WEC ENERGY GROUP, INC. - FORM 10-Q

Attached files

file	filename
EX-32.2 - WEC ENERGY GROUP EXHIBIT 32.2 - WEC ENERGY GROUP, INC.	wec03312016ex322.htm
EX-3.1 - WEC ENERGY GROUP EXHIBIT 3.1 - WEC ENERGY GROUP, INC.	wec03312016ex31.htm
EX-32.1 - WEC ENERGY GROUP EXHIBIT 32.1 - WEC ENERGY GROUP, INC.	wec03312016ex321.htm
EX-31.2 - WEC ENERGY GROUP EXHIBIT 31.2 - WEC ENERGY GROUP, INC.	wec03312016ex312.htm
EX-31.1 - WEC ENERGY GROUP EXHIBIT 31.1 - WEC ENERGY GROUP, INC.	wec03312016ex311.htm

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 March 31, 2016



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

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

Yes [X] No [ ]

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

Yes [X] No [ ]

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



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

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

Yes [ ] No [X]

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

Common Stock, $.01 Par Value,

315,647,207 shares outstanding at

March 31, 2016

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WEC ENERGY GROUP, INC.

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended March 31, 2016

TABLE OF CONTENTS



				Page
	CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION			1
PART I.	FINANCIAL INFORMATION			3
ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)			3
	Condensed Consolidated Income Statements			3
	Condensed Consolidated Statements of Comprehensive Income			4
	Condensed Consolidated Balance Sheets			5
	Condensed Consolidated Statements of Cash Flows			6
	Notes to Condensed Consolidated Financial Statements			7
			Page
	Note 1	General Information	7
	Note 2	Acquisition	7
	Note 3	Dispositions	9
	Note 4	Common Equity	9
	Note 5	Short-Term Debt and Lines of Credit	10
	Note 6	Long-Term Debt	10
	Note 7	Materials, Supplies, and Inventories	11
	Note 8	Fair Value Measurements	11
	Note 9	Derivative Instruments	13
	Note 10	Guarantees	15
	Note 11	Employee Benefits	15
	Note 12	Goodwill	16
	Note 13	Investment in American Transmission Company	16
	Note 14	Segment Information	17
	Note 15	Variable Interest Entities	18
	Note 16	Commitments and Contingencies	19
	Note 17	Supplemental Cash Flow Information	24
	Note 18	Regulatory Environment	24
	Note 19	New Accounting Pronouncements	27
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			29
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			42
ITEM 4.	CONTROLS AND PROCEDURES			43
PART II.	OTHER INFORMATION			44
ITEM 1.	LEGAL PROCEEDINGS			44
ITEM 1A.	RISK FACTORS			44
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			45
ITEM 6.	EXHIBITS			46
SIGNATURE				47



03/31/2016 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
Integrys		Integrys Holding, Inc. (previously known as Integrys Energy Group, Inc.)
ITF		Integrys Transportation Fuels, LLC (doing business as Trillium CNG)
MERC		Minnesota Energy Resources Corporation
MGU		Michigan Gas Utilities Corporation
NSG		North Shore Gas Company
PDL		WPS Power Development, LLC
PGL		The Peoples Gas Light and Coke Company
WBS		WEC Business Services LLC
We Power		W.E. Power, LLC
WE		Wisconsin Electric Power Company
WG		Wisconsin Gas LLC
WPS		Wisconsin Public Service Corporation

Federal and State Regulatory Agencies
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
ICC		Illinois Commerce Commission
MDEQ		Michigan Department of Environmental Quality
MPSC		Michigan Public Service Commission
MPUC		Minnesota Public Utilities Commission
PSCW		Public Service Commission of Wisconsin
SEC		United States Securities and Exchange Commission
WDNR		Wisconsin Department of Natural Resources

Accounting Terms
AFUDC		Allowance for Funds Used During Construction
ASC		Accounting Standards Codification
ASU		Accounting Standards Update
FASB		Financial Accounting Standards Board
GAAP		United States Generally Accepted Accounting Principles
OPEB		Other Postretirement Employee Benefits

Environmental Terms
CO₂		Carbon Dioxide
GHG		Greenhouse Gas
MATS		Mercury and Air Toxics Standards
NAAQS		National Ambient Air Quality Standards
NOx		Nitrogen Oxide
SO₂		Sulfur Dioxide

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



03/31/2016 Form 10-Q	ii	WEC Energy Group, Inc.

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



03/31/2016 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, liquidity and capital resources, and other matters.

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


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


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


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


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


•	The timely completion of capital projects within budgets, as well as the recovery of 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;



03/31/2016 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 intrusion, including the failure to maintain the security of personally identifiable information, the associated costs to protect our assets and personal information, and the costs to notify affected persons to mitigate their information security concerns;


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


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


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


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


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


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


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


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


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


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

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



03/31/2016 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
	March 31
(in millions, except per share amounts)	2016			2015
Operating revenues	$	2,194.8		$	1,387.9

Operating expenses
Cost of sales	838.9			613.9
Other operation and maintenance	531.5			280.7
Depreciation and amortization	187.9			102.6
Property and revenue taxes	47.2			31.9
Total operating expenses	1,605.5			1,029.1

Operating income	589.3			358.8

Equity in earnings of transmission affiliate	38.5			16.1
Other income, net	32.7			3.0
Interest expense	100.9			59.4
Other expense	(29.7		)	(40.3		)

Income before income taxes	559.6			318.5
Income tax expense	213.1			122.4
Net income	346.5			196.1

Preferred stock dividends of subsidiary	0.3			0.3
Net income attributed to common shareholders	$	346.2		$	195.8

Earnings per share
Basic	$	1.10		$	0.87
Diluted	$	1.09		$	0.86

Weighted average common shares outstanding
Basic	315.7			225.5
Diluted	317.1			227.3

Dividends per share of common stock	$	0.4950		$	0.4225

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



03/31/2016 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
	March 31
(in millions)	2016			2015
Net income	$	346.5		$	196.1

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

Other comprehensive loss, net of tax	(0.3		)	—

Comprehensive income	346.2			196.1

Preferred stock dividends of subsidiary	0.3			0.3
Comprehensive income attributed to common shareholders	$	345.9		$	195.8

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



03/31/2016 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)	March 31, 2016			December 31, 2015
Assets
Property, plant, and equipment
In service	$	26,523.3		$	26,249.5
Accumulated depreciation	(8,005.9		)	(7,919.1		)
	18,517.4			18,330.4
Construction work in progress	706.6			822.9
Leased facilities, net	35.0			36.4
Net property, plant, and equipment	19,259.0			19,189.7
Investments
Equity investment in transmission affiliate	1,422.5			1,380.9
Other	87.5			85.8
Total investments	1,510.0			1,466.7
Current assets
Cash and cash equivalents	34.7			49.8
Accounts receivable and unbilled revenues, net of reserves of $114.3 and $113.3, respectively	1,088.1			1,028.6
Materials, supplies, and inventories	470.7			687.0
Assets held for sale	—			96.8
Prepayments	243.4			285.8
Other	59.5			58.8
Total current assets	1,896.4			2,206.8
Deferred charges and other assets
Regulatory assets	3,060.8			3,064.6
Goodwill	2,999.1			3,023.5
Other	379.3			403.9
Total deferred charges and other assets	6,439.2			6,492.0
Total assets	$	29,104.6		$	29,355.2

Capitalization and liabilities
Capitalization
Common stock – $.01 par value; 325,000,000 shares authorized; 315,647,207 and 315,683,496 shares outstanding, respectively	$	3.2		$	3.2
Additional paid in capital	4,321.1			4,347.2
Retained earnings	4,489.7			4,299.8
Accumulated other comprehensive income	4.3			4.6
Preferred stock of subsidiary	30.4			30.4
Long-term debt	8,955.8			9,124.1
Total capitalization	17,804.5			17,809.3
Current liabilities
Current portion of long-term debt	152.4			157.7
Short-term debt	896.4			1,095.0
Accounts payable	584.4			815.4
Accrued payroll and benefits	102.7			169.7
Accrued interest	118.6			67.4
Other	375.3			403.8
Total current liabilities	2,229.8			2,709.0
Deferred credits and other liabilities
Regulatory liabilities	1,411.8			1,392.2
Deferred income taxes	4,856.5			4,622.3
Deferred revenue, net	576.1			579.4
Pension and other postretirement benefit obligations	541.1			543.1
Environmental remediation	617.6			628.2
Other	1,067.2			1,071.7
Total deferred credits and other liabilities	9,070.3			8,836.9

Commitments and contingencies (Note 16)

Total capitalization and liabilities	$	29,104.6		$	29,355.2

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



03/31/2016 Form 10-Q	5	WEC Energy Group, Inc.

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WEC ENERGY GROUP, INC.



CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Three Months Ended
	March 31
(in millions)	2016			2015
Operating Activities
Net income	$	346.5		$	196.1
Reconciliation to cash provided by operating activities
Depreciation and amortization	191.9			107.3
Deferred income taxes and investment tax credits, net	214.6			106.6
Contributions and payments related to pension and OPEB plans	(15.1		)	(103.7		)
Equity income in transmission affiliate, net of distributions	(23.4		)	(5.7		)
Change in –
Accounts receivable and unbilled revenues	(48.6		)	(28.0		)
Materials, supplies, and inventories	217.2			110.9
Other current assets	(63.7		)	44.5
Accounts payable	(123.7		)	(71.3		)
Accrued taxes, net	89.6			(6.5		)
Other current liabilities	(32.9		)	28.1
Other, net	(56.5		)	(48.3		)
Net cash provided by operating activities	695.9			330.0

Investing Activities
Capital expenditures	(312.0		)	(153.2		)
Investment in transmission affiliate	(9.0		)	(1.3		)
Proceeds from sale of businesses	106.5			—
Withdrawal of restricted cash from Rabbi trust for qualifying payments	21.0			—
Other, net	5.1			(1.8		)
Net cash used in investing activities	(188.4		)	(156.3		)

Financing Activities
Exercise of stock options	21.4			8.4
Purchase of common stock	(59.6		)	(23.4		)
Dividends paid on common stock	(156.2		)	(95.3		)
Retirement of long-term debt	(139.4		)	(9.3		)
Change in short-term debt	(198.6		)	(54.6		)
Other, net	9.8			3.8
Net cash used in financing activities	(522.6		)	(170.4		)

Net change in cash and cash equivalents	(15.1		)	3.3
Cash and cash equivalents at beginning of period	49.8			61.9
Cash and cash equivalents at end of period	$	34.7		$	65.2

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



03/31/2016 Form 10-Q	6	WEC Energy Group, Inc.

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WEC ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

March 31, 2016

NOTE 1—GENERAL INFORMATION

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

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

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

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

Reclassifications

On the income statements for the quarter ended March 31, 2015, we reclassified $2.5 million from treasury grant to depreciation and amortization. We also reclassified an insignificant amount from interest expense to preferred stock dividends of subsidiaries on the income statements for the quarter ended March 31, 2015. These reclassifications were made to be consistent with the current period presentation on the income statements.

On the statements of cash flows for the quarter ended March 31, 2015, we reclassified $0.9 million from depreciation and amortization to other operating activities. In addition, we reclassified $3.7 million of non-qualified pension and OPEB contributions from other operating activities to contributions and payments related to pension and OPEB plans on the statements of cash flows for the quarter ended March 31, 2015. We also reclassified $3.7 million from other investing activities to capital expenditures on the statements of cash flows for the quarter ended March 31, 2015. An insignificant amount of preferred stock dividends of subsidiaries was also reclassified from other financing activities to net income on the statements of cash flows for the quarter ended March 31, 2015. These reclassifications were made to be consistent with the current period presentation on the statements of cash flows.

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

NOTE 2—ACQUISITION

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

Allocation of Purchase Price

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



03/31/2016 Form 10-Q	7	WEC Energy Group, Inc.

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return on investment of assets and liabilities included in rate base. As such, the fair values of these assets and liabilities equal their carrying values. Accordingly, neither the assets and liabilities acquired, nor the pro forma financial information, reflect any adjustments related to these amounts.

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

The table below shows the preliminary allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. In the first quarter of 2016, adjustments were made to the estimated fair values of the assets acquired and liabilities assumed, primarily in connection with the sale of ITF. The allocation is subject to change during the remainder of the measurement period, which ends one year from the acquisition date, as we obtain additional information, including with respect to certain regulatory and legal matters.



(in millions)
Current assets	$	1,060.7
Net property, plant, and equipment	7,107.4
Investments *	1,071.8
Goodwill	2,557.2
Deferred charges and other assets, excluding goodwill	1,758.5
Current liabilities, including current maturities of long-term debt	(1,299.1		)
Deferred credits and other liabilities	(3,678.7		)
Long-term debt	(2,943.6		)
Preferred stock of subsidiary	(51.1		)
Total purchase price	$	5,583.1


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

Pro Forma Information

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

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



(in millions, except per share amounts)	Three Months Ended March 31, 2015
Unaudited Pro Forma Financial Information
Operating Revenues	$	2,550.9
Net Income	$	329.9
Earnings per share (Basic)	$	1.05
Earnings per share (Diluted)	$	1.04

Impact of Acquisition

In connection with the acquisition, WEC Energy Group and its subsidiaries recorded pre-tax acquisition costs of $8.8 million during the three months ended March 31, 2015. These costs consisted of professional fees and other miscellaneous costs. They were recorded in the other operation and maintenance line item on the income statement. Acquisition costs recorded during the three months ended March 31, 2016 were not significant.

Our revenues for the three months ended March 31, 2016, include revenues attributable to Integrys of $983.1 million. Included in our net income for the three months ended March 31, 2016, is net income attributable to Integrys of $158.2 million.



03/31/2016 Form 10-Q	8	WEC Energy Group, Inc.

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NOTE 3—DISPOSITIONS

Corporate and Other Segment – 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 sale in the first quarter of 2016, as ITF's assets and liabilities were adjusted to fair value through purchase accounting. The sale of ITF met the criteria to qualify as held for sale at December 31, 2015, but did not meet the requirements to qualify as a discontinued operation. The results of operations of ITF remained in continuing operations through the sale date as the sale of ITF did not represent a shift in our corporate strategy and will not have a major effect on our operations and financial results. The pre-tax profit or loss of this individually significant component was not material for the quarter ended March 31, 2016.

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



(in millions)	2015
Property, plant, and equipment	$	37.2
Accounts receivable and unbilled revenues	34.9
Materials, supplies, and inventories	18.4
Other current assets	2.6
Other long-term assets	3.7
Total assets	$	96.8

Accounts payable	$	12.9
Accrued payroll and benefits	2.4
Other current liabilities	4.5
Pension and OPEB obligations	1.2
Other long-term liabilities	0.6
Total liabilities *	$	21.6


*	Included in other current liabilities on our balance sheet.

NOTE 4—COMMON EQUITY

Stock-Based Compensation Plans

During the first quarter of 2016, the Compensation Committee of our Board of Directors awarded the following stock-based compensation awards to our directors, officers, and certain other key employees under our and Integrys's normal schedule of awarding long-term incentive compensation:



Award Type		Number of Awards
Stock options ⁽¹⁾		752,085
Restricted shares⁽²⁾		140,897
Performance units		283,505


⁽¹⁾	Stock options awarded had a weighted-average exercise price of $51.80 and a weighted-average grant date fair value of $5.03 per option.


⁽²⁾	Restricted shares awarded had a weighted-average grant date fair value of $53.40 per share.



03/31/2016 Form 10-Q	9	WEC Energy Group, Inc.

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Restrictions

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

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

NOTE 5—SHORT-TERM DEBT AND LINES OF CREDIT

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



(in millions, except percentages)	March 31, 2016			December 31, 2015
Commercial paper
Amount outstanding	$	896.4		$	1,095.0
Weighted-average interest rate on amounts outstanding	0.61		%	0.68		%

Our average amount of commercial paper borrowings based on daily outstanding balances during the three months ended March 31, 2016, was $1,043.7 million with a weighted-average interest rate during the period of 0.63%.

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



(in millions)	Maturity	March 31, 2016
WEC Energy Group	December 2020	$	1,050.0
WE	December 2020	500.0
WPS *	December 2016	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		$	18.0
Commercial paper outstanding		896.4

Available capacity under existing agreements		$	1,585.6


*	In March 2016, WPS requested approval from the PSCW to extend the maturity through December 2020.

NOTE 6—LONG-TERM DEBT

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



03/31/2016 Form 10-Q	10	WEC Energy Group, Inc.

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NOTE 7—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:



(in millions)	March 31, 2016		December 31, 2015
Materials and supplies	$	217.8	$	219.2
Fossil fuel	163.4		183.7
Natural gas in storage	89.5		284.1
Total	$	470.7	$	687.0

PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the last-in, first-out (LIFO) cost method. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. The amounts were as follows at March 31, 2016:



(in millions)	Balance Sheet Presentation	PGL		NSG
Temporary LIFO liquidation debit	Other current assets	$	17.6	$	—
Temporary LIFO liquidation credit	Other current liabilities	—		6.0

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

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

NOTE 8—FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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

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



03/31/2016 Form 10-Q	11	WEC Energy Group, Inc.

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

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



	March 31, 2016
(in millions)	Level 1		Level 2		Level 3		Total
Assets
Derivative assets
Natural gas contracts	$	0.6	$	1.7	$	—	$	2.3
FTRs	—		—		1.1		1.1
Petroleum products contracts	1.1		—		—		1.1
Coal contracts	—		1.6		—		1.6
Total derivative assets	$	1.7	$	3.3	$	1.1	$	6.1

Investments held in rabbi trust	$	41.7	$	—	$	—	$	41.7

Liabilities
Derivative liabilities
Natural gas contracts	$	8.8	$	21.7	$	—	$	30.5
Petroleum products contracts	3.8		—		—		3.8
Coal contracts	—		14.7		—		14.7
Total derivative liabilities	$	12.6	$	36.4	$	—	$	49.0



	December 31, 2015
(in millions)	Level 1		Level 2		Level 3		Total
Assets
Derivative assets
Natural gas contracts	$	1.6	$	1.5	$	—	$	3.1
FTRs	—		—		3.6		3.6
Petroleum products contracts	1.2		—		—		1.2
Coal contracts	—		2.0		—		2.0
Total derivative assets	$	2.8	$	3.5	$	3.6	$	9.9

Investments held in rabbi trust	$	39.8	$	—	$	—	$	39.8

Liabilities
Derivative liabilities
Natural gas contracts	$	16.5	$	25.3	$	—	$	41.8
Petroleum products contracts	4.9		—		—		4.9
Coal contracts	—		12.3		—		12.3
Total derivative liabilities	$	21.4	$	37.6	$	—	$	59.0

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

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



	Three Months Ended March 31
(in millions)	2016			2015
Balance at the beginning of the period	$	3.6		$	7.0
Realized and unrealized losses	(0.2		)	—
Sales	(0.1		)	—
Settlements	(2.2		)	(3.7		)
Balance at the end of the period	$	1.1		$	3.3



03/31/2016 Form 10-Q	12	WEC Energy Group, Inc.

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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:



	March 31, 2016				December 31, 2015
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock	$	30.4	$	28.6	$	30.4	$	27.3
Long-term debt, including current portion *	$	9,055.4	$	9,790.5	$	9,221.9	$	9,681.0


*	The carrying amount of long-term debt excludes capital lease obligations of $52.8 million and $59.9 million at March 31, 2016, and

December 31, 2015, respectively.

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

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:



	March 31, 2016				December 31, 2015
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	1.7	$	28.7	$	2.6	$	38.5
Petroleum products contracts	0.9		3.3		0.9		3.8
FTRs	1.1		—		3.6		—
Coal contracts	1.6		10.3		1.7		6.7
Total other current *	$	5.3	$	42.3	$	8.8	$	49.0

Other long-term
Natural gas contracts	$	0.6	$	1.8	$	0.5	$	3.3
Petroleum products contracts	0.2		0.5		0.3		1.1
Coal contracts	—		4.4		0.3		5.6
Total other long-term *	$	0.8	$	6.7	$	1.1	$	10.0
Total	$	6.1	$	49.0	$	9.9	$	59.0


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



03/31/2016 Form 10-Q	13	WEC Energy Group, Inc.

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



	Three Months Ended March 31, 2016				Three Months Ended March 31, 2015
(in millions)	Volume	Gains (Losses)			Volume	Gains (Losses)
Natural gas contracts	50.1 Dth	$	(33.5	)	13.3 Dth	$	(7.1	)
Petroleum products contracts	3.0 gallons	(1.1		)	0.9 gallons	(0.1		)
FTRs	7.6 MWh	3.0			6.2 MWh	2.1
Total		$	(31.6	)		$	(5.1	)

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At March 31, 2016, and December 31, 2015, we had posted collateral of $30.5 million and $42.3 million, respectively, in our margin accounts. These amounts were recorded on the balance sheets in other current assets.

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



	March 31, 2016						December 31, 2015
(in millions)	Derivative Assets			Derivative Liabilities			Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	6.1		$	49.0		$	9.9		$	59.0
Gross amount not offset on balance sheet *	(1.6		)	(13.6		)	(3.0		)	(22.5		)
Net amount	$	4.5		$	35.4		$	6.9		$	36.5


*	Includes cash collateral posted of $12.0 million and $19.5 million as of March 31, 2016, and December 31, 2015, respectively.

Certain of our derivative and nonderivative commodity instruments contain provisions that could require "adequate assurance" in the event of a material change in our creditworthiness, or the posting of additional collateral for instruments in net liability positions, if triggered by a decrease in credit ratings. The aggregate fair value of all derivative instruments with specific credit risk-related contingent features that were in a liability position was $21.4 million and $23.8 million at March 31, 2016, and December 31, 2015, respectively. At March 31, 2016, and December 31, 2015, we had not posted any cash collateral related to the credit risk-related contingent features of these commodity instruments. If all of the credit risk-related contingent features contained in derivative instruments in a net liability position had been triggered at March 31, 2016, and December 31, 2015, we would have been required to post collateral of $20.4 million and $18.0 million, respectively.

During 2015, we settled several forward interest rate swap agreements entered into to mitigate interest risk associated with the issuance of $1.2 billion of long-term debt related to the acquisition of Integrys. As these agreements qualified for cash flow hedging accounting treatment, the payments of $19.0 million received upon settlement of these agreements were deferred in accumulated other comprehensive income and are being amortized as a decrease to interest expense over the periods in which the interest costs are recognized in earnings.

During the three months ended March 31, 2016, we reclassified $0.5 million of forward interest rate swap agreement settlements deferred in accumulated other comprehensive income as a reduction to interest expense. We estimate that during the next twelve months, $2.2 million will be reclassified from accumulated other comprehensive income as a reduction to interest expense.



03/31/2016 Form 10-Q	14	WEC Energy Group, Inc.

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NOTE 10—GUARANTEES

The following table shows our outstanding guarantees:



	Total Amounts Committed		Expiration
(in millions)	at March 31, 2016		Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees
Guarantees supporting commodity transactions of subsidiaries ⁽¹⁾	$	168.7	$	89.7	$	—	$	79.0
Standby letters of credit ⁽²⁾	28.3		18.7		9.4		0.2
Surety bonds⁽³⁾	10.2		10.2		—		—
Other guarantees⁽⁴⁾	58.9		20.6		0.1		38.2
Total guarantees	$	266.1	$	139.2	$	9.5	$	117.4


⁽¹⁾	Consists of (a) $5.0 million and $11.0 million to support the business operations of WBS and PDL, respectively; and (b) $114.8 million and $37.9 million related to natural gas supply at MERC and MGU, respectively. These amounts are not reflected on our balance sheets.


⁽²⁾	At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets.


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

⁽⁴⁾

Consists of (a) $19.0 million to support PDL's future payment obligations related to its distributed solar generation projects, of which $6.6 million is covered by a reciprocal guarantee from a third party; (b) $20.0 million for an interconnection agreement between WPS and ATC; (c) $10.0 million related to the sale of a nonregulated retail marketing business previously owned by Integrys; and (d) $9.9 million related to other indemnifications. The amounts discussed in items (a) and (b) are not reflected on our balance sheets. An insignificant liability was recorded for item (c). In addition, a liability of $9.2 million related to workers compensation coverage was recorded for item (d).

NOTE 11—EMPLOYEE BENEFITS

Defined Benefit Plans

The following tables show the components of net periodic pension and OPEB costs for our benefit plans. Our pension and OPEB costs for the three months ended March 31, 2016, include costs attributable to the Integrys pension and OPEB plans. The terms and conditions of the legacy company plans have not changed since the acquisition.



	Pension Costs
	Three Months Ended March 31
(in millions)	2016			2015
Service cost	$	11.3		$	3.9
Interest cost	33.2			15.2
Expected return on plan assets	(49.0		)	(25.8		)
Amortization of prior service cost	0.9			0.5
Amortization of net actuarial loss	20.5			11.6
Net periodic benefit cost	$	16.9		$	5.4



	OPEB Costs
	Three Months Ended March 31
(in millions)	2016			2015
Service cost	$	6.7		$	2.6
Interest cost	9.2			4.2
Expected return on plan assets	(13.1		)	(5.9		)
Amortization of prior service credit	(2.3		)	(0.3		)
Amortization of net actuarial loss	2.3			0.5
Net periodic benefit cost	$	2.8		$	1.1



03/31/2016 Form 10-Q	15	WEC Energy Group, Inc.

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We did not make any contributions to our qualified pension plans during the first three months of 2016. During the three months ended March 31, 2016, we made payments of $13.7 million related to our non-qualified pension plans and $1.4 million to our OPEB plans. We expect to make payments of $8.5 million to our pension plans and $10.8 million to our OPEB plans during the remainder of 2016, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

NOTE 12—GOODWILL

Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. The following table shows changes to our goodwill balances by segment during the three months ended March 31, 2016:



(in millions)	Wisconsin				Illinois				Other States				Total
Goodwill balance as of January 1, 2016	$	2,109.5			$	731.2			$	182.8			$	3,023.5
Adjustment to Integrys purchase price allocation	(12.4		)		(8.5		)		(3.5		)		(24.4		)
Goodwill balance as of March 31, 2016 ⁽¹⁾	$	2,097.1		⁽²⁾	$	722.7		⁽³⁾	$	179.3		⁽³⁾	$	2,999.1


⁽¹⁾	We had no accumulated impairment losses related to our goodwill as of March 31, 2016.


⁽²⁾	Of this amount, $1,655.2 million relates to the acquisition of Integrys.


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

NOTE 13—INVESTMENT IN AMERICAN TRANSMISSION COMPANY

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



	Three Months Ended March 31
(in millions)	2016		2015
Balance at beginning of period	$	1,380.9	$	424.1
Add: Earnings from equity method investment	38.5		16.1
Add: Capital contributions	9.0		1.3
Add: Adjustment to equity method goodwill	9.3		—
Less: Distributions received	15.1		10.4
Less: Other	0.1		—
Balance at end of period	$	1,422.5	$	431.1

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



	Three Months Ended March 31
(in millions)	2016		2015
Charges to ATC for services and construction	$	4.1	$	2.5
Charges from ATC for network transmission services	100.8		59.6

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



(in millions)	March 31, 2016		December 31, 2015
Accounts receivable
Services provided to ATC	$	2.0	$	1.0
Accounts payable
Services received from ATC	30.4		28.3



03/31/2016 Form 10-Q	16	WEC Energy Group, Inc.

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



	Three Months Ended March 31
(in millions)	2016		2015
Income statement data
Revenues	$	164.2	$	152.4
Operating expenses	79.1		80.0
Other expense	24.0		24.4
Net income	$	61.1	$	48.0



(in millions)	March 31, 2016		December 31, 2015
Balance sheet data
Current assets	$	88.7	$	80.5
Noncurrent assets	4,022.1		3,948.3
Total assets	$	4,110.8	$	4,028.8

Current liabilities	$	337.8	$	330.3
Long-term debt	1,790.9		1,790.7
Other noncurrent liabilities	265.8		245.0
Shareholders' equity	1,716.3		1,662.8
Total liabilities and shareholders' equity	$	4,110.8	$	4,028.8

NOTE 14—SEGMENT INFORMATION

We reorganized our business segments during the third quarter of 2015 to reflect our new internal organization and management structure following the acquisition of Integrys. We use operating income to measure segment profitability and allocate resources to our businesses. All prior period amounts impacted by this change were reclassified to conform to the new presentation. At March 31, 2016, we reported six segments, which are described below.


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


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


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


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


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


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



03/31/2016 Form 10-Q	17	WEC Energy Group, Inc.

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All of our operations are located within the United States. The following tables show summarized financial information concerning our reportable segments for the three months ended March 31, 2016 and 2015:



	Regulated Operations
(in millions)	Wisconsin		Illinois		Other States		Electric Transmission		Total Regulated Operations		We Power		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Three Months Ended
March 31, 2016
External revenues	$	1,579.8	$	448.5	$	148.4	$	—	$	2,176.7	$	6.2	$	11.9		$	—		$	2,194.8
Intersegment revenues	0.1		—		—		—		0.1		104.5		—			(104.6		)	—
Other operation and maintenance	491.3		117.9		30.0		—		639.2		0.4		(3.5		)	(104.6		)	531.5
Depreciation and amortization	122.9		32.8		5.1		—		160.8		17.0		10.1			—			187.9
Operating income (loss)	327.5		137.0		31.8		—		496.3		93.3		(0.3		)	—			589.3
Equity in earnings of transmission affiliate	—		—		—		38.5		38.5		—		—			—			38.5
Interest expense	44.5		9.7		2.5		—		56.7		15.6		31.3			(2.7		)	100.9



	Regulated Operations
(in millions)	Wisconsin		Illinois		Other States		Electric Transmission		Total Regulated Operations		We Power		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Three Months Ended
March 31, 2015
External revenues	$	1,376.5	$	—	$	—	$	—	$	1,376.5	$	11.1	$	0.3		$	—		$	1,387.9
Intersegment revenues	0.4		—		—		—		0.4		98.6		—			(99.0		)	—
Other operation and maintenance	369.1		—		—		—		369.1		0.4		10.1			(98.9		)	280.7
Depreciation and amortization	85.4		—		—		—		85.4		16.8		0.4			—			102.6
Operating income (loss)	276.5		—		—		—		276.5		92.5		(10.2		)	—			358.8
Equity in earnings of transmission affiliate	—		—		—		16.1		16.1		—		—			—			16.1
Interest expense	31.4		—		—		—		31.4		15.9		12.2			(0.1		)	59.4

NOTE 15—VARIABLE INTEREST ENTITIES

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

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

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



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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 instead account for ATC as an equity method investment. See Note 13, Investment in American Transmission Company, for more information.

The significant assets and liabilities related to ATC recorded on our balance sheets included our equity investment and accounts payable. At March 31, 2016, and December 31, 2015, our equity investment was $1,422.5 million and $1,380.9 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC. In addition, we had $30.4 million and $28.3 million of accounts payable due to ATC at March 31, 2016, and December 31, 2015, respectively, for network transmission services.

Purchased Power Agreement

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

We have approximately $119.2 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 each of the three months ended March 31, 2016 and 2015 were $13.5 million. Our maximum exposure to loss is limited to the capacity payments under the contract.

NOTE 16—COMMITMENTS AND CONTINGENCIES

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

Energy Related Purchased Power Agreements

Our natural gas utilities have obligations to distribute and sell natural gas to their customers, and our electric utilities have obligations to distribute and sell electricity to their customers. The utilities expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of March 31, 2016, including those of our subsidiaries, were $12,494.4 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 SO₂, NOx, fine particulates, mercury, and GHGs; water discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.

Air Quality

Sulfur Dioxide National Ambient Air Quality Standards

The EPA issued a revised 1-Hour SO₂ NAAQS that became effective in August 2010. The EPA issued a final rule in August 2015 describing the implementation requirements and established a compliance timeline for the revised standard. The final rule affords



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state agencies some latitude in rule implementation. A nonattainment designation could have negative impacts for a localized geographic area, including additional permitting requirements for new or existing sources in the area.

In March 2015, a federal court entered a consent decree between the EPA and the Sierra Club and others agreeing to specific actions related to implementing the revised standard for areas containing large sources emitting above a certain threshold level of SO₂. The consent decree requires the EPA to complete attainment designations for certain areas with large sources by no later than July 2, 2016. SO₂emissions from PIPP are above the consent decree emission threshold, which means that the Marquette area required action earlier than would otherwise have been required under the revised NAAQS. However, we were able to show through modeling that the area should be designated as attainment. Based upon this modeling, the state of Michigan recommended to the EPA that the Marquette area be designated as attainment, and in February 2016, the EPA issued a draft recommendation to have the Marquette area classified as unclassified/attainment. We expect the EPA recommendation to be finalized in 2016.

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

8-Hour Ozone National Ambient Air Quality Standards

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

Mercury and Other Hazardous Air Pollutants

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

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

Climate Change

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



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

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

Draft Federal Plan and Model Trading Rules were also published in October 2015 for use in developing state plans or for use in states where a plan is not submitted or approved. In December 2015, the state of Wisconsin submitted petitions for review to the EPA of the final standards for existing as well as new, modified, and reconstructed generating units. A petition for review was also submitted jointly by the Wisconsin utilities. Among other things, the petitions narrowly ask the EPA to consider revising the state goal for existing units to reflect the 2013 retirement of the Kewaunee Power Station, which could lower the state's CO₂equivalent reduction goal by about 10%. Michigan state agencies announced modeling results that suggest that the state will be able to meet existing source requirements until 2025, based on planned coal plant retirements, along with a continuation of state renewable standards and current levels of energy efficiency.

We are required to report our CO₂ equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2015, we reported aggregated CO₂ equivalent emissions of 31.0 million metric tonnes to the EPA. The level of CO₂ and other GHG emissions vary from year to year and are dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO.

We are also required to report CO₂ equivalent amounts related to the natural gas that our natural gas utilities distribute and sell. For 2015, we reported aggregated CO₂ equivalent emissions of 27.2 million metric tonnes to the EPA related to our distribution and sale of natural gas.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

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

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

BTA determinations must also be made by the WDNR and MDEQ to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. We have received an EM BTA determination by the WDNR, with EPA concurrence, for our proposed intake modification at VAPP. BTA determinations for EM will be made in future permit reissuances for Pulliam Units 7



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and 8, Weston Units 2 through 4, Port Washington Generating Station, Pleasant Prairie Power Plant, PIPP, and Oak Creek Power Plant Units 5 through 8.

During 2016–2018, we will be completing studies and evaluating options to address the EM BTA requirements at our plants. With the exception of Pleasant Prairie Power Plant and Weston Units 3 and 4 (which all have existing cooling towers that meet EM BTA requirements), and VAPP, we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at our facilities. We also expect that limited studies to support WDNR BTA determinations will be conducted at the Weston facility. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the EM BTA requirements based on low capacity use of the unit. In addition, the rule allows the EM BTA requirements to be waived in cases of pending facility retirements, which we are currently considering for PIPP. Based on discussions with the MDEQ, if we submit a signed certification with our next National Pollutant Discharge Elimination System permit application stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2022), then the EM BTA requirements will be waived. Entrainment studies are currently being conducted at Pulliam Units 7 and 8 and are also underway at PIPP.

Steam Electric Effluent Guidelines

The EPA's final steam electric effluent guidelines rule took effect in January 2016 and applies to discharges of wastewater from our power plant processes in Wisconsin and Michigan. Unless pending challenges to the final guidelines are successful, the WDNR and MDEQ will modify the state rules and incorporate the new requirements into our facility permits, which are renewed every five years. We expect the new requirements to be phased in between 2018 and 2023 as our permits are renewed. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, these standards will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use. The final rule phases in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. New requirements for wet scrubber wastewater treatment will require additional zero liquid discharge or other advanced treatment capital improvements for the Oak Creek and Pleasant Prairie facilities. The rule also requires dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are required by the new rule, and modifications will be required at Oak Creek Units 5 and 6, the Pleasant Prairie units, the PIPP units, Pulliam Units 7 and 8, and Weston Unit 3. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $95 million to $130 million for these advanced treatment and bottom ash transport systems.

Valley Power Plant Wisconsin Pollutant Discharge Elimination System Permit

The WDNR issued a Wisconsin Pollutant Discharge Elimination System permit for VAPP that became effective in January 2013. The permit contains several additional requirements including effluent toxicity testing and monitoring for additional parameters (phosphorous, mercury, and ammonia-nitrogen), and a new heat addition limit from the cooling water discharges that all took effect immediately. Other long-term compliance requirements include thermal discharge studies, phosphorous evaluation and feasibility for reduction, mercury minimization planning, and the installation of new cooling water intake fish protection screens. Installation of wedge wire screens for fish protection on the VAPP Unit 2 cooling water intake structure is complete. An identical modification is scheduled to begin for VAPP Unit 1 in the third quarter of 2016. We are also currently working on plans to meet the remaining long-term requirements.

Manufactured Gas Plant Remediation

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

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



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

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



(in millions)	March 31, 2016		December 31, 2015
Regulatory assets	$	683.7	$	697.0
Reserves for future remediation	617.5		628.0

Enforcement and Litigation Matters

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

Weston Title V Air Permit

In August 2013, the WDNR issued the Weston Title V air permit. In September 2013, WPS challenged various requirements in the permit by filing a contested case proceeding with the WDNR and also filed a Petition for Judicial Review in the Brown County Circuit Court. The Sierra Club and Clean Wisconsin also challenged various aspects of the permit. The WDNR granted all parties' requests for contested case proceedings. The Petitions for Judicial Review, by all parties, were stayed pending the resolution of the contested cases. In February 2014, a new permit change was challenged and added to the case. The parties negotiated a settlement of their challenges to the permit. As a result, in March 2016, the ALJ issued an order dismissing the contested case proceedings, and in April 2016, the Brown County Circuit Court dismissed the Petitions for Judicial Review.

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

Consent Decrees

Wisconsin Electric Power Company Consent Decree

In April 2003, WE entered into a Consent Decree with the EPA, in which it agreed to significantly reduce air emissions from its coal-fired power plants. Under the terms of the Consent Decree, WE could request its termination after December 31, 2015. WE made this termination request in March 2016, and the request is currently under review.

Wisconsin Public Service Corporation Consent Decree – Weston and Pulliam

In November 2009, the EPA issued a Notice of Violation (NOV) to WPS, which alleged violations of the Clean Air Act's (CAA) New Source Review requirements relating to certain projects completed at the Weston and Pulliam plants from 1994 to 2009. WPS entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Eastern District of Wisconsin in March 2013.

The Consent Decree contains a requirement to, among other things, refuel, repower, and/or retire certain Weston and Pulliam units. Effective June 1, 2015, WPS retired Weston Unit 1 and Pulliam Units 5 and 6 and recorded a regulatory asset of $11.5 million for the undepreciated book value. WPS received approval from the PSCW in its 2015 rate order to defer and amortize the undepreciated book value of the retired plant associated with these units starting June 1, 2015, and concluding by 2023.

WPS received approval from the PSCW in its rate orders to recover prudently incurred costs as a result of complying with the terms of the Consent Decree, with the exception of a $1.2 million civil penalty. The majority of the beneficial environmental projects proposed by WPS have been approved by the EPA. In March 2016, WPS submitted a proposed revision to the EPA to update requirements reflecting the conversion of Weston Unit 2 from coal to natural gas fuel and to reflect changes to other environmental projects that are not expected to materially impact the overall cost.



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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 March 31, 2016. It is unknown whether the Sierra Club will take further action in the future.

Joint Ownership Power Plants Consent Decree – Columbia and Edgewater

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

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

NOTE 17—SUPPLEMENTAL CASH FLOW INFORMATION



	Three Months Ended March 31
(in millions)	2016			2015
Cash (paid) for interest, net of amount capitalized	$	(40.7	)	$	(20.0	)
Cash (paid) for income taxes, net of refunds	(0.4		)	(4.3		)
Significant non-cash transactions:
Accounts payable related to construction costs	90.1			1.6
Amortization of deferred revenue	6.2			11.1

At March 31, 2016, and December 31, 2015, restricted cash of $95.9 million and $118.4 million, respectively, was recorded within other long-term assets on our balance sheets. The majority of this amount was held in the Integrys rabbi trust and represents a portion of the required funding that was triggered by the announcement of the Integrys acquisition.

NOTE 18—REGULATORY ENVIRONMENT

Wisconsin Electric Power Company

2015 Wisconsin Rate Order

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

•

A net bill increase related to non-fuel costs for WE's retail electric customers of approximately $2.7 million (0.1%) in 2015. This amount reflects WE's receipt of SSR payments from MISO that were higher than WE anticipated when it filed its rate request in May 2014, as well as an offset of $26.6 million related to a refund of prior fuel costs and the remainder of the proceeds from a Section 1603 Renewable Energy Treasury Grant that WE received in connection with its biomass facility. The majority of this $26.6 million was returned to customers in the form of bill credits in 2015.


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


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


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


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



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

The authorized ROE for WE was set at 10.2%, and its common equity component remained at an average of 51.0%. The PSCW order reaffirmed the deferral of WE's transmission costs, and it verified that 2015 and 2016 fuel costs should continue to be monitored using a 2% tolerance window. The PSCW approved a change in rate design for WE, which included higher fixed charges to better match the related fixed costs of providing service. The PSCW order also authorized escrow accounting for SSR revenues because of the uncertainty of the actual revenues WE will receive under the PIPP SSR agreements. Under escrow accounting, WE records SSR revenues from MISO of $90.7 million a year. If actual SSR payments from MISO exceed $90.7 million a year, the difference is deferred and returned to customers, with interest, in a future rate case. If actual SSR payments from MISO are less than $90.7 million a year, the difference is deferred and recovered from customers with interest, in a future rate case.

In January 2015, certain parties appealed a portion of the PSCW's final decision adopting WE's specific rate design changes, including new charges for customer-owned generation within its service territory. The Dane County Circuit Court, in its November 2015 order, ruled that there was not enough evidence provided in WE's rate case to support a demand charge for customer-owned generation. As a result, this demand charge did not take effect on January 1, 2016. No other rates approved by the PSCW in the rate case were impacted by the Dane County Circuit Court order.

Wisconsin Gas LLC

2015 Wisconsin Rate Order

In May 2014, WG applied to the PSCW for a biennial review of costs and rates. In December 2014, the PSCW approved rate increases of $17.1 million (2.6%) in 2015 and $21.4 million (3.2%) in 2016 for WG's natural gas customers, which were effective January 1, 2015, and January 1, 2016, respectively. The authorized ROE for WG was set at 10.3%. The PSCW also authorized an increase in WG's common equity component to an average of 49.5%.

Wisconsin Public Service Corporation

2016 Wisconsin Rate Order

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

In March 2016, WPS requested extensions from the PSCW through 2017 for the deferral of the revenue requirement of ReACT™ costs above the authorized $275.0 million level as well as escrow accounting of ATC and MISO network transmission expenses. In April 2016, WPS also requested a deferral through 2017 of the revenue requirement difference between the Real Time Market Pricing and the standard tariffed rates for any of WPS's current large commercial and industrial customers who entered into a service agreement with WPS under Real Time Market Pricing prior to April 15, 2016.

2015 Wisconsin Rate Order

In April 2014, WPS initiated a rate proceeding with the PSCW. In December 2014, the PSCW issued a final written order for WPS, effective January 1, 2015. It authorized a net retail electric rate increase of $24.6 million and a net retail natural gas rate decrease of $15.4 million, reflecting a 10.2% ROE. The order authorized a common equity component average of 50.28%. The PSCW approved a change in rate design for WPS, which included higher fixed charges to better match the related fixed costs of providing service. In addition, the order continued to exclude a decoupling mechanism that was terminated beginning January 1, 2014.



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The primary driver of the increase in retail electric rates was higher costs of fuel for electric generation of approximately $42.0 million. In addition, 2015 rates included approximately $9.0 million of lower refunds to customers related to decoupling over-collections. In 2015 rates, WPS refunded approximately $4.0 million to customers related to 2013 decoupling over-collections compared with refunding approximately $13.0 million to customers in 2014 rates related to 2012 decoupling over-collections. Absent these adjustments for electric fuel costs and decoupling refunds, WPS would have realized an electric rate decrease. In addition, WPS received approval from the PSCW to defer and amortize the undepreciated book value associated with Pulliam Units 5 and 6 and Weston Unit 1 starting with the actual retirement date, June 1, 2015, and concluding by 2023. See Note 16, Commitments and Contingencies, for more information. The PSCW allowed WPS to escrow ATC and MISO network transmission expenses for 2015 and 2016. As a result, WPS defers as a regulatory asset or liability the differences between actual transmission expenses and those included in rates until a future rate proceeding. Finally, the PSCW ordered that 2015 fuel costs should continue to be monitored using a 2% tolerance window.

The retail natural gas rate decrease was driven by the approximate $16.0 million year-over-year negative impact of decoupling refunds to and collections from customers. In 2015 rates, WPS refunded approximately $8.0 million to customers related to 2013 decoupling over-collections compared with recovering approximately $8.0 million from customers in 2014 rates related to 2012 decoupling under-collections. Absent the adjustment for decoupling refunds to and collections from customers, WPS would have realized a retail natural gas rate increase.

2015 Michigan Rate Order

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. 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, WPS will discontinue the deferral of Fox Energy Center costs and will begin amortizing this deferral along with the deferral associated with the termination of a tolling agreement related to the Fox Energy Center. WPS also received approval from the MPSC to defer and amortize the undepreciated book value of the retired plant associated with Pulliam Units 5 and 6 and Weston Unit 1 starting with the actual retirement date, June 1, 2015, and concluding by 2023. Lastly, WPS will not seek an increase to retail electric base rates that would become effective prior to January 1, 2018.

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

Illinois Investigations

In March 2015, the ICC opened a docket, naming PGL as respondent, to investigate the veracity of certain allegations included in anonymous letters that the ICC staff received regarding the AMRP. The Illinois Attorney General’s office is also conducting an inquiry into the same allegations. Since the investigations are ongoing, it is too early to determine what effect, if any, the investigations will have on the AMRP. In July 2015, we engaged a nationally recognized engineering and construction firm to conduct an independent, bottom up review of the AMRP's long-term cost, scope, and schedule. We filed the results of that review with the ICC in November 2015.

In November 2015, the ICC initiated an investigation into whether we, PGL, or Integrys knowingly misled or withheld material information from the ICC at its open meeting on May 20, 2015. The investigation relates to the ICC Staff's presentation of the independent audit findings reached for the AMRP. The Illinois Attorney General’s office is conducting an inquiry into this matter as well.

In December 2015, the ICC ordered a series of stakeholder workshops to evaluate the AMRP. This ICC action does not impact PGL's ongoing work to modernize and maintain the safety of its natural gas distribution system, but it instead provides the ICC with an opportunity to analyze long-term elements of the program through the stakeholder workshops. The workshops are expected to result in an ICC order with final and binding recommendations for the AMRP. The workshops that commenced in January 2016 were completed, and a report is expected to be presented to the ICC by the end of May 2016. We are currently unable to determine what, if any, long-term impact there will be on the AMRP.



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2015 Illinois Rate Order

In February 2014, PGL and NSG initiated a rate proceeding with the ICC. In January 2015, the ICC issued a final written order for PGL and NSG, effective January 28, 2015. The order authorized a retail natural gas rate increase of $74.8 million for PGL and $3.7 million for NSG. In February 2015, the ICC issued an amendatory order that revised the increases to $71.1 million for PGL and $3.5 million for NSG, effective February 26, 2015, to reflect the extension of bonus depreciation in 2014. The rates for PGL reflected a 9.05% ROE and a common equity component average of 50.33%. The rates for NSG reflected a 9.05% ROE and a common equity component average of 50.48%. The rate order allowed PGL and NSG to continue the use of their decoupling mechanisms and uncollectible expense true-up mechanisms. In addition, PGL recovers a return on certain investments and depreciation expense through the qualifying infrastructure plant rider, and accordingly, such costs are not subject to PGL's rate order.

Minnesota Energy Resources Corporation

2016 Minnesota Rate Case

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

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

2015 Minnesota Rate Order

In September 2013, MERC initiated a rate proceeding with the MPUC. In October 2014, the MPUC issued a final written order for MERC, effective April 1, 2015. The order authorized a retail natural gas rate increase of $7.6 million. The rates reflected a 9.35% ROE and a common equity component average of 50.31%. The order approved a deferral of customer billing system costs, for which recovery will be requested in a future rate case. A decoupling mechanism with a 10% cap remains in effect for MERC's residential and small commercial and industrial customers. The final approved rate increase was lower than the interim rates collected from customers during 2014. Therefore, MERC refunded $4.7 million to customers in 2015.

Michigan Gas Utilities Corporation

2016 Michigan Rate Order

In June 2015, MGU initiated a rate proceeding with the MPSC. In December 2015, the MPSC issued a final written order approving a settlement agreement for MGU. The order, which reflected a 9.9% ROE and a common equity component average of 52.0%, authorized a retail natural gas rate increase of $3.4 million (2.4%), effective January 1, 2016. Based on the settlement agreement, MGU discontinued the use of its decoupling mechanism after December 31, 2015. In addition, since bonus depreciation is in effect in 2016, MGU is required to establish a regulatory liability for the resulting cost savings and must reflect the liability in its next general rate case.

NOTE 19—NEW ACCOUNTING PRONOUNCEMENTS

Revenue Recognition

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



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Classification and Measurement of Financial Instruments

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

Leases

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

Stock-Based Compensation

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



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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, 2015.

Introduction

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

Corporate Strategy

Our goal is to continue to create long-term value for our stockholders 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 network.


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


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

Operating Efficiency

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

Financial Discipline

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

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


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

•

Our primary investment opportunities are in three areas: our regulated utility business; our investment in ATC; and our generation plants within our We Power segment. In addition to the projects discussed above, other on-going 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.


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



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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.

RESULTS OF OPERATIONS

Consolidated Earnings

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



	Three Months Ended March 31
(in millions, except per share data)	2016			2015			B (W)
Wisconsin	$	327.5		$	276.5		$	51.0
Illinois	137.0			—			137.0
Other states	31.8			—			31.8
We Power	93.3			92.5			0.8
Corporate and other	(0.3		)	(10.2		)	9.9
Total operating income	589.3			358.8			230.5
Electric transmission	38.5			16.1			22.4
Other income, net	32.7			3.0			29.7
Interest expense	100.9			59.4			(41.5		)
Income before income taxes	559.6			318.5			241.1
Income tax expense	213.1			122.4			(90.7		)
Preferred stock dividends of subsidiary	0.3			0.3			—
Net income attributed to common shareholders	$	346.2		$	195.8		$	150.4

Diluted earnings per share	$	1.09		$	0.86		$	0.23

Earnings increased $150.4 million in 2016, driven by a $158.2 million increase in earnings due to the inclusion of Integrys's results. Integrys was acquired on June 29, 2015. Partially offsetting this increase was a $29.2 million pre-tax decrease ($17.5 million after tax) in WE and WG margins due to lower sales volumes, driven by warmer weather in 2016.

Wisconsin Segment Contribution to Operating Income

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



	Three Months Ended March 31
(in millions)	2016		2015		B (W)
Electric revenues	$	1,117.2	$	886.7	$	230.5
Fuel and purchased power	336.3		297.9		(38.4		)
Total electric margins	780.9		588.8		192.1

Natural gas revenues	462.7		490.2		(27.5		)
Cost of natural gas sold	261.6		316.2		54.6
Total natural gas margins	201.1		174.0		27.1

Other operation and maintenance	491.3		369.1		(122.2		)
Depreciation and amortization	122.9		85.4		(37.5		)
Property and revenue taxes	40.3		31.8		(8.5		)
Operating income	$	327.5	$	276.5	$	51.0



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



	Three Months Ended March 31
	MWh (in thousands)
Electric Sales Volumes	2016	2015	B (W)
Customer Class
Residential	2,655.3	2,008.3	647.0
Small commercial and industrial	3,187.0	2,225.2	961.8
Large commercial and industrial	3,318.3	2,159.1	1,159.2
Other	47.5	39.0	8.5
Total retail	9,208.1	6,431.6	2,776.5
Wholesale	856.1	420.0	436.1
Resale	2,232.3	2,104.7	127.6
Total sales in MWh	12,296.5	8,956.3	3,340.2
Electric Customer Choice*	64.3	250.0	(185.7	)


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



	Three Months Ended March 31
	Therms (in millions)
Natural Gas Sales Volumes	2016	2015	B (W)
Customer Class
Residential	477.8	427.2	50.6
Commercial and industrial	270.8	245.7	25.1
Total retail	748.6	672.9	75.7
Transport	380.5	267.9	112.6
Total sales in therms	1,129.1	940.8	188.3



	Three Months Ended March 31
	Degree Days
Weather	2016	2015	B(W)
WE and WG ⁽¹⁾
Heating (3,339 normal)	3,105	3,656	(551	)

WPS ⁽²⁾
Heating (3,717 normal)	3,438	N/A	N/A


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


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

Electric Utility Margins

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

Electric utility margins at the Wisconsin segment increased $192.1 million in the first quarter of 2016, related to a $195.2 million margin contribution from WPS, offset by a $3.1 million decrease in margins from WE.

The significant factor impacting the $3.1 million lower electric utility margins at WE was an $11.2 million decrease related to sales volume variances, primarily driven by warmer weather. As measured by heating degree days, the first quarter of 2016 was 15.1% warmer than 2015.

This decrease in electric utility margins at WE related to sales volumes was partially offset by a $6.2 million increase in margins from a positive impact from collections of fuel and purchased power costs as compared with costs approved in rates, as well as lower fly



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ash removal costs. Under the fuel rule, WE defers under or over-collections of certain fuel and purchased power costs that exceed a 2% price variance from the costs included in rates, and the remaining variance impacts margins. Fly ash removal costs are not included in the fuel rule recovery mechanism.

Natural Gas Utility Margins

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

Natural gas utility margins at the Wisconsin segment increased $27.1 million in the first quarter of 2016, related to a $37.1 million margin contribution from WPS, partially offset by a $10.0 million decrease in margins from WE and WG.

The significant factor impacting the $10.0 million lower natural gas utility margins at WE and WG was an $18.0 million decrease related to sales volumes, primarily driven by warmer weather in the first quarter of 2016. This decrease in margins related to sales volumes was partially offset by a $9.7 million margin increase as a result of increased rates, effective January 1, 2016, in the WG PSCW rate order. See Note 18, Regulatory Environment, for more information.

Operating Income

Operating income at the Wisconsin segment increased $51.0 million during the first quarter of 2016, driven by the $219.2 million increase in margins discussed above, partially offset by $168.2 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes). Higher operating expenses were driven by $155.4 million of operating expenses from WPS and a $12.8 million increase in operating expenses from WE and WG in the first quarter of 2016.

Significant factors impacting the $12.8 million increase in operating expenses in the first quarter of 2016 at WE and WG were:


•	A $6.7 million increase in depreciation and amortization, driven by an overall increase in utility plant in service. In November 2015, WG completed the Western Gas lateral project, and WE completed the conversion of the fuel source for VAPP from coal to natural gas.


•	A $4.6 million increase in employee and director benefit costs.

Illinois Segment Contribution to Operating Income



	Three Months Ended
(in millions)	March 31, 2016
Natural gas revenues	$	448.5
Cost of natural gas sold	157.3
Total natural gas margins	291.2

Other operation and maintenance	117.9
Depreciation and amortization	32.8
Property and revenue taxes	3.5
Operating income	$	137.0



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



		Therms (in millions)
		Three Months Ended
Natural Gas Sales Volumes		March 31, 2016
Customer Class
Residential		431.6
Commercial and industrial		88.4
Total retail		520.0
Transport		345.9
Total sales in therms		865.9



		Degree Days
		Three Months Ended
Weather *		March 31, 2016
Heating (3,216 Normal)		2,908


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

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

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



	Three Months Ended
(in millions)	March 31, 2016
Environmental cleanup costs	$	10.8
Energy efficiency program	8.8
Bad debt rider	3.5
Total increase in margins and operating expenses	$	23.1

Other States Segment Contribution to Operating Income



	Three Months Ended
(in millions)	March 31, 2016
Natural gas revenues	$	148.4
Cost of natural gas sold	78.4
Total natural gas margins	70.0

Other operation and maintenance	30.0
Depreciation and amortization	5.1
Property and revenue taxes	3.1
Operating income	$	31.8



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



		Therms (in millions)
		Three Months Ended
Natural Gas Sales Volumes		March 31, 2016
Customer Class
Residential		142.0
Commercial and industrial		87.6
Total retail		229.6
Transport		227.1
Total sales in therms		456.7



		Degree Days
		Three Months Ended
Weather *		March 31, 2016
Heating (3,611 Normal)		3,231


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

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

We Power Segment Contribution to Operating Income



	Three Months Ended March 31
(in millions)	2016		2015		B (W)
Operating income	$	93.3	$	92.5	$	0.8

There were no significant changes in operating income for the We Power segment.

Corporate and Other Segment Contribution to Operating Income



	Three Months Ended March 31
(in millions)	2016			2015			B (W)
Operating loss	$	(0.3	)	$	(10.2	)	$	9.9

Operating loss at the corporate and other segment decreased $9.9 million when compared to the first quarter of 2015, driven by $7.8 million of acquisition costs incurred in 2015.

Electric Transmission Segment Operations



	Three Months Ended March 31
(in millions)	2016		2015		B (W)
Equity in earnings of transmission affiliate	$	38.5	$	16.1	$	22.4

Earnings from our ownership interest in ATC increased $22.4 million when compared to the first quarter of 2015, driven by the increase in our ownership interest from 26.2% to approximately 60% as a result of the acquisition of Integrys on June 29, 2015.



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Consolidated Other Income, Net



	Three Months Ended March 31
(in millions)	2016		2015		B (W)
AFUDC – Equity	$	7.0	$	1.7	$	5.3
Gain on repurchase of notes	23.6		—		23.6
Other, net	2.1		1.3		0.8
Other income, net	$	32.7	$	3.0	$	29.7

Other income, net increased by $29.7 million when compared to the first quarter of 2015. The increase was primarily due to the repurchase of a portion of Integrys's 6.11% Junior Notes at a discount in February 2016, as well as higher AFUDC due to the inclusion of AFUDC from the Integrys companies subsequent to the acquisition in June 2015. See Note 6, Long-Term Debt, for more information on the repurchase.

Consolidated Interest Expense



	Three Months Ended March 31
(in millions)	2016		2015		B (W)
Interest expense	$	100.9	$	59.4	$	(41.5	)

Interest expense increased by $41.5 million, or 69.9%, as compared to the first quarter of 2015. The increase was driven by $34.8 million of interest expense from Integrys and its subsidiaries in 2016. Integrys was acquired on June 29, 2015. Additionally, we issued $1.2 billion of long-term debt in June 2015 to finance a portion of the cash consideration for the acquisition of Integrys.

Consolidated Income Tax Expense



	Three Months Ended March 31
	2016		2015		B (W)
Effective tax rate	38.1	%	38.4	%	0.3	%

There were no significant changes in the effective tax rate. We expect our 2016 annual effective tax rate to be between 37.5% and 38.5%.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

The following summarizes our cash flows during the three months ended March 31:



(in millions)	2016			2015			Change in 2016 Over 2015
Cash provided by (used in):
Operating activities	$	695.9		$	330.0		$	365.9
Investing activities	(188.4		)	(156.3		)	(32.1		)
Financing activities	(522.6		)	(170.4		)	(352.2		)

Operating Activities

Net cash provided by operating activities increased $365.9 million in the first quarter of 2016. This increase was driven by $307.8 million of net cash flows from the operating activities of Integrys during the first quarter of 2016, which excludes payments related to the WEC Energy Group income tax allocation agreement. See Note 2, Acquisition, for more information on the acquisition of Integrys.

The remaining $58.1 million increase in net cash provided by operating activities from the legacy Wisconsin Energy Corporation companies was driven by an $89.9 million decrease in contributions and payments related to our pension and OPEB plans. We did not make any contributions to our qualified pension plans during the first quarter of 2016.



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This increase in net cash from the legacy Wisconsin Energy Corporation companies was partially offset by a $41.8 million net decrease in cash related to lower overall collections from customers in the first quarter of 2016, partially offset by an increase in cash from lower payments for natural gas, fuel, and purchased power. This net decrease in cash was primarily due to the impact of lower commodity prices in the first quarter of 2016.

Investing Activities

Net cash used in investing activities increased $32.1 million in the first quarter of 2016, driven by $158.8 million of higher capital expenditures, which is discussed in more detail below.

This increase in net cash used for investing activities was partially offset by:


•	Proceeds of $106.5 million received in the first quarter of 2016 related to the sale of certain businesses.


•	The receipt of $21.0 million of cash from the Rabbi trust to fund deferred compensation and non-qualified pension plan payments in the first quarter of 2016.

Capital Expenditures

Capital expenditures by business segment for the three months ended March 31 were as follows:



Reportable Segment (in millions)	2016		2015		Change in 2016 Over 2015
Wisconsin	$	201.8	$	147.9	$	53.9
Illinois	76.2		—		76.2
Other states	10.3		—		10.3
We Power	4.2		3.9		0.3
Corporate and other	19.5		1.4		18.1
Total capital expenditures	$	312.0	$	153.2	$	158.8

The increase in capital expenditures for the Wisconsin segment in the first quarter of 2016 was due to the inclusion of WPS. WPS's capital expenditures of $90.7 million in the first quarter of 2016 primarily related to the ReACT^TM emission control technology project at Weston Unit 3 as well as a combustion turbine project at the Fox Energy Center. Partially offsetting this increase was lower capital expenditures in the first quarter of 2016 for WG's Western Gas Lateral project, which was completed in November 2015.

The Illinois segment includes capital expenditures from PGL and NSG in the first quarter of 2016. PGL continues to incur significant capital expenditures related to the AMRP.

The other states segment includes capital expenditures from MERC and MGU in the first quarter of 2016.

The increase in capital expenditures for the corporate and other segment in the first quarter of 2016 was driven by an information technology project related to improving the billing, call center, and credit collection functions of Integrys as well as other software projects.

See Significant Capital Projects below for more information.

Financing Activities

Net cash used in financing activities increased $352.2 million in the first quarter of 2016, driven by:


•	A $144.0 million increase in the repayment of commercial paper in the first quarter of 2016.


•	A $130.1 million increase in the retirement of long-term debt. In February 2016, we repurchased a portion of Integrys's 6.11% Junior Notes at a discount.


•	A $60.9 million increase in dividends paid on common stock due to the issuance of 90.2 million shares in 2015 as a result of the Integrys acquisition as well as a higher quarterly dividend rate in the first quarter of 2016.



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•	A $36.2 million increase in cash used to purchase shares of our common stock in the first quarter of 2016 to satisfy requirements of certain stock-based employee benefit and compensation plans.

These increases in net cash used in financing activities were partially offset by a $13.0 million increase in cash received from stock option exercises in the first quarter of 2016.

Significant Financing Activities

For information on our short-term debt, see Note 5, Short-Term Debt and Lines of Credit.

For information on our long-term debt, see Note 6, Long-Term Debt.

Capital Resources and Requirements

Capital Resources

Liquidity

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

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

WEC Energy Group, WE, WG, WPS, and PGL maintain bank back-up credit facilities, which provide liquidity support for each company's obligations with respect to commercial paper and for general corporate purposes. We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. See Note 5, Short-Term Debt and Lines of Credit, for more information about these credit facilities. See Note 6, Long-Term Debt, for more information about our long-term debt.

The following table shows our capitalization structure as of March 31, 2016, as well as an adjusted capitalization structure that we believe is consistent with the manner in which the rating agencies currently view our 2007 6.25% Series A Junior Subordinated Notes due 2067, Integrys's 6.11% Junior Notes, and Integrys's 2013 6.00% Junior Subordinated Notes due 2073 (collectively, Junior Notes):



(in millions)	Actual			Adjusted
Common equity	$	8,818.3		$	9,325.7
Preferred stock of subsidiary	30.4			30.4
Long-term debt (including current maturities)	9,108.2			8,600.8
Short-term debt	896.4			896.4
Total capitalization	$	18,853.3		$	18,853.3

Total debt	$	10,004.6		$	9,497.2

Ratio of debt to total capitalization	53.1		%	50.4		%

Included in long-term debt on our balance sheet as of March 31, 2016, is $1,014.9 million aggregate principal amount of Junior Notes. The adjusted presentation attributes $507.4 million of the Junior Notes to common equity and $507.5 million to long-term debt. We believe this presentation is consistent with the 50% equity credit the majority of rating agencies currently attribute to the Junior Notes.

The adjusted presentation of our consolidated capitalization structure is presented as a complement to our capitalization structure presented in accordance with GAAP. Management evaluates and manages our capitalization structure, including our total debt to total capitalization ratio, using the GAAP calculation as adjusted by the rating agency treatment of the Junior Notes. Therefore, we



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believe the non-GAAP adjusted presentation reflecting this treatment is useful and relevant to investors in understanding how management and the rating agencies evaluate our capitalization structure.

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

WE is the obligor under two series of tax-exempt pollution control refunding bonds in an outstanding principal amount of $147.0 million. In August 2009, WE terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. WE purchased the bonds at par plus accrued interest to the date of purchase. As of March 31, 2016, the repurchased bonds were still outstanding, but were not reported in our consolidated long-term debt because they are held by WE. One of the series of bonds, with $67.0 million aggregate principal amount outstanding, matures on August 1, 2016. Depending on market conditions and other factors, WE may change the method used to determine the interest rate on the other series of bonds and have them remarketed to third parties.

Working Capital

As of March 31, 2016, our current liabilities exceeded our current assets by approximately $333.4 million. We do not expect this to have any impact on our liquidity because we believe we have adequate back-up lines of credit in place for ongoing operations. We also have access to the capital markets to finance our construction programs and to refinance current maturities of long-term debt if necessary.

Capital Requirements

Significant Capital Projects

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



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

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

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

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

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



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Common Stock Dividends

On January 21, 2016, our Board of Directors increased our quarterly common stock dividend to $0.4950 per share. This represents an 8.2% increase over the prior quarterly rate and equates to an annual dividend of $1.98 per share.

Off-Balance Sheet Arrangements

We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit which support construction projects, commodity contracts, and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future 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 10, Guarantees, and Note 15, Variable Interest Entities.

Contractual Obligations

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

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

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

Regulatory Recovery

Regulated entities are allowed to defer certain costs that would otherwise be charged to expense, if the regulated entity believes the recovery of these costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by our regulators. Recovery of these deferred costs in future rates is subject to the review and approval by those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of these deferred costs, including those referenced below are 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.

The following includes various projects discussed in recent and pending rate proceedings, orders, and investigations involving our utilities that we will be or have requested recovery for:


•	The PSCW approved deferral of costs related to WPS's ReACT™ project above the originally authorized $275.0 million level through 2016. WPS will be required to obtain a separate approval for collection of these deferred costs.

•

Prior to the acquisition of Integrys, 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 March 31, 2016, none of the costs for this project have been disallowed in rate proceedings. We will be required to obtain approval for the recovery of additional costs incurred through the completion of this long-term project.


•	In January 2014, the ICC approved PGL's use of the Qualifying Infrastructure Plant rider as a recovery mechanism for costs incurred related to investments in qualifying infrastructure plant. This rider is subject to an annual audit process whereby costs are reviewed for accuracy and prudency. The 2014 audit process has been placed on a stay due to the stakeholder workshops



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ordered by the ICC in December 2015 to evaluate the AMRP. No procedural dates are currently in place for the 2015 audit process. As of March 31, 2016, none of the costs for this project have been disallowed as a result of the audits or investigations.

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

Environmental Matters

Cross-State Air Pollution Rule

In July 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR), which replaced a previous rule, the Clean Air Interstate Rule (CAIR). The purpose of the CSAPR was to limit the interstate transport of emissions of NOx and SO₂ that contribute to fine particulate matter and ozone nonattainment in downwind states through a proposed allocation plan and allowance trading scheme. The rule was to become effective in January 2012. However, in December 2011, the CSAPR requirements were stayed by the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court of Appeals) and CAIR was implemented during the stay period. In August 2012, the D.C. Circuit Court of Appeals issued a ruling vacating and remanding CSAPR and simultaneously reinstating CAIR pending the issuance of a replacement rule by the EPA. The case was appealed to the United States Supreme Court (Supreme Court). In April 2014, the Supreme Court issued a decision largely upholding CSAPR and remanded it to the D.C. Circuit Court of Appeals for further proceedings. In October 2014, the D.C. Circuit Court of Appeals issued a decision that allowed the EPA to begin implementing CSAPR on January 1, 2015. The compliance deadlines were also changed by three years, so that Phase I emissions budgets apply in 2015 and 2016, and Phase 2 emissions budgets will apply to 2017 and beyond.

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

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

Other Matters

American Transmission Company Allowed Return on Equity Complaints

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

In February 2015, a second complaint was filed with the FERC requesting a reduction in the base ROE used by MISO transmission owners, including ATC, to 8.67%, with a refund effective date retroactive to the filing date of the complaint. The FERC conducted hearings in February 2016 with respect to this second complaint, and an initial decision is expected by June 30, 2016.

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



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Any change to ATC's ROE could result in lower equity earnings and distributions from ATC in the future. We are currently unable to determine how the FERC may rule in these complaints. However, we believe it is probable that refunds will be required upon resolution of these issues. Based on the ALJ's initial decision in December 2015, ATC reduced its earnings in the fourth quarter of 2015, which resulted in us recognizing lower earnings from our investment in ATC.

Wisconsin Power and Light's Riverside Energy Center Facility

In April 2015, Wisconsin Power and Light Company (WP&L) filed a Certificate of Public Convenience and Necessity application with the PSCW for approval to construct an approximate 650 MW natural gas-fired combined-cycle generating unit in Beloit, Wisconsin. Construction proposals received by WP&L indicate that the unit could generate up to 700 MWs. In the third quarter of 2015, WE and WPS requested and received intervention in this proceeding. As intervenors, WE and WPS proposed purchased power agreement alternatives to the new generating unit. In December 2015, WE, WPS, and WP&L entered into a settlement agreement that was approved by the PSCW. Based on the settlement agreement, the generating unit cannot become commercially operational before June 1, 2020. In addition, WP&L must enter into a purchased power agreement with WE for MISO planning years 2017, 2018, and 2019, whereby WE will sell and WP&L will purchase capacity and energy at certain agreed upon prices. WPS also will have the option to purchase an undivided ownership interest of up to 100 MWs of generating capacity from the unit during the first two years of operation and up to an aggregate 200 MWs of generating capacity during the third and fourth years of operation. Other major terms of the settlement include an agreement on ownership of future WE and WPS natural gas units, negotiation of a renewable generation joint development plan, and ownership terms of the jointly-owned Columbia plant. In March 2016, the PSCW approved the construction of the new natural gas-fired generating unit.



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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 Reports on Form 10-K for the year ended December 31, 2015. In addition to the Form 10-K disclosures, see Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in Item 2 of 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 first quarter of 2016 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 2015 Annual Report on Form 10-K. See Note 16, Commitments and Contingencies, and Note 18, Regulatory Environment, in this report for more information on material legal proceedings and matters related to us and our subsidiaries.

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

Environmental Matters

Sheboygan River Matter

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

Other Matters

Litigation Relating to the Acquisition of Integrys

After the announcement of the acquisition, Integrys and its board of directors, along with WEC Energy Group, were named as defendants in ten separate purported class action lawsuits filed in Brown County, Wisconsin (three of the cases – Rubin v. Integrys, et al., Blachor v. Integrys, et al., and Albera v. Integrys, et al.), Milwaukee County, Wisconsin (two of the cases – Amo v. Integrys, et al. and Inman v. Integrys, et al.), Cook County, Illinois (two of the cases – Taxman v. Integrys, et al. and Curley v. Integrys, et al.), and the federal court for the Northern District of Illinois (three of the cases – Steiner v. Integrys, et al., Tri-State Joint Fund v. Integrys, et al., and Collison v. Integrys, et al.). In the Tri-State Joint Fund case, WEC Energy Group’s then CEO was also named as a defendant. The cases were brought on behalf of proposed classes consisting of former shareholders of Integrys. The complaints alleged, among other things, that the Integrys board members breached their fiduciary duties by failing to maximize the value to be received by Integrys’s shareholders, that WEC Energy Group aided and abetted the breaches of fiduciary duty, and that the joint proxy statement/prospectus contained material misstatements and omissions. The Brown County and Cook County cases were dismissed in favor of the Milwaukee County actions. In November 2014, the parties entered into a Memorandum of Understanding which provided the basis for a complete settlement of these actions. A Stipulation of Settlement was presented to the Court in late July 2015. In December 2015, the Court approved the settlement and entered a final judgment in this matter, which resulted in the complete dismissal of all remaining actions. The period to appeal the Court's order in this matter ended on March 16, 2016, with no filings. The settlement is now final.

ITEM 1A. RISK FACTORS

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



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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 March 31, 2016:

Issuer Purchases of Equity Securities



2016	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
January 1 – January 31 *	23,352	$	53.08	—	$	—
February 1 – February 29	—	$	—	—	$	—
March 1 – March 31	—	$	—	—	$	—
Total	23,352	$	53.08	—


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



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ITEM 6. EXHIBITS



Number	Exhibit
3	Articles of Incorporation and By-laws

	3.1	Bylaws of WEC Energy Group, Inc., as amended to May 1, 2016.

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

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

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

32	Section 1350 Certifications

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

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

101	Interactive Data File



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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:	May 6, 2016	William J. Guc
		Vice President and Controller

		(Duly Authorized Officer and Chief Accounting Officer)



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