Edgar Filing: WEC ENERGY GROUP, INC.

Document

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, 2018



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

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

Yes [X] No [ ]

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

Yes [X] No [ ]

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



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

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

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

Yes [ ] No [X]

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

Common Stock, $.01 Par Value,

315,526,051 shares outstanding at

September 30, 2018

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WEC ENERGY GROUP, INC.

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended September 30, 2018

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
	Condensed Consolidated Statements of Equity			7
	Notes to Condensed Consolidated Financial Statements			8
			Page
	Note 1	General Information	8
	Note 2	Acquisitions	8
	Note 3	Disposition	9
	Note 4	Operating Revenues	10
	Note 5	Regulatory Assets and Liabilities	15
	Note 6	Property, Plant, and Equipment	16
	Note 7	Common Equity	17
	Note 8	Short-Term Debt and Lines of Credit	18
	Note 9	Long-Term Debt	18
	Note 10	Materials, Supplies, and Inventories	19
	Note 11	Income Taxes	19
	Note 12	Fair Value Measurements	20
	Note 13	Derivative Instruments	21
	Note 14	Guarantees	24
	Note 15	Employee Benefits	24
	Note 16	Goodwill	25
	Note 17	Investment in Transmission Affiliates	25
	Note 18	Segment Information	27
	Note 19	Variable Interest Entities	29
	Note 20	Commitments and Contingencies	30
	Note 21	Supplemental Cash Flow Information	34
	Note 22	Regulatory Environment	34
	Note 23	New Accounting Pronouncements	37
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			39
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			65
ITEM 4.	CONTROLS AND PROCEDURES			66
PART II.	OTHER INFORMATION			67
ITEM 1.	LEGAL PROCEEDINGS			67
ITEM 1A.	RISK FACTORS			67
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			68
ITEM 6.	EXHIBITS			69
SIGNATURE				70



09/30/2018 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
ATC Holdco		ATC Holdco LLC
Bishop Hill III		Bishop Hill Energy III LLC
Bluewater		Bluewater Natural Gas Holding, LLC
Bostco		Bostco LLC
Integrys		Integrys Holding, Inc.
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
WE		Wisconsin Electric Power Company
We Power		W.E. Power, LLC
WG		Wisconsin Gas LLC
WPS		Wisconsin Public Service Corporation

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

Accounting Terms
AFUDC		Allowance for Funds Used During Construction
ASU		Accounting Standards Update
FASB		Financial Accounting Standards Board
GAAP		United States Generally Accepted Accounting Principles
LIFO		Last-In, First-Out
OPEB		Other Postretirement Employee Benefits

Environmental Terms
CAA		Clean Air Act
CO₂		Carbon Dioxide
CPP		Clean Power Plan
GHG		Greenhouse Gas
NOV		Notice of Violation
WPDES		Wisconsin Pollutant Discharge Elimination System

Measurements
Dth		Dekatherm
MW		Megawatt
MWh		Megawatt-hour



09/30/2018 Form 10-Q	ii	WEC Energy Group, Inc.

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Other Terms and Abbreviations
2006 Junior Notes		Integrys's 2006 Junior Subordinated Notes Due 2066
2007 Junior Notes		WEC Energy Group, Inc.'s 2007 Junior Subordinated Notes Due 2067
ALJ		Administrative Law Judge
D.C. Circuit Court of Appeals		United States Court of Appeals for the District of Columbia Circuit
ERGS		Elm Road Generating Station
Exchange Act		Securities Exchange Act of 1934, as amended
FTRs		Financial Transmission Rights
MISO		Midcontinent Independent System Operator, Inc.
MISO Energy Markets		MISO Energy and Operating Reserves Markets
OCPP		Oak Creek Power Plant
OC 5		Oak Creek Power Plant Unit 5
OC 6		Oak Creek Power Plant Unit 6
OC 7		Oak Creek Power Plant Unit 7
OC 8		Oak Creek Power Plant Unit 8
PIPP		Presque Isle Power Plant
QIP		Qualifying Infrastructure Plant
ROE		Return on Equity
SMP		Natural Gas System Modernization Program
Supreme Court		United States Supreme Court
Tax Legislation		Tax Cuts and Jobs Act of 2017
VITA		Variable Income Tax Adjustment Rider



09/30/2018 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 rates, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, environmental matters, liquidity and capital resources, and other matters.

Forward-looking statements are subject to a number of risks and uncertainties that could cause our actual results to differ materially from those expressed or implied in the statements. These risks and uncertainties include those described in risk factors as set forth in this report and our 2017 Annual Report on Form 10-K, and those identified below:


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


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


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


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


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

•

The impact of federal, state, and local legislative and regulatory changes, including changes in rate-setting policies or procedures, 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;


•	The uncertainty surrounding the recently enacted Tax Legislation, including implementing regulations and IRS interpretations, the amount to be returned to our ratepayers, and its impact on our or our subsidiaries’ credit ratings;

•

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 regulations or permit conditions by regulatory agencies, and the recovery of associated remediation and compliance costs;


•	Factors affecting the implementation of our generation reshaping plan, including related regulatory decisions, the cost of materials, supplies, and labor, and the feasibility of competing projects;


•	Increased pressure on us by investors and other stakeholder groups to take more aggressive action to reduce future GHG emissions in order to limit future global temperature increases;

•

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;



09/30/2018 Form 10-Q	1	WEC Energy Group, Inc.

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•	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, that could prevent us from paying our common stock dividends, taxes, and other expenses, and meeting our debt obligations;


•	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 attacks and cyber security intrusions, as well as the threat of such incidents, including the failure to maintain the security of personally identifiable information, the associated costs to protect our utility assets, technology systems, and personal information, and the costs to notify affected persons to mitigate their information security concerns;


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


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


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


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


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


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


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


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


•	The ability to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act, while both integrating and continuing to consolidate our enterprise systems;


•	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.



09/30/2018 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)	2018			2017			2018			2017
Operating revenues	$	1,643.7		$	1,657.5		$	5,602.7		$	5,593.5

Operating expenses
Cost of sales	524.1			542.7			2,043.9			2,025.6
Other operation and maintenance	553.1			473.1			1,602.7			1,457.4
Depreciation and amortization	212.8			201.2			628.1			593.5
Property and revenue taxes	51.0			48.3			149.4			147.9
Total operating expenses	1,341.0			1,265.3			4,424.1			4,224.4

Operating income	302.7			392.2			1,178.6			1,369.1

Equity in earnings of transmission affiliates	33.7			39.2			95.2			122.9
Other income, net	26.1			17.8			65.0			49.2
Interest expense	112.0			103.8			327.2			310.4
Other expense	(52.2		)	(46.8		)	(167.0		)	(138.3		)

Income before income taxes	250.5			345.4			1,011.6			1,230.8
Income tax expense	17.0			129.7			156.4			458.8
Net income	233.5			215.7			855.2			772.0

Preferred stock dividends of subsidiary	0.3			0.3			0.9			0.9
Net income attributed to common shareholders	$	233.2		$	215.4		$	854.3		$	771.1

Earnings per share
Basic	$	0.74		$	0.68		$	2.71		$	2.44
Diluted	$	0.74		$	0.68		$	2.70		$	2.43

Weighted average common shares outstanding
Basic	315.5			315.6			315.5			315.6
Diluted	316.9			317.5			316.9			317.5

Dividends per share of common stock	$	0.5525		$	0.5200		$	1.6575		$	1.5600

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



09/30/2018 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)	2018			2017			2018			2017
Net income	$	233.5		$	215.7		$	855.2		$	772.0

Other comprehensive (loss) income, net of tax
Derivatives accounted for as cash flow hedges
Net derivative gains, net of tax	0.3			—			0.3			—
Reclassification of net gains to net income, net of tax	(0.4		)	(0.4		)	(1.0		)	(1.0		)
Cash flow hedges, net	(0.1		)	(0.4		)	(0.7		)	(1.0		)

Defined benefit plans
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax	—			0.3			0.2			0.5

Other comprehensive loss, net of tax	(0.1		)	(0.1		)	(0.5		)	(0.5		)

Comprehensive income	233.4			215.6			854.7			771.5

Preferred stock dividends of subsidiary	0.3			0.3			0.9			0.9
Comprehensive income attributed to common shareholders	$	233.1		$	215.3		$	853.8		$	770.6

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



09/30/2018 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, 2018		December 31, 2017
Assets
Current assets
Cash and cash equivalents	$	14.5	$	38.9
Accounts receivable and unbilled revenues, net of reserves of $153.7 and $143.2, respectively	1,017.3		1,350.7
Materials, supplies, and inventories	608.5		539.0
Prepayments	137.6		210.0
Other	61.8		74.9
Current assets	1,839.7		2,213.5

Long-term assets
Property, plant, and equipment, net of accumulated depreciation of $8,589.3 and $8,618.5, respectively	21,663.7		21,347.0
Regulatory assets	3,643.5		2,803.2
Equity investment in transmission affiliates	1,613.7		1,553.4
Goodwill	3,052.8		3,053.5
Other	749.0		619.9
Long-term assets	30,722.7		29,377.0
Total assets	$	32,562.4	$	31,590.5

Liabilities and Equity
Current liabilities
Short-term debt	$	1,788.3	$	1,444.6
Current portion of long-term debt	369.4		842.1
Accounts payable	690.4		859.9
Accrued payroll and benefits	143.1		169.1
Accrued taxes	217.4		178.5
Other	393.9		375.1
Current liabilities	3,602.5		3,869.3

Long-term liabilities
Long-term debt	9,119.0		8,746.6
Deferred income taxes	3,172.1		2,999.8
Deferred revenue, net	525.9		543.3
Regulatory liabilities	3,960.3		3,718.6
Environmental remediation liabilities	617.4		617.4
Pension and OPEB obligations	489.1		397.4
Other	1,233.4		1,206.3
Long-term liabilities	19,117.2		18,229.4

Commitments and contingencies (Note 20)

Common shareholders' equity
Common stock – $0.01 par value; 325,000,000 shares authorized; 315,526,051 and 315,574,624 shares outstanding, respectively	3.2		3.2
Additional paid in capital	4,261.6		4,278.5
Retained earnings	5,508.1		5,176.8
Accumulated other comprehensive income	2.4		2.9
Common shareholders' equity	9,775.3		9,461.4

Preferred stock of subsidiary	30.4		30.4
Noncontrolling interest in subsidiary	37.0		—
Total liabilities and equity	$	32,562.4	$	31,590.5

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



09/30/2018 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)	2018			2017
Operating Activities
Net income	$	855.2		$	772.0
Reconciliation to cash provided by operating activities
Depreciation and amortization	628.1			593.5
Deferred income taxes and investment tax credits, net	34.4			444.4
Contributions and payments related to pension and OPEB plans	(13.8		)	(115.4		)
Equity income in transmission affiliates, net of distributions	(4.5		)	(18.5		)
Change in –
Accounts receivable and unbilled revenues	312.1			310.5
Materials, supplies, and inventories	(69.0		)	(84.1		)
Other current assets	112.7			56.8
Accounts payable	(71.2		)	(111.2		)
Other current liabilities	42.5			23.4
Other, net	181.7			(125.7		)
Net cash provided by operating activities	2,008.2			1,745.7

Investing Activities
Capital expenditures	(1,490.5		)	(1,309.2		)
Acquisition of Bishop Hill III, net of restricted cash acquired of $4.5	(143.5		)	—
Acquisition of Forward Wind Energy Center	(77.1		)	—
Acquisition of Bluewater	—			(226.0		)
Capital contributions to transmission affiliates	(43.7		)	(63.3		)
Proceeds from the sale of assets and businesses	10.9			22.7
Proceeds from the sale of investments held in rabbi trust	16.6			8.6
Other, net	7.3			1.4
Net cash used in investing activities	(1,720.0		)	(1,565.8		)

Financing Activities
Exercise of stock options	13.9			25.6
Purchase of common stock	(42.0		)	(60.6		)
Dividends paid on common stock	(523.0		)	(492.4		)
Issuance of long-term debt	600.0			210.0
Retirement of long-term debt	(694.4		)	(26.9		)
Change in short-term debt	343.7			133.3
Other, net	(4.8		)	(3.1		)
Net cash used in financing activities	(306.6		)	(214.1		)

Net change in cash, cash equivalents, and restricted cash	(18.4		)	(34.2		)
Cash, cash equivalents, and restricted cash at beginning of period	58.6			72.7
Cash, cash equivalents, and restricted cash at end of period	$	40.2		$	38.5

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



09/30/2018 Form 10-Q	6	WEC Energy Group, Inc.

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WEC ENERGY GROUP, INC.



CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited)

	WEC Energy Group Common Shareholders' Equity
(in millions)	Common Stock		Additional Paid In Capital			Retained Earnings			Accumulated Other Comprehensive Income			Total Common Shareholders' Equity			Preferred Stock of Subsidiary		Non-controlling Interest in Subsidiary		Total Equity
Balance at December 31, 2017	$	3.2	$	4,278.5		$	5,176.8		$	2.9		$	9,461.4		$	30.4	$	—	$	9,491.8
Net income attributed to common shareholders	—		—			854.3			—			854.3			—		—		854.3
Other comprehensive loss	—		—			—			(0.5		)	(0.5		)	—		—		(0.5		)
Common stock dividends	—		—			(523.0		)	—			(523.0		)	—		—		(523.0		)
Exercise of stock options	—		13.9			—			—			13.9			—		—		13.9
Purchase of common stock	—		(42.0		)	—			—			(42.0		)	—		—		(42.0		)
Acquisition of a noncontrolling interest in subsidiary	—		—			—			—			—			—		37.0		37.0
Stock-based compensation and other	—		11.2			—			—			11.2			—		—		11.2
Balance at September 30, 2018	$	3.2	$	4,261.6		$	5,508.1		$	2.4		$	9,775.3		$	30.4	$	37.0	$	9,842.7



	WEC Energy Group Common Shareholders' Equity
(in millions)	Common Stock		Additional Paid In Capital			Retained Earnings			Accumulated Other Comprehensive Income			Total Common Shareholders' Equity			Preferred Stock of Subsidiary		Non-controlling Interest in Subsidiary		Total Equity
Balance at December 31, 2016	$	3.2	$	4,309.8		$	4,613.9		$	2.9		$	8,929.8		$	30.4	$	—	$	8,960.2
Net income attributed to common shareholders	—		—			771.1			—			771.1			—		—		771.1
Other comprehensive loss	—		—			—			(0.5		)	(0.5		)	—		—		(0.5		)
Common stock dividends	—		—			(492.4		)	—			(492.4		)	—		—		(492.4		)
Exercise of stock options	—		25.6			—			—			25.6			—		—		25.6
Purchase of common stock	—		(60.6		)	—			—			(60.6		)	—		—		(60.6		)
Cumulative effect adjustment from ASU 2016-09	—		—			15.7			—			15.7			—		—		15.7
Stock-based compensation and other	—		6.6			—			—			6.6			—		—		6.6
Balance at September 30, 2017	$	3.2	$	4,281.4		$	4,908.3		$	2.4		$	9,195.3		$	30.4	$	—	$	9,225.7

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



09/30/2018 Form 10-Q	7	WEC Energy Group, Inc.

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WEC ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

September 30, 2018

NOTE 1—GENERAL INFORMATION

WEC Energy Group serves approximately 1.6 million electric customers and 2.9 million natural gas customers, and owns approximately 60% of ATC.

As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, statements of comprehensive income, balance sheets, statements of cash flows, and statements of equity, 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 consolidate on our balance sheets our majority-owned subsidiaries and reflect a noncontrolling interest for the portion of an entity that we do not own as a component of consolidated equity separate from the equity attributable to our shareholders. We acquired an 80% membership interest in Bishop Hill Energy III Holdings LLC on August 31, 2018, which owns 100% of Bishop Hill III. The noncontrolling interest that we reported as equity on our balance sheets as of September 30, 2018, relates to a minority interest held by a third party. See Note 2, Acquisitions, for more information.

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, 2017. 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, 2018, are not necessarily indicative of expected results for 2018 due to seasonal variations and other factors.

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

NOTE 2—ACQUISITIONS

Acquisition of a Wind Energy Generation Facility in Illinois

On August 31, 2018, we completed the acquisition of an 80% membership interest in a commercially operational 132 MW wind generating facility located in Henry County, Illinois, known as Bishop Hill III, for $143.5 million, which is net of restricted cash acquired of $4.5 million. Bishop Hill III has a 22-year offtake agreement with an unaffiliated company for the sale of all energy produced by the facility. Under the Tax Legislation, our investment in Bishop Hill III qualifies for production tax credits and 100% bonus depreciation. Bishop Hill III is included in the non-utility energy infrastructure segment.

The table below shows the preliminary allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. The allocation is subject to change during the remainder of the measurement period, which ends one year from the acquisition date, as we obtain additional information.



(in millions)
Current assets	$	1.4
Net property, plant, and equipment	189.0
Other long-term assets *	4.5
Current liabilities	(1.6		)
Long-term liabilities	(8.3		)
Noncontrolling interest	(37.0		)
Total purchase price	$	148.0


*	Represents restricted cash.



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On October 19, 2018, we signed an agreement for the acquisition of an additional 10% membership interest in Bishop Hill III. We believe our additional investment qualifies for production tax credits and 100% bonus depreciation. The transaction is subject to FERC approval and is expected to close by the end of the year.

Acquisition of a Wind Energy Generation Facility in Nebraska

On April 30, 2018, we signed an agreement for the acquisition of an 80% membership interest in a 202.5 MW wind generating facility currently under construction known as Upstream Wind Energy Center (“Upstream”) for $276.0 million. Upstream is located in Antelope County, Nebraska and will supply energy to the Southwest Power Pool. Upstream's revenue will be substantially fixed over a 10-year period through an agreement with an unaffiliated party. Under the Tax Legislation, our investment in Upstream will qualify for production tax credits and 100% bonus depreciation. The transaction is subject to FERC approval and is expected to close in the first quarter of 2019, after Upstream achieves commercial operation. Upstream will be included in the non-utility energy infrastructure segment.

Acquisition of a Wind Energy Generation Facility in Wisconsin

On April 2, 2018, WPS, along with two unaffiliated utilities, completed the purchase of Forward Wind Energy Center, which consists of 86 wind turbines located in Wisconsin with a total capacity of 129 MW. The aggregate purchase price was $172.9 million of which WPS’s proportionate share was 44.6%, or $77.1 million. Since 2008 and up until the acquisition, WPS purchased 44.6% of the facility’s energy output under a power purchase agreement.

The table below shows the allocation of the purchase price to the assets acquired at the date of the acquisition, which are included in rate base.



(in millions)
Current assets	$	0.2
Net property, plant, and equipment	76.9
Total purchase price	$	77.1

Under a joint ownership agreement with the two other utilities, WPS is entitled to its share of generating capability and output of the facility equal to its ownership interest. WPS is also paying its ownership share of additional capital expenditures and operating expenses. Forward Wind Energy Center is included in the Wisconsin segment.

Acquisition of Natural Gas Storage Facilities in Michigan

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

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. Bluewater is included in the non-utility energy infrastructure segment.



(in millions)
Current assets	$	2.0
Net property, plant, and equipment	218.3
Goodwill	6.6
Current liabilities	(0.9		)
Total purchase price	$	226.0

NOTE 3—DISPOSITION

Corporate and Other Segment—Sale of Bostco Real Estate Holdings

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



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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.

NOTE 4—OPERATING REVENUES

Adoption of ASU 2014-09, Revenues from Contracts with Customers

On January 1, 2018, we adopted ASU 2014-09, Revenues from Contracts with Customers, and the related amendments. In accordance with the guidance, we recognize revenues when control of the promised goods or services is transferred to our customers in an amount that reflects the consideration we expect to be entitled to receive in exchange for those goods or services. These revenues include unbilled revenues, which are estimated using the amount of energy delivered to our customers but not billed until after the end of the period.

We adopted this standard using the modified retrospective method. Results for reporting periods beginning after January 1, 2018, are presented under the new standard. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Adoption of the standard did not result in an adjustment to our opening retained earnings balance as of January 1, 2018, and we do not expect the adoption of the standard to have a material impact on our net income in future periods.

We adopted the following practical expedients and optional exemptions for the implementation of this standard:


•	We elected to exclude from the transaction price any amounts collected from customers for all sales taxes and other similar taxes.


•	When applicable, we elected to apply the standard to a portfolio of contracts with similar characteristics, primarily our tariff-based contracts, as we reasonably expect that the effects on the financial statements of applying this guidance to the portfolio would not differ materially from applying this guidance to the individual contracts.


•	We elected to recognize revenue in the amount we have the right to invoice for performance obligations satisfied over time when the consideration received from a customer corresponds directly with the value provided to the customer during the same period.


•	We elected to not disclose the remaining performance obligations of a contract that has an original expected duration of one year or less.


•	We elected to apply this standard only to contracts that are not completed as of the date of initial application.

Disaggregation of Operating Revenues

The following tables present our operating revenues disaggregated by revenue source. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For our segments, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations have different expectations of service, energy and demand requirements, and are impacted by regulatory activities within their jurisdictions.



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Comparable amounts have not been presented for the three and nine months ended September 30, 2017, due to our adoption of this standard under the modified retrospective method.



(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Electric Transmission		Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations			WEC Energy Group Consolidated
Three Months Ended September 30, 2018
Electric	$	1,218.3	$	—	$	—	$	1,218.3	$	—	$	—	$	—	$	—		$	1,218.3
Natural gas	167.4		193.2		45.9		406.5		—		10.0		—		(12.7		)	403.8
Total utility revenues	1,385.7		193.2		45.9		1,624.8		—		10.0		—		(12.7		)	1,622.1
Other non-utility revenues	—		0.1		4.0		4.1		—		7.9		2.3		(0.7		)	13.6
Total revenues from contracts with customers	1,385.7		193.3		49.9		1,628.9		—		17.9		2.3		(13.4		)	1,635.7
Other operating revenues	3.0		4.6		0.3		7.9		—		97.3		0.1		(97.3		)	8.0
Total operating revenues	$	1,388.7	$	197.9	$	50.2	$	1,636.8	$	—	$	115.2	$	2.4	$	(110.7	)	$	1,643.7



(in millions)	Wisconsin		Illinois			Other States			Total Utility Operations		Electric Transmission		Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations			WEC Energy Group Consolidated
Nine Months Ended September 30, 2018
Electric	$	3,370.2	$	—		$	—		$	3,370.2	$	—	$	—	$	—	$	—		$	3,370.2
Natural gas	921.8		974.6			287.5			2,183.9		—		34.9		—		(27.9		)	2,190.9
Total utility revenues	4,292.0		974.6			287.5			5,554.1		—		34.9		—		(27.9		)	5,561.1
Other non-utility revenues	—		0.2			11.8			12.0		—		24.3		6.4		(4.5		)	38.2
Total revenues from contracts with customers	4,292.0		974.8			299.3			5,566.1		—		59.2		6.4		(32.4		)	5,599.3
Other operating revenues	11.3		(1.6		)	(6.8		)	2.9		—		291.1		0.5		(291.1		)	3.4
Total operating revenues	$	4,303.3	$	973.2		$	292.5		$	5,569.0	$	—	$	350.3	$	6.9	$	(323.5	)	$	5,602.7

Revenues from Contracts with Customers

Electric Utility Operating Revenues

The following table disaggregates electric utility operating revenues into customer class:



	Electric Utility Operating Revenues
(in millions)	Three Months Ended September 30, 2018		Nine Months Ended September 30, 2018
Residential	$	465.3	$	1,243.3
Small commercial and industrial	388.2		1,072.2
Large commercial and industrial	249.7		695.2
Other	7.5		22.4
Total retail revenues	1,110.7		3,033.1
Wholesale	62.0		175.3
Resale	40.7		139.6
Steam	2.7		16.9
Other utility revenues	2.2		5.3
Total electric utility operating revenues	$	1,218.3	$	3,370.2



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Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our Wisconsin residential and commercial and industrial customers and the majority of our Michigan residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. In our Michigan service territory, a limited number of residential and commercial and industrial customers can purchase the commodity from a third party. In this case, the delivery of the electricity represents our sole performance obligation. The rates, charges, terms, and conditions of service for sales to these customers are included in tariffs that have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month.

Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have our utilities provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. The rates, charges, terms and conditions of service for sales to wholesale customers are included in tariffs that have been approved by the FERC. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric utilities and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis.

We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales and net sales in a single hour are recorded as resale revenues. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets.

For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days. For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility's costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual current year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services.



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Natural Gas Utility Operating Revenues

The following tables disaggregate natural gas utility operating revenues into customer class:



(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Three Months Ended September 30, 2018
Residential	$	71.9	$	112.7	$	20.1	$	204.7
Commercial and industrial	35.0		29.4		12.6		77.0
Total retail revenues	106.9		142.1		32.7		281.7
Transport	13.9		43.3		4.9		62.1
Other utility revenues *	46.6		7.8		8.3		62.7
Total natural gas utility operating revenues	$	167.4	$	193.2	$	45.9	$	406.5



(in millions)	Wisconsin		Illinois		Other States			Total Natural Gas Utility Operating Revenues
Nine Months Ended September 30, 2018
Residential	$	556.7	$	609.0	$	181.2		$	1,346.9
Commercial and industrial	286.4		186.1		96.0			568.5
Total retail revenues	843.1		795.1		277.2			1,915.4
Transport	51.3		175.6		21.6			248.5
Other utility revenues *	27.4		3.9		(11.3		)	20.0
Total natural gas utility operating revenues	$	921.8	$	974.6	$	287.5		$	2,183.9


*	Includes amounts collected from (refunded to) customers for purchased gas adjustment costs.

We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under the tariffs of our regulated utilities. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In certain of our service territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer.

The transaction price of the performance obligations is valued using rates in the tariffs of our regulated utilities, which have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month.

Consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days.

Other Natural Gas Operating Revenues

We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment. Bluewater has entered into long-term service agreements for natural gas storage services with WE, WG, and WPS, and provides service to several unaffiliated customers. We recognize revenues using a time-based output method through a monthly fixed service fee.



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Other Non-Utility Operating Revenues

Other non-utility operating revenues consist primarily of the following:



(in millions)	Three Months Ended September 30, 2018		Nine Months Ended September 30, 2018
We Power revenues	$	6.4	$	19.0
Appliance service revenues	4.0		11.8
Distributed renewable solar project revenues	2.3		6.4
Wind generation revenues	0.8		0.8
Other	0.1		0.2
Total other non-utility operating revenues	$	13.6	$	38.2

As part of the construction of the We Power electric generating units, we capitalized interest during construction, which is included in property, plant, and equipment. As allowed by the PSCW, we collected these carrying costs from WE's utility customers during construction. The equity portion of these carrying costs was recorded as deferred revenue, and we continually amortize the deferred carrying costs to revenues over the life of the related lease term that We Power has with WE. During the three and nine months ended September 30, 2018, we recorded $6.4 million and $19.0 million, respectively, of revenue related to these deferred carrying costs, which were included in the contract liability balance at the beginning of the period. This contract liability is presented as deferred revenue, net on our balance sheets.

Non-utility operating revenues are also derived from servicing appliances for customers at MERC. These contracts customarily have a duration of one year or less and consist of a single performance obligation satisfied over time. We use a time-based output method to recognize revenues monthly for the service fee.

Revenues from distributed renewable solar projects consist primarily of sales of renewable energy and solar renewable energy certificates (SRECs) generated by PDL. The sale of SRECs is a distinct performance obligation as they are often sold separately from the renewable energy generated. Although the performance obligation for the sale of renewable energy is recognized over time and the performance obligation for SRECs is recognized at a point-in-time, the timing of revenue recognition is the same, as the generation of renewable energy and sales of SREC's occur concurrently.

On August 31, 2018, we completed the acquisition of an 80% membership interest in a commercially operational 132 MW wind generating facility located in Henry County, Illinois, known as Bishop Hill III. Bishop Hill III has a 22-year offtake agreement with an unaffiliated company for the sale of all energy produced by the facility. See Note 2, Acquisitions, for more information on this acquisition. We recognize revenue as energy is produced and delivered to the customer within the production month.

Other Operating Revenues

Other operating revenues consist primarily of the following:



(in millions)	Three Months Ended September 30, 2018			Nine Months Ended September 30, 2018
Alternative revenues *	$	(1.9	)	$	(32.2	)
Late payment charges	9.4			31.9
Leases	0.5			3.7
Total other operating revenues	$	8.0		$	3.4


*	Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to decoupling mechanisms and wholesale true-ups, as discussed below.



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Alternative Revenues

Alternative revenues are created from programs authorized by regulators that allow our utilities to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. Alternative revenue programs allow compensation for the effects of weather abnormalities, other external factors, or demand side management initiatives. Alternative revenue programs can also provide incentive awards if the utility achieves certain objectives and in other limited circumstances. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers.

Below is a summary of the alternative revenue programs at our utilities:


•	The rates of PGL, NSG, and MERC include decoupling mechanisms. These mechanisms differ by state and allow the utilities to recover or refund the differences between actual and authorized margins for certain customer classes.


•	MERC’s rates include a conservation improvement program rider, which includes a financial incentive for meeting energy savings goals.

•

WE and WPS provide wholesale electric service to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.

NOTE 5—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets were reflected on our balance sheets at September 30, 2018 and December 31, 2017. For more information on our regulatory assets, see Note 4, Regulatory Assets and Liabilities, in our 2017 Annual Report on Form 10-K.



(in millions)	September 30, 2018		December 31, 2017
Regulatory assets ⁽¹⁾
Unrecognized pension and OPEB costs	$	1,071.0	$	1,142.0
Plant retirements ⁽²⁾	778.4		15.1
Environmental remediation costs	680.0		676.6
System support resource	315.0		298.9
Income tax ⁽³⁾	272.0		15.7
Asset retirement obligations	224.1		192.2
Electric transmission costs ⁽⁴⁾	124.0		221.0
We Power generation	48.7		71.3
Uncollectible expense	39.3		35.1
Energy efficiency programs	15.7		24.6
Other, net	105.6		147.9
Total regulatory assets	$	3,673.8	$	2,840.4

Balance Sheet Presentation
Current assets	$	30.3	$	37.2
Regulatory assets	3,643.5		2,803.2
Total regulatory assets	$	3,673.8	$	2,840.4


⁽¹⁾	Based on prior and current rate treatment, we believe it is probable that our utilities will continue to recover from customers the regulatory assets in this table.


⁽²⁾	For information on the retirement of our older and less efficient fossil fuel generating units, see Note 6, Property, Plant, and Equipment.


⁽³⁾	For information on the flow through of tax repairs and the regulatory treatment of the Tax Legislation in our various jurisdictions, see Note 22, Regulatory Environment.


⁽⁴⁾	In May 2018, the PSCW issued an order requiring WE to use a portion of its tax benefits related to the Tax Legislation that was signed into law in December 2017 to reduce its transmission regulatory assets. See Note 22, Regulatory Environment, for more information.



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The following regulatory liabilities were reflected on our balance sheets at September 30, 2018 and December 31, 2017. For more information on our regulatory liabilities, see Note 4, Regulatory Assets and Liabilities, in our 2017 Annual Report on Form 10-K.



(in millions)	September 30, 2018		December 31, 2017
Regulatory liabilities
Income tax *	$	2,279.1	$	2,134.1
Removal costs	1,313.4		1,294.9
Mines deferral	115.4		95.1
Unrecognized pension and OPEB costs	106.5		114.2
Energy efficiency programs	30.0		21.1
Energy costs refundable through rate adjustments	25.2		42.0
Uncollectible expense	23.9		24.7
Decoupling	22.8		1.8
Earnings sharing mechanisms	20.6		2.5
Other, net	49.0		30.0
Total regulatory liabilities	$	3,985.9	$	3,760.4

Balance Sheet Presentation
Current liabilities	$	25.6	$	41.8
Regulatory liabilities	3,960.3		3,718.6
Total regulatory liabilities	$	3,985.9	$	3,760.4


*	For information on the regulatory treatment of the Tax Legislation in our various jurisdictions, see Note 22, Regulatory Environment.

NOTE 6—PROPERTY, PLANT, AND EQUIPMENT

Wisconsin Segment Plant to be Retired

We have evaluated future plans for our older and less efficient fossil fuel generating units and have either retired or announced the retirement of the plants identified below. In addition, a severance liability was recorded in other current liabilities on our balance sheets within the Wisconsin segment related to these plant retirements.



(in millions)
Severance liability at December 31, 2017	$	29.4
Severance payments	(9.5		)
Other	(3.0		)
Total severance liability at September 30, 2018	$	16.9

Pleasant Prairie Power Plant

The Pleasant Prairie power plant was retired effective April 10, 2018. The carrying value of this plant was $653.3 million at September 30, 2018. This amount included the net book value of $755.8 million, which was classified as a regulatory asset on our balance sheet. In addition, a $102.5 million cost of removal reserve related to the Pleasant Prairie power plant was classified as a regulatory liability at September 30, 2018. WE continues to amortize this regulatory asset on a straight-line basis using the composite depreciation rates approved by the PSCW before this plant was retired. Amortization is included in depreciation and amortization in the income statement. The physical dismantlement of the plant will not occur immediately. It may take several years to finalize long-term plans for the site. See Note 20, Commitments and Contingencies, for more information.

Presque Isle Power Plant

In October 2017, the MPSC approved UMERC’s application to construct and operate approximately 180 MW of natural gas-fired generation in the Upper Peninsula of Michigan. The new units are expected to begin commercial operation during the second quarter of 2019. Upon receiving the MPSC's approval, retirement of the PIPP generating units became probable. In connection with MISO's April 2018 approval of the retirement of the plant, the PIPP units will be retired on or before May 31, 2019. The carrying value of the PIPP units was $186.9 million at September 30, 2018. This amount included the net book value of $197.4 million, which was classified as plant to be retired within property, plant, and equipment on our balance sheet. In addition, a $10.5 million cost of



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removal reserve related to the PIPP units was classified as a regulatory liability at September 30, 2018. These units are included in rate base, and WE continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW. See Note 20, Commitments and Contingencies, for more information.

Pulliam Power Plant

In connection with a MISO ruling, WPS retired Pulliam Units 7 and 8 effective October 21, 2018. The carrying value of the Pulliam units was $40.8 million at September 30, 2018. This amount included the net book value of $61.1 million, which was classified as plant to be retired within property, plant, and equipment on our balance sheet. In addition, a $20.3 million cost of removal reserve related to the Pulliam units was classified as a regulatory liability at September 30, 2018. The net book value was reclassified as a regulatory asset on our balance sheet in the fourth quarter as a result of the retirement of the generating units. WPS continues to amortize this regulatory asset on a straight-line basis using the composite depreciation rates approved by the PSCW before these generating units were retired. See Note 20, Commitments and Contingencies, for more information.

Edgewater Unit 4

The Edgewater 4 generating unit was retired effective September 28, 2018. The carrying value of the generating unit was $8.3 million at September 30, 2018. This amount included the net book value of WPS's ownership share of this generating unit of $10.2 million, which was reclassified as a regulatory asset on our balance sheet in the third quarter as a result of the retirement of the generating unit. In addition, a $1.9 million cost of removal reserve related to the Edgewater 4 generating unit was classified as a regulatory liability at September 30, 2018. WPS continues to amortize this regulatory asset on a straight-line basis using the composite depreciation rates approved by the PSCW before this generating unit was retired. Amortization is included in depreciation and amortization in the income statement. See Note 20, Commitments and Contingencies, for more information.

NOTE 7—COMMON EQUITY

Stock-Based Compensation

During the first quarter of 2018, 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⁾		710,710
Restricted shares⁽²⁾		156,340
Performance units		217,560


⁽¹⁾	Stock options awarded had a weighted-average exercise price of $65.60 and a weighted-average grant date fair value of $7.71 per option.


⁽²⁾	Restricted shares awarded had a weighted-average grant date fair value of $64.20 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 UMERC and MGU, are prohibited from loaning funds to us, either directly or indirectly. See Note 9, Common Equity, in our 2017 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 18, 2018, our Board of Directors declared a quarterly cash dividend of $0.5525 per share, payable on December 1, 2018, to shareholders of record on November 14, 2018.



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NOTE 8—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, 2018			December 31, 2017
Commercial paper
Amount outstanding	$	1,788.3		$	1,444.6
Weighted-average interest rate on amounts outstanding	2.35		%	1.77		%

Our average amount of commercial paper borrowings based on daily outstanding balances during the nine months ended September 30, 2018, was $1,322.4 million with a weighted-average interest rate during the period of 2.20%.

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



(in millions)	Maturity	September 30, 2018
WEC Energy Group	October 2022	$	1,200.0
WE	October 2022	500.0
WPS	October 2022	350.0
WG	October 2022	400.0
PGL	October 2022	350.0
Total short-term credit capacity		$	2,800.0
Less:
Letters of credit issued inside credit facilities		$	3.0
Commercial paper outstanding		1,788.3
Available capacity under existing agreements		$	1,008.7

NOTE 9—LONG-TERM DEBT

WEC Energy Group, Inc.

In July 2018, we executed two interest rate swaps with a combined notional value of $250.0 million to hedge the variable interest rate risk associated with our 2007 Junior Notes. The swaps will provide a fixed interest rate of 4.9765% on $250.0 million of the $500.0 million outstanding of 2007 Junior Notes through November 15, 2021.

In June 2018, we issued $600.0 million of 3.375% Senior Notes due June 15, 2021. We used the net proceeds to repay short-term debt, including short-term debt used to redeem at par all $114.9 million outstanding principal amount of Integrys's 2006 Junior Notes, to repay all $300.0 million of our 1.65% Senior Notes that matured in June 2018, and for working capital and general corporate purposes.

Wisconsin Electric Power Company

In October 2018, WE issued $300.0 million of 4.30% Debentures due October 15, 2048, and used the net proceeds to repay short-term debt and for working capital and other corporate purposes.

In July 2018, WE redeemed all $80.0 million of its series of tax-exempt pollution control refunding bonds. From August 2009 until they were called, the bonds were not reported in our long-term debt because they were previously repurchased by WE.

In June 2018, WE's $250.0 million of 1.70% Debentures matured, and the outstanding principal was paid with proceeds received from issuing commercial paper.

Integrys Holding, Inc.

In May 2018, Integrys redeemed at par all $114.9 million outstanding of its 2006 Junior Notes.



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The Peoples Gas Light and Coke Company

In October 2018, PGL secured commitments for $150.0 million of Series FFF Bonds due November 1, 2028. PGL expects to issue the Series FFF Bonds in November 2018. The net proceeds will be used for general corporate purposes, including funding capital expenditures and the refinancing of short-term debt.

North Shore Gas Company

In October 2018, NSG secured commitments for $50.0 million of Series R Bonds due November 1, 2028. NSG expects to issue the Series R Bonds in November 2018. The net proceeds will be used for general corporate purposes, including funding capital expenditures and the refinancing of short-term debt.

NOTE 10—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:



(in millions)	September 30, 2018		December 31, 2017
Natural gas in storage	$	274.4	$	209.0
Materials and supplies	227.5		211.2
Fossil fuel	106.6		118.8
Total	$	608.5	$	539.0

PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. At September 30, 2018, all LIFO layers were replenished, and the LIFO liquidation balance was zero.

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 11—INCOME TAXES

The provision for income taxes differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following:



	Three Months Ended September 30, 2018					Nine Months Ended September 30, 2018
	Amount (in millions)			Effective Tax Rate		Amount (in millions)			Effective Tax Rate
Statutory federal income tax	$	52.6		21.0	%	$	212.3		21.0	%
State income taxes net of federal tax benefit	16.0			6.4	%	63.6			6.3	%
Tax repairs	(35.8		)	(14.3	)%	(83.9		)	(8.3	)%
Federal tax reform	(3.2		)	(1.3	)%	(17.2		)	(1.7	)%
Other	(12.6		)	(5.0	)%	(18.4		)	(1.8	)%
Total income tax expense	$	17.0		6.8	%	$	156.4		15.5	%

The effective tax rates of 6.8% and 15.5% for the three and nine months ended September 30, 2018, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to the flow through of tax repairs in connection with the Wisconsin rate settlement and the impact of the Tax Legislation, partially offset by state income taxes. The Tax Legislation, signed into law in December 2017, required our regulated utilities to remeasure their deferred income taxes and we began to amortize the resulting excess deferred income taxes beginning in 2018 in accordance with normalization requirements (see federal tax reform line above). See Note 22, Regulatory Environment, for more information about the impact of the Tax Legislation and the Wisconsin rate settlement.

On December 22, 2017, the SEC staff issued guidance in Staff Accounting Bulletin 118 (SAB 118), Income Tax Accounting Implications of the Tax Legislation, which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, certain amounts related to bonus depreciation and future tax benefit utilization recorded in the



09/30/2018 Form 10-Q	19	WEC Energy Group, Inc.

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financial statements as a result of the Tax Legislation are to be considered "provisional" as discussed in SAB 118 and subject to revision. We are awaiting additional guidance from industry and income tax authorities in order to finalize our accounting.

NOTE 12—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 between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

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

We recognize transfers between levels of the fair value hierarchy at their value as of the end of the reporting period.

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



	September 30, 2018
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	9.6	$	0.3	$	—	$	9.9
FTRs	—		—		11.5		11.5
Coal contracts	—		0.8		—		0.8
Interest rate swaps	—		0.8		—		0.8
Total derivative assets	$	9.6	$	1.9	$	11.5	$	23.0

Investments held in rabbi trust	$	115.3	$	—	$	—	$	115.3

Derivative liabilities
Natural gas contracts	$	3.6	$	1.3	$	—	$	4.9



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	December 31, 2017
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	1.8	$	3.9	$	—	$	5.7
Petroleum products contracts	1.2		—		—		1.2
FTRs	—		—		4.4		4.4
Coal contracts	—		1.1		—		1.1
Total derivative assets	$	3.0	$	5.0	$	4.4	$	12.4

Investments held in rabbi trust	$	120.7	$	—	$	—	$	120.7

Derivative liabilities
Natural gas contracts	$	7.0	$	3.8	$	—	$	10.8
Coal contracts	—		0.8		—		0.8
Total derivative liabilities	$	7.0	$	4.6	$	—	$	11.6

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 and interest rates. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy Markets.

We hold investments in the Integrys rabbi trust. These investments are restricted as they can only be withdrawn from the trust to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans. These investments are included in other long-term assets on our balance sheets. For the three months ended September 30, 2018 and 2017, the net unrealized gains included in earnings related to the investments held at the end of the period were $7.1 million and $4.4 million, respectively. For the nine months ended September 30, 2018 and 2017, the net unrealized gains included in earnings related to the investments held at the end of the period were $7.5 million and $12.2 million, respectively.

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)	2018			2017			2018			2017
Balance at the beginning of the period	$	16.7		$	11.8		$	4.4		$	5.1
Purchases	—			—			18.4			13.8
Settlements	(5.2		)	(4.5		)	(11.3		)	(11.6		)
Balance at the end of the period	$	11.5		$	7.3		$	11.5		$	7.3

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, 2018				December 31, 2017
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock of subsidiary	$	30.4	$	28.3	$	30.4	$	30.5
Long-term debt, including current portion *	9,464.2		9,762.1		9,561.7		10,341.9


*	The carrying amount of long-term debt excludes capital lease obligations of $24.2 million and $27.0 million at September 30, 2018 and December 31, 2017, respectively.

The fair values of our long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.

NOTE 13—DERIVATIVE INSTRUMENTS

We use derivatives as part of our risk management program to manage the risks associated with the price volatility of interest rates, 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.



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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.

None of our derivatives are designated as hedging instruments, with the exception of our interest rate swaps, which have been designated as cash flow hedges. The following table shows our derivative assets and derivative liabilities:



	September 30, 2018				December 31, 2017
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	9.7	$	4.5	$	5.6	$	9.4
Petroleum products contracts	—		—		1.2		—
FTRs	11.5		—		4.4		—
Coal contracts	0.4		—		0.6		0.6
Total other current *	$	21.6	$	4.5	$	11.8	$	10.0

Other long-term
Natural gas contracts	$	0.2	$	0.4	$	0.1	$	1.4
Coal contracts	0.4		—		0.5		0.2
Interest rate swaps	0.8		—		—		—
Total other long-term *	$	1.4	$	0.4	$	0.6	$	1.6
Total	$	23.0	$	4.9	$	12.4	$	11.6


*	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 derivatives not designated as hedging 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, 2018			Three Months Ended September 30, 2017
(in millions)	Volumes	Gains		Volumes	Gains (Losses)
Natural gas contracts	36.7 Dth	$	0.4	24.9 Dth	$	(2.1	)
Petroleum products contracts	1.3 gallons	0.5		4.4 gallons	(0.5		)
FTRs	7.9 MWh	7.1		9.4 MWh	4.2
Total		$	8.0		$	1.6



	Nine Months Ended September 30, 2018				Nine Months Ended September 30, 2017
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	124.7 Dth	$	(7.1	)	84.2 Dth	$	(1.1	)
Petroleum products contracts	5.1 gallons	1.3			14.2 gallons	(1.4		)
FTRs	22.9 MWh	14.7			28.0 MWh	9.4
Total		$	8.9			$	6.9

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, 2018 and December 31, 2017, we had posted cash collateral of $6.8 million and $16.2 million, respectively, in our margin accounts. These amounts were recorded on our balance sheets in other current assets. At September 30, 2018, we had also received cash collateral of $0.1 million in our margin accounts. This amount was recorded on our balance sheet in other current liabilities. We had not received any cash collateral at December 31, 2017.



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



	September 30, 2018							December 31, 2017
(in millions)	Derivative Assets				Derivative Liabilities			Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	23.0			$	4.9		$	12.4		$	11.6
Gross amount not offset on the balance sheet	(3.7		)	⁽¹⁾	(3.6		)	(4.9		)	(9.0		)	⁽²⁾
Net amount	$	19.3			$	1.3		$	7.5		$	2.6


⁽¹⁾	Includes cash collateral received of $0.1 million.


⁽²⁾	Includes cash collateral posted of $4.1 million.

Certain of our derivative and nonderivative commodity instruments contain provisions that could require "adequate assurance" in the event of a material change in our creditworthiness, or the posting of additional collateral for instruments in net liability positions, if triggered by a decrease in credit ratings. We did not have any derivative instruments with specific credit risk-related contingent features that were in a net liability position at September 30, 2018. The aggregate fair value of all derivative instruments with these features that were in a net liability position at December 31, 2017 was $3.7 million. At December 31, 2017, 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 December 31, 2017, we would have been required to post collateral of $2.7 million.

Cash Flow Hedges

In July 2018, we executed two interest rate swap agreements with a combined notional value of $250.0 million to hedge the variable interest rate risk associated with our 2007 Junior Notes. The swap agreements will provide a fixed interest rate of 4.9765% on $250.0 million of the $500.0 million of outstanding 2007 Junior Notes through November 15, 2021. As these agreements qualified for cash flow hedge accounting treatment, the related gains and losses are being deferred in accumulated other comprehensive income (OCI) and are being amortized to interest expense as interest is accrued on the 2007 Junior Notes.

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

The table below shows the amounts related to these cash flow hedges recorded in OCI and in earnings:



	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2018		2017		2018		2017
Amount of net derivative gain recognized in OCI	$	0.4	$	—	$	0.4	$	—
Amount of net derivative gain reclassified from accumulated OCI to interest expense	0.2		0.6		1.3		1.7

We estimate that during the next twelve months, $1.6 million will be reclassified from accumulated OCI as a reduction to interest expense.



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NOTE 14—GUARANTEES

The following table shows our outstanding guarantees:



			Expiration
(in millions)	Total Amounts Committed at September 30, 2018		Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees
Guarantees supporting commodity transactions of subsidiaries ⁽¹⁾	$	5.6	$	5.6	$	—	$	—
Standby letters of credit ⁽²⁾	104.2		25.5		0.2		78.5		⁽⁵⁾
Surety bonds⁽³⁾	9.2		9.1		0.1		—
Other guarantees⁽⁴⁾	12.8		0.5		0.9		11.4
Total guarantees	$	131.8	$	40.7	$	1.2	$	89.9


⁽¹⁾	Primarily to support the business operations of Bluewater.


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


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


⁽⁴⁾	Consists of $12.8 million related to other indemnifications, for which a liability of $11.4 million related to workers compensation coverage was recorded on our balance sheets.


⁽⁵⁾	Consists of standby letters of credit that automatically renew each year unless proper termination notice is given.

NOTE 15—EMPLOYEE BENEFITS

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



	Pension Costs
	Three Months Ended September 30						Nine Months Ended September 30
(in millions)	2018			2017			2018			2017
Service cost	$	11.9		$	11.1		$	35.7		$	33.2
Interest cost	28.5			30.3			85.5			91.7
Expected return on plan assets	(49.2		)	(48.8		)	(147.6		)	(146.9		)
Loss on plan settlement	0.4			2.9			1.1			8.2
Amortization of prior service cost	0.7			0.7			2.0			2.2
Amortization of net actuarial loss	23.6			21.5			70.6			64.5
Net periodic benefit cost	$	15.9		$	17.7		$	47.3		$	52.9



	OPEB Costs
	Three Months Ended September 30						Nine Months Ended September 30
(in millions)	2018			2017			2018			2017
Service cost	$	5.9		$	6.0		$	17.7		$	17.9
Interest cost	7.5			8.4			22.4			25.3
Expected return on plan assets	(14.9		)	(13.6		)	(44.6		)	(40.9		)
Amortization of prior service credit	(3.8		)	(2.8		)	(11.5		)	(8.4		)
Amortization of net actuarial loss	0.3			0.7			0.8			2.3
Net periodic benefit credit	$	(5.0	)	$	(1.3	)	$	(15.2	)	$	(3.8	)

During the nine months ended September 30, 2018, we made contributions and payments of $9.8 million related to our pension plans and $4.0 million related to our OPEB plans. We expect to make contributions and payments of $2.8 million related to our pension plans and $4.1 million related to our OPEB plans during the remainder of 2018, dependent upon various factors affecting us, including our liquidity position and the effects of the new Tax Legislation.



09/30/2018 Form 10-Q	24	WEC Energy Group, Inc.

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Effective January 1, 2018, we adopted ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, which modifies certain aspects of the accounting for employee benefit costs. Under the new guidance, only the service cost component can be included in total operating expenses. The remaining components of net periodic benefit cost (credit) are required to be presented in the income statement separately from the service cost component, outside of operating income. As required, this change was applied retrospectively to all prior periods presented. Accordingly, for the three and nine months ended September 30, 2018 and 2017, we have presented the service cost component of our retirement benefit plans in other operation and maintenance on the income statements, while presenting the non-service components in other income, net.

The following table shows the non-service credit components of net benefit costs:



	Three Months Ended September 30						Nine Months Ended September 30
(in millions)	2018			2017			2018			2017
Non-service credit components	$	(7.3	)	$	(1.4	)	$	(19.8	)	$	(4.0	)

For the three and nine months ended September 30, 2017, the net credits from the non-service components of net benefit cost (credit) were reclassified from other operation and maintenance to other income, net, on our income statements.

Under ASU 2017-07, only the service cost component of net periodic benefit cost is eligible for capitalization to property, plant, and equipment. In prior periods, a portion of all net benefit cost components was capitalized to property, plant, and equipment. As required, this amendment was applied prospectively, beginning January 1, 2018. As a result of the application of accounting principles for rate regulated entities, the non-service cost (credit) components of the net benefit cost (credit) that are no longer eligible for capitalization under this standard, but are capitalized under the regulatory framework, are presented as regulatory assets or liabilities rather than property, plant, and equipment.

NOTE 16—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, 2018:



(in millions)	Wisconsin		Illinois		Other States		Non-Utility Energy Infrastructure			Total
Goodwill balance as of January 1, 2018	$	2,104.3	$	758.7	$	183.2	$	7.3		$	3,053.5
Adjustment to Bluewater purchase price allocation ⁽¹⁾	—		—		—		(0.7		)	(0.7		)
Goodwill balance as of September 30, 2018 ⁽²⁾	$	2,104.3	$	758.7	$	183.2	$	6.6		$	3,052.8


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


⁽²⁾	We had no accumulated impairment losses related to our goodwill as of September 30, 2018.

In the third quarter of 2018, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of July 1, 2018. No impairments resulted from these tests.

NOTE 17—INVESTMENT IN TRANSMISSION AFFILIATES

We own approximately 60% of ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects. We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. The following tables provide a reconciliation of the changes in our investments in ATC and ATC Holdco:



	Three Months Ended September 30, 2018
(in millions)	ATC		ATC Holdco			Total
Balance at beginning of period	$	1,558.4	$	38.2		$	1,596.6
Add: Earnings (loss) from equity method investment	34.6		(0.9		)	33.7
Add: Capital contributions	9.1		2.2			11.3
Less: Distributions	27.8		—			27.8
Less: Other	0.1		—			0.1
Balance at end of period	$	1,574.2	$	39.5		$	1,613.7



09/30/2018 Form 10-Q	25	WEC Energy Group, Inc.

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	Three Months Ended September 30, 2017
(in millions)	ATC		ATC Holdco			Total
Balance at beginning of period	$	1,539.5	$	4.5		$	1,544.0
Add: Earnings (loss) from equity method investment	40.9		(1.7		)	39.2
Add: Capital contributions	12.1		0.7			12.8
Less: Distributions	35.2		—			35.2
Balance at end of period	$	1,557.3	$	3.5		$	1,560.8



	Nine Months Ended September 30, 2018
(in millions)	ATC			ATC Holdco			Total
Balance at beginning of period	$	1,515.8	⁽¹⁾	$	37.6		$	1,553.4
Add: Earnings (loss) from equity method investment	97.8			(2.6		)	95.2
Add: Capital contributions	39.2			4.5			43.7
Less: Distributions	78.5		⁽²⁾	—			78.5
Less: Other	0.1			—			0.1
Balance at end of period	$	1,574.2		$	39.5		$	1,613.7


⁽¹⁾	Distributions of $39.9 million, received in the first quarter of 2018, were approved and recorded as a receivable from ATC in other current assets at December 31, 2017.


⁽²⁾	Distributions of $27.7 million, received in the fourth quarter of 2018, were approved and recorded as a receivable from ATC in accounts receivable at September 30, 2018.



	Nine Months Ended September 30, 2017
(in millions)	ATC			ATC Holdco			Total
Balance at beginning of period	$	1,443.9	*	$	—		$	1,443.9
Add: Earnings (loss) from equity method investment	131.4			(8.5		)	122.9
Add: Capital contributions	51.3			12.0			63.3
Less: Distributions	69.2			—			69.2
Less: Other	0.1			—			0.1
Balance at end of period	$	1,557.3		$	3.5		$	1,560.8


*	Distributions of $35.2 million, received in the first quarter of 2017, were approved and recorded as a receivable from ATC in other current assets at December 31, 2016.

We pay ATC for network transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed 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)	2018		2017		2018		2017
Charges to ATC for services and construction	$	5.0	$	4.4	$	13.7	$	12.3
Charges from ATC for network transmission services	84.4		87.4		253.5		262.0
Refund from ATC related to a FERC audit	—		—		22.0		—
Refund from ATC per FERC ROE order	—		—		—		28.3



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



(in millions)	September 30, 2018		December 31, 2017
Accounts receivable for services provided to ATC	$	2.9	$	1.5
Dividends receivable from ATC	27.7		39.9
Accounts payable for services received from ATC	28.1		31.2

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



	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2018		2017		2018		2017
Income statement data
Operating revenues	$	170.4	$	171.1	$	501.3	$	522.4
Operating expenses	87.9		85.3		264.3		251.0
Other expense, net	27.4		27.2		80.4		78.7
Net income	$	55.1	$	58.6	$	156.6	$	192.7



(in millions)	September 30, 2018		December 31, 2017
Balance sheet data
Current assets	$	95.3	$	87.7
Noncurrent assets	4,857.6		4,598.9
Total assets	$	4,952.9	$	4,686.6

Current liabilities	$	640.6	$	767.2
Long-term debt	2,013.9		1,790.6
Other noncurrent liabilities	313.6		240.3
Shareholders' equity	1,984.8		1,888.5
Total liabilities and shareholders' equity	$	4,952.9	$	4,686.6

NOTE 18—SEGMENT INFORMATION

At September 30, 2018, we reported six segments, which are described below.


•	The Wisconsin segment includes the electric and natural gas utility operations of WE, WG, WPS, and UMERC.


•	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, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects, and our approximate 75% ownership interest in ATC Holdco, which invests in transmission-related projects outside of ATC's traditional footprint.

•

The non-utility energy infrastructure segment includes We Power, which owns and leases generating facilities to WE, Bluewater, which owns underground natural gas storage facilities in Michigan that provide approximately one-third of the current storage needs for our Wisconsin natural gas utilities, and our 80% membership interest in Bishop Hill III, a wind generating facility located in Henry County, Illinois. See Note 2, Acquisitions, for more information on Bluewater and Bishop Hill III.

•

The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the Peoples Energy, LLC holding company, Wispark LLC, Bostco, Wisvest LLC, Wisconsin Energy Capital Corporation, WEC Business Services LLC, and PDL. In the first quarter of 2017, we sold substantially all of the remaining assets of Bostco, and, in October 2018, Bostco was dissolved. See Note 3, Disposition, for more information on this sale.



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All of our operations are located within the United States. The following tables show summarized financial information related to our reportable segments for the three and nine months ended September 30, 2018 and 2017:



	Utility Operations
(in millions)	Wisconsin		Illinois		Other States			Total Utility Operations		Electric Transmission		Non-Utility Energy Infrastructure		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Three Months Ended
September 30, 2018
External revenues	$	1,388.7	$	197.9	$	50.2		$	1,636.8	$	—	$	4.5	$	2.4		$	—		$	1,643.7
Intersegment revenues	—		—		—			—		—		110.7		—			(110.7		)	—
Other operation and maintenance	525.0		104.5		23.0			652.5		—		3.0		(4.4		)	(98.0		)	553.1
Depreciation and amortization	137.2		43.0		6.4			186.6		—		19.1		7.1			—			212.8
Operating income (loss)	201.4		15.5		(5.4		)	211.5		—		91.6		(0.4		)	—			302.7
Equity in earnings of transmission affiliates	—		—		—			—		33.7		—		—			—			33.7
Interest expense	49.6		12.8		2.1			64.5		—		15.9		32.9			(1.3		)	112.0



	Utility Operations
(in millions)	Wisconsin		Illinois		Other States			Total Utility Operations		Electric Transmission		Non-Utility Energy Infrastructure		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Three Months Ended
September 30, 2017
External revenues	$	1,401.3	$	187.2	$	49.8		$	1,638.3	$	—	$	13.6	$	5.6		$	—		$	1,657.5
Intersegment revenues	—		—		—			—		—		111.6		—			(111.6		)	—
Other operation and maintenance *	460.5		99.0		21.5			581.0		—		1.5		(0.4		)	(109.0		)	473.1
Depreciation and amortization	131.5		38.9		6.3			176.7		—		18.2		6.3			—			201.2
Operating income (loss) *	277.5		14.3		(3.0		)	288.8		—		103.4		—			—			392.2
Equity in earnings of transmission affiliates	—		—		—			—		39.2		—		—			—			39.2
Interest expense	48.5		11.0		2.3			61.8		—		16.2		25.4			0.4			103.8


*	Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 15, Employee Benefits, for more information on this new standard.



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	Utility Operations
(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Electric Transmission		Non-Utility Energy Infrastructure		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Nine Months Ended
September 30, 2018
External revenues	$	4,303.3	$	973.2	$	292.5	$	5,569.0	$	—	$	26.8	$	6.9		$	—		$	5,602.7
Intersegment revenues	—		—		—		—		—		323.5		—			(323.5		)	—
Other operation and maintenance	1,495.9		320.8		74.5		1,891.2		—		9.2		(2.5		)	(295.2		)	1,602.7
Depreciation and amortization	406.9		125.7		17.5		550.1		—		55.7		22.3			—			628.1
Operating income (loss)	670.2		204.8		38.9		913.9		—		277.0		(12.3		)	—			1,178.6
Equity in earnings of transmission affiliates	—		—		—		—		95.2		—		—			—			95.2
Interest expense	147.5		37.4		6.3		191.2		—		48.0		91.2			(3.2		)	327.2



	Utility Operations
(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Electric Transmission		Non-Utility Energy Infrastructure		Corporate and Other			Reconciling Eliminations			WEC Energy Group Consolidated
Nine Months Ended
September 30, 2017
External revenues	$	4,316.6	$	965.7	$	273.4	$	5,555.7	$	—	$	26.1	$	11.7		$	—		$	5,593.5
Intersegment revenues	—		—		—		—		—		333.2		—			(333.2		)	—
Other operation and maintenance *	1,385.9		321.0		73.0		1,779.9		—		4.6		3.5			(330.6		)	1,457.4
Depreciation and amortization	391.1		112.6		18.4		522.1		—		53.1		18.3			—			593.5
Operating income (loss) *	829.6		214.9		35.2		1,079.7		—		299.5		(10.1		)	—			1,369.1
Equity in earnings of transmission affiliates	—		—		—		—		122.9		—		—			—			122.9
Interest expense	145.4		33.0		6.5		184.9		—		46.7		81.3			(2.5		)	310.4


*	Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 15, Employee Benefits, for more information on this new standard.

NOTE 19—VARIABLE INTEREST ENTITIES

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

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

Investment in Transmission Affiliates

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



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impact ATC's economic performance. Therefore, we account for ATC as an equity method investment. The significant assets and liabilities related to ATC recorded on our balance sheets were our equity investment, distributions receivable, and accounts payable. At September 30, 2018 and December 31, 2017, our equity investment was $1,574.2 million and $1,515.8 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC. In addition, we had receivables of $27.7 million and $39.9 million recorded at September 30, 2018 and December 31, 2017, respectively, for distributions from ATC. We also had $28.1 million and $31.2 million of accounts payable due to ATC at September 30, 2018 and December 31, 2017, respectively, for network transmission services.

We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. We have determined that ATC Holdco is a variable interest entity but that consolidation is not required since we are not ATC Holdco'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 Holdco's economic performance. Therefore, we account for ATC Holdco as an equity method investment. The only significant asset or liability related to ATC Holdco recorded on our balance sheets was our equity investment of $39.5 million and $37.6 million at September 30, 2018 and December 31, 2017, respectively. Our equity investment approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.

See Note 17, Investment in Transmission Affiliates, for more information.

Purchased Power Agreement

We have 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 four 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 $60.4 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under this contract for the nine months ended September 30, 2018 and 2017 were $14.1 million and $13.5 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

NOTE 20—COMMITMENTS AND CONTINGENCIES

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

Unconditional Purchase Obligations

Our electric utilities have obligations to distribute and sell electricity to their customers, and our natural gas utilities have obligations to distribute and sell natural gas to their customers. The utilities expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of September 30, 2018, including those of our subsidiaries, were $12,034.4 million.

Environmental Matters

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



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Air Quality

8-Hour Ozone National Ambient Air Quality Standards

After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, which lowered the limit for ground-level ozone, creating a more stringent standard than the 2008 National Ambient Air Quality Standards. The EPA issued final nonattainment area designations on May 1, 2018. The following counties within our service territories were designated as partial nonattainment: Door, Kenosha, Manitowoc, Northern Milwaukee/Ozaukee, and Sheboygan shorelines. The state of Wisconsin will need to develop a state implementation plan to bring these areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020. We believe we are well positioned to meet the requirements associated with the ozone standard and do not expect to incur significant costs to comply.

Climate Change

In 2015, the EPA issued a final rule regulating GHG emissions from existing generating units, referred to as the Clean Power Plan, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In February 2016, the Supreme Court stayed the effectiveness of the CPP until disposition of certain litigation in the D.C. Circuit Court of Appeals challenging the rule and, to the extent that further appellate review is sought, at the Supreme Court. In April 2017, pursuant to motions made by the EPA, the D.C. Circuit Court of Appeals ordered the challenges to the CPP, as well as related performance standards for new, reconstructed, and modified fossil-fueled power plants, to be held in abeyance, which remains the case.

In December 2017, the EPA issued an advanced notice of proposed rulemaking to solicit input on whether it is appropriate to replace the CPP. Then, in August 2018, the EPA issued a proposed replacement rule for the CPP, the Affordable Clean Energy (ACE) rule. The proposed ACE rule would require the EPA to develop emission guidelines for states to use to develop their individual state plans. The state plans would focus on reducing GHG emissions by improving the efficiency of fossil-fueled power plants. The type of power plants most likely affected by this rule would be coal-fueled electric generating units. The EPA is also considering revisions to new source review (NSR) permitting as part of this rulemaking that could allow certain power plant efficiency improvement projects to be implemented without triggering NSR permitting requirements. We submitted comments on the ACE rule by the October 31, 2018 due date.

We continue to evaluate opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute towards long-term GHG reductions. Our plan is to work with our industry partners, environmental groups, and the State of Wisconsin, with goals of reducing CO₂ emissions by approximately 40% and 80% below 2005 levels by 2030 and 2050, respectively. We have implemented and continue to evaluate numerous options in order to meet our CO₂ reduction goals. As a result of our generation reshaping plan, we expect to retire 1,800 MW of coal generation by 2020, including PIPP, which we are required to retire by May 31, 2019, and Pleasant Prairie power plant, Pulliam power plant, and the jointly-owned Edgewater Unit 4 generation units, all of which have been retired. See Note 6, Property, Plant, and Equipment, for more information. In addition, we are evaluating our goals, and possible subsequent actions, with respect to national and international efforts to reduce future GHG emissions in order to limit future global temperature increases to less than two degrees Celsius.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

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

Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities, except for Pulliam Units 7 and 8 and Weston Unit 2, satisfy the IM BTA requirements. WPS retired Pulliam Units 7 and 8 effective October 21, 2018. See Note 6, Property, Plant, and Equipment, for more information on the retirement of the Pulliam



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generating units. Therefore, WPS will not be required to make alterations to the existing water intake at Pulliam Units 7 and 8. Based on the reissued WPDES permit for Weston, 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 the Valley power plant. There has also been an interim EM BTA determination made by the WDNR as part of the reissued WPDES permit for Weston Units 3 and 4, and we intend to extrapolate these results to assess Weston Unit 2. The entrainment study and other technical information will be used by the WDNR to make a final 316(b) determination during the next five year WPDES permit term. At this time, we expect that the WDNR will conclude that the existing cooling tower systems for Weston Units 3 and 4 are BTA for both impingement and entrainment reduction. In addition, the WDNR has initially indicated that based on the low capacity utilization of Weston Unit 2, impingement mortality reduction technology will not be required and further entrainment reduction will not be necessary. Due to the retirements of Pleasant Prairie power plant and Pulliam Units 7 and 8 and our plans to retire PIPP, we do not believe that BTA determinations for EM will be necessary for these units. Although we currently believe that existing technologies at Port Washington Generating Station and OC 5 through OC 8 satisfy the EM BTA requirements, BTA determinations to address EM reduction requirements will not be made until discharge permits are renewed for these units. Until that time, we cannot determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements for these units. During 2018, we will continue to evaluate options to address the EM BTA requirements for these units.

We have also provided information to the WDNR and the MDEQ about planned unit retirements. Based on discussions with the MDEQ, if we submit a signed certification stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2023), the EM BTA requirements will be waived. We expect to submit the letter identifying the last operating date for PIPP to the MDEQ no later than early 2019, ahead of when the agency begins processing our pending application for the National Pollutant Discharge Elimination System permit reissuance. In light of the retirement of Pulliam Units 7 and 8, we will not be required to submit additional 316(b) information.

As a result of past capital investments completed to address 316(b) compliance at WE and WPS, we believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation.

Steam Electric Effluent Limitation Guidelines

The EPA's final steam electric effluent limitation guidelines (ELG) rule took effect in January 2016. This rule created new requirements for several types of power plant wastewaters. The two new requirements that affect WE and WPS relate to discharge limits for bottom ash transport water (BATW) and wet flue gas desulfurization (FGD) wastewater. Various petitions challenging the rule were consolidated and are pending in the United States Court of Appeals for the Fifth Circuit. In April 2017, the EPA issued an administrative stay of certain compliance deadlines while further reviewing the rule. In September 2017, the EPA issued a final rule (Postponement Rule) to postpone the earliest compliance date to November 1, 2020 for the BATW and wet FGD wastewater requirements. The latest ELG rule compliance date remains December 31, 2023 for any new wastewater treatment requirements contained in power plant discharge permits. This rule applies to wastewater discharges from our power plant processes in Wisconsin. Litigation over various aspects of the final ELG rule and the Postponement Rule is pending in several Federal Courts.

Due to pending generating unit retirements, the only facilities that will require bottom ash system modifications are Weston Unit 3 and Oak Creek Units 7 and 8. One wastewater treatment system modification may be required for the wet FGD discharges from the six units that make up the OCPP and ERGS.

As a result of past capital investments completed to address ELG compliance at WE and WPS, we believe our fleet overall is well positioned to meet this new regulation. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, as currently constructed, the ELG rule will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use.

The final rule would phase in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. New requirements for wet scrubber wastewater treatment would require additional zero liquid discharge or other advanced treatment capital improvements for the OCPP and ERGS. The rule also would require dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are required by the new rule, and modifications would be required at OC 7, OC 8, and Weston Unit 3. We are beginning preliminary engineering for compliance with the rule and estimate approximately $70 million would be required to design and install these advanced treatment



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and bottom ash transport systems. This estimate reflects the retirements of certain of our generation plants as a result of our generation reshaping plan discussed in Climate Change above.

Land Quality

Manufactured Gas Plant Remediation

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

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

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

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



(in millions)	September 30, 2018		December 31, 2017
Regulatory assets	$	680.0	$	676.6
Reserves for future remediation	617.4		617.2

Consent Decrees

Wisconsin Public Service Corporation Consent Decree – Weston and Pulliam Power Plants

In November 2009, the EPA issued an 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. WPS retired Pulliam Units 7 and 8 effective October 21, 2018. See Note 6, Property, Plant, and Equipment, for more information about the retirement.

Joint Ownership Power Plants Consent Decree – Columbia and Edgewater

In December 2009, the EPA issued an 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. As a result of the continued implementation of the Consent Decree related to the jointly owned Columbia and Edgewater plants, the Edgewater 4 generating unit was retired effective September 28, 2018. See Note 6, Property, Plant, and Equipment, for more information about the retirement.

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



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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.

NOTE 21—SUPPLEMENTAL CASH FLOW INFORMATION



	Nine Months Ended September 30
(in millions)	2018			2017
Cash (paid) for interest, net of amount capitalized	$	(278.1	)	$	(258.2	)
Cash (paid) received for income taxes, net	(55.9		)	7.3
Significant non-cash transactions
Accounts payable related to construction costs	71.9			172.7
Portion of Bostco real estate holdings sale financed with note receivable *	—			7.0


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

Effective January 1, 2018, we adopted ASU 2016-18, Restricted Cash. Under this ASU, amounts generally described as restricted cash and restricted cash equivalents are included with cash and cash equivalents when reconciling the beginning-of-the period and end-of-the period total amounts shown on the statements of cash flows. As a result, we no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statements of cash flows. Instead, changes in restricted cash are classified as either operating activities, investing activities, or financing activities.

The majority of our restricted cash consists of amounts held in the Integrys rabbi trust, which are used to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans. All assets held within the rabbi trust are restricted as they can only be withdrawn from the trust to make qualifying benefit payments. The adoption of ASU 2016-18 resulted in an increase of $13.8 million in net cash flows used by investing activities from what was previously reported for the nine months ended September 30, 2017.

See the following table for a reconciliation of cash and cash equivalents and restricted cash reported within the balance sheets to the sum of the total of the same amounts shown in the statements of cash flows at September 30:



(in millions)	2018		2017
Cash and cash equivalents	$	14.5	$	18.1
Restricted cash included in other long term assets	25.7		20.4
Cash, cash equivalents, and restricted cash	$	40.2	$	38.5

Effective January 1, 2018, we adopted ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments. There are eight main provisions of this ASU for which current GAAP either was unclear or did not include specific guidance. The adoption of this guidance had no impact on our financial statements for the nine months ended September 30, 2018 and 2017.

ASU 2016-15 provides an accounting policy election for classifying distributions received from equity method investments. We adopted the cumulative earnings approach for classifying distributions received in the statements of cash flows. Under the cumulative earnings approach, we compare the distributions received to cumulative equity method earnings since inception. Any distributions received up to the amount of cumulative equity earnings are considered a return on investment and classified in operating activities. Any excess distributions are considered a return of investment and classified in investing activities. We did not receive any excess distributions during the nine months ended September 30, 2018 and 2017.

NOTE 22—REGULATORY ENVIRONMENT

Tax Cuts and Jobs Act of 2017

In December 2017, our regulated utilities deferred for return to ratepayers, through future refunds, bill credits, riders, or reductions in other regulatory assets, the estimated tax benefit of $2,450 million related to the Tax Legislation that was signed into law in December 2017. This tax benefit resulted from the revaluation of deferred taxes. The Tax Legislation also reduced the corporate federal tax rate from a maximum of 35% to a 21% rate, effective January 1, 2018. We have received written orders from the PSCW and the MPSC addressing the refunding of certain of these tax benefits to ratepayers in Wisconsin and Michigan, respectively, and the ICC has approved the VITA in Illinois. See the Variable Income Tax Adjustment Rider discussion below for more information on the Illinois rider. A summary of the Wisconsin and Michigan orders and our proposed approach in Minnesota is outlined below.



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Wisconsin

In May 2018, the PSCW issued an order regarding the benefits associated with the Tax Legislation. The PSCW order requires WE's and WPS’s electric utility operations to use 80% and 40%, respectively, of the current 2018 and 2019 tax benefits to reduce certain regulatory assets. The remaining 20% and 60% at WE and WPS, respectively, is to be returned to electric customers in the form of bill credits. For our Wisconsin natural gas utility operations, the PSCW indicated that 100% of the current 2018 and 2019 tax benefits should be returned to natural gas customers in the form of bill credits. Regarding the net tax benefit associated with the revaluation of deferred taxes, amortization required in accordance with normalization accounting is to be used to reduce certain regulatory assets for our electric utilities and is being deferred at our natural gas utilities. The timing and method of returning the remaining net tax benefit associated with the revaluation of deferred taxes at our electric and natural gas utilities was not addressed and will be determined in a future rate proceeding.

Michigan

In February 2018, the MPSC issued an order requiring Michigan utilities to make three filings related to the Tax Legislation. The first of those filings, which was filed in March 2018, prospectively addressed the impact on base rates for the change in tax expense resulting from the federal tax rate reduction from 35% to 21%. UMERC and MGU proposed providing a volumetric bill credit, subject to reconciliation and true up. In May 2018, the MPSC issued orders approving settlements that resulted in volumetric bill credits for all of UMERC's and MGU's customers effective July 1, 2018.

The second filing, which was filed in July 2018, addressed the impact on base rates for the change in tax expense resulting from the federal tax rate reduction from 35% to 21% from January 1, 2018 until July 1, 2018. UMERC and MGU proposed to return the tax savings from these months to customers via volumetric bill credits over multiple months. The MPSC issued orders approving settlements in September 2018. In accordance with the settlement orders, the savings will be returned to UMERC's and MGU's customers via volumetric bill credits that will be in effect from October 1, 2018 through December 31, 2018.

The third filing was filed in October 2018 and addresses the remaining impacts of the Tax Legislation on base rates – most notably the re-measurement of deferred tax balances. UMERC and MGU proposed providing a volumetric bill credit, subject to reconciliation and true up, to return these remaining impacts of the Tax Legislation to customers.

WE, which serves one retail electric customer in Michigan, has reached a settlement with that customer. That settlement was approved by the MPSC in May 2018 and addresses all base rate impacts of the Tax Legislation, which will be returned to the customer through bill credits.

Minnesota

MERC is currently in an active rate case for 2018 and expects to address all aspects of the Tax Legislation, including the re-measurement of deferred tax balances, in that rate case. MERC expects that all impacts of the Tax Legislation will be incorporated into base rates when they are approved by the MPUC during its current rate proceeding.

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

2018 and 2019 Rates

During April 2017, WE, WG, and WPS filed an application with the PSCW for approval of a settlement agreement they made with several of their commercial and industrial customers regarding 2018 and 2019 base rates. In September 2017, the PSCW issued an order that approved the settlement agreement, which freezes base rates through 2019 for electric, natural gas, and steam customers of WE, WG, and WPS. Based on the PSCW order, the authorized ROE for WE, WG, and WPS remains at 10.2%, 10.3%, and 10.0%, respectively, and the current capital cost structure for all of our Wisconsin utilities will remain unchanged through 2019. Various intervenors had filed requests for rehearing, all of which have been denied.

In addition to freezing base rates, the settlement agreement extends and expands the electric real-time market pricing program options for large commercial and industrial customers and mitigates the continued growth of certain escrowed costs at WE during the base rate freeze period by accelerating the recognition of certain tax benefits. WE will flow through the tax benefit of its repair-related deferred tax liabilities in 2018 and 2019, to maintain certain regulatory asset balances at their December 31, 2017 levels.



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While WE would typically follow the normalization accounting method and utilize the tax benefits of the deferred tax liabilities in rate-making as an offset to rate base, benefiting customers over time, the federal tax code does allow for passing these tax repair-related benefits to ratepayers much sooner using the flow through accounting method. The flow through treatment of the repair-related deferred tax liabilities offsets the negative income statement impact of holding the regulatory assets level, resulting in no change to net income.

The agreement also allows WPS to extend through 2019, the deferral for the revenue requirement of ReACT™ costs above the authorized $275.0 million level, and other deferrals related to WPS's electric real-time market pricing program and network transmission expenses. The total cost of the ReACT™ project, excluding $51 million of AFUDC, is currently estimated to be $342 million.

Pursuant to the settlement agreement, WPS also agreed to adopt, beginning in 2018, the earnings sharing mechanism that has been in place for WE and WG since January 2016, and all three utilities agreed to keep the mechanism in place through 2019. Under this earnings sharing mechanism, if WE, WG, or WPS earns above its authorized ROE, 50% of the first 50 basis points of additional utility earnings must be shared with customers. All utility earnings above the first 50 basis points must also be shared with customers.

Wisconsin Public Service Corporation Proposed Solar Generation Projects

On May 31, 2018, WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire ownership interests in two proposed solar projects in Wisconsin. Badger Hollow Solar Farm will be located in Iowa County, Wisconsin, and Two Creeks Solar Project will be located in Manitowoc County, Wisconsin. WPS will own 100 MW of the output of each project for a total of 200 MW. WPS's share of the cost of both projects is estimated to be $260 million.

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

Illinois Proceedings

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 were completed in March 2016. In July 2016, the ICC initiated a proceeding to review, among other things, the planning, reporting, and monitoring of the program, including the target end date for the program, and issued a final order in January 2018. The order did not have a significant impact on PGL's existing SMP design and execution. An appeal related to the final order was filed by the Illinois Attorney General in April 2018.

Qualifying Infrastructure Plant Rider

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

PGL's QIP rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2018, PGL filed its 2017 reconciliation with the ICC, which, along with the 2016 and 2015 reconciliations, are still pending. In February 2018, PGL agreed to a settlement of the 2014 reconciliation, which included a rate base reduction of $5.4 million and a $4.7 million refund to ratepayers.

As of September 30, 2018, there can be no assurance that all costs incurred under PGL's QIP rider during the open reconciliation years will be deemed recoverable by the ICC.

Variable Income Tax Adjustment Rider

In April 2018, the ICC approved the VITA proposed by PGL and NSG. The VITA recovers or refunds changes in income tax expense resulting from differences in income tax rates and amortization of deferred tax excesses and deficiencies (in accordance with the Tax Legislation) from the amounts used in the last PGL and NSG rate case, effective January 25, 2018.



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Minnesota Energy Resources Corporation

2018 Minnesota Rate Case

In October 2017, MERC initiated a rate proceeding with the MPUC to increase retail natural gas rates $12.6 million (5.05%). MERC's request reflected a 10.3% ROE and a common equity component average of 50.9%. In November 2017, the MPUC approved an interim rate order, effective January 1, 2018, authorizing a retail natural gas rate increase of $9.5 million (3.78%). In March 2018, to reflect changes in MERC's effective tax rate as a result of the enactment of the Tax Legislation, the MPUC approved a $2.5 million reduction in interim retail natural gas rates to $7.0 million (2.81%), effective April 1, 2018. The interim rates reflect a 9.1% ROE and a common equity component average of 50.9%. The interim rate increase is subject to refund pending the final written rate order, which is expected in the first half of 2019.

NOTE 23—NEW ACCOUNTING PRONOUNCEMENTS

Leases

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which revises current guidance (Topic 840) regarding accounting for leases. Revisions include requiring a lessee to recognize a lease asset and a lease liability on its balance sheet for each lease, including operating leases, with an initial term greater than 12 months. In addition, required quantitative and qualitative disclosures related to lease agreements were expanded. For lessors however, accounting for leases is largely unchanged from previous provisions of GAAP. This guidance will be effective for our financial statements for periods beginning after December 15, 2018, and interim periods within those annual periods. Companies are able to elect several practical expedients to aid in the transition to Topic 842. The following three practical expedients must all be elected together, and we intend to elect these practical expedients to aid in our implementation of Topic 842.


•	An entity need not reassess whether any expired or existing contracts are or contain leases.


•	An entity need not reassess the lease classification for any expired or existing leases (that is, all existing leases that were classified as operating leases in accordance with Topic 840, Leases, will continue to be classified as operating leases, and all existing leases that were classified as capital leases in accordance with Topic 840 will continue to be classified as capital leases).


•	An entity need not reassess initial direct costs for any existing leases.

Other practical expedients that can be elected individually, and that we are still assessing as part of our implementation of Topic 842, are as follows:


•	An entity may use hindsight in determining the lease term and in assessing impairment of the entity’s right-of-use assets.


•	An entity may elect, by class of underlying asset, to account for the nonlease components in a contract as part of the single lease component to which they are related.

In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842, which is an amendment to ASU 2016-02. Land easements (also commonly referred to as rights of way) represent the right to use, access or cross another entity's land for a specified purpose. This new guidance permits an entity to elect a transitional practical expedient, to be applied consistently, to not evaluate under Topic 842 land easements that were already in existence or had expired at the time of the entity's adoption of Topic 842. Once Topic 842 is adopted, an entity is required to apply Topic 842 prospectively to all new (or modified) land easements to determine whether the arrangement should be accounted for as a lease. ASU 2018-01 is effective for fiscal years beginning after December 15, 2018. We intend to elect this practical expedient.

In July 2018, the FASB issued ASU 2018-11, "Leases (Topic 842): Targeted Improvements," which amends ASU 2016-02 and allows entities the option to initially apply Topic 842 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. We are in the process of finalizing our inventory of leases, which includes continuing to monitor activities of the FASB as well as utility industry implementation guidance. We also continue to document technical accounting issues, analyze financial reporting implications and implement required changes to internal controls and processes. We plan to adopt Topic 842 effective January 1, 2019, using the optional transition method to apply the new guidance as of January 1, 2019, rather than as of the earliest period presented. Upon adoption, we do expect an increase in assets and liabilities (which we are still in the process of quantifying), although we do not expect the guidance to have a significant impact on our results of operations or cash flows.



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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.



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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 2017 Annual Report on Form 10-K.

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 American Transmission Company LLC (ATC) (a for-profit electric transmission company regulated by the FERC and certain state regulatory commissions), and non-utility energy infrastructure operations through We Power (which owns generation assets in Wisconsin), Bluewater (which owns underground natural gas storage facilities in Michigan), and Bishop Hill III (a wind generating facility in Illinois).

Corporate Strategy

Our goal is to continue to build and sustain long-term value for our shareholders and customers by focusing on the fundamentals of our business: reliability; operating efficiency; financial discipline; customer care; and safety.

Reshaping Our Generation Fleet

The planned reshaping of our generation fleet will balance reliability and customer cost with environmental stewardship. Taken as a whole, this plan should reduce costs to customers, preserve fuel diversity, and lower carbon emissions. Generation reshaping includes retiring older fossil fuel generation units, building state-of-the-art natural gas generation, and investing in cost-effective zero-carbon generation with a goal of reducing CO₂ emissions by approximately 40% below 2005 levels by 2030. In addition, we set a new long-term goal of reducing CO₂ emissions by approximately 80% below 2005 levels by 2050. We expect to retire approximately 1,800 MW of coal generation by 2020, and add additional natural gas-fired generating units and renewable generation, including utility-scale solar projects. Our 1,190 MW Pleasant Prairie power plant was retired in April 2018. The physical dismantlement of the Pleasant Prairie power plant will not occur immediately. It may take several years to finalize long-term plans for the site. The Edgewater 4 generating unit was retired in September 2018 and the Pulliam power plant was retired in October 2018. See Note 6, Property, Plant, and Equipment, for information related to the Pleasant Prairie power plant, Edgewater 4, and Pulliam power plant retirements and the planned retirement of the Presque Isle power plant.

Reliability

We have made significant reliability-related investments in recent years, and plan to continue strengthening and modernizing our generation fleet and distribution networks to further improve reliability. Our investments, coupled with our commitment to operating efficiency and customer care, resulted in We Energies being recognized by PA Consulting Group, an independent consulting firm, as the most reliable utility in the United States in 2017 and, for the seventh year in a row, as the most reliable utility in the Midwest.

Below are a few examples of reliability projects that are currently underway.

•

Upper Michigan Energy Resources Corporation (UMERC), our Michigan electric and natural gas utility, is moving forward with its long-term generation solution for electric reliability in the Upper Peninsula of Michigan. The plan calls for UMERC to construct and operate approximately 180 MW of natural gas-fueled generation located in the Upper Peninsula. The new generation is expected to achieve commercial operation during the second quarter of 2019 and provide the region with affordable, reliable electricity that generates less emissions than the Presque Isle power plant (PIPP). In accordance with a written approval letter received from the Midcontinent Independent System Operator, we must retire PIPP by May 31, 2019.


•	The Peoples Gas Light and Coke Company continues to work on its Natural Gas System Modernization Program, which primarily involves replacing old cast and ductile iron pipes and facilities in Chicago’s natural gas delivery system with modern polyethylene pipes to reinforce the long-term safety and reliability of the system.



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•

Wisconsin Public Service Corporation (WPS) continues work on its System Modernization and Reliability Project, which involves modernizing parts of its electric distribution system, including burying or upgrading lines. The project focuses on constructing facilities to improve the reliability of electric service WPS provides to its customers. WPS, Wisconsin Electric Power Company, and Wisconsin Gas LLC also continue to upgrade their electric and natural gas distribution systems to enhance reliability.

Operating Efficiency

We continually look for ways to optimize the operating efficiency of our company. For example, we are making progress on our Advanced Metering Infrastructure program, replacing aging meter-reading equipment on both our network and customer property. An integrated system of smart meters, communication networks, and data management programs enables two-way communication between our utilities and our customers. This program reduces the manual effort for disconnects and reconnects and enhances outage management capabilities.

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

Financial Discipline

A strong adherence to financial discipline is essential to meeting our earnings projections and maintaining a strong balance sheet, stable cash flows, a growing dividend, 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, plants, 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, Acquisitions, for information about our acquisitions of natural gas storage facilities in Michigan and portions of wind energy generation facilities in Wisconsin, Illinois, and Nebraska.


•	See Note 3, Disposition, for information on the sale of Bostco LLC's real estate holdings.

Our investment focus remains in our regulated utility and non-utility energy infrastructure businesses, as well as our investment in ATC. We expect total capital expenditures for our regulated utility and non-utility energy infrastructure businesses to be almost $12.7 billion from 2019 to 2023. Specific projects are discussed in more detail below under Liquidity and Capital Resources.

From 2019 to 2023, we expect capital contributions to ATC and ATC Holdco to be approximately $250 million. ATC Holdco is a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. Capital investments at ATC and ATC Holdco will be funded utilizing these capital contributions, in addition to cash generated from operations and debt. We currently forecast that our share of ATC's and ATC Holdco's projected capital expenditures over the next five years will be $1.2 billion inside the traditional ATC footprint and $250 million outside of the traditional ATC footprint.

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, demonstrating personal responsibility for results, 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, through which employees of our utility subsidiaries contact customers after a completed service call. Customer satisfaction is a priority, and making "We Care" calls is one of the main methods we use to gauge our performance to improve customer satisfaction.

Safety

We have a long-standing commitment to both workplace and public safety, and under our "Target Zero" mission, we have an ultimate goal of zero incidents, accidents, and injuries. We also set goals around injury-prevention activities that raise awareness and facilitate



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conversations about employee safety. Our corporate safety program provides a forum for addressing employee concerns, training employees and contractors on current safety standards, and recognizing those who demonstrate a safety focus.

RESULTS OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2018

Consolidated Earnings

The following table compares our consolidated results for the third quarter of 2018 with the third quarter of 2017, including favorable or better, "B", and unfavorable or worse, "W", variances:



	Three Months Ended September 30
(in millions, except per share data)	2018			2017			B (W)			Change Related to Flow Through of Tax Repairs			Change Related to Tax Legislation			Remaining Change B (W)
Wisconsin	$	201.4		$	277.5		$	(76.1	)	$	(49.3	)	$	(33.3	)	$	6.5
Illinois	15.5			14.3			1.2			—			0.4			0.8
Other states	(5.4		)	(3.0		)	(2.4		)	—			1.6			(4.0		)
Non-utility energy infrastructure	91.6			103.4			(11.8		)	—			(12.6		)	0.8
Corporate and other	(0.4		)	—			(0.4		)	—			—			(0.4		)
Total operating income	302.7			392.2			(89.5		)	(49.3		)	(43.9		)	3.7
Equity in earnings of transmission affiliates	33.7			39.2			(5.5		)	—			(8.4		)	2.9
Other income, net	26.1			17.8			8.3			—			—			8.3
Interest expense	112.0			103.8			(8.2		)	—			—			(8.2		)
Income before income taxes	250.5			345.4			(94.9		)	(49.3		)	(52.3		)	6.7
Income tax expense	17.0			129.7			112.7			49.3			49.6			13.8
Preferred stock dividends of subsidiary	0.3			0.3			—			—			—			—
Net income attributed to common shareholders	$	233.2		$	215.4		$	17.8		$	—		$	(2.7	)	$	20.5

Diluted earnings per share	$	0.74		$	0.68		$	0.06

Earnings increased $17.8 million during the third quarter of 2018, compared with the same quarter in 2017. The table above shows the income statement impact associated with the flow through of tax repairs beginning January 1, 2018 and the Tax Legislation signed into law in December 2017. As shown in the table above, the changes related to these items did not have a significant impact on net income attributed to common shareholders. See Note 11, Income Taxes, and Note 22, Regulatory Environment, for more information.

The significant factors impacting the remaining $20.5 million increase in earnings were:

•

A $13.8 million remaining decrease in income tax expense. During the third quarter, we reconcile the income tax amounts included in the financial statements for the previous year to our federal income tax return and we record any significant preliminary true-ups to income tax expense as necessary (return-to-accrual). The decrease in tax expense is primarily related to the true-up of the prior year's estimated taxes.


•	An $8.3 million increase in other income, net, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 15, Employee Benefits, for more information on our benefit costs.

•

A $6.5 million remaining increase in operating income at the Wisconsin segment, driven by an increase in electric margins related to higher retail sales volumes as a result of favorable weather and higher weather-normalized use per customer. This increase in margins was partially offset by higher operating expenses during the third quarter of 2018, which were driven by the earnings sharing mechanisms in place at our Wisconsin utilities and additional expenses in 2018 related to staff reductions.



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These increases in earnings were partially offset by:


•	An $8.2 million increase in interest expense, driven by higher short-term debt balances, primarily used to fund capital investments, and higher interest rates on both short-term and long-term debt.


•	A $4.0 million remaining increase in operating loss at the other states segment, driven by an increase in operating expenses.

Non-GAAP Financial Measure

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

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

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of our segment operating performance. Operating income for the third quarter of 2018 and 2017 for each of our segments is presented in the “Consolidated Earnings” table above.

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

Wisconsin Segment Contribution to Operating Income



	Three Months Ended September 30
(in millions)	2018		2017		B (W)
Electric revenues	$	1,220.5	$	1,242.7	$	(22.2	)
Fuel and purchased power	400.8		419.9		19.1
Total electric margins	819.7		822.8		(3.1		)

Natural gas revenues	168.2		158.6		9.6
Cost of natural gas sold	83.5		71.4		(12.1		)
Total natural gas margins	84.7		87.2		(2.5		)

Total electric and natural gas margins	904.4		910.0		(5.6		)

Other operation and maintenance	525.0		460.5		(64.5		)
Depreciation and amortization	137.2		131.5		(5.7		)
Property and revenue taxes	40.8		40.5		(0.3		)
Operating income	$	201.4	$	277.5	$	(76.1	)



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



	Three Months Ended September 30
(in millions)	2018		2017		B (W)
Operation and maintenance not included in line items below	$	195.5	$	186.2	$	(9.3	)
We Power ⁽¹⁾	127.8		129.6		1.8
Transmission ⁽²⁾	106.5		108.8		2.3
Transmission expense related to the flow through of tax repairs ⁽³⁾	27.4		—		(27.4		)
Transmission expense related to Tax Legislation ⁽⁴⁾	16.9		—		(16.9		)
Regulatory amortizations and other pass through expenses ⁽⁵⁾	35.9		35.9		—
Earnings sharing mechanisms ⁽⁶⁾	15.0		—		(15.0		)
Total other operation and maintenance	$	525.0	$	460.5	$	(64.5	)

⁽¹⁾

Represents costs associated with the We Power generation units, including operating and maintenance costs incurred by WE, as well as the lease payments that are billed from We Power to WE and then recovered in WE's rates. During the three months ended September 30, 2018 and 2017, $124.8 million and $129.0 million, respectively, of both lease and operating and maintenance costs were billed to or incurred by WE, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

⁽²⁾

The PSCW has approved escrow accounting for ATC and MISO network transmission expenses for our Wisconsin electric utilities. As a result, WE and WPS defer as a regulatory asset or liability the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the three months ended September 30, 2018 and 2017, $124.7 million and $128.9 million, respectively, of costs were billed by transmission providers to our electric utilities.


⁽³⁾	Represents additional transmission expense associated with WE's flow through of tax benefits of its repair-related deferred tax liabilities starting in 2018, in accordance with a settlement agreement with the PSCW, to maintain certain regulatory asset balances at their December 31, 2017 levels. See Note 22, Regulatory Environment, for more information.


⁽⁴⁾	Represents additional transmission expense associated with the May 2018 PSCW order requiring WE to use 80% of its current 2018 tax benefit, including the amortization associated with the revaluation of deferred taxes, to reduce its transmission regulatory asset balance. See Note 22, Regulatory Environment, for more information.


⁽⁵⁾	Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income.


⁽⁶⁾	See Note 22, Regulatory Environment, for more information about our earnings sharing mechanisms.

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



	Three Months Ended September 30
	MWh (in thousands)
Electric Sales Volumes	2018	2017	B (W)
Customer Class
Residential	3,262.5	2,960.4	302.1
Small commercial and industrial *	3,617.5	3,440.6	176.9
Large commercial and industrial *	3,461.5	3,364.6	96.9
Other	39.9	39.8	0.1
Total retail *	10,381.4	9,805.4	576.0
Wholesale	959.9	977.8	(17.9	)
Resale	1,313.7	2,484.8	(1,171.1	)
Total sales in MWh *	12,655.0	13,268.0	(613.0	)


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



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	Three Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2018	2017	B (W)
Customer Class
Residential	59.5	58.3	1.2
Commercial and industrial	58.9	56.3	2.6
Total retail	118.4	114.6	3.8
Transport	291.6	275.7	15.9
Total sales in therms	410.0	390.3	19.7



	Three Months Ended September 30
	Degree Days
Weather	2018	2017	B(W)
WE and WG ⁽¹⁾
Heating (113 normal)	75	72	4.2	%
Cooling (556 normal)	686	542	26.6	%

WPS ⁽²⁾
Heating (194 normal)	147	178	(17.4	)%
Cooling (369 normal)	459	315	45.7	%

UMERC ⁽³⁾
Heating (319 normal)	267	306	(12.7	)%
Cooling (246 normal)	340	186	82.8	%


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


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


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

Electric Utility Margins

Electric utility margins at the Wisconsin segment decreased $3.1 million during the third quarter of 2018, compared with the same quarter in 2017. The significant factors impacting the lower electric utility margins were:


•	A $21.9 million decrease in margins associated with WE's flow through of tax benefits of its repair-related deferred tax liabilities starting in 2018, in accordance with a settlement agreement with the PSCW to maintain certain regulatory assets at their December 31, 2017 levels. See Note 22, Regulatory Environment, for more information.


•	A $13.6 million decrease in margins related to amounts expected to be returned to customers through refunds, bill credits, or reductions in other regulatory assets, driven by the Tax Legislation. See Note 11, Income Taxes, and Note 22, Regulatory Environment, for more information.


•	A $6.1 million decrease in wholesale margins driven both by lower sales volumes and reduced capacity rates due in part to the Tax Legislation.

These decreases in margins were partially offset by a $38.0 million increase related to higher retail sales volumes during the third quarter of 2018, primarily driven by favorable weather and higher overall use per retail customer due in part to a stronger economy. As measured by cooling degree days, the third quarter of 2018 was 26.6% and 45.7% warmer than the same quarter in 2017 in the Milwaukee area and Green Bay area, respectively.



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Natural Gas Utility Margins

Natural gas utility margins at the Wisconsin segment decreased $2.5 million during the third quarter of 2018, compared with the same quarter in 2017, and was driven by amounts expected to be returned to customers through refunds or bill credits related to the Tax Legislation. See Note 11, Income Taxes, and Note 22, Regulatory Environment, for more information.

Operating Income

Operating income at the Wisconsin segment decreased $76.1 million during the third quarter of 2018, compared with the same quarter in 2017. This decrease was driven by $70.5 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes), and the $5.6 million of lower margins discussed above.

The significant factors impacting the increase in operating expenses during the third quarter of 2018, compared with the same quarter in 2017, were:


•	A $27.4 million increase in transmission expense related to the flow through of tax repairs, as discussed in the other operation and maintenance table above.


•	A $16.9 million increase in transmission expense associated with the May 2018 order from the PSCW related to our required treatment of the benefits associated with the Tax Legislation, as discussed in the other operation and maintenance table above.


•	A $15.0 million expense recorded in the third quarter of 2018 related to the earnings sharing mechanisms in place at our Wisconsin utilities. See Note 22, Regulatory Environment, for more information.


•	A $13.6 million increase in benefit costs, which included $7.9 million of expenses related to staff reductions.


•	A $5.7 million increase in depreciation and amortization driven by an increase in capital expenditures as we continue to execute on our capital plan.

These increases in operating expenses were partially offset by a $9.2 million decrease in expenses at our plants, primarily related to the retirement of the Pleasant Prairie power plant in April 2018 and the winding down of operations in anticipation of other expected plant retirements. This resulted in lower maintenance and labor costs during the third quarter of 2018. See Note 6, Property, Plant, and Equipment, for more information on the plant retirements.

Illinois Segment Contribution to Operating Income



	Three Months Ended September 30
(in millions)	2018		2017		B (W)
Natural gas revenues	$	197.9	$	187.2	$	10.7
Cost of natural gas sold	29.8		31.1		1.3
Total natural gas margins	168.1		156.1		12.0

Other operation and maintenance	104.5		99.0		(5.5		)
Depreciation and amortization	43.0		38.9		(4.1		)
Property and revenue taxes	5.1		3.9		(1.2		)
Operating income	$	15.5	$	14.3	$	1.2



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



	Three Months Ended September 30
(in millions)	2018			2017		B (W)
Operation and maintenance not included in the line items below	$	93.7		$	87.1	$	(6.6	)
Riders *	10.6			11.5		0.9
Regulatory amortizations *	(0.4		)	—		0.4
Other	0.6			0.4		(0.2		)
Total other operation and maintenance	$	104.5		$	99.0	$	(5.5	)


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

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



	Three Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2018	2017	B (W)
Customer Class
Residential	43.2	51.7	(8.5	)
Commercial and industrial	22.9	21.8	1.1
Total retail	66.1	73.5	(7.4	)
Transport	103.0	98.4	4.6
Total sales in therms	169.1	171.9	(2.8	)



	Three Months Ended September 30
	Degree Days
Weather *	2018	2017	B (W)
Heating (81 Normal)	54	43	25.6	%


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

Natural Gas Utility Margins

Natural gas utility margins, net of the $0.9 million impact of the riders referenced in the table above, increased $12.9 million during the third quarter of 2018, compared with the same quarter in 2017, driven by an increase in revenue at PGL due to continued capital investment in the SMP project under its QIP rider. PGL currently recovers the costs related to the SMP through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023. See Note 22, Regulatory Environment, for more information.

Operating Income

Operating income at the Illinois segment increased $1.2 million during the third quarter of 2018, compared with the same quarter in 2017. This increase was due to the $12.9 million net increase in margins discussed above, partially offset by an $11.7 million increase in operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes), net of the impact of the riders referenced in the table above. The increase in operating expenses was driven by higher depreciation expense at PGL primarily due to continued capital investment in the SMP project, as well as an increase in gas maintenance costs.



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Other States Segment Contribution to Operating Income



	Three Months Ended September 30
(in millions)	2018			2017			B (W)
Natural gas revenues	$	50.2		$	49.8		$	0.4
Cost of natural gas sold	21.7			21.3			(0.4		)
Total natural gas margins	28.5			28.5			—

Other operation and maintenance	23.0			21.5			(1.5		)
Depreciation and amortization	6.4			6.3			(0.1		)
Property and revenue taxes	4.5			3.7			(0.8		)
Operating loss	$	(5.4	)	$	(3.0	)	$	(2.4	)

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



	Three Months Ended September 30
(in millions)	2018		2017		B (W)
Operation and maintenance not included in line item below	$	19.6	$	18.4	$	(1.2	)
Regulatory amortizations and other pass through expenses *	3.4		3.1		(0.3		)
Total other operation and maintenance	$	23.0	$	21.5	$	(1.5	)


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

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



	Three Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2018	2017	B (W)
Customer Class
Residential	16.7	18.1	(1.4	)
Commercial and industrial	16.9	18.5	(1.6	)
Total retail	33.6	36.6	(3.0	)
Transport	159.6	147.6	12.0
Total sales in therms	193.2	184.2	9.0



	Three Months Ended September 30
	Degree Days
Weather *	2018	2017	B (W)
MERC
Heating (217 Normal)	207	190	8.9	%

MGU
Heating (120 Normal)	86	117	(26.5	)%


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

Operating Loss

Operating loss at the other states segment increased $2.4 million during the third quarter of 2018, compared to the same quarter last year. This increased operating loss was driven by a $2.4 million increase in operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes).



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Non-Utility Energy Infrastructure Segment Contribution to Operating Income



	Three Months Ended September 30
(in millions)	2018		2017		B (W)
Operating income	$	91.6	$	103.4	$	(11.8	)

Operating income at the non-utility energy infrastructure segment decreased $11.8 million during the third quarter of 2018, compared with the same quarter in 2017. The decrease was driven by a $12.6 million decrease in revenue related to the Tax Legislation signed into law in December 2017. As a result of the Tax Legislation, the lease payments charged by We Power to WE were reduced. The reduction in the lease payments was offset by a decrease in income tax expense, resulting in no impact on net income. See Note 11, Income Taxes, and Note 22, Regulatory Environment, for more information.

Corporate and Other Segment Contribution to Operating Income



	Three Months Ended September 30
(in millions)	2018			2017		B (W)
Operating loss	$	(0.4	)	$	—	$	(0.4	)

Electric Transmission Segment Operations



	Three Months Ended September 30
(in millions)	2018		2017		B (W)
Equity in earnings of transmission affiliates	$	33.7	$	39.2	$	(5.5	)

Earnings from our ownership interests in transmission affiliates decreased $5.5 million during the third quarter of 2018, compared with the same quarter in 2017, primarily due to the Tax Legislation signed into law in December 2017. The $8.4 million decrease in our equity earnings from the Tax Legislation did not affect our net income as it was offset by an equal reduction in our income tax expense. See Note 11, Income Taxes, for more information. The decrease in equity earnings from the Tax Legislation was partially offset by increased equity earnings related to continued capital investment by our transmission affiliates.

Consolidated Other Income, Net



	Three Months Ended September 30
(in millions)	2018		2017		B (W)
AFUDC – Equity	$	3.7	$	3.0	$	0.7
Non-service components of net periodic benefit costs	7.3		1.4		5.9
Other, net	15.1		13.4		1.7
Other income, net	$	26.1	$	17.8	$	8.3

Other income, net increased $8.3 million during the third quarter of 2018, compared with the same quarter in 2017. An increase of $5.9 million was driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 15, Employee Benefits, for more information on our benefit costs. Higher gains on investments held in our rabbi trust also drove a $2.7 million quarter-over-quarter increase.

Consolidated Interest Expense



	Three Months Ended September 30
(in millions)	2018		2017		B (W)
Interest expense	$	112.0	$	103.8	$	(8.2	)

Interest expense increased $8.2 million during the third quarter of 2018, compared with the same quarter in 2017, primarily due to higher short-term debt balances and higher interest rates on both short-term and long-term debt. This increase in debt balances is primarily related to continued capital investments.



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Consolidated Income Tax Expense



	Three Months Ended September 30
	2018		2017		B (W)
Effective tax rate	6.8	%	37.6	%	30.8	%

Our effective tax rate decreased by 30.8% when compared with the third quarter of 2017, primarily due to the impact of the Tax Legislation. Contributing 14.3% to the decrease in the effective tax rate was the flow through of tax repairs in connection with the Wisconsin rate settlement. See Note 11, Income Taxes, and Note 22, Regulatory Environment, for more information.

NINE MONTHS ENDED SEPTEMBER 30, 2018

Consolidated Earnings

The following table compares our consolidated results for the nine months ended September 30, 2018 with the nine months ended September 30, 2017, including favorable or better, "B", and unfavorable or worse, "W", variances:



	Nine Months Ended September 30
(in millions, except per share data)	2018			2017			B (W)			Change Related to Flow Through of Tax Repairs			Change Related to Tax Legislation			Remaining Change B (W)
Wisconsin	$	670.2		$	829.6		$	(159.4	)	$	(115.3	)	$	(103.4	)	$	59.3
Illinois	204.8			214.9			(10.1		)	—			(18.7		)	8.6
Other states	38.9			35.2			3.7			—			(4.5		)	8.2
Non-utility energy infrastructure	277.0			299.5			(22.5		)	—			(37.8		)	15.3
Corporate and other	(12.3		)	(10.1		)	(2.2		)	—			—			(2.2		)
Total operating income	1,178.6			1,369.1			(190.5		)	(115.3		)	(164.4		)	89.2
Equity in earnings of transmission affiliates	95.2			122.9			(27.7		)	—			(28.5		)	0.8
Other income, net	65.0			49.2			15.8			—			—			15.8
Interest expense	327.2			310.4			(16.8		)	—			—			(16.8		)
Income before income taxes	1,011.6			1,230.8			(219.2		)	(115.3		)	(192.9		)	89.0
Income tax expense	156.4			458.8			302.4			115.3			183.0			4.1
Preferred stock dividends of subsidiary	0.9			0.9			—			—			—			—
Net income attributed to common shareholders	$	854.3		$	771.1		$	83.2		$	—		$	(9.9	)	$	93.1

Diluted Earnings Per Share	$	2.70		$	2.43		$	0.27

Earnings increased $83.2 million during the nine months ended September 30, 2018, compared with the same period in 2017. The table above shows the income statement impact associated with the flow through of tax repairs beginning January 1, 2018 and the Tax Legislation signed into law in December 2017. As shown in the table above, the changes related to these items decreased net income attributed to common shareholders by $9.9 million. See Note 11, Income Taxes, and Note 22, Regulatory Environment, for more information.

The significant factors impacting the remaining $93.1 million increase in earnings were:

•

A $59.3 million remaining increase in operating income at the Wisconsin segment, driven by an increase in electric and natural gas margins related to higher retail sales volumes as a result of favorable weather and higher weather-normalized use per customer. This increase in margins was partially offset by higher operating expenses during the nine months ended September 30, 2018, which were driven by the earnings sharing mechanisms in place at our Wisconsin utilities, an increase in depreciation expense, and additional expenses in 2018 related to staff reductions.


•	A $15.8 million increase in other income, net, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 15, Employee Benefits, for more information on our benefit costs.



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•	A $15.3 million remaining increase in operating income at the non-utility energy infrastructure segment, primarily driven by the inclusion of the operations of Bluewater following its acquisition on June 30, 2017.


•	An $8.6 million remaining increase in operating income at the Illinois segment. The increase was driven by higher natural gas margins at PGL due to continued capital investment in the SMP project under its QIP rider.


•	An $8.2 million remaining increase in operating income at the other states segment. The increase was driven by higher natural gas margins, which were primarily a result of the colder winter weather in 2018 as well as customer growth and an interim rate increase.

These increases in earnings were partially offset by a $16.8 million increase in interest expense, driven by higher short-term debt balances, primarily used to fund capital investments, and higher interest rates on both short-term and long-term debt.

Non-GAAP Financial Measure

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of our segment operating performance. Operating income for the nine months ended September 30, 2018 and 2017 for each of our segments is presented in the “Consolidated Earnings” table above.

Wisconsin Segment Contribution to Operating Income



	Nine Months Ended September 30
(in millions)	2018		2017		B (W)
Electric revenues	$	3,377.1	$	3,448.7	$	(71.6	)
Fuel and purchased power	1,081.3		1,115.4		34.1
Total electric margins	2,295.8		2,333.3		(37.5		)

Natural gas revenues	926.2		867.9		58.3
Cost of natural gas sold	528.1		473.1		(55.0		)
Total natural gas margins	398.1		394.8		3.3

Total electric and natural gas margins	2,693.9		2,728.1		(34.2		)

Other operation and maintenance	1,495.9		1,385.9		(110.0		)
Depreciation and amortization	406.9		391.1		(15.8		)
Property and revenue taxes	120.9		121.5		0.6
Operating income	$	670.2	$	829.6	$	(159.4	)



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



	Nine Months Ended September 30
(in millions)	2018		2017		B (W)
Operation and maintenance not included in line items below	$	560.9	$	565.8	$	4.9
We Power ⁽¹⁾	380.9		384.3		3.4
Transmission ⁽²⁾	315.7		318.8		3.1
Transmission expense related to the flow through of tax repairs ⁽³⁾	52.1		—		(52.1		)
Transmission expense related to Tax Legislation ⁽⁴⁾	50.7		—		(50.7		)
Regulatory amortizations and other pass through expenses ⁽⁵⁾	116.9		117.0		0.1
Earnings sharing mechanism ⁽⁶⁾	18.7		—		(18.7		)
Total other operation and maintenance	$	1,495.9	$	1,385.9	$	(110.0	)

⁽¹⁾

Represents costs associated with the We Power generation units, including operating and maintenance costs incurred by WE, as well as the lease payments that are billed from We Power to WE and then recovered in WE's rates. During the nine months ended September 30, 2018 and 2017, $361.5 million and $394.0 million, respectively, of both lease and operating and maintenance costs were billed to or incurred by WE, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

⁽²⁾

The PSCW has approved escrow accounting for ATC and MISO network transmission expenses for our Wisconsin electric utilities. As a result, WE and WPS defer as a regulatory asset or liability the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the nine months ended September 30, 2018 and 2017, $316.3 million and $330.4 million, respectively, of costs were billed by transmission providers to our electric utilities.


⁽³⁾	Represents additional transmission expense associated with WE's flow through of tax benefits of its repair-related deferred tax liabilities starting in 2018, in accordance with a settlement agreement with the PSCW, to maintain certain regulatory asset balances at their December 31, 2017 levels. See Note 22, Regulatory Environment, for more information.


⁽⁴⁾	Represents additional transmission expense associated with the May 2018 PSCW order requiring WE to use 80% of its current 2018 tax benefit, including the amortization associated with the revaluation of deferred taxes, to reduce its transmission regulatory asset balance. See Note 22, Regulatory Environment, for more information.


⁽⁵⁾	Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income.


⁽⁶⁾	See Note 22, Regulatory Environment, for more information about our earnings sharing mechanisms.

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	2018	2017	B (W)
Customer Class
Residential	8,545.0	8,013.9	531.1
Small commercial and industrial *	10,032.8	9,746.8	286.0
Large commercial and industrial *	9,838.2	9,669.4	168.8
Other	124.2	126.9	(2.7	)
Total retail *	28,540.2	27,557.0	983.2
Wholesale	2,692.7	2,854.4	(161.7	)
Resale	4,550.4	6,002.5	(1,452.1	)
Total sales in MWh *	35,783.3	36,413.9	(630.6	)


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



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	Nine Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2018	2017	B (W)
Customer Class
Residential	753.3	661.2	92.1
Commercial and industrial	497.6	428.9	68.7
Total retail	1,250.9	1,090.1	160.8
Transport	1,026.8	952.0	74.8
Total sales in therms	2,277.7	2,042.1	235.6



	Nine Months Ended September 30
	Degree Days
Weather	2018	2017	B(W)
WE and WG ⁽¹⁾
Heating (4,282 normal)	4,323	3,669	17.8	%
Cooling (722 normal)	903	745	21.2	%

WPS ⁽²⁾
Heating (4,755 normal)	4,864	4,285	13.5	%
Cooling (502 normal)	674	440	53.2	%

UMERC ⁽³⁾
Heating (5,416 normal)	5,509	5,109	7.8	%
Cooling (323 normal)	478	233	105.2	%


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


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


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

Electric Utility Margins

Electric utility margins at the Wisconsin segment decreased $37.5 million during the nine months ended September 30, 2018, compared with the same period in 2017. The significant factors impacting the lower electric utility margins were:


•	A $63.2 million decrease in margins associated with WE's flow through of tax benefits of its repair-related deferred tax liabilities starting in 2018, in accordance with a settlement agreement with the PSCW to maintain certain regulatory assets at their December 31, 2017 levels. See Note 22, Regulatory Environment, for more information.


•	A $29.9 million decrease in margins related to amounts expected to be returned to customers through refunds, bill credits, or reductions in other regulatory assets, driven by the Tax Legislation. See Note 11, Income Taxes, and Note 22, Regulatory Environment, for more information.


•	A $13.7 million decrease in wholesale margins driven both by lower sales volumes and reduced capacity rates due in part to the Tax Legislation.

These decreases in margins were partially offset by a $68.0 million increase related to higher retail sales volumes during the nine months ended September 30, 2018, primarily driven by favorable weather and higher overall use per retail customer due in part to a stronger economy. Colder winter weather and a warmer summer in 2018 contributed to the increase. As measured by heating degree days, the nine months ended September 30, 2018, were 17.8% and 13.5% colder than the same period in 2017 in the Milwaukee area and Green Bay area, respectively. As measured by cooling degree days, the nine months ended September 30, 2018, were 21.2% and 53.2% warmer than the same period in 2017 in the Milwaukee area and Green Bay area, respectively.



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Natural Gas Utility Margins

Natural gas utility margins at the Wisconsin segment increased $3.3 million during the nine months ended September 30, 2018, compared with the same period in 2017. The most significant factor impacting the higher natural gas utility margins was a $30.0 million increase related to higher sales volumes, primarily driven by colder winter weather, customer growth, and higher use per commercial and industrial customer due in part to a stronger economy. This increase in margins was partially offset by $26.8 million of amounts expected to be returned to customers through refunds or bill credits, driven by the Tax Legislation. See Note 11, Income Taxes, and Note 22, Regulatory Environment, for more information.

Operating Income

Operating income at the Wisconsin segment decreased $159.4 million during the nine months ended September 30, 2018, compared with the same period in 2017. This decrease was driven by $125.2 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes), and the $34.2 million net decrease in margins discussed above.

The significant factors impacting the increase in operating expenses during the nine months ended September 30, 2018, compared with the same period in 2017, were:


•	A $52.1 million increase in transmission expense related to the flow through of tax repairs, as discussed in the other operation and maintenance table above.


•	A $50.7 million increase in transmission expense associated with the May 2018 order from the PSCW related to our required treatment of the benefits associated with the Tax Legislation, as discussed in the other operation and maintenance table above.


•	An $18.7 million expense recorded in the third quarter of 2018 related to the earnings sharing mechanisms in place at our Wisconsin utilities. See Note 22, Regulatory Environment, for more information.


•	A $15.8 million increase in depreciation and amortization, driven by an increase in capital expenditures as we continue to execute on our capital plan. This increase in depreciation and amortization was partially offset by a decrease related to the reduction of certain WPS regulatory deferrals as a result of the PSCW's May 2018 order addressing the Tax Legislation.


•	A $12.4 million increase in benefit costs, which included $7.9 million of expenses related to staff reductions.

These increases in operating expenses were partially offset by a $16.9 million decrease in expenses at our plants, primarily related to the retirement of the Pleasant Prairie power plant in April 2018 and the winding down of operations in anticipation of other expected plant retirements. This resulted in lower maintenance and labor costs during the nine months ended September 30, 2018. See Note 6, Property, Plant, and Equipment, for more information on the plant retirements.

Illinois Segment Contribution to Operating Income



	Nine Months Ended September 30
(in millions)	2018		2017		B (W)
Natural gas revenues	$	973.2	$	965.7	$	7.5
Cost of natural gas sold	306.8		302.9		(3.9		)
Total natural gas margins	666.4		662.8		3.6

Other operation and maintenance	320.8		321.0		0.2
Depreciation and amortization	125.7		112.6		(13.1		)
Property and revenue taxes	15.1		14.3		(0.8		)
Operating income	$	204.8	$	214.9	$	(10.1	)



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



	Nine Months Ended September 30
(in millions)	2018			2017		B (W)
Operation and maintenance not included in the line items below	$	253.1		$	245.7	$	(7.4	)
Riders *	67.2			73.2		6.0
Regulatory amortizations *	(1.1		)	1.2		2.3
Other	1.6			0.9		(0.7		)
Total other operation and maintenance	$	320.8		$	321.0	$	0.2


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

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



	Nine Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2018	2017	B (W)
Customer Class
Residential	610.2	509.7	100.5
Commercial and industrial	250.8	216.9	33.9
Total retail	861.0	726.6	134.4
Transport	628.7	565.8	62.9
Total sales in therms	1,489.7	1,292.4	197.3



	Nine Months Ended September 30
	Degree Days
Weather *	2018	2017	B (W)
Heating (3,907 Normal)	4,003	3,306	21.1	%


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

Natural Gas Utility Margins

Natural gas utility margins, net of the $6.0 million impact of the riders referenced in the table above, increased $9.6 million during the nine months ended September 30, 2018, compared with the same period in 2017, driven by an increase in revenue at PGL due to continued capital investment in the SMP project under its QIP rider. PGL currently recovers the costs related to the SMP through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023. This increase was partially offset by a decrease in margins related to amounts being returned to customers through the VITA in connection with the Tax Legislation signed into law in December 2017. See Note 11, Income Taxes, and Note 22, Regulatory Environment, for more information.

Operating Income

Operating income at the Illinois segment decreased $10.1 million during the nine months ended September 30, 2018, compared with the same period in 2017. This decrease was due to a $19.7 million increase in operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes), net of the impact of the riders referenced in the table above, partially offset by the $9.6 million net increase in margins discussed above. The increase in operating expenses was driven by higher depreciation expense at PGL primarily due to continued capital investment in the SMP project, as well as an increase in gas maintenance costs.



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Other States Segment Contribution to Operating Income



	Nine Months Ended September 30
(in millions)	2018		2017		B (W)
Natural gas revenues	$	292.5	$	273.4	$	19.1
Cost of natural gas sold	149.1		135.1		(14.0		)
Total natural gas margins	143.4		138.3		5.1

Other operation and maintenance	74.5		73.0		(1.5		)
Depreciation and amortization	17.5		18.4		0.9
Property and revenue taxes	12.5		11.7		(0.8		)
Operating income	$	38.9	$	35.2	$	3.7

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



	Nine Months Ended September 30
(in millions)	2018		2017		B (W)
Operation and maintenance not included in line item below	$	55.9	$	56.1	$	0.2
Regulatory amortizations and other pass through expenses *	18.6		16.9		(1.7		)
Total other operation and maintenance	$	74.5	$	73.0	$	(1.5	)


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

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



	Nine Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2018	2017	B (W)
Customer Class
Residential	234.1	191.5	42.6
Commercial and industrial	152.0	130.1	21.9
Total retail	386.1	321.6	64.5
Transport	551.9	506.6	45.3
Total sales in therms	938.0	828.2	109.8



	Nine Months Ended September 30
	Degree Days
Weather *	2018	2017	B (W)
MERC
Heating (5,016 Normal)	5,356	4,626	15.8	%

MGU
Heating (4,079 Normal)	4,079	3,501	16.5	%


*	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

Natural gas utility margins increased $5.1 million during the nine months ended September 30, 2018, compared to the same period in 2017. The increase was primarily driven by colder winter weather in 2018 as well as customer growth and an interim rate increase, partially offset by a $4.5 million decrease in margins related to amounts expected to be returned to customers through bill credits or reductions in future rates, related to the Tax Legislation signed into law in December 2017. See Note 11, Income Taxes, and Note 22, Regulatory Environment, for more information.



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Operating Income

Operating income at the other states segment increased $3.7 million during the nine months ended September 30, 2018, compared with the same period in 2017. The increase was driven by the $5.1 million increase in margins discussed above, partially offset by a $1.4 million increase in operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes).

Non-Utility Energy Infrastructure Segment Contribution to Operating Income



	Nine Months Ended September 30
(in millions)	2018		2017		B (W)
Operating income	$	277.0	$	299.5	$	(22.5	)

Operating income at the non-utility energy infrastructure segment decreased $22.5 million during the nine months ended September 30, 2018, compared with the same period in 2017. The decrease was driven by a $37.8 million decrease in revenue related to the Tax Legislation signed into law in December 2017. As a result of the Tax Legislation, the lease payments charged by We Power to WE were reduced. The reduction in the lease payments was offset by a decrease in income tax expense, resulting in no impact on net income. See Note 11, Income Taxes, and Note 22, Regulatory Environment, for more information. Partially offsetting the impact of the Tax Legislation was a $19.0 million contribution to operating income from Bluewater during the nine months ended September 30, 2018, compared to a $5.8 million contribution during the same period in 2017. Bluewater was acquired on June 30, 2017. See Note 2, Acquisitions, for more information.

Corporate and Other Segment Contribution to Operating Income



	Nine Months Ended September 30
(in millions)	2018			2017			B (W)
Operating loss	$	(12.3	)	$	(10.1	)	$	(2.2	)

Electric Transmission Segment Operations



	Nine Months Ended September 30
(in millions)	2018		2017		B (W)
Equity in earnings of transmission affiliates	$	95.2	$	122.9	$	(27.7	)

Earnings from our ownership interests in transmission affiliates decreased $27.7 million during the nine months ended September 30, 2018, compared with the same period in 2017, primarily due to the Tax Legislation signed into law in December 2017. The $28.5 million decrease in our equity earnings from the Tax Legislation did not affect our net income as it was offset by an equal reduction in our income tax expense. See Note 11, Income Taxes, for more information. The decrease in equity earnings from the Tax Legislation was partially offset by increased equity earnings related to continued capital investment by our transmission affiliates.

Consolidated Other Income, Net



	Nine Months Ended September 30
(in millions)	2018		2017		B (W)
AFUDC – Equity	$	10.7	$	8.3	$	2.4
Non-service components of net periodic benefit costs	19.8		4.0		15.8
Other, net	34.5		36.9		(2.4		)
Other income, net	$	65.0	$	49.2	$	15.8

Other income, net increased $15.8 million during the nine months ended September 30, 2018, compared with the same period in 2017, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 15, Employee Benefits, for more information on our benefit costs.



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Consolidated Interest Expense



	Nine Months Ended September 30
(in millions)	2018		2017		B (W)
Interest expense	$	327.2	$	310.4	$	(16.8	)

Interest expense increased $16.8 million during the nine months ended September 30, 2018, compared with the same period in 2017, primarily due to higher short-term debt balances and higher interest rates on both short-term and long-term debt. This increase in debt balances is primarily related to continued capital investments.

Consolidated Income Tax Expense



	Nine Months Ended September 30
	2018		2017		B (W)
Effective tax rate	15.5	%	37.3	%	21.8	%

Our effective tax rate decreased 21.8% when compared with the nine months ended September 30, 2017, primarily due to the impact of the Tax Legislation. Contributing 8.3% to the decrease in the effective tax rate was the flow through of tax repairs in connection with the Wisconsin rate settlement. See Note 11, Income Taxes, and Note 22, Regulatory Environment, for more information.

We expect our 2018 annual effective tax rate to be between 14% and 15%, which includes an estimated 10% effective tax rate benefit due to the flow through of tax repairs.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

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



(in millions)	2018			2017			Change in 2018 Over 2017
Cash provided by (used in):
Operating activities	$	2,008.2		$	1,745.7		$	262.5
Investing activities	(1,720.0		)	(1,565.8		)	(154.2		)
Financing activities	(306.6		)	(214.1		)	(92.5		)

Operating Activities

Net cash provided by operating activities increased $262.5 million during the nine months ended September 30, 2018, compared with the same period in 2017, driven by:


•	A $220.0 million increase in cash related to higher overall collections from customers, primarily due to favorable weather during the nine months ended September 30, 2018, compared with the same period in 2017.


•	A $120.7 million increase in cash from lower payments for other operation and maintenance costs. During the nine months ended September 30, 2018, our payments related to plant maintenance and labor costs as well as transmission decreased.


•	A $101.6 million increase in cash due to lower contributions and payments to our pension and OPEB plans during the nine months ended September 30, 2018, compared with the same period in 2017.

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


•	A $101.8 million decrease in cash resulting from higher payments during the nine months ended September 30, 2018, compared with the same period in 2017, for natural gas we purchased at the end of 2017 and during the nine months ended September 30, 2018, to meet the requirements of our customers during the colder winter weather.



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•	A $63.2 million net decrease in cash related to $55.9 million of cash paid for income taxes during the nine months ended September 30, 2018, compared with $7.3 million of cash received for income taxes during the same period in 2017. This decrease in cash was primarily due to the repeal of bonus depreciation for our regulated utilities as a result of the Tax Legislation.

Investing Activities

Net cash used in investing activities increased $154.2 million during the nine months ended September 30, 2018, compared with the same period in 2017, driven by:


•	A $181.3 million increase in cash paid for capital expenditures during the nine months ended September 30, 2018, compared with the same period in 2017, which is discussed in more detail below.


•	The acquisition of Bishop Hill III during August 2018 for $143.5 million, which is net of restricted cash acquired of $4.5 million. See Note 2, Acquisitions, for more information.


•	The acquisition of Forward Wind Energy Center during April 2018 for $77.1 million. See Note 2, Acquisitions, for more information.

These increases in net cash used in investing activities were partially offset by:


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

•

A $19.6 million decrease in our capital contributions to ATC and ATC Holdco during the nine months ended September 30, 2018, compared with the same period in 2017. Our capital contributions decreased due to the refunds ATC paid in 2017 as a result of the ATC ROE complaints filed with the FERC, which were partially funded by capital contributions. See Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints for more information.

Capital Expenditures

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



Reportable Segment (in millions)	2018		2017		Change in 2018 Over 2017
Wisconsin	$	983.4	$	764.0	$	219.4
Illinois	376.6		356.8		19.8
Other states	75.3		52.9		22.4
Non-utility energy infrastructure	24.6		19.1		5.5
Corporate and other	30.6		116.4		(85.8		)
Total capital expenditures	$	1,490.5	$	1,309.2	$	181.3

The increase in cash paid for capital expenditures at the Wisconsin segment during the nine months ended September 30, 2018, compared with the same period in 2017, was driven by a project to construct a new natural gas-fired generation facility in the Upper Peninsula of Michigan and our advanced metering infrastructure program. Upgrades to our electric distribution systems, an information technology project created to improve WE's and WG's billing, call center, and credit collection functions, and various other software projects also contributed to the increase in our capital expenditures.

The increase in cash paid for capital expenditures at the Illinois segment during the nine months ended September 30, 2018, compared with the same period in 2017, was driven by increased construction activity related to NSG's natural gas pipeline distribution system.

The increase in cash paid for capital expenditures at the other states segment during the nine months ended September 30, 2018, compared with the same period in 2017, was driven by upgrades to MERC's natural gas distribution systems.

The decrease in cash paid for capital expenditures at the corporate and other segment during the nine months ended September 30, 2018, compared with the same period in 2017, was driven by the implementation of a new enterprise resource planning system during the first quarter of 2018. The 2017 completion of an information technology project created to improve the billing, call center,



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and credit collection functions of the Integrys subsidiaries reduced our capital expenditures as well. Various other software projects, the majority of which were completed during 2017, also contributed to the decrease in our capital expenditures.

See Capital Resources and Requirements – Capital Requirements – Significant Capital Projects for more information.

Financing Activities

Net cash used in financing activities increased $92.5 million during the nine months ended September 30, 2018, compared with the same period in 2017, driven by:


•	A $667.5 million decrease in cash related to higher long-term debt repayments during the nine months ended September 30, 2018, compared with the same period in 2017.


•	A $30.6 million increase in dividends paid on our common stock during the nine months ended September 30, 2018, compared with the same period in 2017. In January 2018, our Board of Directors increased our quarterly dividend by $0.0325 per share (6.25%) effective with the first quarter of 2018 dividend payment.

These increases in net cash used in financing activities were partially offset by:


•	A $390.0 million increase in cash due to the issuance of more long-term debt during the nine months ended September 30, 2018, compared with the same period in 2017.


•	A $210.4 million increase in net borrowings of commercial paper during the nine months ended September 30, 2018, compared with the same period in 2017.

Significant Financing Activities

For more information on our financing activities, see Note 8, Short-Term Debt and Lines of Credit, and Note 9, 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 8, 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, 2018, as well as an adjusted capitalization structure that we believe is consistent with how a majority of the rating agencies currently view our 2007 Junior Notes:



(in millions)	Actual			Adjusted
Common shareholders' equity	$	9,775.3		$	10,025.3
Preferred stock of subsidiary	30.4			30.4
Long-term debt (including current portion)	9,488.4			9,238.4
Short-term debt	1,788.3			1,788.3
Total capitalization	$	21,082.4		$	21,082.4

Total debt	$	11,276.7		$	11,026.7

Ratio of debt to total capitalization	53.5		%	52.3		%

Included in long-term debt on our balance sheet as of September 30, 2018, is $500.0 million principal amount of the 2007 Junior Notes. The adjusted presentation attributes $250.0 million of the 2007 Junior Notes to common equity and $250.0 million to long-term debt.

The adjusted presentation of our consolidated capitalization structure is included as a complement to our capitalization structure presented in accordance with GAAP. Management evaluates and manages our capitalization structure, including our total debt to total capitalization ratio, using the GAAP calculation as adjusted by the rating agency treatment of the 2007 Junior Notes. Therefore, we believe the non-GAAP adjusted presentation reflecting this treatment is useful and relevant to investors in understanding how management and the rating agencies evaluate our capitalization structure.

Working Capital

As of September 30, 2018, our current liabilities exceeded our current assets by $1,762.8 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 believe that we can access the capital markets to finance our construction programs and to refinance current maturities of long-term debt.

Credit Rating Risk

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

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

In January 2018, Moody's downgraded the rating outlook for WG to negative from stable as a result of the new Tax Legislation. We do not believe the change in rating outlook will have a material impact on our ability to access capital markets.

In July 2018, Moody's downgraded the ratings of WEC Energy Group (senior unsecured), Wisconsin Energy Capital Corporation (senior unsecured), and Integrys (senior unsecured) to Baa1 from A3. Moody's also downgraded the ratings of WEC Energy Group (junior subordinated) and Integrys (junior subordinated) to Baa2 from Baa1. Reduced cash flow due to Tax Legislation, which impacts the majority of companies in our industry, was a catalyst for the downgrade. Moody's affirmed the commercial paper ratings of WEC Energy Group (senior unsecured, P-2), and Integrys (senior unsecured, P-2) and changed the rating outlook for WEC Energy Group, Wisconsin Energy Capital Corporation, and Integrys, to stable from rating under review.

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



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If we are unable to successfully take actions to manage the adverse impacts of the Tax Legislation, or if additional interpretations, regulations, amendments or technical corrections exacerbate the adverse impacts of the Tax Legislation, the legislation could result in credit rating agencies placing our or our subsidiaries’ credit ratings on negative outlook or additional downgrading of our or our subsidiaries' credit ratings. Any such actions by credit rating agencies may make it more difficult and costly for us and our subsidiaries to issue future debt securities and certain other types of financing and could increase borrowing costs under our and our subsidiaries’ credit facilities.

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, impacts from the Tax Legislation, acquisition and development opportunities, market volatility, and economic trends. Our estimated capital expenditures and acquisitions for the next three years are as follows:



(in millions)	2018		2019		2020
Wisconsin	$	1,413.3	$	1,344.9	$	1,677.5
Illinois	568.5		765.2		684.0
Other states	96.2		155.4		135.8
Non-utility energy infrastructure	216.9		339.2		503.8
Corporate and other	19.5		15.7		11.0
Total	$	2,314.4	$	2,620.4	$	3,012.1

WPS is continuing work on the System Modernization and Reliability Project. This project includes modernizing parts of its electric distribution system, including burying or upgrading lines. The project focuses on constructing facilities to improve the reliability of electric service WPS provides to its customers. WPS expects to invest approximately $250 million between 2018 and 2021 on this project. WE, WPS, and WG will also continue to upgrade their electric and natural gas distribution systems to enhance reliability. These upgrades include the advanced metering infrastructure (AMI) program. AMI is an integrated system of smart meters, communication networks and data management systems that enable two-way communication between utilities and customers.

As part of our commitment to invest in zero-carbon generation, we plan to invest in utility scale solar of up to 350 MW within our Wisconsin segment. WPS has partnered with an unaffiliated utility to acquire ownership interests in two proposed solar projects in Wisconsin. Badger Hollow Solar Farm will be located in Iowa County, Wisconsin, and Two Creeks Solar Project will be located in Manitowoc County, Wisconsin. WPS will own 100 MW of the output of each project for a total of 200 MW. WPS's share of the cost of both projects is estimated to be $260 million. Commercial operation for both projects is targeted for the end of 2020. Solar generation technology has greatly improved, has become more cost-effective, and it complements our summer demand curve.

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, contingent upon UMERC's construction of approximately 180 MW of natural gas-fired generation in the Upper Peninsula of Michigan. The new generation is expected to begin commercial operation during the second quarter of 2019. The estimated cost of this project is approximately $266 million ($277 million including AFUDC), 50% of which is expected to be recovered from Tilden, with the remaining 50% expected to be recovered from UMERC's other utility customers.

PGL is continuing work on the SMP, a project under which PGL is replacing approximately 2,000 miles of Chicago's aging natural gas pipeline infrastructure. PGL currently recovers these costs through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023. PGL's projected average annual investment through 2020 is between $280 million and $300 million. See Note 22, Regulatory Environment, for more information on the SMP.

The non-utility energy infrastructure segment includes our investment in Bishop Hill III and our planned investment in the Upstream Wind Energy Center. See Note 2, Acquisitions, for more information on these wind projects.

We expect to provide total capital contributions to ATC (not included in the above table) of approximately $155 million from 2018 through 2020.



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Common Stock Dividends

Our current quarterly dividend rate is $0.5525 per share, which equates to an annual dividend of $2.21 per share. For information related to our most recent common stock dividend declared, see Note 7, 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 8, Short-Term Debt and Lines of Credit, Note 14, Guarantees, and Note 19, 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 2017 Annual Report on Form 10-K.

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity, and capital resources. The following discussion should be read together with the information in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources in our 2017 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, industry restructuring, environmental matters, critical accounting policies and estimates, and other matters.

Market Risks and Other Significant Risks

We are exposed to market and other significant risks as a result of the nature of our businesses and the environments in which those businesses operate. These risks include, but are not limited to, the regulatory recovery risk described below. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in our 2017 Annual Report on Form 10-K for a discussion of other significant risks applicable to us.

Regulatory Recovery

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

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

•

In June 2016, the PSCW approved the deferral of costs related to WPS's ReACT™ project above the originally authorized $275.0 million level through 2017. The total cost of the ReACT™ project, excluding $51 million of AFUDC, is currently estimated to be $342 million. In September 2017, the PSCW approved an extension of this deferral through 2019 as part of a settlement agreement. See Note 22, Regulatory Environment, for more information. WPS will be required to obtain a separate approval for collection of these deferred costs in a future rate case.


•	Prior to its acquisition by us, 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,



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call center, and credit collection functions. As of September 30, 2018, we had not received any significant disallowances of the costs incurred for this project. We will be required to obtain approval for the recovery of additional costs incurred through the completion of this long-term project.

•

In January 2014, the ICC approved PGL's use of the QIP rider as a recovery mechanism for costs incurred related to investments in QIP. This rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2018, PGL filed its 2017 reconciliation with the ICC, which, along with the 2016 and 2015 reconciliations, are still pending. In February 2018, PGL agreed to a settlement of the 2014 reconciliation, which includes a rate base reduction of $5.4 million and a $4.7 million refund to ratepayers. As of September 30, 2018, there can be no assurance that all costs incurred under the QIP rider during the open reconciliation years will be deemed recoverable by the ICC.

See Note 22, Regulatory Environment, for more information regarding recent and pending rate proceedings, orders, and investigations involving our utilities.

Environmental Matters

See Note 20, 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

Tax Cuts and Jobs Act of 2017

In December 2017, the Tax Legislation was signed into law. The PSCW and the MPSC have issued written orders regarding how to refund certain tax savings from the Tax Legislation to ratepayers in Wisconsin and Michigan, respectively, and the ICC has approved the VITA in Illinois. We expect the MPUC to address how we should return the tax savings from the Tax Legislation to our Minnesota ratepayers in MERC's currently active 2018 rate case. We are also working with the FERC to modify our formula rate tariffs for the impacts of the Tax Legislation, and we expect to receive FERC approval for the modified tariffs in 2019. See Note 22, Regulatory Environment, for more information.

American Transmission Company Allowed Return on Equity Complaints

In November 2013, a group of MISO industrial customer organizations filed a complaint with the FERC requesting to reduce the base ROE used by MISO transmission owners, including ATC, from 12.2% to 9.15%. In October 2014, the FERC issued an order to hear the complaint on ROE and set a refund effective date retroactive to November 2013. In December 2015, the ALJ issued an initial decision recommending that ATC and all other MISO transmission owners be authorized to collect a base ROE of 10.32%, as well as the 0.5% incentive adder approved by the FERC in January 2015 for MISO transmission owners. The incentive adder only applies to revenues collected after January 6, 2015. In September 2016, the FERC issued a final order related to this complaint affirming the use of the ROE stated in the ALJ's initial decision, effective as of the order date, on a going-forward basis. The order also required ATC to provide refunds, with interest, for the 15-month refund period from November 12, 2013, through February 11, 2015. The refunds ATC provided to WE and WPS for transmission costs paid during the refund period reduced the regulatory assets recorded under the PSCW-approved escrow accounting for transmission expense and resulted in a net regulatory liability for WPS. See Note 17, Investment in Transmission Affiliates, for more information.

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

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



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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 2017 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, 2018. No impairments were recorded as a result of these tests. For all of our reporting units, the fair values calculated in step one of the test were greater than their carrying values. The fair values for the reporting units were 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.

For all of our reporting units, fair value exceeded carrying value by over 50%. 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, 2018:



(in millions, except percentages)	Goodwill		Percentage of Total Goodwill
Wisconsin	$	2,104.3	68.9	%
Illinois	758.7		24.9	%
Other states	183.2		6.0	%
Bluewater	6.6		0.2	%
Total goodwill	$	3,052.8	100.0	%

See Note 16, 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 2017 Annual Report on Form 10-K. 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 12, Fair Value Measurements, Note 13, Derivative Instruments, and Note 14, 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

During 2018, we completed an enterprise resource planning (ERP) system integration project to bring all of our subsidiaries onto a consolidated ERP system. Accordingly, we are modifying the design and documentation of certain internal control processes and procedures related to the integrated ERP system. We do not believe that the implementation of the ERP system will have an adverse effect on our internal control over financial reporting.

With the exception of the ERP system implementation described above, 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 2018 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 2017 Annual Report on Form 10-K. See Note 20, Commitments and Contingencies, and Note 22, 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 in Note 20, Commitments and Contingencies, Note 22, Regulatory Environment, and below, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these additional 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

Manlove Field Matter

In September 2017, the Illinois Department of Natural Resources (Illinois DNR), Office of Oil and Gas Resource Management, issued a NOV to PGL related to a leak of natural gas that PGL identified at its Manlove Gas Storage Field in December 2016. PGL quickly contained the leak after it was discovered. The leak resulted in the migration of natural gas from a well located at the facility to the Mahomet Aquifer located in central Illinois, which impacted residential freshwater wells. PGL has been working with any residents potentially impacted by the natural gas leak, as well as the Illinois DNR and other state agencies to investigate and remediate the impacts of the natural gas leak to the Mahomet Aquifer. In October 2017, the Illinois Attorney General (AG) filed a complaint against PGL alleging certain violations of the Illinois Environmental Protection Act and the Oil and Gas Act. PGL entered into an interim agreed order with the State of Illinois in October 2017 whereby PGL agreed, among other things, to continue actions it was already undertaking proactively. In addition, in December 2017, the Illinois Environmental Protection Agency served a NOV to PGL alleging the same violations as the AG, and in January 2018, served a NOV alleging certain violations of Illinois air emission rules arising from the construction and operation of flaring equipment at the leak site. Both matters have been referred to the AG for enforcement.

In the complaint, as is customary in these types of actions, the AG cited to the statutory penalties allowed by law. Ultimately, the pursuit of any civil penalties is at the AG’s discretion. In the event the AG wishes to consider such penalties, we believe that PGL's high level of cooperation and quick action to remedy the situation and to work with the potentially impacted homeowners would be taken into account. At this time, we believe that civil penalties, if any, will not have a material impact on our financial statements.

Presque Isle Power Plant Matter

In March 2018, the EPA issued a Finding of Violation to WE regarding alleged violations of mercury emission limits for PIPP Units 5, 6, 8, and 9, as well as failure to conduct mercury tests on its low emitting electric generating units once every 12 months. WE is cooperating with the EPA, and we do not expect this matter to have a material impact on our financial statements.

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors presented in our 2017 Annual Report on Form 10-K. See Item 1A. Risk Factors in Part I of our Form 10-K for a discussion of certain risk factors applicable to us.



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

The following table sets forth information regarding the purchases of our equity securities made by or on behalf of us or any affiliated purchaser (as defined in Exchange Act Rule 10b-18) during the three months ended September 30, 2018:

Issuer Purchases of Equity Securities



2018	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
July 1 – July 31	6,567	$	65.52	—	$	—
August 1 – August 31	—	—		—	—
September 1 – September 30	—	—		—	—
Total *	6,567	$	65.52	—


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



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ITEM 6. EXHIBITS



Number	Exhibit
4	Instruments defining the rights of security holders, including indentures
	4.1	Securities Resolution No. 17 of WE, dated as of October 1, 2018, under the Indenture for Debt Securities, dated as of December 1, 1995, between WE and U.S. Bank National Association (as successor to Firstar Trust Company), as Trustee. (Exhibit 4.1 to WE's Form 8-K filed October 4, 2018.)

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 2, 2018	William J. Guc
		Vice President and Controller

		(Duly Authorized Officer and Chief Accounting Officer)



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