WEC ENERGY GROUP, INC. - Quarter Report: 2016 September (Form 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 Ended September 30, 2016



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

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

Yes [X] No [ ]

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

Yes [X] No [ ]

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



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

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

Yes [ ] No [X]

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

Common Stock, $.01 Par Value,

315,617,299 shares outstanding at

September 30, 2016

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WEC ENERGY GROUP, INC.

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended September 30, 2016

TABLE OF CONTENTS



				Page
	CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION			1
PART I.	FINANCIAL INFORMATION			3
ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)			3
	Condensed Consolidated Income Statements			3
	Condensed Consolidated Statements of Comprehensive Income			4
	Condensed Consolidated Balance Sheets			5
	Condensed Consolidated Statements of Cash Flows			6
	Notes to Condensed Consolidated Financial Statements			7
			Page
	Note 1	General Information	7
	Note 2	Acquisition	7
	Note 3	Dispositions	9
	Note 4	Common Equity	10
	Note 5	Short-Term Debt and Lines of Credit	10
	Note 6	Long-Term Debt	11
	Note 7	Materials, Supplies, and Inventories	11
	Note 8	Fair Value Measurements	12
	Note 9	Derivative Instruments	14
	Note 10	Guarantees	15
	Note 11	Employee Benefits	16
	Note 12	Goodwill	16
	Note 13	Investment in American Transmission Company	17
	Note 14	Segment Information	18
	Note 15	Variable Interest Entities	19
	Note 16	Commitments and Contingencies	20
	Note 17	Supplemental Cash Flow Information	25
	Note 18	Regulatory Environment	26
	Note 19	New Accounting Pronouncements	27
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			29
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			50
ITEM 4.	CONTROLS AND PROCEDURES			51
PART II.	OTHER INFORMATION			52
ITEM 1.	LEGAL PROCEEDINGS			52
ITEM 1A.	RISK FACTORS			52
ITEM 6.	EXHIBITS			53
SIGNATURE				54



09/30/2016 Form 10-Q	i	WEC Energy Group, Inc.

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GLOSSARY OF TERMS AND ABBREVIATIONS

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



Subsidiaries and Affiliates
ATC		American Transmission Company LLC
Integrys		Integrys Holding, Inc. (previously known as Integrys Energy Group, Inc.)
ITF		Integrys Transportation Fuels, LLC
MERC		Minnesota Energy Resources Corporation
MGU		Michigan Gas Utilities Corporation
NSG		North Shore Gas Company
PDL		WPS Power Development, LLC
PGL		The Peoples Gas Light and Coke Company
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
ASC		Accounting Standards Codification
ASU		Accounting Standards Update
FASB		Financial Accounting Standards Board
GAAP		United States Generally Accepted Accounting Principles
LIFO		Last-In, First-Out
OPEB		Other Postretirement Employee Benefits

Environmental Terms
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CSAPR		Cross-State Air Pollution Rule
GHG		Greenhouse Gas
MATS		Mercury and Air Toxics Standards
NAAQS		National Ambient Air Quality Standards
NOV		Notice of Violation
NOx		Nitrogen Oxide
SO₂		Sulfur Dioxide



09/30/2016 Form 10-Q	ii	WEC Energy Group, Inc.

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Measurements
Btu		British Thermal Units
Dth		Dekatherm (One Dth equals one million Btu)
MW		Megawatt (One MW equals one million Watts)
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
Exchange Act		Securities Exchange Act of 1934, as amended
FTRs		Financial Transmission Rights
MCPP		Milwaukee County Power Plant
MISO		Midcontinent Independent System Operator, Inc.
MISO Energy Markets		MISO Energy and Operating Reserves Markets
N/A		Not Applicable
PIPP		Presque Isle Power Plant
ROE		Return on Equity
SMP		Gas System Modernization Program
SMRP		System Modernization and Reliability Project
SSR		System Support Resource
Supreme Court		United States Supreme Court
VAPP		Valley Power Plant



09/30/2016 Form 10-Q	iii	WEC Energy Group, Inc.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

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


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


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


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


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


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

•

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


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

•

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


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


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


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



09/30/2016 Form 10-Q	1	WEC Energy Group, Inc.

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


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


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


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


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


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


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


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


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


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


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


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


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

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



09/30/2016 Form 10-Q	2	WEC Energy Group, Inc.

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WEC ENERGY GROUP, INC.



CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited)	Three Months Ended						Nine Months Ended
	September 30						September 30
(in millions, except per share amounts)	2016			2015			2016			2015
Operating revenues	$	1,712.5		$	1,698.7		$	5,509.3		$	4,077.8

Operating expenses
Cost of sales	554.7			590.6			1,901.9			1,557.5
Other operation and maintenance	517.5			535.9			1,571.0			1,153.6
Depreciation and amortization	191.6			176.5			569.5			382.6
Property and revenue taxes	49.7			50.0			146.5			113.8
Total operating expenses	1,313.5			1,353.0			4,188.9			3,207.5

Operating income	399.0			345.7			1,320.4			870.3

Equity in earnings of transmission affiliate	38.3			40.0			107.7			70.4
Other income, net	7.5			11.1			72.6			40.2
Interest expense	99.1			103.2			300.1			224.4
Other expense	(53.3		)	(52.1		)	(119.8		)	(113.8		)

Income before income taxes	345.7			293.6			1,200.6			756.5
Income tax expense	128.4			110.5			455.1			296.1
Net income	217.3			183.1			745.5			460.4

Preferred stock dividends of subsidiary	0.3			0.6			0.9			1.2
Net income attributed to common shareholders	$	217.0		$	182.5		$	744.6		$	459.2

Earnings per share
Basic	$	0.69		$	0.58		$	2.36		$	1.79
Diluted	$	0.68		$	0.58		$	2.35		$	1.78

Weighted average common shares outstanding
Basic	315.6			315.7			315.6			256.2
Diluted	316.9			317.1			317.0			257.8

Dividends per share of common stock	$	0.4950		$	—		$	1.4850		$	1.2854

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



09/30/2016 Form 10-Q	3	WEC Energy Group, Inc.

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WEC ENERGY GROUP, INC.



CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)	Three Months Ended						Nine Months Ended
	September 30						September 30
(in millions)	2016			2015			2016			2015
Net income	$	217.3		$	183.1		$	745.5		$	460.4

Other comprehensive (loss) income, net of tax
Derivatives accounted for as cash flow hedges
Gains on settlement, net of tax of $7.6	—			—			—			11.4
Reclassification of gains to net income, net of tax	(0.3		)	(0.4		)	(0.9		)	(0.5		)
Cash flow hedges, net	(0.3		)	(0.4		)	(0.9		)	10.9

Defined benefit plans
Amortization of pension and OPEB credits included in net periodic benefit cost, net of tax	(0.4		)	—			—			—

Other comprehensive (loss) income, net of tax	(0.7		)	(0.4		)	(0.9		)	10.9

Comprehensive income	216.6			182.7			744.6			471.3

Preferred stock dividends of subsidiary	0.3			0.6			0.9			1.2
Comprehensive income attributed to common shareholders	$	216.3		$	182.1		$	743.7		$	470.1

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



09/30/2016 Form 10-Q	4	WEC Energy Group, Inc.

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WEC ENERGY GROUP, INC.



CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts)	September 30, 2016			December 31, 2015
Assets
Property, plant, and equipment
In service	$	26,965.3		$	26,249.5
Accumulated depreciation	(8,141.5		)	(7,919.1		)
	18,823.8			18,330.4
Construction work in progress	756.2			822.9
Leased facilities, net	32.2			36.4
Net property, plant, and equipment	19,612.2			19,189.7
Investments
Equity investment in transmission affiliate	1,453.1			1,380.9
Other	91.4			85.8
Total investments	1,544.5			1,466.7
Current assets
Cash and cash equivalents	25.0			49.8
Accounts receivable and unbilled revenues, net of reserves of $109.3 and $113.3, respectively	871.5			1,028.6
Materials, supplies, and inventories	654.3			687.0
Assets held for sale	—			96.8
Prepayments	217.4			285.8
Other	49.5			58.8
Total current assets	1,817.7			2,206.8
Deferred charges and other assets
Regulatory assets	3,004.6			3,064.6
Goodwill	3,046.2			3,023.5
Other	418.3			403.9
Total deferred charges and other assets	6,469.1			6,492.0
Total assets	$	29,443.5		$	29,355.2

Capitalization and liabilities
Capitalization
Common stock – $.01 par value; 325,000,000 shares authorized; 315,617,299 and 315,683,496 shares outstanding, respectively	$	3.2		$	3.2
Additional paid in capital	4,308.8			4,347.2
Retained earnings	4,575.8			4,299.8
Accumulated other comprehensive income	3.7			4.6
Preferred stock of subsidiary	30.4			30.4
Long-term debt	9,088.1			9,124.1
Total capitalization	18,010.0			17,809.3
Current liabilities
Current portion of long-term debt	89.4			157.7
Short-term debt	789.4			1,095.0
Accounts payable	663.5			815.4
Accrued payroll and benefits	127.8			169.7
Accrued interest	115.2			67.4
Other	240.2			403.8
Total current liabilities	2,025.5			2,709.0
Deferred credits and other liabilities
Regulatory liabilities	1,451.1			1,392.2
Deferred income taxes	5,067.0			4,622.3
Deferred revenue, net	569.5			579.4
Pension and OPEB obligations	545.1			543.1
Environmental remediation	608.3			628.2
Other	1,167.0			1,071.7
Total deferred credits and other liabilities	9,408.0			8,836.9

Commitments and contingencies (Note 16)

Total capitalization and liabilities	$	29,443.5		$	29,355.2

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



09/30/2016 Form 10-Q	5	WEC Energy Group, Inc.

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WEC ENERGY GROUP, INC.



CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Nine Months Ended
	September 30
(in millions)	2016			2015
Operating Activities
Net income	$	745.5		$	460.4
Reconciliation to cash provided by operating activities
Depreciation and amortization	581.5			390.9
Deferred income taxes and investment tax credits, net	439.5			220.1
Contributions and payments related to pension and OPEB plans	(23.5		)	(109.3		)
Equity income in transmission affiliate, net of distributions	(35.8		)	(17.8		)
Change in –
Accounts receivable and unbilled revenues	185.2			269.5
Materials, supplies, and inventories	33.8			(101.4		)
Other current assets	88.5			75.6
Accounts payable	(94.7		)	(55.9		)
Other current liabilities	(92.9		)	97.9
Other, net	(105.2		)	(155.6		)
Net cash provided by operating activities	1,721.9			1,074.4

Investing Activities
Capital expenditures	(1,000.1		)	(791.8		)
Business acquisition, net of cash acquired of $156.3	—			(1,329.9		)
Capital contributions to transmission affiliate	(27.1		)	(5.6		)
Proceeds from the sale of assets and businesses	161.2			26.7
Withdrawal of restricted cash from Rabbi trust for qualifying payments	23.8			0.7
Other, net	0.6			4.0
Net cash used in investing activities	(841.6		)	(2,095.9		)

Financing Activities
Exercise of stock options	40.4			26.4
Purchase of common stock	(105.6		)	(66.1		)
Dividends paid on common stock	(468.6		)	(310.9		)
Issuance of long-term debt	200.0			1,650.0
Retirement of long-term debt	(253.5		)	(27.1		)
Change in short-term debt	(305.6		)	(270.5		)
Other, net	(12.2		)	(20.0		)
Net cash (used in) provided by financing activities	(905.1		)	981.8

Net change in cash and cash equivalents	(24.8		)	(39.7		)
Cash and cash equivalents at beginning of period	49.8			61.9
Cash and cash equivalents at end of period	$	25.0		$	22.2

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



09/30/2016 Form 10-Q	6	WEC Energy Group, Inc.

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WEC ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

September 30, 2016

NOTE 1—GENERAL INFORMATION

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

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

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

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

Reclassifications

On the income statements for the three and nine months ended September 30, 2015, we reclassified an insignificant amount from interest expense to preferred stock dividends of subsidiary. This reclassification was made to be consistent with the current period presentation.

On the statement of cash flows for the nine months ended September 30, 2015, we reclassified an insignificant amount of preferred stock dividends of subsidiary from other financing activities to net income. This reclassification was made to be consistent with the current period presentation.

NOTE 2—ACQUISITION

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

Allocation of Purchase Price

The Integrys assets acquired and liabilities assumed were measured at estimated fair value in accordance with the accounting guidance under the Business Combinations Topic in the FASB ASC. Substantially all of Integrys's operations are subject to the rate-setting authority of federal and state regulatory commissions. These operations are accounted for following the accounting guidance under the Regulated Operations Topic of the FASB ASC. The underlying assets and liabilities of ATC are also regulated by the FERC. Integrys's assets and liabilities that are subject to rate-setting provisions provide revenues derived from costs, including a return on investment of assets less liabilities included in rate base. As such, the fair values of these assets and liabilities equal their carrying values. Accordingly, neither the assets and liabilities acquired, nor the pro forma financial information, reflect any adjustments related to these amounts.

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



09/30/2016 Form 10-Q	7	WEC Energy Group, Inc.

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



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


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

Pro Forma Information

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

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



(in millions, except per share amounts)	Nine Months Ended September 30, 2015
Unaudited Pro Forma Financial Information
Operating revenues	$	5,878.8
Net income	$	664.9
Earnings per share (Basic)	$	2.11
Earnings per share (Diluted)	$	2.10

Impact of Acquisition

In connection with the acquisition, WEC Energy Group and its subsidiaries recorded pre-tax acquisition costs of $3.5 million during the three and nine months ended September 30, 2016. Pre-tax acquisition costs of $6.1 million and $79.8 million were recorded during the three and nine months ended September 30, 2015, respectively. These costs consisted of employee-related expenses, professional fees, and other miscellaneous costs. They were recorded in other operation and maintenance on our income statements.

Our revenues for the three and nine months ended September 30, 2015 included revenues attributable to Integrys of $633.4 million. Included in our net income for the three and nine months ended September 30, 2015, is net income attributable to Integrys of $48.7 million and$22.1 million, respectively.



09/30/2016 Form 10-Q	8	WEC Energy Group, Inc.

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NOTE 3—DISPOSITIONS

Wisconsin Segment

Sale of Milwaukee County Power Plant

In April 2016, we sold the MCPP steam generation and distribution assets, located in Wauwatosa, Wisconsin. MCPP primarily provides steam to the Milwaukee Regional Medical Center hospitals and other campus buildings. During the second quarter of 2016, we recorded a pre-tax gain on the sale of $10.9 million ($6.5 million after tax), which 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 Certain Assets of Wisvest

In April 2016, as part of the MCPP sale transaction, we sold the chilled water generation and distribution assets of Wisvest, which are used to provide chilled water services to the Milwaukee Regional Medical Center hospitals and other campus buildings. During the second quarter of 2016, we recorded a pre-tax gain on the sale of $19.6 million ($11.8 million after tax), which 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 sale of ITF met the criteria to qualify as held for sale at December 31, 2015, but did not meet the requirements to qualify as a discontinued operation. The results of operations of ITF remained in continuing operations through the sale date as the sale of ITF did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results. The pre-tax profit or loss of this component was not material through the sale date in 2016.

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



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

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


*	Included in other current liabilities on our balance sheet.



09/30/2016 Form 10-Q	9	WEC Energy Group, Inc.

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NOTE 4—COMMON EQUITY

Stock-Based Compensation Plans

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



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


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


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

Restrictions

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

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

Common Stock Dividends

On October 20, 2016, our Board of Directors declared a quarterly cash dividend of $0.4950 per share, payable on December 1, 2016, to stockholders of record on November 14, 2016.

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)	September 30, 2016			December 31, 2015
Commercial paper
Amount outstanding	$	789.4		$	1,095.0
Weighted-average interest rate on amounts outstanding	0.69		%	0.68		%

Our average amount of commercial paper borrowings based on daily outstanding balances during the nine months ended September 30, 2016, was $901.8 million with a weighted-average interest rate during the period of 0.62%.



09/30/2016 Form 10-Q	10	WEC Energy Group, Inc.

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



(in millions)	Maturity	September 30, 2016
WEC Energy Group	December 2020	$	1,050.0
WE	December 2020	500.0
WPS	December 2020	250.0
WG	December 2020	350.0
PGL	December 2020	350.0
Total short-term credit capacity		$	2,500.0

Less:
Letters of credit issued inside credit facilities		$	26.0
Commercial paper outstanding		789.4

Available capacity under existing agreements		$	1,684.6

NOTE 6—LONG-TERM DEBT

On November 1, 2016, PGL issued $50.0 million of 3.65% Series CCC Bonds due December 15, 2046. The net proceeds were used to repay at maturity PGL's $50.0 million 2.21% First and Refunding Mortgage Bonds, Series XX.

In October 2016, PGL secured commitments for $150.0 million of 3.65% Series DDD Bonds Due December 15, 2046. Subject to the satisfaction of customary closing conditions, PGL expects to issue these bonds on December 15, 2016, and to use the net proceeds to repay short-term debt and for other corporate purposes.

In September 2016, WG issued $200.0 million of 3.71% Debentures due September 30, 2046. The net proceeds were used to repay short-term debt.

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

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

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

NOTE 7—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:



(in millions)	September 30, 2016		December 31, 2015
Natural gas in storage	$	298.5	$	284.1
Materials and supplies	209.3		219.2
Fossil fuel	146.5		183.7
Total	$	654.3	$	687.0

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 September 30, 2016, all LIFO layers were replenished, and the LIFO liquidation balance was zero.



09/30/2016 Form 10-Q	11	WEC Energy Group, Inc.

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

NOTE 8—FAIR VALUE MEASUREMENTS

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

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

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:



	September 30, 2016
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	5.5	$	8.6	$	—	$	14.1
FTRs	—		—		9.2		9.2
Petroleum products contracts	0.3		—		—		0.3
Coal contracts	—		1.8		—		1.8
Total derivative assets	$	5.8	$	10.4	$	9.2	$	25.4

Investments held in rabbi trust	$	47.7	$	—	$	—	$	47.7

Derivative liabilities
Natural gas contracts	$	1.3	$	1.2	$	—	$	2.5
Petroleum products contracts	1.0		—		—		1.0
Coal contracts	—		2.3		—		2.3
Total derivative liabilities	$	2.3	$	3.5	$	—	$	5.8



09/30/2016 Form 10-Q	12	WEC Energy Group, Inc.

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

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

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

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

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



	Three Months Ended September 30						Nine Months Ended September 30
(in millions)	2016			2015			2016			2015
Balance at the beginning of the period	$	13.4		$	2.3		$	3.6		$	7.0
Realized and unrealized gains (losses)	—			0.2			(0.2		)	0.2
Purchases	—			—			15.2			3.9
Sales	—			—			(0.2		)	—
Settlements	(4.2		)	(2.1		)	(9.2		)	(9.4		)
Acquisition of Integrys	—			—			—			(1.3		)
Balance at the end of the period	$	9.2		$	0.4		$	9.2		$	0.4

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

Fair Value of Financial Instruments

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



	September 30, 2016				December 31, 2015
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock	$	30.4	$	29.9	$	30.4	$	27.3
Long-term debt, including current portion *	$	9,139.9	$	10,248.4	$	9,221.9	$	9,681.0


*	The carrying amount of long-term debt excludes capital lease obligations of $37.6 million and $59.9 million at September 30, 2016, and

December 31, 2015, respectively.

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



09/30/2016 Form 10-Q	13	WEC Energy Group, Inc.

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NOTE 9—DERIVATIVE INSTRUMENTS

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

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

The following table shows our derivative assets and derivative liabilities:



	September 30, 2016				December 31, 2015
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	13.2	$	2.3	$	2.6	$	38.5
Petroleum products contracts	0.3		1.0		0.9		3.8
FTRs	9.2		—		3.6		—
Coal contracts	1.3		1.4		1.7		6.7
Total other current *	$	24.0	$	4.7	$	8.8	$	49.0

Other long-term
Natural gas contracts	$	0.9	$	0.2	$	0.5	$	3.3
Petroleum products contracts	—		—		0.3		1.1
Coal contracts	0.5		0.9		0.3		5.6
Total other long-term *	$	1.4	$	1.1	$	1.1	$	10.0
Total	$	25.4	$	5.8	$	9.9	$	59.0


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

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



	Three Months Ended September 30, 2016				Three Months Ended September 30, 2015
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	30.5 Dth	$	(3.4	)	24.2 Dth	$	(13.2	)
Petroleum products contracts	4.3 gallons	(0.4		)	2.8 gallons	(0.9		)
FTRs	9.9 MWh	7.1			8.6 MWh	3.1
Total		$	3.3			$	(11.0	)

	Nine Months Ended September 30, 2016				Nine Months Ended September 30, 2015
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	113.3 Dth	$	(56.9	)	47.5 Dth	$	(26.2	)
Petroleum products contracts	10.9 gallons	(2.5		)	4.5 gallons	(0.9		)
FTRs	24.9 MWh	11.7			20.7 MWh	6.0
Total		$	(47.7	)		$	(21.1	)

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At September 30, 2016, and December 31, 2015, we had posted cash collateral of $21.4 million and $42.3 million, respectively, in our margin accounts. These amounts were recorded on the balance sheets in other current assets.



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



	September 30, 2016						December 31, 2015
(in millions)	Derivative Assets			Derivative Liabilities			Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	25.4		$	5.8		$	9.9		$	59.0
Gross amount not offset on the balance sheet *	(3.3		)	(3.3		)	(3.0		)	(22.5		)
Net amount	$	22.1		$	2.5		$	6.9		$	36.5


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

Certain of our derivative and nonderivative commodity instruments contain provisions that could require "adequate assurance" in the event of a material change in our creditworthiness, or the posting of additional collateral for instruments in net liability positions, if triggered by a decrease in credit ratings. The aggregate fair value of all derivative instruments with specific credit risk-related contingent features that were in a liability position was $0.9 million and $23.8 million at September 30, 2016, and December 31, 2015, respectively. At September 30, 2016, and December 31, 2015, 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 September 30, 2016, and December 31, 2015, we would have been required to post collateral of $0.2 million and $18.0 million, respectively.

NOTE 10—GUARANTEES

The following table shows our outstanding guarantees:



	Total Amounts Committed at		Expiration
(in millions)	September 30, 2016		Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees
Guarantees supporting commodity transactions of subsidiaries ⁽¹⁾	$	152.0	$	73.0	$	5.0	$	74.0
Standby letters of credit ⁽²⁾	36.4		36.0		0.2		0.2
Surety bonds⁽³⁾	11.0		10.4		0.6		—
Other guarantees⁽⁴⁾	38.0		0.6		6.8		30.6
Total guarantees	$	237.4	$	120.0	$	12.6	$	104.8


⁽¹⁾	Consists of (a) $5.0 million and $10.0 million to support the business operations of WBS and PDL, respectively; and (b) $100.6 million and $36.4 million related to natural gas supply at MERC and MGU, respectively. These amounts are not reflected on our balance sheets.


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


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

⁽⁴⁾

Consists of (a) $19.1 million to support PDL's future payment obligations related to its distributed solar generation projects, of which $6.6 million is covered by a reciprocal guarantee from a third party that is not reflected on our balance sheets; (b) $10.0 million related to the sale of a nonregulated retail marketing business previously owned by Integrys, of which an insignificant liability was recorded; and (c) $8.9 million related to other indemnifications, of which a liability of $8.4 million related to workers compensation coverage was recorded.



09/30/2016 Form 10-Q	15	WEC Energy Group, Inc.

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NOTE 11—EMPLOYEE BENEFITS

The following tables show the components of net periodic pension and OPEB costs for our benefit plans. Our pension and OPEB costs for the three and nine months ended September 30, 2016, and the three months ended September 30, 2015, include costs attributable to the Integrys pension and OPEB plans. The terms and conditions of the legacy company plans have not changed materially since the acquisition.



	Pension Costs
	Three Months Ended September 30						Nine Months Ended September 30
(in millions)	2016			2015			2016			2015
Service cost	$	10.9		$	11.3		$	32.9		$	19.1
Interest cost	33.2			31.9			99.4			62.2
Expected return on plan assets	(49.0		)	(52.1		)	(147.0		)	(103.5		)
Loss on plan settlement	0.7			—			14.8			—
Amortization of prior service cost	0.9			0.7			2.6			1.7
Amortization of net actuarial loss	20.4			22.7			61.1			45.7
Net periodic benefit cost	$	17.1		$	14.5		$	63.8		$	25.2



	OPEB Costs
	Three Months Ended September 30						Nine Months Ended September 30
(in millions)	2016			2015			2016			2015
Service cost	$	6.5		$	8.0		$	19.6		$	12.7
Interest cost	9.2			9.3			27.7			17.4
Expected return on plan assets	(13.2		)	(13.9		)	(39.6		)	(25.7		)
Amortization of prior service credit	(2.3		)	(2.9		)	(7.0		)	(3.5		)
Amortization of net actuarial loss	2.2			1.5			6.4			2.5
Net periodic benefit cost	$	2.4		$	2.0		$	7.1		$	3.4

We did not make any contributions to our qualified pension plans during the first nine months of 2016. During the nine months ended September 30, 2016, we made payments of $19.9 million related to our non-qualified pension plans and $3.6 million to our OPEB plans. We expect to make payments of $3.1 million related to our non-qualified pension plans and $5.0 million related to our OPEB plans during the remainder of 2016, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

NOTE 12—GOODWILL

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



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


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


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


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

Due to the acquisition of Integrys, we changed the date of our annual goodwill impairment test from August 31 to July 1. In the third quarter of 2016, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of July 1, 2016. No impairments resulted from these tests.



09/30/2016 Form 10-Q	16	WEC Energy Group, Inc.

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NOTE 13—INVESTMENT IN AMERICAN TRANSMISSION COMPANY

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



	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2016		2015		2016				2015
Balance at beginning of period	$	1,425.0	$	987.8	$	1,380.9		⁽¹⁾	$	424.1
Add: Earnings from equity method investment	38.3		40.0		107.7				70.4
Add: Capital contributions	15.0		3.0		27.1				5.5
Add: Acquisition of Integrys's investment in ATC	—		—		(1.0		)	⁽²⁾	552.0
Add: Adjustment to equity method goodwill	—		—		10.4				—
Less: Distributions received	25.2		31.4		71.9				52.6
Less: Other	—		—		0.1				—
Balance at end of period	$	1,453.1	$	999.4	$	1,453.1			$	999.4


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


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

We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, for which we 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 September 30				Nine Months Ended September 30
(in millions)	2016		2015		2016		2015
Charges to ATC for services and construction	$	4.4	$	5.5	$	12.8	$	10.5
Charges from ATC for network transmission services	89.3		82.2		271.4		201.4

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



(in millions)	September 30, 2016		December 31, 2015
Accounts receivable
Services provided to ATC	$	1.5	$	1.0
Accounts payable
Services received from ATC	30.1		28.3

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



	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2016		2015		2016		2015
Income statement data
Revenues	$	158.1	$	164.5	$	476.6	$	482.0
Operating expenses	80.2		78.0		241.0		238.3
Other expense	23.5		23.1		71.2		71.7
Net income	$	54.4	$	63.4	$	164.4	$	172.0



09/30/2016 Form 10-Q	17	WEC Energy Group, Inc.

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(in millions)	September 30, 2016		December 31, 2015
Balance sheet data
Current assets	$	86.3	$	80.5
Noncurrent assets	4,205.7		3,948.3
Total assets	$	4,292.0	$	4,028.8

Current liabilities	$	420.7	$	330.3
Long-term debt	1,791.2		1,790.7
Other noncurrent liabilities	318.7		245.0
Shareholders' equity	1,761.4		1,662.8
Total liabilities and shareholders' equity	$	4,292.0	$	4,028.8

NOTE 14—SEGMENT INFORMATION

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


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


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


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


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


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

•

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

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



	Regulated Operations
(in millions)	Wisconsin		Illinois		Other States			Electric Transmission		Total Regulated Operations		We Power		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Three Months Ended
September 30, 2016
External revenues	$	1,470.6	$	181.8	$	49.9		$	—	$	1,702.3	$	6.2	$	4.0		$	—		$	1,712.5
Intersegment revenues	—		—		—			—		—		105.0		—			(105.0		)	—
Other operation and maintenance	498.2		105.9		21.2			—		625.3		0.4		(3.2		)	(105.0		)	517.5
Depreciation and amortization	124.5		33.5		5.2			—		163.2		17.1		11.3			—			191.6
Operating income (loss)	299.1		11.7		(1.0		)	—		309.8		93.7		(4.5		)	—			399.0
Equity in earnings of transmission affiliate	—		—		—			38.3		38.3		—		—			—			38.3
Interest expense	44.6		9.3		1.9			—		55.8		15.6		29.7			(2.0		)	99.1



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	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
September 30, 2015
External revenues	$	1,439.7	$	171.8	$	49.6		$	—	$	1,661.1	$	9.7	$	27.9		$	—		$	1,698.7
Intersegment revenues	2.6		—		—			—		2.6		101.0		—			(103.6		)	—
Other operation and maintenance	501.9		101.0		23.1			—		626.0		0.6		12.9			(103.6		)	535.9
Depreciation and amortization	117.5		31.2		4.9			—		153.6		16.9		6.1			(0.1		)	176.5
Operating income (loss)	256.6		3.5		(3.7		)	—		256.4		93.2		(3.9		)	—			345.7
Equity in earnings of transmission affiliate	—		—		—			40.0		40.0		—		—			—			40.0
Interest expense	45.9		9.7		2.6			—		58.2		15.8		31.3			(2.1		)	103.2



	Regulated Operations
(in millions)	Wisconsin		Illinois		Other States		Electric Transmission		Total Regulated Operations		We Power		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Nine Months Ended
September 30, 2016
External revenues	$	4,354.9	$	853.1	$	262.3	$	—	$	5,470.3	$	18.7	$	20.3		$	—		$	5,509.3
Intersegment revenues	0.3		—		—		—		0.3		317.1		—			(317.4		)	—
Other operation and maintenance	1,477.3		340.0		80.6		—		1,897.9		3.5		(13.0		)	(317.4		)	1,571.0
Depreciation and amortization	370.1		99.4		15.5		—		485.0		51.1		33.4			—			569.5
Operating income (loss)	841.3		171.3		33.1		—		1,045.7		281.1		(6.4		)	—			1,320.4
Equity in earnings of transmission affiliate	—		—		—		107.7		107.7		—		—			—			107.7
Interest expense	133.5		28.8		6.5		—		168.8		46.8		91.2			(6.7		)	300.1



	Regulated Operations
(in millions)	Wisconsin		Illinois		Other States			Electric Transmission		Total Regulated Operations		We Power		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Nine Months Ended
September 30, 2015
External revenues	$	3,794.7	$	171.8	$	49.6		$	—	$	4,016.1	$	30.4	$	31.3		$	—		$	4,077.8
Intersegment revenues	4.4		—		—			—		4.4		302.7		—			(307.1		)	—
Other operation and maintenance	1,239.3		101.0		23.1			—		1,363.4		3.7		93.1			(306.6		)	1,153.6
Depreciation and amortization	289.2		31.2		4.9			—		325.3		50.6		6.8			(0.1		)	382.6
Operating income (loss)	673.5		3.5		(3.7		)	—		673.3		278.9		(81.9		)	—			870.3
Equity in earnings of transmission affiliate	—		—		—			70.4		70.4		—		—			—			70.4
Interest expense	109.4		9.7		2.6			—		121.7		47.6		57.5			(2.4		)	224.4

NOTE 15—VARIABLE INTEREST ENTITIES

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



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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 13, Investment in American Transmission Company, for more information.

The significant assets and liabilities related to ATC recorded on our balance sheets included our equity investment and accounts payable. At September 30, 2016, and December 31, 2015, our equity investment was $1,453.1 million and $1,380.9 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC. In addition, we had $30.1 million and $28.3 million of accounts payable due to ATC at September 30, 2016, and December 31, 2015, respectively, for network transmission services.

Purchased Power Agreement

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

We have approximately $96.6 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 nine months ended September 30, 2016, and 2015 were $40.5 million and $40.2 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

NOTE 16—COMMITMENTS AND CONTINGENCIES

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

Energy Related Purchased Power Agreements

Our natural gas utilities have obligations to distribute and sell natural gas to their customers, and our electric utilities have obligations to distribute and sell electricity to their customers. The utilities expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of September 30, 2016, including those of our subsidiaries, were $12,048.8 million.

Environmental Matters

Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues that may potentially affect 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;



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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 CAIR. The purpose of the CSAPR was to limit the interstate transport of emissions of NOx and SO₂ that contribute to fine particulate matter and ozone nonattainment in downwind states through a proposed allocation plan and allowance trading scheme. The rule was to become effective in January 2012. However, in December 2011, the CSAPR requirements were stayed by the D.C. Circuit Court of Appeals, and CAIR was implemented during the stay period. In August 2012, the D.C. Circuit Court of Appeals issued a ruling vacating and remanding CSAPR and simultaneously reinstating CAIR pending the issuance of a replacement rule by the EPA. The case was appealed to the Supreme Court. In April 2014, the Supreme Court issued a decision largely upholding CSAPR and remanded it to the D.C. Circuit Court of Appeals for further proceedings. In October 2014, the D.C. Circuit Court of Appeals issued a decision that allowed the EPA to begin implementing CSAPR on January 1, 2015. Phase I emissions budgets applied in 2015 and also apply in 2016, while the Phase II emissions budgets discussed below will apply to 2017 and beyond.

In December 2015, the EPA published its proposed update to the CSAPR for the 2008 ozone NAAQS and issued the final rule in September 2016. Starting in 2017, this rule requires reductions in the ozone season (May 1 through September 30) NOxemissions from power plants in 23 states in the eastern United States, including Wisconsin. The EPA updated Phase II CSAPR NOxozone season budgets for electric generating units in the affected states. In the final rule, the EPA significantly increased the NOx ozone season budget from the proposed rule for Wisconsin starting in 2017. We are currently evaluating compliance options that include using our banked allowances, purchasing allowances, implementing natural gas co-firing at certain of our coal plants, and other NOx control optimizations.

Sulfur Dioxide National Ambient Air Quality Standards

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

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

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

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

8-Hour Ozone National Ambient Air Quality Standards

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



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Mercury and Other Hazardous Air Pollutants

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

We believe that the WE and WPS fleets are well positioned to comply with this regulation. Controls for acid gases and mercury are already in operation at the Pulliam units, and our compliance plans currently include capital projects for WPS's jointly owned plants to achieve the required reductions for MATS. In April 2013, WE received a one year MATS compliance extension from the MDEQ for PIPP through April 2016. The addition of a dry sorbent injection system for further control of mercury and acid gases at PIPP was placed into service in March 2016, and PIPP is now in compliance with MATS. Construction of the ReACT^TM multi-pollutant control system at Weston Unit 3 is complete and testing was completed on schedule. We are currently in compliance with both MATS and the WPS Consent Decree emission requirements.

Climate Change

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

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

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

Draft Federal Plan and Model Trading Rules were also published in October 2015 for use in developing state plans or for use in states where a plan is not submitted or approved. In December 2015, the state of Wisconsin submitted petitions for reconsideration of the EPA's final standards for existing, as well as for new, modified, and reconstructed generating units. A petition for reconsideration of the EPA's final standards for existing generating units was also submitted jointly by the Wisconsin utilities. Among other things, the petitions narrowly ask the EPA to consider revising the state goal for existing units to reflect the 2013 retirement of the Kewaunee Power Station, which could lower the state's carbon dioxideequivalent reduction goal by about 10%. In May 2016, the EPA denied the state of Wisconsin's petition for reconsideration related to new, modified, and reconstructed generating units, except that the EPA deferred the portion related to the treatment of biomass. The EPA has not issued decisions yet regarding the above referenced



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petitions for reconsideration of the final EPA standards for existing generating units. In December 2015, Michigan state agencies announced modeling results that suggest that the state will be able to meet existing source requirements until 2025, based on planned coal plant retirements, along with a continuation of state renewable standards and current levels of energy efficiency.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

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

Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities, except for Pulliam Units 7 and 8 and Weston Unit 2, satisfy the IM BTA requirements. For VAPP Units 1 and 2, projects to install fish protection screens were completed to meet the IM BTA standard. 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 Oak Creek Power Plant Units 5 through 8.

During 2016–2018, we will be completing studies and evaluating options to address the EM BTA requirements at our plants. With the exception of Pleasant Prairie Power Plant and Weston Units 3 and 4 (which all have existing cooling towers that meet EM BTA requirements) and VAPP, we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at our facilities. We also expect that limited studies to support WDNR BTA determinations will be conducted at the Weston facility. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the EM BTA requirements based on low capacity use of the unit. 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 UMERC discussion in Note 18, Regulatory Environment, regarding the potential retirement of PIPP.

Steam Electric Effluent Guidelines

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



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system would be required at PIPP if we were not expecting to retire the plant. See UMERC discussion in Note 18, Regulatory Environment, regarding the potential retirement of PIPP.

Valley Power Plant Wisconsin Pollutant Discharge Elimination System Permit

The WDNR issued a Wisconsin Pollutant Discharge Elimination System (WPDES) permit for VAPP that became effective in January 2013. The permit contains several additional requirements including effluent toxicity testing and monitoring for additional parameters (phosphorous, mercury, and ammonia-nitrogen), and a new heat addition limit from the cooling water discharges that all took effect immediately. Other long-term compliance requirements include thermal discharge studies, phosphorous evaluation and feasibility for reduction, mercury minimization planning, and the installation of new cooling water intake fish protection screens. Installation of wedge wire screens for fish protection on VAPP Units 1 and 2 cooling water intake structures have been completed. The VAPP WPDES permit is now in place and process wastewater is now being received by the Milwaukee Metropolitan Sewage District, which addresses phosphorous, mercury, and ammonia-nitrogen requirements.

Manufactured Gas Plant Remediation

We have identified sites at which our utilities or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Our natural gas utilities are responsible for the environmental remediation of these sites, some of which are in the EPA Superfund 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)	September 30, 2016		December 31, 2015
Regulatory assets	$	681.8	$	697.0
Reserves for future remediation	608.1		628.0

Enforcement and Litigation Matters

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

Consent Decrees

Wisconsin Electric Power Company Consent Decree

In April 2003, WE entered into a Consent Decree with the EPA, in which it agreed to significantly reduce air emissions from its coal-fired power plants. All of the substantive requirements from the Consent Decree have either been completed (projects) or have been transferred to the plant's Title V permits (operational limits), and the Consent Decree was terminated in August 2016.



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Wisconsin Public Service Corporation Consent Decree – Weston and Pulliam

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

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

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

Also, in May 2010, WPS received from the Sierra Club a Notice of Intent to file a civil lawsuit based on allegations that WPS violated the CAA at the Weston and Pulliam plants. WPS entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended in October 2012, but no further action has been taken by the Sierra Club as of September 30, 2016. It is unknown whether the Sierra Club will take further action in the future.

Joint Ownership Power Plants Consent Decree – Columbia and Edgewater

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

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

NOTE 17—SUPPLEMENTAL CASH FLOW INFORMATION



	Nine Months Ended September 30
(in millions)	2016			2015
Cash (paid) for interest, net of amount capitalized	$	(260.7	)	$	(150.1	)
Cash received (paid) for income taxes, net	11.7			(2.0		)
Significant non-cash transactions
Accounts payable related to construction costs	113.1			179.1
Amortization of deferred revenue	18.5			30.3

At September 30, 2016, and December 31, 2015, restricted cash of $90.2 million and $118.4 million, respectively, was recorded within other long-term assets on our balance sheets. The majority of this amount was held in the Integrys rabbi trust and represents a portion of the required funding that was triggered by the announcement of the Integrys acquisition. Withdrawals of restricted cash from the rabbi trust for qualifying payments are shown as an investing activity on the statements of cash flows. Increases and decreases in restricted cash due to the sale or purchase of restricted investments held in the rabbi trust are reflected as non-cash transactions on the statements of cash flows.



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NOTE 18—REGULATORY ENVIRONMENT

Wisconsin Public Service Corporation

2016 Wisconsin Rate Order

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

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

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

Illinois Investigations

In March 2015, the ICC opened a docket, naming PGL as respondent, to investigate the veracity of certain allegations included in anonymous letters that the ICC staff received regarding PGL's SMP. This matter is still pending.

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 what the target end date for the program should be. This proceeding is expected to result in a final order by the ICC in the first quarter of 2017. We are currently unable to determine what, if any, long-term impact there will be on PGL's SMP.

Minnesota Energy Resources Corporation

2016 Minnesota Rate Case

In September 2015, MERC initiated a rate proceeding with the MPUC. In October 2016, the MPUC issued a final written order for MERC, which is expected to be effective in the first half of 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 September 30, 2016, we estimate that $1.9 million will be refunded to MERC's customers during 2017.

Upper Michigan Energy Resources Corporation

In June 2016, we filed a proposal with the MPSC and the PSCW for approval to operate UMERC as a stand-alone utility in the Upper Peninsula of Michigan. This utility will include the electric and natural gas distribution assets of WE and WPS located in the Upper



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Peninsula. The proposal was filed pursuant to the MPSC's approval of our acquisition of Integrys, whereby we agreed to form a separate Michigan utility company. In October 2016, we reached a unanimous settlement agreement with all parties in Michigan, including the MPSC staff, the Michigan attorney general, and the Tilden Mining Company (Tilden), relating to our application to form UMERC. As part of the settlement agreement, the existing contract between WE and Tilden will remain in place until a new power generation solution for the region is commercially operational. If the settlement agreement is approved by the MPSC, we anticipate that the new utility will become operational effective January 1, 2017.

In August 2016, we entered into an agreement with Tilden under which it will purchase electric power from UMERC for 20 years. The agreement also calls for UMERC to construct and operate approximately 170 MW of natural gas generation located in the Upper Peninsula of Michigan. The estimated cost of this project is $255 million, 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 achieve commercial operation in 2019 and should allow for the retirement of PIPP by late 2019 or 2020.

NOTE 19—NEW ACCOUNTING PRONOUNCEMENTS

Revenue Recognition

In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. Several amendments were issued subsequent to the standard to clarify the guidance. The core principle of the guidance is to recognize revenue in an amount that an entity is entitled to receive in exchange for goods and services. The guidance also requires additional disclosures about the nature, amount, timing, and uncertainty of revenues and the related cash flows arising from contracts with customers. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and can either be applied retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently assessing the effects this guidance may have on our financial statements.

Classification and Measurement of Financial Instruments

In January 2016, the FASB issued ASU 2016-01, Classification and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. 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.

Stock-Based Compensation

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. Under this ASU, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement, the tax effects of exercised or vested awards are treated as discrete items in the reporting period in which they occur, and excess tax benefits are recognized in the current period regardless of whether the benefit reduces taxes payable. On the cash flow statement, excess tax benefits are classified along with other income tax cash flows as an operating activity, and cash paid by an employer when directly withholding shares for tax purposes is classified as a financing activity. We are currently assessing the effects this guidance may have on our financial statements.



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Financial Instruments Credit Losses

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

Classification of Certain Cash Receipts and Cash Payments

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



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

CORPORATE DEVELOPMENTS

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

Introduction

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

Corporate Strategy

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

Reliability

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


•	PGL is continuing to work on its 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. WPS is planning to expand the scope of this project with SMRP Phase II. If approved, SMRP Phase II will address areas of WPS's service territory where reliability is sub-standard to a lesser degree than the areas addressed in the initial phase of the SMRP.

Operating Efficiency

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

Financial Discipline

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

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


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


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



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discussed in more detail within Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.


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

Exceptional Customer Care

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

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

RESULTS OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2016

Consolidated Earnings

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



	Three Months Ended September 30
(in millions, except per share data)	2016			2015			B (W)
Wisconsin	$	299.1		$	256.6		$	42.5
Illinois	11.7			3.5			8.2
Other states	(1.0		)	(3.7		)	2.7
We Power	93.7			93.2			0.5
Corporate and other	(4.5		)	(3.9		)	(0.6		)
Total operating income	399.0			345.7			53.3
Electric transmission	38.3			40.0			(1.7		)
Other income, net	7.5			11.1			(3.6		)
Interest expense	99.1			103.2			4.1
Income before income taxes	345.7			293.6			52.1
Income tax expense	128.4			110.5			(17.9		)
Preferred stock dividends of subsidiary	0.3			0.6			0.3
Net income attributed to common shareholders	$	217.0		$	182.5		$	34.5

Diluted earnings per share	$	0.68		$	0.58		$	0.10

Earnings increased $34.5 million during the third quarter of 2016, driven by a $47.7 million pre-tax ($28.6 million after tax) increase in electric margins at the Wisconsin segment. The increase in electric margins was primarily due to higher sales volumes during the third quarter of 2016, driven by warmer weather.



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Wisconsin Segment Contribution to Operating Income



	Three Months Ended September 30
(in millions)	2016		2015		B (W)
Electric revenues	$	1,320.4	$	1,282.2	$	38.2
Fuel and purchased power	442.5		452.0		9.5
Total electric margins	877.9		830.2		47.7

Natural gas revenues	150.2		160.1		(9.9		)
Cost of natural gas sold	65.5		72.3		6.8
Total natural gas margins	84.7		87.8		(3.1		)

Other operation and maintenance	498.2		501.9		3.7
Depreciation and amortization	124.5		117.5		(7.0		)
Property and revenue taxes	40.8		42.0		1.2
Operating income	$	299.1	$	256.6	$	42.5

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



	Three Months Ended September 30
	MWh (in thousands)
Electric Sales Volumes	2016	2015	B (W)
Customer Class
Residential	3,291.0	3,044.2	246.8
Small commercial and industrial	3,592.4	3,470.8	121.6
Large commercial and industrial	3,441.7	3,357.0	84.7
Other	36.4	41.1	(4.7	)
Total retail	10,361.5	9,913.1	448.4
Wholesale	1,006.9	1,004.4	2.5
Resale	2,544.4	2,460.8	83.6
Total sales in MWh	13,912.8	13,378.3	534.5
Electric Customer Choice*	62.5	66.4	(3.9	)


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



	Three Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2016	2015	B (W)
Customer Class
Residential	54.3	59.5	(5.2	)
Commercial and industrial	54.6	53.8	0.8
Total retail	108.9	113.3	(4.4	)
Transport	260.3	245.9	14.4
Total sales in therms	369.2	359.2	10.0



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	Three Months Ended September 30
	Degree Days
Weather	2016	2015	B(W)
WE and WG ⁽¹⁾
Heating (123 normal)	27	94	(67	)
Cooling (527 normal)	781	521	260

WPS ⁽²⁾
Heating (208 normal)	79	120	(41	)
Cooling (352 normal)	426	396	30


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


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

Electric Utility Margins

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

Electric utility margins at the Wisconsin segment increased $47.7 million during the third quarter of 2016, compared with the same period in 2015. The significant factors impacting the higher electric utility margins were:


•	A $28.2 million increase related to higher sales volumes during the third quarter of 2016, driven by warmer weather. As measured by cooling degree days, the third quarter of 2016 was 49.9% and 7.6% warmer than the same period in 2015 in the Milwaukee and Green Bay areas, respectively.


•	A $12.5 million positive impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, our electric utilities defer under or over-collections of certain fuel and purchased power costs that exceed a 2% price variance from the costs included in rates, and the remaining variance impacts margins.


•	A $5.7 million increase in the third quarter of 2016 as a result of WPS's PSCW rate order, effective January 1, 2016. See Note 18, Regulatory Environment, for more information.

Natural Gas Utility Margins

Natural gas utility margins are defined as natural gas revenues less the cost of natural gas sold. We believe that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues, since prudently incurred natural gas commodity costs are passed through to our customers in current rates. The average per-unit cost of natural gas sold for our Wisconsin natural gas utilities decreased 17.7% quarter over quarter, which had no impact on margins.

Natural gas utility margins at the Wisconsin segment decreased $3.1 million during the third quarter of 2016, compared with the same period in 2015. This decrease was driven by lower residential sales volumes, including the impact of warmer weather. As measured by heating degree days, the third quarter of 2016 was 71.3% and 34.2% warmer than the same period in 2015 in the Milwaukee and Green Bay areas, respectively. The third quarter is generally not a heating period, and therefore, it historically has the lowest natural gas margins of the year.

Operating Income

Operating income at the Wisconsin segment increased $42.5 million during the third quarter of 2016, compared with the same period in 2015. This increase was driven by the $44.6 million net increase in margins discussed above, partially offset by $2.1 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes).



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The significant factors impacting the increase in operating expenses were:

•

An $18.6 million expense related to the earnings sharing mechanisms in place at WE and WG, effective January 1, 2016. Under the earnings sharing mechanisms, if either company earns above its authorized return, 50% of the first 50 basis points of additional utility earnings will be shared with customers. For WE, the additional utility earnings will be used to reduce the company's transmission escrow. For WG, the additional utility earnings will be used to reduce the costs of the Western Gas Lateral recovered from customers. All utility earnings above the first 50 basis points will be used to reduce the transmission escrow for WE and reduce the costs of the Western Gas Lateral recovered for WG. This amount is subject to change based on fourth quarter results.


•	A $7.0 million increase in depreciation and amortization, driven by an overall increase in utility plant in service. In November 2015, WG completed the Western Gas lateral project, and WE completed the conversion of the fuel source for VAPP from coal to natural gas.

These increases in operating expenses were partially offset by a $17.8 million decrease in benefit costs, primarily related to stock-based compensation.

Illinois Segment Contribution to Operating Income



	Three Months Ended September 30
(in millions)	2016		2015		B (W)
Natural gas revenues	$	181.8	$	171.8	$	10.0
Cost of natural gas sold	25.3		31.5		6.2
Total natural gas margins	156.5		140.3		16.2

Other operation and maintenance	105.9		101.0		(4.9		)
Depreciation and amortization	33.5		31.2		(2.3		)
Property and revenue taxes	5.4		4.6		(0.8		)
Operating income	$	11.7	$	3.5	$	8.2

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



	Three Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2016	2015	B (W)
Customer Class
Residential	52.9	56.2	(3.3	)
Commercial and industrial	15.1	15.2	(0.1	)
Total retail	68.0	71.4	(3.4	)
Transport	104.0	103.7	0.3
Total sales in therms	172.0	175.1	(3.1	)



	Three Months Ended September 30
	Degree Days
Weather *	2016	2015	B (W)
Heating (85 Normal)	23	66	(43	)


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



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



	Three Months Ended September 30
(in millions)	2016		2015		Change
Environmental cleanup costs	$	2.7	$	2.8	$	(0.1	)
Energy efficiency program	2.9		2.2		0.7
Bad debt rider	8.9		1.0		7.9
Total increase in margins and operating expenses	$	14.5	$	6.0	$	8.5

Natural Gas Utility Margins

We believe that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues, since prudently incurred natural gas commodity costs are passed through to our customers in current rates. The average per-unit cost of natural gas sold for our Illinois utilities decreased 18.7% quarter over quarter, which had no impact on margins.

Natural gas utility margins at the Illinois segment, net of the impact of the riders in the table above, increased $7.7 million during the third quarter of 2016. The increase was driven by a $7.3 million increase in revenue at PGL due to continued capital investment in projects under its Qualifying Infrastructure Plant rider.

Operating Income

Operating income at the Illinois segment increased $8.2 million during the third quarter of 2016. This increase was driven by the $7.7 million increase in margins discussed above.

Other States Segment Contribution to Operating Income



	Three Months Ended September 30
(in millions)	2016			2015			B (W)
Natural gas revenues	$	49.9		$	49.6		$	0.3
Cost of natural gas sold	21.1			22.3			1.2
Total natural gas margins	28.8			27.3			1.5

Other operation and maintenance	21.2			23.1			1.9
Depreciation and amortization	5.2			4.9			(0.3		)
Property and revenue taxes	3.4			3.0			(0.4		)
Operating loss	$	(1.0	)	$	(3.7	)	$	2.7

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



	Three Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2016	2015	B (W)
Customer Class
Residential	14.7	13.6	1.1
Commercial and industrial	10.1	14.0	(3.9	)
Total retail	24.8	27.6	(2.8	)
Transport	146.0	122.6	23.4
Total sales in therms	170.8	150.2	20.6



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	Three Months Ended September 30
	Degree Days
Weather *	2016	2015	B (W)
Heating (180 Normal)	83	131	(48	)


*	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.

Natural Gas Utility Margins

We believe that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues, since prudently incurred natural gas commodity costs are passed through to our customers in current rates. The average per-unit cost of natural gas sold for our other states utilities decreased 14.2% quarter over quarter, which had no impact on margins.

Operating Income

Operating income at the other states segment increased $2.7 million during the third quarter of 2016, compared to the same period last year. The increase was driven by a $1.5 million increase in margins and a $1.2 million decrease in operating expenses.

We Power Segment Contribution to Operating Income



	Three Months Ended September 30
(in millions)	2016		2015		B (W)
Operating income	$	93.7	$	93.2	$	0.5

Corporate and Other Segment Contribution to Operating Income



	Three Months Ended September 30
(in millions)	2016			2015			B (W)
Operating loss	$	(4.5	)	$	(3.9	)	$	(0.6	)

Electric Transmission Segment Operations



	Three Months Ended September 30
(in millions)	2016		2015		B (W)
Equity in earnings of transmission affiliate	$	38.3	$	40.0	$	(1.7	)

As a result of several ALJ recommendations and a recent FERC decision regarding allowed transmission ROE, we recognized lower earnings during the third quarter of 2016 from our investment in ATC as compared to the same period in 2015. See Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints below for more information on these decisions.

Consolidated Other Income, Net



	Three Months Ended September 30
(in millions)	2016		2015		B (W)
AFUDC – Equity	$	6.7	$	8.1	$	(1.4	)
Gain on asset sales	—		0.2		(0.2		)
Other, net	0.8		2.8		(2.0		)
Other income, net	$	7.5	$	11.1	$	(3.6	)



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Consolidated Interest Expense



	Three Months Ended September 30
(in millions)	2016		2015		B (W)
Interest expense	$	99.1	$	103.2	$	4.1

Interest expense decreased by $4.1 million, or 4.0%, as compared to the third quarter of 2015. The decrease was primarily driven by the repurchase and retirement of Integrys' 6.11% Junior Notes in the first quarter of 2016.

Consolidated Income Tax Expense



	Three Months Ended September 30
	2016		2015		B (W)
Effective tax rate	37.1	%	37.6	%	0.5	%

The decrease in our effective tax rate was primarily due to a tax benefit associated with acquisition related expenses previously treated as non-deductible.

NINE MONTHS ENDED SEPTEMBER 30, 2016

Consolidated Earnings

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



	Nine Months Ended September 30
(in millions, except per share data)	2016			2015			B (W)
Wisconsin	$	841.3		$	673.5		$	167.8
Illinois	171.3			3.5			167.8
Other states	33.1			(3.7		)	36.8
We Power	281.1			278.9			2.2
Corporate and other	(6.4		)	(81.9		)	75.5
Total operating income	1,320.4			870.3			450.1
Electric transmission	107.7			70.4			37.3
Other income, net	72.6			40.2			32.4
Interest expense	300.1			224.4			(75.7		)
Income before income taxes	1,200.6			756.5			444.1
Income tax expense	455.1			296.1			(159.0		)
Preferred stock dividends of subsidiary	0.9			1.2			0.3
Net income attributed to common shareholders	$	744.6		$	459.2		$	285.4

Diluted Earnings Per Share	$	2.35		$	1.78		$	0.57

Earnings increased $285.4 million during the first nine months of 2016, driven by a $263.3 million increase in earnings due to the inclusion of Integrys's results for the first six months of 2016 and higher acquisition costs incurred in 2015. Integrys was acquired on June 29, 2015.



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Wisconsin Segment Contribution to Operating Income

For the year to date periods presented in this Quarterly Report on Form 10-Q, our Wisconsin segment includes operations of WE and WG for the nine months ended September 30, 2016 and 2015, and operations of WPS for the nine months ended September 30, 2016, but only the third quarter of 2015, due to the acquisition of Integrys and its subsidiaries on June 29, 2015.



	Nine Months Ended September 30
(in millions)	2016		2015		B (W)
Electric revenues	$	3,534.8	$	2,990.6	$	544.2
Fuel and purchased power	1,121.9		1,023.8		(98.1		)
Total electric margins	2,412.9		1,966.8		446.1

Natural gas revenues	820.4		808.5		11.9
Cost of natural gas sold	422.4		467.8		45.4
Total natural gas margins	398.0		340.7		57.3

Other operation and maintenance	1,477.3		1,239.3		(238.0		)
Depreciation and amortization	370.1		289.2		(80.9		)
Property and revenue taxes	122.2		105.5		(16.7		)
Operating income	$	841.3	$	673.5	$	167.8

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



	Nine Months Ended September 30
	MWh (in thousands)
Electric Sales Volumes	2016	2015	B (W)
Customer Class
Residential	8,401.6	6,744.4	1,657.2
Small commercial and industrial	9,940.8	7,828.6	2,112.2
Large commercial and industrial	10,154.5	7,869.0	2,285.5
Other	124.0	113.9	10.1
Total retail	28,620.9	22,555.9	6,065.0
Wholesale	2,760.3	1,711.0	1,049.3
Resale	6,638.9	6,453.3	185.6
Total sales in MWh	38,020.1	30,720.2	7,299.9
Electric Customer Choice*	201.8	383.0	(181.2	)


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



	Nine Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2016	2015	B (W)
Customer Class
Residential	692.5	590.4	102.1
Commercial and industrial	426.3	361.8	64.5
Total retail	1,118.8	952.2	166.6
Transport	931.8	690.0	241.8
Total sales in therms	2,050.6	1,642.2	408.4



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	Nine Months Ended September 30
	Degree Days
Weather	2016	2015	B(W)
WE and WG ⁽¹⁾
Heating (4,413 normal)	4,058	4,684	(626	)
Cooling (685 normal)	977	620	357

WPS ⁽²⁾
Heating (4,895 normal)	4,481	N/A	N/A
Cooling (483 normal)	568	N/A	N/A


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


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

Electric Utility Margins

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

Electric utility margins at the Wisconsin segment increased $446.1 million during the nine months ended September 30, 2016, compared with the same period in 2015. The increase was primarily driven by a $386.4 million margin contribution from WPS during the first six months of 2016, compared to no margin contribution from WPS for the first six months of 2015.

The significant factors impacting the remaining $59.7 million increase in electric utility margins at the Wisconsin segment were:


•	A $31.2 million increase related to higher sales volumes during 2016, driven by warmer weather. As measured by cooling degree days, the nine months ended September 30, 2016, were 57.6% warmer than the same period in 2015 in the Milwaukee area.


•	A $10.9 million positive impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, our electric utilities defer under or over-collections of certain fuel and purchased power costs that exceed a 2% price variance from the costs included in rates, and the remaining variance impacts margins.


•	The expiration of $9.6 million of bill credits refunded to customers in 2015 related to the treasury grant WE received in connection with its biomass facility.


•	A $5.7 million increase in the third quarter of 2016 as a result of WPS's PSCW rate order, effective January 1, 2016. See Note 18, Regulatory Environment, for more information.

Natural Gas Utility Margins

We believe that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues, since prudently incurred natural gas commodity costs are passed through to our customers in current rates. The average per-unit cost of natural gas sold for our Wisconsin natural gas utilities decreased 22.9% period over period, which had no impact on margins.

Natural gas utility margins at the Wisconsin segment increased $57.3 million during the nine months ended September 30, 2016, compared with the same period in 2015. The increase was driven by a $63.6 million margin contribution from WPS during the first six months of 2016, compared to no margin contribution from WPS for the first six months of 2015.

The most significant factor impacting the offsetting $6.3 million decrease in natural gas utility margins at the Wisconsin segment was a $15.8 million decrease related to lower sales volumes during 2016, driven by warmer weather. As measured by heating degree days, the nine months ended September 30, 2016 were 13.4% warmer than the same period in 2015 in the Milwaukee area. This



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decrease was partially offset by a net positive impact of $12.6 million from WG's rate order effective January 1, 2016, as well as the impact of WPS's rate order in the third quarter of 2016. See Note 18, Regulatory Environment, for more information.

Operating Income

Operating income at the Wisconsin segment increased $167.8 million during the nine months ended September 30, 2016, compared with the same period in 2015. The increase was driven by the $503.4 million increase in margins discussed above, partially offset by $335.6 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes). Higher operating expenses were driven by $321.6 million of operating expenses from WPS during the first six months of 2016.

The significant factors impacting the remaining $14.0 million of higher operating expenses at the Wisconsin segment were:


•	A $19.9 million increase in depreciation and amortization, driven by an overall increase in utility plant in service. In November 2015, WG completed the Western Gas lateral project, and WE completed the conversion of the fuel source for VAPP from coal to natural gas.

•

These increases in operating expenses were partially offset by:


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


•	An $8.6 million decrease in benefit costs, primarily related to stock-based compensation.

Illinois Segment Contribution to Operating Income



	Nine Months Ended September 30, 2016
(in millions)	2016		2015		B (W)
Natural gas revenues	$	853.1	$	171.8	$	681.3
Cost of natural gas sold	228.8		31.5		(197.3		)
Total natural gas margins	624.3		140.3		484.0

Other operation and maintenance	340.0		101.0		(239.0		)
Depreciation and amortization	99.4		31.2		(68.2		)
Property and revenue taxes	13.6		4.6		(9.0		)
Operating income	$	171.3	$	3.5	$	167.8

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



	Therms (in millions)
	Nine Months Ended September 30, 2016
Natural Gas Sales Volumes	2016	2015	B (W)
Customer Class
Residential	623.1	56.2	566.9
Commercial and industrial	130.7	15.2	115.5
Total retail	753.8	71.4	682.4
Transport	606.6	103.7	502.9
Total sales in therms	1,360.4	175.1	1,185.3



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	Degree Days
	Nine Months Ended September 30, 2016
Weather *	2016	2015	B (W)
Heating (3,990 Normal)	3,687	66	3,621


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

Because we did not have any operations in Illinois until our acquisition of Integrys on June 29, 2015, for 2015 our Illinois segment only includes the operations of PGL and NSG for the three months ended September 30, 2015. As a result, the only meaningful variance for this segment is the quarter-over-quarter variance. Since the majority of PGL and NSG customers use natural gas for heating, operating income is sensitive to weather and is generally higher during the winter months. For a comparison of the results of the Illinois segment for the third quarter of 2016 with the third quarter of 2015, see Results of Operations – Three Months Ended September 30, 2016 above.



	Nine Months Ended September 30, 2016
(in millions)	2016		2015		Change
Environmental cleanup costs	$	18.3	$	2.8	$	15.5
Energy efficiency program	15.5		2.2		13.3
Bad debt rider	16.5		1.0		15.5
Total increase in margins and operating expenses	$	50.3	$	6.0	$	44.3

Other States Segment Contribution to Operating Income



	Nine Months Ended September 30, 2016
(in millions)	2016		2015			B (W)
Natural gas revenues	$	262.3	$	49.6		$	212.7
Cost of natural gas sold	123.1		22.3			(100.8		)
Total natural gas margins	139.2		27.3			111.9

Other operation and maintenance	80.6		23.1			(57.5		)
Depreciation and amortization	15.5		4.9			(10.6		)
Property and revenue taxes	10.0		3.0			(7.0		)
Operating income (loss)	$	33.1	$	(3.7	)	$	36.8

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



	Nine Months Ended September 30, 2016
	Therms (in millions)
Natural Gas Sales Volumes	2016	2015	B (W)
Customer Class
Residential	198.4	13.6	184.8
Commercial and industrial	125.5	14.0	111.5
Total retail	323.9	27.6	296.3
Transport	530.2	122.6	407.6
Total sales in therms	854.1	150.2	703.9



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	Nine Months Ended September 30, 2016
	Degree Days
Weather *	2016	2015	B (W)
Heating (4,656 Normal)	4,162	131	4,031


*	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.

Because we did not have any operations in this segment until our acquisition of Integrys on June 29, 2015, for 2015 our other states segment only includes the operations of MERC and MGU for the three month period ended September 30, 2015. As a result, the only meaningful variance for the other states segment is the quarter-over-quarter variance. For a comparison of the results of the other states segment for the third quarter of 2016 with the third quarter of 2015, see Results of Operations – Three Months Ended September 30, 2016 above.

We Power Segment Contribution to Operating Income



	Nine Months Ended September 30
(in millions)	2016		2015		B (W)
Operating income	$	281.1	$	278.9	$	2.2

Operating income at the We Power segment increased $2.2 million, or 0.8%, when compared to the first nine months of 2015. 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



	Nine Months Ended September 30
(in millions)	2016			2015			B (W)
Operating loss	$	(6.4	)	$	(81.9	)	$	75.5

The operating loss at the corporate and other segment decreased $75.5 million when compared to the first nine months of 2015. The decrease was driven by $78.8 million of acquisition costs incurred during the first nine months of 2015, compared with $3.5 million of acquisition costs incurred during the same period in 2016.

Electric Transmission Segment Operations



	Nine Months Ended September 30
(in millions)	2016		2015		B (W)
Equity in earnings of transmission affiliate	$	107.7	$	70.4	$	37.3

Earnings from our ownership interest in ATC increased $37.3 million when compared to the first nine months of 2015, primarily driven by the increase in our ownership interest from 26.2% to approximately 60% as a result of the acquisition of Integrys. However, as a result of several ALJ recommendations and a recent FERC decision regarding allowed transmission ROE, we recognized lower earnings during the first nine months of 2016 from our investment in ATC as compared to the same period in 2015. See Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints below for more information on these decisions.

Consolidated Other Income, Net



	Nine Months Ended September 30
(in millions)	2016		2015		B (W)
AFUDC – Equity	20.7		12.1		8.6
Gain on repurchase of notes	23.6		—		23.6
Gain on asset sales	19.6		21.0		(1.4		)
Other, net	8.7		7.1		1.6
Other income, net	$	72.6	$	40.2	$	32.4



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Other income, net increased by $32.4 million when compared to the first nine months of 2015. The increase was primarily due to the repurchase of a portion of Integrys's 6.11% Junior Notes at a discount in February 2016, as well as higher AFUDC due to the inclusion of AFUDC from the Integrys companies subsequent to the acquisition on June 29, 2015. See Note 6, Long-Term Debt, for more information on the repurchase. Partially offsetting this increase was a $19.6 million gain recorded in April 2016 from the sale of the chilled water generation and distribution assets of Wisvest, compared with a $20.8 million gain from the sale of Minergy LLC and its remaining financial assets in June 2015. See Note 3, Dispositions, for more information on our asset sales.

Consolidated Interest Expense



	Nine Months Ended September 30
(in millions)	2016		2015		B (W)
Interest expense	$	300.1	$	224.4	$	(75.7	)

Interest expense increased by $75.7 million, or 33.7%, as compared to the first nine months of 2015. The increase was primarily driven by $68.5 million of interest expense from Integrys and its subsidiaries during the first six months of 2016. Additionally, we issued $1.2 billion of long-term debt in June 2015 to finance a portion of the cash consideration for the acquisition of Integrys.

Consolidated Income Tax Expense



	Nine Months Ended September 30
	2016		2015		B (W)
Effective tax rate	37.9	%	39.1	%	1.2	%

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

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

The following table summarizes our cash flows during the nine months ended September 30:



(in millions)	2016			2015			Change in 2016 Over 2015
Cash provided by (used in)
Operating activities	$	1,721.9		$	1,074.4		$	647.5
Investing activities	(841.6		)	(2,095.9		)	1,254.3
Financing activities	(905.1		)	981.8			(1,886.9		)

Operating Activities

Net cash provided by operating activities increased $647.5 million during the nine months ended September 30, 2016. This increase was driven by $466.6 million of net cash flows from the operating activities of Integrys during the first six months of 2016, which excludes payments related to the WEC Energy Group income tax allocation agreement. See Note 2, Acquisition, for more information on the acquisition of Integrys.

The remaining $180.9 million increase in net cash provided by operating activities was primarily due to activity at the legacy Wisconsin Energy Corporation companies and was driven by:


•	A $236.7 million increase in cash from lower payments for natural gas and fuel and purchased power, due to lower commodity prices and warmer weather during the 2016 heating season.


•	An $87.2 million decrease in contributions and payments to our pension and OPEB plans. We did not make any contributions to our qualified pension plans during the nine months ended September 30, 2016, compared with contributions of $100.0 million during the same period in 2015.



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•	A $71.5 million increase in cash due to lower payments for operating and maintenance costs, driven by lower acquisition costs during the nine months ended September 30, 2016.

These increases in net cash provided by operating activities from the legacy Wisconsin Energy Corporation companies were partially offset by a $185.6 million decrease in cash related to lower overall collections from customers. Collections from customers decreased because of lower commodity prices and warmer weather during the 2016 heating season.

Investing Activities

Net cash used in investing activities decreased $1,254.3 million during the nine months ended September 30, 2016, driven by:


•	An investment of $1,329.9 million in June 2015 related to the acquisition of Integrys, which is net of cash acquired of $156.3 million. See Note 2, Acquisition, for more information.


•	A $134.5 million increase in the proceeds received from the sale of certain assets and businesses during the nine months ended September 30, 2016. See Note 3, Dispositions, for more information.

These decreases in net cash used in investing activities were partially offset by a $208.3 million increase in capital expenditures, which is discussed in more detail below.

Capital Expenditures

Capital expenditures by segment for the nine months ended September 30 were as follows:



Reportable Segment (in millions)	2016		2015		Change in 2016 Over 2015
Wisconsin	$	644.5	$	651.9	$	(7.4	)
Illinois	204.3		85.8		118.5
Other states	42.7		16.4		26.3
We Power	39.5		16.2		23.3
Corporate and other	69.1		21.5		47.6
Total capital expenditures	$	1,000.1	$	791.8	$	208.3

The decrease in cash paid for capital expenditures at the Wisconsin segment during the nine months ended September 30, 2016, was driven by lower capital expenditures for WG's Western Gas Lateral project and WE's coal to natural gas conversion project at VAPP, both of which were completed in November 2015. Also contributing to the decrease were lower payments at WE for electric distribution system upgrades. The inclusion of WPS, however, for all nine months of 2016 as compared to only the third quarter of 2015, substantially offset these lower capital expenditures. WPS's capital expenditures of $154.1 million during the first six months of 2016 related to the ReACT^TM emission control technology project at Weston Unit 3, a combustion turbine project at the Fox Energy Center, and the SMRP.

The increase in cash paid for capital expenditures at the Illinois segment during the nine months ended September 30, 2016, was due to the inclusion of PGL and NSG for all nine months of 2016 as compared to only the third quarter of 2015. PGL's and NSG's capital expenditures of $137.1 million during the first six months of 2016 primarily related to the SMP at PGL.

The increase in cash paid for capital expenditures at the other states segment during the nine months ended September 30, 2016, was due to the inclusion of MERC and MGU for all nine months of 2016 as compared to only the third quarter of 2015. MERC's and MGU's capital expenditures during the first six months of 2016 were $22.7 million.

The increase in cash paid for capital expenditures at the We Power segment during the nine months ended September 30, 2016, was driven by the fuel flexibility project at the Oak Creek Expansion units.

The increase in cash paid for capital expenditures at the corporate and other segment during the nine months ended September 30, 2016, was driven by an information technology project created to improve the billing, call center, and credit collection functions of the Integrys subsidiaries and a project to implement a new enterprise resource planning system.

See Significant Capital Projects below for more information.



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Financing Activities

Net cash related to financing activities decreased $1,886.9 million during the nine months ended September 30, 2016, driven by:


•	A $1,450.0 million decrease in the issuance of long-term debt during the nine months ended September 30, 2016. We issued $1,200.0 million of long-term debt during 2015 in connection with the acquisition of Integrys.


•	A $226.4 million increase in cash used for the retirement of long-term debt during the nine months ended September 30, 2016, primarily at Integrys and its subsidiaries. In February 2016, we repurchased a portion of Integrys's 6.11% Junior Notes at a discount.


•	A $157.7 million increase in dividends paid on common stock during the nine months ended September 30, 2016, due to the issuance of 90.2 million shares of our common stock in June 2015 as a result of the Integrys acquisition and increases to our quarterly dividend rate.


•	A $39.5 million increase in cash used to purchase shares of our common stock during the nine months ended September 30, 2016, to satisfy requirements of our stock-based benefit and compensation plans.


•	A $35.1 million increase in the repayment of commercial paper during the nine months ended September 30, 2016.

Significant Financing Activities

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

Capital Resources and Requirements

Capital Resources

Liquidity

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

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

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



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The following table shows our capitalization structure as of September 30, 2016, as well as an adjusted capitalization structure that we believe is consistent with how the rating agencies currently view our 2007 6.25% Series A Junior Subordinated Notes due 2067 (6.25% Junior Notes):



(in millions)	Actual			Adjusted
Common equity	$	8,891.5		$	9,141.5
Preferred stock of subsidiary	30.4			30.4
Long-term debt (including current portion)	9,177.5			8,927.5
Short-term debt	789.4			789.4
Total capitalization	$	18,888.8		$	18,888.8

Total debt	$	9,966.9		$	9,716.9

Ratio of debt to total capitalization	52.8		%	51.4		%

Included in long-term debt on our balance sheet as of September 30, 2016, 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. We believe this presentation is consistent with the 50% equity credit that the majority of rating agencies currently attribute to the 6.25% Junior Notes. As a result of Integrys’s repurchase and retirement of some of its 6.11% Junior Notes, we were recently informed by one rating agency that it will no longer attribute equity credit to Integrys’s remaining junior subordinated notes, consisting of $114.9 million aggregate principal amount of the 6.11% Junior Notes and $400.0 million aggregate principal amount of its 6.00% Junior Subordinated Notes due 2073. Therefore, the Integrys junior subordinated notes are no longer being adjusted in the table above. For additional information on the repurchase of the 6.11% Junior Notes, see Note 6, 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.

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

As of September 30, 2016, 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 September 30, 2016, the repurchased bonds were still outstanding but were not reported in our long-term debt since they were 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. A related bond series that had an outstanding principal amount of $67.0 million matured on August 1, 2016.

Working Capital

As of September 30, 2016, our current liabilities exceeded our current assets by approximately $207.8 million. We do not expect this to have any impact on our liquidity since we believe we have adequate back-up lines of credit in place for our ongoing operations. We also can access the capital markets to finance our construction programs and to refinance current maturities of long-term debt, if necessary.

Credit Rating Risk

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

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



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

In September 2016, Fitch Ratings made a change to certain of its rating criteria that resulted in several companies with a long-term issuer rating of A- being assigned an F2 short-term rating. As a result of this change in criteria, in October 2016, Fitch changed the ratings of both WG and PGL to F2 from F1. The ratings changes do not reflect any change in the financial condition of WG or PGL.

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

Capital Requirements

Significant Capital Projects

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



(in millions)	2016		2017		2018
Wisconsin	$	910.5	$	1,146.1	$	1,270.5
Illinois	338.3		544.8		517.7
Other states	63.9		91.0		102.7
We Power	52.0		38.4		35.0
Corporate and other	120.7		131.9		30.9
Total	$	1,485.4	$	1,952.2	$	1,956.8

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

WPS is also continuing work on the SMRP. This project includes converting more than 1,000 miles of overhead distribution power lines to underground in northern Wisconsin and adding distribution automation equipment on 400 miles of lines. WPS expects to invest approximately $45 million annually through 2018. Subject to regulatory review, Phase II of the SMRP will expand the scope and cost of the original SMRP and will consist of close to 1,000 miles of underground circuit installation. WPS expects to invest approximately $200 million between 2018 and 2021 related to Phase II.

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 qualifying infrastructure plant rider, which is in effect through 2023. PGL's projected average annual investment through 2018 is between $250 million and $280 million.

In connection with the formation of UMERC, we entered into an agreement with Tilden Mining Company under which it will purchase electric power from UMERC for 20 years. The agreement calls for UMERC to construct and operate approximately 170 MW of natural gas generation located in the Upper Peninsula of Michigan. The estimated cost of this project is $255 million. See Note 18, Regulatory Environment, for more information about UMERC and this new generation.

We expect to provide total capital contributions to ATC (not included in the above table) of approximately $328 million from 2016 through 2018.



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Common Stock Dividends

Our current quarterly dividend rate is $0.4950 per share, which equates to an annual dividend of $1.98 per share. For information related to our most recent common stock dividend declared, see Note 4, Common Equity.

Off-Balance Sheet Arrangements

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

Contractual Obligations

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

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

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

Market Risks and Other Significant Risks

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

Regulatory Recovery

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

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


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

•

Prior to 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 September 30, 2016, we had received no significant disallowances of the costs incurred for this



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

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

Environmental Matters

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

Other Matters

American Transmission Company Allowed Return on Equity Complaints

In November 2013, a group of MISO industrial customer organizations filed a complaint with the FERC requesting to reduce the base ROE used by MISO transmission owners, including ATC, to 9.15%. ATC's current authorized ROE is 12.2%. In October 2014, the FERC issued an order to hear the complaint on ROE and set a refund effective date retroactive to November 2013. The FERC conducted hearings in August 2015, and the ALJ issued an initial decision in December 2015. The ALJ's initial decision recommended that ATC and all other MISO transmission owners be authorized to collect a base ROE of 10.32%, as well as the 0.5% incentive adder approved by the FERC in January 2015 for MISO transmission owners. The 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 ALJ's initial decision. The final order requires ATC to provide refunds, with interest, for the 15-month refund period from November 13, 2013, through February 11, 2015. The refunds ATC must provide to WE and WPS for transmission costs paid during this period will reduce the regulatory assets we recorded under the PSCW-approved escrow accounting for transmission expense.

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

Regarding several of the FERC orders, the MISO transmission owners filed various appeals with the D.C. Circuit Court of Appeals as well as requests for rehearings.

These changes to ATC's ROE will result in lower equity earnings and distributions from ATC in the future. Based on the FERC's final order and the ALJ's initial decisions, we recognized lower earnings during the first nine months of 2016 from our investment in ATC as compared with the same period in 2015.



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Critical Accounting Policies and Estimates

We have reviewed our critical accounting policies and considered whether any new critical accounting estimates or other significant changes to our accounting policies require additional disclosures. We have found that the disclosures made in our 2015 Annual Report on Form 10-K are still current and that there have been no significant changes, except as follows:

Goodwill Impairment

We completed our annual goodwill impairment tests for all of our reporting units that carried a goodwill balance as of July 1, 2016. No impairments were recorded as a result of these tests. For all of our reporting units, the fair value calculated in step one of the test was greater than carrying value. The fair value of each reporting unit was calculated using a combination of the income approach and the market approach.

For the income approach, we used internal forecasts to project cash flows. Any forecast contains a degree of uncertainty, and changes in these cash flows could significantly increase or decrease the fair value of a reporting unit. Since all of our reporting units are regulated, a fair recovery of and return on costs prudently incurred to serve customers is assumed. An unfavorable outcome in a rate case could cause the fair values of our reporting units to decrease.

Key assumptions used in the income approach include ROEs, long-term growth rates used to determine terminal values at the end of the discrete forecast period, and discount rates. The discount rate is applied to estimated future cash flows and is one of the most significant assumptions used to determine fair value under the income approach. As interest rates rise, the calculated fair values will decrease. The discount rate is based on the weighted-average cost of capital for each reporting unit, taking into account

both the after-tax cost of debt and cost of equity. The terminal year ROE for each utility is driven by its current allowed ROE. The terminal growth rate is based primarily on a combination of historical and forecasted statistics for real gross domestic product and personal income for each utility service area.

For the market approach, we used an equal weighting of the guideline public company method and the guideline merged and acquired company method. The guideline public company method uses financial metrics from similar publicly traded companies to determine fair value. The guideline merged and acquired company method calculates fair value by analyzing the actual prices paid for recent mergers and acquisitions in the industry. We applied multiples derived from these two methods to the appropriate operating metrics for our reporting units to determine fair value.

The underlying assumptions and estimates used in the impairment tests were made as of a point in time. Subsequent changes in these assumptions and estimates could change the results of the tests.

The fair values of our reporting units exceeded their carrying values by a substantial amount. Based on these results, our reporting units are not at risk of failing step one of the goodwill impairment test.

Our reporting units had the following goodwill balances at July 1, 2016:



(in millions, except percentages)	Goodwill		Percentage of Total Goodwill
Wisconsin	$	2,104.3	69.1	%
Illinois	758.7		24.9	%
Other states	183.2		6.0	%
Total goodwill	$	3,046.2	100.0	%

See Note 12, Goodwill, for more information.



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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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



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ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

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



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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

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

Environmental Matters

Sheboygan River Matter

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

ITEM 1A. RISK FACTORS

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



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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



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SIGNATURE

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



		WEC ENERGY GROUP, INC.
		(Registrant)

		/s/ WILLIAM J. GUC
Date:	November 4, 2016	William J. Guc
		Vice President and Controller

		(Duly Authorized Officer and Chief Accounting Officer)



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