10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period EndedMarch 31, 2017

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

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

Yes [X]    No [  ]

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

Yes [X]    No [  ]

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

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

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

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

Yes [  ]    No [X]

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

Common Stock, $.01 Par Value,

315,579,222 shares outstanding at

March 31, 2017

WEC ENERGY GROUP, INC.

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended March 31, 2017

TABLE OF CONTENTS

				Page
	CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION			1
PART I.	FINANCIAL INFORMATION			3
ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)			3
	Condensed Consolidated Income Statements			3
	Condensed Consolidated Statements of Comprehensive Income			4
	Condensed Consolidated Balance Sheets			5
	Condensed Consolidated Statements of Cash Flows			6
	Notes to Condensed Consolidated Financial Statements			7
			Page
	Note 1	General Information	7
	Note 2	Acquisition	7
	Note 3	Dispositions	7
	Note 4	Common Equity	8
	Note 5	Short-Term Debt and Lines of Credit	9
	Note 6	Materials, Supplies, and Inventories	9
	Note 7	Fair Value Measurements	10
	Note 8	Derivative Instruments	12
	Note 9	Guarantees	13
	Note 10	Employee Benefits	13
	Note 11	Investment in American Transmission Company	14
	Note 12	Segment Information	15
	Note 13	Variable Interest Entities	16
	Note 14	Commitments and Contingencies	17
	Note 15	Supplemental Cash Flow Information	21
	Note 16	Regulatory Environment	22
	Note 17	New Accounting Pronouncements	24
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			26
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			41
ITEM 4.	CONTROLS AND PROCEDURES			42
PART II.	OTHER INFORMATION			43
ITEM 1.	LEGAL PROCEEDINGS			43
ITEM 1A.	RISK FACTORS			43
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			44
ITEM 6.	EXHIBITS			45
SIGNATURE				46

03/31/2017 Form 10-Q i WEC Energy Group, Inc.

GLOSSARY OF TERMS AND ABBREVIATIONS

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

Subsidiaries and Affiliates
ATC	American Transmission Company LLC
Bostco	Bostco LLC
Integrys	Integrys Holding, Inc.
ITF	Integrys Transportation Fuels, LLC
MERC	Minnesota Energy Resources Corporation
MGU	Michigan Gas Utilities Corporation
NSG	North Shore Gas Company
PGL	The Peoples Gas Light and Coke Company
UMERC	Upper Michigan Energy Resources Corporation
WBS	WEC Business Services LLC
WE	Wisconsin Electric Power Company
We Power	W.E. Power, LLC
WG	Wisconsin Gas LLC
Wisvest	Wisvest LLC
WPS	Wisconsin Public Service Corporation
Federal and State Regulatory Agencies
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
ICC	Illinois Commerce Commission
MDEQ	Michigan Department of Environmental Quality
MPSC	Michigan Public Service Commission
MPUC	Minnesota Public Utilities Commission
PSCW	Public Service Commission of Wisconsin
SEC	United States Securities and Exchange Commission
WDNR	Wisconsin Department of Natural Resources
Accounting Terms
AFUDC	Allowance for Funds Used During Construction
ASU	Accounting Standards Update
FASB	Financial Accounting Standards Board
GAAP	United States Generally Accepted Accounting Principles
LIFO	Last-In, First-Out
OPEB	Other Postretirement Employee Benefits
Environmental Terms
CAA	Clean Air Act
CO2	Carbon Dioxide
CSAPR	Cross-State Air Pollution Rule
GHG	Greenhouse Gas
NAAQS	National Ambient Air Quality Standards
NOV	Notice of Violation
NOx	Nitrogen Oxide
SO2	Sulfur Dioxide

03/31/2017 Form 10-Q ii WEC Energy Group, Inc.

Measurements
Dth	Dekatherm
MW	Megawatt
MWh	Megawatt-hour
Other Terms and Abbreviations
6.11% Junior Notes	Integrys's 2006 6.11% Junior Subordinated Notes Due 2066
ALJ	Administrative Law Judge
CNG	Compressed Natural Gas
D.C. Circuit Court of Appeals	United States Court of Appeals for the District of Columbia Circuit
ERGS	Elm Road Generating Station
Exchange Act	Securities Exchange Act of 1934, as amended
FTRs	Financial Transmission Rights
MCPP	Milwaukee County Power Plant
MISO	Midcontinent Independent System Operator, Inc.
MISO Energy Markets	MISO Energy and Operating Reserves Markets
OCPP	Oak Creek Power Plant
OC 5	Oak Creek Power Plant Unit 5
OC 6	Oak Creek Power Plant Unit 6
OC 7	Oak Creek Power Plant Unit 7
OC 8	Oak Creek Power Plant Unit 8
PIPP	Presque Isle Power Plant
QIP	Qualifying Infrastructure Plant
ROE	Return on Equity
SMP	Gas System Modernization Program
SMRP	System Modernization and Reliability Project
Supreme Court	United States Supreme Court
VAPP	Valley Power Plant

03/31/2017 Form 10-Q iii WEC Energy Group, Inc.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

Forward-looking statements are subject to a number of risks and uncertainties that could cause our actual results to differ materially from those expressed or implied in the statements. These risks and uncertainties include those described in risk factors as set forth in this report and our Annual Report on Form 10-K for the year ended December 31, 2016, and those identified below:

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

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

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

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

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

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

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

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

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

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

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

03/31/2017 Form 10-Q 1 WEC Energy Group, Inc.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

03/31/2017 Form 10-Q 2 WEC Energy Group, Inc.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited)	Three Months Ended
	March 31
(in millions, except per share amounts)	2017			2016
Operating revenues	$	2,304.5		$	2,194.8
Operating expenses
Cost of sales	941.1			838.9
Other operation and maintenance	501.9			531.5
Depreciation and amortization	194.6			187.9
Property and revenue taxes	49.6			47.2
Total operating expenses	1,687.2			1,605.5
Operating income	617.3			589.3
Equity in earnings of transmission affiliate	41.9			38.5
Other income, net	15.7			32.7
Interest expense	104.7			100.9
Other expense	(47.1		)	(29.7		)
Income before income taxes	570.2			559.6
Income tax expense	213.3			213.1
Net income	356.9			346.5
Preferred stock dividends of subsidiary	0.3			0.3
Net income attributed to common shareholders	$	356.6		$	346.2
Earnings per share
Basic	$	1.13		$	1.10
Diluted	$	1.12		$	1.09
Weighted average common shares outstanding
Basic	315.6			315.7
Diluted	317.2			317.1
Dividends per share of common stock	$	0.5200		$	0.4950

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

03/31/2017 Form 10-Q 3 WEC Energy Group, Inc.

WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)	Three Months Ended
	March 31
(in millions)	2017			2016
Net income	$	356.9		$	346.5
Other comprehensive loss, net of tax
Derivatives accounted for as cash flow hedges
Reclassification of gains to net income, net of tax	(0.3		)	(0.3		)
Defined benefit plans
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax	0.1			—
Other comprehensive loss, net of tax	(0.2		)	(0.3		)
Comprehensive income	356.7			346.2
Preferred stock dividends of subsidiary	0.3			0.3
Comprehensive income attributed to common shareholders	$	356.4		$	345.9

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

03/31/2017 Form 10-Q 4 WEC Energy Group, Inc.

WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts)	March 31, 2017		December 31, 2016
Assets
Current assets
Cash and cash equivalents	$	45.7	$	37.5
Accounts receivable and unbilled revenues, net of reserves of $123.1 and $108.0, respectively	1,191.4		1,241.7
Materials, supplies, and inventories	417.1		587.6
Prepayments	161.8		204.4
Other	39.3		97.5
Current assets	1,855.3		2,168.7
Long-term assets
Property, plant, and equipment, net of accumulated depreciation of $8,312.8 and $8,214.6, respectively	19,990.2		19,915.5
Regulatory assets	3,084.1		3,087.9
Equity investment in transmission affiliate	1,513.3		1,443.9
Goodwill	3,046.2		3,046.2
Other	527.5		461.0
Long-term assets	28,161.3		27,954.5
Total assets	$	30,016.6	$	30,123.2
Liabilities and Equity
Current liabilities
Short-term debt	$	670.4	$	860.2
Current portion of long-term debt	158.0		157.2
Accounts payable	582.3		861.5
Accrued payroll and benefits	107.5		163.8
Accrued interest	115.1		67.0
Other	421.3		321.9
Current liabilities	2,054.6		2,431.6
Long-term liabilities
Long-term debt	9,143.6		9,158.2
Deferred income taxes	5,287.4		5,146.6
Deferred revenue, net	561.0		566.2
Regulatory liabilities	1,563.4		1,563.8
Environmental remediation liabilities	630.7		633.6
Pension and OPEB obligations	458.9		498.6
Other	1,161.0		1,164.4
Long-term liabilities	18,806.0		18,731.4
Commitments and contingencies (Note 14)
Common shareholders' equity
Common stock – $0.01 par value; 325,000,000 shares authorized; 315,579,222 and 315,614,941 shares outstanding, respectively	3.2		3.2
Additional paid in capital	4,297.7		4,309.8
Retained earnings	4,822.0		4,613.9
Accumulated other comprehensive income	2.7		2.9
Common shareholders' equity	9,125.6		8,929.8
Preferred stock of subsidiary	30.4		30.4
Total liabilities and equity	$	30,016.6	$	30,123.2

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

03/31/2017 Form 10-Q 5 WEC Energy Group, Inc.

WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Three Months Ended
	March 31
(in millions)	2017			2016
Operating Activities
Net income	$	356.9		$	346.5
Reconciliation to cash provided by operating activities
Depreciation and amortization	194.6			191.9
Deferred income taxes and investment tax credits, net	150.2			214.6
Contributions and payments related to pension and OPEB plans	(106.0		)	(15.1		)
Equity income in transmission affiliate, net of distributions	(6.7		)	(23.4		)
Change in –
Accounts receivable and unbilled revenues	55.0			(48.6		)
Materials, supplies, and inventories	170.5			217.2
Other current assets	41.2			(63.7		)
Accounts payable	(212.7		)	(123.7		)
Other current liabilities	90.8			56.7
Other, net	(19.2		)	(56.5		)
Net cash provided by operating activities	714.6			695.9
Investing Activities
Capital expenditures	(329.7		)	(312.0		)
Capital contributions to transmission affiliate	(27.6		)	(9.0		)
Proceeds from the sale of assets and businesses	13.1			106.5
Withdrawal of restricted cash from Rabbi trust for qualifying payments	16.1			21.0
Other, net	2.5			5.1
Net cash used in investing activities	(325.6		)	(188.4		)
Financing Activities
Exercise of stock options	5.9			21.4
Purchase of common stock	(20.2		)	(59.6		)
Dividends paid on common stock	(164.1		)	(156.2		)
Retirement of long-term debt	(12.0		)	(139.4		)
Change in short-term debt	(189.8		)	(198.6		)
Other, net	(0.6		)	9.8
Net cash used in financing activities	(380.8		)	(522.6		)
Net change in cash and cash equivalents	8.2			(15.1		)
Cash and cash equivalents at beginning of period	37.5			49.8
Cash and cash equivalents at end of period	$	45.7		$	34.7

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

03/31/2017 Form 10-Q 6 WEC Energy Group, Inc.

WEC ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

March 31, 2017

NOTE 1—GENERAL INFORMATION

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

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

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2016. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three months ended March 31, 2017, are not necessarily indicative of expected results for 2017 due to seasonal variations and other factors.

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

NOTE 2—ACQUISITION

Acquisition of a Natural Gas Storage Facility in Michigan

In January 2017, we signed an agreement for the acquisition of a natural gas storage facility in Michigan for $225 million that would provide approximately one-third of the current storage needs for our Wisconsin natural gas utilities. In addition, we expect to incur approximately $5 million of acquisition related costs. A request has been filed with the PSCW for a declaratory ruling related to the recovery of this investment. PSCW approval and closing of this transaction are expected to occur by the third quarter of 2017.

NOTE 3—DISPOSITIONS

Wisconsin Segment

Sale of Milwaukee County Power Plant

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

Corporate and Other Segment

Sale of Bostco Real Estate Holdings

In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space. During the first quarter of 2017, we recorded an insignificant gain on the sale, which was included in other income, net on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations associated with these assets remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.

03/31/2017 Form 10-Q 7 WEC Energy Group, Inc.

Sale of Certain Assets of Wisvest

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

Sale of Integrys Transportation Fuels

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

NOTE 4—COMMON EQUITY

Stock-Based Compensation

During the first quarter of 2017, the Compensation Committee of our Board of Directors awarded the following stock-based compensation awards to our directors, officers, and certain other key employees:

Award Type	Number of Awards
Stock options (1)	552,215
Restricted shares (2)	82,622
Performance units	237,650

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

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

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which modifies certain aspects of the accounting for stock-based compensation awards. This ASU became effective for us on January 1, 2017. Under the new guidance, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement on a prospective basis. Prior to January 1, 2017, these amounts were recorded in additional paid in capital on the balance sheet, and the tax benefits could only be recognized to the extent they reduced taxes payable. In the first quarter of 2017, we recorded a $15.7 million cumulative-effect adjustment to retained earnings for excess tax benefits that had not been recognized in prior years as they did not reduce taxes payable. The following table shows the changes to our retained earnings for the three months ended March 31, 2017:

(in millions)	Retained Earnings
Balance at December 31, 2016	$	4,613.9
Net income attributed to common shareholders	356.6
Common stock dividends	(164.1		)
Cumulative effect of adoption of ASU 2016-09	15.7
Other	(0.1		)
Balance at March 31, 2017	$	4,822.0

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

03/31/2017 Form 10-Q 8 WEC Energy Group, Inc.

Restrictions

Our ability as a holding company to pay common stock dividends primarily depends on the availability of funds received from our utility subsidiaries and our non-utility subsidiary, We Power. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans, or advances. All of our utility subsidiaries, with the exception of MGU, are prohibited from loaning funds to us, either directly or indirectly. See Note 11, Common Equity, in our 2016 Annual Report on Form 10-K for additional information on these and other restrictions.

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

Common Stock Dividends

On April 20, 2017, our Board of Directors declared a quarterly cash dividend of $0.52 per share, payable on June 1, 2017, to stockholders of record on May 12, 2017.

NOTE 5—SHORT-TERM DEBT AND LINES OF CREDIT

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

(in millions, except percentages)	March 31, 2017			December 31, 2016
Commercial paper
Amount outstanding	$	670.4		$	860.2
Weighted-average interest rate on amounts outstanding	1.18		%	0.96		%

Our average amount of commercial paper borrowings based on daily outstanding balances during the three months ended March 31, 2017, was $746.2 million with a weighted-average interest rate during the period of 1.01%.

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, 2017
WEC Energy Group	December 2020	$	1,050.0
WE	December 2020	500.0
WPS	December 2020	250.0
WG	December 2020	350.0
PGL	December 2020	350.0
Total short-term credit capacity		$	2,500.0
Less:
Letters of credit issued inside credit facilities		$	29.1
Commercial paper outstanding		670.4
Available capacity under existing agreements		$	1,800.5

NOTE 6—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:

(in millions)	March 31, 2017		December 31, 2016
Natural gas in storage	$	45.8	$	223.1
Materials and supplies	208.3		206.5
Fossil fuel	163.0		158.0
Total	$	417.1	$	587.6

PGL and NSG price natural gas storage injections at the calendar year average of the cost of natural gas supply purchased. Withdrawals from storage are priced using the LIFO cost method. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. At March 31, 2017, we had a temporary LIFO liquidation credit of $31.6 million recorded within other

03/31/2017 Form 10-Q 9 WEC Energy Group, Inc.

current liabilities on our balance sheet. Due to seasonality requirements, PGL and NSG expect these interim reductions in LIFO layers to be replenished by year end.

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

NOTE 7—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.

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, 2017
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	2.3	$	9.5	$	—	$	11.8
FTRs	—		—		1.7		1.7
Coal contracts	—		1.0		—		1.0
Total derivative assets	$	2.3	$	10.5	$	1.7	$	14.5
Investments held in rabbi trust	$	101.7	$	—	$	—	$	101.7
Derivative liabilities
Natural gas contracts	$	—	$	0.9	$	—	$	0.9
Petroleum products contracts	0.3		—		—		0.3
Coal contracts	—		3.0		—		3.0
Total derivative liabilities	$	0.3	$	3.9	$	—	$	4.2

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	December 31, 2016
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	10.1	$	24.2	$	—	$	34.3
Petroleum products contracts	0.2		—		—		0.2
FTRs	—		—		5.1		5.1
Coal contracts	—		2.0		—		2.0
Total derivative assets	$	10.3	$	26.2	$	5.1	$	41.6
Investments held in rabbi trust	$	103.9	$	—	$	—	$	103.9
Derivative liabilities
Natural gas contracts	$	0.2	$	0.2	$	—	$	0.4
Petroleum products contracts	0.1		—		—		0.1
Coal contracts	—		1.9		—		1.9
Total derivative liabilities	$	0.3	$	2.1	$	—	$	2.4

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

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

	Three Months Ended March 31
(in millions)	2017			2016
Balance at the beginning of the period	$	5.1		$	3.6
Realized and unrealized losses	—			(0.2		)
Sales	—			(0.1		)
Settlements	(3.4		)	(2.2		)
Balance at the end of the period	$	1.7		$	1.1

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, 2017				December 31, 2016
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock	$	30.4	$	28.9	$	30.4	$	28.8
Long-term debt, including current portion *	9,272.7		9,730.2		9,285.8		9,818.2

* The carrying amount of long-term debt excludes capital lease obligations of $28.9 million and $29.6 million at March 31, 2017 and

December 31, 2016, respectively.

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

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NOTE 8—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, 2017				December 31, 2016
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	11.4	$	0.7	$	31.4	$	0.4
Petroleum products contracts	—		0.3		0.2		0.1
FTRs	1.7		—		5.1		—
Coal contracts	1.0		1.8		1.5		1.4
Total other current *	$	14.1	$	2.8	$	38.2	$	1.9
Other long-term
Natural gas contracts	$	0.4	$	0.2	$	2.9	$	—
Coal contracts	—		1.2		0.5		0.5
Total other long-term *	$	0.4	$	1.4	$	3.4	$	0.5
Total	$	14.5	$	4.2	$	41.6	$	2.4

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

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

	Three Months Ended March 31, 2017				Three Months Ended March 31, 2016
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	34.1 Dth	$	(0.3	)	50.1 Dth	$	(33.5	)
Petroleum products contracts	4.9 gallons	(0.5		)	3.0 gallons	(1.1		)
FTRs	9.2 MWh	3.0			7.6 MWh	3.0
Total		$	2.2			$	(31.6	)

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, 2017 and December 31, 2016, we had posted cash collateral of $19.3 million and $16.4 million, respectively, in our margin accounts. These amounts were recorded on the balance sheets in other current assets. At December 31, 2016, we had also received cash collateral of $4.4 million in our margin accounts. This amount was recorded on our balance sheet in other current liabilities.

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

	March 31, 2017						December 31, 2016
(in millions)	Derivative Assets			Derivative Liabilities			Derivative Assets				Derivative Liabilities
Gross amount recognized on the balance sheet	$	14.5		$	4.2		$	41.6			$	2.4
Gross amount not offset on the balance sheet	(1.2		)	(1.2		)	(4.9		)	*	(0.5		)
Net amount	$	13.3		$	3.0		$	36.7			$	1.9

* Includes cash collateral received of $4.4 million.

Certain of our derivative and nonderivative commodity instruments contain provisions that could require "adequate assurance" in the event of a material change in our creditworthiness, or the posting of additional collateral for instruments in net liability positions, if triggered by a decrease in credit ratings. The aggregate fair value of all derivative instruments with specific credit risk-related contingent features that were in a net liability position was $0.9 million and $0.2 million at March 31, 2017 and December 31, 2016, respectively. At March 31, 2017 and December 31, 2016, we had not posted any collateral related to the credit risk-related contingent features of these commodity instruments. If all of the credit risk-related contingent features contained in derivative instruments in a net liability position had been triggered at March 31, 2017 and December 31, 2016, we would not have been required to post any collateral.

NOTE 9—GUARANTEES

The following table shows our outstanding guarantees:

	Total Amounts Committed at		Expiration
(in millions)	March 31, 2017		Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees
Standby letters of credit (1)	$	29.1	$	28.0	$	1.1	$	—
Surety bonds (2)	10.9		10.2		0.7		—
Other guarantees (3)	8.1		0.5		—		7.6
Total guarantees	$	48.1	$	38.7	$	1.8	$	7.6

⁽¹⁾  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.

⁽²⁾  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.

⁽³⁾  Consists of $8.1 million related to other indemnifications, for which a liability of $7.6 million related to workers compensation coverage was recorded on our balance sheets.

NOTE 10—EMPLOYEE BENEFITS

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

	Pension Costs
	Three Months Ended March 31
(in millions)	2017			2016
Service cost	$	11.7		$	11.3
Interest cost	31.2			33.2
Expected return on plan assets	(49.6		)	(49.0		)
Amortization of prior service cost	0.7			0.9
Amortization of net actuarial loss	21.9			20.5
Net periodic benefit cost	$	15.9		$	16.9

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	OPEB Costs
	Three Months Ended March 31
(in millions)	2017			2016
Service cost	$	6.3		$	6.7
Interest cost	8.5			9.2
Expected return on plan assets	(13.7		)	(13.1		)
Amortization of prior service credit	(2.8		)	(2.3		)
Amortization of net actuarial loss	1.5			2.3
Net periodic benefit (credit) cost	$	(0.2	)	$	2.8

During the three months ended March 31, 2017, we made payments of $104.1 million to our pension plans and $1.9 million to our OPEB plans. We expect to make payments of $9.0 million related to our pension plans and $6.5 million related to our OPEB plans during the remainder of 2017, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

NOTE 11—INVESTMENT IN AMERICAN TRANSMISSION COMPANY

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

	Three Months Ended March 31
(in millions)	2017		2016
Balance at beginning of period	$	1,443.9	$	1,380.9
Add: Earnings from equity method investment	41.9		38.5
Add: Capital contributions	27.6		9.0
Add: Adjustment to equity method goodwill	—		9.3
Less: Distributions *	—		15.1
Less: Other	0.1		0.1
Balance at end of period	$	1,513.3	$	1,422.5

* Distributions of $35.2 million, received in the first quarter of 2017, were approved and recorded in December 2016.

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

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

	Three Months Ended March 31
(in millions)	2017			2016
Charges to ATC for services and construction	$	4.2		$	4.1
Charges from ATC for network transmission services	87.3			100.8
Refund from ATC per FERC ROE order	(28.3		)	—

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

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

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

	Three Months Ended March 31
(in millions)	2017		2016
Income statement data
Revenues	$	174.7	$	164.2
Operating expenses	82.4		79.1
Other expense	26.4		24.0
Net income	$	65.9	$	61.1

(in millions)	March 31, 2017		December 31, 2016
Balance sheet data
Current assets	$	85.5	$	75.8
Noncurrent assets	4,402.2		4,312.9
Total assets	$	4,487.7	$	4,388.7
Current liabilities	$	401.8	$	495.1
Long-term debt	1,940.4		1,865.3
Other noncurrent liabilities	282.9		271.5
Shareholders' equity	1,862.6		1,756.8
Total liabilities and shareholders' equity	$	4,487.7	$	4,388.7

NOTE 12—SEGMENT INFORMATION

At March 31, 2017, we reported six segments, which are described below.

• The Wisconsin segment includes the electric and natural gas utility operations of WE, WG, and WPS, including WE's and WPS's electric and natural gas operations in the state of Michigan that were transferred to UMERC effective January 1, 2017.

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

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

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

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

• The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the Peoples Energy, LLC holding company, Wispark LLC, Bostco, Wisvest, Wisconsin Energy Capital Corporation, WBS, WPS Power Development LLC, and ITF. The sale of ITF was completed in the first quarter of 2016. In the first quarter of 2017, we sold substantially all of the remaining assets of Bostco and in the second quarter of 2016, we sold certain assets of Wisvest. See Note 3, Dispositions, for more information on these sales.

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All of our operations are located within the United States. The following tables show summarized financial information related to our reportable segments for the three months ended March 31, 2017 and 2016:

	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, 2017
External revenues	$	1,612.1	$	525.3	$	157.9	$	—	$	2,295.3	$	6.3	$	2.9		$	—		$	2,304.5
Intersegment revenues	—		—		—		—		—		109.0		—			(109.0		)	—
Other operation and maintenance	462.9		120.9		28.3		—		612.1		0.4		(1.6		)	(109.0		)	501.9
Depreciation and amortization	129.3		36.2		6.0		—		171.5		17.5		5.6			—			194.6
Operating income (loss)	332.3		155.4		33.4		—		521.1		97.4		(1.2		)	—			617.3
Equity in earnings of transmission affiliate	—		—		—		41.9		41.9		—		—			—			41.9
Interest expense	48.7		11.1		2.3		—		62.1		15.3		29.1			(1.8		)	104.7

	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

NOTE 13—VARIABLE INTEREST ENTITIES

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

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

American Transmission Company

We own approximately 60% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. We have determined that ATC is a variable interest entity but that consolidation is not required since we are not ATC's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC's economic performance. We account for ATC as an equity method investment. See Note 11, 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, 2017 and December 31, 2016, our equity investment was $1,513.3 million and $1,443.9 million, respectively,

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which approximates our maximum exposure to loss as a result of our involvement with ATC. In addition, we had $29.1 million and $28.7 million of accounts payable due to ATC at March 31, 2017 and December 31, 2016, respectively, for network transmission services.

Purchased Power Agreement

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

We have approximately $81.9 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under this contract for the three months ended March 31, 2017 and 2016 were $4.5 million and $13.5 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

NOTE 14—COMMITMENTS AND CONTINGENCIES

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

Unconditional Purchase Obligations

Our electric utilities have obligations to distribute and sell electricity to their customers, and our natural gas utilities have obligations to distribute and sell natural gas to their customers. The utilities expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of March 31, 2017, including those of our subsidiaries, were $11,774.4 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

Cross-State Air Pollution Rule

In July 2011, the EPA issued the CSAPR, which replaced a previous rule, the Clean Air Interstate Rule. The purpose of the CSAPR was to limit the interstate transport of NOx and SO₂ that contribute to fine particulate matter and ozone nonattainment in downwind states through a proposed allowance allocation and trading plan. After several lawsuits and related appeals, in October 2014, the D.C. Circuit Court of Appeals issued a decision that allowed the EPA to begin implementing CSAPR on January 1, 2015. The emissions budgets of Phase I of the rule applied in 2015 and 2016, while the Phase II emissions budgets apply to 2017 and beyond.

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

Sulfur Dioxide National Ambient Air Quality Standards

The EPA issued a revised 1-Hour 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 June 2016, we provided modeling to the WDNR that shows the area around the Weston Power Plant to be in compliance. Based upon the submittal, the WDNR provided final modeling to the EPA demonstrating the area around the Weston Power Plant to be in compliance. We expect that the EPA will consider the WDNR's recommendation and finalize its recommended designation in August 2017, for finalization by the end of 2017.

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

8-Hour Ozone National Ambient Air Quality Standards

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

After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, which lowered the limit for ground-level ozone, creating a more stringent standard than the 2008 NAAQS. This is expected to cause nonattainment for Wisconsin's Lake Michigan shoreline counties (or partial counties), with potential future impacts for our fossil-fueled power plant fleet. In January 2017, the EPA released preliminary interstate ozone transport modeling for the 2015 ozone NAAQS. The EPA is currently scheduled to finalize designations in October 2017. For nonattainment areas, the state of Wisconsin will have to develop a state implementation plan to bring the areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020. We will not know the potential impacts for complying with the 2015 ozone NAAQS until the designations are final and until the state prepares a draft attainment plan.

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

Climate Change

In 2015, the EPA issued a final rule regulating GHG emissions from existing generating units, referred to as the Clean Power Plan (CPP), a proposed federal plan and model trading rules as alternatives or guides to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In October 2015, following publication of the CPP, numerous states (including Wisconsin and Michigan) and other parties, filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but in February 2016, the Supreme Court stayed the effectiveness of the CPP until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that further appellate review is sought, at the Supreme Court. The D.C. Circuit Court of Appeals heard one case in September 2016, and the other case is still pending. On April 28, 2017, pursuant to motions made by the EPA, the D.C. Circuit Court of Appeals ordered the cases to be held in abeyance, with supplemental briefs to be provided by May 15, 2017, addressing whether the cases should be remanded to the EPA rather than held in abeyance.

The CPP seeks to achieve state-specific GHG emission reduction goals by 2030, and would have required states to submit plans by September 2016. The goal of the final rule is to reduce nationwide GHG emissions by 32% from 2005 levels. The rule is seeking GHG emission reductions in Wisconsin and Michigan of 41% and 39%, respectively, below 2012 levels by 2030. Interim goals starting in 2022 would require states to achieve about two-thirds of the 2030 required reduction.

In March 2017, President Trump issued an executive order that, among other things, specifically directs the EPA to review, and if appropriate, initiate proceedings to suspend, revise, or rescind the CPP. The EPA announced that it has initiated this review. As a result of this order and related EPA review, as well as the ongoing legal proceedings, the timelines for the GHG emission reduction goals and all other aspects of the CPP are uncertain. In April 2017, the EPA withdrew the proposed rule for a federal plan and model trading rules that were published in October 2015 for use in developing state plans to implement the CPP or for use in states where a

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plan is not submitted or approved. In addition, the Governor of Wisconsin issued an executive order in February 2016, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan.

Notwithstanding the uncertain future of the CPP, and given current fuel and technology markets, we continue to evaluate opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute towards long-term GHG reductions. Our plan is to work with our industry partners, environmental groups, and the State of Wisconsin, with a goal of reducing CO₂ emissions by approximately 40% below 2005 levels by 2030. We continue to evaluate numerous options in order to meet our CO₂ reduction goal, such as increased use of existing natural gas combined cycle units, co-firing or switching to natural gas in existing coal-fired units, reduced operation or retirement of existing coal-fired units, addition of new renewable energy resources (wind, solar), and consideration of supply and demand-side energy efficiency and distributed generation.

We are required to report our CO₂ equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2016, we reported aggregated CO₂ equivalent emissions of approximately 29.6 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 emissions from the natural gas that our natural gas utilities distribute and sell. For 2016, we reported aggregated CO₂ equivalent emissions of approximately 26.7 million metric tonnes to the EPA.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

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

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

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

During 2017 and 2018, we will continue to complete studies and evaluate options to address the EM BTA requirements at these plants. With the exception of Pleasant Prairie Power Plant and Weston Units 3 and 4 (which all have existing cooling towers that meet EM BTA requirements), we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at the facilities. We also expect that limited studies to support WDNR BTA determinations will be conducted at the Weston facility. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the EM BTA requirements based on low capacity use of the unit. Based on discussions with the MDEQ, if we provide information about unit retirements with our next National Pollutant Discharge Elimination System permit application and then submit a signed certification by August 2017 stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2022), then the EM BTA requirements will be waived. Entrainment studies are currently being conducted at Pulliam Units 7 and 8 and were recently completed at PIPP. See the UMERC discussion in Note 16, Regulatory Environment, regarding the potential retirement of PIPP.

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

Steam Electric Effluent 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. This rule is being litigated in the United States Court of Appeals for the Fifth Circuit (Fifth Circuit Court of Appeals) and may result in changes to the discharge requirements. In April 2017, the EPA granted a petition filed by the Utility Water Act Group to reconsider and stay the steam effluent guidelines and related compliance deadlines. On April 24, 2017, in response to a motion by the EPA, the Fifth Circuit Court of Appeals ordered a stay of the litigation for 120 days while the rule is being redrafted to address the petition's concerns.

After a final rule is back in effect, the WDNR and MDEQ will modify the state rules as necessary 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 site 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 OC 7, OC 8, the Pleasant Prairie units, Pulliam Units 7 and 8, and Weston Unit 3. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $80 million to $110 million for these advanced treatment and bottom ash transport systems. A similar system would be required at PIPP if we were not expecting to retire the plant. See the UMERC discussion in Note 16, Regulatory Environment, regarding the potential retirement of PIPP.

Land Quality

Manufactured Gas Plant Remediation

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

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

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

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

(in millions)	March 31, 2017		December 31, 2016
Regulatory assets	$	685.4	$	702.7
Reserves for future remediation	630.5		633.4

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Enforcement and Litigation Matters

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

Consent Decrees

Wisconsin Public Service Corporation Consent Decree – Weston and Pulliam

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

Also, in May 2010, WPS received from the Sierra Club a Notice of Intent to file a civil lawsuit based on allegations that WPS violated the CAA at the Weston and Pulliam plants. WPS entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended in October 2012, but no further action has been taken by the Sierra Club as of March 31, 2017. It is unknown whether the Sierra Club will take further action in the future.

Joint Ownership Power Plants Consent Decree – Columbia and Edgewater

In December 2009, the EPA issued a NOV to Wisconsin Power and Light, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric, WE (former co-owner of an Edgewater unit), and WPS. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. WPS, along with Wisconsin Power and Light, Madison Gas and Electric, and WE, entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013.

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

NOTE 15—SUPPLEMENTAL CASH FLOW INFORMATION

	Three Months Ended March 31
(in millions)	2017			2016
Cash (paid) for interest, net of amount capitalized	$	(56.6	)	$	(53.0	)
Cash received (paid) for income taxes, net	8.9			(0.4		)
Significant non-cash transactions
Accounts payable related to construction costs	116.4			90.1
Increase (decrease) in restricted cash from the sale (purchase) of investments held in the rabbi trust	8.3			(1.5		)
Portion of Bostco real estate holdings sale financed with note receivable *	7.0			—
Amortization of deferred revenue	6.2			6.2

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

At March 31, 2017, and December 31, 2016, restricted cash of $26.9 million and $33.6 million, respectively, was recorded within other long-term assets on our balance sheets. The majority of this amount was held in the Integrys rabbi trust and represents a portion of the required funding that was triggered by the announcement of the Integrys acquisition. Withdrawals of restricted cash from the rabbi trust for qualifying payments are shown as an investing activity on the statements of cash flows. Changes in restricted cash due to the sale or purchase of investments held in the rabbi trust are non-cash transactions and are included in the table above.

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NOTE 16—REGULATORY ENVIRONMENT

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

2018 and 2019 Rates

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

Pursuant to the settlement agreement, WPS also agreed to adopt, beginning in 2018, the earnings sharing mechanism currently in place for WE and WG, and all three utilities agreed to keep the mechanism in place through 2019. Under this earnings sharing mechanism, if WE, WG, or WPS earns above its authorized ROE, 50% of the first 50 basis points of additional utility earnings must be shared with customers. All utility earnings above the first 50 basis points must also be shared with customers. We expect the PSCW to issue a final order on the settlement agreement in 2017.

Natural Gas Storage Facility in Michigan

In January 2017, we signed an agreement for the acquisition of a natural gas storage facility in Michigan that would provide approximately one-third of the current storage needs for WE, WG, and WPS. As a result of this agreement, WE, WG, and WPS filed a request with the PSCW in February 2017 for a declaratory ruling on various items associated with the storage facility. In the filing, WE, WG, and WPS requested that the PSCW review and confirm the reasonableness and prudency of their potential long-term storage service agreements and interstate natural gas transportation contracts related to the storage facility. WE, WG, and WPS also requested approval to amend our Affiliated Interest Agreement to ensure WBS and our other subsidiaries would be able to provide services to the storage facility. We expect to receive these PSCW declarations and approvals by the third quarter of 2017.

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

Illinois Investigations

In March 2015, the ICC opened a docket, naming PGL as respondent, to investigate the veracity of certain allegations included in anonymous letters that the ICC staff received regarding PGL's SMP. PGL and the ICC staff filed a settlement agreement related to these anonymous letters with the ICC during March 2017. In this agreement, we agreed to modify our code of business conduct to address certain concerns regarding conflicts of interest and provide a quarterly report to the ICC for four years identifying code of conduct and conflict of interest allegations. The agreement also requested that PGL provide semi-annual quality assurance reports to the ICC for four years on the SMP capital construction performed by PGL crews and contractors. We are uncertain when the ICC will issue an order related to this settlement agreement.

In December 2015, the ICC ordered a series of stakeholder workshops to evaluate PGL's SMP. This ICC action did not impact PGL's ongoing work to modernize and maintain the safety of its natural gas distribution system, but it instead provided the ICC with an opportunity to analyze long-term elements of the program through the stakeholder workshops. The workshops commenced in January 2016 and were completed in March 2016. The ICC staff submitted a report on the workshop process in May 2016. In July 2016, the ICC initiated a proceeding to review, among other things, the planning, reporting, and monitoring of the program, including the target end date for the program. In March 2017, the ICC issued an order directing that additional hearings be held before the ALJ on certain issues to further develop the evidentiary record in the case. This proceeding is expected to result in a final order by the ICC during the second half of 2017. We are currently unable to determine what, if any, long-term impact there will be on the SMP.

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Qualifying Infrastructure Plant Rider

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

PGL's QIP rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2017, PGL filed its 2016 reconciliation with the ICC, which, along with the 2015 reconciliation, is still pending. For PGL's 2014 reconciliation, the ALJ has issued a schedule, and we expect to receive an order from the ICC in 2017. As of March 31, 2017, there can be no assurance that all costs incurred under PGL's QIP rider will be recoverable.

Minnesota Energy Resources Corporation

2016 Minnesota Rate Order

In September 2015, MERC initiated a rate proceeding with the MPUC. In October 2016, the MPUC issued a final written order for MERC, effective March 1, 2017. The order authorized a retail natural gas rate increase of $6.8 million (3.0%). The rates reflect a 9.11% ROE and a common equity component average of 50.32%. The order approved MERC's request to continue the use of its currently authorized decoupling mechanism for another three years. The final approved rate increase was lower than the interim rates collected from customers during 2016. Therefore, as of March 31, 2017, we estimated that $4.1 million will be refunded to MERC's customers in May 2017.

Upper Michigan Energy Resources Corporation

Formation of Upper Michigan Energy Resources Corporation

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

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

2015 Michigan Rate Order

Prior to the formation of UMERC, in October 2014, WPS initiated a rate proceeding with the MPSC. In April 2015, the MPSC issued a final written order for WPS, effective April 24, 2015, approving a settlement agreement. As a result of the formation of UMERC, the terms and conditions of this WPS rate order now apply to UMERC, including the deferrals described below. The order authorized a retail electric rate increase of $4.0 million to be implemented over three years to recover costs for the 2013 acquisition of the Fox Energy Center as well as other capital investments associated with the Crane Creek wind farm and environmental upgrades at generation plants. The rates reflected a 10.2% ROE and a common equity component average of 50.48%. The increase reflected the continued deferral of costs associated with the Fox Energy Center until the second anniversary of the order. The increase also reflected the deferral of Weston Unit 3 ReACT™ environmental project costs. On the second anniversary of the order, the Fox Energy Center costs deferral was discontinued and amortization of this deferral began, along with the amortization of the deferral associated with the termination of a Fox Energy Center tolling agreement. In the order, the MPSC also approved the deferral and amortization of the undepreciated book value of the retired plant associated with Pulliam Units 5 and 6 and Weston Unit 1 starting with the actual

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retirement date, June 1, 2015, and concluding by 2023. UMERC will not seek an increase to retail electric base rates that would become effective prior to January 1, 2018.

NOTE 17—NEW ACCOUNTING PRONOUNCEMENTS

Revenue Recognition

In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. Several amendments were issued subsequent to the standard to clarify the guidance. The core principle of the guidance is to recognize revenue in an amount that an entity is entitled to receive in exchange for goods and services. The guidance also requires additional disclosures about the nature, amount, timing, and uncertainty of revenues and the related cash flows arising from contracts with customers.

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

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

Recognition and Measurement of Financial Instruments

In January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. This guidance requires equity investments, including other ownership interests such as partnerships, unincorporated joint ventures, and limited liability companies, to be measured at fair value with changes in fair value recognized in net income. It also simplifies the impairment assessment of equity investments without readily determinable fair values and amends certain disclosure requirements associated with the fair value of financial instruments. This ASU does not apply to investments accounted for under the equity method of accounting. We 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. The main provision of this ASU is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP.  We are currently assessing the effects this guidance may have on our financial statements.

Financial Instruments Credit Losses

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

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Classification of Certain Cash Receipts and Cash Payments

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

Restricted Cash

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

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

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

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

CORPORATE DEVELOPMENTS

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

Introduction

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

Corporate Strategy

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

Reliability

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

• UMERC, our newly created Michigan electric and natural gas utility, is proposing a long-term generation solution for electric reliability in the Upper Peninsula of Michigan. The plan calls for UMERC to construct and operate approximately 180 MWs of natural gas-fired generation that will be located in the Upper Peninsula of Michigan. The new generation would provide the region with affordable, reliable electricity that generates less emissions than PIPP. Subject to regulatory approval, the new generation is expected to achieve commercial operation in 2019 and should allow for the retirement of PIPP no later than 2020. For more information, see Note 16, Regulatory Environment.

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

• WPS continues work on its SMRP, which involves modernizing parts of its electric distribution system 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 ERGS to enable the facility to burn coal from the Powder River Basin located in the western United States. The coal plant was originally designed to burn coal mined from the eastern United States. This project is creating flexibility and has enabled the plant to operate at lower costs, placing it in a better position to be called upon in the MISO Energy Markets, resulting in lower fuel costs for our customers.

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

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Financial Discipline

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

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

• See Note 2, Acquisition, for information about our pending acquisition of a natural gas storage facility in Michigan.

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

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

Excluding ATC, we expect total capital expenditures for our regulated utility business to be in the range of $9.5 billion to $10.0 billion over the next five years. Ongoing projects are discussed in more detail within Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.

Exceptional Customer Care

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

One example of how we obtain feedback from our customers is through our "We Care" calls, where employees of our utility subsidiaries contact customers after a completed service call. Customer satisfaction is a priority, and making "We Care" calls is one of the main methods we use to gauge our performance in order to improve customer satisfaction.

Safety

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

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RESULTS OF OPERATIONS

THREE MONTHS ENDED MARCH 31, 2017

Consolidated Earnings

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

	Three Months Ended March 31
(in millions, except per share data)	2017			2016			B (W)
Wisconsin	$	332.3		$	327.5		$	4.8
Illinois	155.4			137.0			18.4
Other states	33.4			31.8			1.6
We Power	97.4			93.3			4.1
Corporate and other	(1.2		)	(0.3		)	(0.9		)
Total operating income	617.3			589.3			28.0
Equity in earnings of transmission affiliate	41.9			38.5			3.4
Other income, net	15.7			32.7			(17.0		)
Interest expense	104.7			100.9			(3.8		)
Income before income taxes	570.2			559.6			10.6
Income tax expense	213.3			213.1			(0.2		)
Preferred stock dividends of subsidiary	0.3			0.3			—
Net income attributed to common shareholders	$	356.6		$	346.2		$	10.4
Diluted earnings per share	$	1.12		$	1.09		$	0.03

Earnings increased $10.4 million during the first quarter of 2017, compared with the same quarter in 2016. The significant factors impacting the increase in earnings were:

• A $28.4 million pre-tax ($17.0 million after tax) decrease in other operation and maintenance expenses at the Wisconsin segment. The decrease primarily related to lower operation and maintenance expenses at our electric generation plants, lower electric and natural gas distribution expenses, and a decrease in benefit costs.

• An $18.4 million pre-tax ($11.0 million after tax) increase in operating income at the Illinois segment. The increase was driven by higher natural gas margins at PGL due to continued capital investment in projects under its QIP rider and a decrease in benefit costs related to both lower pension costs and lower medical costs.

These increases in earnings were partially offset by:

• A $16.1 million pre-tax ($9.7 million after tax) decrease in electric margins at the Wisconsin segment primarily driven by lower retail sales volumes in the first quarter of 2017.

• A $17.0 million pre-tax ($10.2 million after tax) decrease in other income, net. The decrease was driven by the quarter-over-quarter impact of the gain recognized in 2016 related to the repurchase of a portion of Integrys's 6.11% Junior Notes.

Non-GAAP Financial Measure

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

We believe that electric and natural gas margins provide a more meaningful basis for evaluating utility operations than operating revenues since the majority of prudently incurred fuel and purchased power costs, as well as prudently incurred natural gas costs,

03/31/2017 Form 10-Q 28 WEC Energy Group, Inc.

are passed through to customers in current rates. As a result, management uses electric and natural gas margins internally when assessing the operating performance of our segments as these measures exclude the majority of revenue fluctuations caused by changes in these expenses. Similarly, the presentation of electric and natural gas margins herein is intended to provide supplemental information for investors regarding our operating performance.

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

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

Wisconsin Segment Contribution to Operating Income

	Three Months Ended March 31
(in millions)	2017		2016		B (W)
Electric revenues	$	1,115.3	$	1,117.2	$	(1.9	)
Fuel and purchased power	350.5		336.3		(14.2		)
Total electric margins	764.8		780.9		(16.1		)
Natural gas revenues	496.8		462.7		34.1
Cost of natural gas sold	296.6		261.6		(35.0		)
Total natural gas margins	200.2		201.1		(0.9		)
Total electric and natural gas margins	965.0		982.0		(17.0		)
Other operation and maintenance	462.9		491.3		28.4
Depreciation and amortization	129.3		122.9		(6.4		)
Property and revenue taxes	40.5		40.3		(0.2		)
Operating income	$	332.3	$	327.5	$	4.8

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

	Three Months Ended March 31
(in millions)	2017		2016		B (W)
Operation and maintenance not included in line items below	$	186.9	$	215.7	$	28.8
We Power (1)	127.6		128.6		1.0
Transmission (2)	103.9		105.8		1.9
Regulatory amortizations and other pass through expenses (3)	44.5		41.2		(3.3		)
Total other operation and maintenance	$	462.9	$	491.3	$	28.4

⁽¹⁾  Represents costs associated with the We Power generation units, including operating and maintenance costs incurred by WE, as well as the lease payments that are billed from We Power to WE and then recovered in WE's rates. During the three months ended March 31, 2017 and 2016, $124.7 million and $122.8 million, respectively, of both lease and operating and maintenance costs were billed to or incurred by WE, with the difference in costs billed or incurred and expenses recognized, deferred, or deducted from the regulatory asset.

⁽²⁾  The PSCW has approved escrow accounting for ATC and MISO network transmission expenses for our Wisconsin electric utilities. As a result, WE and WPS defer as a regulatory asset or liability the differences between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the three months ended March 31, 2017 and 2016, $82.9 million and $123.5 million, respectively, of costs were billed by transmission providers to our electric utilities.

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

03/31/2017 Form 10-Q 29 WEC Energy Group, Inc.

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	2017	2016	B (W)
Customer Class
Residential	2,598.3	2,655.3	(57.0	)
Small commercial and industrial *	3,192.6	3,197.0	(4.4	)
Large commercial and industrial *	3,080.4	3,372.6	(292.2	)
Other	47.2	47.5	(0.3	)
Total retail *	8,918.5	9,272.4	(353.9	)
Wholesale	942.9	856.1	86.8
Resale	2,277.1	2,232.3	44.8
Total sales in MWh *	12,138.5	12,360.8	(222.3	)

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

	Three Months Ended March 31
	Therms (in millions)
Natural Gas Sales Volumes	2017	2016	B (W)
Customer Class
Residential	472.4	477.8	(5.4	)
Commercial and industrial	275.9	270.8	5.1
Total retail	748.3	748.6	(0.3	)
Transport	382.7	380.5	2.2
Total sales in therms	1,131.0	1,129.1	1.9

	Three Months Ended March 31
	Degree Days
Weather	2017	2016	B(W)
WE and WG (1)
Heating (3,278 normal)	2,849	3,105	(256	)
WPS (2)
Heating (3,651 normal)	3,273	3,438	(165	)
UMERC (3)
Heating (3,954 normal)	3,662	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.

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

Electric Utility Margins

Electric utility margins at the Wisconsin segment decreased $16.1 million during the first quarter of 2017, compared with the same period in 2016. The significant factors impacting the lower electric utility margins were:

• A $15.0 million decrease related to lower retail sales volumes during the first quarter of 2017, partially related to warmer winter weather and an additional day of sales during the same period in 2016 due to leap year. As measured by heating degree days, the first quarter of 2017 was 8.2% and 4.8% warmer than the same period in 2016 in the Milwaukee and Green Bay areas, respectively.

03/31/2017 Form 10-Q 30 WEC Energy Group, Inc.

• A $5.6 million negative impact from collections of fuel and purchased power costs compared with costs approved in rates in the first quarter of 2017, as compared with the same period in 2016. Under the Wisconsin fuel rules, the margins of our electric utilities are impacted by under or over-collections of certain fuel and purchased power costs that are less than a 2% price variance from the costs included in rates, and the remaining variance that exceeds the 2% variance is deferred.

• A $3.9 million decrease in steam margins related to the sale of the MCPP in April 2016. See Note 3, Dispositions, for more information.

These decreases in margins were partially offset by $7.2 million of lower capacity payments to a counterparty in the first quarter of 2017.

Natural Gas Utility Margins

Natural gas utility margins at the Wisconsin segment decreased $0.9 million during the first quarter of 2017, compared with the same period in 2016. The most significant factor impacting the lower natural gas utility margins were lower retail sales volumes, primarily driven by warmer winter weather. The lower margins were partially offset by higher overall retail use per customer.

Operating Income

Operating income at the Wisconsin segment increased $4.8 million during the first quarter of 2017, compared with the same period in 2016. This increase was driven by $21.8 million of lower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes), partially offset by the $17.0 million decrease in margins discussed above.

The significant factors impacting the decrease in operating expenses were:

• An $11.3 million decrease in operation and maintenance expenses at our plants, partially related to the seasonal operation of our plants, the timing of planned outages and maintenance, and the sale of the MCPP in April 2016. See Note 3, Dispositions, for more information on the sale of the MCPP.

• A $6.5 million decrease in electric and natural gas distribution expenses.

• A $5.9 million decrease in benefit costs, primarily driven by lower employee and postretirement medical costs and stock-based compensation.

These decreases in operating expenses were partially offset by a $6.4 million increase in depreciation and amortization, driven by the completion of the ReACT^TM multi-pollutant control system at Weston Unit 3 during the fourth quarter of 2016 and an overall increase in utility plant in service.

Illinois Segment Contribution to Operating Income

	Three Months Ended March 31
(in millions)	2017		2016		B (W)
Natural gas revenues	$	525.3	$	448.5	$	76.8
Cost of natural gas sold	207.7		157.3		(50.4		)
Total natural gas margins	317.6		291.2		26.4
Other operation and maintenance	120.9		117.9		(3.0		)
Depreciation and amortization	36.2		32.8		(3.4		)
Property and revenue taxes	5.1		3.5		(1.6		)
Operating income	$	155.4	$	137.0	$	18.4

03/31/2017 Form 10-Q 31 WEC Energy Group, Inc.

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

	Three Months Ended March 31
(in millions)	2017		2016		B (W)
Operation and maintenance not included in the line items below	$	77.8	$	94.1	$	16.3
Riders *	42.3		23.1		(19.2		)
Regulatory amortizations *	0.7		0.6		(0.1		)
Other	0.1		0.1		—
Total other operation and maintenance	$	120.9	$	117.9	$	(3.0	)

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

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

	Three Months Ended March 31
	Therms (in millions)
Natural Gas Sales Volumes	2017	2016	B (W)
Customer Class
Residential	407.0	431.6	(24.6	)
Commercial and industrial	85.7	88.4	(2.7	)
Total retail	492.7	520.0	(27.3	)
Transport	328.3	345.9	(17.6	)
Total sales in therms	821.0	865.9	(44.9	)

	Three Months Ended March 31
	Degree Days
Weather *	2017	2016	B (W)
Heating (3,171 Normal)	2,661	2,908	(247	)

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

Natural Gas Utility Margins

Natural gas utility margins, net of the $19.2 million impact of the riders referenced in the table above, increased $7.2 million during the first quarter of 2017, compared with the same period in 2016. The increase was primarily driven by an increase in revenue at PGL due to continued capital investment in the SMP project under its QIP rider. PGL currently recovers the costs related to the SMP through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023.

Operating Income

Operating income at the Illinois segment increased $18.4 million during the first quarter of 2017, compared with the same period in 2016. This increase was due to the $7.2 million increase in margins discussed above and an $11.2 million decrease in operating expenses, net of the impact of the riders referenced in the table above. The decrease in operating expenses was driven by a decrease in benefits costs related to both lower pension costs and lower medical costs.

03/31/2017 Form 10-Q 32 WEC Energy Group, Inc.

Other States Segment Contribution to Operating Income

	Three Months Ended March 31
(in millions)	2017		2016		B (W)
Natural gas revenues	$	157.9	$	148.4	$	9.5
Cost of natural gas sold	86.4		78.4		(8.0		)
Total natural gas margins	71.5		70.0		1.5
Other operation and maintenance	28.3		30.0		1.7
Depreciation and amortization	6.0		5.1		(0.9		)
Property and revenue taxes	3.8		3.1		(0.7		)
Operating income	$	33.4	$	31.8	$	1.6

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

	Three Months Ended March 31
(in millions)	2017		2016		B (W)
Operation and maintenance not included in line item below	$	19.5	$	20.9	$	1.4
Regulatory amortizations and other pass through expenses *	8.8		9.1		0.3
Total other operation and maintenance	$	28.3	$	30.0	$	1.7

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

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

	Three Months Ended March 31
	Therms (in millions)
Natural Gas Sales Volumes	2017	2016	B (W)
Customer Class
Residential	133.8	142.0	(8.2	)
Commercial and industrial	83.9	87.6	(3.7	)
Total retail	217.7	229.6	(11.9	)
Transport	191.4	227.1	(35.7	)
Total sales in therms	409.1	456.7	(47.6	)

	Three Months Ended March 31
	Degree Days
Weather *	2017	2016	B (W)
Heating (3,558 Normal)	3,134	3,231	(97	)

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

Operating Income

Operating income at the other states segment increased $1.6 million during the first quarter of 2017, compared to the same period last year. The increase was primarily driven by lower operation and maintenance expense due in part to effective cost control measures.

We Power Segment Contribution to Operating Income

	Three Months Ended March 31
(in millions)	2017		2016		B (W)
Operating income	$	97.4	$	93.3	$	4.1

03/31/2017 Form 10-Q 33 WEC Energy Group, Inc.

Operating income at the We Power segment increased $4.1 million, or 4.4%, when compared to the first quarter of 2016. This increase was primarily related to higher revenues in connection with capital additions to the plants it owns and leases to WE.

Corporate and Other Segment Contribution to Operating Income

	Three Months Ended March 31
(in millions)	2017			2016			B (W)
Operating loss	$	(1.2	)	$	(0.3	)	$	(0.9	)

Electric Transmission Segment Operations

	Three Months Ended March 31
(in millions)	2017		2016		B (W)
Equity in earnings of transmission affiliate	$	41.9	$	38.5	$	3.4

Equity in earnings of transmission affiliate increased $3.4 million, or 8.8%, when compared to the first quarter of 2016. Lower earnings in the first quarter of 2016 were due to accounting activity related to the ongoing FERC ROE complaints. See Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints for more information.

Consolidated Other Income, Net

	Three Months Ended March 31
(in millions)	2017		2016		B (W)
AFUDC – Equity	$	2.4	$	7.0	$	(4.6	)
Gain on repurchase of notes	—		23.6		(23.6		)
Other, net	13.3		2.1		11.2
Other income, net	$	15.7	$	32.7	$	(17.0	)

Other Income, net decreased by $17.0 million when compared to the first quarter of 2016. The decrease was primarily due to the repurchase of a portion of the Integrys' 6.11% Junior Notes at a discount in February 2016 as well as lower AFUDC largely due to the ReACT^TM emission control technology project at Weston Unit 3 going into service during the fourth quarter of 2016. This decrease was offset in part by a $5.7 million increase in gains on investments held in the rabbi trust during the first quarter of 2017, compared with the same period in 2016.

Consolidated Interest Expense

	Three Months Ended March 31
(in millions)	2017		2016		B (W)
Interest expense	$	104.7	$	100.9	$	(3.8	)

Interest expense increased by $3.8 million, as compared to the first quarter of 2016. This increase was due to lower capitalized interest in the first quarter of 2017 as a result of the completion of the ReACT^TM emission control project in the fourth quarter of 2016, higher short-term interest rates, and higher long-term debt levels in 2017 to fund capital expenditures.

Consolidated Income Tax Expense

	Three Months Ended March 31
	2017		2016		B (W)
Effective tax rate	37.4	%	38.1	%	0.7	%

Our effective tax rate decreased by 0.7% when compared to the first quarter of 2016, primarily due to the recognition of $3.2 million of excess tax benefits related to share-based payments in the first quarter of 2017. See Note 4, Common Equity, for more information on the excess tax benefits related to share-based payments. We expect our 2017 annual effective tax rate to be between 37.0% and 38.0%.

03/31/2017 Form 10-Q 34 WEC Energy Group, Inc.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

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

(in millions)	2017			2016			Change in 2017 Over 2016
Cash provided by (used in):
Operating activities	$	714.6		$	695.9		$	18.7
Investing activities	(325.6		)	(188.4		)	(137.2		)
Financing activities	(380.8		)	(522.6		)	141.8

Operating Activities

Net cash provided by operating activitiesincreased$18.7 million during the first quarter of 2017, compared with the same period in 2016, driven by:

• A $151.5 million increase in cash related to higher overall collections from customers, primarily due to higher commodity prices. The average per-unit cost of natural gas sold increased 21.8% during the first quarter of 2017, compared with the same period in 2016.

• A $43.4 million increase in cash from lower payments for operating and maintenance costs. During the first quarter of 2017, our payments related to transmission, electric generation costs, and employee benefits decreased.

• A $20.1 million increase in cash distributions provided by ATC during the first quarter of 2017.

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

• A $110.3 million decrease in cash resulting from higher payments for natural gas and fuel and purchased power, due to higher commodity prices during the first quarter of 2017, compared with the same period in 2016.

• A $90.9 millionincrease in contributions and payments to our pension and OPEB plans during the first quarter of 2017.

Investing Activities

Net cash used in investing activitiesincreased$137.2 million during the first quarter of 2017, compared with the same period in 2016, driven by:

• A $93.4 million decrease in the proceeds received from the sale of assets and businesses during the first quarter of 2017, compared with the same period in 2016. See Note 3, Dispositions, for more information.

• An $18.6 million increase in our capital contributions to ATC during the first quarter of 2017. Our capital contributions increased due to the continued investment in equipment and facilities by ATC to improve reliability as well as the ROE refunds that ATC was required to provide as a result of the FERC order issued in September 2016. See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints for more information on this FERC order.

• A $17.7 million increase in cash paid for capital expenditures during the first quarter of 2017, which is discussed in more detail below.

03/31/2017 Form 10-Q 35 WEC Energy Group, Inc.

Capital Expenditures

Capital expenditures by segment for the first quarter ended March 31 were as follows:

Reportable Segment (in millions)	2017		2016		Change in 2017 Over 2016
Wisconsin	$	199.0	$	201.8	$	(2.8	)
Illinois	97.5		76.2		21.3
Other states	12.6		10.3		2.3
We Power	5.2		4.2		1.0
Corporate and other	15.4		19.5		(4.1		)
Total capital expenditures	$	329.7	$	312.0	$	17.7

The increase in cash paid for capital expenditures at the Illinois segment during the first quarter of 2017 was primarily driven by increased construction activity related to PGL's SMP.

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

Financing Activities

Net cash used in financing activities decreased $141.8 million during the first quarter of 2017, compared with the same period in 2016, driven by:

• A $127.4 million decrease in cash used for the repayment of long-term debt during the first quarter of 2017. In February 2016, we repurchased a portion of Integrys's 6.11% Junior Notes at a discount.

• A $39.4 milliondecrease in cash used to purchase shares of our common stock during the first quarter of 2017 to satisfy requirements of our stock-based compensation plans.

These decreases in net cash used in financing activities were partially offset by a $15.5 million decrease in cash received from stock option exercises during the first quarter of 2017.

Significant Financing Activities

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

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.

03/31/2017 Form 10-Q 36 WEC Energy Group, Inc.

The following table shows our capitalization structure as of March 31, 2017, as well as an adjusted capitalization structure that we believe is consistent with how a majority of the rating agencies currently view our 2007 6.25% Series A Junior Subordinated Notes due 2067 (6.25% Junior Notes):

(in millions)	Actual			Adjusted
Common equity	$	9,125.6		$	9,375.6
Preferred stock of subsidiary	30.4			30.4
Long-term debt (including current portion)	9,301.6			9,051.6
Short-term debt	670.4			670.4
Total capitalization	$	19,128.0		$	19,128.0
Total debt	$	9,972.0		$	9,722.0
Ratio of debt to total capitalization	52.1		%	50.8		%

Included in long-term debt on our balance sheet as of March 31, 2017, is $500.0 million principal amount of 6.25% Junior Notes. The adjusted presentation attributes $250.0 million of the 6.25% Junior Notes to common equity and $250.0 million to long-term debt.

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 6.25% Junior Notes. Therefore, we believe the non-GAAP adjusted presentation reflecting this treatment is useful and relevant to investors in understanding how management and the rating agencies evaluate our capitalization structure.

As of March 31, 2017, WE was the obligor under a series of tax-exempt pollution control refunding bonds with an outstanding principal amount of $80.0 million. In August 2009, WE terminated a letter of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. WE purchased the bonds at par plus accrued interest to the date of purchase. As of March 31, 2017, the repurchased bonds were still outstanding but are not reported in our long-term debt since they are held by WE. Depending on market conditions and other factors, WE may change the method used to determine the interest rate on this bond series and have it remarketed to third parties.

Working Capital

As of March 31, 2017, our current liabilities exceeded our current assets by $199.3 million. We do not expect this to have any impact on our liquidity since we believe we have adequate back-up lines of credit in place for our ongoing operations. We also can access the capital markets to finance our construction programs and to refinance current maturities of long-term debt, if necessary.

Capital Requirements

Significant Capital Projects

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

(in millions)	2017		2018		2019
Wisconsin	$	1,376.1	$	1,270.5	$	1,203.8
Illinois	544.8		517.7		523.4
Other states	91.0		102.7		106.8
We Power	38.4		35.0		36.4
Corporate and other	131.9		30.9		28.9
Total	$	2,182.2	$	1,956.8	$	1,899.3

03/31/2017 Form 10-Q 37 WEC Energy Group, Inc.

WPS is continuing work on the SMRP. This project includes converting more than 1,000 miles of overhead distribution power lines to underground in northern Wisconsin, adding distribution automation equipment on 400 miles of lines, and installing over 900 miles of underground circuit. WPS expects to invest approximately $300 million between 2017 and 2021 on this project. WE, WPS, and WG will also continue to upgrade their electric and natural gas distribution systems to enhance reliability.

In connection with the formation of UMERC, we entered into an agreement withTilden Mining Companyunder which it will purchase electric power from UMERC for 20 years. The agreement calls for UMERC to construct and operate approximately 180 MW of natural gas-fired generation located in the Upper Peninsula of Michigan. The estimated cost of this project is approximately $265 million ($275 million including AFUDC).See Note 16, Regulatory Environment, for more informationabout UMERC and this new generation.

In January 2017, we signed an agreement for the acquisition of a natural gas storage facility in Michigan for $225 million that would provide approximately one-third of the current storage needs for our Wisconsin natural gas utilities. In addition, we expect to incur approximately $5 million of acquisition related costs. See Note 2, Acquisition, for more information on this transaction.

PGL is continuing work on the SMP, a project under which PGL is replacing approximately 2,000 miles of Chicago's aging natural gas pipeline infrastructure. PGL currently recovers these costs through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023. PGL's projected average annual investment through 2019 is between $280 million and $300 million. See Note 16, Regulatory Environment, for more informationon the SMP.

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

Common Stock Dividends

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

Off-Balance Sheet Arrangements

We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit that support construction projects, commodity contracts, and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see Note 5, Short-Term Debt and Lines of Credit, Note 9, Guarantees, and Note 13, Variable Interest Entities.

Contractual Obligations

For additional information about our commitments, see Contractual Obligations in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Requirements in our 2016 Annual Report on Form 10-K.

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity, and capital resources. The following discussion should be read together with the information in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources in our 2016 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, industry restructuring, environmental matters, critical accounting policies and estimates, and other matters.

Market Risks and Other Significant Risks

We are exposed to market and other significant risks as a result of the nature of our businesses and the environments in which those businesses operate. These risks include, but are not limited to, the regulatory recovery risk described below. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and

03/31/2017 Form 10-Q 38 WEC Energy Group, Inc.

Capital Resources – Market Risks and Other Significant Risks in our 2016 Annual Report on Form 10-K for a discussion of other significant risks applicable to us.

Regulatory Recovery

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

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

• In June 2016, the PSCW approved the deferral of costs related to WPS's ReACT™ project above the originally authorized $275.0 million level through 2017. In April 2017, WPS requested an extension of this deferral through 2019 from the PSCW as part of a settlement agreement. We expect the PSCW to issue a final order related to this extension in 2017. See Note 16, Regulatory Environment, for more information. WPS will be required to obtain a separate approval for collection of these deferred costs.

• Prior to its acquisition, Integrys initiated an information technology project with the goal of improving the customer experience at its subsidiaries. Specifically, the project is expected to provide functional and technological benefits to the billing, call center, and credit collection functions. As of March 31, 2017, we had not received any significant disallowances of the costs incurred for this project. We will be required to obtain approval for the recovery of additional costs incurred through the completion of this long-term project.

• In January 2014, the ICC approved PGL's use of the QIP rider as a recovery mechanism for costs incurred related to investments in QIP. This rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2017, PGL filed its 2016 reconciliation with the ICC, which, along with the 2015 reconciliation, is still pending. For PGL's 2014 reconciliation, the ALJ has issued a schedule, and we expect to receive an order from the ICC in 2017. As of March 31, 2017, there can be no assurance that all costs incurred under the QIP rider will be recoverable.

See Note 16, Regulatory Environment, for more information regarding recent and pending rate proceedings, orders, and investigations involving our utilities.

Environmental Matters

See Note 14, Commitments and Contingencies, for a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change.

Other Matters

American Transmission Company Allowed Return on Equity Complaints

In November 2013, a group of MISO industrial customer organizations filed a complaint with the FERC requesting to reduce the base ROE used by MISO transmission owners, including ATC, from 12.2% to 9.15%. In October 2014, the FERC issued an order to hear the complaint on ROE and set a refund effective date retroactive to November 2013. In December 2015, the ALJ issued an initial decision recommending that ATC and all other MISO transmission owners be authorized to collect a base ROE of 10.32%, as well as the 0.5% incentive adder approved by the FERC in January 2015 for MISO transmission owners. The incentive adder only applies to revenues collected after January 6, 2015. In September 2016, the FERC issued a final order related to this complaint affirming the use of the ROEs stated in the ALJ's initial decision, effective as of the order date, on a going-forward basis. The order also requires ATC to provide refunds, with interest, for the 15-month refund period from November 13, 2013, through February 11, 2015. As of March 31, 2017, ATC had started to provide refunds to WE and WPS for transmission costs paid during the refund period, and we expect the refund process to be completed by June 2017. As these refunds are received, WE and WPS reduce the regulatory assets recorded under the PSCW-approved escrow accounting for transmission expense.

03/31/2017 Form 10-Q 39 WEC Energy Group, Inc.

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

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

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

03/31/2017 Form 10-Q 40 WEC Energy Group, Inc.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes related to market risk from the disclosures presented in our Annual Report on Form 10-K for the year ended December 31, 2016. In addition to the Form 10-K disclosures, see Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in Item 2 of Part I of this report, as well as Note 7, Fair Value Measurements, Note 8, Derivative Instruments, and Note 9, Guarantees, in this report for information concerning our market risk exposures.

03/31/2017 Form 10-Q 41 WEC Energy Group, Inc.

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

03/31/2017 Form 10-Q 42 WEC Energy Group, Inc.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The following should be read in conjunction with Item 3. Legal Proceedings in Part I of our 2016 Annual Report on Form 10-K. See Note 14, Commitments and Contingencies, and Note 16, Regulatory Environment, in this report for more information on material legal proceedings and matters related to us and our subsidiaries.

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

Environmental Matters

Sheboygan River Matter

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

ITEM 1A. RISK FACTORS

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

03/31/2017 Form 10-Q 43 WEC Energy Group, Inc.

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, 2017:

Issuer Purchases of Equity Securities

2017	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
January 1 – January 31	18,881	$	58.71	—	$	—
February 1 – February 28	6,250	57.19		—	$	—
March 1 – March 31	—	—		—	$	—
Total *	25,131	$	58.33	—

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

03/31/2017 Form 10-Q 44 WEC Energy Group, Inc.

ITEM 6. EXHIBITS

Number	Exhibit
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

03/31/2017 Form 10-Q 45 WEC Energy Group, Inc.

SIGNATURE

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

		WEC ENERGY GROUP, INC.
		(Registrant)
		/s/ WILLIAM J. GUC
Date:	May 5, 2017	William J. Guc
		Vice President and Controller
		(Duly Authorized Officer and Chief Accounting Officer)

03/31/2017 Form 10-Q 46 WEC Energy Group, Inc.

EX-31.1

Exhibit 31.1

Certification Pursuant to

Rule 13a-14(a) or 15d-14(a),

as Adopted Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002

I, Allen L. Leverett, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of WEC Energy Group, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an Annual Report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	May 5, 2017
	/s/ ALLEN L. LEVERETT
	Allen L. Leverett
	Chief Executive Officer and President
	(Principal Executive Officer)

EX-31.2

Exhibit 31.2

Certification Pursuant to

Rule 13a-14(a) or 15d-14(a),

as Adopted Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002

I, Scott J. Lauber, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of WEC Energy Group, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an Annual Report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	May 5, 2017
	/s/ SCOTT J. LAUBER
	Scott J. Lauber
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)

EX-32.1

Exhibit 32.1

Certification Pursuant to

18 U.S.C. Section 1350,

As Adopted Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of WEC Energy Group, Inc. (the "Company") on Form 10-Q for the quarter ended March 31, 2017, as filed with the Securities and Exchange Commission on May 5, 2017 (the "Report"), I, Allen L. Leverett, Chief Executive Officer and President of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ ALLEN L. LEVERETT

Allen L. Leverett

Chief Executive Officer and President

May 5, 2017

EX-32.2

Exhibit 32.2

Certification Pursuant to

18 U.S.C. Section 1350,

As Adopted Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of WEC Energy Group, Inc. (the "Company") on Form 10-Q for the quarter ended March 31, 2017, as filed with the Securities and Exchange Commission on May 5, 2017 (the "Report"), I, Scott J. Lauber, Executive Vice President and Chief Financial Officer of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ SCOTT J. LAUBER

Scott J. Lauber

Executive Vice President and Chief Financial Officer

May 5, 2017

XML

DOCUMENT AND ENTITY INFORMATION	3 Months Ended
	Mar. 31, 2017 shares
Document and Entity Information [Abstract]
Entity Registrant Name	WEC Energy Group, Inc.
Entity Central Index Key	0000783325
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding	315,579,222

XML

CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Income Statement [Abstract]
Operating revenues	$ 2,304.5	$ 2,194.8
Operating expenses
Cost of sales	941.1	838.9
Other operation and maintenance	501.9	531.5
Depreciation and amortization	194.6	187.9
Property and revenue taxes	49.6	47.2
Total operating expenses	1,687.2	1,605.5
Operating income	617.3	589.3
Equity in earnings of transmission affiliate	41.9	38.5
Other income, net	15.7	32.7
Interest expense	104.7	100.9
Other expense	(47.1)	(29.7)
Income before income taxes	570.2	559.6
Income tax expense	213.3	213.1
Net income	356.9	346.5
Preferred stock dividends of subsidiary	0.3	0.3
Net income attributed to common shareholders	$ 356.6	$ 346.2
Earnings per share
Basic (in dollars per share)	$ 1.13	$ 1.10
Diluted (in dollars per share)	$ 1.12	$ 1.09
Weighted average common shares outstanding
Basic (in shares)	315.6	315.7
Diluted (in shares)	317.2	317.1
Dividends per share of common stock (in dollars per share)	$ 0.5200	$ 0.4950

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Statement of Comprehensive Income [Abstract]
Net income	$ 356.9	$ 346.5
Derivatives accounted for as cash flow hedges
Reclassification of gains to net income, net of tax	(0.3)	(0.3)
Defined benefit plans
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax	0.1	0.0
Other comprehensive loss, net of tax	(0.2)	(0.3)
Comprehensive income	356.7	346.2
Preferred stock dividends of subsidiary	0.3	0.3
Comprehensive income attributed to common shareholders	$ 356.4	$ 345.9

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents	$ 45.7	$ 37.5
Accounts receivable and unbilled revenues, net of reserves of $123.1 and $108.0, respectively	1,191.4	1,241.7
Materials, supplies, and inventories	417.1	587.6
Prepayments	161.8	204.4
Other	39.3	97.5
Current assets	1,855.3	2,168.7
Long-term assets
Property, plant, and equipment, net of accumulated depreciation of $8,312.8 and $8,214.6, respectively	19,990.2	19,915.5
Regulatory assets	3,084.1	3,087.9
Equity investment in transmission affiliate	1,513.3	1,443.9
Goodwill	3,046.2	3,046.2
Other	527.5	461.0
Long-term assets	28,161.3	27,954.5
Total assets	30,016.6	30,123.2
Current liabilities
Short-term debt	670.4	860.2
Current portion of long-term debt	158.0	157.2
Accounts payable	582.3	861.5
Accrued payroll and benefits	107.5	163.8
Accrued interest	115.1	67.0
Other	421.3	321.9
Current liabilities	2,054.6	2,431.6
Long-term liabilities
Long-term debt	9,143.6	9,158.2
Deferred income taxes	5,287.4	5,146.6
Deferred revenue, net	561.0	566.2
Regulatory liabilities	1,563.4	1,563.8
Environmental remediation liabilities	630.7	633.6
Pension and OPEB obligations	458.9	498.6
Other	1,161.0	1,164.4
Long-term liabilities	18,806.0	18,731.4
Commitments and contingencies (Note 14)
Common shareholders' equity
Common stock – $0.01 par value; 325,000,000 shares authorized; 315,579,222 and 315,614,941 shares outstanding, respectively	3.2	3.2
Additional paid in capital	4,297.7	4,309.8
Retained earnings	4,822.0	4,613.9
Accumulated other comprehensive income	2.7	2.9
Common shareholders' equity	9,125.6	8,929.8
Preferred stock of subsidiary	30.4	30.4
Total liabilities and equity	$ 30,016.6	$ 30,123.2

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Accounts receivable and accrued unbilled revenues, reserves	$ 123.1	$ 108.0
Property, plant, and equipment, accumulated depreciation	$ 8,312.8	$ 8,214.6
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	325,000,000	325,000,000
Common stock, shares outstanding	315,579,222	315,614,941

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Operating Activities
Net income	$ 356.9	$ 346.5
Reconciliation to cash provided by operating activities
Depreciation and amortization	194.6	191.9
Deferred income taxes and investment tax credits, net	150.2	214.6
Contributions and payments related to pension and OPEB plans	(106.0)	(15.1)
Equity income in transmission affiliate, net of distributions	(6.7)	(23.4)
Change in -
Accounts receivable and unbilled revenues	55.0	(48.6)
Materials, supplies, and inventories	170.5	217.2
Other current assets	41.2	(63.7)
Accounts payable	(212.7)	(123.7)
Other current liabilities	90.8	56.7
Other, net	(19.2)	(56.5)
Net cash provided by operating activities	714.6	695.9
Investing Activities
Capital expenditures	(329.7)	(312.0)
Capital contributions to transmission affiliate	(27.6)	(9.0)
Proceeds from the sale of assets and businesses	13.1	106.5
Withdrawal of restricted cash from Rabbi trust for qualifying payments	16.1	21.0
Other, net	2.5	5.1
Net cash used in investing activities	(325.6)	(188.4)
Financing Activities
Exercise of stock options	5.9	21.4
Purchase of common stock	(20.2)	(59.6)
Dividends paid on common stock	(164.1)	(156.2)
Retirement of long-term debt	(12.0)	(139.4)
Change in short-term debt	(189.8)	(198.6)
Other, net	(0.6)	9.8
Net cash used in financing activities	(380.8)	(522.6)
Net change in cash and cash equivalents	8.2	(15.1)
Cash and cash equivalents at beginning of period	37.5	49.8
Cash and cash equivalents at end of period	$ 45.7	$ 34.7

XML

GENERAL INFORMATION

3 Months Ended

Mar. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

GENERAL INFORMATION

GENERAL INFORMATION

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

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

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2016. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three months ended March 31, 2017, are not necessarily indicative of expected results for 2017 due to seasonal variations and other factors.

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

XML

ACQUISITION

3 Months Ended

Mar. 31, 2017

Business Combinations [Abstract]

ACQUISITION

ACQUISITION

Acquisition of a Natural Gas Storage Facility in Michigan

In January 2017, we signed an agreement for the acquisition of a natural gas storage facility in Michigan for $225 million that would provide approximately one-third of the current storage needs for our Wisconsin natural gas utilities. In addition, we expect to incur approximately $5 million of acquisition related costs. A request has been filed with the PSCW for a declaratory ruling related to the recovery of this investment. PSCW approval and closing of this transaction are expected to occur by the third quarter of 2017.

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DISPOSITIONS

3 Months Ended

Mar. 31, 2017

Discontinued Operations and Disposal Groups [Abstract]

DISPOSITIONS

DISPOSITIONS

Wisconsin Segment

Sale of Milwaukee County Power Plant

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

Corporate and Other Segment

Sale of Bostco Real Estate Holdings

In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space. During the first quarter of 2017, we recorded an insignificant gain on the sale, which was included in other income, net on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations associated with these assets remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.

Sale of Certain Assets of Wisvest

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

Sale of Integrys Transportation Fuels

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

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COMMON EQUITY

3 Months Ended

Mar. 31, 2017

Equity [Abstract]

COMMON EQUITY

COMMON EQUITY

Stock-Based Compensation

During the first quarter of 2017, the Compensation Committee of our Board of Directors awarded the following stock-based compensation awards to our directors, officers, and certain other key employees:

Award Type	Number of Awards
Stock options (1)	552,215
Restricted shares (2)	82,622
Performance units	237,650

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

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

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which modifies certain aspects of the accounting for stock-based compensation awards. This ASU became effective for us on January 1, 2017. Under the new guidance, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement on a prospective basis. Prior to January 1, 2017, these amounts were recorded in additional paid in capital on the balance sheet, and the tax benefits could only be recognized to the extent they reduced taxes payable. In the first quarter of 2017, we recorded a $15.7 million cumulative-effect adjustment to retained earnings for excess tax benefits that had not been recognized in prior years as they did not reduce taxes payable. The following table shows the changes to our retained earnings for the three months ended March 31, 2017:

(in millions)	Retained Earnings
Balance at December 31, 2016	$	4,613.9
Net income attributed to common shareholders	356.6
Common stock dividends	(164.1		)
Cumulative effect of adoption of ASU 2016-09	15.7
Other	(0.1		)
Balance at March 31, 2017	$	4,822.0

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

Restrictions

Our ability as a holding company to pay common stock dividends primarily depends on the availability of funds received from our utility subsidiaries and our non-utility subsidiary, We Power. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans, or advances. All of our utility subsidiaries, with the exception of MGU, are prohibited from loaning funds to us, either directly or indirectly. See Note 11, Common Equity, in our 2016 Annual Report on Form 10-K for additional information on these and other restrictions.

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

Common Stock Dividends

On April 20, 2017, our Board of Directors declared a quarterly cash dividend of $0.52 per share, payable on June 1, 2017, to stockholders of record on May 12, 2017.

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SHORT-TERM DEBT AND LINES OF CREDIT

3 Months Ended

Mar. 31, 2017

Short-term Debt [Abstract]

SHORT-TERM DEBT AND LINES OF CREDIT

SHORT-TERM DEBT AND LINES OF CREDIT

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

(in millions, except percentages)	March 31, 2017			December 31, 2016
Commercial paper
Amount outstanding	$	670.4		$	860.2
Weighted-average interest rate on amounts outstanding	1.18		%	0.96		%

Our average amount of commercial paper borrowings based on daily outstanding balances during the three months ended March 31, 2017, was $746.2 million with a weighted-average interest rate during the period of 1.01%.

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, 2017
WEC Energy Group	December 2020	$	1,050.0
WE	December 2020	500.0
WPS	December 2020	250.0
WG	December 2020	350.0
PGL	December 2020	350.0
Total short-term credit capacity		$	2,500.0
Less:
Letters of credit issued inside credit facilities		$	29.1
Commercial paper outstanding		670.4
Available capacity under existing agreements		$	1,800.5

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MATERIALS, SUPPLIES, AND INVENTORIES

3 Months Ended

Mar. 31, 2017

Inventory Disclosure [Abstract]

MATERIALS, SUPPLIES, AND INVENTORIES

MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:

(in millions)	March 31, 2017		December 31, 2016
Natural gas in storage	$	45.8	$	223.1
Materials and supplies	208.3		206.5
Fossil fuel	163.0		158.0
Total	$	417.1	$	587.6

PGL and NSG price natural gas storage injections at the calendar year average of the cost of natural gas supply purchased. Withdrawals from storage are priced using the LIFO cost method. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. At March 31, 2017, we had a temporary LIFO liquidation credit of $31.6 million recorded within other current liabilities on our balance sheet. Due to seasonality requirements, PGL and NSG expect these interim reductions in LIFO layers to be replenished by year end.

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

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FAIR VALUE MEASUREMENTS

3 Months Ended

Mar. 31, 2017

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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

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

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, 2017
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	2.3	$	9.5	$	—	$	11.8
FTRs	—		—		1.7		1.7
Coal contracts	—		1.0		—		1.0
Total derivative assets	$	2.3	$	10.5	$	1.7	$	14.5
Investments held in rabbi trust	$	101.7	$	—	$	—	$	101.7
Derivative liabilities
Natural gas contracts	$	—	$	0.9	$	—	$	0.9
Petroleum products contracts	0.3		—		—		0.3
Coal contracts	—		3.0		—		3.0
Total derivative liabilities	$	0.3	$	3.9	$	—	$	4.2

	December 31, 2016
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	10.1	$	24.2	$	—	$	34.3
Petroleum products contracts	0.2		—		—		0.2
FTRs	—		—		5.1		5.1
Coal contracts	—		2.0		—		2.0
Total derivative assets	$	10.3	$	26.2	$	5.1	$	41.6
Investments held in rabbi trust	$	103.9	$	—	$	—	$	103.9
Derivative liabilities
Natural gas contracts	$	0.2	$	0.2	$	—	$	0.4
Petroleum products contracts	0.1		—		—		0.1
Coal contracts	—		1.9		—		1.9
Total derivative liabilities	$	0.3	$	2.1	$	—	$	2.4

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

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

	Three Months Ended March 31
(in millions)	2017			2016
Balance at the beginning of the period	$	5.1		$	3.6
Realized and unrealized losses	—			(0.2		)
Sales	—			(0.1		)
Settlements	(3.4		)	(2.2		)
Balance at the end of the period	$	1.7		$	1.1

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, 2017				December 31, 2016
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock	$	30.4	$	28.9	$	30.4	$	28.8
Long-term debt, including current portion *	9,272.7		9,730.2		9,285.8		9,818.2

* The carrying amount of long-term debt excludes capital lease obligations of $28.9 million and $29.6 million at March 31, 2017 and

December 31, 2016, respectively.

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

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DERIVATIVE INSTRUMENTS

3 Months Ended

Mar. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS

DERIVATIVE INSTRUMENTS

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

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

The following table shows our derivative assets and derivative liabilities:

	March 31, 2017				December 31, 2016
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	11.4	$	0.7	$	31.4	$	0.4
Petroleum products contracts	—		0.3		0.2		0.1
FTRs	1.7		—		5.1		—
Coal contracts	1.0		1.8		1.5		1.4
Total other current *	$	14.1	$	2.8	$	38.2	$	1.9
Other long-term
Natural gas contracts	$	0.4	$	0.2	$	2.9	$	—
Coal contracts	—		1.2		0.5		0.5
Total other long-term *	$	0.4	$	1.4	$	3.4	$	0.5
Total	$	14.5	$	4.2	$	41.6	$	2.4

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

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

	Three Months Ended March 31, 2017				Three Months Ended March 31, 2016
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	34.1 Dth	$	(0.3	)	50.1 Dth	$	(33.5	)
Petroleum products contracts	4.9 gallons	(0.5		)	3.0 gallons	(1.1		)
FTRs	9.2 MWh	3.0			7.6 MWh	3.0
Total		$	2.2			$	(31.6	)

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, 2017 and December 31, 2016, we had posted cash collateral of $19.3 million and $16.4 million, respectively, in our margin accounts. These amounts were recorded on the balance sheets in other current assets. At December 31, 2016, we had also received cash collateral of $4.4 million in our margin accounts. This amount was recorded on our balance sheet in other current liabilities.

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

	March 31, 2017						December 31, 2016
(in millions)	Derivative Assets			Derivative Liabilities			Derivative Assets				Derivative Liabilities
Gross amount recognized on the balance sheet	$	14.5		$	4.2		$	41.6			$	2.4
Gross amount not offset on the balance sheet	(1.2		)	(1.2		)	(4.9		)	*	(0.5		)
Net amount	$	13.3		$	3.0		$	36.7			$	1.9

* Includes cash collateral received of $4.4 million.

Certain of our derivative and nonderivative commodity instruments contain provisions that could require "adequate assurance" in the event of a material change in our creditworthiness, or the posting of additional collateral for instruments in net liability positions, if triggered by a decrease in credit ratings. The aggregate fair value of all derivative instruments with specific credit risk-related contingent features that were in a net liability position was $0.9 million and $0.2 million at March 31, 2017 and December 31, 2016, respectively. At March 31, 2017 and December 31, 2016, we had not posted any collateral related to the credit risk-related contingent features of these commodity instruments. If all of the credit risk-related contingent features contained in derivative instruments in a net liability position had been triggered at March 31, 2017 and December 31, 2016, we would not have been required to post any collateral.

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GUARANTEES

3 Months Ended

Mar. 31, 2017

Guarantees [Abstract]

GUARANTEES

GUARANTEES

The following table shows our outstanding guarantees:

	Total Amounts Committed at		Expiration
(in millions)	March 31, 2017		Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees
Standby letters of credit (1)	$	29.1	$	28.0	$	1.1	$	—
Surety bonds (2)	10.9		10.2		0.7		—
Other guarantees (3)	8.1		0.5		—		7.6
Total guarantees	$	48.1	$	38.7	$	1.8	$	7.6

⁽¹⁾  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.

⁽²⁾  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.

⁽³⁾  Consists of $8.1 million related to other indemnifications, for which a liability of $7.6 million related to workers compensation coverage was recorded on our balance sheets.

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EMPLOYEE BENEFITS

3 Months Ended

Mar. 31, 2017

Compensation and Retirement Disclosure [Abstract]

EMPLOYEE BENEFITS

EMPLOYEE BENEFITS

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

	Pension Costs
	Three Months Ended March 31
(in millions)	2017			2016
Service cost	$	11.7		$	11.3
Interest cost	31.2			33.2
Expected return on plan assets	(49.6		)	(49.0		)
Amortization of prior service cost	0.7			0.9
Amortization of net actuarial loss	21.9			20.5
Net periodic benefit cost	$	15.9		$	16.9

	OPEB Costs
	Three Months Ended March 31
(in millions)	2017			2016
Service cost	$	6.3		$	6.7
Interest cost	8.5			9.2
Expected return on plan assets	(13.7		)	(13.1		)
Amortization of prior service credit	(2.8		)	(2.3		)
Amortization of net actuarial loss	1.5			2.3
Net periodic benefit (credit) cost	$	(0.2	)	$	2.8

During the three months ended March 31, 2017, we made payments of $104.1 million to our pension plans and $1.9 million to our OPEB plans. We expect to make payments of $9.0 million related to our pension plans and $6.5 million related to our OPEB plans during the remainder of 2017, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

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INVESTMENT IN AMERICAN TRANSMISSION COMPANY

3 Months Ended

Mar. 31, 2017

Equity Method Investments and Joint Ventures [Abstract]

INVESTMENT IN AMERICAN TRANSMISSION COMPANY

INVESTMENT IN AMERICAN TRANSMISSION COMPANY

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

	Three Months Ended March 31
(in millions)	2017		2016
Balance at beginning of period	$	1,443.9	$	1,380.9
Add: Earnings from equity method investment	41.9		38.5
Add: Capital contributions	27.6		9.0
Add: Adjustment to equity method goodwill	—		9.3
Less: Distributions *	—		15.1
Less: Other	0.1		0.1
Balance at end of period	$	1,513.3	$	1,422.5

* Distributions of $35.2 million, received in the first quarter of 2017, were approved and recorded in December 2016.

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

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

	Three Months Ended March 31
(in millions)	2017			2016
Charges to ATC for services and construction	$	4.2		$	4.1
Charges from ATC for network transmission services	87.3			100.8
Refund from ATC per FERC ROE order	(28.3		)	—

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

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

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

	Three Months Ended March 31
(in millions)	2017		2016
Income statement data
Revenues	$	174.7	$	164.2
Operating expenses	82.4		79.1
Other expense	26.4		24.0
Net income	$	65.9	$	61.1

(in millions)	March 31, 2017		December 31, 2016
Balance sheet data
Current assets	$	85.5	$	75.8
Noncurrent assets	4,402.2		4,312.9
Total assets	$	4,487.7	$	4,388.7
Current liabilities	$	401.8	$	495.1
Long-term debt	1,940.4		1,865.3
Other noncurrent liabilities	282.9		271.5
Shareholders' equity	1,862.6		1,756.8
Total liabilities and shareholders' equity	$	4,487.7	$	4,388.7

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SEGMENT INFORMATION

3 Months Ended

Mar. 31, 2017

Segment Reporting [Abstract]

SEGMENT INFORMATION

SEGMENT INFORMATION

At March 31, 2017, we reported six segments, which are described below.

• The Wisconsin segment includes the electric and natural gas utility operations of WE, WG, and WPS, including WE's and WPS's electric and natural gas operations in the state of Michigan that were transferred to UMERC effective January 1, 2017.

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

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

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

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

• The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the Peoples Energy, LLC holding company, Wispark LLC, Bostco, Wisvest, Wisconsin Energy Capital Corporation, WBS, WPS Power Development LLC, and ITF. The sale of ITF was completed in the first quarter of 2016. In the first quarter of 2017, we sold substantially all of the remaining assets of Bostco and in the second quarter of 2016, we sold certain assets of Wisvest. See Note 3, Dispositions, for more information on these sales.

All of our operations are located within the United States. The following tables show summarized financial information related to our reportable segments for the three months ended March 31, 2017 and 2016:

	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, 2017
External revenues	$	1,612.1	$	525.3	$	157.9	$	—	$	2,295.3	$	6.3	$	2.9		$	—		$	2,304.5
Intersegment revenues	—		—		—		—		—		109.0		—			(109.0		)	—
Other operation and maintenance	462.9		120.9		28.3		—		612.1		0.4		(1.6		)	(109.0		)	501.9
Depreciation and amortization	129.3		36.2		6.0		—		171.5		17.5		5.6			—			194.6
Operating income (loss)	332.3		155.4		33.4		—		521.1		97.4		(1.2		)	—			617.3
Equity in earnings of transmission affiliate	—		—		—		41.9		41.9		—		—			—			41.9
Interest expense	48.7		11.1		2.3		—		62.1		15.3		29.1			(1.8		)	104.7

	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

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VARIABLE INTEREST ENTITIES

3 Months Ended

Mar. 31, 2017

Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Determination Methodology and Factors [Abstract]

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES

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

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

American Transmission Company

We own approximately 60% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. We have determined that ATC is a variable interest entity but that consolidation is not required since we are not ATC's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC's economic performance. We account for ATC as an equity method investment. See Note 11, 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, 2017 and December 31, 2016, our equity investment was $1,513.3 million and $1,443.9 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC. In addition, we had $29.1 million and $28.7 million of accounts payable due to ATC at March 31, 2017 and December 31, 2016, respectively, for network transmission services.

Purchased Power Agreement

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

We have approximately $81.9 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under this contract for the three months ended March 31, 2017 and 2016 were $4.5 million and $13.5 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

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COMMITMENTS AND CONTINGENCIES

3 Months Ended

Mar. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

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

Unconditional Purchase Obligations

Our electric utilities have obligations to distribute and sell electricity to their customers, and our natural gas utilities have obligations to distribute and sell natural gas to their customers. The utilities expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of March 31, 2017, including those of our subsidiaries, were $11,774.4 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

Cross-State Air Pollution Rule

In July 2011, the EPA issued the CSAPR, which replaced a previous rule, the Clean Air Interstate Rule. The purpose of the CSAPR was to limit the interstate transport of NOx and SO₂ that contribute to fine particulate matter and ozone nonattainment in downwind states through a proposed allowance allocation and trading plan. After several lawsuits and related appeals, in October 2014, the D.C. Circuit Court of Appeals issued a decision that allowed the EPA to begin implementing CSAPR on January 1, 2015. The emissions budgets of Phase I of the rule applied in 2015 and 2016, while the Phase II emissions budgets apply to 2017 and beyond.

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

Sulfur Dioxide National Ambient Air Quality Standards

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

In June 2016, we provided modeling to the WDNR that shows the area around the Weston Power Plant to be in compliance. Based upon the submittal, the WDNR provided final modeling to the EPA demonstrating the area around the Weston Power Plant to be in compliance. We expect that the EPA will consider the WDNR's recommendation and finalize its recommended designation in August 2017, for finalization by the end of 2017.

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

8-Hour Ozone National Ambient Air Quality Standards

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

After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, which lowered the limit for ground-level ozone, creating a more stringent standard than the 2008 NAAQS. This is expected to cause nonattainment for Wisconsin's Lake Michigan shoreline counties (or partial counties), with potential future impacts for our fossil-fueled power plant fleet. In January 2017, the EPA released preliminary interstate ozone transport modeling for the 2015 ozone NAAQS. The EPA is currently scheduled to finalize designations in October 2017. For nonattainment areas, the state of Wisconsin will have to develop a state implementation plan to bring the areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020. We will not know the potential impacts for complying with the 2015 ozone NAAQS until the designations are final and until the state prepares a draft attainment plan.

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

Climate Change

In 2015, the EPA issued a final rule regulating GHG emissions from existing generating units, referred to as the Clean Power Plan (CPP), a proposed federal plan and model trading rules as alternatives or guides to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In October 2015, following publication of the CPP, numerous states (including Wisconsin and Michigan) and other parties, filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but in February 2016, the Supreme Court stayed the effectiveness of the CPP until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that further appellate review is sought, at the Supreme Court. The D.C. Circuit Court of Appeals heard one case in September 2016, and the other case is still pending. On April 28, 2017, pursuant to motions made by the EPA, the D.C. Circuit Court of Appeals ordered the cases to be held in abeyance, with supplemental briefs to be provided by May 15, 2017, addressing whether the cases should be remanded to the EPA rather than held in abeyance.

The CPP seeks to achieve state-specific GHG emission reduction goals by 2030, and would have required states to submit plans by September 2016. The goal of the final rule is to reduce nationwide GHG emissions by 32% from 2005 levels. The rule is seeking GHG emission reductions in Wisconsin and Michigan of 41% and 39%, respectively, below 2012 levels by 2030. Interim goals starting in 2022 would require states to achieve about two-thirds of the 2030 required reduction.

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

Notwithstanding the uncertain future of the CPP, and given current fuel and technology markets, we continue to evaluate opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute towards long-term GHG reductions. Our plan is to work with our industry partners, environmental groups, and the State of Wisconsin, with a goal of reducing CO₂ emissions by approximately 40% below 2005 levels by 2030. We continue to evaluate numerous options in order to meet our CO₂ reduction goal, such as increased use of existing natural gas combined cycle units, co-firing or switching to natural gas in existing coal-fired units, reduced operation or retirement of existing coal-fired units, addition of new renewable energy resources (wind, solar), and consideration of supply and demand-side energy efficiency and distributed generation.

We are required to report our CO₂ equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2016, we reported aggregated CO₂ equivalent emissions of approximately 29.6 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 emissions from the natural gas that our natural gas utilities distribute and sell. For 2016, we reported aggregated CO₂ equivalent emissions of approximately 26.7 million metric tonnes to the EPA.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

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

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

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

During 2017 and 2018, we will continue to complete studies and evaluate options to address the EM BTA requirements at these plants. With the exception of Pleasant Prairie Power Plant and Weston Units 3 and 4 (which all have existing cooling towers that meet EM BTA requirements), we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at the facilities. We also expect that limited studies to support WDNR BTA determinations will be conducted at the Weston facility. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the EM BTA requirements based on low capacity use of the unit. Based on discussions with the MDEQ, if we provide information about unit retirements with our next National Pollutant Discharge Elimination System permit application and then submit a signed certification by August 2017 stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2022), then the EM BTA requirements will be waived. Entrainment studies are currently being conducted at Pulliam Units 7 and 8 and were recently completed at PIPP. See the UMERC discussion in Note 16, Regulatory Environment, regarding the potential retirement of PIPP.

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

Steam Electric Effluent 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. This rule is being litigated in the United States Court of Appeals for the Fifth Circuit (Fifth Circuit Court of Appeals) and may result in changes to the discharge requirements. In April 2017, the EPA granted a petition filed by the Utility Water Act Group to reconsider and stay the steam effluent guidelines and related compliance deadlines. On April 24, 2017, in response to a motion by the EPA, the Fifth Circuit Court of Appeals ordered a stay of the litigation for 120 days while the rule is being redrafted to address the petition's concerns.

After a final rule is back in effect, the WDNR and MDEQ will modify the state rules as necessary 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 site 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 OC 7, OC 8, the Pleasant Prairie units, Pulliam Units 7 and 8, and Weston Unit 3. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $80 million to $110 million for these advanced treatment and bottom ash transport systems. A similar system would be required at PIPP if we were not expecting to retire the plant. See the UMERC discussion in Note 16, Regulatory Environment, regarding the potential retirement of PIPP.

Land Quality

Manufactured Gas Plant Remediation

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

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

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

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

(in millions)	March 31, 2017		December 31, 2016
Regulatory assets	$	685.4	$	702.7
Reserves for future remediation	630.5		633.4

Enforcement and Litigation Matters

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

Consent Decrees

Wisconsin Public Service Corporation Consent Decree – Weston and Pulliam

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

Also, in May 2010, WPS received from the Sierra Club a Notice of Intent to file a civil lawsuit based on allegations that WPS violated the CAA at the Weston and Pulliam plants. WPS entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended in October 2012, but no further action has been taken by the Sierra Club as of March 31, 2017. It is unknown whether the Sierra Club will take further action in the future.

Joint Ownership Power Plants Consent Decree – Columbia and Edgewater

In December 2009, the EPA issued a NOV to Wisconsin Power and Light, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric, WE (former co-owner of an Edgewater unit), and WPS. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. WPS, along with Wisconsin Power and Light, Madison Gas and Electric, and WE, entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013.

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

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SUPPLEMENTAL CASH FLOW INFORMATION

3 Months Ended

Mar. 31, 2017

Supplemental Cash Flow Information [Abstract]

SUPPLEMENTAL CASH FLOW INFORMATION

SUPPLEMENTAL CASH FLOW INFORMATION

	Three Months Ended March 31
(in millions)	2017			2016
Cash (paid) for interest, net of amount capitalized	$	(56.6	)	$	(53.0	)
Cash received (paid) for income taxes, net	8.9			(0.4		)
Significant non-cash transactions
Accounts payable related to construction costs	116.4			90.1
Increase (decrease) in restricted cash from the sale (purchase) of investments held in the rabbi trust	8.3			(1.5		)
Portion of Bostco real estate holdings sale financed with note receivable *	7.0			—
Amortization of deferred revenue	6.2			6.2

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

At March 31, 2017, and December 31, 2016, restricted cash of $26.9 million and $33.6 million, respectively, was recorded within other long-term assets on our balance sheets. The majority of this amount was held in the Integrys rabbi trust and represents a portion of the required funding that was triggered by the announcement of the Integrys acquisition. Withdrawals of restricted cash from the rabbi trust for qualifying payments are shown as an investing activity on the statements of cash flows. Changes in restricted cash due to the sale or purchase of investments held in the rabbi trust are non-cash transactions and are included in the table above.

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REGULATORY ENVIRONMENT

3 Months Ended

Mar. 31, 2017

Regulated Operations [Abstract]

REGULATORY ENVIRONMENT

REGULATORY ENVIRONMENT

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

2018 and 2019 Rates

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

Pursuant to the settlement agreement, WPS also agreed to adopt, beginning in 2018, the earnings sharing mechanism currently in place for WE and WG, and all three utilities agreed to keep the mechanism in place through 2019. Under this earnings sharing mechanism, if WE, WG, or WPS earns above its authorized ROE, 50% of the first 50 basis points of additional utility earnings must be shared with customers. All utility earnings above the first 50 basis points must also be shared with customers. We expect the PSCW to issue a final order on the settlement agreement in 2017.

Natural Gas Storage Facility in Michigan

In January 2017, we signed an agreement for the acquisition of a natural gas storage facility in Michigan that would provide approximately one-third of the current storage needs for WE, WG, and WPS. As a result of this agreement, WE, WG, and WPS filed a request with the PSCW in February 2017 for a declaratory ruling on various items associated with the storage facility. In the filing, WE, WG, and WPS requested that the PSCW review and confirm the reasonableness and prudency of their potential long-term storage service agreements and interstate natural gas transportation contracts related to the storage facility. WE, WG, and WPS also requested approval to amend our Affiliated Interest Agreement to ensure WBS and our other subsidiaries would be able to provide services to the storage facility. We expect to receive these PSCW declarations and approvals by the third quarter of 2017.

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

Illinois Investigations

In March 2015, the ICC opened a docket, naming PGL as respondent, to investigate the veracity of certain allegations included in anonymous letters that the ICC staff received regarding PGL's SMP. PGL and the ICC staff filed a settlement agreement related to these anonymous letters with the ICC during March 2017. In this agreement, we agreed to modify our code of business conduct to address certain concerns regarding conflicts of interest and provide a quarterly report to the ICC for four years identifying code of conduct and conflict of interest allegations. The agreement also requested that PGL provide semi-annual quality assurance reports to the ICC for four years on the SMP capital construction performed by PGL crews and contractors. We are uncertain when the ICC will issue an order related to this settlement agreement.

In December 2015, the ICC ordered a series of stakeholder workshops to evaluate PGL's SMP. This ICC action did not impact PGL's ongoing work to modernize and maintain the safety of its natural gas distribution system, but it instead provided the ICC with an opportunity to analyze long-term elements of the program through the stakeholder workshops. The workshops commenced in January 2016 and were completed in March 2016. The ICC staff submitted a report on the workshop process in May 2016. In July 2016, the ICC initiated a proceeding to review, among other things, the planning, reporting, and monitoring of the program, including the target end date for the program. In March 2017, the ICC issued an order directing that additional hearings be held before the ALJ on certain issues to further develop the evidentiary record in the case. This proceeding is expected to result in a final order by the ICC during the second half of 2017. We are currently unable to determine what, if any, long-term impact there will be on the SMP.

Qualifying Infrastructure Plant Rider

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

PGL's QIP rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2017, PGL filed its 2016 reconciliation with the ICC, which, along with the 2015 reconciliation, is still pending. For PGL's 2014 reconciliation, the ALJ has issued a schedule, and we expect to receive an order from the ICC in 2017. As of March 31, 2017, there can be no assurance that all costs incurred under PGL's QIP rider will be recoverable.

Minnesota Energy Resources Corporation

2016 Minnesota Rate Order

In September 2015, MERC initiated a rate proceeding with the MPUC. In October 2016, the MPUC issued a final written order for MERC, effective March 1, 2017. The order authorized a retail natural gas rate increase of $6.8 million (3.0%). The rates reflect a 9.11% ROE and a common equity component average of 50.32%. The order approved MERC's request to continue the use of its currently authorized decoupling mechanism for another three years. The final approved rate increase was lower than the interim rates collected from customers during 2016. Therefore, as of March 31, 2017, we estimated that $4.1 million will be refunded to MERC's customers in May 2017.

Upper Michigan Energy Resources Corporation

Formation of Upper Michigan Energy Resources Corporation

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

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

2015 Michigan Rate Order

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

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NEW ACCOUNTING PRONOUNCEMENTS

3 Months Ended

Mar. 31, 2017

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

NEW ACCOUNTING PRONOUNCEMENTS

NEW ACCOUNTING PRONOUNCEMENTS

Revenue Recognition

In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. Several amendments were issued subsequent to the standard to clarify the guidance. The core principle of the guidance is to recognize revenue in an amount that an entity is entitled to receive in exchange for goods and services. The guidance also requires additional disclosures about the nature, amount, timing, and uncertainty of revenues and the related cash flows arising from contracts with customers.

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

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

Recognition and Measurement of Financial Instruments

In January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. This guidance requires equity investments, including other ownership interests such as partnerships, unincorporated joint ventures, and limited liability companies, to be measured at fair value with changes in fair value recognized in net income. It also simplifies the impairment assessment of equity investments without readily determinable fair values and amends certain disclosure requirements associated with the fair value of financial instruments. This ASU does not apply to investments accounted for under the equity method of accounting. We 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. The main provision of this ASU is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP.  We are currently assessing the effects this guidance may have on our financial statements.

Financial Instruments Credit Losses

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

Classification of Certain Cash Receipts and Cash Payments

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

Restricted Cash

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

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

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

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GENERAL INFORMATION (Policies)

3 Months Ended

Mar. 31, 2017

Accounting policies

Consolidation

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.

Basis of Accounting

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2016. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three months ended March 31, 2017, are not necessarily indicative of expected results for 2017 due to seasonal variations and other factors.

Fair Value Measurement

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

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

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

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

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

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

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

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

Derivative Instruments

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

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

New Accounting Pronouncements

Revenue Recognition

In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. Several amendments were issued subsequent to the standard to clarify the guidance. The core principle of the guidance is to recognize revenue in an amount that an entity is entitled to receive in exchange for goods and services. The guidance also requires additional disclosures about the nature, amount, timing, and uncertainty of revenues and the related cash flows arising from contracts with customers.

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

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

Recognition and Measurement of Financial Instruments

In January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. This guidance requires equity investments, including other ownership interests such as partnerships, unincorporated joint ventures, and limited liability companies, to be measured at fair value with changes in fair value recognized in net income. It also simplifies the impairment assessment of equity investments without readily determinable fair values and amends certain disclosure requirements associated with the fair value of financial instruments. This ASU does not apply to investments accounted for under the equity method of accounting. We 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. The main provision of this ASU is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP.  We are currently assessing the effects this guidance may have on our financial statements.

Financial Instruments Credit Losses

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

Classification of Certain Cash Receipts and Cash Payments

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

Restricted Cash

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

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

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

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COMMON EQUITY (Tables)

3 Months Ended

Mar. 31, 2017

Equity [Abstract]

Schedule of stock-based compensation awards granted

During the first quarter of 2017, the Compensation Committee of our Board of Directors awarded the following stock-based compensation awards to our directors, officers, and certain other key employees:

Award Type	Number of Awards
Stock options (1)	552,215
Restricted shares (2)	82,622
Performance units	237,650

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

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

Retained earnings

Schedule of changes to retained earnings

Schedule of changes in retained earnings

The following table shows the changes to our retained earnings for the three months ended March 31, 2017:

(in millions)	Retained Earnings
Balance at December 31, 2016	$	4,613.9
Net income attributed to common shareholders	356.6
Common stock dividends	(164.1		)
Cumulative effect of adoption of ASU 2016-09	15.7
Other	(0.1		)
Balance at March 31, 2017	$	4,822.0

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SHORT-TERM DEBT AND LINES OF CREDIT (Tables)

3 Months Ended

Mar. 31, 2017

Short-term Debt [Abstract]

Short-term notes payable balances and their corresponding weighted average interest rate

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

(in millions, except percentages)	March 31, 2017			December 31, 2016
Commercial paper
Amount outstanding	$	670.4		$	860.2
Weighted-average interest rate on amounts outstanding	1.18		%	0.96		%

Schedule of revolving credit facilities and remaining available capacity

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

(in millions)	Maturity	March 31, 2017
WEC Energy Group	December 2020	$	1,050.0
WE	December 2020	500.0
WPS	December 2020	250.0
WG	December 2020	350.0
PGL	December 2020	350.0
Total short-term credit capacity		$	2,500.0
Less:
Letters of credit issued inside credit facilities		$	29.1
Commercial paper outstanding		670.4
Available capacity under existing agreements		$	1,800.5

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MATERIALS, SUPPLIES, AND INVENTORIES (Tables)

3 Months Ended

Mar. 31, 2017

Inventory Disclosure [Abstract]

Schedule of inventory

Our inventory consisted of:

(in millions)	March 31, 2017		December 31, 2016
Natural gas in storage	$	45.8	$	223.1
Materials and supplies	208.3		206.5
Fossil fuel	163.0		158.0
Total	$	417.1	$	587.6

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FAIR VALUE MEASUREMENTS (Tables)

3 Months Ended

Mar. 31, 2017

Fair Value Disclosures [Abstract]

Fair value of assets and liabilities measured on a recurring basis, categorized by level within the fair value hierarchy

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

	March 31, 2017
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	2.3	$	9.5	$	—	$	11.8
FTRs	—		—		1.7		1.7
Coal contracts	—		1.0		—		1.0
Total derivative assets	$	2.3	$	10.5	$	1.7	$	14.5
Investments held in rabbi trust	$	101.7	$	—	$	—	$	101.7
Derivative liabilities
Natural gas contracts	$	—	$	0.9	$	—	$	0.9
Petroleum products contracts	0.3		—		—		0.3
Coal contracts	—		3.0		—		3.0
Total derivative liabilities	$	0.3	$	3.9	$	—	$	4.2

	December 31, 2016
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	10.1	$	24.2	$	—	$	34.3
Petroleum products contracts	0.2		—		—		0.2
FTRs	—		—		5.1		5.1
Coal contracts	—		2.0		—		2.0
Total derivative assets	$	10.3	$	26.2	$	5.1	$	41.6
Investments held in rabbi trust	$	103.9	$	—	$	—	$	103.9
Derivative liabilities
Natural gas contracts	$	0.2	$	0.2	$	—	$	0.4
Petroleum products contracts	0.1		—		—		0.1
Coal contracts	—		1.9		—		1.9
Total derivative liabilities	$	0.3	$	2.1	$	—	$	2.4

Reconciliation of changes in fair value of items categorized as level 3 measurements

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

	Three Months Ended March 31
(in millions)	2017			2016
Balance at the beginning of the period	$	5.1		$	3.6
Realized and unrealized losses	—			(0.2		)
Sales	—			(0.1		)
Settlements	(3.4		)	(2.2		)
Balance at the end of the period	$	1.7		$	1.1

Schedule of carrying value and estimated fair value of financial instruments not recorded at fair value

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

	March 31, 2017				December 31, 2016
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock	$	30.4	$	28.9	$	30.4	$	28.8
Long-term debt, including current portion *	9,272.7		9,730.2		9,285.8		9,818.2

* The carrying amount of long-term debt excludes capital lease obligations of $28.9 million and $29.6 million at March 31, 2017 and

December 31, 2016, respectively.

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DERIVATIVE INSTRUMENTS (Tables)

3 Months Ended

Mar. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative assets and derivative liabilities

The following table shows our derivative assets and derivative liabilities:

	March 31, 2017				December 31, 2016
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	11.4	$	0.7	$	31.4	$	0.4
Petroleum products contracts	—		0.3		0.2		0.1
FTRs	1.7		—		5.1		—
Coal contracts	1.0		1.8		1.5		1.4
Total other current *	$	14.1	$	2.8	$	38.2	$	1.9
Other long-term
Natural gas contracts	$	0.4	$	0.2	$	2.9	$	—
Coal contracts	—		1.2		0.5		0.5
Total other long-term *	$	0.4	$	1.4	$	3.4	$	0.5
Total	$	14.5	$	4.2	$	41.6	$	2.4

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

Estimated notional volumes and realized gain (losses)

Our estimated notional sales volumes and realized gains (losses) were as follows:

	Three Months Ended March 31, 2017				Three Months Ended March 31, 2016
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	34.1 Dth	$	(0.3	)	50.1 Dth	$	(33.5	)
Petroleum products contracts	4.9 gallons	(0.5		)	3.0 gallons	(1.1		)
FTRs	9.2 MWh	3.0			7.6 MWh	3.0
Total		$	2.2			$	(31.6	)

Offsetting assets and liabilities

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

	March 31, 2017						December 31, 2016
(in millions)	Derivative Assets			Derivative Liabilities			Derivative Assets				Derivative Liabilities
Gross amount recognized on the balance sheet	$	14.5		$	4.2		$	41.6			$	2.4
Gross amount not offset on the balance sheet	(1.2		)	(1.2		)	(4.9		)	*	(0.5		)
Net amount	$	13.3		$	3.0		$	36.7			$	1.9

* Includes cash collateral received of $4.4 million.

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GUARANTEES (Tables)

3 Months Ended

Mar. 31, 2017

Guarantees [Abstract]

Schedule of outstanding guarantees

The following table shows our outstanding guarantees:

	Total Amounts Committed at		Expiration
(in millions)	March 31, 2017		Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees
Standby letters of credit (1)	$	29.1	$	28.0	$	1.1	$	—
Surety bonds (2)	10.9		10.2		0.7		—
Other guarantees (3)	8.1		0.5		—		7.6
Total guarantees	$	48.1	$	38.7	$	1.8	$	7.6

⁽¹⁾  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.

⁽²⁾  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.

⁽³⁾  Consists of $8.1 million related to other indemnifications, for which a liability of $7.6 million related to workers compensation coverage was recorded on our balance sheets.

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EMPLOYEE BENEFITS (Tables)

3 Months Ended

Mar. 31, 2017

Compensation and Retirement Disclosure [Abstract]

Schedule of the components of net periodic benefit cost

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

	Pension Costs
	Three Months Ended March 31
(in millions)	2017			2016
Service cost	$	11.7		$	11.3
Interest cost	31.2			33.2
Expected return on plan assets	(49.6		)	(49.0		)
Amortization of prior service cost	0.7			0.9
Amortization of net actuarial loss	21.9			20.5
Net periodic benefit cost	$	15.9		$	16.9

	OPEB Costs
	Three Months Ended March 31
(in millions)	2017			2016
Service cost	$	6.3		$	6.7
Interest cost	8.5			9.2
Expected return on plan assets	(13.7		)	(13.1		)
Amortization of prior service credit	(2.8		)	(2.3		)
Amortization of net actuarial loss	1.5			2.3
Net periodic benefit (credit) cost	$	(0.2	)	$	2.8

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INVESTMENT IN AMERICAN TRANSMISSION COMPANY (Tables) - ATC

3 Months Ended

Mar. 31, 2017

Investment in ATC

Schedule of changes to our investment in ATC

The following table shows changes to our investment in ATC:

	Three Months Ended March 31
(in millions)	2017		2016
Balance at beginning of period	$	1,443.9	$	1,380.9
Add: Earnings from equity method investment	41.9		38.5
Add: Capital contributions	27.6		9.0
Add: Adjustment to equity method goodwill	—		9.3
Less: Distributions *	—		15.1
Less: Other	0.1		0.1
Balance at end of period	$	1,513.3	$	1,422.5

* Distributions of $35.2 million, received in the first quarter of 2017, were approved and recorded in December 2016

Schedule of significant transactions with ATC

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

	Three Months Ended March 31
(in millions)	2017			2016
Charges to ATC for services and construction	$	4.2		$	4.1
Charges from ATC for network transmission services	87.3			100.8
Refund from ATC per FERC ROE order	(28.3		)	—

Schedule of receivables and payables with ATC

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

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

Schedule of summarized income statement data for ATC

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

	Three Months Ended March 31
(in millions)	2017		2016
Income statement data
Revenues	$	174.7	$	164.2
Operating expenses	82.4		79.1
Other expense	26.4		24.0
Net income	$	65.9	$	61.1

Schedule of summarized balance sheet data for ATC

(in millions)	March 31, 2017		December 31, 2016
Balance sheet data
Current assets	$	85.5	$	75.8
Noncurrent assets	4,402.2		4,312.9
Total assets	$	4,487.7	$	4,388.7
Current liabilities	$	401.8	$	495.1
Long-term debt	1,940.4		1,865.3
Other noncurrent liabilities	282.9		271.5
Shareholders' equity	1,862.6		1,756.8
Total liabilities and shareholders' equity	$	4,487.7	$	4,388.7

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SEGMENT INFORMATION (Tables)

3 Months Ended

Mar. 31, 2017

Segment Reporting [Abstract]

Financial information of reportable segments

The following tables show summarized financial information related to our reportable segments for the three months ended March 31, 2017 and 2016:

	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, 2017
External revenues	$	1,612.1	$	525.3	$	157.9	$	—	$	2,295.3	$	6.3	$	2.9		$	—		$	2,304.5
Intersegment revenues	—		—		—		—		—		109.0		—			(109.0		)	—
Other operation and maintenance	462.9		120.9		28.3		—		612.1		0.4		(1.6		)	(109.0		)	501.9
Depreciation and amortization	129.3		36.2		6.0		—		171.5		17.5		5.6			—			194.6
Operating income (loss)	332.3		155.4		33.4		—		521.1		97.4		(1.2		)	—			617.3
Equity in earnings of transmission affiliate	—		—		—		41.9		41.9		—		—			—			41.9
Interest expense	48.7		11.1		2.3		—		62.1		15.3		29.1			(1.8		)	104.7

	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

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COMMITMENTS AND CONTINGENCIES (Tables)

3 Months Ended

Mar. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Schedule of regulatory assets and reserves related to manufactured gas plant sites

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

(in millions)	March 31, 2017		December 31, 2016
Regulatory assets	$	685.4	$	702.7
Reserves for future remediation	630.5		633.4

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SUPPLEMENTAL CASH FLOW INFORMATION (Tables)

3 Months Ended

Mar. 31, 2017

Supplemental Cash Flow Information [Abstract]

Schedule of supplemental cash flow information

	Three Months Ended March 31
(in millions)	2017			2016
Cash (paid) for interest, net of amount capitalized	$	(56.6	)	$	(53.0	)
Cash received (paid) for income taxes, net	8.9			(0.4		)
Significant non-cash transactions
Accounts payable related to construction costs	116.4			90.1
Increase (decrease) in restricted cash from the sale (purchase) of investments held in the rabbi trust	8.3			(1.5		)
Portion of Bostco real estate holdings sale financed with note receivable *	7.0			—
Amortization of deferred revenue	6.2			6.2

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

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GENERAL INFORMATION - GENERAL (Details) customer in Millions	Mar. 31, 2017 customer
Electric
Product information [Line Items]
Number Of Customers	1.6
Natural gas
Product information [Line Items]
Number Of Customers	2.8
ATC
Product information [Line Items]
Equity method investment, ownership interest (as a percent)	60.00%

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ACQUISITION (Details) - Natural gas storage facility in Michigan - USD ($) $ in Millions	1 Months Ended
	Jan. 31, 2017	Mar. 31, 2017
Business Acquisition [Line Items]
Purchase price	$ 225
Percentage of current storage needs provided		33.00%
Expected acquisition costs		$ 5

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DISPOSITIONS (Details) - USD ($) $ in Millions	3 Months Ended
	Jun. 30, 2016	Mar. 31, 2016
Wisconsin | WE
Dispositions
After-tax gain on sale	$ 6.5
Wisconsin | WE | Other operation and maintenance
Dispositions
Pre-tax gain on sale	10.9
Corporate and Other | Wisvest
Dispositions
After-tax gain on sale	11.8
Corporate and Other | Wisvest | Other income, net
Dispositions
Pre-tax gain on sale	$ 19.6
Corporate and Other | ITF
Dispositions
Pre-tax gain on sale		$ 0.0

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COMMON EQUITY - STOCK-BASED COMPENSATION AWARDS GRANTED (Details)	3 Months Ended
	Mar. 31, 2017 $ / shares shares
Stock options
Stock-based Compensation
Stock options granted | shares	552,215
Stock options granted, weighted average exercise price | $ / shares	$ 58.31
Stock options granted, weighted-average grant date fair value | $ / shares	$ 7.45
Restricted shares
Stock-based Compensation
Awards granted | shares	82,622
Restricted shares granted, weighted-average grant date fair value | $ / shares	$ 58.10
Performance units
Stock-based Compensation
Awards granted | shares	237,650

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COMMON EQUITY - ADOPTION OF ASU 2016-09 (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Changes in retained earnings [Roll Forward]
Balance at December 31, 2016	$ 4,613.9
Net income attributed to common shareholders	356.6	$ 346.2
Common stock dividends	(164.1)
Cumulative effect of adoption of ASU 2016-09	15.7
Other	(0.1)
Balance at March 31, 2017	$ 4,822.0

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COMMON EQUITY - COMMON STOCK DIVIDENDS (Details) - $ / shares		3 Months Ended
	Apr. 20, 2017	Mar. 31, 2017	Mar. 31, 2016
Dividends Payable
Quarterly cash dividend declared (in dollars per share)		$ 0.5200	$ 0.4950
Subsequent event
Dividends Payable
Quarterly cash dividend declared (in dollars per share)	$ 0.52

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SHORT-TERM DEBT AND LINES OF CREDIT - SHORT-TERM BORROWINGS (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Short-term borrowings
Commercial Paper	$ 670.4	$ 860.2
Commercial paper
Short-term borrowings
Weighted-average interest rate on amounts outstanding	1.18%	0.96%
Average amounts outstanding during the period	$ 746.2
Weighted-average interest rate during the period	1.01%

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SHORT-TERM DEBT AND LINES OF CREDIT - REVOLVING CREDIT FACILITIES (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Line of Credit Facility [Line Items]
Short-term credit capacity	$ 2,500.0
Letters of credit issued inside credit facilities	29.1
Commercial Paper	670.4	$ 860.2
Available capacity under existing agreements	1,800.5
WEC Energy Group | Credit facility maturing December 2020
Line of Credit Facility [Line Items]
Short-term credit capacity	1,050.0
Wisconsin Electric | Credit facility maturing December 2020
Line of Credit Facility [Line Items]
Short-term credit capacity	500.0
WPS | Credit facility maturing December 2020
Line of Credit Facility [Line Items]
Short-term credit capacity	250.0
Wisconsin Gas | Credit facility maturing December 2020
Line of Credit Facility [Line Items]
Short-term credit capacity	350.0
PGL | Credit facility maturing December 2020
Line of Credit Facility [Line Items]
Short-term credit capacity	$ 350.0

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MATERIALS, SUPPLIES, AND INVENTORIES (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Materials, supplies, and inventories
Natural gas in storage	$ 45.8	$ 223.1
Materials and supplies	208.3	206.5
Fossil fuel	163.0	158.0
Total	417.1	$ 587.6
PGL and NSG
Materials, supplies, and inventories
Temporary LIFO liquidation debit	$ 31.6

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FAIR VALUE MEASUREMENTS - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Assets
Derivative asset	$ 14.5	$ 41.6
Liabilities
Derivative liability	4.2	2.4
Fair value measurements on a recurring basis
Assets
Derivative asset	14.5	41.6
Investments held in rabbi trust	101.7	103.9
Liabilities
Derivative liability	4.2	2.4
Fair value measurements on a recurring basis | Level 1
Assets
Derivative asset	2.3	10.3
Investments held in rabbi trust	101.7	103.9
Liabilities
Derivative liability	0.3	0.3
Fair value measurements on a recurring basis | Level 2
Assets
Derivative asset	10.5	26.2
Investments held in rabbi trust	0.0	0.0
Liabilities
Derivative liability	3.9	2.1
Fair value measurements on a recurring basis | Level 3
Assets
Derivative asset	1.7	5.1
Investments held in rabbi trust	0.0	0.0
Liabilities
Derivative liability	0.0	0.0
Fair value measurements on a recurring basis | Natural gas contracts
Assets
Derivative asset	11.8	34.3
Liabilities
Derivative liability	0.9	0.4
Fair value measurements on a recurring basis | Natural gas contracts | Level 1
Assets
Derivative asset	2.3	10.1
Liabilities
Derivative liability	0.0	0.2
Fair value measurements on a recurring basis | Natural gas contracts | Level 2
Assets
Derivative asset	9.5	24.2
Liabilities
Derivative liability	0.9	0.2
Fair value measurements on a recurring basis | Natural gas contracts | Level 3
Assets
Derivative asset	0.0	0.0
Liabilities
Derivative liability	0.0	0.0
Fair value measurements on a recurring basis | Petroleum products contracts
Assets
Derivative asset		0.2
Liabilities
Derivative liability	0.3	0.1
Fair value measurements on a recurring basis | Petroleum products contracts | Level 1
Assets
Derivative asset		0.2
Liabilities
Derivative liability	0.3	0.1
Fair value measurements on a recurring basis | Petroleum products contracts | Level 2
Assets
Derivative asset		0.0
Liabilities
Derivative liability	0.0	0.0
Fair value measurements on a recurring basis | Petroleum products contracts | Level 3
Assets
Derivative asset		0.0
Liabilities
Derivative liability	0.0	0.0
Fair value measurements on a recurring basis | FTRs
Assets
Derivative asset	1.7	5.1
Fair value measurements on a recurring basis | FTRs | Level 1
Assets
Derivative asset	0.0	0.0
Fair value measurements on a recurring basis | FTRs | Level 2
Assets
Derivative asset	0.0	0.0
Fair value measurements on a recurring basis | FTRs | Level 3
Assets
Derivative asset	1.7	5.1
Fair value measurements on a recurring basis | Coal contracts
Assets
Derivative asset	1.0	2.0
Liabilities
Derivative liability	3.0	1.9
Fair value measurements on a recurring basis | Coal contracts | Level 1
Assets
Derivative asset	0.0	0.0
Liabilities
Derivative liability	0.0	0.0
Fair value measurements on a recurring basis | Coal contracts | Level 2
Assets
Derivative asset	1.0	2.0
Liabilities
Derivative liability	3.0	1.9
Fair value measurements on a recurring basis | Coal contracts | Level 3
Assets
Derivative asset	0.0	0.0
Liabilities
Derivative liability	$ 0.0	$ 0.0

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FAIR VALUE MEASUREMENTS - LEVEL 3 RECONCILIATION (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Balance at the beginning of the period	$ 5.1	$ 3.6
Realized and unrealized losses	0.0	(0.2)
Sales	0.0	(0.1)
Settlements	(3.4)	(2.2)
Balance at the end of period	1.7	1.1
Unrealized gains and losses on level 3 derivatives included in earnings	$ 0.0	$ 0.0

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FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Financial Instruments
Preferred stock	$ 30.4	$ 30.4
Carrying Amount
Financial Instruments
Preferred stock	30.4	30.4
Long-term debt, including current portion	9,272.7	9,285.8
Capital lease obligations	28.9	29.6
Fair Value
Financial Instruments
Preferred stock	28.9	28.8
Long-term debt, including current portion	$ 9,730.2	$ 9,818.2

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DERIVATIVE INSTRUMENTS - DERIVATIVE ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Derivative Asset
Other current derivative assets	$ 14.1	$ 38.2
Other long-term derivative assets	0.4	3.4
Derivative asset	14.5	41.6
Derivative Liability
Other current derivative liabilities	2.8	1.9
Other long-term derivative liabilities	1.4	0.5
Derivative liability	4.2	2.4
Natural gas contracts
Derivative Asset
Other current derivative assets	11.4	31.4
Other long-term derivative assets	0.4	2.9
Derivative Liability
Other current derivative liabilities	0.7	0.4
Other long-term derivative liabilities	0.2	0.0
Petroleum products contracts
Derivative Asset
Other current derivative assets	0.0	0.2
Derivative Liability
Other current derivative liabilities	0.3	0.1
FTRs
Derivative Asset
Other current derivative assets	1.7	5.1
Derivative Liability
Other current derivative liabilities	0.0	0.0
Coal contracts
Derivative Asset
Other current derivative assets	1.0	1.5
Other long-term derivative assets	0.0	0.5
Derivative Liability
Other current derivative liabilities	1.8	1.4
Other long-term derivative liabilities	$ 1.2	$ 0.5

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DERIVATIVE INSTRUMENTS - GAINS (LOSSES) AND NOTIONAL VOLUMES (Details) gal in Millions, MWh in Millions, MMBTU in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($) MMBTU MWh gal	Mar. 31, 2016 USD ($) MMBTU MWh gal
Realized Gain (Loss) on Derivatives, Net
Gains (Losses)	$ 2.2	$ (31.6)
Natural gas contracts
Realized Gain (Loss) on Derivatives, Net
Gains (Losses)	$ (0.3)	$ (33.5)
Notional Sales Volumes
Notional sales volumes (Dth or MWh) | MMBTU	34.1	50.1
Petroleum products contracts
Realized Gain (Loss) on Derivatives, Net
Gains (Losses)	$ (0.5)	$ (1.1)
Notional Sales Volumes
Notional sales volumes (gallons) | gal	4.9	3.0
FTRs
Realized Gain (Loss) on Derivatives, Net
Gains (Losses)	$ 3.0	$ 3.0
Notional Sales Volumes
Notional sales volumes (Dth or MWh) | MWh	9.2	7.6

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DERIVATIVE INSTRUMENTS - BALANCE SHEET OFFSETTING (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Cash collateral
Cash collateral in margin account	$ 19.3	$ 16.4
Cash collateral received		4.4
Offsetting Derivative Assets
Gross amount recognized on the balance sheet	14.5	41.6
Gross amount not offset on the balance sheet	(1.2)	(4.9)
Net amount	13.3	36.7
Collateral received		4.4
Offsetting Derivative Liabilities
Gross amount recognized on the balance sheet	4.2	2.4
Gross amount not offset on the balance sheet	(1.2)	(0.5)
Net amount	3.0	1.9
Credit Risk Related Contingent Features
Aggregate fair value of derivative instruments with credit risk-related contingent features that were in a liability position	$ 0.9	$ 0.2

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GUARANTEES (Details) $ in Millions	Mar. 31, 2017 USD ($)
Guarantees
Total guarantees	$ 48.1
Guarantees expiring in less than 1 year	38.7
Guarantees expiring within 1 to 3 years	1.8
Guarantees with expiration over 3 years	7.6
Standby letters of credit
Guarantees
Total guarantees	29.1
Guarantees expiring in less than 1 year	28.0
Guarantees expiring within 1 to 3 years	1.1
Guarantees with expiration over 3 years	0.0
Surety bonds
Guarantees
Total guarantees	10.9
Guarantees expiring in less than 1 year	10.2
Guarantees expiring within 1 to 3 years	0.7
Guarantees with expiration over 3 years	0.0
Other guarantees
Guarantees
Total guarantees	8.1
Guarantees expiring in less than 1 year	0.5
Guarantees expiring within 1 to 3 years	0.0
Guarantees with expiration over 3 years	7.6
Other indemnifications
Guarantees
Total guarantees	8.1
Liability related to workers compensation coverage	$ 7.6

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EMPLOYEE BENEFITS (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Employee Benefit Plans
Document Fiscal Year Focus	2017
Components of net periodic benefit cost
Contributions and payments related to pension and OPEB plans	$ 106.0	$ 15.1
Pension Costs
Components of net periodic benefit cost
Service cost	11.7	11.3
Interest cost	31.2	33.2
Expected return on plan assets	(49.6)	(49.0)
Amortization of prior service cost (credit)	0.7	0.9
Amortization of net actuarial loss	21.9	20.5
Net periodic benefit (credit) cost	15.9	16.9
Contributions and payments related to pension and OPEB plans	104.1
Estimated future employer contributions for the remainder of the year	9.0
Other Postretirement Benefit Costs
Components of net periodic benefit cost
Service cost	6.3	6.7
Interest cost	8.5	9.2
Expected return on plan assets	(13.7)	(13.1)
Amortization of prior service cost (credit)	(2.8)	(2.3)
Amortization of net actuarial loss	1.5	2.3
Net periodic benefit (credit) cost	(0.2)	$ 2.8
Contributions and payments related to pension and OPEB plans	1.9
Estimated future employer contributions for the remainder of the year	$ 6.5

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INVESTMENT IN AMERICAN TRANSMISSION COMPANY - CHANGES TO INVESTMENT (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Changes to investment in ATC
Investment in ATC, balance at beginning of period	$ 1,443.9
Add: Earnings from equity method investment	41.9	$ 38.5
Investment in ATC, balance at end of period	$ 1,513.3
ATC
Investment in ATC
Ownership interest in ATC (as a percent)	60.00%
Changes to investment in ATC
Investment in ATC, balance at beginning of period	$ 1,443.9	1,380.9
Add: Earnings from equity method investment	41.9	38.5
Add: Capital contributions	27.6	9.0
Add: Adjustment to equity method goodwill	0.0	9.3
Less: Distributions	0.0	15.1
Less: Other	0.1	0.1
Investment in ATC, balance at end of period	$ 1,513.3	$ 1,422.5
Dividends Receivable			$ 35.2

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INVESTMENT IN AMERICAN TRANSMISSION COMPANY - RELATED PARTY TRANSACTIONS (Details) - ATC - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Investment in ATC
Charges to ATC for services and construction	$ 4.2	$ 4.1
Charges from ATC for network transmission services	87.3	100.8
Refund from ATC per FERC ROE order	$ (28.3)	$ 0.0

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INVESTMENT IN AMERICAN TRANSMISSION COMPANY - RELATED PARTY TRANSACTIONS BALANCE SHEET INFORMATION (Details) - ATC - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Investment in ATC
Accounts receivable for services provided to ATC	$ 1.2	$ 2.2
Accounts payable for services received from ATC	$ 29.1	$ 28.7

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INVESTMENT IN AMERICAN TRANSMISSION COMPANY - SUMMARIZED FINANCIAL DATA (Details) - ATC - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Income statement data
Revenues	$ 174.7	$ 164.2
Operating expenses	82.4	79.1
Other expense	26.4	24.0
Net income	65.9	$ 61.1
Balance sheet data
Current assets	85.5		$ 75.8
Noncurrent assets	4,402.2		4,312.9
Total assets	4,487.7		4,388.7
Current liabilities	401.8		495.1
Long-term debt	1,940.4		1,865.3
Other noncurrent liabilities	282.9		271.5
Shareholders' equity	1,862.6		1,756.8
Total liabilities and shareholders' equity	$ 4,487.7		$ 4,388.7

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SEGMENT INFORMATION (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($) segment	Mar. 31, 2016 USD ($)
Segment information
Number of reportable segments | segment	6
Revenues	$ 2,304.5	$ 2,194.8
Other operation and maintenance	501.9	531.5
Depreciation and amortization	194.6	187.9
Operating income (loss)	617.3	589.3
Equity in earnings of transmission affiliate	41.9	38.5
Interest expense	104.7	100.9
Intersegment revenues
Segment information
Revenues	0.0	0.0
We Power
Segment information
Revenues	6.3	6.2
Other operation and maintenance	0.4	0.4
Depreciation and amortization	17.5	17.0
Operating income (loss)	97.4	93.3
Equity in earnings of transmission affiliate	0.0	0.0
Interest expense	15.3	15.6
We Power | Intersegment revenues
Segment information
Revenues	109.0	104.5
Corporate and Other
Segment information
Revenues	2.9	11.9
Other operation and maintenance	(1.6)	(3.5)
Depreciation and amortization	5.6	10.1
Operating income (loss)	(1.2)	(0.3)
Equity in earnings of transmission affiliate	0.0	0.0
Interest expense	29.1	31.3
Corporate and Other | Intersegment revenues
Segment information
Revenues	0.0	0.0
Reconciling Eliminations
Segment information
Revenues	0.0	0.0
Other operation and maintenance	(109.0)	(104.6)
Depreciation and amortization	0.0	0.0
Operating income (loss)	0.0	0.0
Equity in earnings of transmission affiliate	0.0	0.0
Interest expense	(1.8)	(2.7)
Reconciling Eliminations | Intersegment revenues
Segment information
Revenues	(109.0)	(104.6)
Regulated operations
Segment information
Revenues	2,295.3	2,176.7
Other operation and maintenance	612.1	639.2
Depreciation and amortization	171.5	160.8
Operating income (loss)	521.1	496.3
Equity in earnings of transmission affiliate	41.9	38.5
Interest expense	62.1	56.7
Regulated operations | Intersegment revenues
Segment information
Revenues	0.0	0.1
Regulated operations | Wisconsin
Segment information
Revenues	1,612.1	1,579.8
Other operation and maintenance	462.9	491.3
Depreciation and amortization	129.3	122.9
Operating income (loss)	332.3	327.5
Equity in earnings of transmission affiliate	0.0	0.0
Interest expense	48.7	44.5
Regulated operations | Wisconsin | Intersegment revenues
Segment information
Revenues	0.0	0.1
Regulated operations | Illinois
Segment information
Revenues	525.3	448.5
Other operation and maintenance	120.9	117.9
Depreciation and amortization	36.2	32.8
Operating income (loss)	155.4	137.0
Equity in earnings of transmission affiliate	0.0	0.0
Interest expense	11.1	9.7
Regulated operations | Illinois | Intersegment revenues
Segment information
Revenues	0.0	0.0
Regulated operations | Other States
Segment information
Revenues	157.9	148.4
Other operation and maintenance	28.3	30.0
Depreciation and amortization	6.0	5.1
Operating income (loss)	33.4	31.8
Equity in earnings of transmission affiliate	0.0	0.0
Interest expense	2.3	2.5
Regulated operations | Other States | Intersegment revenues
Segment information
Revenues	0.0	0.0
Regulated operations | Electric Transmission
Segment information
Revenues	0.0	0.0
Other operation and maintenance	0.0	0.0
Depreciation and amortization	0.0	0.0
Operating income (loss)	0.0	0.0
Equity in earnings of transmission affiliate	41.9	38.5
Interest expense	0.0	0.0
Regulated operations | Electric Transmission | Intersegment revenues
Segment information
Revenues	$ 0.0	0.0
ATC
Segment information
Equity method investment, ownership interest (as a percent)	60.00%
Equity in earnings of transmission affiliate	$ 41.9	$ 38.5

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VARIABLE INTEREST ENTITIES (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($) MW	Mar. 31, 2016 USD ($)	Dec. 31, 2016 USD ($)
Variable interest entities
Equity investment in ATC	$ 1,513.3		$ 1,443.9
ATC
Variable interest entities
Ownership interest in ATC (as a percent)	60.00%
Equity investment in ATC	$ 1,513.3		1,443.9
Accounts payable due to ATC	$ 29.1		$ 28.7
Purchased power agreement
Variable interest entities
Firm capacity from purchased power agreement (in megawatts) | MW	236
Minimum energy requirements over remaining term of purchased power agreement (in megawatts) | MW	0
Remaining term of purchased power agreement (in years)	5 years
Residual guarantee associated with purchased power agreement	$ 0.0
Required payments over remaining term of purchased power agreement	81.9
Total capacity and lease payments	$ 4.5	$ 13.5

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COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Millions	Mar. 31, 2017 USD ($)
Minimum future commitments for purchase obligations
Purchase obligations	$ 11,774.4

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COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) T in Millions, $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Aug. 31, 2014	Mar. 31, 2017 USD ($)	Dec. 31, 2016 USD ($) T	Dec. 31, 2015	Sep. 30, 2016
Climate Change | Electric
Air quality
Number of legal cases heard by a court					1
Percentage of nationwide greenhouse gas emissions reduction				32.00%
Interim goal for greenhouse gas emissions reduction (fraction)				0.667
Percentage carbon dioxide emission reduction company goal		40.00%
Carbon dioxide emissions | T			29.6
Climate Change | Electric | Wisconsin
Air quality
Percentage of greenhouse gas emissions reduction by state				41.00%
Climate Change | Electric | Michigan
Air quality
Percentage of greenhouse gas emissions reduction by state				39.00%
Climate Change | Natural gas
Air quality
Carbon dioxide emissions | T			26.7
Clean Water Act Cooling Water Intake Structure Rule | Electric
Water quality
Number of compliance options available to meet standard	7
Steam Electric Effluent Guidelines | Electric
Water quality
Renewal period for facility permits		5 years
Steam Electric Effluent Guidelines | Minimum | Electric
Water quality
Expected cost to achieve required emissions reductions		$ 80.0
Steam Electric Effluent Guidelines | Maximum | Electric
Water quality
Expected cost to achieve required emissions reductions		110.0
Manufactured Gas Plant Remediation | Natural gas
Manufactured gas plant remediation
Regulatory assets recorded for remediation of manufactured gas plant sites		685.4	$ 702.7
Reserves recorded for remediation of manufactured gas plant sites		$ 630.5	$ 633.4

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SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Supplemental Cash Flow Information [Abstract]
Cash (paid) for interest, net of amount capitalized	$ (56.6)	$ (53.0)
Cash received (paid) for income taxes, net	8.9	(0.4)
Accounts payable related to construction costs	116.4	90.1
Increase (decease) in restricted cash from the sale (purchase) of investments held in the rabbi trust	8.3	(1.5)
Portion of Bostco real estate holdings sale financed with note receivable	7.0	0.0
Amortization of deferred revenue	6.2	$ 6.2
Long-term restricted cash	$ 26.9		$ 33.6

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REGULATORY ENVIRONMENT (Details) $ in Millions	1 Months Ended
	Apr. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)	Jan. 31, 2017	Oct. 31, 2016 USD ($)	Aug. 31, 2016 USD ($) MW	Apr. 30, 2015 USD ($)
WE, WG, and WPS | Natural gas storage facility in Michigan
Regulatory environment
Percentage of natural gas storage needs provided by the facility			33.33%
PGL | Illinois Commerce Commission (ICC)
Regulatory environment
Number of years code of conduct reports must be provided to the ICC		4 years
Number of years quality assurance reports must be provided to the ICC		4 years
Amount of assurance that PGL's QIP rider costs will be recoverable		0
MERC | Minnesota Public Utilities Commission (MPUC) | 2016 rates | Natural gas rates
Regulatory environment
Approved rate increase				$ 6.8
Approved rate increase (as a percent)				3.00%
Approved return on equity (as a percent)				9.11%
Approved common equity component average (as a percent)				50.32%
Number of years decoupling mechanism authorized for use				3 years
Interim rate refund		$ 4.1
UMERC
Regulatory environment
Term of electric power purchase agreement (in years)					20 years
Capacity of natural gas-fired generation facility (in megawatts) | MW					180
Estimated cost of constructing a power plant					$ 265.0
Estimated cost of constructing a power plant, including AFUDC					$ 275.0
Portion of the power plant costs recoverable from Tilden Mining Company (as a percent)					50.00%
Portion of the power plant costs recoverable from utility customers (as a percent)					50.00%
UMERC | Michigan Public Service Commission (MPSC) | 2015 rates | Electric rates
Regulatory environment
Approved rate increase						$ 4.0
Approved return on equity (as a percent)						10.20%
Approved common equity component average (as a percent)						50.48%
Period of rate implementation (in years)						3 years
Subsequent event | WE, WG, and WPS | Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates
Regulatory environment
Authorized revenue requirement for ReACT	$ 275.0
Number of utilities with earnings sharing mechanism	3
Percentage of first 50 basis points of additional utility earnings shared with customers	50.00%
ROE in excess of authorized amount (as a percent)	0.50%