adjustment to the allocation of the purchase price made in the second quarter of 2016.

Schedule of significant transactions with ATC

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

	Three Months Ended June 30				Six Months Ended June 30
(in millions)	2016		2015		2016		2015
Charges to ATC for services and construction	$	4.3	$	2.5	$	8.4	$	5.0
Charges from ATC for network transmission services	91.1		59.6		182.1		119.2

Schedule of receivables and payables with ATC

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

(in millions)	June 30, 2016		December 31, 2015
Accounts receivable
Services provided to ATC	$	1.4	$	1.0
Accounts payable
Services received from ATC	30.3		28.3

Schedule of summarized income statement data for ATC

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

	Three Months Ended June 30				Six Months Ended June 30
(in millions)	2016		2015		2016		2015
Income statement data
Revenues	$	154.3	$	165.1	$	318.5	$	317.5
Operating expenses	81.7		80.3		160.8		160.3
Other expense	23.7		24.2		47.7		48.6
Net income	$	48.9	$	60.6	$	110.0	$	108.6

Schedule of summarized balance sheet data for ATC

(in millions)	June 30, 2016		December 31, 2015
Balance sheet data
Current assets	$	83.9	$	80.5
Noncurrent assets	4,104.6		3,948.3
Total assets	$	4,188.5	$	4,028.8
Current liabilities	$	382.5	$	330.3
Long-term debt	1,791.0		1,790.7
Other noncurrent liabilities	293.8		245.0
Shareholders' equity	1,721.2		1,662.8
Total liabilities and shareholders' equity	$	4,188.5	$	4,028.8

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Segment Information (Tables)

6 Months Ended

Jun. 30, 2016

Segment Reporting [Abstract]

Financial information of reportable segments

The following tables show summarized financial information concerning our reportable segments for the three and six months ended June 30, 2016 and 2015:

	Regulated Operations
(in millions)	Wisconsin		Illinois		Other States		Electric Transmission		Total Regulated Operations		We Power		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Three Months Ended
June 30, 2016
External revenues	$	1,304.5	$	222.8	$	64.0	$	—	$	1,591.3	$	6.3	$	4.4		$	—		$	1,602.0
Intersegment revenues	0.2		—		—		—		0.2		107.6		—			(107.8		)	—
Other operation and maintenance	487.8		116.2		29.4		—		633.4		2.7		(6.3		)	(107.8		)	522.0
Depreciation and amortization	122.7		33.1		5.2		—		161.0		17.0		12.0			—			190.0
Operating income (loss)	214.7		22.6		2.3		—		239.6		94.1		(1.6		)	—			332.1
Equity in earnings of transmission affiliate	—		—		—		30.9		30.9		—		—			—			30.9
Interest expense	44.4		9.8		2.1		—		56.3		15.6		30.2			(2.0		)	100.1

	Regulated Operations
(in millions)	Wisconsin		Illinois		Other States		Electric Transmission		Total Regulated Operations		We Power		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Three Months Ended
June 30, 2015
External revenues	$	978.5	$	—	$	—	$	—	$	978.5	$	9.6	$	3.1		$	—		$	991.2
Intersegment revenues	1.4		—		—		—		1.4		103.1		—			(104.5		)	—
Other operation and maintenance	368.3		—		—		—		368.3		2.7		70.1			(104.1		)	337.0
Depreciation and amortization	86.3		—		—		—		86.3		16.9		0.3			—			103.5
Operating income (loss)	140.4		—		—		—		140.4		93.2		(67.8		)	—			165.8
Equity in earnings of transmission affiliate	—		—		—		14.3		14.3		—		—			—			14.3
Interest expense	32.1		—		—		—		32.1		15.9		14.0			(0.2		)	61.8

	Regulated Operations
(in millions)	Wisconsin		Illinois		Other States		Electric Transmission		Total Regulated Operations		We Power		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Six Months Ended
June 30, 2016
External revenues	$	2,884.3	$	671.3	$	212.4	$	—	$	3,768.0	$	12.5	$	16.3		$	—		$	3,796.8
Intersegment revenues	0.3		—		—		—		0.3		212.1		—			(212.4		)	—
Other operation and maintenance	979.1		234.1		59.4		—		1,272.6		3.1		(9.8		)	(212.4		)	1,053.5
Depreciation and amortization	245.6		65.9		10.3		—		321.8		34.0		22.1			—			377.9
Operating income (loss)	542.2		159.6		34.1		—		735.9		187.4		(1.9		)	—			921.4
Equity in earnings of transmission affiliate	—		—		—		69.4		69.4		—		—			—			69.4
Interest expense	88.9		19.5		4.6		—		113.0		31.2		61.5			(4.7		)	201.0

	Regulated Operations
(in millions)	Wisconsin		Illinois		Other States		Electric Transmission		Total Regulated Operations		We Power		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Six Months Ended
June 30, 2015
External revenues	$	2,355.0	$	—	$	—	$	—	$	2,355.0	$	20.7	$	3.4		$	—		$	2,379.1
Intersegment revenues	1.8		—		—		—		1.8		201.7		—			(203.5		)	—
Other operation and maintenance	737.4		—		—		—		737.4		3.1		80.2			(203.0		)	617.7
Depreciation and amortization	171.7		—		—		—		171.7		33.7		0.7			—			206.1
Operating income (loss)	416.9		—		—		—		416.9		185.7		(78.0		)	—			524.6
Equity in earnings of transmission affiliate	—		—		—		30.4		30.4		—		—			—			30.4
Interest expense	63.5		—		—		—		63.5		31.8		26.2			(0.3		)	121.2

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Commitments and Contingencies (Tables)

6 Months Ended

Jun. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Schedule of regulatory assets and reserves related to manufactured gas plant sites

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

(in millions)	June 30, 2016		December 31, 2015
Regulatory assets	$	686.6	$	697.0
Reserves for future remediation	617.7		628.0

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Supplemental Cash Flow Information (Tables)

6 Months Ended

Jun. 30, 2016

Supplemental Cash Flow Information [Abstract]

Schedule of supplemental cash flow information

	Six Months Ended June 30
(in millions)	2016			2015
Cash (paid) for interest, net of amount capitalized	$	(209.2	)	$	(116.3	)
Cash received (paid) for income taxes, net of (payments) refunds	7.4			(3.0		)
Significant non-cash transactions
Accounts payable related to construction costs	114.0			3.5
Amortization of deferred revenue	12.3			20.7

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General Information - General (Details) - customer customer in Millions	Jun. 30, 2016	Jun. 29, 2015
Electric
Product information [Line Items]
Number Of Customers	1.6
Natural gas
Product information [Line Items]
Number Of Customers	2.8
ATC
Product information [Line Items]
Equity method investment, ownership interest (as a percent)	60.00%	26.20%

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General Information - Reclassifications (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2015
Income Statement Reclassification
Item Effected [Line Items]
Prior Period Income Statement Reclassification Treasury Grant	$ 2.2	$ 4.7
Cash Flow Statement Reclassification
Item Effected [Line Items]
Prior Period Cash Flow Statement Reclassification Depreciation and Amortization		1.7
Prior Period Cash Flow Statement Reclassification Other Operating Activities		6.1
Prior period cash flow statment reclassification other investing activities		$ 11.5

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Acquisition - General (Details)	Jun. 29, 2015
Business Combinations [Abstract]
Percentage of Integrys common shares acquired	100.00%

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Acquisition - Purchase Price Allocation (Details) $ in Millions	Jun. 29, 2015 USD ($)
Business Combinations [Abstract]
Deferred taxes related to goodwill	$ 0.0
Assets acquired
Current assets	1,060.1
Net property, plant, and equipment	7,107.4
Investments	1,072.0
Goodwill	2,604.3
Deferred charges and other assets, excluding goodwill	1,758.5
Liabilities assumed
Current liabilities, including current maturities of long-term debt	(1,320.7)
Deferred credits and other liabilities	(3,703.8)
Long-term debt	(2,943.6)
Preferred stock of subsidiary	(51.1)
Total purchase price	$ 5,583.1

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Acquisition - Pro Forma Financial Information (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2015
Business Combinations [Abstract]
Operating Revenues	$ 1,629.2	$ 4,180.1
Net Income	$ 159.1	$ 488.7
Earnings per share (Basic)	$ 0.50	$ 1.55
Earnings per share (Diluted)	$ 0.50	$ 1.54

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Acquisition - Impacts (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2015
Business Combinations [Abstract]
Acquisition costs	$ 65.0	$ 73.7
Net loss attributable to Integrys	$ 26.6	$ 26.6

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Dispositions (Details) - USD ($) $ in Millions	3 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015
Wisconsin | WE
Dispositions
After-tax gain (loss) on sale	$ 6.5
Wisconsin | WE | Other operation and maintenance
Dispositions
Pre-tax gain (loss) on sale	10.9
Corporate and Other | Wisvest
Dispositions
After-tax gain (loss) on sale	11.8
Corporate and Other | Wisvest | Other income, net
Dispositions
Pre-tax gain (loss) on sale	$ 19.6
Corporate and Other | ITF
Dispositions
Pre-tax gain (loss) on sale		$ 0.0
Assets and liabilities included in held for sale
Property, plant, and equipment			$ 37.2
Accounts receivable and unbilled revenues			34.9
Materials, supplies, and inventories			18.4
Other current assets			2.6
Other long-term assets			3.7
Total assets			96.8
Accounts payable			12.9
Accrued payroll and benefits			2.4
Other current liabilities			4.5
Pension and OPEB obligations			1.2
Other long-term liabilities			0.6
Total liabilities			$ 21.6

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Common Equity - Share-Based Compensation Plans (Details)	6 Months Ended
	Jun. 30, 2016 $ / shares shares
Stock options
Stock-based Compensation Plans
Stock options granted | shares	794,764
Stock options granted, weighted average exercise price (in dollars per share) | $ / shares	$ 52.15
Stock options granted, weighted-average grant date fair value (in dollars per share) | $ / shares	$ 5.14
Restricted shares
Stock-based Compensation Plans
Awards granted, other than stock options | shares	146,941
Weighted average grant date fair value, awards other than stock options (in dollars per share) | $ / shares	$ 53.69
Performance units
Stock-based Compensation Plans
Awards granted, other than stock options | shares	297,397

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Short-term Debt and Lines of Credit - Short-term Borrowings (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Short-term borrowings
Commercial Paper	$ 927.8	$ 1,095.0
Commercial paper
Short-term borrowings
Weighted-average interest rate on amounts outstanding	0.66%	0.68%
Average amounts outstanding during the period	$ 903.5
Weighted-average interest rate during the period	0.61%

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Short-term Debt and Lines of Credit - Revolving Credit Facilities (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Short-term credit capacity	$ 2,500.0
Letters of credit issued inside credit facilities	26.0
Commercial Paper	927.8	$ 1,095.0
Available capacity under existing agreements	1,546.2
WEC Energy Group | Credit facility maturing December 2020
Line of Credit Facility [Line Items]
Short-term credit capacity	1,050.0
Wisconsin Electric | Credit facility maturing December 2020
Line of Credit Facility [Line Items]
Short-term credit capacity	500.0
WPS | Credit facility maturing December 2020
Line of Credit Facility [Line Items]
Short-term credit capacity	250.0
Wisconsin Gas | Credit facility maturing December 2020
Line of Credit Facility [Line Items]
Short-term credit capacity	350.0
PGL | Credit facility maturing December 2020
Line of Credit Facility [Line Items]
Short-term credit capacity	$ 350.0

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Long Term Debt (Details) - USD ($) $ in Millions	1 Months Ended		6 Months Ended
	Jun. 30, 2016	Feb. 29, 2016	Jun. 30, 2016	Jun. 01, 2016	Feb. 01, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Common Stock, Value, Issued	$ 3.2		$ 3.2			$ 3.2
Integrys
Debt Instrument [Line Items]
Common Stock, Value, Issued					$ 66.4
Integrys | Integrys unsecured Senior Notes 8 Percent, Due 2016
Debt Instrument [Line Items]
Retirement of long-term debt	50.0
Interest rate on long-term debt				8.00%
Integrys | TEG Junior Subordinated Notes, 6.11% due 2066
Debt Instrument [Line Items]
Retirement of long-term debt		$ 154.9
Interest rate on long-term debt					6.11%
Debt Instrument, Repurchase Amount					$ 128.6
Long-term Debt, Gross	114.9		$ 114.9
Debt Instrument, Basis Spread on Variable Rate			2.12%
PGL | PGL Fixed First and Refunding Mortgage RR Series 4.3 Percent Bonds, Due 2035
Debt Instrument [Line Items]
Retirement of long-term debt	$ 50.0
Interest rate on long-term debt				4.30%

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Materials, Supplies, and Inventories (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Inventory Disclosure [Abstract]
Materials and supplies	$ 217.3	$ 219.2
Fossil fuel	156.6	183.7
Natural gas in storage	120.6	284.1
Total	494.5	$ 687.0
Temporary LIFO liquidation debit	$ 28.8

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Fair Value Measurements - Assets and liabilities measured on a recurring basis (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Assets
Derivative asset	$ 37.6	$ 9.9
Liabilities
Derivative liability	19.9	59.0
Fair value measurements on a recurring basis
Assets
Derivative asset	37.6	9.9
Investments held in rabbi trust	42.8	39.8
Liabilities
Derivative liability	19.9	59.0
Fair value measurements on a recurring basis | Level 1
Assets
Derivative asset	10.5	2.8
Investments held in rabbi trust	42.8	39.8
Liabilities
Derivative liability	1.9	21.4
Fair value measurements on a recurring basis | Level 2
Assets
Derivative asset	13.7	3.5
Investments held in rabbi trust	0.0	0.0
Liabilities
Derivative liability	18.0	37.6
Fair value measurements on a recurring basis | Level 3
Assets
Derivative asset	13.4	3.6
Investments held in rabbi trust	0.0	0.0
Liabilities
Derivative liability	0.0	0.0
Fair value measurements on a recurring basis | Natural gas contracts
Assets
Derivative asset	22.5	3.1
Liabilities
Derivative liability	5.9	41.8
Fair value measurements on a recurring basis | Natural gas contracts | Level 1
Assets
Derivative asset	10.1	1.6
Liabilities
Derivative liability	0.5	16.5
Fair value measurements on a recurring basis | Natural gas contracts | Level 2
Assets
Derivative asset	12.4	1.5
Liabilities
Derivative liability	5.4	25.3
Fair value measurements on a recurring basis | Natural gas contracts | Level 3
Assets
Derivative asset	0.0	0.0
Liabilities
Derivative liability	0.0	0.0
Fair value measurements on a recurring basis | FTRs
Assets
Derivative asset	13.4	3.6
Fair value measurements on a recurring basis | FTRs | Level 1
Assets
Derivative asset	0.0	0.0
Fair value measurements on a recurring basis | FTRs | Level 2
Assets
Derivative asset	0.0	0.0
Fair value measurements on a recurring basis | FTRs | Level 3
Assets
Derivative asset	13.4	3.6
Fair value measurements on a recurring basis | Petroleum products contracts
Assets
Derivative asset	0.4	1.2
Liabilities
Derivative liability	1.4	4.9
Fair value measurements on a recurring basis | Petroleum products contracts | Level 1
Assets
Derivative asset	0.4	1.2
Liabilities
Derivative liability	1.4	4.9
Fair value measurements on a recurring basis | Petroleum products contracts | Level 2
Assets
Derivative asset	0.0	0.0
Liabilities
Derivative liability	0.0	0.0
Fair value measurements on a recurring basis | Petroleum products contracts | Level 3
Assets
Derivative asset	0.0	0.0
Liabilities
Derivative liability	0.0	0.0
Fair value measurements on a recurring basis | Coal contracts
Assets
Derivative asset	1.3	2.0
Liabilities
Derivative liability	12.6	12.3
Fair value measurements on a recurring basis | Coal contracts | Level 1
Assets
Derivative asset	0.0	0.0
Liabilities
Derivative liability	0.0	0.0
Fair value measurements on a recurring basis | Coal contracts | Level 2
Assets
Derivative asset	1.3	2.0
Liabilities
Derivative liability	12.6	12.3
Fair value measurements on a recurring basis | Coal contracts | Level 3
Assets
Derivative asset	0.0	0.0
Liabilities
Derivative liability	$ 0.0	$ 0.0

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Fair Value Measurements - Level 3 Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Balance at the beginning of the period	$ 1.1	$ 3.3	$ 3.6	$ 7.0
Realized and unrealized losses	0.0	0.0	(0.2)	0.0
Purchases	15.2	3.9	15.2	3.9
Sales	(0.1)	0.0	0.2	0.0
Settlements	(2.8)	(3.6)	(5.0)	(7.3)
Acquisition of Integrys	0.0	(1.3)	0.0	(1.3)
Balance at the end of period	13.4	2.3	13.4	2.3
Unrealized gains and losses on level 3 derivatives included in earnings	$ 0.0	$ 0.0	$ 0.0	$ 0.0

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Fair Value Measurements - Financial Instruments (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Financial Instruments
Preferred stock	$ 30.4	$ 30.4
Carrying Amount
Financial Instruments
Preferred stock	30.4	30.4
Long-term debt, including current portion	8,952.6	9,221.9
Capital lease obligations	45.3	59.9
Fair Value
Financial Instruments
Preferred stock	29.7	27.3
Long-term debt, including current portion	$ 9,984.8	$ 9,681.0

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Derivative Instruments - Derivative assets and liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Derivative Asset
Other current derivative assets	$ 34.3	$ 8.8
Other long-term derivative assets	3.3	1.1
Derivative asset	37.6	9.9
Derivative Liability
Other current derivative liabilities	17.1	49.0
Other long-term derivative liabilities	2.8	10.0
Derivative liability	19.9	59.0
Natural gas contracts
Derivative Asset
Other current derivative assets	19.3	2.6
Other long-term derivative assets	3.2	0.5
Derivative Liability
Other current derivative liabilities	5.9	38.5
Other long-term derivative liabilities	0.0	3.3
Petroleum products contracts
Derivative Asset
Other current derivative assets	0.3	0.9
Other long-term derivative assets	0.1	0.3
Derivative Liability
Other current derivative liabilities	1.4	3.8
Other long-term derivative liabilities	0.0	1.1
FTRs
Derivative Asset
Other current derivative assets	13.4	3.6
Derivative Liability
Other current derivative liabilities	0.0	0.0
Coal contracts
Derivative Asset
Other current derivative assets	1.3	1.7
Other long-term derivative assets	0.0	0.3
Derivative Liability
Other current derivative liabilities	9.8	6.7
Other long-term derivative liabilities	$ 2.8	$ 5.6

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Derivative Instruments - Gains (Losses) and Notional Volumes (Details) gal in Millions, MWh in Millions, MMBTU in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016 USD ($) MMBTU MWh gal	Jun. 30, 2015 USD ($) MMBTU MWh gal	Jun. 30, 2016 USD ($) MMBTU MWh gal	Jun. 30, 2015 USD ($) MMBTU MWh gal
Realized Gain (Loss) on Derivatives, Net
Gains (Losses)	$ (19.4)	$ (5.0)	$ (51.0)	$ (10.1)
Natural gas contracts
Realized Gain (Loss) on Derivatives, Net
Gains (Losses)	$ (20.0)	$ (5.9)	$ (53.5)	$ (13.0)
Notional Volumes
Notional sales volumes (Dth or MWh) | MMBTU	32.7	10.0	82.8	23.3
Petroleum products contracts
Realized Gain (Loss) on Derivatives, Net
Gains (Losses)	$ (1.0)	$ 0.1	$ (2.1)	$ 0.0
Notional Volumes
Notional sales volumes (gallons) | gal	3.6	0.8	6.6	1.7
FTRs
Realized Gain (Loss) on Derivatives, Net
Gains (Losses)	$ 1.6	$ 0.8	$ 4.6	$ 2.9
Notional Volumes
Notional sales volumes (Dth or MWh) | MWh	7.4	5.9	15.0	12.1

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Derivative Instruments - Balance Sheet Offseting (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Cash collateral
Cash collateral in margin account	$ 22.4	$ 42.3
Offsetting Derivative Assets
Gross amount recognized on the balance sheet	37.6	9.9
Gross amount not offset on the balance sheet	(4.2)	(3.0)
Net amount	33.4	6.9
Offsetting Derivative Liabilities
Gross amount recognized on the balance sheet	19.9	59.0
Gross amount not offset on the balance sheet	(4.2)	(22.5)
Net amount	15.7	36.5
Cash collateral posted	0.0	19.5
Credit Risk Related Contingent Features
Aggregate fair value of derivative instruments with credit risk-related contingent features that were in a liability position	3.1	23.8
Collateral that would have been required	$ 1.3	$ 18.0

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Guarantees (Details) $ in Millions	Jun. 30, 2016 USD ($)
Guarantees
Total guarantees	$ 233.2
Guarantees expiring in less than 1 year	116.0
Guarantees expiring within 1 to 3 years	12.0
Guarantees with expiration over 3 years	105.2
Guarantees supporting commodity transactions of subsidiaries
Guarantees
Total guarantees	147.1
Guarantees expiring in less than 1 year	68.1
Guarantees expiring within 1 to 3 years	5.0
Guarantees with expiration over 3 years	74.0
Guarantees supporting commodity transactions of subsidiaries | WBS
Guarantees
Total guarantees	5.0
Guarantees supporting commodity transactions of subsidiaries | PDL
Guarantees
Total guarantees	10.0
Guarantees supporting commodity transactions of subsidiaries | MERC
Guarantees
Total guarantees	99.3
Guarantees supporting commodity transactions of subsidiaries | MGU
Guarantees
Total guarantees	32.8
Standby letters of credit
Guarantees
Total guarantees	36.4
Guarantees expiring in less than 1 year	36.0
Guarantees expiring within 1 to 3 years	0.2
Guarantees with expiration over 3 years	0.2
Surety bonds
Guarantees
Total guarantees	11.2
Guarantees expiring in less than 1 year	11.2
Guarantees expiring within 1 to 3 years	0.0
Guarantees with expiration over 3 years	0.0
Other guarantees
Guarantees
Total guarantees	38.5
Guarantees expiring in less than 1 year	0.7
Guarantees expiring within 1 to 3 years	6.8
Guarantees with expiration over 3 years	31.0
Other guarantees | PDL
Guarantees
Total guarantees	19.1
Other guarantees | Integrys
Guarantees
Total guarantees	10.0
Reciprocal guarantee | PDL
Guarantees
Total guarantees	6.6
Other indemnifications
Guarantees
Total guarantees	9.4
Liability related to workers compensation coverage	$ 8.8

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Employee Benefits (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Components of net periodic benefit cost
Contributions and payments related to pension and OPEB plans			$ 19.5	$ 106.1
Pension Costs
Components of net periodic benefit cost
Service cost	$ 10.7	$ 3.9	22.0	7.8
Interest cost	33.0	15.1	66.2	30.3
Expected return on plan assets	(49.0)	(25.6)	(98.0)	(51.4)
Loss on plan settlement	14.1	0.0	14.1	0.0
Amortization of prior service cost (credit)	0.8	0.5	1.7	1.0
Amortization of net actuarial loss	20.2	11.4	40.7	23.0
Net periodic benefit cost	29.8	5.3	46.7	10.7
Contributions and payments related to pension and OPEB plans			17.0
Estimated future employer contributions for the remainder of the year			6.0
Other Postretirement Benefit Costs
Components of net periodic benefit cost
Service cost	6.4	2.1	13.1	4.7
Interest cost	9.3	3.9	18.5	8.1
Expected return on plan assets	(13.3)	(5.9)	(26.4)	(11.8)
Amortization of prior service cost (credit)	(2.4)	(0.3)	(4.7)	(0.6)
Amortization of net actuarial loss	1.9	0.5	4.2	1.0
Net periodic benefit cost	$ 1.9	$ 0.3	4.7	$ 1.4
Contributions and payments related to pension and OPEB plans			2.5
Estimated future employer contributions for the remainder of the year			$ 15.2

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Goodwill (Details) $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($)
Goodwill
Accumulated impairment losses	$ 0.0
Changes to our goodwill balances by segment
Goodwill balance as of January 1, 2016	3,023.5
Adjustment to Integrys purchase price allocation	22.7
Goodwill balance as of June 30, 2016	3,046.2
Wisconsin
Changes to our goodwill balances by segment
Goodwill balance as of January 1, 2016	2,109.5
Adjustment to Integrys purchase price allocation	(5.2)
Goodwill balance as of June 30, 2016	2,104.3
Wisconsin | Integrys
Changes to our goodwill balances by segment
Goodwill balance as of June 30, 2016	1,662.4
Illinois
Changes to our goodwill balances by segment
Goodwill balance as of January 1, 2016	731.2
Adjustment to Integrys purchase price allocation	27.5
Goodwill balance as of June 30, 2016	758.7
Other States
Changes to our goodwill balances by segment
Goodwill balance as of January 1, 2016	182.8
Adjustment to Integrys purchase price allocation	0.4
Goodwill balance as of June 30, 2016	$ 183.2

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Investment in American Transmission Company - Changes to Investment (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015	Jun. 29, 2015
Changes to investment in ATC
Investment in ATC, balance at beginning of period			$ 1,380.9
Add: Earnings from equity method investment	$ 30.9	$ 14.3	69.4	$ 30.4
Investment in ATC, balance at end of period	$ 1,425.0		$ 1,425.0
ATC
Investment in ATC
Equity method goodwill from the acquisition of Integrys					$ 395.8
Ownership interest in ATC (as a percent)	60.00%		60.00%			26.20%
Changes to investment in ATC
Investment in ATC, balance at beginning of period	$ 1,422.5	431.1	$ 1,380.9	424.1
Add: Earnings from equity method investment	30.9	14.3	69.4	30.4
Add: Capital contributions	3.1	1.2	12.1	2.5
Add: Acquisition of Integrys's investment in ATC	(1.0)	552.0	(1.0)	552.0
Add: Adjustment to equity method goodwill	1.1	0.0	10.4	0.0
Less: Distributions received	31.6	10.8	46.7	21.2
Less: Other	0.0	0.0	0.1	0.0
Investment in ATC, balance at end of period	$ 1,425.0	$ 987.8	$ 1,425.0	$ 987.8

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Investment in American Transmission Company - Related Party Transactions (Details) - ATC - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Investment in ATC
Charges to ATC for services and construction	$ 4.3	$ 2.5	$ 8.4	$ 5.0
Charges from ATC for network transmission services	91.1	$ 59.6	182.1	$ 119.2
Accounts receivable for services provided to ATC	1.4		1.4		$ 1.0
Accounts payable for services received from ATC	$ 30.3		$ 30.3		$ 28.3

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Investment in American Transmission Company - Summarized Financial Data (Details) - ATC - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Income statement data
Revenues	$ 154.3	$ 165.1	$ 318.5	$ 317.5
Operating expenses	81.7	80.3	160.8	160.3
Other expense	23.7	24.2	47.7	48.6
Net income	48.9	$ 60.6	110.0	$ 108.6
Balance sheet data
Current assets	83.9		83.9		$ 80.5
Noncurrent assets	4,104.6		4,104.6		3,948.3
Total assets	4,188.5		4,188.5		4,028.8
Current liabilities	382.5		382.5		330.3
Long-term debt	1,791.0		1,791.0		1,790.7
Other noncurrent liabilities	293.8		293.8		245.0
Shareholders' equity	1,721.2		1,721.2		1,662.8
Total liabilities and shareholders' equity	$ 4,188.5		$ 4,188.5		$ 4,028.8

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Segment Information (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016 USD ($)	Jun. 30, 2015 USD ($)	Jun. 30, 2016 USD ($) segment	Jun. 30, 2015 USD ($)	Jun. 29, 2015
Segment information
Number of reportable segments | segment			6
Revenues	$ 1,602.0	$ 991.2	$ 3,796.8	$ 2,379.1
Other operation and maintenance	522.0	337.0	1,053.5	617.7
Depreciation and amortization	190.0	103.5	377.9	206.1
Operating income (loss)	332.1	165.8	921.4	524.6
Equity in earnings of transmission affiliate	30.9	14.3	69.4	30.4
Interest expense	100.1	61.8	201.0	121.2
Intersegment revenues
Segment information
Revenues	0.0	0.0	0.0	0.0
We Power
Segment information
Revenues	6.3	9.6	12.5	20.7
Other operation and maintenance	2.7	2.7	3.1	3.1
Depreciation and amortization	17.0	16.9	34.0	33.7
Operating income (loss)	94.1	93.2	187.4	185.7
Equity in earnings of transmission affiliate	0.0	0.0	0.0	0.0
Interest expense	15.6	15.9	31.2	31.8
We Power | Intersegment revenues
Segment information
Revenues	107.6	103.1	212.1	201.7
Corporate and other
Segment information
Revenues	4.4	3.1	16.3	3.4
Other operation and maintenance	(6.3)	70.1	(9.8)	80.2
Depreciation and amortization	12.0	0.3	22.1	0.7
Operating income (loss)	(1.6)	(67.8)	(1.9)	(78.0)
Equity in earnings of transmission affiliate	0.0	0.0	0.0	0.0
Interest expense	30.2	14.0	61.5	26.2
Corporate and other | Intersegment revenues
Segment information
Revenues	0.0	0.0	0.0	0.0
Reconciling eliminations
Segment information
Revenues	0.0	0.0	0.0	0.0
Other operation and maintenance	(107.8)	(104.1)	(212.4)	(203.0)
Depreciation and amortization	0.0	0.0	0.0	0.0
Operating income (loss)	0.0	0.0	0.0	0.0
Equity in earnings of transmission affiliate	0.0	0.0	0.0	0.0
Interest expense	(2.0)	(0.2)	(4.7)	(0.3)
Reconciling eliminations | Intersegment revenues
Segment information
Revenues	(107.8)	(104.5)	(212.4)	(203.5)
Regulated operations
Segment information
Revenues	1,591.3	978.5	3,768.0	2,355.0
Other operation and maintenance	633.4	368.3	1,272.6	737.4
Depreciation and amortization	161.0	86.3	321.8	171.7
Operating income (loss)	239.6	140.4	735.9	416.9
Equity in earnings of transmission affiliate	30.9	14.3	69.4	30.4
Interest expense	56.3	32.1	113.0	63.5
Regulated operations | Intersegment revenues
Segment information
Revenues	0.2	1.4	0.3	1.8
Regulated operations | Wisconsin
Segment information
Revenues	1,304.5	978.5	2,884.3	2,355.0
Other operation and maintenance	487.8	368.3	979.1	737.4
Depreciation and amortization	122.7	86.3	245.6	171.7
Operating income (loss)	214.7	140.4	542.2	416.9
Equity in earnings of transmission affiliate	0.0	0.0	0.0	0.0
Interest expense	44.4	32.1	88.9	63.5
Regulated operations | Wisconsin | Intersegment revenues
Segment information
Revenues	0.2	1.4	0.3	1.8
Regulated operations | Illinois
Segment information
Revenues	222.8	0.0	671.3	0.0
Other operation and maintenance	116.2	0.0	234.1	0.0
Depreciation and amortization	33.1	0.0	65.9	0.0
Operating income (loss)	22.6	0.0	159.6	0.0
Equity in earnings of transmission affiliate	0.0	0.0	0.0	0.0
Interest expense	9.8	0.0	19.5	0.0
Regulated operations | Illinois | Intersegment revenues
Segment information
Revenues	0.0	0.0	0.0	0.0
Regulated operations | Other States
Segment information
Revenues	64.0	0.0	212.4	0.0
Other operation and maintenance	29.4	0.0	59.4	0.0
Depreciation and amortization	5.2	0.0	10.3	0.0
Operating income (loss)	2.3	0.0	34.1	0.0
Equity in earnings of transmission affiliate	0.0	0.0	0.0	0.0
Interest expense	2.1	0.0	4.6	0.0
Regulated operations | Other States | Intersegment revenues
Segment information
Revenues	0.0	0.0	0.0	0.0
Regulated operations | Electric transmission
Segment information
Revenues	0.0	0.0	0.0	0.0
Other operation and maintenance	0.0	0.0	0.0	0.0
Depreciation and amortization	0.0	0.0	0.0	0.0
Operating income (loss)	0.0	0.0	0.0	0.0
Equity in earnings of transmission affiliate	30.9	14.3	69.4	30.4
Interest expense	0.0	0.0	0.0	0.0
Regulated operations | Electric transmission | Intersegment revenues
Segment information
Revenues	$ 0.0	0.0	$ 0.0	0.0
ATC
Segment information
Equity method investment, ownership interest (as a percent)	60.00%		60.00%		26.20%
Equity in earnings of transmission affiliate	$ 30.9	$ 14.3	$ 69.4	$ 30.4

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Variable Interest Entities (Details) $ in Millions	3 Months Ended	6 Months Ended
	Mar. 31, 2016 USD ($)	Jun. 30, 2016 USD ($) MW	Jun. 30, 2015 USD ($)	Dec. 31, 2015 USD ($)
Variable interest entities
Equity investment in ATC		$ 1,425.0		$ 1,380.9
ATC
Variable interest entities
Ownership interest in ATC (as a percent)		60.00%
Equity investment in ATC		$ 1,425.0		1,380.9
Accounts payable due to ATC		$ 30.3		$ 28.3
Purchased power agreement
Variable interest entities
Firm capacity from purchased power agreement (in megawatts) | MW		236
Minimum energy requirements over remaining term of purchased power agreement (in megawatts) | MW		0
Remaining term of purchased power agreement (in years)		6 years
Residual guarantee associated with purchased power agreement		$ 0.0
Required payments over remaining term of purchased power agreement		107.9
Total capacity and lease payments		$ 26.9	$ 26.8
Accounting Standards Update 2015-02
Variable interest entities
Changes to disclosures and financial statement presentation	$ 0.0

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Commitments and Contingencies - Unconditional Purchase Obligations (Details) $ in Millions	Jun. 30, 2016 USD ($)
Minimum future commitments for purchase obligations
Purchase obligations	$ 12,345.8

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Commitments and Contingencies - Environmental Matters (Details) $ in Millions	1 Months Ended					6 Months Ended	12 Months Ended
	Jan. 31, 2016	Dec. 31, 2015 USD ($)	Aug. 31, 2014	Apr. 30, 2013	Mar. 31, 2013 USD ($)	Jun. 30, 2016 USD ($)	Dec. 31, 2015 USD ($)	Jun. 01, 2015 USD ($)
Mercury and Other Hazardous Air Pollutants | Electric
Air quality
Percentage of mercury emissions reduction required by Wisconsin and Michigan						90.00%
Mercury and Other Hazardous Air Pollutants | Electric | WE
Air quality
Term of Mercury and Air Toxics Standards compliance extension				1 year
Mercury and Other Hazardous Air Pollutants | Electric | WPS
Air quality
Term of Mercury and Air Toxics Standards compliance extension						1 year
Climate Change | Electric
Air quality
Percentage of nationwide greenhouse gas emissions reduction							32.00%
Interim goal for greenhouse gas emissions reduction (fraction)							0.667
Climate Change | Electric | Wisconsin
Air quality
Percentage of greenhouse gas emissions reduction by state							41.00%
Percentage of greenhouse gas emissions reduction for retirement of a nuclear plant		10.00%
Climate Change | Electric | Michigan
Air quality
Percentage of greenhouse gas emissions reduction by state							39.00%
Clean Water Act Cooling Water Intake Structure Rule | Electric
Water quality
Number of compliance options available to meet standard			7
Steam Electric Effluent Guidelines | Electric
Water quality
Renewal period for facility permits	5 years
Steam Electric Effluent Guidelines | Minimum | Electric
Water quality
Expected cost to achieve required emissions reductions						$ 95.0
Steam Electric Effluent Guidelines | Maximum | Electric
Water quality
Expected cost to achieve required emissions reductions						130.0
Manufactured Gas Plant Remediation | Natural gas
Manufactured gas plant remediation
Regulatory assets recorded for remediation of manufactured gas plant sites		$ 697.0				686.6	$ 697.0
Reserves recorded for remediation of manufactured gas plant sites		$ 628.0				$ 617.7	$ 628.0
Weston and Pulliam Consent Decree | Electric | WPS
WPS consent decree - Weston and Pulliam
Beneficial environmental projects					$ 6.0
Regulatory asset for undepreciated book value of retired plants								$ 11.5
Civil penalty					$ 1.2

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Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
Cash (paid) for interest, net of amount capitalized	$ (209.2)	$ (116.3)
Cash received (paid) for income taxes, net of (payments) refunds	7.4	(3.0)
Accounts payable related to construction costs	114.0	3.5
Amortization of deferred revenue	12.3	$ 20.7
Long-term restricted cash	$ 94.4		$ 118.4

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Regulatory Environment (Details) - USD ($) $ in Millions	1 Months Ended
	May 31, 2016	Mar. 31, 2016	Dec. 31, 2015	Nov. 30, 2015	Sep. 30, 2015
WPS | Public Service Commission of Wisconsin (PSCW) | 2016 Rates
Regulatory environment
Approved return on equity (as a percent)			10.00%
Approved common equity component average (as a percent)			51.00%
WPS | Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Electric rates
Regulatory environment
Approved annual rate increase (decrease)			$ (7.9)
Approved annual rate increase (decrease), percentage			(0.80%)
Percent fuel costs can vary from the rate case approved costs before deferral is required			2.00%
Authorized revenue requirement for ReACT		$ 275.0
WPS | Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Natural gas rates
Regulatory environment
Approved annual rate increase (decrease)			$ (6.2)
Approved annual rate increase (decrease), percentage			(2.10%)
PGL
Regulatory environment
Amount related to settlement agreement	$ 18.5
MERC | Minnesota Public Utilities Commission (MPUC) | 2016 Rates | Natural gas rates
Regulatory environment
Requested annual rate increase (decrease)					$ 14.8
Requested annual rate increase (decrease), percentage					5.50%
Requested return on equity (as a percent)					10.30%
Requested common equity component average (as a percent)					50.32%
Interim rate increase				$ 9.7
Interim rate increase, percentage				3.70%
Interim return on equity (as a percent)				9.35%
Interim common equity component average (as a percent)				50.32%