WEC ENERGY GROUP, INC. (Form: 10-Q, Received: 08/04/2017 10:13:14)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended June 30, 2017



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, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.



	Large accelerated filer [X]		Accelerated filer [ ]
	Non-accelerated filer [ ] (Do not check if a smaller reporting company)
			Smaller reporting company [ ]
			Emerging growth company [ ]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]

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,

315,576,571 shares outstanding at

June 30, 2017

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WEC ENERGY GROUP, INC.

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended June 30, 2017

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	7
	Note 4	Common Equity	8
	Note 5	Short-Term Debt and Lines of Credit	9
	Note 6	Long-Term Debt	10
	Note 7	Materials, Supplies, and Inventories	10
	Note 8	Fair Value Measurements	10
	Note 9	Derivative Instruments	13
	Note 10	Guarantees	14
	Note 11	Employee Benefits	15
	Note 12	Goodwill	15
	Note 13	Investment in American Transmission Company	16
	Note 14	Segment Information	17
	Note 15	Variable Interest Entities	18
	Note 16	Commitments and Contingencies	19
	Note 17	Supplemental Cash Flow Information	23
	Note 18	Regulatory Environment	24
	Note 19	New Accounting Pronouncements	26
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			28
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			52
ITEM 4.	CONTROLS AND PROCEDURES			53
PART II.	OTHER INFORMATION			54
ITEM 1.	LEGAL PROCEEDINGS			54
ITEM 1A.	RISK FACTORS			54
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			55
ITEM 6.	EXHIBITS			56
SIGNATURE				57



06/30/2017 Form 10-Q	i	WEC Energy Group, Inc.

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GLOSSARY OF TERMS AND ABBREVIATIONS

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



Subsidiaries and Affiliates
ATC		American Transmission Company LLC
Bluewater		Bluewater Natural Gas Holding, LLC
Bostco		Bostco LLC
Integrys		Integrys Holding, Inc.
ITF		Integrys Transportation Fuels, LLC
MERC		Minnesota Energy Resources Corporation
MGU		Michigan Gas Utilities Corporation
NSG		North Shore Gas Company
PGL		The Peoples Gas Light and Coke Company
UMERC		Upper Michigan Energy Resources Corporation
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
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
CO ₂		Carbon Dioxide
CSAPR		Cross-State Air Pollution Rule
GHG		Greenhouse Gas
NAAQS		National Ambient Air Quality Standards
NOV		Notice of Violation
NOx		Nitrogen Oxide
SO ₂		Sulfur Dioxide



06/30/2017 Form 10-Q	ii	WEC Energy Group, Inc.

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Measurements
Dth		Dekatherm
MW		Megawatt
MWh		Megawatt-hour

Other Terms and Abbreviations
2006 Junior Notes		Integrys's 2006 Junior Subordinated Notes Due 2066
2007 Junior Notes		WEC Energy Group, Inc.'s 2007 Junior Subordinated Notes Due 2067
ALJ		Administrative Law Judge
CNG		Compressed Natural Gas
D.C. Circuit Court of Appeals		United States Court of Appeals for the District of Columbia Circuit
ERGS		Elm Road Generating Station
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
OCPP		Oak Creek Power Plant
OC 5		Oak Creek Power Plant Unit 5
OC 6		Oak Creek Power Plant Unit 6
OC 7		Oak Creek Power Plant Unit 7
OC 8		Oak Creek Power Plant Unit 8
PIPP		Presque Isle Power Plant
QIP		Qualifying Infrastructure Plant
ROE		Return on Equity
SMP		Gas System Modernization Program
SMRP		System Modernization and Reliability Project
Supreme Court		United States Supreme Court
VAPP		Valley Power Plant



06/30/2017 Form 10-Q	iii	WEC Energy Group, Inc.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of capital projects, sales and customer growth, rate actions and related filings with regulatory authorities, environmental and other regulations and associated compliance costs, legal proceedings, dividend payout ratios, effective tax rate, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, environmental matters, 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, 2016 , 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 the ability to earn a reasonable return on investment, 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;



06/30/2017 Form 10-Q	1	WEC Energy Group, Inc.

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•	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 security 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 timing, costs, and anticipated benefits associated with the remaining integration efforts relating to the Integrys acquisition;


•	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.



06/30/2017 Form 10-Q	2	WEC Energy Group, Inc.

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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)	2017			2016			2017			2016
Operating revenues	$	1,631.5		$	1,602.0		$	3,936.0		$	3,796.8

Operating expenses
Cost of sales	541.8			508.3			1,482.9			1,347.2
Other operation and maintenance	479.8			522.0			981.7			1,053.5
Depreciation and amortization	197.7			190.0			392.3			377.9
Property and revenue taxes	50.0			49.6			99.6			96.8
Total operating expenses	1,269.3			1,269.9			2,956.5			2,875.4

Operating income	362.2			332.1			979.5			921.4

Equity in earnings of transmission affiliate	41.8			30.9			83.7			69.4
Other income, net	13.1			32.4			28.8			65.1
Interest expense	101.9			100.1			206.6			201.0
Other expense	(47.0		)	(36.8		)	(94.1		)	(66.5		)

Income before income taxes	315.2			295.3			885.4			854.9
Income tax expense	115.8			113.6			329.1			326.7
Net income	199.4			181.7			556.3			528.2

Preferred stock dividends of subsidiary	0.3			0.3			0.6			0.6
Net income attributed to common shareholders	$	199.1		$	181.4		$	555.7		$	527.6

Earnings per share
Basic	$	0.63		$	0.57		$	1.76		$	1.67
Diluted	$	0.63		$	0.57		$	1.75		$	1.66

Weighted average common shares outstanding
Basic	315.6			315.6			315.6			315.6
Diluted	317.4			317.0			317.4			317.0

Dividends per share of common stock	$	0.5200		$	0.4950		$	1.0400		$	0.9900

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



06/30/2017 Form 10-Q	3	WEC Energy Group, Inc.

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WEC ENERGY GROUP, INC.



CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)	Three Months Ended						Six Months Ended
	June 30						June 30
(in millions)	2017			2016			2017			2016
Net income	$	199.4		$	181.7		$	556.3		$	528.2

Other comprehensive (loss) income, net of tax
Derivatives accounted for as cash flow hedges
Reclassification of gains to net income, net of tax	(0.3		)	(0.3		)	(0.6		)	(0.6		)

Defined benefit plans
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax	0.1			0.4			0.2			0.4

Other comprehensive (loss) income, net of tax	(0.2		)	0.1			(0.4		)	(0.2		)

Comprehensive income	199.2			181.8			555.9			528.0

Preferred stock dividends of subsidiary	0.3			0.3			0.6			0.6
Comprehensive income attributed to common shareholders	$	198.9		$	181.5		$	555.3		$	527.4

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



06/30/2017 Form 10-Q	4	WEC Energy Group, Inc.

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WEC ENERGY GROUP, INC.



CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts)	June 30, 2017		December 31, 2016
Assets
Current assets
Cash and cash equivalents	$	36.5	$	37.5
Accounts receivable and unbilled revenues, net of reserves of $111.6 and $108.0, respectively	1,004.3		1,241.7
Materials, supplies, and inventories	510.0		587.6
Prepayments	181.6		204.4
Other	47.3		97.5
Current assets	1,779.7		2,168.7

Long-term assets
Property, plant, and equipment, net of accumulated depreciation of $8,433.2 and $8,214.6, respectively	20,524.3		19,915.5
Regulatory assets	3,108.4		3,087.9
Equity investment in transmission affiliate	1,544.0		1,443.9
Goodwill	3,053.5		3,046.2
Other	549.7		461.0
Long-term assets	28,779.9		27,954.5
Total assets	$	30,559.6	$	30,123.2

Liabilities and Equity

Current liabilities
Short-term debt	$	774.8	$	860.2
Current portion of long-term debt	708.4		157.2
Accounts payable	724.1		861.5
Accrued payroll and benefits	140.0		163.8
Other	440.0		388.9
Current liabilities	2,787.3		2,431.6

Long-term liabilities
Long-term debt	8,799.7		9,158.2
Deferred income taxes	5,416.1		5,146.6
Deferred revenue, net	554.6		566.2
Regulatory liabilities	1,574.0		1,563.8
Environmental remediation liabilities	622.6		633.6
Pension and OPEB obligations	451.0		498.6
Other	1,171.1		1,164.4
Long-term liabilities	18,589.1		18,731.4

Commitments and contingencies (Note 16)

Common shareholders' equity
Common stock – $0.01 par value; 325,000,000 shares authorized; 315,576,571 and 315,614,941 shares outstanding, respectively	3.2		3.2
Additional paid in capital	4,290.1		4,309.8
Retained earnings	4,857.0		4,613.9
Accumulated other comprehensive income	2.5		2.9
Common shareholders' equity	9,152.8		8,929.8

Preferred stock of subsidiary	30.4		30.4
Total liabilities and equity	$	30,559.6	$	30,123.2

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



06/30/2017 Form 10-Q	5	WEC Energy Group, Inc.

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WEC ENERGY GROUP, INC.



CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Six Months Ended
	June 30
(in millions)	2017			2016
Operating Activities
Net income	$	556.3		$	528.2
Reconciliation to cash provided by operating activities
Depreciation and amortization	392.3			386.0
Deferred income taxes and investment tax credits, net	274.6			307.1
Contributions and payments related to pension and OPEB plans	(111.5		)	(19.5		)
Equity income in transmission affiliate, net of distributions	(14.5		)	(22.7		)
Change in –
Accounts receivable and unbilled revenues	247.3			130.1
Materials, supplies, and inventories	77.9			193.5
Other current assets	15.6			66.7
Accounts payable	(114.0		)	(112.4		)
Other current liabilities	18.3			(139.0		)
Other, net	(74.3		)	(93.9		)
Net cash provided by operating activities	1,268.0			1,224.1

Investing Activities
Capital expenditures	(790.0		)	(618.7		)
Acquisition of Bluewater	(226.0		)	—
Capital contributions to transmission affiliate	(50.5		)	(12.1		)
Proceeds from the sale of assets and businesses	20.7			161.0
Withdrawal of restricted cash from Rabbi trust for qualifying payments	17.2			22.5
Other, net	4.7			(1.8		)
Net cash used in investing activities	(1,023.9		)	(449.1		)

Financing Activities
Exercise of stock options	15.6			35.0
Purchase of common stock	(39.7		)	(94.2		)
Dividends paid on common stock	(328.3		)	(312.4		)
Issuance of long-term debt	210.0			—
Retirement of long-term debt	(14.6		)	(241.8		)
Change in short-term debt	(85.4		)	(167.2		)
Other, net	(2.7		)	(12.1		)
Net cash used in financing activities	(245.1		)	(792.7		)

Net change in cash and cash equivalents	(1.0		)	(17.7		)
Cash and cash equivalents at beginning of period	37.5			49.8
Cash and cash equivalents at end of period	$	36.5		$	32.1

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



06/30/2017 Form 10-Q	6	WEC Energy Group, Inc.

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WEC ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

June 30, 2017

NOTE 1— GENERAL INFORMATION

WEC Energy Group serves approximately 1.6 million electric customers and 2.8 million natural gas customers, and owns approximately 60% of ATC.

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, 2016 . 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 , 2017 , are not necessarily indicative of expected results for 2017 due to seasonal variations and other factors.

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

NOTE 2— ACQUISITION

Acquisition of Natural Gas Storage Facilities in Michigan

On June 30, 2017, we completed the acquisition of Bluewater for $226.0 million . Bluewater owns natural gas storage facilities in Michigan that will provide approximately one-third of the current storage needs for our Wisconsin natural gas utilities. In addition, we accrued $4.9 million of acquisition related costs.

The table below shows the preliminary allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. Bluewater is included in the non-utility energy segment. See Note 14, Segment Information, for more information .



(in millions)
Current assets	$	2.0
Net property, plant, and equipment	217.6
Goodwill	7.3
Current liabilities	(0.9		)
Total purchase price	$	226.0

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



06/30/2017 Form 10-Q	7	WEC Energy Group, Inc.

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Corporate and Other Segment

Sale of Bostco Real Estate Holdings

In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space. During the first quarter of 2017, we recorded an insignificant gain on the sale, which was 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 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 were 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 was 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 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.

NOTE 4— COMMON EQUITY

Stock-Based Compensation

During the first quarter of 2017, 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⁾		552,215
Restricted shares ⁽²⁾		82,622
Performance units		237,650


⁽¹⁾	Stock options awarded had a weighted-average exercise price of $58.31 and a weighted-average grant date fair value of $7.45 per option.


⁽²⁾	Restricted shares awarded had a weighted-average grant date fair value of $58.10 per share.



06/30/2017 Form 10-Q	8	WEC Energy Group, Inc.

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In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which modifies certain aspects of the accounting for stock-based compensation awards. This ASU became effective for us on January 1, 2017. Under the new guidance, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement on a prospective basis. Prior to January 1, 2017, these amounts were recorded in additional paid in capital on the balance sheet, and the tax benefits could only be recognized to the extent they reduced taxes payable. In the first quarter of 2017, we recorded a $15.7 million cumulative-effect adjustment to retained earnings for excess tax benefits that had not been recognized in prior years as they did not reduce taxes payable. The following table shows the changes to our retained earnings for the six months ended June 30, 2017 :



(in millions)	Retained Earnings
Balance at December 31, 2016	$	4,613.9
Net income attributed to common shareholders	555.7
Common stock dividends	(328.3		)
Cumulative effect of adoption of ASU 2016-09	15.7
Balance at June 30, 2017	$	4,857.0

ASU 2016-09 also requires excess tax benefits to be classified as an operating activity on the statement of cash flows. As we have elected to apply this provision on a prospective basis, the prior year amounts will continue to be reflected as a financing activity. As allowed under this ASU, we have also elected to account for forfeitures as they occur, rather than estimating expected forfeitures and recording them over the vesting period.

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 2016 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.

Common Stock Dividends

On July 20, 2017, our Board of Directors declared a quarterly cash dividend of $0.52 per share, payable on September 1, 2017, to stockholders of record on August 14, 2017.

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, 2017			December 31, 2016
Commercial paper
Amount outstanding	$	774.8		$	860.2
Weighted-average interest rate on amounts outstanding	1.42		%	0.96		%

Our average amount of commercial paper borrowings based on daily outstanding balances during the six months ended June 30, 2017 , was $655.5 million with a weighted-average interest rate during the period of 1.09% .



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



(in millions)	Maturity	June 30, 2017
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		$	41.3
Commercial paper outstanding		774.8
Available capacity under existing agreements		$	1,683.9

NOTE 6— LONG-TERM DEBT

Effective May 2017, the $500.0 million of 2007 Junior Notes bear interest at the three-month LIBOR plus 211.25 basis points, and reset quarterly.

In June 2017, MERC issued $120.0 million of senior notes. The senior notes were issued in three tranches: $40.0 million of 3.11% Senior Notes due July 15, 2027; $40.0 million of 3.41% Senior Notes due July 15, 2032; and $40.0 million of 4.01% Senior Notes due July 15, 2047. Net proceeds were used to repay MERC's $78.0 million aggregate long-term debt obligation to its parent, Integrys. Remaining proceeds were used for general corporate purposes, including repayment of short-term debt borrowed from Integrys.

In June 2017, MGU issued $90.0 million of senior notes. The senior notes were issued in three tranches: $30.0 million of 3.11% Senior Notes due July 15, 2027; $30.0 million of 3.41% Senior Notes due July 15, 2032; and $30.0 million of 4.01% Senior Notes due July 15, 2047. Net proceeds were used to repay MGU's $71.0 million aggregate long-term debt obligation to its parent, Integrys. Remaining proceeds were used for general corporate purposes, including repayment of short-term debt borrowed from Integrys.

NOTE 7— MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:



(in millions)	June 30, 2017		December 31, 2016
Natural gas in storage	$	137.8	$	223.1
Materials and supplies	216.3		206.5
Fossil fuel	155.9		158.0
Total	$	510.0	$	587.6

PGL and NSG price natural gas storage injections at the calendar year average of the cost of natural gas supply purchased. Withdrawals from storage are priced using 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. The temporary LIFO liquidation amounts were not significant at June 30, 2017.

Substantially all other natural gas in storage, materials and supplies, and fossil fuel 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:



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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 financial 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 between levels of the fair value hierarchy at their value as of the end of the reporting period.

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



	June 30, 2017
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	1.2	$	3.5	$	—	$	4.7
Petroleum products contracts	0.3		—		—		0.3
FTRs	—		—		11.8		11.8
Coal contracts	—		0.7		—		0.7
Total derivative assets	$	1.5	$	4.2	$	11.8	$	17.5

Investments held in rabbi trust	$	108.6	$	—	$	—	$	108.6

Derivative liabilities
Natural gas contracts	$	2.0	$	2.5	$	—	$	4.5
Petroleum products contracts	0.1		—		—		0.1
Coal contracts	—		3.4		—		3.4
Total derivative liabilities	$	2.1	$	5.9	$	—	$	8.0



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	December 31, 2016
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	10.1	$	24.2	$	—	$	34.3
Petroleum products contracts	0.2		—		—		0.2
FTRs	—		—		5.1		5.1
Coal contracts	—		2.0		—		2.0
Total derivative assets	$	10.3	$	26.2	$	5.1	$	41.6

Investments held in rabbi trust	$	103.9	$	—	$	—	$	103.9

Derivative liabilities
Natural gas contracts	$	0.2	$	0.2	$	—	$	0.4
Petroleum products contracts	0.1		—		—		0.1
Coal contracts	—		1.9		—		1.9
Total derivative liabilities	$	0.3	$	2.1	$	—	$	2.4

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

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)	2017			2016			2017			2016
Balance at the beginning of the period	$	1.7		$	1.1		$	5.1		$	3.6
Realized and unrealized losses	—			—			—			(0.2		)
Purchases	13.8			15.2			13.8			15.2
Sales	—			(0.1		)	—			(0.2		)
Settlements	(3.7		)	(2.8		)	(7.1		)	(5.0		)
Balance at the end of the period	$	11.8		$	13.4		$	11.8		$	13.4

Unrealized gains and losses on Level 3 derivatives are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have no impact on earnings. Realized gains and losses on these instruments flow through cost of sales on the 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, 2017				December 31, 2016
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock	$	30.4	$	30.5	$	30.4	$	28.8
Long-term debt, including current portion *	9,479.8		10,128.3		9,285.8		9,818.2


*	The carrying amount of long-term debt excludes capital lease obligations of $28.3 million and $29.6 million at June 30, 2017 and

December 31, 2016 , respectively.

Due to the short-term nature of cash and cash equivalents, net accounts receivable and unbilled revenues, accounts payable, and short-term debt, 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 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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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.

The following table shows our derivative assets and derivative liabilities:



	June 30, 2017				December 31, 2016
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	4.3	$	4.1	$	31.4	$	0.4
Petroleum products contracts	0.3		0.1		0.2		0.1
FTRs	11.8		—		5.1		—
Coal contracts	0.7		2.3		1.5		1.4
Total other current *	$	17.1	$	6.5	$	38.2	$	1.9

Other long-term
Natural gas contracts	$	0.4	$	0.4	$	2.9	$	—
Coal contracts	—		1.1		0.5		0.5
Total other long-term *	$	0.4	$	1.5	$	3.4	$	0.5
Total	$	17.5	$	8.0	$	41.6	$	2.4


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

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



	Three Months Ended June 30, 2017				Three Months Ended June 30, 2016
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	25.2 Dth	$	1.3		32.7 Dth	$	(20.0	)
Petroleum products contracts	4.9 gallons	(0.4		)	3.6 gallons	(1.0		)
FTRs	9.4 MWh	2.2			7.4 MWh	1.6
Total		$	3.1			$	(19.4	)



	Six Months Ended June 30, 2017				Six Months Ended June 30, 2016
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	59.3 Dth	$	1.0		82.8 Dth	$	(53.5	)
Petroleum products contracts	9.8 gallons	(0.9		)	6.6 gallons	(2.1		)
FTRs	18.6 MWh	5.2			15.0 MWh	4.6
Total		$	5.3			$	(51.0	)

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, 2017 and December 31, 2016 , we had posted cash collateral of $25.6 million and $16.4 million , respectively, in our margin accounts. These amounts were recorded on our balance sheets in other current assets. At December 31, 2016, we had also received cash collateral of $4.4 million in our margin accounts. This amount was recorded on our balance sheet in other current liabilities.



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



	June 30, 2017							December 31, 2016
(in millions)	Derivative Assets			Derivative Liabilities				Derivative Assets				Derivative Liabilities
Gross amount recognized on the balance sheet	$	17.5		$	8.0			$	41.6			$	2.4
Gross amount not offset on the balance sheet	(3.0		)	(3.8		)	⁽¹⁾	(4.9		)	⁽²⁾	(0.5		)
Net amount	$	14.5		$	4.2			$	36.7			$	1.9


⁽¹⁾	Includes cash collateral posted of $0.8 million .


⁽²⁾	Includes cash collateral received of $4.4 million .

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 net liability position was $2.4 million and $0.2 million at June 30, 2017 and December 31, 2016 , respectively. At June 30, 2017 and December 31, 2016 , we had not posted any 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, 2017 , we would have been required to post collateral of $0.7 million . At December 31, 2016 , we would not have been required to post any collateral.

NOTE 10— GUARANTEES

The following table shows our outstanding guarantees:



	Total Amounts Committed at		Expiration
(in millions)	June 30, 2017		Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees
Guarantees supporting commodity transactions of subsidiaries ⁽¹⁾	$	8.1	$	8.1	$	—	$	—
Standby letters of credit ⁽²⁾	44.2		38.7		5.5		—
Surety bonds ⁽³⁾	9.5		7.8		1.7		—
Other guarantees ⁽⁴⁾	10.1		0.5		—		9.6
Total guarantees	$	71.9	$	55.1	$	7.2	$	9.6


⁽¹⁾	Consists of $8.1 million to support the business operations of Bluewater.


⁽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 $10.1 million related to other indemnifications, for which a liability of $9.6 million related to workers compensation coverage was recorded on our balance sheets.



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NOTE 11— EMPLOYEE BENEFITS

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



	Pension Costs
	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2017			2016			2017			2016
Service cost	$	10.4		$	10.7		$	22.1		$	22.0
Interest cost	30.2			33.0			61.4			66.2
Expected return on plan assets	(48.5		)	(49.0		)	(98.1		)	(98.0		)
Loss on plan settlement	5.3			14.1			5.3			14.1
Amortization of prior service cost	0.8			0.8			1.5			1.7
Amortization of net actuarial loss	21.1			20.2			43.0			40.7
Net periodic benefit cost	$	19.3		$	29.8		$	35.2		$	46.7



	OPEB Costs
	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2017			2016			2017			2016
Service cost	$	5.6		$	6.4		$	11.9		$	13.1
Interest cost	8.4			9.3			16.9			18.5
Expected return on plan assets	(13.6		)	(13.3		)	(27.3		)	(26.4		)
Amortization of prior service credit	(2.8		)	(2.4		)	(5.6		)	(4.7		)
Amortization of net actuarial loss	0.1			1.9			1.6			4.2
Net periodic benefit (credit) cost	$	(2.3	)	$	1.9		$	(2.5	)	$	4.7

During the six months ended June 30, 2017 , we made payments of $107.2 million to our pension plans and $4.3 million to our OPEB plans. We expect to make payments of $6.4 million related to our pension plans and $5.3 million related to our OPEB plans during the remainder of 2017 , 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, 2017 :



(in millions)	Wisconsin		Illinois		Other States		Non-Utility Energy		Total
Goodwill balance as of January 1, 2017	$	2,104.3	$	758.7	$	183.2	$	—	$	3,046.2
Acquisition of Bluewater ⁽¹⁾	—		—		—		7.3		7.3
Goodwill balance as of June 30, 2017 ⁽²⁾	$	2,104.3	$	758.7	$	183.2	$	7.3	$	3,053.5


⁽¹⁾	See Note 2, Acquisition, for more information on the acquisition of Bluewater.


⁽²⁾	We had no accumulated impairment losses related to our goodwill as of June 30, 2017 .



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NOTE 13— INVESTMENT IN AMERICAN TRANSMISSION COMPANY

We own approximately 60% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. The following table shows changes to our investment in ATC:



	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2017		2016				2017			2016
Balance at beginning of period	$	1,513.3	$	1,422.5			$	1,443.9		$	1,380.9
Add: Earnings from equity method investment	41.8		30.9				83.7			69.4
Add: Capital contributions	22.9		3.1				50.5			12.1
Add: Acquisition of Integrys's investment in ATC	—		(1.0		)	⁽¹⁾	—			(1.0		)	⁽¹⁾
Add: Adjustment to equity method goodwill	—		1.1				—			10.4
Less: Distributions	34.0		31.6				34.0		⁽²⁾	46.7
Less: Other	—		—				0.1			0.1
Balance at end of period	$	1,544.0	$	1,425.0			$	1,544.0		$	1,425.0


⁽¹⁾	Amount reflects an adjustment to the allocation of the purchase price for Integrys made in the second quarter of 2016.


⁽²⁾	Distributions of $35.2 million , received in the first quarter of 2017, were approved and recorded in December 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 are reimbursed by ATC. We are required to pay the cost of needed transmission infrastructure upgrades for new generation projects while the projects are under construction. ATC reimburses us for these costs when the new generation is placed in service.

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



	Three Months Ended June 30				Six Months Ended June 30
(in millions)	2017		2016		2017			2016
Charges to ATC for services and construction	$	3.7	$	4.3	$	7.9		$	8.4
Charges from ATC for network transmission services	87.3		91.1		174.6			182.1
Refund from ATC per FERC ROE order	—		—		(28.3		)	—

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



(in millions)	June 30, 2017		December 31, 2016
Accounts receivable
Services provided to ATC	$	1.2	$	2.2
Accounts payable
Services received from ATC	29.1		28.7

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



	Three Months Ended June 30				Six Months Ended June 30
(in millions)	2017		2016		2017		2016
Income statement data
Revenues	$	176.6	$	154.3	$	351.3	$	318.5
Operating expenses	82.7		81.7		165.1		160.8
Other expense	25.7		23.7		52.1		47.7
Net income	$	68.2	$	48.9	$	134.1	$	110.0



06/30/2017 Form 10-Q	16	WEC Energy Group, Inc.

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(in millions)	June 30, 2017		December 31, 2016
Balance sheet data
Current assets	$	86.2	$	75.8
Noncurrent assets	4,489.3		4,312.9
Total assets	$	4,575.5	$	4,388.7

Current liabilities	$	640.3	$	495.1
Long-term debt	1,740.6		1,865.3
Other noncurrent liabilities	291.4		271.5
Shareholders' equity	1,903.2		1,756.8
Total liabilities and shareholders' equity	$	4,575.5	$	4,388.7

NOTE 14— SEGMENT INFORMATION

At June 30, 2017 , 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 that were transferred to UMERC effective January 1, 2017.


•	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.


•	Following the acquisition of Bluewater, our We Power segment was renamed the non-utility energy segment. This segment includes We Power, which owns and leases generating facilities to WE, and Bluewater, which owns underground natural gas storage facilities in Michigan. See Note 2, Acquisition, for more information on the Bluewater transaction.

•

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, Wisvest, Wisconsin Energy Capital Corporation, WBS, WPS Power Development LLC, and ITF. In the first quarter of 2017, we sold substantially all of the remaining assets of Bostco and in the second quarter of 2016, we sold certain assets of Wisvest. The sale of ITF was completed in the first quarter of 2016. 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 related to our reportable segments for the three and six months ended June 30 , 2017 and 2016 :



	Utility Operations
(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Electric Transmission		Non-Utility Energy		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Three Months Ended
June 30, 2017
External revenues	$	1,303.2	$	253.2	$	65.7	$	1,622.1	$	—	$	6.2	$	3.2		$	—		$	1,631.5
Intersegment revenues	—		—		—		—		—		112.6		—			(112.6		)	—
Other operation and maintenance	458.7		104.9		23.3		586.9		—		2.7		2.8			(112.6		)	479.8
Depreciation and amortization	130.3		37.5		6.1		173.9		—		17.4		6.4			—			197.7
Operating income (loss)	223.6		41.4		4.7		269.7		—		98.7		(6.2		)	—			362.2
Equity in earnings of transmission affiliate	—		—		—		—		41.8		—		—			—			41.8
Interest expense	48.2		10.9		1.9		61.0		—		15.2		26.8			(1.1		)	101.9



06/30/2017 Form 10-Q	17	WEC Energy Group, Inc.

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	Utility Operations
(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Electric Transmission		Non-Utility Energy		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
Interest expense	44.4		9.8		2.1		56.3		—		15.6		30.2			(2.0		)	100.1



	Utility Operations
(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Electric Transmission		Non-Utility Energy		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Six Months Ended
June 30, 2017
External revenues	$	2,915.3	$	778.5	$	223.6	$	3,917.4	$	—	$	12.5	$	6.1		$	—		$	3,936.0
Intersegment revenues	—		—		—		—		—		221.6		—			(221.6		)	—
Other operation and maintenance	921.6		225.8		51.6		1,199.0		—		3.1		1.2			(221.6		)	981.7
Depreciation and amortization	259.6		73.7		12.1		345.4		—		34.9		12.0			—			392.3
Operating income (loss)	555.9		196.8		38.1		790.8		—		196.1		(7.4		)	—			979.5
Equity in earnings of transmission affiliate	—		—		—		—		83.7		—		—			—			83.7
Interest expense	96.9		22.0		4.2		123.1		—		30.5		55.9			(2.9		)	206.6



	Utility Operations
(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Electric Transmission		Non-Utility Energy		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
Interest expense	88.9		19.5		4.6		113.0		—		31.2		61.5			(4.7		)	201.0

NOTE 15— VARIABLE INTEREST ENTITIES

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

We assess our relationships with potential variable interest entities, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to power purchase agreements, investments, and joint



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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, distributions receivable, and accounts payable. At June 30, 2017 and December 31, 2016 , our equity investment was $1,544.0 million and $1,443.9 million , respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC. In addition, we had a receivable of $35.2 million recorded at December 31, 2016 for distributions from ATC. We also had $29.1 million and $28.7 million of accounts payable due to ATC at June 30, 2017 and December 31, 2016 , 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 MWs 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 five 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 $78.4 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, 2017 and 2016 were $9.0 million and $26.9 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.

Unconditional Purchase Obligations

Our electric utilities have obligations to distribute and sell electricity to their customers, and our natural gas utilities have obligations to distribute and sell natural gas 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, 2017 , including those of our subsidiaries, were $12,065.4 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 SO ₂ , 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.



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Air Quality

Cross-State Air Pollution Rule

In July 2011, the EPA issued the CSAPR, which replaced a previous rule, the Clean Air Interstate Rule. The purpose of the CSAPR was to limit the interstate transport of NOx and SO ₂ that contribute to fine particulate matter and ozone nonattainment in downwind states through a proposed allowance allocation and trading plan. After several lawsuits and related appeals, 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. The emissions budgets of Phase I of the rule applied in 2015 and 2016, while the Phase II emissions budgets apply to 2017 and beyond.

The EPA published its proposed update to the CSAPR for the 2008 ozone NAAQS in December 2015, and issued the final rule in September 2016. We remain well positioned to meet the rule requirements and do not expect to incur significant costs to comply with this rule.

Sulfur Dioxide National Ambient Air Quality Standards

The EPA issued a revised 1-Hour SO ₂ 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 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, the WDNR provided final modeling to the EPA demonstrating the area around the Weston Power Plant to be in compliance. We expect that the EPA will consider the WDNR's recommendation and will finalize its designation by the end of 2017. We believe our fleet overall is well positioned to meet the regulation and do not expect to incur significant costs to comply with this regulation.

8-Hour Ozone National Ambient Air Quality Standards

Sheboygan County and the eastern portion of Kenosha County are currently designated as nonattainment with the 2008 ozone standard. In response, Wisconsin has updated the 2008 ozone NAAQS attainment plan for Kenosha County and submitted it to the EPA for approval. The plan concluded that Wisconsin will not need to implement any new regulatory measures or programs. The area is forecasted to meet the standard by the 2018 compliance date due to emission control measures already in place. Wisconsin has prepared a draft attainment plan for Sheboygan County, which is out for public comment and is expected to submit a final plan to the EPA for approval this summer. A final EPA action regarding Wisconsin's attainment plan is expected later in 2017.

After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, which lowered the limit for ground-level ozone, creating a more stringent standard than the 2008 NAAQS. This is expected to cause nonattainment for Wisconsin's Lake Michigan shoreline counties (or partial counties), with potential future impacts for our fossil-fueled power plant fleet. In January 2017, the EPA released preliminary interstate ozone transport modeling for the 2015 ozone NAAQS. The EPA is currently scheduled to finalize designations in October 2017. For nonattainment areas, the state of Wisconsin 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. We will not know the potential impacts for complying with the 2015 ozone NAAQS until the designations are final and until the state prepares a draft attainment plan.

Although we are still in the process of reviewing and determining potential impacts resulting from this rule, we believe we are well positioned to meet the ozone standard and do not expect to incur significant costs to comply.

Climate Change

In 2015, the EPA issued a final rule regulating GHG emissions from existing generating units, referred to as the Clean Power Plan (CPP), 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 CPP, numerous states (including Wisconsin and Michigan) and other 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 CPP until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that further appellate review is sought, at the Supreme Court. The D.C. Circuit Court of Appeals heard one case in September 2016, and the other case is still pending. In April



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2017, pursuant to motions made by the EPA, the D.C. Circuit Court of Appeals ordered the cases to be held in abeyance. Supplemental briefs were provided addressing whether the cases should be remanded to the EPA rather than held in abeyance. The EPA argued that the cases should continue to be held in abeyance pending the conclusion of the EPA's review of the CPP and any resulting rulemaking.

The CPP seeks to achieve state-specific GHG emission reduction goals by 2030, and would have required states to submit plans by September 2016. 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.

In March 2017, President Trump issued an executive order that, among other things, specifically directs the EPA to review, and if appropriate, initiate proceedings to suspend, revise, or rescind the CPP and related GHG regulations for new, reconstructed, or modified fossil-fueled power plants. The EPA announced that it has initiated this review. As a result of this order and related EPA review, as well as the ongoing legal proceedings, the timelines for the GHG emission reduction goals and all other aspects of the CPP are uncertain. In April 2017, the EPA withdrew the proposed rule for a federal plan and model trading rules that were published in October 2015 for use in developing state plans to implement the CPP or for use in states where a plan is not submitted or approved. In addition, the Governor of Wisconsin issued an executive order in February 2016, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan.

Notwithstanding the uncertain future of the CPP, and given current fuel and technology markets, we continue to evaluate opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute towards long-term GHG reductions. Our plan is to work with our industry partners, environmental groups, and the State of Wisconsin, with a goal of reducing CO ₂ emissions by approximately 40% below 2005 levels by 2030. We continue to evaluate numerous options in order to meet our CO ₂ reduction goal, such as increased use of existing natural gas combined cycle units, co-firing or switching to natural gas in existing coal-fired units, reduced operation or retirement of existing coal-fired units, addition of new renewable energy resources (wind, solar), and consideration of supply and demand-side energy efficiency and distributed generation.

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 (entrapping organisms on water intake screens) and entrainment (drawing organisms into water intake). The rule became effective in October 2014, and applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS 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 Pulliam Units 7 and 8 and Weston Unit 2, satisfy the IM BTA requirements. 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 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 OC 5 through OC 8.

During 2017 and 2018, we will continue to complete studies and evaluate options to address the EM BTA requirements at these 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), we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at the 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.



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Based on discussions with the MDEQ, if we provide information about unit retirements with our next National Pollutant Discharge Elimination System permit application and then submit a signed certification by August 2017 stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2022), then the EM BTA requirements will be waived. We expect to submit entrainment studies being conducted at Pulliam Units 7 and 8 to the WDNR by June 2018.

We believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation.

Steam Electric Effluent Limitation Guidelines

The EPA's final steam electric effluent limitation guidelines (ELG) rule took effect in January 2016. In April 2017, the EPA issued an administrative stay of certain compliance deadlines while further reviewing the rule. In June 2017, the EPA issued a proposed rule to codify this stay. This rule applies to wastewater discharges from our power plant processes in Wisconsin and Michigan. While the ELG compliance deadlines are postponed, the WDNR and the MDEQ have indicated that they will refrain from incorporating certain new requirements into any reissued discharge permits between 2018 and 2023.

After a final rule is back in effect, the WDNR and MDEQ have indicated that they will modify the state rules as necessary and incorporate the new requirements into our facility permits, which are renewed every five years . Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, as currently constructed, the ELG rule will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use.

The final rule would phase 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 would require additional zero liquid discharge or other advanced treatment capital improvements for the Oak Creek site and Pleasant Prairie facilities. The rule also would require 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 would be required at OC 7, OC 8, the Pleasant Prairie 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 $80 million to $110 million for these advanced treatment and bottom ash transport systems. A similar system would be required at PIPP if we were not expecting to retire the plant. See the UMERC discussion in Note 18, Regulatory Environment , regarding the potential retirement of PIPP.

Land Quality

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 Alternative Approach 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.



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



(in millions)	June 30, 2017		December 31, 2016
Regulatory assets	$	683.8	$	702.7
Reserves for future remediation	622.4		633.4

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.

Consent Decrees

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.

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, 2017 . 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.

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. Management of the joint owners has 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)	2017			2016
Cash (paid) for interest, net of amount capitalized	$	(209.3	)	$	(209.2	)
Cash received for income taxes, net	9.5			7.4
Significant non-cash transactions
Accounts payable related to construction costs	155.5			114.0
Increase (decrease) in restricted cash from the sale (purchase) of investments held in the rabbi trust	4.6			(1.5		)
Portion of Bostco real estate holdings sale financed with note receivable *	7.0			—
Amortization of deferred revenue	12.4			12.3


*	See Note 3, Dispositions, for more information on this sale.



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At June 30, 2017 , and December 31, 2016 , restricted cash of $21.8 million and $33.6 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. Withdrawals of restricted cash from the rabbi trust for qualifying payments are shown as an investing activity on the statements of cash flows. Changes in restricted cash due to the sale or purchase of investments held in the rabbi trust are non-cash transactions and are included in the table above.

NOTE 18— REGULATORY ENVIRONMENT

Wisconsin Electric Power Company, Wisconsin Gas LLC, and Wisconsin Public Service Corporation

2018 and 2019 Rates

During April 2017, WE, WG, and WPS filed an application with the PSCW for approval of a settlement agreement they made with several of their commercial and industrial customers regarding 2018 and 2019 base rates. In this proposed settlement agreement, WE, WG, and WPS agreed to keep electric and natural gas base rates frozen for their customers through 2019. In addition, WE and WPS agreed to extend and expand the electric real-time pricing options for large commercial and industrial customers, and WE agreed to prevent the continued growth of certain escrowed costs. Deferral by WE, WG, and WPS of the revenue requirement impacts of any federal corporate tax reform enacted in 2017, or during the rate freeze period, was included in the agreement as well. Additionally, the agreement allows WPS to extend, through 2019, the deferral for the revenue requirement of ReACT™ costs above the authorized $275.0 million level. The total cost of the ReACT™ project, excluding $51 million of AFUDC, is currently estimated to be $342 million . The agreement also included an extension, through 2019, of other deferrals related to WPS's electric real-time pricing program and network transmission expenses.

Pursuant to the settlement agreement, WPS also agreed to adopt, beginning in 2018, the earnings sharing mechanism currently in place for WE and WG, and all three utilities agreed to keep the mechanism in place through 2019. Under this earnings sharing mechanism, if WE, WG, or WPS earns above its authorized ROE, 50% of the first 50 basis points of additional utility earnings must be shared with customers. All utility earnings above the first 50 basis points must also be shared with customers.

In July 2017, the PSCW staff issued a commission memorandum in response to the settlement agreement, and we expect the PSCW to issue a final order on the agreement during the third quarter of 2017. If the PSCW rejects the proposed settlement agreement, we expect we will file a traditional rate proceeding.

Natural Gas Storage Facilities in Michigan

In January 2017, we signed an agreement for the acquisition of Bluewater. Bluewater owns natural gas storage facilities in Michigan that would provide approximately one-third of the current storage needs for the natural gas distribution service customers of WE, WG, and WPS. As a result of this agreement, WE, WG, and WPS filed a request with the PSCW in February 2017 for a declaratory ruling on various items associated with the storage facilities. In the filing, WE, WG, and WPS requested that the PSCW review and confirm the reasonableness and prudency of their potential long-term storage service agreements and interstate natural gas transportation contracts related to the storage facilities. WE, WG, and WPS also requested approval to amend our Affiliated Interest Agreement to ensure WBS and our other subsidiaries could provide services to the storage facilities. During June 2017, the PSCW granted, subject to various conditions, these declarations and approvals, and we acquired Bluewater on June 30, 2017. See Note 2, Acquisition, for more information .

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

Illinois Proceedings

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 SMP. PGL and the ICC staff filed a settlement agreement related to these anonymous letters with the ICC during March 2017. In this agreement, we agreed to modify our code of business conduct to address certain concerns regarding conflicts of interest, and PGL agreed to provide a quarterly report to the ICC for four years identifying code of conduct and conflict of interest allegations. The agreement also requested that PGL provide semi-annual quality assurance reports to the ICC for four years on the SMP capital construction performed by PGL crews and contractors. During May



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2017, the ICC issued a final order approving the settlement agreement. The period to appeal this order has expired, and no appeals were filed.

In December 2015, the ICC ordered a series of stakeholder workshops to evaluate PGL's SMP. 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 commenced in January 2016 and were completed in March 2016. In July 2016, the ICC initiated a proceeding to review, among other things, the planning, reporting, and monitoring of the program, including the target end date for the program. In March 2017, the ICC issued an order directing that additional hearings be held before the ALJ on certain issues to further develop the evidentiary record in the case. This proceeding is expected to result in a final order by the ICC in 2017. We are currently unable to determine what, if any, long-term impact there will be on the SMP.

Qualifying Infrastructure Plant Rider

In July 2013, Illinois Public Act 98-0057, The Natural Gas Consumer, Safety & Reliability Act, became law. The Act provides PGL with a cost recovery mechanism that allows collection, through a surcharge on customer bills, of prudently incurred costs to upgrade Illinois natural gas infrastructure. This Act eliminated a requirement for PGL to file biennial rate proceedings under existing Illinois coal-to-gas legislation. In September 2013, PGL filed with the ICC requesting the proposed rider, which was approved in January 2014.

PGL's QIP rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2017, PGL filed its 2016 reconciliation with the ICC, which, along with the 2015 reconciliation, is still pending. For PGL's 2014 reconciliation, the ICC staff and the Illinois Attorney General's office filed testimony in June 2017. PGL filed rebuttal testimony in July 2017, and we expect to receive an order related to the 2014 reconciliation in the fourth quarter of 2017. As of June 30, 2017 , there can be no assurance that all costs incurred under PGL's QIP rider during the open reconciliation years will be recoverable.

Minnesota Energy Resources Corporation

2016 Minnesota Rate Order

In September 2015, MERC initiated a rate proceeding with the MPUC. In October 2016, the MPUC issued a final written order for MERC, effective March 1, 2017. The order authorized a retail natural gas rate increase of $6.8 million ( 3.0% ). The rates reflect a 9.11% ROE and a common equity component average of 50.32% . The order approved MERC's request to continue the use of its currently authorized decoupling mechanism for another three years . The final approved rate increase was lower than the interim rates collected from customers during 2016. Therefore, we refunded $4.1 million to MERC's customers during the second quarter of 2017.

Upper Michigan Energy Resources Corporation

Formation of Upper Michigan Energy Resources Corporation

In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan, and UMERC became operational effective January 1, 2017. This utility holds the electric and natural gas distribution assets, previously held by WE and WPS, located in the Upper Peninsula of Michigan.

In August 2016, we entered into an agreement with the Tilden Mining Company (Tilden), under which Tilden will purchase electric power from UMERC for its iron ore mine for 20 years . The agreement also calls for UMERC to construct and operate approximately 180 MWs of natural gas-fired generation located in the Upper Peninsula of Michigan. During January 2017, UMERC filed an application with the MPSC for a certificate of necessity to begin construction of the proposed generation. The estimated cost of this project is approximately $265 million ( $275 million with AFUDC), 50% of which is expected to be recovered from Tilden, with the remaining 50% expected to be recovered from utility customers located in the Upper Peninsula of Michigan. Subject to regulatory approval of both the agreement with Tilden and the construction of the proposed generation, the new units are expected to begin commercial operation in 2019 and should allow for the retirement of PIPP no later than 2020. Tilden will remain a customer of WE until this new generation begins commercial operation. We expect the MPSC to issue final orders on the Tilden agreement and the proposed generation during the fourth quarter of 2017.



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2015 Michigan Rate Order

Prior to the formation of UMERC, in October 2014, WPS initiated a rate proceeding with the MPSC. In April 2015, the MPSC issued a final written order for WPS, effective April 24, 2015, approving a settlement agreement. As a result of the formation of UMERC, the terms and conditions of this WPS rate order now apply to UMERC, including the deferrals described below. The order authorized a retail electric rate increase of $4.0 million to be implemented over three years to recover costs for the 2013 acquisition of the Fox Energy Center as well as other capital investments associated with the Crane Creek wind farm and environmental upgrades at generation plants. The rates reflected a 10.2% ROE and a common equity component average of 50.48% . The increase reflected the continued deferral of costs associated with the Fox Energy Center until the second anniversary of the order. The increase also reflected the deferral of Weston Unit 3 ReACT™ environmental project costs. On the second anniversary of the order, the Fox Energy Center costs deferral was discontinued and amortization of this deferral began, along with the amortization of the deferral associated with the termination of the Fox Energy Center tolling agreement. In the order, the MPSC also approved the deferral and amortization of the undepreciated book value of the retired plant associated with Pulliam Units 5 and 6 and Weston Unit 1 starting with the actual retirement date, June 1, 2015, and concluding by 2023. UMERC will not seek an increase to retail electric base rates that would become effective prior to January 1, 2018.

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. Several amendments were issued subsequent to the standard to clarify the guidance. The core principle of the guidance is to recognize revenue in an amount that an entity is entitled to receive in exchange for goods and services. The guidance also requires additional disclosures about the nature, amount, timing, and uncertainty of revenues and the related cash flows arising from contracts with customers.

We intend to adopt this standard for interim and annual periods beginning January 1, 2018, as required, and plan to use the modified retrospective method of adoption. If applicable, this method requires a cumulative-effect adjustment to be recorded on the balance sheet as of the beginning of 2018, as if the standard had always been in effect. If applicable, disclosures in 2018 will include a reconciliation of results under the new revenue recognition guidance compared with what would have been reported in 2018 under the old revenue recognition guidance in order to help facilitate comparability with the prior periods.

We are currently reviewing our contracts with customers and related financial disclosures to evaluate the impact of the amended guidance on our existing revenue recognition policies and procedures. We consider tariff sales at our regulated utilities, excluding the revenue component related to alternative revenue programs, to be in the scope of the new standard. We have evaluated the nature of these revenues and do not expect that there will be a significant shift in the timing or pattern of revenue recognition for such sales. However, in our evaluation, we are also monitoring unresolved implementation issues for our industry. The final resolution of these issues could impact our current accounting policies and revenue recognition.

Recognition and Measurement of Financial Instruments

In January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. This guidance requires equity investments, including other ownership interests such as partnerships, unincorporated joint ventures, and limited liability companies, to be measured at fair value with changes in fair value recognized in net income. It also simplifies the impairment assessment of equity investments without readily determinable fair values and amends certain disclosure requirements associated with the fair value of financial instruments. This ASU does not apply to investments accounted for under the equity method of accounting. We do not believe the adoption of this guidance will have a significant impact on our financial statements.

Leases

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



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Financial Instruments Credit Losses

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

Classification of Certain Cash Receipts and Cash Payments

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

Restricted Cash

In November 2016, the FASB issued ASU 2016-18, Restricted Cash. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. Under this ASU, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-the period and end-of-the period total amounts shown on the statements of cash flows. We do not believe the adoption of this guidance will have a significant impact on our financial statements.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. Under this ASU, an employer is required to disaggregate the service cost component from the other components of the net benefit cost. The amendments provide explicit guidance on how to present the service cost component and the other components of the net benefit cost in the income statement and allow only the service cost component of the net benefit cost to be eligible for capitalization. The amendments should be applied retrospectively for the presentation of the service cost component and the other components of the net benefit cost in the income statement, and prospectively for the capitalization of the service cost component in assets. We are currently assessing the effects this guidance may have on our financial statements.



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

CORPORATE DEVELOPMENTS

The following discussion should be read in conjunction with the accompanying financial statements and related notes and our Annual Report on Form 10-K for the year ended December 31, 2016 .

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 energy operations through our We Power business and our recently acquired underground natural gas storage facilities in Michigan. For more information on the natural gas storage facilities, see Note 2, Acquisition .

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.

•

UMERC, our Michigan electric and natural gas utility, is proposing a long-term generation solution for electric reliability in the Upper Peninsula of Michigan. The plan calls for UMERC to construct and operate approximately 180 MWs of natural gas-fired generation that will be located in the Upper Peninsula of Michigan. The new generation would provide the region with affordable, reliable electricity that generates less emissions than PIPP. Subject to regulatory approval, the new generation is expected to achieve commercial operation in 2019 and should allow for the retirement of PIPP no later than 2020. For more information, see Note 18, Regulatory Environment .


•	PGL continues to work on its SMP, 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 SMRP, which involves modernizing parts of its electric distribution system, including burying or upgrading lines. The project focuses on constructing facilities to improve the reliability of electric service WPS provides to its customers. WE, WPS, and WG also continue to upgrade their electric and natural gas distribution systems to enhance reliability.

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 ERGS to enable the facility to burn coal from the Powder River Basin located in the western United States. The coal plant was originally designed to burn coal mined from the eastern United States. This project is creating flexibility and has enabled 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.

We continue to focus on integrating and improving business processes and consolidating our IT infrastructure across all of our companies. We expect the emphasis we are placing on these integration efforts to continue to drive operational efficiency and to put us in position to effectively support plans for future growth.



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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 natural gas storage facilities in Michigan.


•	See Note 3, Dispositions , for information on the sale of ITF, the MCPP, certain assets of Wisvest, and Bostco's real estate holdings.

Our primary investment opportunities are in our regulated utility business and our investment in ATC. Over the next five years, we expect capital contributions to ATC and ATC Holdco, LLC to be approximately $350 million. ATC Holdco is a separate entity formed in December 2016 to invest in transmission related projects outside of ATC's traditional footprint. Capital investments at ATC and ATC Holdco will be funded utilizing these capital contributions, in addition to cash generated from operations and debt. We currently forecast that our share of ATC's and ATC Holdco's projected capital expenditures over the next five years will be $1.4 billion inside the traditional ATC footprint and $300 million outside of the traditional ATC footprint.

Excluding ATC, we expect total capital expenditures for our regulated utility business to be in the range of $9.5 billion to $10.0 billion over the next five years. 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.

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. 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.

Safety

We have a long-standing commitment to both workplace and public safety, and under our "Target Zero" mission, we have an ultimate goal of zero incidents, accidents, and injuries.



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RESULTS OF OPERATIONS

THREE MONTHS ENDED JUNE 30, 2017

Consolidated Earnings

The following table compares our consolidated results for the second quarter of 2017 with the second quarter of 2016 , including favorable or better, "B", and unfavorable or worse, "W", variances:



	Three Months Ended June 30
(in millions, except per share data)	2017			2016			B (W)
Wisconsin	$	223.6		$	214.7		$	8.9
Illinois	41.4			22.6			18.8
Other states	4.7			2.3			2.4
Non-utility energy	98.7			94.1			4.6
Corporate and other	(6.2		)	(1.6		)	(4.6		)
Total operating income	362.2			332.1			30.1
Equity in earnings of transmission affiliate	41.8			30.9			10.9
Other income, net	13.1			32.4			(19.3		)
Interest expense	101.9			100.1			(1.8		)
Income before income taxes	315.2			295.3			19.9
Income tax expense	115.8			113.6			(2.2		)
Preferred stock dividends of subsidiary	0.3			0.3			—
Net income attributed to common shareholders	$	199.1		$	181.4		$	17.7

Diluted earnings per share	$	0.63		$	0.57		$	0.06

Earnings increased $17.7 million during the second quarter of 2017 , compared with the same quarter in 2016 . The significant factors impacting the increase in earnings were:


•	An $18.8 million pre-tax ($11.3 million after tax) increase in operating income at the Illinois segment. The increase was driven by lower operating expenses and higher natural gas margins at PGL due to continued capital investment in projects under its QIP rider.

•

A $10.9 million pre-tax ($6.5 million after tax) increase in earnings from our ownership interest in ATC. In the second quarter of 2016, ATC recognized lower earnings as a result of an ALJ recommendation related to the FERC ROE reviews. See Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints for more information.


•	An $8.9 million pre-tax ($5.3 million after tax) increase in operating income at the Wisconsin segment driven by lower operating expenses. Partially offsetting the lower operating expenses was a decrease in electric and natural gas margins driven by lower sales volumes.


•	A 1.8% decrease in our effective tax rate also drove an increase in earnings. The decrease in our effective tax rate was in part due to the recognition of excess tax benefits related to share-based payments and favorable compensation expense in the second quarter of 2017.

These increases in earnings were partially offset by a $19.3 million pre-tax ($11.6 million after tax) decrease in other income, net. The decrease was driven by the quarter-over-quarter impact of the gain recognized in 2016 related to the sale of certain assets of Wisvest. See Note 3, Dispositions, for more information on this transaction.

Non-GAAP Financial Measure



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revenues less cost of natural gas sold) are non-GAAP financial measures because they exclude other operation and maintenance expense, depreciation and amortization, and property and revenue taxes.

We believe that electric and natural gas margins provide a more meaningful basis for evaluating utility operations than operating revenues since the majority of prudently incurred fuel and purchased power costs, as well as prudently incurred natural gas costs, are passed through to customers in current rates. As a result, management uses electric and natural gas margins internally when assessing the operating performance of our segments as these measures exclude the majority of revenue fluctuations caused by changes in these expenses. Similarly, the presentation of electric and natural gas margins herein is intended to provide supplemental information for investors regarding our operating performance.

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of our segment operating performance. Operating income for the second quarter of 2017 and 2016 for each of our segments is presented in the “Consolidated Earnings” table above.

Each applicable segment operating income discussion below includes a table that provides the calculation of electric margins and natural gas margins, as applicable, along with a reconciliation to segment operating income.

Wisconsin Segment Contribution to Operating Income



	Three Months Ended June 30
(in millions)	2017		2016		B (W)
Electric revenues	$	1,090.7	$	1,097.2	$	(6.5	)
Fuel and purchased power	345.0		343.1		(1.9		)
Total electric margins	745.7		754.1		(8.4		)

Natural gas revenues	212.5		207.5		5.0
Cost of natural gas sold	105.1		95.3		(9.8		)
Total natural gas margins	107.4		112.2		(4.8		)

Total electric and natural gas margins	853.1		866.3		(13.2		)

Other operation and maintenance	458.7		487.8		29.1
Depreciation and amortization	130.3		122.7		(7.6		)
Property and revenue taxes	40.5		41.1		0.6
Operating income	$	223.6	$	214.7	$	8.9

The following table shows a breakdown of other operation and maintenance:



	Three Months Ended June 30
(in millions)	2017		2016		B (W)
Operation and maintenance not included in line items below	$	188.8	$	217.2	$	28.4
We Power ⁽¹⁾	127.1		127.3		0.2
Transmission ⁽²⁾	106.1		105.8		(0.3		)
Regulatory amortizations and other pass through expenses ⁽³⁾	36.7		37.5		0.8
Total other operation and maintenance	$	458.7	$	487.8	$	29.1

⁽¹⁾

Represents costs associated with the We Power generation units, including operating and maintenance costs incurred by WE, as well as the lease payments that are billed from We Power to WE and then recovered in WE's rates. During the three months ended June 30, 2017 and 2016 , $139.2 million and $139.5 million , respectively, of both lease and operating and maintenance costs were billed to or incurred by WE, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

⁽²⁾

The PSCW has approved escrow accounting for ATC and MISO network transmission expenses for our Wisconsin electric utilities. As a result, WE and WPS defer as a regulatory asset or liability the differences between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the three months ended June 30, 2017 and 2016 , $118.6 million and $120.4 million , respectively, of costs were billed by transmission providers to our electric utilities.



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⁽³⁾	Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income.

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	2017	2016	B (W)
Customer Class
Residential	2,455.2	2,455.3	(0.1	)
Small commercial and industrial *	3,113.6	3,172.2	(58.6	)
Large commercial and industrial *	3,224.4	3,458.7	(234.3	)
Other	39.9	40.1	(0.2	)
Total retail *	8,833.1	9,126.3	(293.2	)
Wholesale	933.7	897.3	36.4
Resale	1,240.6	1,862.2	(621.6	)
Total sales in MWh *	11,007.4	11,885.8	(878.4	)


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



	Three Months Ended June 30
	Therms (in millions)
Natural Gas Sales Volumes	2017	2016	B (W)
Customer Class
Residential	137.1	160.4	(23.3	)
Commercial and industrial	90.1	100.9	(10.8	)
Total retail	227.2	261.3	(34.1	)
Transport	293.6	291.0	2.6
Total sales in therms	520.8	552.3	(31.5	)



	Three Months Ended June 30
	Degree Days
Weather	2017	2016	B(W)
WE and WG ⁽¹⁾
Heating (937 normal)	748	926	(178	)
Cooling (161 normal)	203	196	7

WPS ⁽²⁾
Heating (958 normal)	834	964	(130	)
Cooling (131 normal)	125	142	(17	)

UMERC ⁽³⁾
Heating (1,183 normal)	1,141	N/A	N/A
Cooling (79 normal)	47	N/A	N/A


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


⁽²⁾	Normal degree days are based on a 20-year moving average of monthly temperatures from the Green Bay, Wisconsin weather station.


⁽³⁾	Normal degree days are based on a 20-year moving average of monthly temperatures from the Iron Mountain, Michigan weather station.



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Electric Utility Margins

Electric utility margins at the Wisconsin segment decreased $8.4 million during the second quarter of 2017, compared with the same quarter in 2016. The significant factors impacting the lower electric utility margins were:


•	An $11.3 million decrease related to lower sales volumes during the second quarter of 2017, driven by lower overall retail use per customer.

•

A $5.2 million negative impact from collections of fuel and purchased power costs compared with costs approved in rates in the second quarter of 2017, as compared with the same quarter in 2016. Under the Wisconsin fuel rules, the margins of our electric utilities are impacted by under or over-collections of certain fuel and purchased power costs that are less than a 2% price variance from the costs included in rates, and the remaining variance that exceeds the 2% variance is deferred.

These decreases in margins were partially offset by $9.0 million of lower capacity payments to a counterparty during the second quarter of 2017.

Natural Gas Utility Margins

Natural gas utility margins at the Wisconsin segment decreased $4.8 million during the second quarter of 2017, compared with the same quarter in 2016. The most significant factor impacting the lower natural gas utility margins were lower retail sales volumes, primarily driven by warmer weather. As measured by heating degree days, the second quarter of 2017 was 19.2% and 13.5% warmer than the same period in 2016 in the Milwaukee and Green Bay areas, respectively.

Operating Income

Operating income at the Wisconsin segment increased $8.9 million during the second quarter of 2017, compared with the same quarter in 2016. This increase was driven by $22.1 million of lower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes), partially offset by the $13.2 million decrease in margins discussed above.

The Wisconsin segment experienced lower overall operating expenses related to synergy savings resulting from the Integrys acquisition. The significant factors impacting the decrease in operating expenses, which were due in part to synergy savings, were:


•	A $10.3 million decrease in operation and maintenance expenses at our plants, primarily related to the seasonal operation of the Pleasant Prairie Power Plant and the timing of planned outages and maintenance.


•	A $10.2 million decrease in electric and natural gas distribution expenses.


•	A $6.4 million decrease in benefit costs, primarily driven by lower pension and OPEB costs.


•	A $5.9 million decrease in expenses related to an information technology project created to improve the billing, call center, and credit collection functions of the Integrys subsidiaries. Lower expenses were due in part to a decrease in asset usage charges from WBS, driven by the transfer of this project from WBS to WPS in 2017.

These decreases 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 on the sale of the MCPP.


•	A $7.6 million increase in depreciation and amortization, driven by the completion of the ReACT ^TM multi-pollutant control system at Weston Unit 3 during the fourth quarter of 2016 and an overall increase in utility plant in service.



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Illinois Segment Contribution to Operating Income



	Three Months Ended June 30
(in millions)	2017		2016		B (W)
Natural gas revenues	$	253.2	$	222.8	$	30.4
Cost of natural gas sold	64.1		46.2		(17.9		)
Total natural gas margins	189.1		176.6		12.5

Other operation and maintenance	104.9		116.2		11.3
Depreciation and amortization	37.5		33.1		(4.4		)
Property and revenue taxes	5.3		4.7		(0.6		)
Operating income	$	41.4	$	22.6	$	18.8

The following table shows a breakdown of other operation and maintenance:



	Three Months Ended June 30
(in millions)	2017		2016		B (W)
Operation and maintenance not included in the line items below	$	84.6	$	99.9	$	15.3
Riders *	19.4		12.7		(6.7		)
Regulatory amortizations *	0.5		0.7		0.2
Other	0.4		2.9		2.5
Total other operation and maintenance	$	104.9	$	116.2	$	11.3


*	Riders and regulatory amortizations are substantially offset in margins and therefore do not have a significant impact on operating income.

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



	Three Months Ended June 30
	Therms (in millions)
Natural Gas Sales Volumes	2017	2016	B (W)
Customer Class
Residential	132.8	138.6	(5.8	)
Commercial and industrial	27.5	27.2	0.3
Total retail	160.3	165.8	(5.5	)
Transport	144.5	156.7	(12.2	)
Total sales in therms	304.8	322.5	(17.7	)



	Three Months Ended June 30
	Degree Days
Weather *	2017	2016	B (W)
Heating (695 Normal)	602	756	(154	)


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

Natural Gas Utility Margins

Natural gas utility margins, net of the $6.7 million impact of the riders referenced in the table above, increased $5.8 million during the second quarter of 2017, compared with the same quarter in 2016. The increase was primarily driven by an increase in revenue at PGL due to continued capital investment in the SMP project under its QIP rider. PGL currently recovers the costs related to the SMP through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023.



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Operating Income

Operating income at the Illinois segment increased $18.8 million during the second quarter of 2017, compared with the same quarter in 2016. This increase was due to the $5.8 million net increase in margins discussed above and a $13.0 million decrease in operating expenses, net of the impact of the riders referenced in the table above. The significant factors impacting the decrease in operating expenses were:


•	A $7.5 million decrease in benefit costs driven by lower pension costs.


•	A $4.1 million decrease driven by the residual impact of the warmer weather this past winter leading to reduced need for repair and maintenance activity.

Other States Segment Contribution to Operating Income



	Three Months Ended June 30
(in millions)	2017		2016		B (W)
Natural gas revenues	$	65.7	$	64.0	$	1.7
Cost of natural gas sold	27.4		23.6		(3.8		)
Total natural gas margins	38.3		40.4		(2.1		)

Other operation and maintenance	23.3		29.4		6.1
Depreciation and amortization	6.1		5.2		(0.9		)
Property and revenue taxes	4.2		3.5		(0.7		)
Operating income	$	4.7	$	2.3	$	2.4

The following table shows a breakdown of other operation and maintenance:



	Three Months Ended June 30
(in millions)	2017		2016		B (W)
Operation and maintenance not included in line item below	$	18.2	$	24.1	$	5.9
Regulatory amortizations and other pass through expenses *	5.1		5.3		0.2
Total other operation and maintenance	$	23.3	$	29.4	$	6.1


*	Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income.

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



	Three Months Ended June 30
	Therms (in millions)
Natural Gas Sales Volumes	2017	2016	B (W)
Customer Class
Residential	39.6	41.7	(2.1	)
Commercial and industrial	27.7	27.8	(0.1	)
Total retail	67.3	69.5	(2.2	)
Transport	167.6	157.1	10.5
Total sales in therms	234.9	226.6	8.3



	Three Months Ended June 30
	Degree Days
Weather *	2017	2016	B (W)
Heating (858 Normal)	776	848	(72	)


*	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.



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Operating Income

Operating income at the other states segment increased $2.4 million during the second quarter of 2017, compared to the same quarter last year. The increase was primarily driven by lower operation and maintenance expense due to effective cost control measures.

Non-Utility Energy Segment Contribution to Operating Income



	Three Months Ended June 30
(in millions)	2017		2016		B (W)
Operating income	$	98.7	$	94.1	$	4.6

Operating income at the non-utility energy segment increased $4.6 million , or 4.9%, when compared to the second quarter of 2016. This increase was primarily related to higher revenues in connection with capital additions to the plants We Power owns and leases to WE. See Note 14, Segment Information, for more information on the change in segment name.

Corporate and Other Segment Contribution to Operating Income



	Three Months Ended June 30
(in millions)	2017			2016			B (W)
Operating loss	$	(6.2	)	$	(1.6	)	$	(4.6	)

Operating loss at the corporate and other segment increased $4.6 million, when compared to the second quarter of 2016 due to higher general corporate expenses.

Electric Transmission Segment Operations



	Three Months Ended June 30
(in millions)	2017		2016		B (W)
Equity in earnings of transmission affiliate	$	41.8	$	30.9	$	10.9

Equity in earnings of transmission affiliate increased $10.9 million , or 35.3% , when compared to the second quarter of 2016 . Lower earnings in the second quarter of 2016 were the result of an ALJ recommendation related to the FERC ROE reviews. See Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints for more information.

Consolidated Other Income, Net



	Three Months Ended June 30
(in millions)	2017		2016		B (W)
AFUDC – Equity	$	2.9	$	7.0	$	(4.1	)
Gain on sale of certain assets of Wisvest	—		19.6		(19.6		)
Other, net	10.2		5.8		4.4
Other income, net	$	13.1	$	32.4	$	(19.3	)

Other Income, net decreased by $19.3 million when compared to the second quarter of 2016. The decrease was primarily due to the $19.6 million gain recorded in April 2016 from the sale of the chilled water generation and distribution assets of Wisvest as well as lower AFUDC largely due to the ReACT ^TM emission control technology project at Weston Unit 3 going into service during the fourth quarter of 2016. See Note 3, Dispositions, for more information on our asset sales.

Consolidated Interest Expense



	Three Months Ended June 30
(in millions)	2017		2016		B (W)
Interest expense	$	101.9	$	100.1	$	(1.8	)



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Consolidated Income Tax Expense



	Three Months Ended June 30
	2017		2016		B (W)
Effective tax rate	36.7	%	38.5	%	1.8	%

Our effective tax rate decreased by 1.8% when compared to the second quarter of 2016, in part due to the recognition of excess tax benefits related to share-based payments and favorable compensation expense in the second quarter of 2017. See Note 4, Common Equity, for more information on the excess tax benefits related to share-based payments.

SIX MONTHS ENDED JUNE 30, 2017

Consolidated Earnings

The following table compares our consolidated results for the first six months of 2017 with the first six months of 2016 , including favorable or better, "B", and unfavorable or worse, "W", variances:



	Six Months Ended June 30
(in millions, except per share data)	2017			2016			B (W)
Wisconsin	$	555.9		$	542.2		$	13.7
Illinois	196.8			159.6			37.2
Other states	38.1			34.1			4.0
Non-utility energy	196.1			187.4			8.7
Corporate and other	(7.4		)	(1.9		)	(5.5		)
Total operating income	979.5			921.4			58.1
Equity in earnings of transmission affiliate	83.7			69.4			14.3
Other income, net	28.8			65.1			(36.3		)
Interest expense	206.6			201.0			(5.6		)
Income before income taxes	885.4			854.9			30.5
Income tax expense	329.1			326.7			(2.4		)
Preferred stock dividends of subsidiary	0.6			0.6			—
Net income attributed to common shareholders	$	555.7		$	527.6		$	28.1

Diluted Earnings Per Share	$	1.75		$	1.66		$	0.09

Earnings increased $28.1 million during the first six months of 2017 , compared with same period in 2016 . The significant factors impacting the increase in earnings were:


•	A $37.2 million pre-tax ($22.3 million after tax) increase in operating income at the Illinois segment. The increase was driven by lower operating expenses and higher natural gas margins at PGL due to continued capital investment in projects under its QIP rider.


•	A $14.3 million pre-tax ($8.6 million after tax) increase in earnings from our ownership interest in ATC. In 2016, ATC recognized lower earnings as a result of an ALJ recommendation related to the FERC ROE reviews. See Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints for more information.


•	A $13.7 million pre-tax ($8.2 million after tax) increase in operating income at the Wisconsin segment driven by lower operating expenses. Partially offsetting the lower operating expenses was a decrease in electric and natural gas margins driven by lower sales volumes.


•	A 1.0% decrease in our effective tax rate also drove an increase in earnings. The decrease in our effective tax rate was in part due to the recognition of excess tax benefits related to share-based payments and favorable compensation expense in the first six months of 2017.



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These increases in earnings were partially offset by a $36.3 million pre-tax ($21.8 million after tax) decrease in other income, net. The decrease was driven by the period-over-period impact of the gains recognized in 2016 related to the repurchase of a portion of Integrys's 6.11% Junior Notes and the sale of certain assets of Wisvest. See Note 3, Dispositions, for more information on the Wisvest sale.

Non-GAAP Financial Measure

The discussions below address the operating income contribution of each of our segments and include financial information prepared in accordance with GAAP, as well as electric margins and natural gas margins, which are not measures of financial performance under GAAP. Electric margin (electric revenues less fuel and purchased power costs) and natural gas margin (natural gas revenues less cost of natural gas sold) are non-GAAP financial measures because they exclude other operation and maintenance expense, depreciation and amortization, and property and revenue taxes.

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of our segment operating performance. Operating income for the six months ended June 30, 2017 and 2016 for each of our segments is presented in the “Consolidated Earnings” table above.

Wisconsin Segment Contribution to Operating Income



	Six Months Ended June 30
(in millions)	2017		2016		B (W)
Electric revenues	$	2,206.0	$	2,214.4	$	(8.4	)
Fuel and purchased power	695.5		679.4		(16.1		)
Total electric margins	1,510.5		1,535.0		(24.5		)

Natural gas revenues	709.3		670.2		39.1
Cost of natural gas sold	401.7		356.9		(44.8		)
Total natural gas margins	307.6		313.3		(5.7		)

Total electric and natural gas margins	1,818.1		1,848.3		(30.2		)

Other operation and maintenance	921.6		979.1		57.5
Depreciation and amortization	259.6		245.6		(14.0		)
Property and revenue taxes	81.0		81.4		0.4
Operating income	$	555.9	$	542.2	$	13.7



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The following table shows a breakdown of other operation and maintenance:



	Six Months Ended June 30
(in millions)	2017		2016		B (W)
Operation and maintenance not included in line items below	$	375.7	$	432.8	$	57.1
We Power ⁽¹⁾	254.7		255.9		1.2
Transmission ⁽²⁾	210.0		211.6		1.6
Regulatory amortizations and other pass through expenses ⁽³⁾	81.2		78.8		(2.4		)
Total other operation and maintenance	$	921.6	$	979.1	$	57.5

⁽¹⁾

Represents costs associated with the We Power generation units, including operating and maintenance costs incurred by WE, as well as the lease payments that are billed from We Power to WE and then recovered in WE's rates. During the six months ended June 30, 2017 and 2016 , $265.0 million and $263.5 million , respectively, of both lease and operating and maintenance costs were billed to or incurred by WE, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

⁽²⁾

The PSCW has approved escrow accounting for ATC and MISO network transmission expenses for our Wisconsin electric utilities. As a result, WE and WPS defer as a regulatory asset or liability the differences between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the six months ended June 30, 2017 and 2016 , $201.5 million and $243.9 million , respectively, of costs were billed by transmission providers to our electric utilities.


⁽³⁾	Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income.

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	2017	2016	B (W)
Customer Class
Residential	5,053.5	5,110.6	(57.1	)
Small commercial and industrial *	6,306.2	6,369.2	(63.0	)
Large commercial and industrial *	6,304.8	6,831.3	(526.5	)
Other	87.1	87.6	(0.5	)
Total retail *	17,751.6	18,398.7	(647.1	)
Wholesale	1,876.6	1,753.4	123.2
Resale	3,517.7	4,094.5	(576.8	)
Total sales in MWh *	23,145.9	24,246.6	(1,100.7	)


*	Includes 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	2017	2016	B (W)
Customer Class
Residential	609.5	638.2	(28.7	)
Commercial and industrial	366.0	371.7	(5.7	)
Total retail	975.5	1,009.9	(34.4	)
Transport	676.3	671.5	4.8
Total sales in therms	1,651.8	1,681.4	(29.6	)



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	Six Months Ended June 30
	Degree Days
Weather	2017	2016	B(W)
WE and WG ⁽¹⁾
Heating (4,215 normal)	3,597	4,031	(434	)
Cooling (161 normal)	203	196	7

WPS ⁽²⁾
Heating (4,609 normal)	4,107	4,402	(295	)
Cooling (131 normal)	125	142	(17	)

UMERC ⁽³⁾
Heating (5,137 normal)	4,803	N/A	N/A
Cooling (79 normal)	47	N/A	N/A


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


⁽²⁾	Normal degree days are based on a 20-year moving average of monthly temperatures from the Green Bay, Wisconsin weather station.


⁽³⁾	Normal degree days are based on a 20-year moving average of monthly temperatures from the Iron Mountain, Michigan weather station.

Electric Utility Margins

Electric utility margins at the Wisconsin segment decreased $24.5 million during the first six months of 2017, compared with the same period in 2016. The significant factors impacting the lower electric utility margins were:

•

A $24.9 million decrease related to lower sales volumes during the first six months of 2017, primarily driven by lower overall retail use per customer. Warmer winter weather and an additional day of sales during the same period in 2016 due to leap year also contributed to the decrease. As measured by heating degree days, the first six months of 2017 were 10.8% and 6.7% warmer than the same period in 2016 in the Milwaukee and Green Bay areas, respectively.

•

A $10.8 million negative impact from collections of fuel and purchased power costs compared with costs approved in rates in the first six months of 2017, as compared with the same period in 2016. Under the Wisconsin fuel rules, the margins of our electric utilities are impacted by under or over-collections of certain fuel and purchased power costs that are less than a 2% price variance from the costs included in rates, and the remaining variance that exceeds the 2% variance is deferred.


•	A $4.7 million decrease in steam margins related to the sale of the MCPP in April 2016. See Note 3, Dispositions, for more information .

These decreases in margins were partially offset by $18.0 million of lower capacity payments to a counterparty during the first six months of 2017.

Natural Gas Utility Margins

Natural gas utility margins at the Wisconsin segment decreased $5.7 million during the first six months of 2017, compared with the same period in 2016. The most significant factor impacting the lower natural gas utility margins were lower retail sales volumes, primarily driven by warmer weather. As measured by heating degree days, the first six months of 2017 were 10.8% and 6.7% warmer than the same period in 2016 in the Milwaukee and Green Bay areas, respectively. An additional day of sales during 2016 due to leap year also contributed to the decrease. The lower margins were partially offset by higher overall retail use per customer.

Operating Income

Operating income at the Wisconsin segment increased $13.7 million during the first six months of 2017, compared with the same period in 2016. This increase was driven by $43.9 million of lower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes), partially offset by the $30.2 million decrease in margins discussed above.



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•	A $17.9 million decrease in operation and maintenance expenses at our plants, primarily related to the seasonal operation of the Pleasant Prairie Power Plant, the timing of planned outages and maintenance, and the sale of the MCPP in April 2016. See Note 3, Dispositions, for more information on the sale of the MCPP.


•	A $16.8 million decrease in electric and natural gas distribution expenses.


•	A $13.4 million decrease in benefit costs, partially driven by lower pension and OPEB costs, lower employee medical costs, and lower stock-based compensation expense.


•	An $8.2 million decrease in expenses related to an information technology project created to improve the billing, call center, and credit collection functions of the Integrys subsidiaries. Lower expenses were due in part to a decrease in asset usage charges from WBS, driven by the transfer of this project from WBS to WPS in 2017.

These decreases in operating expenses were partially offset by:


•	A $14.0 million increase in depreciation and amortization, driven by the completion of the ReACT ^TM multi-pollutant control system at Weston Unit 3 during the fourth quarter of 2016 and an overall increase in utility plant in service.


•	A $10.9 million gain on the sale of the MCPP, which was sold in April 2016. See Note 3, Dispositions, for more information on the sale of the MCPP.

Illinois Segment Contribution to Operating Income



	Six Months Ended June 30
(in millions)	2017		2016		B (W)
Natural gas revenues	$	778.5	$	671.3	$	107.2
Cost of natural gas sold	271.8		203.5		(68.3		)
Total natural gas margins	506.7		467.8		38.9

Other operation and maintenance	225.8		234.1		8.3
Depreciation and amortization	73.7		65.9		(7.8		)
Property and revenue taxes	10.4		8.2		(2.2		)
Operating income	$	196.8	$	159.6	$	37.2

The following table shows a breakdown of other operation and maintenance:



	Six Months Ended June 30
(in millions)	2017		2016		B (W)
Operation and maintenance not included in the line items below	$	162.4	$	194.0	$	31.6
Riders *	61.7		35.8		(25.9		)
Regulatory amortizations *	1.2		1.3		0.1
Other	0.5		3.0		2.5
Total other operation and maintenance	$	225.8	$	234.1	$	8.3


*	Riders and regulatory amortizations are substantially offset in margins and therefore do not have a significant impact on operating income.



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



	Six Months Ended June 30
	Therms (in millions)
Natural Gas Sales Volumes	2017	2016	B (W)
Customer Class
Residential	539.8	570.2	(30.4	)
Commercial and industrial	113.2	115.6	(2.4	)
Total retail	653.0	685.8	(32.8	)
Transport	472.8	502.6	(29.8	)
Total sales in therms	1,125.8	1,188.4	(62.6	)



	Six Months Ended June 30
	Degree Days
Weather *	2017	2016	B (W)
Heating (3,866 Normal)	3,263	3,664	(401	)


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

Natural Gas Utility Margins

Natural gas utility margins, net of the $25.9 million impact of the riders referenced in the table above, increased $13.0 million during the six months ended June 30, 2017, compared with the same period in 2016. The increase was primarily driven by an increase in revenue at PGL due to continued capital investment in the SMP project under its QIP rider. PGL currently recovers the costs related to the SMP through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023.

Operating Income

Operating income at the Illinois segment increased $37.2 million during the six months ended June 30, 2017, compared with the same period in 2016. This increase was due to the $13.0 million net increase in margins discussed above and a $24.2 million decrease in operating expenses, net of the impact of the riders referenced in the table above. The significant factors impacting the decrease in operating expenses were:


•	A $16.5 million decrease in benefit costs driven by lower pension costs.


•	An $8.8 million decrease driven by the residual impact of the warmer weather this past winter leading to reduced need for repair and maintenance activity.

Other States Segment Contribution to Operating Income



	Six Months Ended June 30
(in millions)	2017		2016		B (W)
Natural gas revenues	$	223.6	$	212.4	$	11.2
Cost of natural gas sold	113.8		102.0		(11.8		)
Total natural gas margins	109.8		110.4		(0.6		)

Other operation and maintenance	51.6		59.4		7.8
Depreciation and amortization	12.1		10.3		(1.8		)
Property and revenue taxes	8.0		6.6		(1.4		)
Operating income	$	38.1	$	34.1	$	4.0



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The following table shows a breakdown of other operation and maintenance:



	Six Months Ended June 30
(in millions)	2017		2016		B (W)
Operation and maintenance not included in line item below	$	37.8	$	45.0	$	7.2
Regulatory amortizations and other pass through expenses *	13.8		14.4		0.6
Total other operation and maintenance	$	51.6	$	59.4	$	7.8


*	Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income.

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



	Six Months Ended June 30
	Therms (in millions)
Natural Gas Sales Volumes	2017	2016	B (W)
Customer Class
Residential	173.4	183.7	(10.3	)
Commercial and industrial	111.6	115.4	(3.8	)
Total retail	285.0	299.1	(14.1	)
Transport	359.0	384.2	(25.2	)
Total sales in therms	644.0	683.3	(39.3	)



	Six Months Ended June 30
	Degree Days
Weather *	2017	2016	B (W)
Heating (4,416 Normal)	3,910	4,079	(169	)


*	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.

Operating Income

Operating income at the other states segment increased $4.0 million during the six months ended June 30, 2017, compared with the same period in 2016. The increase was primarily driven by lower operation and maintenance expense due to effective cost control measures.

Non-Utility Energy Segment Contribution to Operating Income



	Six Months Ended June 30
(in millions)	2017		2016		B (W)
Operating income	$	196.1	$	187.4	$	8.7

Operating income at the non-utility energy segment increased $8.7 million , or 4.6%, when compared to the first six months of 2016. This increase was primarily related to higher revenues in connection with capital additions to the plants We Power owns and leases to WE. See Note 14, Segment Information, for more information on the change in segment name.

Corporate and Other Segment Contribution to Operating Income



	Six Months Ended June 30
(in millions)	2017			2016			B (W)
Operating loss	$	(7.4	)	$	(1.9	)	$	(5.5	)

Operating loss at the corporate and other segment increased $5.5 million, when compared to the first six months of 2016 due to higher general corporate expenses.



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Electric Transmission Segment Operations



	Six Months Ended June 30
(in millions)	2017		2016		B (W)
Equity in earnings of transmission affiliate	$	83.7	$	69.4	$	14.3

Equity in earnings of transmission affiliate increased $14.3 million , or 20.6% , when compared to the first six months of 2016 . Lower earnings during the first six months of 2016 were the result of an ALJ recommendation related to the FERC ROE reviews. See Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints for more information.

Consolidated Other Income, Net



	Six Months Ended June 30
(in millions)	2017		2016		B (W)
AFUDC – Equity	$	5.3	$	14.0	$	(8.7	)
Gain on repurchase of notes	—		23.6		(23.6		)
Gain on sale of certain assets of Wisvest	—		19.6		(19.6		)
Other, net	23.5		7.9		15.6
Other income, net	$	28.8	$	65.1	$	(36.3	)

Other income, net decreased by $36.3 million when compared to the first six months of 2016 . The decrease was primarily due to the $23.6 million gain on the repurchase of a portion of Integrys's 6.11% Junior Notes at a discount in February 2016, a $19.6 million gain recorded in April 2016 from the sale of the chilled water generation and distribution assets of Wisvest, and lower AFUDC largely due to the ReACT ^TM emission control technology project at Weston Unit 3 going into service during the fourth quarter of 2016. These decreases were offset in part by a $7.7 million increase in gains on investments held in the rabbi trust during the first six months of 2017, compared with the same period in 2016. See Note 3, Dispositions, for more information on our asset sales.

Consolidated Interest Expense



	Six Months Ended June 30
(in millions)	2017		2016		B (W)
Interest expense	$	206.6	$	201.0	$	(5.6	)

Interest expense increased by $5.6 million, as compared to the first six months of 2016 . The increase was primarily due to lower capitalized interest in the first six months of 2017 as a result of the completion of the ReACT ^TM emission control project in the fourth quarter of 2016.

Consolidated Income Tax Expense



	Six Months Ended June 30
	2017		2016		B (W)
Effective tax rate	37.2	%	38.2	%	1.0	%

Our effective tax rate decreased by 1.0% when compared to the first six months of 2016, in part due to the recognition of excess tax benefits related to share-based payments and favorable compensation expense in the first six months of 2017. See Note 4, Common Equity, for more information on the excess tax benefits related to share-based payments. We expect our 2017 annual effective tax rate to be between 37.0% and 38.0%.



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LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

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



(in millions)	2017			2016			Change in 2017 Over 2016
Cash provided by (used in):
Operating activities	$	1,268.0		$	1,224.1		$	43.9
Investing activities	(1,023.9		)	(449.1		)	(574.8		)
Financing activities	(245.1		)	(792.7		)	547.6

Operating Activities

Net cash provided by operating activities increased $43.9 million during the first six months of 2017, compared with the same period in 2016, driven by:


•	A $188.7 million increase in cash related to higher overall collections from customers, primarily due to higher commodity prices. The average per-unit cost of natural gas sold increased 23.6% during the first six months of 2017, compared with the same period in 2016.


•	A $76.3 million increase in cash from lower payments for operating and maintenance costs. During the first six months of 2017, our payments related to transmission, electric and natural gas distribution costs, electric generation costs, and employee benefits decreased.

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


•	A $113.1 million decrease in cash resulting from higher payments for natural gas and fuel and purchased power, primarily due to higher commodity prices during the first six months of 2017, compared with the same period in 2016.


•	A $92.0 million increase in contributions and payments to our pension and OPEB plans during the first six months of 2017.

Investing Activities

Net cash used in investing activities increased $574.8 million during the first six months of 2017, compared with the same period in 2016, driven by:


•	The acquisition of Bluewater during June 2017 for $226.0 million . See Note 2, Acquisition, for more information .


•	A $171.3 million increase in cash paid for capital expenditures during the first six months of 2017, compared with the same period in 2016, which is discussed in more detail below.


•	A $140.3 million decrease in the proceeds received from the sale of assets and businesses during the first six months of 2017, compared with the same period in 2016. See Note 3, Dispositions, for more information .

•

A $38.4 million increase in our capital contributions to ATC during the first six months of 2017, compared with the same period in 2016, due to the continued investment in equipment and facilities by ATC to improve reliability. The refunds and reserves resulting from the ATC ROE complaints filed with the FERC also contributed to the increase in our capital contributions. See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints for more information on these ATC ROE complaints.



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Capital Expenditures

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



Reportable Segment (in millions)	2017		2016		Change in 2017 Over 2016
Wisconsin	$	463.4	$	400.5	$	62.9
Illinois	204.7		137.1		67.6
Other states	30.8		22.7		8.1
Non-utility energy	13.0		24.3		(11.3		)
Corporate and other	78.1		34.1		44.0
Total capital expenditures	$	790.0	$	618.7	$	171.3

The increase in cash paid for capital expenditures at the Wisconsin segment during the first six months of 2017 was driven by upgrades to WE's electric and natural gas distribution systems, including meter and main replacement projects, WPS's SMRP, and various projects at the OCPP. These increases in capital expenditures were partially offset by lower expenditures at WPS for both the ReACT ^TM emission control technology project at Weston Unit 3 and a combustion turbine project at the Fox Energy Center.

The increase in cash paid for capital expenditures at the Illinois segment during the first six months of 2017 was driven by increased construction activity related to PGL's SMP and a project to relocate one of PGL's service facilities.

The increase in cash paid for capital expenditures at the corporate and other segment during the first six months of 2017 was primarily driven by a project to implement a new enterprise resource planning system.

See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital Requirements – Significant Capital Projects for more information.

Financing Activities

Net cash used in financing activities decreased $547.6 million during the first six months of 2017, compared with the same period in 2016, driven by:


•	A $227.2 million decrease in cash used for the repayment of long-term debt during the first six months of 2017, compared with the same period in 2016. In February 2016, we repurchased a portion of Integrys's 2006 Junior Notes at a discount.


•	A $210.0 million issuance of long-term debt during the first six months of 2017. In June 2017, MERC and MGU issued $120.0 million and $90.0 million, respectively, of senior notes.


•	An $81.8 million decrease in the repayment of commercial paper during the first six months of 2017, compared with the same period in 2016.


•	A $54.5 million decrease in cash used to purchase shares of our common stock during the first six months of 2017, compared with the same period in 2016, to satisfy requirements of our stock-based compensation plans.

These decrease s in net cash used in financing activities were partially offset by a $19.4 million decrease in cash received from stock option exercises during the first six months of 2017, compared with the same period in 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 .



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Capital Resources and Requirements

Capital Resources

Liquidity

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

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, 2017 , as well as an adjusted capitalization structure that we believe is consistent with how a majority of the rating agencies currently view our 2007 Junior Notes:



(in millions)	Actual			Adjusted
Common equity	$	9,152.8		$	9,402.8
Preferred stock of subsidiary	30.4			30.4
Long-term debt (including current portion)	9,508.1			9,258.1
Short-term debt	774.8			774.8
Total capitalization	$	19,466.1		$	19,466.1

Total debt	$	10,282.9		$	10,032.9

Ratio of debt to total capitalization	52.8		%	51.5		%

Included in long-term debt on our balance sheet as of June 30, 2017 , is $500.0 million principal amount of 2007 Junior Notes. The adjusted presentation attributes $250.0 million of the 2007 Junior Notes to common equity and $250.0 million to long-term debt.

The adjusted presentation of our consolidated capitalization structure is included 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 2007 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.

As of June 30, 2017 , WE was the obligor under a series of tax-exempt pollution control refunding bonds with an outstanding principal amount of $80.0 million. In August 2009, WE terminated a letter of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. WE purchased the bonds at par plus accrued interest to the date of purchase. As of June 30, 2017 , the repurchased bonds were still outstanding but are not reported in our long-term debt since they are held by WE. Depending on market conditions and other factors, WE may change the method used to determine the interest rate on this bond series and have it remarketed to third parties.

Working Capital

As of June 30, 2017 , our current liabilities exceeded our current assets by $1,007.6 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.



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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. 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 July 2017, Moody's downgraded the ratings of WE (senior unsecured), WPS (senior unsecured), WG (senior unsecured), and Elm Road Generating Station Supercritical, LLC (senior secured) to A2 from A1. Moody's affirmed the commercial paper ratings of WE (P-1), WPS (P-1), and WG (P-1). Moody's also affirmed the ratings of WEC Energy Group (senior unsecured, A3), Wisconsin Energy Capital Corporation (senior unsecured, A3), and Integrys (senior unsecured, A3), but changed the rating outlook for these companies from stable to negative. We do not believe the change in ratings and 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.

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)	2017		2018		2019
Wisconsin	$	1,146.1	$	1,270.5	$	1,203.8
Illinois	544.8		517.7		523.4
Other states	91.0		102.7		106.8
Non-utility energy	268.4		35.0		36.4
Corporate and other	131.9		30.9		28.9
Total	$	2,182.2	$	1,956.8	$	1,899.3

WPS is continuing work on the SMRP. This project includes modernizing parts of its electric distribution system, including burying or upgrading lines. The project focuses on constructing facilities to improve the reliability of electric service WPS provides to its customers. WPS expects to invest approximately $300 million between 2017 and 2021 on this project. WE, WPS, and WG will also continue to upgrade their electric and natural gas distribution systems to enhance reliability. These upgrades include the advanced metering infrastructure (AMI) program. AMI is an integrated system of smart meters, communication networks and data management systems that enable two-way communication between utilities and customers.

In connection with the formation of UMERC, we entered into an agreement with Tilden Mining Company under which it will purchase electric power from UMERC for 20 years. The agreement calls for UMERC to construct and operate approximately 180 MW of natural gas-fired generation located in the Upper Peninsula of Michigan. The estimated cost of this project is approximately $265 million ($275 million including AFUDC). See Note 18, Regulatory Environment, for more information about UMERC and this new generation.

On June 30, 2017, we completed the acquisition of Bluewater for $226 million. Bluewater owns natural gas storage facilities in Michigan that will provide approximately one-third of the current storage needs for our Wisconsin natural gas utilities. In addition, we accrued approximately $5 million of acquisition related costs. See Note 2, Acquisition, for more information on this transaction.



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PGL is continuing work on the SMP, 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 QIP rider, which is in effect through 2023. PGL's projected average annual investment through 2019 is between $280 million and $300 million. See Note 18, Regulatory Environment, for more information on the SMP.

We expect to provide total capital contributions to ATC (not included in the above table) of approximately $226 million from 2017 through 2019 .

Common Stock Dividends

Our current quarterly dividend rate is $0.52 per share, which equates to an annual dividend of $2.08 per share. For information related to our most recent common stock dividend declared, see Note 4, Common Equity .

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 2016 Annual Report on Form 10-K.

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity, and capital resources. The following discussion should be read together with the information in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources in our 2016 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 2016 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 the 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 the 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.



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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 the deferral of costs related to WPS's ReACT™ project above the originally authorized $275.0 million level through 2017. The total cost of the ReACT™ project, excluding $51 million of AFUDC, is currently estimated to be $342 million. In April 2017, WPS requested an extension of this deferral through 2019 as part of a settlement agreement. We expect the PSCW to issue a final order on the settlement agreement during the third quarter of 2017. See Note 18, Regulatory Environment, for more information . WPS will be required to obtain a separate approval for collection of these deferred costs in a future rate case.

•

Prior to its 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, 2017 , we had not received any significant disallowances of the costs incurred for this project. 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 QIP rider as a recovery mechanism for costs incurred related to investments in QIP. This rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2017, PGL filed its 2016 reconciliation with the ICC, which, along with the 2015 reconciliation, is still pending. For PGL's 2014 reconciliation, the ICC staff and the Illinois Attorney General's office filed testimony in June 2017. PGL filed rebuttal testimony in July 2017, and we expect to receive an order related to the 2014 reconciliation in the fourth quarter of 2017. As of June 30, 2017 , there can be no assurance that all costs incurred under the QIP rider during the open reconciliation years 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

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

Other Matters

American Transmission Company Allowed Return on Equity Complaints

In November 2013, a group of MISO industrial customer organizations filed a complaint with the FERC requesting to reduce the base ROE used by MISO transmission owners, including ATC, from 12.2% to 9.15%. In October 2014, the FERC issued an order to hear the complaint on ROE and set a refund effective date retroactive to November 2013. In December 2015, the ALJ issued an initial decision recommending 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 incentive adder only applies to revenues collected after January 6, 2015. In September 2016, the FERC issued a final order related to this complaint affirming the use of the ROEs stated in the ALJ's initial decision, effective as of the order date, on a going-forward basis. The order also required ATC to provide refunds, with interest, for the 15-month refund period from November 13, 2013, through February 11, 2015. The refunds ATC provided to WE and WPS for transmission costs paid during the refund period reduced the regulatory assets recorded under the PSCW-approved escrow accounting for transmission expense and resulted in a net regulatory liability of $6.9 million for WPS.

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. In June 2016, the ALJ issued an initial decision recommending 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. We are uncertain when a FERC order related to this matter will be issued.

MISO transmission owners have filed various appeals related to several of the FERC orders with the D.C. Circuit Court of Appeals as well as requests for rehearing.



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The decrease in ATC's ROE resulting from the FERC's final order issued in September 2016 will have a negative impact on our equity earnings and distributions from ATC in the future.



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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, 2016 . 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 2017 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.



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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The following should be read in conjunction with Item 3. Legal Proceedings in Part I of our 2016 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 referenced above and discussed below, 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. Substantial remediation of the uplands at the legacy Sheboygan Camp Marina manufactured gas plant site has already occurred. We agreed to settle this matter, subject to the approval of the United States District Court for the Eastern District of Wisconsin. The terms of the settlement, if approved, will not have a material impact on our financial statements.

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors presented in our Annual Report on Form 10-K for the year ended December 31, 2016 . See Item 1A. Risk Factors in Part I of our 2016 Annual Report on Form 10-K for a discussion of certain risk factors applicable to us.



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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, 2017 :

Issuer Purchases of Equity Securities



2017	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	527	60.78		—	$	—
June 1 – June 30	—	—		—	$	—
Total *	527	$	60.78	—


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



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ITEM 6. EXHIBITS



Number	Exhibit
10	Material Contracts

	10.1	Integrys Energy Group, Inc. Pension Restoration and Supplemental Retirement Plan, as Amended and Restated effective January 1, 2017.

31	Rule 13a-14(a) / 15d-14(a) Certifications

	31.1	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31.2	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32	Section 1350 Certifications

	32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

	32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101	Interactive Data File



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SIGNATURE

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



		WEC ENERGY GROUP, INC.
		(Registrant)

		/s/ WILLIAM J. GUC
Date:	August 4, 2017	William J. Guc
		Vice President and Controller

		(Duly Authorized Officer and Chief Accounting Officer)



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Exhibit 10.1

INTEGRYS ENERGY GROUP, INC.

PENSION RESTORATION AND

SUPPLEMENTAL RETIREMENT PLAN

As Amended and Restated Effective January 1, 2017

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	7

ARTICLE II. PAYMENT ELECTIONS			8
	Section 2.01.	General Rules	8
	Section 2.02.	Participant Payment Election	8

ARTICLE III. PENSION RESTORATION BENEFIT			10
	Section 3.01.	Eligibility	10
	Section 3.02.	Pension Restoration Benefit Formula	10
	Section 3.03.	Distribution of Single Sum Benefits	10
	Section 3.04.	Distribution of 180 Month Period Certain Installment Benefit	11
	Section 3.05.	Distribution of Annuity Benefits	11
	Section 3.06.	Death Benefits	13

ARTICLE IV. SUPPLEMENTAL RETIREMENT BENEFIT			14
	Section 4.01.	Eligibility	14
	Section 4.02.	Final Average Earnings	14
	Section 4.03.	Supplemental Retirement Benefit Formula	14
	Section 4.04.	Distribution of Single Sum Benefits	16
	Section 4.05.	Distribution of 180 Month Period Certain Installment Benefit	16
	Section 4.06.	Distribution of Annuity Benefits	16
	Section 4.07.	Death Benefits	17

ARTICLE V. SPECIAL DEFINED CONTRIBUTION CREDITS			19
	Section 5.01.	Application	19
	Section 5.02.	Distribution In Accordance With This Plan	19
	Section 5.03.	Distribution of Single Sum Benefits	19
	Section 5.04.	Distribution of 180 Month Period Certain Installment Benefit	19
	Section 5.05.	Distribution of Annuity Benefits	20
	Section 5.06.	Death Benefits	20

ARTICLE VI. SPECIAL RULES APPLICABLE IN THE EVENT OF A CHANGE IN CONTROL OF THE COMPANY			22
	Section 6.01.	Application	22
	Section 6.02.	Definitions	22
	Section 6.03.	Special Provisions Following Change in Control	23
	Section 6.04.	Maximum Payment Limitation	25
	Section 6.05.	Resolution of Disputes	26

ARTICLE VII. GENERAL PROVISIONS			27
	Section 7.01.	Administration	27
	Section 7.02.	Claims Procedures	27
	Section 7.03	Participant Rights Unsecured	28
	Section 7.04.	Tax Withholding	28
	Section 7.05.	Amendment or Termination of Plan	28
	Section 7.06.	Administrative Expenses	30
	Section 7.07.	Effect on Other Employee Benefit Plans	30
	Section 7.08.	Successor and Assigns	30
	Section 7.09.	Additional Section 409A Provisions	30
	Section 7.10.	Offset	30

Exhibit 10.1

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 December 31, 2017, all benefit accruals under the Plan will be frozen and no compensation or employment after December 31, 2017 will be recognized under the Plan.

The Plan is amended and restated effective January 1, 2017, as set forth herein.

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) 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 the Retirement Plan 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 the Retirement Plan.


(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.

Exhibit 10.1


(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;

Exhibit 10.1


(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 WEC Energy Group Executive Deferred Compensation Plan, as amended and in effect from time to time, or any successor to such plan. With respect to periods before January 1, 2017, Deferred Compensation Plan refers to the Integrys Energy Group, Inc. Deferred Compensation 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

Exhibit 10.1

though designated for participation in the Deferred Compensation Plan, shall not be eligible for the Pension 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 Payment Date 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). Prior to the administrative change made on or about October 1, 2017, the Payment Date is the last business day of the seventh month following the month in which the Participant's Separation from Service occurs and all benefits are paid on the last business day of the month. Effective on or about October 1, 2017, for administrative purposes, the Payment Date will be the first business day of the seventh month following the month in which the Participant's Separation from Service occurs and all future benefit payments will be paid on the first business day of the month. The administrative change in the prior sentence is required in connection with a change in the third‑party entity processing Plan payments and is made in accordance with Treasury Regulation Section 1.409A‑3(d), which allows payments to be made up to 30 days prior to a designated payment date without being treated as accelerated payments, provided that the Participant is not permitted, directly or indirectly to designate the taxable year of the payment.

(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 WEC Energy Group Retirement Savings Plan, as amended and in effect from time to time, or any successor to such plan. With respect to periods before September 14, 2016, Qualified Defined Contribution Plan refers to the Integrys Energy Group 401(k) Plan for Administrative Employees.

(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.

Exhibit 10.1

(y) Retirement Plan: Part A or C (whichever is applicable to the Participant) of the legacy Integrys Energy Group Retirement Plan. Effective January 1, 2017, the Integrys Energy Group Retirement Plan was split into six separate plans, five of which contain benefits for participants from legacy Part A or Part C. With respect to periods on and after January 1, 2017, Retirement Plan refers to the following retirement plan, as amended and in effect from time to time, or any successor thereto, that is applicable to a Participant:


▪	Part A of the WEC Energy Group Retirement Plan for Wisconsin Public Service Corporation;


▪	Part A of the WEC Energy Group Retirement Plan for WEC Business Services;


▪	Part B of the WEC Energy Group Retirement Plan for WEC Business Services;


▪	Part A of the WEC Energy Group Retirement Plan for Integrys Holding;


▪	Part A of the WEC Energy Group Retirement Plan for Michigan Gas Utilities Corporation; or


▪	Part A of the WEC Energy Group Retirement Plan for Minnesota Energy Resources Corporation.

(z) Retroactive Benefit Payment: The sum of the Regular Monthly Payments that would have been made 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 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.

Exhibit 10.1

(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.

Exhibit 10.1

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 (iii) 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).

Exhibit 10.1

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

Exhibit 10.1

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

Exhibit 10.1

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 last day of the month preceding the month in which the Payment Date occurs. 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 last day of the month preceding the month in which the Payment Date occurs. 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

Exhibit 10.1

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 the Retirement Plan if the benefit were being paid to the Participant 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 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 the Retirement Plan if the Pension Restoration Benefit were being paid to the Participant under 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 to the Participant under the Retirement Plan. 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.

(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 last day of the month preceding the month in which the Payment Date occurs. 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.

(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.

Exhibit 10.1

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.

Exhibit 10.1

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

Exhibit 10.1


(2)	The sum of (A) and (B):

(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.

Exhibit 10.1

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 last day of the month preceding the month in which the Payment Date occurs. 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 last day of the month preceding the month in which the Payment Date occurs. 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

Exhibit 10.1

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 last day of the month preceding the month in which the Payment Date occurs. 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.

Exhibit 10.1

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 installments.

Exhibit 10.1

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 recordkeeping 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 last day of the month preceding the month in which the Payment Date occurs. 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 Benefit Payment, the Participant’s Special

Exhibit 10.1

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.

(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).

Exhibit 10.1

(b) Death on or After the Payment Date .

Exhibit 10.1

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.

(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 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.

Exhibit 10.1

(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.

(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

Exhibit 10.1

“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 5	36% 32% 28% 24% 20%

Exhibit 10.1

(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 7.05 to 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.

Exhibit 10.1

(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.

Exhibit 10.1

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) no 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

Exhibit 10.1

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 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 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

Exhibit 10.1

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).

Exhibit 10.1

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.

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.

35735447v4

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 4, 2017

	/s/ ALLEN L. LEVERETT
	Allen L. Leverett
	Chief Executive Officer and President
	(Principal Executive Officer)

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 4, 2017

	/s/ SCOTT J. LAUBER
	Scott J. Lauber
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)

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, 2017 , as filed with the Securities and Exchange Commission on August 4, 2017 (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 4, 2017

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, 2017 , as filed with the Securities and Exchange Commission on August 4, 2017 (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 4, 2017